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 June 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 August 7, 1996, the Company had 54,632,075 shares of common stock
outstanding.
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
Year-To-Date
June 30, June 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
REVENUES $ 462,324 $ 465,940
EXPENSES:
Operations 190,653 209,118
Maintenance 28,659 36,021
Selling, general and administrative 50,449 51,168
Taxes other than income taxes 42,814 45,060
Depreciation, depletion and amortization 42,106 44,424
354,681 385,791
INCOME FROM OPERATIONS 107,643 80,149
INTEREST EXPENSE AND OTHER INCOME:
Interest 23,635 21,623
Other (income) deductions-net (2,408) (2,958)
21,227 18,665
INCOME TAXES 31,815 19,582
NET INCOME 54,601 41,902
DIVIDENDS ON PREFERRED STOCK 3,614 3,614
NET INCOME AVAILABLE FOR COMMON STOCK $ 50,987 $ 38,288
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,635 53,857
NET INCOME PER SHARE OF COMMON STOCK $ 0.93 $ 0.71
The accompanying notes are an integral part of these statements.
</TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
Quarter Ended
June 30, June 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
REVENUES $ 197,919 $ 203,643
EXPENSES:
Operations 82,831 95,315
Maintenance 15,357 20,681
Selling, general and administrative 25,965 23,632
Taxes other than income taxes 20,134 23,140
Depreciation, depletion and amortization 21,351 21,731
165,638 184,499
INCOME FROM OPERATIONS 32,281 19,144
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,649 10,668
Other (income) deductions-net (1,667) (1,400)
9,982 9,268
INCOME TAXES 8,013 2,306
NET INCOME 14,286 7,570
DIVIDENDS ON PREFERRED STOCK 1,807 1,807
NET INCOME AVAILABLE FOR COMMON STOCK $ 12,479 $ 5,763
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,632 53,976
NET INCOME PER SHARE OF COMMON STOCK $ 0.23 $ 0.11
The accompanying notes are an integral part of these statements.
</TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
A S S E T S
June 30, December 31,
1996 1995
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $59,162 and $57,095
plant under construction)
Electric $ 1,739,651 $ 1,713,133
Natural gas 496,633 492,431
2,236,284 2,205,564
Less - accumulated depreciation and depletion 690,629 663,215
1,545,655 1,542,349
NON-UTILITY PROPERTY (includes $28,110 and $15,887
property under construction) 644,321 631,901
Less - accumulated depreciation and depletion 250,950 252,613
393,371 379,288
1,939,026 1,921,637
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 54,569 57,013
Other 48,053 46,966
102,622 103,979
CURRENT ASSETS:
Cash and temporary cash investments 6,719 15,541
Accounts receivable 111,789 152,386
Materials and supplies (principally at average cost) 41,810 42,194
Prepayments and other assets 51,402 46,172
Deferred income taxes 15,843 15,899
227,563 272,192
DEFERRED CHARGES:
Advanced coal royalties 20,689 20,175
Regulatory assets related to income taxes 148,359 148,350
Regulatory assets - other 68,172 68,637
Other deferred charges 54,858 51,121
292,078 288,283
$ 2,561,289 $ 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
June 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 292,194 285,000
Unallocated stock held by trustee for deferred
savings and employee stock ownership plan (29,488) (30,565)
954,658 945,478
Preferred stock 101,416 101,416
Long-term debt 601,357 616,574
1,657,431 1,663,468
CURRENT LIABILITIES:
Short-term borrowing 89,500 96,348
Long-term debt - portion due within one year 23,406 24,804
Dividends payable 23,649 23,668
Income taxes 12,537 9,937
Other taxes 38,661 43,302
Accounts payable 43,867 63,920
Interest accrued 12,063 12,341
Other current liabilities 67,517 63,488
311,200 337,808
DEFERRED CREDITS:
Deferred income taxes 324,568 320,736
Investment tax credit 46,130 47,001
Accrued mining reclamation costs 124,602 122,008
Other deferred credits 97,358 95,070
592,658 584,815
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,561,289 $ 2,586,091
The accompanying notes are an integral part of these statements.
</TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Year-To-Date
June 30, June 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 54,601 $ 41,902
Noncash charges (credits) to net income:
Depreciation and depletion 42,106 44,424
Mining reclamation costs expensed 7,673 8,345
Deferred income taxes. 3,005 6,283
Amortization of loss on long-term sales
of power (1,145) (1,632)
Other - net 7,786 8,713
Changes in other assets and liabilities (12,033) (10,195)
Accounts receivable 40,597 57,834
Materials and supplies 384 2,656
Accounts payable (20,053) (5,759)
Payment of mining reclamation costs (5,079) (5,664)
Net Cash Flows from Operating Activities 117,842 146,907
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (60,715) (91,659)
Sales of property 5,212 6,359
Additional investments (1,031) (1,897)
Net Cash Flows from Investing Activities (56,534) (87,197)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock 815 11,259
Issuance of long-term debt 125 19,949
Retirement of long-term debt (16,871) (692)
Short-term debt (6,847) (50,793)
Dividends on common and preferred stock (47,352) (46,595)
Net Cash Flows from Financing Activities (70,130) (66,872)
Change in Cash Flows (8,822) (7,162)
Cash and cash equivalents at beginning of period 15,541 21,564
Cash and cash equivalents at end of period $ 6,719 $ 14,402
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Six Months For:
Income taxes $ 26,210 $ 21,651
Interest 24,322 22,964
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 June 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 and wildlife
habitat affected by the operation of the Kerr hydroelectric project, which
would cost the Company $18,400,000 initially and, thereafter, $1,100,000
annually. These amounts are presented in 1995 dollars. Previously, the amounts
were reported in 1990 dollars, which were subject to Consumer Price Index
escalation. FERC and the Department of the Interior (Department) have proposed
alternatives which the Company estimates would cost $48,000,000 initially and,
thereafter, $1,300,000 annually (1995 dollars). The alternatives proposed by
FERC staff and the Department would also change the operation of the project
which may further reduce the value of the license to the Company. The Company
is exploring options, including transfer of the license, to address the
potential that these mitigation and operating obligations may cause operation
of the Project to be uneconomic. It 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, which is expected to
decrease project capability by 26 megawatts, has a net present value of
$16,800,000. This brings the total cost of relicensing to $167,800,000.
Further action regarding this application is not expected until winter of 1996
when FERC staff is expected to issue a draft environmental impact statement.
The Company has brought an action against Puget Sound Power & Light
Company (Puget) in the Federal District Court for the Western 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 a firm transmission path for the power,
thereby entitling Puget to terminate the agreement. The Company and Puget
have agreed that, should it be determined that Puget is entitled to terminate
the agreement, the Company would reimburse Puget for the excess, if any, of
the cost of power purchased under the agreement after February 1995, over the
cost which Puget may demonstrate it would have paid for such power elsewhere.
Also, the Company would be obligated to reimburse Puget for approximately
$40,000,000, excluding interest, the amount by which Puget's payments through
February 1995 have exceeded its projected avoided cost. 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. In accordance with SFAS
No. 121, the Company would be required to write down assets related to the
agreement by approximately $25,000,000, 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, which is expected in 1997.
Western Energy Company (Western) was a party in an arbitration initiated
by the non-operating owners of the Colstrip Units 3 and 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 principal issues were the amounts of and prices for
coal that the Buyers are obligated to purchase in excess of 600,000 tons
monthly, 6,000,000 tons yearly and 170,000,000 tons over the lives of the
contracts, Western's obligation to mine in a manner dictated by the Buyers,
and Western's obligation to place reclamation funds received in a trust
account.
The arbitrator's decision was favorable to Western with respect to the
amounts and prices for coal that the Colstrip owners are obligated to
purchase, indicating that the Buyers must purchase the Units' requirements
from Western at prices and under terms stated in the contracts. The decision
affirms Western's mine plan and interpretation of its mining obligations and
does not assess damages against Western for not adopting mine plan changes
suggested by the Buyers. The decision does, however, obligate Western to
initiate a permit application seeking mine plan changes regarding the mining
sequence which the Buyers may propose and to exercise good faith in supporting
the application. If the mine plan sequence changes are permitted, Western must
bear the Buyers' cost incurred in developing, proposing and advocating for the
sequence changes. The decision also required the deposit of $42,000,000 of
mine reclamation funds to an interest-bearing bank account. The Company has
transferred to the account $25,000,000 it had collected earlier and the
remittance by the non-operating owners of the balance is substantially
complete. Previously, the arbitrator had dismissed the non-operating owners'
claims for refunds of certain coal transportation charges. The decision will
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 Tenaska power plant at Frederickson,
Washington. The Partnership contracted in 1994 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 decreases in demand for power and increasing
constraints in protection of endangered species have frustrated its purposes
for entering into the power purchase contract and, consequently, have excused
it 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 Company does not believe this dispute will adversely affect its
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 (PSC)
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.
The approved amount 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 PSC'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 of $6,700,000 or 5.3 percent effective July 1, 1996, including
$3,100,000 which had been included in rates on an interim basis as of 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 with the
PSC. In this filing, the Company is requesting an increase in natural gas
revenues of $4,800,000 or 3.8 percent to recover increased costs of service
and to facilitate the Gas Utility's restructuring plan (the Plan). The Plan
proposes a reduction in the transportation eligibility threshold, thereby
increasing the number of customers eligible to choose their own suppliers.
Within five years, all customers would have this choice. The Plan recommends
the recovery of all Utility investment. Hearings on the filing have not yet
been scheduled.
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 June 30,
1996, the Company had swap agreements to hedge approximately 222,000 barrels of
oil, or 50 percent, of its expected production through November 1996. In
addition, the Company had swap agreements to hedge approximately 1.4 Bcf of
non-regulated natural gas, or 23 percent, of its delivery obligations under
long-term natural gas sales contracts through February 1997. At June 30, 1996,
the Company had approximately $1,200,000 in deferred gains 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.
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 which involve certain risks and uncertainties.
Actual results and events may differ significantly from those discussed in the
forward-looking statements.
Year-To-Date June 30, 1996 and 1995:
Net Income Per Share of Common Stock:
Consolidated net income for the year-to-date June 30, 1996 was 93 cents
per share compared with 71 cents per share for the same period last year. The
twenty-two cent increase is primarily due to two non-recurring charges
recorded in 1995. A coal contract arbitration decision decreased 1995
consolidated earnings by five cents per share. The Non-Utility's Colorado coal
mine, which has been closed, sustained operating losses of thirteen cents per
share during the first six months of 1995. A more detailed discussion of the
individual operations follows. Non-Utility operations now include Entech and
the Independent Power Group.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Year-To-Date
June 30, June 30,
1996 1995
Utility Operations $ 0.61 $ 0.58
Non-Utility Operations 0.32 0.13
Consolidated $ 0.93 $ 0.71
UTILITY OPERATIONS
<TABLE>
<CAPTION>
Year-To-Date
June 30, June 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 205,297 $ 201,809
Intersegment revenues 3,515 3,228
208,812 205,037
EXPENSES:
Power supply 66,745 68,157
Transmission and distribution 15,021 13,134
Selling, general and administrative 22,055 21,382
Taxes other than income taxes 23,419 23,275
Depreciation and amortization 23,095 21,251
150,335 147,199
INCOME FROM ELECTRIC OPERATIONS 58,477 57,838
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 57,201 49,286
Gas supply cost revenues 13,980 13,386
Intersegment revenues 358 540
71,539 63,212
EXPENSES:
Gas supply costs 13,980 13,386
Other production, gathering and exploration 4,691 5,190
Transmission and distribution 5,907 5,510
Selling, general and administrative 8,682 8,873
Taxes other than income taxes 7,721 7,272
Depreciation, depletion and amortization 5,860 5,401
46,841 45,632
INCOME FROM GAS OPERATIONS 24,698 17,580
INTEREST EXPENSE AND OTHER INCOME:
Interest 23,051 21,898
Other (income) deductions - net (1,461) (2,777)
21,590 19,121
INCOME BEFORE INCOME TAXES 61,585 56,297
INCOME TAXES 24,754 21,562
UTILITY NET INCOME $ 36,831 $ 34,735
</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 temperature in 1996 in the Company's service territory was 9 percent
colder than normal and 11 percent colder than 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 contract arbitration decision recorded
in March 1995, income from electric operations benefited from lower power
supply expenses, increased residential and commercial volumes sold and higher
tariff rates.
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 $ 4
- volume (3)%
- price/kWh 6%
Other utilities - revenue $ -
- volume 12%
- price/kWh (12)%
Miscellaneous - revenue $ 1
Residential and commercial customer revenues increased $9,900,000 or 9
percent during the first six months of the year, primarily as a result of
increased volumes sold due to colder weather and 2 percent customer growth
along with higher tariff rates. Partly offsetting the increase was a decrease
of $6,100,000 in revenues from industrial customers primarily due to the loss
of the Utility's largest retail customer, which shut down operations in
December 1995. The customer was served under an economic retention rate that
was lower than the industrial tariff rate.
While volumes sold to other utilities increased during the period, lower
prices resulting from the abundance of hydroelectric energy in the region
caused revenues to decrease by $400,000.
Increased miscellaneous wheeling revenue resulted from higher rates and
increased volumes.
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 June 30, 1996 and 1995.
1996 1995
Sources MWH
Hydroelectric 2,244,198 1,620,684
Steam 1,704,066 2,199,158
Purchases and other 1,323,752 1,360,709
Total Power Supply 5,272,016 5,180,551
Thousands of Dollars
Hydroelectric $ 9,544 $ 9,265
Steam 20,921 17,405
Purchases and other 36,280 41,487
Total Power Supply Expenses $ 66,745 $ 68,157
Cents Per Kilowatt-Hour 1.266 1.316
Excluding the impact of the coal contract arbitration decision that
reduced 1995 steam expenses $10,100,000, power supply expenses decreased
$11,500,000. While the total power supply available did not increase by a
material amount, the sources of energy used changed significantly. Better
streamflow conditions caused increases in Utility as well as regional low-cost
hydroelectric generation resulting in displacement of higher cost thermal
generation. Power supply costs were reduced by $3,600,000 due to a credit
received from a party who delivers energy to the Company's customers.
Revisions made to the calculation of deliveries spanning a twelve-year period
resulted in 284,209 MWH's of power that will be returned to the Company over
the next year. Improved productivity and shorter maintenance periods at the
Colstrip units further reduced power supply expenses. The decreases were
offset in part by increased payments of $5,400,000 to independent power
producers.
Depreciation and amortization increased as a result of additional
property in service.
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 $ 7
-volume 15%
-price/Mcf 1%
Natural gas revenues (other than gas supply cost revenues) increased as
a result of increased volumes sold due to colder weather, a 3.7 percent
increase in residential and commercial customers and a rate increase,
effective March 31, 1996.
Interest Expense and Other Income:
The increase in interest expense is primarily the result of additional
borrowings. The decrease in other income principally resulted from the non-
recurring receipt of $1,600,000 in interest income under the coal contract
arbitration decision in March 1995.
<TABLE>
<CAPTION>
NON-UTILITY OPERATIONS
Year-To-Date
June 30, June 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 69,709 $ 102,116
Intersegment revenues 13,033 6,514
82,742 108,630
EXPENSES:
Operations and maintenance 52,830 79,716
Selling, general and administrative 10,555 14,564
Taxes other than income taxes 8,842 12,053
Depreciation, depletion and amortization 2,221 6,247
74,448 112,580
INCOME (LOSS) FROM COAL OPERATIONS 8,294 (3,950)
OIL AND NATURAL GAS:
REVENUES:
Revenues 58,469 47,478
Intersegment revenues 166 171
58,635 47,649
EXPENSES:
Operations and maintenance 35,451 27,723
Selling, general and administrative 4,932 4,550
Taxes other than income taxes 1,758 1,314
Depreciation, depletion and amortization 8,588 9,232
50,729 42,819
INCOME FROM OIL AND NATURAL GAS OPERATIONS 7,906 4,830
INDEPENDENT POWER:
REVENUES:
Revenues 38,000 39,311
Earnings (loss) from unconsolidated investments 5,859 (275)
Intersegment revenues 421 616
44,280 39,652
EXPENSES:
Operations and maintenance 31,486 33,223
Selling, general and administrative 1,866 1,372
Taxes other than income taxes 882 983
Depreciation, depletion and amortization 1,568 1,478
35,802 37,056
INCOME FROM INDEPENDENT POWER OPERATIONS $ 8,478 $ 2,59
NON-UTILITY OPERATIONS (continued)
Year-To-Date
June 30, June 30,
1996 1995
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 12,664 $ 10,740
Intersegment revenues 177 169
12,841 10,909
EXPENSES:
Operations and maintenance 8,499 7,297
Selling, general and administrative 2,723 2,276
Taxes other than income taxes 192 163
Depreciation, depletion and amortization 435 377
11,849 10,113
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 992 796
OTHER NON-UTILITY:
REVENUES:
Revenues 583 1,582
Intersegment revenues 409 360
992 1,942
EXPENSES:
Operations and maintenance 555 945
Selling, general and administrative 1,300 100
Depreciation, depletion and amortization 339 438
2,194 1,483
INCOME (LOSS) FROM OTHER NON-UTILITY (1,202) 459
INTEREST EXPENSE AND OTHER INCOME:
Interest 1,980 2,735
Other (income) deductions - net (2,343) (3,191)
(363) (456)
INCOME BEFORE INCOME TAXES 24,831 5,187
INCOME TAXES 7,061 (1,980)
NON-UTILITY NET INCOME $ 17,770 $ 7,167
</TABLE>
NON-UTILITY OPERATIONS:
Coal:
Year-to-date income from coal operations increased as a result of the
nonrecurring 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
offset in part by lower sales to Colstrip Units 3 & 4 and the expiration of a
Midwestern contract.
Revenues:
Excluding a non-recurring charge of approximately $19,000,000 recorded in
1995, as a result of the Colstrip Units 1 & 2 arbitration decision, revenues,
including intersegment revenues, decreased by $44,900,000. Revenues from the
Rosebud Mine decreased $12,800,000 due to a 56 percent decline in volumes sold
to Colstrip Units 3 & 4 and $10,000,000 due to the expiration of a Midwestern
contract at the end of 1995. Colstrip Units 3 & 4 were taken off line during
the period due to the availability of low-cost hydroelectric generation in
the region. The Company expects that the thermal plants will be operated at or
near full load for the rest of 1996. Revenues also decreased approximately
$8,000,000 due primarily to decreased volumes of short-term coal sales.
Revenues from the Jewett Mine decreased $3,300,000 principally as a result of
the mix of tons of lignite mined from Northwestern Resources' lignite leases
and the customer's lignite leases. The closure of the Golden Eagle Mine also
resulted in a $10,800,000 decrease in revenues.
Expenses:
The decrease in volumes sold at the Rosebud Mine reduced operation and
maintenance expenses by $10,100,000, taxes other than income taxes by
$1,700,000 and depreciation and depletion by $2,000,000. The closure of the
Golden Eagle Mine resulted in a $17,000,000 decrease in operation and
maintenance, a $2,600,000 decrease in selling, general and administrative, a
$1,500,000 decrease in taxes other than income taxes and a $1,200,000 decrease
in depreciation and depletion. Expenses also decreased $2,000,000 primarily
due to decreased 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 $ -
-volume (11)%
-price/bbl 7%
Natural gas -revenue $ 11
-volume 16%
-price/Mcf 14%
Natural gas revenues increased $11,500,000 due to an increase in volumes
sold in Canada and higher prices on gas sold in the U.S. The price increase in
the U.S. resulted 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 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 was mostly offset by higher prices in both the U.S.
and Canada. Production from the waterflood project is expected to increase
during the fourth quarter 1996.
Expenses:
Operating expenses increased primarily due to the increase in natural
gas volumes sold and higher prices paid for the gas.
Independent Power:
Year-to-date earnings from independent power operations increased
primarily as a result of continued growth in earnings from investments in
operating projects and the absence of a loss, recorded in 1995, for the
withdrawal from a power investment.
Revenues:
Earnings from unconsolidated investments increased $6,100,000 as a
result of additional investments made in 1995, growth in earnings from prior
investments resulting in part from increased power contract rates and the
absence of the loss recorded in 1995. This increase was moderated by a
$1,300,000 decrease in revenues from long-term power sales contracts resulting
from a decrease in volumes sold.
Expenses:
Operating and maintenance expenses decreased $1,700,000 due primarily to
a $2,600,000 reduction in power supply resulting from lower volumes sold and
the displacement of higher cost thermal generation from the Colstrip plant
with lower cost hydroelectric generation. Operating expenses were also
impacted by a $1,300,000 increase in power purchases, a $900,000 increase in
project development expenses and a $1,000,000 decrease in transmission expense
due to the decrease in sales from Colstrip.
Telecommunications:
Earnings from telecommunications operations increased as a result of higher
long-distance service minutes and equipment service installations completed in
the second quarter. Due to increased marketing efforts, the number of
residential and commercial long-distance customers increased 38 percent
resulting in a 28 percent increase in minutes of use. The revenue increase was
partially offset by the increased operation and maintenance expenses resulting
from the marketing effort and equipment service.
Quarter Ended June 30, 1996 and 1995:
Net Income Per Share of Common Stock:
Net income for the quarter ended June 30, 1996 was 23 cents per share
compared with 11 cents per share for the second quarter 1995. Utility earnings
increased seven cents per share due to a reduction in power supply expenses,
customer growth and higher rates. Earnings from Non-Utility operations
increased five cents per share in part due to continued growth in earnings
from independent power investments and higher natural gas prices. Also, the
Colorado coal mine, which has been closed, sustained losses of seven cents per
share in the second quarter of 1995. These increases were partially offset by
a decline in coal sales. 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
June 30, June 30,
1996 1995
Utility Operations $ 0.11 $ 0.04
Non-Utility Operations 0.12 0.07
Consolidated $ 0.23 $ 0.11
UTILITY OPERATIONS
<TABLE>
<CAPTION>
Quarter Ended
June 30, June 30,
1996 1995
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES:
Revenues $ 85,410 $ 84,625
Intersegment revenues 1,487 1,655
86,897 86,280
EXPENSES:
Power supply 24,999 32,810
Transmission and distribution 7,562 6,706
Selling, general and administrative 10,742 9,334
Taxes other than income taxes 11,481 11,670
Depreciation and amortization 11,548 10,630
66,332 71,150
INCOME FROM ELECTRIC OPERATIONS 20,565 15,130
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 19,313 17,187
Gas supply cost revenues 3,904 4,488
Intersegment revenues 151 189
23,368 21,864
EXPENSES:
Gas supply costs 3,904 4,488
Other production, gathering and exploration 2,325 2,579
Transmission and distribution 2,837 2,929
Selling, general and administrative 4,334 4,485
Taxes other than income taxes 3,709 3,727
Depreciation, depletion and amortization 2,929 2,702
20,038 20,910
INCOME FROM GAS OPERATIONS 3,330 954
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,311 10,804
Other (income) deductions - net (966) (690)
10,345 10,114
INCOME BEFORE INCOME TAXES 13,550 5,970
INCOME TAXES 5,727 2,202
UTILITY NET INCOME $ 7,823 $ 3,768
</TABLE>
UTILITY OPERATIONS:
Electric Utility:
Income from electric operations increased 36 percent largely as a result
of a decrease in power supply expenses. The Electric Utility responded to the
low-cost hydroelectric power available in the region by reducing its thermal
plant production. Shorter maintenance periods and improved productivity at the
Colstrip units and a credit with respect to past power deliveries also
contributed to the decrease.
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 $ -
- volume (6)
- price/kWh 6%
Other utilities - revenue $ 1
- volume 43%
- price/kWh (21)%
Revenues from residential and commercial customers were up $3,200,000
over last year's second quarter primarily as a result of a 2 percent increase
in the number of customers and higher rates. Industrial revenues decreased
$3,600,000, however, as the result of the termination of operations by the
Utility's largest retail customer in December 1995, as mentioned previously in
the year-to-date discussion.
Volumes sold to other utilities increased significantly compared to the
second quarter of 1995, but, due to lower prices, revenues increased by only
$1,100,000.
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 June 30, 1996 and 1995.
1996 1995
Sources MWH
Hydroelectric 1,109,715 879,108
Steam 697,634 849,083
Purchases and other 438,414 563,618
Total Power Supply 2,245,763 2,291,809
Thousands of Dollars
Hydroelectric $ 4,901 $ 4,712
Steam 9,433 13,588
Purchases and other 10,665 14,510
Total Power Supply Expenses $ 24,999 $ 32,810
Cents Per Kilowatt-Hour 1.113 1.435
Total power supply expenses decreased $7,800,000. As a result of the
availability of low-cost wholesale hydroelectric power in the region, steam
generation was displaced, decreasing fuel expenses. Steam maintenance expenses
were lower due to improved productivity and shorter maintenance periods at the
Colstrip units. Purchased power costs decreased primarily due to a $3,600,000
metering refund which was offset in part by increased payments to independent
power producers.
Natural Gas Utility:
Income from natural gas operations increased primarily due to increased
volumes sold and higher rates.
Revenues:
The following table shows the change from the previous year, in millions
of dollars, in the full requirements customer classification of natural gas
revenues and the related percentage changes in volumes sold and prices
received:
Full requirement customers -revenue $ 2
-volume 9%
-price/Mcf 4%
The increase in natural gas revenues (other than gas supply cost
revenues) was primarily due to an increase in volumes sold due 4 percent growth
in residential and commercial customers, colder weather and a rate increase,
effective March 1, 1996.
<TABLE>
<CAPTION>
NON-UTILITY OPERATIONS
Quarter Ended
June 30, June 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 31,319 $ 49,033
Intersegment revenues 4,836 6,216
36,155 55,249
EXPENSES:
Operations and maintenance 25,294 39,276
Selling, general and administrative 5,420 6,749
Taxes other than income taxes 3,467 6,513
Depreciation, depletion and amortization 1,078 2,504
35,259 55,042
INCOME FROM COAL OPERATIONS 896 207
OIL AND NATURAL GAS:
REVENUES:
Revenues 29,406 24,209
Intersegment revenues 67 39
29,473 24,248
EXPENSES:
Operations and maintenance 17,802 14,862
Selling, general and administrative 2,506 2,308
Taxes other than income taxes 924 684
Depreciation, depletion and amortization 4,635 4,744
25,867 22,598
INCOME FROM OIL AND NATURAL GAS OPERATIONS 3,606 1,650
INDEPENDENT POWER:
REVENUES:
Revenues 18,283 19,287
Earnings (loss) from unconsolidated investments 3,150 (1,455)
Intersegment revenues 352 280
21,785 18,112
EXPENSES:
Operations and maintenance 14,874 15,947
Selling, general and administrative 1,044 558
Taxes other than income taxes 451 463
Depreciation, depletion and amortization 784 738
17,153 17,706
INCOME FROM INDEPENDENT POWER OPERATIONS $ 4,632 $ 406
NON-UTILITY OPERATIONS (continued)
Quarter Ended
June 30, June 30,
1996 1995
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 6,435 $ 5,167
Intersegment revenues 108 (32)
6,543 5,135
EXPENSES:
Operations and maintenance 4,335 3,346
Selling, general and administrative 1,427 1,181
Taxes other than income taxes 101 82
Depreciation, depletion and amortization 212 189
6,075 4,798
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 468 337
OTHER NON-UTILITY:
REVENUES:
Revenues 318 872
Intersegment revenues 286 275
604 1,147
EXPENSES:
Operations and maintenance 291 540
Selling, general and administrative 1,365 (76)
Depreciation, depletion and amortization 165 223
1,821 687
INCOME (LOSS) FROM OTHER NON-UTILITY (1,217) 460
INTEREST EXPENSE AND OTHER INCOME:
Interest 1,051 387
Other (income) deductions - net (1,414) (1,233)
(363) (846)
INCOME BEFORE INCOME TAXES 8,748 3,906
INCOME TAXES 2,285 104
NON-UTILITY NET INCOME $ 6,463 $ 3,802
</TABLE>
NON-UTILITY OPERATIONS:
Coal:
Income from coal operations for the quarter remained relatively equal to
that of the second quarter in 1995. The increase resulting from the operating
losses incurred in 1995 at Golden Eagle Mine was offset by lower sales to
Colstrip Units 3 & 4 and the expiration of a Midwestern contract as mentioned
in the year-to-date discussion.
Revenues:
The displacement of Colstrip Units 3 & 4 generation with low-cost
hydroelectric generation and the expiration of a Midwestern contract resulted
in a 50 percent decrease in volumes sold at the Rosebud Mine decreasing
revenues by $12,700,000. Revenues from the Jewett Mine decreased $1,300,000 as
a result of lower reimbursable mining costs and the mix of lignite mined from
Northwestern's leases and the customer's leases. The closure of the Golden
Eagle Mine resulted in a $4,900,000 decrease in revenues.
Expenses:
The decrease in volumes sold at the Rosebud Mine and the closure of the
Golden Eagle Mine reduced operating expenses by $8,200,000 and $10,600,000,
respectively.
Oil and Natural Gas:
Income from the oil and natural gas operations improved primarily due
to increased natural gas sales as mentioned in the year-to-date discussion.
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 $ -
-volume (5)%
-price/bbl 9%
Natural gas -revenue $ 5
-volume 8%
-price/Mcf 19%
The $5,000,000 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 year-to-date discussion.
Expenses:
Operating expenses increased for the reasons mentioned in the year-to-
date discussion.
Independent Power:
Quarterly earnings from independent power operations increased due to
the growth in earnings from investments in operating projects and the absence
of a loss, recorded in the second quarter of 1995, for the withdrawal from a
power investment.
Revenues:
As mentioned in the year-to-date discussion, independent power
operations revenues for the quarter increased due to higher earnings from
unconsolidated investments partially offset by a decrease in revenues from
long-term power sales contracts.
Expenses:
As mentioned in the year-to-date discussion, quarterly operating and
maintenance expenses decreased primarily due to the displacement of higher
cost thermal generation from the Colstrip plant with lower cost hydroelectric
generation.
Telecommunications:
Earnings from telecommunications operations for the quarter increased as
a result of higher long-distance minutes sold and equipment service projects
completion as mentioned in the year-to-date discussion.
LIQUIDITY AND CAPITAL RESOURCES:
Touch America, Inc., a wholly owned subsidiary, 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 in information
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
Touch America'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. While the return on this investment, which will depend
upon such future uncertainties as demand for service, competition and
technological change, cannot be accurately estimated, Touch America
anticipates that, because of existing long-term commitments for the expanded
network's capacity and a population base of nearly 12,000,000 in the
additional long-distance service territory, 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 PSC on September 21, 1995. The PSC 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
$5,800,000.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended June 30, 1996, the Company's ratio of
earnings to fixed charges was 2.22 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 3.09 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 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. Does not require divestiture of assets but utilities must separate
transmission and generation functions from each other.
5. Does not require utilities to create an independent system
transmission operator (ISO). However, the rules do establish
principles concerning how an ISO should be constructed.
The Company is taking the necessary steps to comply with all aspects of
the final ruling.
The Company has joined six other Western electric utilities in a
memorandum of understanding that is a first step toward developing an
independent grid operator for the investor-owned companies' high-voltage
transmission lines. The grid operator would be independent of the utilities,
as required by the Federal Energy Regulatory Commission as part of the
increasing competition in the electric business.
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.
ITEM 4. Submission of Matters to a Vote of Security Holders.
A. The Company's Annual Meeting of Shareholders was held on May 14,
1996.
B. Security holders elected seven persons to the Board of Directors.
Director For Withheld Abstentions
Tucker Hart Adams 47,638,271 -- 1,481,639
Daniel T. Berube 47,796,741 -- 1,323,168
Alan F. Cain 47,698,731 -- 1,421,178
Robert P. Gannon 47,935,560 -- 1,184,349
James P. Lucas 46,363,337 -- 2,745,640
George H. Selover 47,762,029 -- 1,357,880
John R. Jester 47,799,594 -- 1,320,315
Directors whose term of office as a director continued after the
meeting are as follows:
R. D. Corette Kay Foster
Beverly D. Harris Chase T. Hibbard
Arthur K. Neill Daniel P. Lambros
Noble E. Vosburg Jerrold P. Pederson
Carl Lehrkind, III
C. Security holders voted in favor of amending Article IV of the
Company's Restated Articles of Incorporation which limits the
liability of the Directors to the Company or its shareholders. The
amendment will conform Article IV to the present Montana Business
Corporation Act, which was amended subsequent to the adoption of
Article IV. Existing Article IV conforms to the Montana Business
Corporation Act which was in effect at the time of adoption.
For Against Abstentions
43,561,574 4,475,104 1,090,129
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits
Exhibit 3(a)(2) Articles of Amendment
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
June 30, 1996.
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K
DATE SUBJECT
April 10, 1996 Item 5. Other Events. News Release on
Preliminary Arbitration Decision on Coal-
Supply Contract.
April 23, 1996 Item 5. Other Events. Discussion of
First Quarter Net Income.
Item 7. Exhibits. Consolidated Statements
of Income for the Quarters Ended March 31,
1996 and 1995 and for the Twelve Months
Ended March 31, 1996 and 1995, Utility
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1996 and 1995 and for the Twelve Months
Ended March 31, 1996 and 1995, Entech
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1996 and 1995 and for the Twelve Months
Ended March 31, 1996 and 1995 and
Independent Power Group Operations
Schedule of Revenues and Expenses for the
Quarters Ended March 31, 1996 and 1995 and
for the Twelve Months Ended March 31, 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: August 14, 1995
EXHIBIT INDEX
Exhibit 3(a)(2)
Articles of Amendment
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended June 30, 1996
Exhibit 27
Financial Data Schedule
- -26-
- -31-
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
June 30,1996
Net Income $ 69,192
Income Taxes 33,807
$ 102,999
Fixed Charges:
Interest $ 48,255
Amortization of Debt Discount,
Expense and Premium 1,567
Rentals 34,925
$ 84,747
Earnings Before Income Taxes
and Fixed Charges $187,746
Ratio of Earning to Fixed Charges 2.22 x
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 6/30/96, the Consolidated Income Statement and
Consolidated Statement of Cash Flows for the six months ended 6/30/96 and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,545,655
<OTHER-PROPERTY-AND-INVEST> 495,993
<TOTAL-CURRENT-ASSETS> 227,563
<TOTAL-DEFERRED-CHARGES> 292,078
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,561,289
<COMMON> 691,952
<CAPITAL-SURPLUS-PAID-IN> 2,226
<RETAINED-EARNINGS> 260,480
<TOTAL-COMMON-STOCKHOLDERS-EQ> 954,658
0
101,416
<LONG-TERM-DEBT-NET> 599,371
<SHORT-TERM-NOTES> 89,500
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 22,695
0
<CAPITAL-LEASE-OBLIGATIONS> 1,986
<LEASES-CURRENT> 711
<OTHER-ITEMS-CAPITAL-AND-LIAB> 790,952
<TOT-CAPITALIZATION-AND-LIAB> 2,561,289
<GROSS-OPERATING-REVENUE> 462,324
<INCOME-TAX-EXPENSE> 31,815
<OTHER-OPERATING-EXPENSES> 354,681
<TOTAL-OPERATING-EXPENSES> 386,496
<OPERATING-INCOME-LOSS> 75,828
<OTHER-INCOME-NET> 2,408
<INCOME-BEFORE-INTEREST-EXPEN> 78,236
<TOTAL-INTEREST-EXPENSE> 23,635
<NET-INCOME> 54,601
3,614
<EARNINGS-AVAILABLE-FOR-COMM> 50,987
<COMMON-STOCK-DIVIDENDS> 43,727
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 117,842
<EPS-PRIMARY> 0.93
<EPS-DILUTED> 0.93
</TABLE>
ARTICLES OF AMENDMENT
TO THE RESTATED ARTICLES OF INCORPORATION
OF
THE MONTANA POWER COMPANY
Pursuant to the provisions of Section 35-1-230, MCA, the undersigned
corporation adopts the following Articles of Amendment to its Articles of
Incorporation.
FIRST: The name of the corporation is The Montana Power Company.
SECOND: The following amendment to the corporation's Restated
Articles of Incorporation was adopted by the shareholders of the corporation
on May 14, 1996, in the manner prescribed by the Montana Business Corporation
Act.
Article VI of the Restated Articles of Incorporation of the corporation
is amended
to read as follows:
No Director of the Corporation shall be personally liable to the
Corporation or its shareholders for money damages for any actions
taken or any failure to take any action, as a Director, except
liability for: (a) the amount of a financial benefit received by a
Director to which the Director is not entitled; (b) an intentional
infliction of harm on the corporation or its shareholders; (c) a
violation of 35-1-713 of the Montana Code Annotated; or, (d) an
intentional violation of criminal law. No amendment to or repeal
of this Article VI shall apply to or have any effect on the
liability or alleged liability of any Director of the Corporation
for or with respect to any acts or omissions of such Director
occurring prior to such amendment or repeal.
THIRD: The number of Common shares of the corporation outstanding
at the record date was 54,632,075 common shares; and the number of such
shares entitled to vote on the amendment was 54,632,075. The number of
Preferred shares of the corporation outstanding at the record date was
1,919,589; and the number of such shares entitled to vote on the amendment
was 1,919,589.
FOURTH: The number of voting shares represented at the meeting were:
Common 47,509,562 Preferred 1,621,807
FIFTH: The vote on the Amendment was as follows:
For Against
Common and Preferred Total: 43,561,574 4,475,104
DATED: June 13, 1996.
THE MONTANA POWER COMPANY
/s/Robert P. Gannon
Vice Chairman of the Board and
President
(SEAL)
/s/Rose Marie Ralph
Assistant Secretary
STATE OF MONTANA )
ss.
County of Silver Bow )
I, the undersigned Notary Public, do hereby certify that on this 13th
day of June, 1996, personally appeared before me R. P. Gannon, who, being by
me first duly sworn, declared that he is Vice Chairman of the Board and
President of THE MONTANA POWER COMPANY, that he signed the foregoing document
as Vice Chairman of the Board and President of the Corporation, and that the
statements therein contained are true.
/s/Lauri A. Yelenich
Notary Public for the State of Montana
(SEAL) Residing at Butte, Montana
My Commission Expires: 9/1/96
