UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
________________________________________
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1994
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _______________
________________________________________
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
________________________________________________________
(Former name, former address and former fiscal year,
if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
On May 5, 1994, the Company had 53,052,943 shares of common stock
outstanding.
<PAGE>
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
<TABLE>
<CAPTION>
March 31, December 31,
1994 1993
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $47,659 and $38,966
plant under construction)
Electric. . . . . . . . . . . . . . . . . . . . . . . . $ 1,532,652 $ 1,514,472
Natural gas . . . . . . . . . . . . . . . . . . . . . . 430,789 428,956
1,963,441 1,943,428
Less - accumulated depreciation and depletion . . . . . . 584,162 572,141
1,379,279 1,371,287
ENTECH PROPERTY (includes $711 and $2,446
property under construction). . . . . . . . . . . . . . 525,106 526,692
Less - accumulated depreciation and depletion . . . . . . 182,956 182,129
342,150 344,563
INDEPENDENT POWER GROUP PROPERTY (includes $989 and
$84 property under construction). . . . . . . . . . . . 71,203 70,198
Less - accumulated depreciation . . . . . . . . . . . . . 17,372 16,822
53,831 53,376
1,775,260 1,769,226
MISCELLANEOUS INVESTMENTS (at cost):
Miscellaneous special funds . . . . . . . . . . . . . . . 10,874 7,811
Investment in cogeneration projects . . . . . . . . . . . 47,457 45,494
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 52,103 51,492
110,434 104,797
CURRENT ASSETS:
Cash and temporary cash investments . . . . . . . . . . . 11,884 11,604
Accounts receivable . . . . . . . . . . . . . . . . . . . 138,687 158,352
Materials and supplies (principally at average cost). . . 45,531 42,728
Prepayments and other assets. . . . . . . . . . . . . . . 53,967 44,425
250,069 257,109
DEFERRED CHARGES:
Advanced coal royalties . . . . . . . . . . . . . . . . . 22,105 20,905
Costs deferred to future operating periods. . . . . . . . 193,504 185,151
Other deferred charges. . . . . . . . . . . . . . . . . . 50,044 48,839
265,653 254,895
$ 2,401,416 $ 2,386,027
The accompanying notes are an integral part of these statements.
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
March 31, December 31,
1994 1993
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 52,836,246 and
52,498,896 shares issued) . . . . . . . . . . . . . . $ 649,587 $ 642,926
Retained earnings and other shareholders' equity. . . . 316,759 302,725
Unallocated Stock held by Trustee for Deferred
Savings and Employee Stock Ownership Plan . . . . . . (33,975) (34,419)
932,371 911,232
Preferred stock . . . . . . . . . . . . . . . . . . . . . 101,417 101,419
Long-term debt. . . . . . . . . . . . . . . . . . . . . . 575,772 571,870
1,609,560 1,584,521
CURRENT LIABILITIES:
Short-term borrowing. . . . . . . . . . . . . . . . . . . 0 68,865
Long-term debt - portion due within one year. . . . . . . 26,131 26,199
Dividends payable . . . . . . . . . . . . . . . . . . . . 22,960 22,835
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 24,249 4,927
Other taxes . . . . . . . . . . . . . . . . . . . . . . . 58,418 43,743
Accounts payable. . . . . . . . . . . . . . . . . . . . . 49,778 55,794
Interest accrued. . . . . . . . . . . . . . . . . . . . . 12,634 11,942
Accrued lease payments. . . . . . . . . . . . . . . . . . 8,057 0
Other current liabilities . . . . . . . . . . . . . . . . 96,660 79,162
298,887 313,467
DEFERRED CREDITS:
Deferred income taxes . . . . . . . . . . . . . . . . . . 313,082 309,780
Investment tax credit . . . . . . . . . . . . . . . . . . 50,031 50,476
Accrued mining reclamation costs. . . . . . . . . . . . . 103,806 101,817
Other deferred credits. . . . . . . . . . . . . . . . . . 26,050 25,966
492,969 488,039
CONTINGENCIES AND COMMITMENTS (Note 2)
$ 2,401,416 $ 2,386,027
The accompanying notes are an integral part of these statements.
/TABLE
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
For the Three Months Ended
March 31, March 31,
1994 1993
Thousands of Dollars
<S> <C> <C>
UTILITY OPERATIONS:
Operating Revenues:
Electric. . . . . . . . . . . . . . . . . . . . . . . . $ 122,625 $ 127,026
Natural gas . . . . . . . . . . . . . . . . . . . . . . 37,326 41,637
159,951 168,663
Operating Expenses and Taxes:
Operation . . . . . . . . . . . . . . . . . . . . . . . 56,529 59,756
Purchased gas . . . . . . . . . . . . . . . . . . . . . 7,225 11,156
Fuel for electric generation. . . . . . . . . . . . . . 9,456 8,990
Maintenance . . . . . . . . . . . . . . . . . . . . . . 7,847 7,008
Depreciation and depletion. . . . . . . . . . . . . . . 12,042 11,578
Taxes - other than income taxes . . . . . . . . . . . . 14,150 12,609
Income taxes. . . . . . . . . . . . . . . . . . . . . . 15,918 17,556
123,167 128,653
Operating Income. . . . . . . . . . . . . . . . . . . . . 36,784 40,010
Other Income and Expenses:
Interest and dividend income and other. . . . . . . . . 279 38
Income taxes applicable to other. . . . . . . . . . . . (39) 43
240 81
Interest Charges:
Interest on long-term debt. . . . . . . . . . . . . . . 10,258 11,320
Other interest. . . . . . . . . . . . . . . . . . . . . 492 569
10,750 11,889
Income from Utility Operations. . . . . . . . . . . . . 26,274 28,202
ENTECH OPERATIONS:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . 109,936 104,572
Costs and Expenses:
Cost of sales . . . . . . . . . . . . . . . . . . . . . 61,355 58,245
Taxes - other than income taxes . . . . . . . . . . . . 11,472 10,844
Depreciation and depletion. . . . . . . . . . . . . . . 8,583 8,555
Selling, general and administrative . . . . . . . . . . 10,782 10,319
Interest. . . . . . . . . . . . . . . . . . . . . . . . 315 449
Other income - net. . . . . . . . . . . . . . . . . . . 1,265 52
Income taxes. . . . . . . . . . . . . . . . . . . . . . 4,336 4,413
98,108 92,877
Income from Entech Operations . . . . . . . . . . . . . 11,828 11,695
INDEPENDENT POWER GROUP OPERATIONS:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . 30,451 28,255
Expenses (including interest and income taxes). . . . . . 29,375 28,107
Income from Independent Power Group Operations. . . . . 1,076 148
CONSOLIDATED NET INCOME . . . . . . . . . . . . . . . . . . 39,178 40,045
DIVIDENDS ON PREFERRED STOCK. . . . . . . . . . . . . . . . 1,807 947
NET INCOME AVAILABLE FOR COMMON STOCK . . . . . . . . . . . $ 37,371 $ 39,098
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) . . . . . 52,743 51,689
NET INCOME PER SHARE OF COMMON STOCK. . . . . . . . . . . . $ 0.71 $ 0.76
DIVIDENDS DECLARED ON COMMON STOCK, PER SHARE . . . . . . . $ 0.400 $ 0.395
The accompanying notes are an integral part of these statements.
/TABLE
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
For the Three Months Ended
March 31, March 31,
1994 1993
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . $ 39,177 $ 40,045
Noncash charges (credits) to net income:
Depreciation and depletion . . . . . . . . . . . . . 21,360 21,001
Mining reclamation costs expensed. . . . . . . . . . 4,150 3,691
Deferred income taxes. . . . . . . . . . . . . . . . 1,335 802
Amortization of loss on long-term sale
of power . . . . . . . . . . . . . . . . . . . . . (1,057) (1,313)
Other - net. . . . . . . . . . . . . . . . . . . . . 7,711 6,243
Changes in other assets and liabilities. . . . . . . . 40,535 26,285
Accounts receivable. . . . . . . . . . . . . . . . . . 19,665 20,570
Materials and supplies . . . . . . . . . . . . . . . . (2,802) (4,444)
Accounts payable . . . . . . . . . . . . . . . . . . . (6,017) (549)
Payment of mining reclamation costs. . . . . . . . . . (2,161) (915)
Net Cash Flows from Operating Activities . . . . . . 121,896 111,416
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Miscellaneous special funds. . . . . . . . . . . . . . (3,062) 0
Gross additions to property and plant. . . . . . . . . (35,456) (22,203)
Investments in other operations. . . . . . . . . . . . (1,838) (237)
Sales of property. . . . . . . . . . . . . . . . . . . 728 247
Additional investments . . . . . . . . . . . . . . . . (598) 11,156
Net Cash Flows from Investing Activities . . . . . . (40,226) (11,037)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock. . . . . . . . . . . . . . . . . 6,659 5,650
Issuance of long-term debt . . . . . . . . . . . . . . 44,241 92,550
Retirement of long-term debt . . . . . . . . . . . . . (40,466) (108,196)
Short-term debt. . . . . . . . . . . . . . . . . . . . (68,865) (52,300)
Note payable cogeneration project. . . . . . . . . . . 0 (7,605)
Dividends on common and preferred stock. . . . . . . . (22,960) (21,406)
Issuance of preferred stock. . . . . . . . . . . . . .
Net Cash Flows from Financing Activities . . . . . . (81,391) (91,307)
Net Cash Flows . . . . . . . . . . . . . . . . . . 279 9,072
Cash and cash equivalents at beginning of period . . . . 11,604 8,879
Cash and cash equivalents at end of period . . . . . . . $ 11,883 $ 17,951
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Three Months For:
Income taxes . . . . . . . . . . . . . . . . . . . . $ 851 $ 1,269
Interest . . . . . . . . . . . . . . . . . . . . . . 10,345 15,932
The accompanying notes are an integral part of these statements.
/TABLE
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying financial statements of the Company for the interim
periods ended March 31, 1994 and 1993 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, 1993.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1994 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1. INTERCOMPANY TRANSACTIONS:
The Utility and the Independent Power Group (IPG) purchase coal from a
subsidiary of Entech. These intercompany transactions are included in the
Consolidated Statement of Income as revenues and expenses and were as follows:
Quarter Ended
March 31, March 31,
1994 1993
Thousands of Dollars
Coal sales to:
Utility . . . $ 7,864 $ 9,160
IPG . . . . . 3,663 2,800
NOTE 2. CONTINGENCIES AND COMMITMENTS:
In 1990, the Company filed with the Federal Energy Regulatory
Commission (FERC) a plan to mitigate damages to and manage fish and wildlife
habitat impacted by the operation of the Kerr Hydroelectric Project. The Plan
was prepared pursuant to a joint license issued by the FERC to the Company and
the Confederated Salish and Kootenai Tribes (Tribes). It consists of a one-
time payment by the Company of $15,418,000 and annual payments of $965,000
allocated between the Tribes and various groups. The annual payments will be
adjusted annually on the basis of the Consumer Price Index. Additionally, the
Secretary of Interior may impose certain conditions pertaining to fish and
wildlife. The FERC now has the Plan under review. While the Company cannot
predict when or in what form the Plan finally will be approved, it expects
that the cost of mitigation measures will be recovered through rates and,
therefore, will not have a materially adverse effect on the Company's
financial condition or results of operations.
In November 1992, the Company filed with FERC its application to
relicense nine Madison and Missouri River hydroelectric facilities with
electric generating capacity totaling 292 megawatts. The application, in
preparation since 1989, proposes an additional 74 megawatts of generation.
The total capital investment of relicensing, including physical improvements,
environmental protection, mitigation and enhancement measures, is estimated at
$167,600,000. Additional costs for operational changes, as well as annual
payments for environmental protection, mitigation and enhancement, are
estimated to be about $5,400,000 per year. The Company expects that the
relicensing costs will be recovered through rates and, therefore, will not
have a materially adverse effect on the Company's financial condition or
results of operations.
The owners of homes in two residential developments in Colstrip,
Montana, which were built for the Colstrip Units 3 and 4 Project made claims
against the Company and the other owners of the Colstrip Units 3 and 4 for
property damages to their homes allegedly caused by soil-related subsidence.
The Company settled all of these claims. The other Colstrip 3 and 4 owners,
however, denied responsibility for a substantial part of the settlement costs
on the grounds that the Company exceeded its authority in settling the claims.
The Company and the other Colstrip 3 and 4 owners have reached an agreement in
principle to settle this dispute. Under the terms of the proposed settlement,
the Company estimates its liability will exceed its ownership share of sums
expended to settle the property damage claims by approximately $2,200,000.
Other Colstrip property owners also have made claims against the Company
and the other owners of all of the Colstrip Units for property damages
allegedly resulting from soil-related subsidence. The Company has not
determined the magnitude of such alleged damages or the responsibility, if
any, of the Colstrip owners. While the resolution of these claims is
uncertain, the Company believes they will not have a materially adverse effect
on the Company's financial condition or results of operations.
A Rosebud Mine coal supply agreement provides for periodic price
redetermination over the life of the contract. The first date under the
contract that a price redetermination could have occurred was August 1, 1991.
Negotiations to redetermine the coal price have been unsuccessful and an
arbitration proceeding has been scheduled to commence in October, 1994.
Through March 31, 1994, 7,619,000 tons, of which 3,814,000 tons were delivered
to the Company, have been delivered and are subject to a redetermined price.
The price change, if any, from this arbitration is not expected to have a
materially adverse effect on the Company's results of operations.
The Entech Oil Division has agreed to supply 144 Bcf of natural gas to
three cogeneration facilities through September 2007. The Oil Division has
sufficient proven, developed and undeveloped reserves, and controls related
sales of production sufficient to supply all of the remaining natural gas
required by these agreements.
<PAGE>
NOTE 3. RATE MATTERS:
The Montana Public Service Commission (MPSC) issued an order approving
electric and natural gas rate increases for the Company totaling $13,400,000
annually effective April 28, 1994. In October 1993, $12,800,000 of annual
increases were included in rates on an interim basis. In its updated
application, the Company had requested general rate increases of
$37,600,000 annually for electricity and natural gas based upon a 12.25%
return on common equity.
The MPSC allowed the Company a $7,600,000 annual electric rate increase,
down from the interim increase of $8,800,000 and an annual natural gas rate
increase of $5,800,000, up from the interim increase of $4,000,000.
The order reduced the Company's authorized return on common equity from
12.1% to 11.0% for both the electric and natural gas utilities. Of the
$24,100,000 difference between the requested amount and allowed increases,
$11,100,000 is attributable to the lower return on common equity. Another
$7,000,000 of the difference is attributable to the disallowance of certain
fuel expense relating to the MPSC's imputed "excess profits" earned by the
Company's subsidiary, Western Energy Company, on coal sales to the Utility
Division. The remaining difference relates primarily to the denial of the
Company's request to switch from the flow through to the full-normalization
method of recognizing income tax expense. The income tax recognition issue
does not affect net income.
NOTE 4. LONG-TERM DEBT:
In January 1994, the Company sold $5,000,000 of Secured Medium-Term
Notes, 7.25% series due 2024. The proceeds were used to repay short-term debt
incurred to complete the refinancing of $80,000,000 of the 10% and 10-1/8%
series Pollution Control Revenue Bonds in December 1993.
NOTE 5. POSTRETIREMENT BENEFITS:
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other than Pensions" (SFAS No. 106). SFAS No. 106 requires the
accrual of the expected cost of these postretirement benefits (OPEB's) during
the employees' years of service rather than when the costs are paid.
The Company has recorded as a deferred expense the increased costs which
result from adopting SFAS No. 106 for the Utility Division. At March 31,
1994, the cumulative amount of deferred OPEB expense is $2,700,000. In its
April 28, 1994 order, the MPSC allowed the Company to recover in rates the
full OPEB cost on the accrual basis provided by SFAS No. 106, including the
continued amortization of the transition obligation liability over the
remaining 18.75-year period and the amortization of the previously deferred
amounts over a 20-year period.
On January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 112, "Employers' Accounting for Postemployment
Benefits," (SFAS No. 112) with respect to disability related benefits up to
age 65. SFAS No. 112 requires the accrual of a liability or loss contingency
for the estimated obligation for postemployment benefits. At December 31,
1993, the Company's postemployment benefit liability was estimated to be
$10,600,000, with $9,300,000 and $1,300,000 relating to regulated utility and
nonregulated operations, respectively. The utility had recorded a liability
and recovered through rates by year-end approximately $2,400,000 for
disability-related benefits. The incremental increase in 1994 consolidated
expenses due to SFAS No. 112 adoption is estimated to be $1,300,000, all of
which relates to the non-utility operations.
The Company is no longer self-insured for a significant portion of
disability-related benefits effective January 1, 1994 for utility operations
and April 1, 1994 for non-utility operations. The Company will record as a
deferred expense in 1994 the additional postemployment benefit liability of
$6,900,000 that was incurred by the utility but not recognized while self-
insured. The Company will charge a significant portion of this amount to
income and will recover it through rates within 10 years.
<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion should be read in conjunction with the management's
discussion included in the Company's Annual Report on Form 10-K for the year
ended December 31, 1993.
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.
Three Months Ended March 31, 1994 and 1993:
Net Income Per Share of Common Stock
For comparative purposes, the following table shows the breakdown of
consolidated net income per share.
Three Months Ended
March 31,
1994 1993
Utility . . . . . . . . . . . . . $ 0.46 $ 0.53
Entech. . . . . . . . . . . . . . 0.23 0.23
Independent Power Group . . . . . 0.02 0
Consolidated . . . . . . . . $ 0.71 $ 0.76
Consolidated net income for the quarter decreased as a result of reduced
natural gas and electric sales due to warmer weather and less favorable
electric wholesale market conditions in the region. The decrease in utility
sales was partially offset by increased electric and natural gas revenues
resulting from higher rates and from increased consumption resulting from
continuing growth in the number of electric and natural gas customers.
Consolidated net income also benefited from increased Independent Power Group
earnings due to higher revenues from long-term electric sales contracts.
Net income available for common stock for the quarter also decreased as
a result of an increase in preferred dividends resulting from the sale of
additional preferred shares in November 1993. Consolidated earnings per share
amounts for the period also decreased as a result of an increase in the number
of shares outstanding.
<PAGE>
Utility Operations
The following table shows changes from the previous year, in millions of
dollars, in utility revenues with the related percentage changes in volumes
sold and prices received:
Electric
General Business - revenue. . . . . . . . $ 1
- volume . . . . . . . . 0
- price/kWh. . . . . . . 1%
Other utilities - revenue. . . . . . . . $ (6)
- volume . . . . . . . . (6%)
- price/kWh. . . . . . . (14%)
Natural Gas
General Business - revenue. . . . . . . . $ (4)
- volume . . . . . . . . (16%)
- price/Mcf. . . . . . . 7%
Other utilities - revenue. . . . . . . . $ (2)
- volume . . . . . . . . (80%)
- price/Mcf. . . . . . . (12%)
Transportation - revenue. . . . . . . . $ 1
- volume . . . . . . . . 10%
- price/Mcf. . . . . . . 23%
Operating Revenues
Electric revenues from general business customers increased $800,000.
The weather, as measured by heating degree days, was 15% warmer than the first
quarter of 1993. Volumes sold to residential and commercial customers
decreased 4% primarily as a result of the warmer weather decreasing revenues
$2,200,000. A 4% increase in volumes sold to industrial customers increased
revenues $1,400,000. A 1% increase in average rates resulting primarily from
the interim rate order effective in October 1993 raised revenues $1,600,000.
Electric revenues from sales to other utilities decreased $5,600,000 due
to a 14% decrease in the average price and a 6% decrease in volumes sold. The
decreases occurred as a result of a temporary decline in the secondary market
resulting from a weather related reduction in demand in the region during the
quarter and as a result of better than average market conditions experienced
in the first quarter of 1993.
Natural gas revenues from general business customers decreased
$3,600,000. Volumes sold to residential and commercial customers decreased
12% primarily as a result of the warmer weather decreasing revenues
$4,200,000. Volumes sold to industrial, government and municipal customers
decreased 56% decreasing revenues $1,500,000. This decline results from the
switch of eligible customers (non-core customers) from full-service to
transportation service only and is offset by revenues from transportation
fees, lower purchased gas costs and increased revenues from core customers.
Rate increases, including the final stage of the natural gas transportation
order which became effective September 1993 and the interim rate order
effective in October 1993 increased revenues $2,100,000.
Natural gas revenues from sales to other utilities declined $1,800,000
due to an 80% decrease in volumes sold also resulting from the switch by some
customers from full-service to transportation service only. As previously
discussed, the decline in revenues resulting from this switch to
transportation service is offset by revenues from transportation fees, lower
purchased gas costs and increased revenues from core customers.
Operating Expenses and Taxes
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation, and Maintenance) for
the quarters ended March 31, 1994 and 1993.
1994 1993
Sources MWH
Hydroelectric . . . . . . 896,676 751,192
Steam . . . . . . . . . . 1,290,822 1,330,724
Purchases . . . . . . . . 828,006 1,009,957
Total Power Supply. . . 3,015,504 3,091,873
Thousands of Dollars
Hydroelectric (including.
maintenance). . . . . . $ 4,398 $ 4,237
Steam (including fuel and
maintenance). . . . . . 14,797 13,737
Purchases . . . . . . . . 26,895 31,297
Power Supply Expenses
Total. . . . . . . . $ 46,090 $ 49,271
Cents per Kilowatt-Hour 1.528 1.594
The Company's hydroelectric output increased as a result of improved
streamflows. This increased output and the reduced demand, which was caused
by warmer weather and a less favorable wholesale market, offset a reduction of
generation at the Company's coal-fired plants and resulted in reduced purchase
power requirements.
Purchase gas expense decreased $3,900,000 as a result of an 18% decrease
in volumes of purchased and royalty (Company owned) gas due to the warmer
weather and as a result of deferred gas accounting adjustments which annually
balance the gas costs collected from customers with the costs of supplying the
gas. Since changes in expense resulting from the deferred gas accounting
procedure are offset by similar changes in natural gas revenues, net income is
not affected.
Taxes - other than income taxes increased $1,500,000 primarily due to
increased property taxes resulting from higher mill levies and property
additions.
Interest on long-term debt decreased $1,100,000 primarily as a result of
the 1993 refinancing of First Mortgage Bonds and Pollution Control Revenue
Bonds at lower interest rates.
Entech Operations
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of revenues of Entech's businesses
with the related percentage changes in volumes sold and prices received:
Coal - revenue. . . . . . . . $ 10
- volume . . . . . . . . 11%
- price/ton. . . . . . . 4%
Oil - revenue. . . . . . . . $ (3)
- volume . . . . . . . . (18%)
- price/bbl. . . . . . . (30%)
Natural Gas - revenue. . . . . . . . $ 0
- volume . . . . . . . . 2%
- price/Mcf. . . . . . . 9%
Natural gas marketing revenue . . . . . . $ (1)
Other operations revenue. . . . . . . . . $ (1)
Revenues
Coal revenues at the Rosebud Mine increased $1,800,000 due to higher
volumes sold to Colstrip Units 3 and 4 and the timing of purchases by a
Midwestern customer. In addition, revenues from a combination of brokered
coal and SynCoal demonstration plant operating fees increased $1,100,000. At
the Jewett Mine, coal revenues increased $2,700,000 due to higher volumes sold
to the mine-mouth power plant, which was partially reduced by a $1,000,000
decrease from lower reimbursable mining expenses. Increased revenues of
$5,700,000 at the Golden Eagle Mine resulted from higher volumes sold to
supply coal for a short-term contract and spot market sales at higher market
prices. In July 1994, the Golden Eagle Mine will begin delivering up to
1,200,000 tons of coal per year under a long-term contract.
Oil revenues decreased $2,800,000 from both lower market prices received
and lower volumes sold as a result of natural declining production in both the
U.S. and Canada. Natural gas revenues increased $300,000 principally from
higher market prices received in Canada and from higher volumes sold in the
U.S. as a result of development drilling that occurred in 1993. Natural gas
marketing revenues decreased $1,200,000 due to the timing of purchases by a
cogeneration facility and the expiration of a short-term supply contract in
1993.
Revenues from Entech's other operations decreased $1,200,000. This
resulted from the sale of the waste management operations in May 1993,
partially offset by increased revenues from telecommunications operations
resulting from expansion of services provided to common carriers and increased
marketing efforts.
Costs and Expenses
Cost of sales increased approximately $3,100,000. This amount is
comprised of $5,500,000 of increased coal production costs at the Golden Eagle
Mine due to higher volumes sold as described above, offset partially by
$2,100,000 decreased oil production costs and lower volumes of natural gas
purchased for resale. Other income-net decreased approximately $1,200,000 as
a result of losses on the sale of nonstrategic Oil Division assets and from
joint venture losses.
Independent Power Group Operations
Independent Power Group (IPG) revenues increased $2,200,000 due to a
$1,700,000 increase in revenues from long-term sales contracts caused by
higher prices and increased volumes sold. Revenues from North American Energy
Services Company (NAES) increased $500,000.
IPG expenses increased $2,700,000 primarily as a result of increases in
NAES expenses, income taxes and fuel expense. The increases were offset by
$1,400,000 resulting from decreases in transmission expense and IPG's share of
partnerships' earnings.
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements, long-term debt maturities and
sources of funds for the period 1994-1998 have been discussed in the Company's
Annual Report on Form 10-K for the year ended December 31, 1993. During the
first three months of 1994, $23,000,000 was expended for the Utility
construction program, $11,000,000 for Entech capital expenditures and
$3,000,000 for IPG capital expenditures. Due to a deferral of an item beyond
1994, total 1994 capital expenditures for the Utility have been revised to be
approximately $129,000,000.
During the first quarter of 1994, the Company sold $5,000,000 of Secured
Medium-Term Notes, 7.25% series due 2024. The proceeds were used to repay
short-term debt incurred to complete the refinancing of $80,000,000 of the 10%
and 10-1/8% series Pollution Control Revenue Bonds in December 1993.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. At March 31, 1994, the
unfunded net property additions and retired bonds test, which is the most
restrictive test, would have permitted the issuance of approximately
$500,000,000 additional First Mortgage Bonds. There are no material
restrictions upon issuance of unsecured debt or preferred stock in the
Company's Restated Articles of Incorporation, its Mortgage and Deed of Trust
or its Sinking Fund Debenture Agreement.
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended March 31, 1994 the Company's ratio of
earnings to fixed charges was 2.87 times. Fixed charges include interest, the
implicit interest of the Colstrip Unit 4 rentals and one-third of all other
rental payments.
RATE ORDER DECISION
The Company is evaluating the results of the recent MPSC rate order
discussed in Note 3. Parties to that proceeding have approximately 10 days to
file a request for reconsideration of the issues. The Company has requested
an extension of the filing deadline and is reviewing whether to ask for
reconsideration of the $7,000,000 fuel expense disallowance as well as other
issues. Additionally, the Company is analyzing this decision to determine
whether it should file another rate increase request this year, as well as the
degree of impact this rate result will have on our budgeted expenditures for
1994.
<PAGE>
PART II
Other Information
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended March 31,
1994.
(b) Reports on Form 8-K
None<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE MONTANA POWER COMPANY
(Registrant)
/s/ W. C. Verbael
W. C. Verbael
Vice President - Accounting,
Finance and Information Services
Date: May 12, 1994
<PAGE>
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended March 31, 1994
EXHIBIT 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
March 31, 1994
------------------
Net Income $106,357
Income Taxes 53,399
----------
$159,756
----------
Fixed Charges:
Interest $ 46,951
Amortization of Debt Discount,
Expense and Premium 1,763
Rentals 36,608
----------
$ 85,322
----------
Earnings Before Income Taxes
and Fixed Charges $245,078
==========
Ratio of Earnings to Fixed Charges 2.87 X
==========
