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, 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 August 5, 1994, the Company had 53,296,965 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>
June 30, December 31,
1994 1993
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $60,483 and $38,966
plant under construction)
Electric. . . . . . . . . . . . . . . . . . . . . . . . $ 1,559,413 $ 1,514,472
Natural gas . . . . . . . . . . . . . . . . . . . . . . 435,818 428,956
1,995,231 1,943,428
Less - accumulated depreciation and depletion . . . . . . 595,617 572,141
1,399,614 1,371,287
ENTECH PROPERTY (includes $7,018 and $2,446
property under construction). . . . . . . . . . . . . . 530,682 526,692
Less - accumulated depreciation and depletion . . . . . . 188,855 182,129
341,827 344,563
INDEPENDENT POWER GROUP PROPERTY (includes $1,009 and
$84 property under construction). . . . . . . . . . . . 71,492 70,198
Less - accumulated depreciation . . . . . . . . . . . . . 17,863 16,822
53,629 53,376
1,795,070 1,769,226
MISCELLANEOUS INVESTMENTS (at cost):
Miscellaneous special funds . . . . . . . . . . . . . . . 3,035 7,811
Investment in cogeneration projects . . . . . . . . . . . 47,035 45,494
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 51,695 51,492
101,765 104,797
CURRENT ASSETS:
Cash and temporary cash investments . . . . . . . . . . . 8,222 11,604
Accounts receivable . . . . . . . . . . . . . . . . . . . 123,611 158,352
Materials and supplies (principally at average cost). . . 46,442 42,728
Prepayments and other assets. . . . . . . . . . . . . . . 67,512 44,425
245,787 257,109
DEFERRED CHARGES:
Advanced coal royalties . . . . . . . . . . . . . . . . . 22,435 20,905
Costs deferred to future operating periods. . . . . . . . 195,436 185,151
Other deferred charges. . . . . . . . . . . . . . . . . . 51,375 48,839
269,246 254,895
$ 2,411,868 $ 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
June 30, December 31,
1994 1993
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 53,089,610 and
52,498,896 shares issued) . . . . . . . . . . . . . . $ 655,857 $ 642,926
Retained earnings and other shareholders' equity. . . . 304,260 302,725
Unallocated Stock held by Trustee for Deferred
Savings and Employee Stock Ownership Plan . . . . . . (33,520) (34,419)
926,597 911,232
Preferred stock . . . . . . . . . . . . . . . . . . . . . 101,416 101,419
Long-term debt. . . . . . . . . . . . . . . . . . . . . . 575,584 571,870
1,603,597 1,584,521
CURRENT LIABILITIES:
Short-term borrowing. . . . . . . . . . . . . . . . . . . 62,061 68,865
Long-term debt - portion due within one year. . . . . . . 25,857 26,199
Dividends payable . . . . . . . . . . . . . . . . . . . . 23,055 22,835
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 1,189 4,927
Other taxes . . . . . . . . . . . . . . . . . . . . . . . 42,953 43,743
Accounts payable. . . . . . . . . . . . . . . . . . . . . 46,393 55,794
Interest accrued. . . . . . . . . . . . . . . . . . . . . 11,437 11,942
Other current liabilities . . . . . . . . . . . . . . . . 98,885 79,162
311,830 313,467
DEFERRED CREDITS:
Deferred income taxes . . . . . . . . . . . . . . . . . . 316,152 309,780
Investment tax credit . . . . . . . . . . . . . . . . . . 49,586 50,476
Accrued mining reclamation costs. . . . . . . . . . . . . 104,979 101,817
Other deferred credits. . . . . . . . . . . . . . . . . . 25,724 25,966
496,441 488,039
CONTINGENCIES AND COMMITMENTS (Note 2)
$ 2,411,868 $ 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 Six Months Ended
June 30, June 30,
1994 1993
Thousands of Dollars
<S> <C> <C>
UTILITY OPERATIONS:
Operating Revenues:
Electric. . . . . . . . . . . . . . . . . . . . . . . . $ 207,884 $ 208,374
Natural gas . . . . . . . . . . . . . . . . . . . . . . 56,180 60,532
264,064 268,906
Operating Expenses and Taxes:
Operation . . . . . . . . . . . . . . . . . . . . . . . 101,636 105,124
Purchased gas . . . . . . . . . . . . . . . . . . . . . 10,659 15,744
Fuel for electric generation. . . . . . . . . . . . . . 16,470 14,223
Maintenance . . . . . . . . . . . . . . . . . . . . . . 19,929 19,874
Depreciation and depletion. . . . . . . . . . . . . . . 24,042 23,029
Taxes - other than income taxes . . . . . . . . . . . . 27,898 25,444
Income taxes. . . . . . . . . . . . . . . . . . . . . . 16,369 16,478
217,003 219,916
Operating Income. . . . . . . . . . . . . . . . . . . . . 47,061 48,990
Other Income and Expenses:
Interest and dividend income and other. . . . . . . . . 1,628 601
Income taxes applicable to other. . . . . . . . . . . . (8) 6
1,620 607
Interest Charges:
Interest on long-term debt. . . . . . . . . . . . . . . 20,367 22,168
Other interest. . . . . . . . . . . . . . . . . . . . . 878 962
21,245 23,130
Income from Utility Operations. . . . . . . . . . . . . 27,436 26,467
ENTECH OPERATIONS:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . 201,845 190,773
Costs and Expenses:
Cost of sales . . . . . . . . . . . . . . . . . . . . . 114,196 112,758
Taxes - other than income taxes . . . . . . . . . . . . 19,982 17,073
Depreciation and depletion. . . . . . . . . . . . . . . 16,778 15,763
Selling, general and administrative . . . . . . . . . . 20,474 19,288
Interest. . . . . . . . . . . . . . . . . . . . . . . . 665 1,248
Other income - net. . . . . . . . . . . . . . . . . . . 596 (102)
Income taxes. . . . . . . . . . . . . . . . . . . . . . 7,555 6,326
180,246 172,354
Income from Entech Operations . . . . . . . . . . . . . 21,599 18,419
INDEPENDENT POWER GROUP OPERATIONS:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . 65,711 61,686
Expenses (including interest and income taxes). . . . . . 64,859 61,542
Income from Independent Power Group Operations. . . . . 852 144
CONSOLIDATED NET INCOME . . . . . . . . . . . . . . . . . . 49,887 45,030
DIVIDENDS ON PREFERRED STOCK. . . . . . . . . . . . . . . . 3,614 1,895
NET INCOME AVAILABLE FOR COMMON STOCK . . . . . . . . . . . $ 46,273 $ 43,135
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) . . . . . 52,876 51,796
NET INCOME PER SHARE OF COMMON STOCK. . . . . . . . . . . . $ 0.88 $ 0.83
DIVIDENDS DECLARED ON COMMON STOCK, PER SHARE . . . . . . . $ 0.80 $ 0.79
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
June 30, June 30,
1994 1993
Thousands of Dollars
<S> <C> <C>
UTILITY OPERATIONS:
Operating Revenues:
Electric. . . . . . . . . . . . . . . . . . . . . . . . $ 85,259 $ 81,348
Natural gas . . . . . . . . . . . . . . . . . . . . . . 18,854 18,895
104,113 100,243
Operating Expenses and Taxes:
Operation . . . . . . . . . . . . . . . . . . . . . . . 45,108 45,367
Purchased gas . . . . . . . . . . . . . . . . . . . . . 3,434 4,587
Fuel for electric generation. . . . . . . . . . . . . . 7,014 5,233
Maintenance . . . . . . . . . . . . . . . . . . . . . . 12,082 12,866
Depreciation and depletion. . . . . . . . . . . . . . . 12,000 11,451
Taxes - other than income taxes . . . . . . . . . . . . 13,748 12,836
Income taxes. . . . . . . . . . . . . . . . . . . . . . 450 (1,077)
93,836 91,263
Operating Income. . . . . . . . . . . . . . . . . . . . . 10,277 8,980
Other Income and Expenses:
Interest and dividend income and other. . . . . . . . . 1,350 563
Income taxes applicable to other. . . . . . . . . . . . 31 (37)
1,381 526
Interest Charges:
Interest on long-term debt. . . . . . . . . . . . . . . 10,110 10,848
Other interest. . . . . . . . . . . . . . . . . . . . . 386 393
10,496 11,241
Income (Loss) from Utility Operations . . . . . . . . . 1,162 (1,735)
ENTECH OPERATIONS:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . 91,910 86,200
Costs and Expenses:
Cost of sales . . . . . . . . . . . . . . . . . . . . . 52,841 54,513
Taxes - other than income taxes . . . . . . . . . . . . 8,510 6,229
Depreciation and depletion. . . . . . . . . . . . . . . 8,196 7,208
Selling, general and administrative . . . . . . . . . . 9,692 8,969
Interest. . . . . . . . . . . . . . . . . . . . . . . . 350 799
Other income - net. . . . . . . . . . . . . . . . . . . (669) (154)
Income taxes. . . . . . . . . . . . . . . . . . . . . . 3,218 1,913
82,138 79,477
Income from Entech Operations . . . . . . . . . . . . . 9,772 6,723
INDEPENDENT POWER GROUP OPERATIONS:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . 35,260 33,431
Expenses (including interest and income taxes). . . . . . 35,485 33,434
Income (Loss) from Independent Power Group Operations . (225) (3)
CONSOLIDATED NET INCOME . . . . . . . . . . . . . . . . . . 10,709 4,985
DIVIDENDS ON PREFERRED STOCK. . . . . . . . . . . . . . . . 1,807 948
NET INCOME AVAILABLE FOR COMMON STOCK . . . . . . . . . . . $ 8,902 $ 4,037
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) . . . . . 53,009 51,903
NET INCOME PER SHARE OF COMMON STOCK. . . . . . . . . . . . $ 0.17 $ 0.08
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 Six Months Ended
June 30, June 30,
1994 1993
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . $ 49,887 $ 45,030
Noncash charges (credits) to net income:
Depreciation and depletion . . . . . . . . . . . . . 42,272 40,624
Mining reclamation costs expensed. . . . . . . . . . 7,385 5,554
Deferred income taxes. . . . . . . . . . . . . . . . 1,694 4,985
Amortization of loss on long-term sale
of power . . . . . . . . . . . . . . . . . . . . . (2,113) (2,626)
Other - net. . . . . . . . . . . . . . . . . . . . . 13,235 12,238
Changes in other assets and liabilities. . . . . . . . (20,842) (36,035)
Accounts receivable. . . . . . . . . . . . . . . . . . 34,741 36,240
Materials and supplies . . . . . . . . . . . . . . . . (3,714) (5,462)
Accounts payable . . . . . . . . . . . . . . . . . . . (9,402) (2,053)
Payment of mining reclamation costs. . . . . . . . . . (4,223) (2,558)
Net Cash Flows from Operating Activities . . . . . . 108,920 95,937
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Miscellaneous special funds. . . . . . . . . . . . . . 4,776 9,740
Gross additions to property and plant. . . . . . . . . (81,742) (64,431)
Investments in other operations. . . . . . . . . . . . (1,256) (547)
Sales of property. . . . . . . . . . . . . . . . . . . 3,127 5,830
Additional investments . . . . . . . . . . . . . . . . (286) 2,510
Net Cash Flows from Investing Activities . . . . . . (75,381) (46,898)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock. . . . . . . . . . . . . . . . . 12,912 11,378
Issuance of long-term debt . . . . . . . . . . . . . . 23,760 181,050
Retirement of long-term debt . . . . . . . . . . . . . (20,991) (200,464)
Short-term debt. . . . . . . . . . . . . . . . . . . . (6,803) 7,264
Note payable cogeneration project. . . . . . . . . . . 0 (7,605)
Dividends on common and preferred stock. . . . . . . . (45,799) (42,728)
Net Cash Flows from Financing Activities . . . . . . (36,921) (51,105)
Net Cash Flows . . . . . . . . . . . . . . . . . . (3,382) (2,066)
Cash and cash equivalents at beginning of period . . . . 11,604 8,879
Cash and cash equivalents at end of period . . . . . . . $ 8,222 $ 6,813
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Six Months For:
Income taxes . . . . . . . . . . . . . . . . . . . . $ 27,009 $ 28,866
Interest . . . . . . . . . . . . . . . . . . . . . . 22,528 25,442
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 June 30, 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. The Utility sells electricity to the IPG and the IPG
sells electricity to the Utility. These intercompany transactions are
included in the Consolidated Statement of Income as revenues and expenses and
were as follows:
Six Months Ended Three Months Ended
June 30, June 30, June 30, June 30,
1994 1993 1994 1993
Thousands of Dollars Thousand of Dollars
Coal sales to:
Utility . . . $13,771 $12,986 $5,835 $3,949
IPG . . . . . 5,929 3,693 2,338 770
Electric sales:
Utility sales
to IPG. . . $ 644 $ 1,885 $ 629 $1,855
IPG sales to
Utility . . 1,133 909 876 35
NOTE 2. CONTINGENCIES AND COMMITMENTS:
In 1990, the Company filed with the Federal Energy Regulatory
Commission (FERC) a plan to mitigate damages to, and to 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. As part of its review, the FERC, on May 31,
1994, issued a draft environmental assessment of the impacts associated with
the operation of Kerr. The FERC is expected to issue a draft environmental
impact statement later this year with a comment period. While the Company
cannot predict when or in what form the Plan finally will be approved, the
cost of mitigation measures is expected to be recovered through rates and 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 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 settled this dispute.
Additional costs above the Company's ownership share did not have a materially
adverse effect on the Company's financial condition or results of operations.
Other property owners also have made claims against the Company and the
other owners of the Colstrip Generating Units for property damages allegedly
resulting from soil-related subsidence. 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.
The coal supply agreement for Colstrip Units 1 and 2 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 June 30, 1994, 8,086,000 tons, of which 4,048,000 tons
were delivered to the Company, 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 142 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 $13,500,000
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 $7,800,000 annual electric rate increase,
down from the interim increase of $8,800,000 and an annual natural gas rate
increase of $5,700,000, 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 (WECo), 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.
On June 17, 1994, the Company filed a complaint requesting the District
Court, Butte-Silver Bow County, to set aside that portion of the MPSC's
decision which disallows the fuel expense relating to WECo's imputed "excess
profits." A decision at the district court level is expected before the end
of the year. The Company expects to file an electric rate case in the third
quarter of this year.
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.
In June 1994, the Company sold $20,000,000 of Secured Medium-Term Notes,
7.2% series, due 2000, the proceeds of which were used to retire other
long-term debt.
NOTE 5. POSTEMPLOYMENT 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.
In its April 28, 1994 Order, the MPSC allowed the Company to include in
rates the full OPEB cost on the accrual basis provided by SFAS No. 106,
including the amortization of the amounts previously deferred under an MPSC
Accounting Order from January 1, 1993 to April 27, 1994. Consequently, as of
April 28, 1994, the Company commenced recognition of these utility
postretirement benefits in expense in accordance with SFAS No. 106. The
incremental increase in 1994 consolidated expenses due to the utility SFAS
No. 106 expense recognition is estimated to be $900,000.
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 postemployment benefit liability for regulated utility operations
was estimated to be $9,300,000, of which $2,400,000 had been accrued and
included in rates. The remaining $6,900,000 was recorded in 1994 as a
deferred charge and will be expensed and included in rates over the next 10
years. The estimated December 31, 1993 postemployment benefit liability of
$1,300,000 for non-utility operations has been charged to income in 1994. The
Company is no longer self-insured for disability-related benefits resulting
from claims occurring after December 31, 1993, therefore, SFAS No. 112 will
not apply to benefits after that date.
<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.
Six Months Ended June 30, 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.
Six Months Ended
June 30,
1994 1993
Utility Operations $ 0.45 $ 0.47
Entech 0.41 0.36
Independent Power Group 0.02
Consolidated $ 0.88 $ 0.83
Year-to-date consolidated net income increased due to increased coal
sales. Decreases in utility income resulted from warmer weather, the
wholesale market conditions and increased property taxes. Increased electric
industrial loads, reduced purchased power costs and additional revenues from
rate increases and customer growth were positive factors which offset most of
the decrease. Year-to-date Independent Power Group (IPG) earnings increased
as a result of improved generating plant performance.
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. . . . . . . . $ 5
- volume . . . . . . . . 2%
- price/kWh. . . . . . . 1%
Other Utilities - revenue. . . . . . . . $ (6)
- volume . . . . . . . . (7%)
- price/kWh. . . . . . . (9%)
Natural Gas
General Business - revenue. . . . . . . . $ (4)
- volume . . . . . . . . (13%)
- price/Mcf. . . . . . . 7%
Other Utilities - revenue. . . . . . . . $ (3)
- volume . . . . . . . . (81%)
- price/Mcf. . . . . . . (12%)
Transportation - revenue. . . . . . . . $ 2
- volume . . . . . . . . 33%
- price/Mcf. . . . . . . 33%
Operating Revenues
Electric revenues from general business customers increased $4,600,000
including revenues from industrial customers which increased $2,900,000.
Industrial revenues increased as a result of customers installing additional
equipment and due to increased demand for irrigation resulting from the dry
weather conditions. Residential and commercial customer growth provided
approximately $2,400,000 of the additional revenues and higher rates increased
revenues $1,700,000. These increases were partially offset by a $2,400,000
decrease in residential and commercial revenues resulting from decreased
volumes sold due primarily to warmer weather. The weather, as measured by
heating degree days, was 14% warmer than last year.
Electric revenues from sales to other utilities decreased $6,100,000 due
to a 7% reduction in volumes sold and a 9% decrease in the average price. The
decrease resulted primarily from the return to near-normal secondary market
conditions in 1994 compared to much better than average market conditions in
the first six months of 1993. Sales to the IPG, which are included in utility
revenues, also decreased due to less demand resulting from improved generating
plant performance at Colstrip Unit 4.
Natural gas revenues from general business customers decreased
$3,600,000. Volumes sold to residential and commercial customers decreased
more than 9% due primarily to the warmer weather, reducing revenues
$6,600,000. Customer growth of 4.5% and higher rates provided additional
revenues of $2,100,000 and $3,200,000, respectively. Volumes sold to
industrial, government and municipal customers decreased 56% decreasing
revenues $2,300,000. 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 and lower purchased
gas costs.
Natural gas sales to other utilities decreased 81%, or $2,800,000, due
to switching by some customers from full-service to transportation service
only. As previously discussed, this reduction is offset by transportation
fees and lower gas purchase costs.
Other natural gas revenues increased $2,100,000 due primarily to
$1,700,000 in additional transportation revenues resulting from a 33% increase
in both volumes transported and average price.
Operating Expenses and Taxes
The following table shows the electric utility's sources of electricity
and power supply expenses (Operation, Fuel for electric generation and
Maintenance) for the six months ended June 30, 1994 and 1993.
1994 1993
Sources MWH
Hydroelectric 1,778,415 1,658,731
Steam 2,223,611 1,936,779
Purchases 1,318,447 1,781,573
Total Power Supply 5,320,473 5,377,083
Thousands of Dollars
Hydroelectric (including
maintenance) $ 9,002 $ 8,606
Steam (including fuel and
maintenance) 30,076 27,696
Purchases 42,715 49,922
Total Power Supply
Expenses $ 81,793 $ 86,224
Cents Per Kilowatt-Hour 1.537 1.604
Steam generation and related fuel expense increased as a result of
improved performance at the Colstrip units which experienced outages in 1993.
The increased generation and a less favorable secondary market for sales to
other utilities resulted in reduced purchased power requirements. The slight
increase in hydroelectric generation is the result of improved streamflows
caused by earlier snowpack melt.
Operation expense other than power supply costs increased due to
additional pension expenses, the Colstrip housing damage costs and increased
amortization of conservation programs.
Purchased gas expense decreased $5,100,000 as a result of a 19% decrease
in volumes of gas due to the warmer weather and the decrease resulting from
customers switching to transportation service. Purchased gas expense also
decreased as a result of the balancing of deferred gas accounting procedures
which do not affect net income.
Taxes - other than income taxes increased $2,500,000 primarily due to
increased property taxes resulting from higher mill levies and property
additions.
Interest Charges
The $1,800,000 decrease in interest on long-term debt is primarily a
result of refinancing of debt 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 units with
the related percentage changes in volumes sold and prices received:
Coal - revenue. . . . . . . . $ 27
- volume . . . . . . . . 23%
- price/ton. . . . . . . 2%
Oil - revenue. . . . . . . . $ (5)
- volume . . . . . . . . (16%)
- price/bbl. . . . . . . (24%)
Natural Gas - revenue. . . . . . . . $ 1
- volume . . . . . . . . 8%
- price/Mcf. . . . . . . -
Natural gas marketing revenue . . . . . . $(10)
Other operations revenue. . . . . . . . . $ (2)
Revenues
Coal revenues at the Rosebud Mine increased $15,000,000 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 coal transportation fees increased $2,000,000. At the Jewett Mine,
coal revenues increased $2,300,000 due to higher volumes sold to the
mine-mouth power plant. These revenues were partially reduced by $1,400,000
of lower fees because less of the Company's coal and more of the customer's
coal was mined in 1994. Increased revenues of $9,500,000 at the Golden Eagle
Mine were the result of higher volumes sold and higher market prices received
to supply coal for a short-term contract and spot market sales. In July 1994,
the Golden Eagle Mine began delivering coal under a long-term contract which
provides for delivery of up to 1,200,000 tons of coal per year.
Oil revenues decreased $4,700,000 from both lower market prices received
and lower volumes sold as a result of normal declining production. Natural
gas revenues increased $900,000 from higher volumes sold in both the U.S. and
Canada as a result of development drilling that occurred in 1993. Natural gas
marketing revenues decreased $10,400,000 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 $2,200,000 mostly as a
result of the sale of the waste management operations in May 1993.
Costs and Expenses
Cost of sales increased $1,400,000. This amount is comprised of
$13,300,000 increased coal production costs at the Golden Eagle and Rosebud
mines due to higher volumes sold as described above, partially offset by
$10,500,000 decreased costs of natural gas purchased for resale and by
$1,400,000 decreased costs from the sale of the waste management operation.
Higher volumes of coal sold caused the increase in taxes - other than income
taxes. Interest expense decreased due to lower levels of outstanding debt.
Income taxes reflect the tax rate increase in 1993 and higher pre-tax income
principally from the coal operations.
Independent Power Group Operations
IPG revenues increased $4,000,000 due principally to an increase in
revenues from long-term sales contracts caused by higher prices and increased
volumes sold.
IPG expenses increased $3,300,000 due primarily to increased operation
and maintenance expenses related to electric generation at Colstrip Unit 4.
Three Months Ended June 30, 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
June 30,
1994 1993
Utility Operations $ (0.01) $ (0.05)
Entech 0.18 0.13
Independent Power Group
Consolidated $ 0.17 $ 0.08
Consolidated net income for the quarter increased as a result of
increased coal deliveries to the Colstrip generating units which experienced
outages last year and increased electric and natural gas revenues resulting
from customer growth and rate increases. The utility increases were partially
offset by the impacts of warmer weather on natural gas sales and less
favorable electric wholesale market conditions.
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:
<PAGE>
Electric
General Business - revenue. . . . . . . . $ 4
- volume . . . . . . . . 5%
- price/kWh. . . . . . . -
Other Utilities - revenue. . . . . . . . $ (1)
- volume . . . . . . . . (10%)
- price/kWh. . . . . . . 5%
Natural Gas
General Business - revenue. . . . . . . . $ -
- volume . . . . . . . . (7%)
- price/Mcf. . . . . . . 7%
Other Utilities - revenue. . . . . . . . $ (1)
- volume . . . . . . . . (83%)
- price/Mcf. . . . . . . (9%)
Transportation - revenue. . . . . . . . $ 1
- volume . . . . . . . . 68%
- price/Mcf. . . . . . . 15%
Operating Revenues
Electric revenues from general business customers increased $3,900,000
including revenues from industrial customers which increased $1,600,000.
Equipment installations and dry weather conditions as explained in the
six-month discussion were the primary factors increasing industrial volumes.
Residential and commercial customer growth and higher rates contributed
additional revenues of approximately $1,600,000.
Electric revenues from sales to other utilities decreased $600,000 due
to a 10% reduction in volumes sold. The decrease resulted primarily from
reduced sales to the IPG as explained in the six-month discussion.
The decrease of $2,600,000 in natural gas revenues resulting from warmer
weather and customers' switch from full-service to transportation service only
was offset by the additional revenues provided by 4.6% customer growth, rate
increases and increased transportation revenues. Weather for the quarter, as
measured by heating degree days, was 10% warmer than last year.
Operating Expenses and Taxes
The following table shows the electric utility's sources of electricity
and power supply expenses (Operation, Fuel for electric generation and
Maintenance) for the three months ended June 30, 1994 and 1993.
<PAGE>
1994 1993
Sources MWH
Hydroelectric 881,739 907,539
Steam 932,789 606,055
Purchases 490,441 771,616
Total Power Supply 2,304,969 2,285,210
Thousands of Dollars
Hydroelectric (including
maintenance) $ 4,604 $ 4,369
Steam (including fuel and
maintenance) 15,279 13,959
Purchases 15,817 18,625
Total Power Supply
Expenses $ 35,700 $ 36,953
Cents Per Kilowatt-Hour 1.549 1.617
Steam generation and related fuel expense increased as a result of
improved performance at the Colstrip units which experienced outages in 1993.
The large increase in steam generation resulted in reduced purchased power
requirements. In spite of drought conditions in the region, hydroelectric
generation decreased only slightly due to an earlier snowpack melt resulting
from warmer weather.
Operation expense other than power supply costs increased due to the
same reasons explained in the six-month discussion.
Purchased gas expense decreased $1,100,000 as a result of a 12% decrease
in volumes of gas due to the warmer weather and the decrease resulting from
customers' switch to transportation service. Purchased gas expense for the
quarter also decreased as a result of the balancing of deferred gas accounting
procedures which do not affect net income.
<PAGE>
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 units with
the related percentage changes in volumes sold and prices received:
Coal - revenue. . . . . . . . $ 17
- volume . . . . . . . . 40%
- price/ton. . . . . . . (1%)
Oil - revenue. . . . . . . . $ (2)
- volume . . . . . . . . (14%)
- price/bbl. . . . . . . (18%)
Natural Gas - revenue. . . . . . . . $ 1
- volume . . . . . . . . 13%
- price/Mcf. . . . . . . (8%)
Natural gas marketing revenue . . . . . . $ (9)
Other operations revenue. . . . . . . . . $ (1)
Revenues
Coal revenues increased $14,100,000 at the Rosebud Mine and $3,800,000
at the Golden Eagle Mine for the same reasons mentioned in the six-month
discussion. At the Jewett Mine, coal revenues decreased $800,000 due to lower
volumes sold and lower prices received for the same reasons mentioned in the
six-month discussion.
Oil revenues decreased $2,000,000 for the same reasons mentioned in the
six-month discussion. Natural gas revenues increased $600,000 from a
combination of higher volumes sold in both the U.S. and Canada as a result of
development drilling partially offset by the effect of lower U.S. market
prices. Natural gas marketing revenues decreased $8,400,000 for the same
reasons mentioned in the six-month discussion.
Revenues from Entech's other operations decreased $1,000,000 from the
1993 sale of the waste management operation.
Costs and Expenses
Cost of sales decreased $1,600,000. This amount is comprised of
$8,500,000 decreased costs of natural gas purchased for resale and $1,000,000
lower expenses from the sale of the waste management operation. These amounts
were mostly offset by $7,900,000 higher coal production costs as described in
the six-month discussion. Taxes - other than income taxes and depreciation
and depletion increased because of higher volumes of coal sold. Interest
expense decreased due to lower levels of outstanding debt. The $500,000
increase in Other income - net resulted from the sale of assets. Income taxes
increased from higher pre-tax income principally from coal operations.
<PAGE>
Independent Power Group Operations
IPG revenues increased $1,800,000 due primarily to higher revenues from
Colstrip Unit 4 long-term sales contracts caused by higher prices and
increased volumes sold.
IPG expenses increased $2,000,000 due primarily to increased operation
and maintenance expenses related to electric generation at Colstrip Unit 4.
<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 six months of 1994, $58,000,000 was expended for the Utility
construction program, $20,400,000 for Entech capital expenditures and
$4,000,000 for IPG capital expenditures. Total 1994 capital expenditures for
the Utility have been reduced to approximately $133,000,000 from $144,000,000
due primarily to the deferral of items beyond 1994.
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.
In June 1994, the Company sold $20,000,000 of Secured Medium-Term Notes,
7.2% series, due 2000, the proceeds of which were used to retire other
long-term debt.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. At June 30, 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 June 30, 1994 the Company's ratio of
earnings to fixed charges was 3.02 times. Fixed charges include interest, the
implicit interest of the Colstrip Unit 4 rentals and one-third of all other
rental payments.
<PAGE>
PART II
Other Information
ITEM 4. Submission of Matters to a Vote of Security Holders.
A. The Company's annual meeting of shareholders was held on May 10,
1994.
B. Security holders elected five persons to the Board of Directors.
Against
Director For or Withheld Abstentions
Kay Foster 48,529,894 4 821,826
Chase T. Hibbard 48,637,941 4 713,779
Daniel P. Lambros 48,627,884 4 723,836
Carl Lehrkind III 48,656,438 4 695,282
Jerrold P. Pederson 48,667,742 683,982
There were no broker non-votes.
Directors whose term of office as a director continued after the meeting
are as follows:
Daniel T. Berube Beverly D. Harris
John J. Burke James P. Lucas
Allen F. Cain Arthur K. Neill
R. D. Corette George H. Selover
Robert P. Gannon N. E. Vosburg
C. Security holders voted to authorize the Company to redeem the
$2.15 Series of Preferred Stock.
Against
For or Withheld Abstentions
38,593,067 434,140 1,021,294
There were no broker non-votes.
<PAGE>
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 June 30,
1994.
(b) Reports on Form 8-K
Date Subject
April 25, 1994 Item No. 5. Other Items, MPSC decision on
electric and natural gas rate request. See
Note 3 to the Consolidated Financial Statements.
<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/ J. P. Pederson
J. P. Pederson
Vice President and Chief
Financial Officer
Date: August 12, 1994
<PAGE>
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended June 30, 1994
EXHIBIT 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
June 30, 1994
------------------
Net Income $113,649
Income Taxes 56,073
----------
$169,722
----------
Fixed Charges:
Interest $ 45,871
Amortization of Debt Discount,
Expense and Premium 1,727
Rentals 36,608
----------
$ 84,206
----------
Earnings Before Income Taxes
and Fixed Charges $253,928
==========
Ratio of Earnings to Fixed Charges 3.02 X
==========
