UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
________________________________________
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 1998
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _______________
________________________________________
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
________________________________________________________
(Former name, former address and former fiscal year,
if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
On November 4, 1998, the Company had 55,036,595 shares of common stock
outstanding.
<PAGE> PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
REVENUES $873,926 $ 731,661
EXPENSES:
Operations 378,637 291,040
Maintenance 60,724 64,967
Selling, general and
administrative 89,221 83,691
Taxes other than income taxes 72,582 71,919
Depreciation, depletion and
amortization 86,072 68,777
687,236 580,394
INCOME FROM OPERATIONS 186,690 151,267
INTEREST EXPENSE AND OTHER:
Interest 43,563 39,394
Distributions on mandatorily redeemable preferred
securities of subsidiary trust 4,119 4,119
Other (income) deductions - net (3,026) (13,742)
44,656 29,771
INCOME TAXES 46,813 44,298
NET INCOME 95,221 77,198
DIVIDENDS ON PREFERRED STOCK 2,768 2,768
NET INCOME AVAILABLE FOR
COMMON STOCK $ 92,453 $ 74,430
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 54,957 54,636
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 1.68 $ 1.36
FULLY DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 1.68 $ 1.36
</TABLE>
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
Quarter Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
REVENUES $315,215 $234,240
EXPENSES:
Operations 141,805 98,967
Maintenance 20,738 23,552
Selling, general and
administrative 26,284 26,490
Taxes other than income taxes 22,256 24,083
Depreciation, depletion and
amortization 31,285 24,356
242,368 197,448
INCOME FROM OPERATIONS 72,847 36,792
INTEREST EXPENSE AND OTHER:
Interest 14,662 13,958
Distributions on company obligated
mandatorily redeemable preferred
securities of subsidiary trust 1,373 1,373
Other (income) deductions - net (1,179) (1,238)
14,856 14,093
INCOME TAXES 21,188 6,458
NET INCOME 36,803 16,241
DIVIDENDS ON PREFERRED STOCK 923 923
NET INCOME AVAILABLE FOR
COMMON STOCK $ 35,880 $ 15,318
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 55,013 54,645
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.65 $ 0.28
FULLY DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.65 $ 0.28
</TABLE>
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
A S S E T S
September 30, December 31,
1998 1997
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $40,118 and $39,425
plant under construction)
Electric $ 1,833,944 $ 1,820,280
Natural gas 401,862 395,918
2,235,806 2,216,198
Less - accumulated depreciation and depletion 717,201 684,960
1,518,605 1,531,238
NONUTILITY PROPERTY (includes $33,074 and $17,259
property under construction) 856,068 781,406
Less - accumulated depreciation and depletion 295,142 260,567
560,926 520,839
2,079,531 2,052,077
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 34,922 51,534
Reclamation fund 41,004 47,312
Other 43,750 35,619
119,676 134,465
CURRENT ASSETS:
Cash and temporary cash investments 12,818 16,706
Accounts receivable 139,564 126,787
Notes receivable (Note 8) 28,590
Materials and supplies (principally at average cost) 41,321 39,471
Prepayments and other assets 54,171 49,673
Deferred income taxes 8,855 10,539
285,319 243,176
DEFERRED CHARGES:
Advanced coal royalties 16,996 16,698
Regulatory assets related to income taxes 125,514 122,903
Regulatory assets - other 146,710 158,573
Other deferred charges 76,411 73,804
365,631 371,978
$ 2,850,157 $ 2,801,696
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
September 30, December 31,
1998 1997
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 55,024,778 and
54,728,709 shares issued) $ 701,107 $ 694,561
Retained earnings and other shareholders' equity 362,081 342,973
Unallocated stock held by trustee for retirement
savings plan (23,462) (25,945)
1,039,726 1,011,589
Preferred stock 57,654 57,654
Company obligated mandatorily redeemable preferred
securities of subsidiary trust, which holds solely,
company junior subordinated debentures 65,000 65,000
Long-term debt 705,934 653,168
1,868,314 1,787,411
CURRENT LIABILITIES:
Short-term borrowing 66,921 133,958
Long-term debt - portion due within one year 60,124 81,659
Dividends payable 22,760 22,684
Income taxes 15,884 3,803
Other taxes 66,349 47,818
Accounts payable 79,937 77,821
Interest accrued 18,338 13,836
Other current liabilities 49,016 35,158
379,329 416,737
DEFERRED CREDITS:
Deferred income taxes 346,639 340,251
Investment tax credit 33,994 35,182
Accrued mining reclamation costs 128,140 131,108
Other deferred credits 93,741 91,007
602,514 597,548
CONTINGENCIES AND COMMITMENTS (Notes 2 and 5)
$ 2,850,157 $ 2,801,696
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 Nine Months Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 95,221 $ 77,198
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 86,072 70,117
Deferred income taxes 2,522 2,444
Noncash earnings from unconsolidated
independent power investments (8,765) (7,648)
Reclamation expensed and paid - net (2,968) (371)
Deferred stripping expenses and payments - net 46 (509)
Other noncash charges to net income - net 14,334 13,385
Changes in other assets and liabilities:
Accounts and notes receivable (41,367) (166)
Materials and supplies (1,850) (799)
Accounts payable 10,036 (5,077)
Other - net 44,542 (4,950)
Net cash provided by operating activities 197,823 143,624
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (104,578) (197,302)
Reclamation funding 6,308 (3,606)
Sales of property 2,735 48,407
Additional investments (8,130) (135)
Net cash used by investing activities (103,665) (152,636)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (68,662) (68,326)
Sales of common stock 6,619 529
Issuance of long-term debt 64,490 86,591
Retirement of long-term debt (33,456) (12,425)
Issuance of mandatorily redeemable preferred
securities of subsidiary trust (67)
Net change in short-term borrowing (67,037) (29,694)
Net cash used by financing activities (98,046) (23,392)
CHANGE IN CASH FLOWS (3,888) (32,404)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 16,706 32,404
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 12,818 $ -
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Nine Months For:
Income taxes $ 38,292 $ 27,614
Interest 61,692 39,964
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 September 30, 1998 and 1997 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, 1997.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1998 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1 -- DEREGULATION AND ASSET DIVESTITURE, AND OTHER REGULATORY MATTERS:
The electric and natural gas utility businesses are in transition to
competition to provide energy commodity and related services to wholesale and
retail customers. In Montana, electric and natural gas restructuring and
customer choice legislation was passed by the Montana Legislature and signed
into law in 1997. The legislation provides for choice of electricity supplier
for the Company's large customers by July 1, 1998, for pilot programs for
residential and small commercial customers which began November 2, 1998 and
choice for all customers no later than July 1, 2002.
In conjunction with the transition to competition, the Company has
entered into an agreement to sell its electric generating plants in Montana
and has transferred almost all of its Utility natural gas production assets to
an unregulated affiliate. The Company will continue to provide regulated
transmission and distribution of electricity and natural gas and will offer
natural gas supply to retail and wholesale customers through its unregulated
business segments. The Company is exiting the electric commodity trading and
marketing business.
As required by the electric legislation, the Company filed a
comprehensive transition plan with the Montana Public Service Commission (PSC)
on July 1, 1997. The filing contained the Company's transition plan,
including the proposed handling and resolution of transition costs, and
addresses other issues required by the legislation. Initial hearings on the
filing began April 26, 1998 and the issues involved in the restructuring
filing have been separated into three groups. The PSC rendered a decision on
June 24, 1998 on the issues relating to the implementation of customer choice
for the large industrial group and the pilot programs. A decision on the
remaining issues, including the amount of transition costs, the effect of the
sale of the generation assets and the Uniform Systems Benefits Charge is
expected after the sale details are final. The PSC will consider the
Company's efforts to mitigate transition costs in making its determination.
On February 20, 1998, the Company submitted a filing with the PSC
related to pilot programs for natural gas customers. The Company has reached
a settlement with many of the intervening parties in the PSC natural gas pilot
programs case. A PSC hearing was held August 5, 1998 to discuss the
settlement provisions and an order was issued on August 13, 1998. Pilot
programs began concurrently with the electric pilot program on November 2,
1998.
<PAGE>
On June 23, 1998 the PSC issued an order on portions of the Company's
Electric Utility Restructuring Transition Plan addressing customer choice
implementation, customer education, standards of conduct and functional
separation of electricity supply, retail transmission and distribution
service, and regulated and unregulated energy services. The Company filed a
request for reconsideration of portions of the standards of conduct that
address the interaction between the Company's electric transmission and
distribution departments and the Company's affiliates. This motion was denied
by the PSC on September 11, 1998. Because the Company considers portions of
these standards unlawful and/or unreasonable, the Company filed a complaint
against the PSC in District Court on October 9, 1998. The Company believes
the adopted standards go beyond the PSC's authority, are inconsistent with and
exceed the Legislative mandate, take away fundamental economic efficiency
benefits and that portions of the standards are unconstitutional. While the
Company cannot predict the ultimate resolution of this matter, the Company
does not believe it will have a material adverse impact on its financial
condition or results of operations.
The October 1997 PSC order, regarding the Company's July 1996 open-
access and natural gas restructuring filing, froze base rates for two years
and accepted the continuation of the gas cost tracker and the Gas
Transportation Clause (GTAC) procedures. On October 8, 1998, the Company
filed a request for an overall interim increase in natural gas revenues of
$2,000,000 to reflect treatment for the annual Gas Tracking/Unreflected Gas
Cost Account Balance and GTAC Balance. On November 4, 1998, the PSC approved
the Company's request which will result in a net rate increase to core gas
supply customers of approximately 2%.
On March 30, 1998, the Company submitted a filing with the Federal
Energy Regulatory Commission (FERC) requesting increased rates for bundled
wholesale electric service to two rural electric cooperatives. The filing
also included a request for increased transmission rates based upon updated
cost of service reflecting current operating costs for wholesale transmission
service and for FERC regulated transmission service for retail customers that
transition to customer choice. Resolution of this filing is expected before
the end of the second quarter of 1999.
In December 1997, the Company announced that it would offer for sale all
of its electric generating facilities in Montana, consisting of 13 hydro
projects and the Company's interest in 4 coal-fired thermal generating units,
for a total gross capacity of 1,315 megawatts. In addition, the Company
offered for sale its 242-megawatt leasehold interest in Colstrip Unit 4, its
power purchase contracts with qualifying facilities and Basin Electric Power
Cooperative (Basin), and two power exchange agreements.
On November 2, 1998, the Company announced that it had entered into a
definitive Asset Purchase Agreement (the Agreement) with PP&L Global, Inc
(PP&L Global), a subsidiary of PP&L Resources, Inc., a Pennsylvania
corporation. PP&L Global has agreed to purchase for cash the Company's
electric generating assets in Montana for a total gross capacity of 1,556
megawatts along with certain associated high-voltage transmission lines.
Under the Agreement, PP&L Global agreed to purchase the Company's
interest in 12 hydroelectric facilities, four coal-fired thermal generating
plants and a leasehold interest in Colstrip Unit 4 for a total of 1,556
megawatts. PP&L Global will also acquire the power purchase contract with
Basin Electric Power Cooperative and two power exchange agreements. The sale
does not include the power purchase contracts with qualifying facilities (QF)
or the 3-megawatt Milltown Dam near Missoula, Montana. The Company is
currently evaluating potential options with regard to the QF power purchase
contracts and the Milltown Dam. Proceeds from the sale will vary depending
upon various factors, and are anticipated to be between $740,000,000 and
$1,050,000,000.
<PAGE>
In two related transactions, PP&L Global agreed to purchase from Puget
Sound Energy, Inc. (Puget), a Washington corporation, and Portland General
Electric Company (Portland), an Oregon corporation, their respective interests
totaling 1058 MW at the four-unit Colstrip plant. The interests of Washington
Water Power and Pacific Power & Light in the Colstrip unit totaling 402 MW
were not part of this transaction.
These sales are subject to the satisfaction of various conditions and
the receipt of required regulatory approvals. The Company anticipates this
transaction will be completed by the end of 1999.
The Company expects to receive approximately $890,000,000 for the
regulated generation assets pending resolution of issues related to state
regulatory approvals for the sale of Puget and Portland's interests. Proceeds
from the sale of the Company's unregulated leasehold interest in Colstrip Unit
4 are expected to be approximately $96,000,000. The Company will recognize a
gain or loss in the Consolidated Statement of Income on the sale of the
unregulated assets depending on whether the proceeds are greater or less than
the Company's carrying value in those assets at the time the sale is
finalized.
With respect to the sale of the regulated generation assets, the Company
first expects to recover the book value of those assets, estimated to be
$550,000,000 and the costs of the sale transaction. Proceeds in excess of the
book value and transaction costs are expected to reduce the amounts to be
collected from ratepayers in the form of competitive transition charges
(CTC's). The Montana restructuring legislation, passed in 1997, provides for
the collection of CTC's by the Company in order to recover of its non-
mitigatable transition costs, specifically recovery of above-market QF power
purchase contract costs and regulatory assets associated with the generation
business, and recovery for utility-owned above-market generation costs over
the transition period of up to four years. The QF contracts could result in
above-market costs currently estimated between $300,000,000 and $500,000,000
throughout their duration. The generation regulatory assets and the above-
market generation costs over the transition period are currently estimated at
$150,000,000 and $160,000,000, respectively. The sale of the generation
assets will eliminate the above-market generation cost issue.
The regulated generation assets to be sold currently comprise
approximately $500,000,000 of the utility's plant in service upon which it is
allowed to earn a return of approximately 9 percent. Actual rate of return
earned on the Company's electric plant in service was approximately 8 percent
for the year ended December 31, 1997. However, since specific classes of
assets cannot be separated in a regulated environment with fully-bundled rates
charged to customers, the Company cannot accurately estimate the separate
results of operations for these generation assets.
Both the electric and natural gas legislation authorized the issuance of
transition bonds using a financing technique often referred to as a
securitization. The issuance of transition bonds involves the issuance of a
debt instrument, which is repaid through, and secured by, a specified component
of future revenues, thereby reducing the credit risk of the securities.
Although any transition bonds are expected to be shown as debt on the
Consolidated Balance Sheet of the Company, the bonds will be issued by a
special purpose entity and will be without recourse to the general credit of
the Company. Similarly, the right to receive the revenues pledged to secure
the bonds is a specific right of the special purpose entity and not the
Company. However, as a wholly owned subsidiary of the Company, revenues of any
special purpose entity would be shown as revenues on the Consolidated Statement
of Income of the Company. This right to receive revenues will have been
transferred to the special purpose entity issuing the bonds and will not be the
<PAGE>
property of the Company. As a result of such features, the bonds should carry
a relatively low interest rate and allow the Company, on a consolidated basis,
to carry higher debt levels in relation to equity than would otherwise be
desirable.
In November 1997, the Company filed with the PSC to request authorization
to issue up to $65,000,000 in transition bonds related to the natural gas
transition costs and bond issuance costs. In May 1998, the PSC approved the
issuance of up to $65,000,000 of transition bonds and the Company expects in
excess of $60,000,000 of bonds to be issued before the end of the first quarter
of 1999.
As a result of a three-year rate plan approved by the PSC in 1996,
electric rates increased 2.4%, or approximately $9,000,000, effective
January 1, 1998.
NOTE 2 - CONTINGENCIES:
In July 1985, the Federal Energy Regulatory Commission (FERC) issued to
the Company a new license for the 189 megawatt Kerr Project and required the
subsequent development of and adoption of a plan to mitigate the impact of
Kerr Project operations on fish, wildlife and habitat. The Company proposed a
consensus plan in June 1990 that was agreed to by the Confederated Salish and
Kootenai Tribes (Tribes) and other state and federal resource agencies. In
November 1995, the United States Department of Interior (Department) submitted
alternative conditions to those stated in the plan proposed by the Company.
On June 25, 1997, FERC issued an order (the June Order) approving a
mitigation plan, substantially adopting the Department's conditions. The
mitigation plan calls for payments totaling approximately $135,000,000 over
the 35-year term of the license. Included in the $135,000,000 is an
approximately $15,600,000 payment FERC has required the Company to make to
fund the "Fish and Wildlife Implementation Strategy" for the period between
June 25, 1985 and July 29, 1997. The net present value of the total payments,
using an assumed discount rate of 9.5%, is approximately $57,000,000, which
the Company recognized as license costs in plant and long-term debt in the
Consolidated Balance Sheet during the second quarter of 1997.
Subsequently, the Company, the Tribes and the Department requested
rehearing of the June Order. While it considered the request for rehearing,
FERC issued a stay regarding the Company's $15,600,000 payment obligation. On
October 30, 1998, FERC denied the requests for rehearing and lifted the stay
regarding the Company's obligation to make the approximately $15,600,000
payment. On November 4, 1998, the Company filed a motion with FERC seeking a
stay of this payment during an appeal of (i) FERC's June Order and (ii) FERC's
October 30, 1998 order denying the requests for rehearing and lifting the
Company's stay. On November 4, 1998, the Company petitioned the United States
Court of Appeals for the District of Columbia Circuit for judicial review of
these orders.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts (Project 2188). On September 26, 1997, FERC Staff issued a draft
environmental impact statement, recommending acceptance of most of the
measures proposed by the Company in its application. FERC staff recommended
adoption of limited additional measures. The Company analyzed the
recommendations and submitted comments. The analysis indicates that the FERC
staff's recommendations do not materially change the cost of relicensing and
proposed environmental mitigation, previously estimated to be approximately
$162,000,000 on a net present value basis. The Company expects to receive a
license order in late 1999 or early 2000.
<PAGE>
The Kerr Project and Project 2188 are assets to be transferred under the
terms of the Agreement for the Company's sale of its generation assets. At
closing of the sale, PP&L Global will assume the obligation to make payments
required to comply with the license conditions, except that the Company has
retained the obligation to make (i) the $15,600,000 payment for the Fish and
Wildlife Implementation Strategy referred to above and (ii) to the extent not
reimbursed by PP&L Global through the capital and maintenance budget to be
agreed upon by the Company and PP&L Global, other payments regarding "pre-
closing" license compliance expenditures.
Western Energy Company (Western), a subsidiary of the Company, was a
party in a dispute concerning the Coal Supply Agreement (CSA) for Colstrip
Units 3 and 4 with the non-operating owners (NOOs), other than Puget Sound
Energy (Puget). Puget withdrew from this dispute as part of an earlier
settlement concerning a power sales agreement between Puget and the Company.
During the spring of 1996, the Consumer Price Index (CPI) doubled when
compared to the CPI level at the time that the CSA was executed. Under the
terms of the CSA, this change in the CPI allows any party to seek a
modification of the coal price if that party can demonstrate an "unusual
condition" causing a "gross inequity". The NOOs asserted that a number of
"unusual conditions" had occurred, including (i) the deregulation of various
aspects of the electric utility industry, (ii) increased scrutiny of electric
utilities by their public utility commissions, and (iii) changes in economic
conditions not anticipated at the time of execution of the CSA. The NOOs
claimed these "unusual conditions" had created a "gross inequity" that had to
be remedied by a reduction in the coal price. Western did not believe that
under the terms of the contract any "unusual condition" or "gross inequity"
had occurred.
In July 1998, Western and the NOOs settled this gross inequity dispute.
The settlement provided two options from which each NOO could independently
elect. The first option provided a reduction in base price of $0.50 per ton
on tons sold from April 1996 through June 2000. The second option offered
"incentive pricing" the same as that Western offered during 1997 and the first
quarter of 1998 to stimulate sales to the Buyers. Two of the NOO's selected
the first option and the other NOO selected the second option resulting in a
third quarter 1998 reduction to Western's pre-tax earnings of approximately
$2,100,000 for coal delivered prior to June 30, 1998.
In August 1998, all of the owners of Colstrip Units 3 & 4 and Western
amended and restated the CSA and amended the Coal Transportation Agreement
(the CTA). The amended and restated CSA provides new procedures for mine
governance, dispute resolution and final reclamation. Western will receive
payment for its actual costs of mining coal for Units 3 & 4 and will earn a
return on its investment in the mine. Western will also have the opportunity
to receive incentive fees based on its ability to meet certain agreed upon
performance standards. New coal transportation fees were established in the
amendment of the CTA. The amendment and restatement of the CSA and the
amendment of the CTA resulted in a third quarter 1998 reduction to the
Company's pre-tax earnings of approximately $1,000,000 for coal delivered
prior to June 30, 1998.
Until mid-year 2000, Western will realize a modest profit reduction to
account for the gross inequity settlement and the elimination of over
collections by Western in some cost categories. The delivered coal price to
Colstrip Units 3 & 4 will be significantly reduced from current price levels
in increments beginning July 31, 2000 and 2001, the respective dates of the
first scheduled coal supply and coal transportation price reopeners under the
agreements before they were amended. With the pricing structure in effect on
those dates, Western's contribution to the Company's consolidated pre-tax
income from these two contracts is expected to be reduced in increments to
approximately 50 percent of the 1998 projections of $25,000,000. With the
<PAGE>
elimination of the price reopeners and the adoption of the new pricing
structure, Western does not anticipate any further material adjustments to
profitability on these contracts throughout their terms, which run through
December 2019.
Houston Lighting & Power (HL&P), the purchaser of lignite produced by
Northwestern Resources Co. (Northwestern), a Company subsidiary, filed
litigation on October 5, 1995 in the District Court of the 157th Judicial
District, Harris County, Texas, seeking, among other remedies, a declaratory
judgment that changed conditions required a renegotiation of management and
dedication fees paid to Northwestern under the terms of the Lignite Supply
Agreement (LSA) between it and Northwestern. The LSA governs the delivery of
approximately 9,000,000 tons of lignite per year and is effective until
July 29, 2015. Under the terms of the LSA, Northwestern realizes revenues of
approximately $25,000,000 per year from these fees. HL&P alleged Northwestern
failed to renegotiate these fees in good faith. HL&P sought a reduction
exceeding 60% in the LSA fees. It alleged that the reduction should be
retroactive to September 1, 1995. Additionally, HL&P sought a declaration
that it may substitute other fuels for lignite without violating the LSA.
Trial concluded in December 1997 with the jury denying all of HL&P's
claims regarding changed circumstances and Northwestern's alleged obligations
to negotiate reduced fees. Thus, current pricing under the terms of the LSA
is unchanged. HL&P appealed the jury's determination that the fees are
appropriate and do not require renegotiation. In a pretrial summary judgment,
the trial court concluded other fuel may be substituted for lignite at the
Limestone Plant. Northwestern appealed this summary judgment. Northwestern
believes it will maintain a price for lignite that is competitive with
alternate fuels.
The Company and its subsidiaries are party to various other legal
claims, actions and complaints arising in the ordinary course of business.
Management does not expect disposition of these matters to have a material
adverse effect on the Company's consolidated financial position or its
consolidated results of operations.
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS:
The Company has a formal policy regarding the execution, recording, and
reporting of derivative instruments related to the marketing and trading of
electricity, oil, natural gas and natural gas liquids. The purpose of the
policy is to manage a portion of the price risk associated with its Nonutility
producing assets, firm-supply commitments, and natural gas transportation
agreements. The Company uses derivatives as hedging instruments to achieve
earnings targets, reduce earnings volatility, and provide more stabilized cash
flows. When fluctuations in natural gas and crude oil market prices result in
the Company realizing gains on the derivative instruments into which it has
entered, the Company is exposed to credit risk relating to the nonperformance
by counterparties of their obligations to make payments under the agreements.
Such risk to the Company is mitigated by the fact that the counterparties, or
the parent companies of such counterparties, are investment grade financial
institutions. The Company does not anticipate any material impact to its
financial position, results of operations, or cash flow as a result of
nonperformance by counterparties.
To manage a portion of Nonutility price risk, the Company uses a variety
of derivative instruments including crude oil and natural gas swap and option
agreements to hedge revenue from anticipated production of crude oil and
natural gas reserves, supply costs and transportation commitments to its firm
markets. Under swap agreements, the Company receives or makes payments based
on the differential between a specified price and a variable price of oil or
<PAGE>
natural gas when the hedged transaction is settled. The variable price is
either a crude oil or natural gas price quoted on the New York Mercantile
Exchange or a quoted natural gas price in Inside FERC's Gas Market Report or
other recognized industry index. These variable prices are highly correlated
with the market prices received by the Company for its natural gas and crude
oil production or paid by the Company for commodity purchases. Under option
agreements, the Company makes or receives monthly payments at the settlement
date based on the differential between the actual price of oil or natural gas
and the price established in the agreement depending on whether the Company
sells or buys the option. At September 30, 1998, the Company had no hedge
agreements on crude oil. The Company had swap and option agreements on
approximately 1.3 Bcf of Nonutility natural gas, or 16% of its expected
production from proved, developed, and producing Nonutility natural gas
reserves through October 1999. The Company had swap and option agreements to
hedge approximately 2.1 Bcf of Nonutility natural gas, or 13% of its expected
delivery obligations under long-term natural gas sales contracts through
December 1999. In addition, the Company had swap and option agreements to
hedge approximately 1.85 Bcf, or 6%, of its Nonutility natural gas pipeline
transportation obligations under contracts through October 1999.
The Company accounts for derivative transactions through hedge
accounting. The Company designates all of its derivatives as fair value
hedges. A fair value hedge is based on the following criteria:
? The hedged item is specifically identified as a recognized asset or a
firm commitment.
? The hedged item is a single asset or a portfolio of similar assets.
? The hedged item presents an exposure to changes in fair value for the
hedged risk that could affect earnings.
? The hedged item is not an asset or liability that is measured at fair
value with changes in fair value attributable to the hedged risk
reported currently in earnings.
Gains or losses from these derivative instruments are reflected in
operating revenues on the Consolidated Statement of Income at the same time as
the recognition of the revenue or expense associated with the underlying
hedged item. If the Company determines that any portion of the underlying
hedged item will not be produced or purchased, the unmatched portion of the
instrument is marked-to-market and any gain or loss is recognized in the
Consolidated Statement of Income. If the Company terminates a hedging
instrument prior to the date of the anticipated natural gas or crude oil
production, commodity purchase or transportation commitment, the gain or loss
from the agreement is deferred in the Consolidated Balance Sheet at the
termination date. At September 30, 1998, the Company had no material deferred
gains or losses related to these transactions.
The Company also has investments in independent power partnerships, some
of which have entered into derivative financial instruments to hedge against
interest rate exposure on floating rate debt and foreign currency and natural
gas price fluctuations. At September 30, 1998, the Company believes it would
not experience any materially adverse impacts from the risks inherent in these
instruments.
<PAGE>
NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST:
Montana Power Capital I (Trust) was established as a wholly owned
business trust of the Company for the purpose of issuing common and preferred
securities (Trust Securities) and holding Junior Subordinated Deferrable
Interest Debentures (Subordinated Debentures) issued by the Company. The Trust
has issued 2,600,000 units of 8.45% Cumulative Quarterly Income Preferred
Securities, Series A (QUIPS). Holders of the QUIPS are entitled to receive
quarterly distributions at an annual rate of 8.45% of the liquidation
preference value of $25 per security. The sole asset of the Trust is
$67,000,000 of Subordinated Debentures, 8.45% Series due 2036, issued by the
Company. The Trust uses interest payments received on the Subordinated
Debentures it holds to make the quarterly cash distributions on the QUIPS.
NOTE 5 - COMMITMENTS:
The Montana Power Group (MPG), an energy supply and management alliance,
was exclusively endorsed by the California Manufacturers Association (CMA) to
assist its members with their energy decisions. As a participant in the MPG,
Montana Power Trading and Marketing Company (MPT&M), a Nonutility subsidiary
of the Company agreed to offer energy supply, discounted from current utility
tariff rates, and energy management products and services to members of the
CMA. The supply program was offered on a limited basis and was capped at
predetermined volumes. Once the caps were fully subscribed, the Company had,
at its sole discretion, the option to extend the offered supply and services
to other CMA members.
On August 26, 1998, the Company announced it is exiting the electric
commodity trading and marketing businesses. The Company also rescinded the
energy supply portion of the CMA offer. Due to the high volatility and
immaturity of the electric trading market and the Company's prior decision to
sell its generation assets, the Company believes that these activities create
unacceptable risks and would require very large volumes and supplies to be
successful. The Company is in the process of developing its exit strategy,
which will include plans to supply any existing sale commitments with CMA
members. The departure from the electric commodity trading and marketing
businesses, including supply of existing CMA commitments, is not expected to
have a material impact on the Company's results from operations.
The Company has a five-year commitment to sell electricity to an
industrial customer which includes a fixed-price for a portion of the
deliveries. When the sale of the Company's generation assets is finalized,
and to the extent this contract is not addressed in the electric restructuring
transition process, the Company may be subject to the commodity price risks
associated with supplying that portion of the contract. The Company is
currently evaluating the potential options related to this contract. However,
due to the uncertainties relating to the supply requirements under the
contract, the timing of sale of the generation assets and the eventual outcome
of the electric restructuring process, the Company is unable at this time to
determine the potential future impacts of this contract on the Company's
results of operations.
NOTE 6 - LONG-TERM DEBT:
On January 2, 1998, the Company used short-term borrowings to retire
$16,000,000 in sinking fund debentures.
On April 6, 1998, the Company issued $60,000,000 of floating rate Medium
<PAGE>
Term Notes, Series B, due April 6 2001, the proceeds of which were used to
reduce outstanding debt.
NOTE 7 - COMPREHENSIVE INCOME:
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income", defines comprehensive income as "the change in equity
of a business enterprise during a period from transactions and other events
and circumstances from non-owner sources". SFAS No. 130 requires that an
enterprise report all components of comprehensive income in the period in
which they are recognized. These components are net income and other
comprehensive income. Net income includes such items as income from
continuing operations, discontinued operations, extraordinary items, and
cumulative effects of changes in accounting principle. Other comprehensive
income includes foreign currency translations, adjustments of minimum pension
liability, and unrealized gains and losses on certain investments in debt and
equity securities. The statement is effective for fiscal years beginning
after December 15, 1997.
For the nine-month periods ended September 30, 1998 and 1997, the
Company's sole items of other comprehensive income were foreign currency
translation adjustments of $7,306,000 and $631,000, respectively, to retained
earnings. The 1998 adjustment included both the change in the valuation of
the assets of the company's Canadian operations and a change in the rate used
to adjust certain Canadian assets. Until November 1, 1997, the plant of the
Company's natural gas utility operations, owned by a wholly owned subsidiary,
was included in natural gas utility rate base. As such, the Company earned a
rate of return on these assets stated at their historical costs, converted to
U.S. dollars using historical foreign currency exchange rates. When the
assets were transferred from the Company's regulated operations to the
Nonutility operations, and removed from utility rate base, they were converted
to U.S. dollars using current foreign currency exchange rates which resulted
in a decrease of approximately $5,100,000 in retained earnings in 1998.
NOTE 8 - NOTES RECEIVABLE
In September 1997, the Company's telecommunication subsidiary, Touch
America (TA) entered into a limited liability company, FTV Communications LLC
(FTV) with two other companies for the purpose of constructing a fiber optic
route from Portland, Oregon to Los Angeles. From October 1997 to September
1998, TA has loaned FTV approximately $21,000,000 thus far in the project in
separate notes of various amounts at fixed rates of interest of approximately
6 percent per annum. These notes are payable on demand, except that any
payments require the unanimous vote of the member companies of FTV. All the
notes outstanding are expected to be paid shortly after completion of
construction which is expected by year-end 1998.
<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, 1997.
Safe Harbor for Forward-Looking Statements:
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company in this Quarterly Report on Form 10-Q.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events, including potential impacts of the Year 2000
issue, or performance and underlying assumptions and other statements which
are other than statements of historical facts. Such forward-looking statements
may be identified, without limitation, by the use of the words "anticipates",
"estimates", "expects", "intends", "believes" and similar expressions. From
time to time, the Company or one of its subsidiaries individually may publish
or otherwise make available forward-looking statements of this nature. All
such forward-looking statements, whether written or oral, and whether made by,
or on behalf of, the Company or its subsidiaries, are expressly qualified by
these cautionary statements and any other cautionary statements which may
accompany the forward-looking statements. In addition, the Company disclaims
any obligation to update any forward-looking statements to reflect events or
circumstances after the date hereof.
Forward-looking statements made by the Company are subject to risks and
uncertainties that could cause actual results or events to differ materially
from those expressed in, or implied by, the forward-looking statements. These
forward-looking statements include, among others, statements concerning the
Company's revenue and cost trends, cost recovery, cost-reduction strategies
and anticipated outcomes, pricing strategies, mergers, acquisitions or asset
sales, planned capital expenditures, financings, and financing needs, impacts
of the Year 2000 issue and changes in the utility industry. Investors or other
users of the forward-looking statements are cautioned that such statements are
not a guarantee of future performance by the Company and that such forward-
looking statements are subject to risks and uncertainties that could cause
actual results to differ materially from those expressed in, or implied by,
such statements. Some, but not all, of the risks and uncertainties include
general economic and weather conditions in the areas in which the Company has
operations, competitive factors and the impact of restructuring initiatives in
the electric and natural gas industry, market prices, environmental laws and
policies, federal and state regulatory and legislative actions, drilling
successes in oil and natural gas operations, changes in foreign trade and
monetary policies, laws and regulations related to foreign operations, tax
rates and policies, rates of interest and changes in accounting principles or
the application of such principles to the Company.
Results of Operations:
The following discussion presents significant events or trends that have
had an effect on the operations of the Company or which are expected to have an
impact on operating results in the future.
For the Nine Months Ended September 30, 1998 and 1997:
<PAGE>
Net Income Per Share of Common Stock:
The Company had consolidated net income of $1.68 per share in the nine
months ended September 30, 1998; an increase of 32 cents from nine months
ended September 30, 1997 earnings of $1.36 per share.
Nonutility earnings increased to $1.05 per share, compared to 75 cents
in the third quarter of 1997. Utility earnings increased to 63 cents per
share from 61 cents per share in the same period of 1997.
Nonutility earnings benefited from telecommunications operations which
had an earnings improvement of 36 cents a share compared to the same period in
1997 and a contract settlement and improved operations of independent power
investments. Telecommunication increases were driven by capacity sales of lit
fiber and dark fiber sales on the fiber-optic network in service and under
construction.
Oil and natural gas earnings were below year-earlier figures primarily
because of one-time gains in 1997 from the sales of non-strategic properties
and lower oil and natural gas market prices. These decreases were partially
offset by the 1997 acquisition of Colorado properties along with the transfer
of formerly regulated assets to oil and gas operations in the fourth quarter
of 1997.
Utility earnings year to date are up slightly, to 63 cents per share
compared to 61 cents for the same period a year earlier, reflecting both
customer growth and higher rates.
Nine Months Ended
September 30,
1998 1997
Utility Operations $ 0.63 $ 0.61
Nonutility Operations 1.05 0.75
Consolidated $ 1.68 $ 1.36
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Nine Months Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 327,820 $ 323,635
Intersegment revenues 4,712 3,403
332,532 327,038
EXPENSES:
Power supply 97,405 100,130
Transmission and distribution 27,036 28,075
Selling, general and
administrative 38,393 38,900
Taxes other than income taxes 35,936 37,450
Depreciation and amortization 39,554 38,613
238,324 243,168
INCOME FROM ELECTRIC OPERATIONS 94,208 83,870
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 51,364 72,504
Gas supply cost revenues 22,763 11,135
Intersegment revenues 531 439
74,658 84,078
EXPENSES:
Gas supply costs 22,763 11,135
Other production, gathering and
exploration 1,557 6,443
Transmission and distribution 11,091 10,786
Selling, general and
administrative 14,877 13,097
Taxes other than income taxes 9,953 12,264
Depreciation, depletion and
amortization 6,614 9,367
66,855 63,092
INCOME FROM GAS OPERATIONS 7,803 20,986
INTEREST EXPENSE AND OTHER:
Interest 40,695 38,107
Distributions on company obligated
mandatorily redeemable preferred
securities of subsidiary trust 4,119 4,119
Other (income) deductions - net (1,932) (384)
42,882 41,842
INCOME BEFORE INCOME TAXES AND DIVIDENDS 59,129 63,014
INCOME TAXES 21,462 26,695
DIVIDENDS ON PREFERRED STOCK 2,768 2,768
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 34,899 $ 33,551
</TABLE>
<PAGE>
UTILITY OPERATIONS:
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Very cold winters increase
demand, while mild weather reduces demand. The weather's effect is measured
using degree-days. A degree-day is the difference between the average daily
actual temperature and a baseline temperature of 65 degrees. Heating degree-
days result when the average daily actual temperature is less than the
baseline. As measured by heating degree days, the temperatures for the first
nine months of 1998 in the Company's service territory were 9% warmer than
1997 and 8% warmer than the historic average. In addition, winter weather for
the primary heating months of January and February was 9% warmer than normal.
See Note 1 - Deregulation and Asset Divestiture, and Other Regulatory
Matters in the Notes to the Consolidated Financial Statements for a
description of the transition to competition in the electric and natural gas
utility business.
For its regulated operations, the Company follows SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Pursuant to this
pronouncement, certain expenses and credits, normally reflected in income as
incurred, are recognized when included in rates and recovered from or refunded
to the customers. Changes in regulation or changes in the competitive
environment could result in the Company not meeting the criteria of SFAS
No. 71. If the Company were to discontinue application of SFAS No. 71 for some
or all of its regulated operations, the regulatory assets and liabilities
related to those portions would have to be eliminated from the balance sheet
and included in income in the period when the discontinuation occurred unless
recovery of those costs was provided through rates charged to those customers
in a portion of the business that remains regulated. In conjunction with the
ongoing changes in the electric industry and the sale of its generation
assets, the Company will continue to evaluate the applicability of this
accounting principle to that business. Based upon the Company's anticipated
recovery of its regulatory assets in accordance with the electric
restructuring legislation and the amounts expected to be received from the
sale of the generation assets, the Company believes that the discontinuation
of regulatory accounting for its generation assets will not have a material
impact on the Company's financial position or results of operations.
The Company has existing long-term contracts for the purchase and sale
of electricity that have fixed price components. To the extent that these
contracts are not addressed in the restructuring docket, the Company would
become subject to the commodity price risks associated with meeting these
obligations.
In one such contract discussed in Note 5, the Company has a commitment
to sell electricity which includes a fixed-price for a portion of the
deliveries. When the sale of the Company's generation assets is finalized,
and to the extent this contract is not addressed in the electric restructuring
transition process, the Company may be subject to the commodity price risks
associated with supplying that portion of the contract. Due to the
uncertainties relating to the supply requirements under the contract, the
timing of sale of the generation assets and the eventual outcome of the
electric restructuring process, the Company is unable at this time to
determine the potential future impacts of this contract on the Company's
results of operations.
<PAGE>
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of mWh) (Year to Date Average)
9/30/98 9/30/97 9/30/98 9/30/97 9/30/98 9/30/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
Commercial &
Government $202,857 $197,171 3% 3,233 3,197 1% 279,373 275,251 1%
Industrial 82,412 78,425 5% 1,996 1,906 5% 3,666 3,464 6%
General Business 285,269 275,596 4% 5,229 5,103 2% 283,039 278,715 2%
Sales to Other
Utilities 32,005 36,252 -12% 1,326 2,112 -37% 77 84 -8%
Other 10,546 11,787 -11%
Intersegment 4,712 3,403 38% 98 112 -13% 230 229 0%
Total $332,532 $327,038 2% 6,653 7,327 -9% 283,346 279,028 2%
Power Supply
Expenses:
Hydroelectric $ 15,793 $ 16,493 -4% 2,879 3,095 -7%
Steam 36,142 42,846 -16% 3,263 3,097 5%
Purchases
and Other 45,470 40,791 11% 1,613 1,989 -19%
Total Power Supply $ 97,405 $100,130 -3% 7,755 8,181 -5%
Dollars Per mWh $ 1.256 $ 1.224
</TABLE>
<PAGE>
Revenues from general business customers increased year to date primarily
due to higher rates and customer growth. In addition, increased volumes sold
resulting from two new industrial customers, increased irrigation consumption
and increased sales to current customers also added to the higher revenues.
Warmer weather and two customers moving to customer choice partially offset
these increases. As a result of electric deregulation, beginning July 1, 1998,
electric trading activity, including buying and selling of electricity in the
secondary markets, will be conducted in the Nonutility segment of the Company.
The sales of electricity generated by the Company, in excess of the needs for
core customers, will continue to be reflected in "sales to other utilities" in
the table above. The transfer of the electric trading activity to Nonutility
operations in the third quarter of 1998 resulted in decreased sales to other
utilities despite an increase in average prices and increased steam generation
due to decreased plant maintenance.
Power supply expenses decreased primarily due to lower steam maintenance,
which was partially offset by increased purchased power costs. Although less
power was purchased through electric trading activities as a result of the
transfer of this electric trading activity to Nonutility operations, purchased
power costs increased due to higher prices. During the first nine months of
1998, there was a decrease in scheduled maintenance.
<PAGE>
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Year to Date Average)
9/30/98 9/30/97 9/30/98 9/30/97 9/30/98 9/30/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 60,622 $ 70,320 -14% 12,798 15,181 -16% 144,709 140,412 3%
Industrial 999 1,869 -47% 225 435 -48% 392 395 -1%
Subtotal 61,621 72,189 -15% 13,023 15,616 -17% 145,101 140,807 3%
Gas Supply Cost
Revenues (GSC) (22,763) (11,135) -104%
General Business
without GSC 38,858 61,054 -36% 13,023 15,616 -17% 145,101 140,807 3%
Sales to Other
Utilities 463 558 -17% 121 154 -21% 3 4 -25%
Transportation 9,643 6,961 39% 20,141 19,504 3% 23 41 -44%
Other 2,400 3,931 -39%
Total $ 51,364 $ 72,504 -29% 33,285 35,274 -6% 145,127 140,852 3%
</TABLE>
<PAGE>
Year to date revenues from general business customers decreased largely as
the result of lower volumes sold due to warmer weather during prime winter-
heating months. Customer growth slightly offset the decrease. The increase in
transportation revenue is the result of a PSC order allowing natural gas
customers with annual loads greater than 5,000 dekatherms (Dkt) the right to
choose their own supplier effective November 1, 1997. The number of
transportation customers decreased due to aggregators carrying the
transportation contract volumes.
The restructuring of the natural gas utility also affected its operating
results for the period. In November 1997, almost all of the Company's regulated
natural gas production assets were transferred to its Nonutility affiliate, MP
Gas. Since that time, operating expenses related to the transferred assets
have been included in the Company's Nonutility oil and natural gas operations.
The absence of these expenses in the Utility's natural gas operations resulted
in reduced non-gas supply cost revenues and expenses.
As a result of the restructuring mentioned above, the Utility has
contracted to purchase most of its gas from its Nonutility affiliate. The
contract price includes costs associated with the transferred assets and
returns on those assets. Gas cost revenues and expenses, which are always
equal due to regulated rate and accounting procedures, increased in the third
quarter of 1998 due to the new purchase contract. Amortizations of prior
period under-collections also contributed to the increase.
Higher selling, general and administrative expense for the period
resulted primarily from increased amortizations of regulatory assets, which
are currently being collected in rates.
Taxes other than income taxes and depreciation, depletion and
amortization decreased due to the transfer of the natural gas production
properties as discussed above.
<PAGE>
Interest Expense and Other:
Increases in interest expense in the first nine months of 1998 due to
increased short-term borrowing, the mid-1997 recognition of the Kerr Project
mitigation liability, and the issuance of additional medium-term notes in
April 1998 were partially offset by decreases related to retirements of long-
term debt in the fourth quarter of 1997 and first quarter of 1998.
Other income increased due to costs associated with the property
transfer of Flint Creek Dam to Granite County, Montana during 1997 and the
change in interest and dividend income. This was partially offset by the
change in carrying cost capitalized on Utility construction.
Income Taxes:
The increase in income taxes resulting from the increase in pre-tax
income was offset by a reduction in the effective tax rate.
<PAGE>
<TABLE>
<CAPTION>
NONUTILTY OPERATIONS
Nine Months Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $128,869 $122,252
Intersegment revenues 28,501 23,872
157,370 146,124
EXPENSES:
Operations and maintenance 97,030 86,774
Selling, general and
administrative 13,085 15,193
Taxes other than income taxes 17,007 16,605
Depreciation, depletion and
amortization 7,262 4,701
134,384 123,273
INCOME FROM COAL OPERATIONS 22,986 22,851
OIL AND NATURAL GAS:
REVENUES:
Revenues 142,909 116,114
Intersegment revenues 15,560 230
158,469 116,344
EXPENSES:
Operations and maintenance 115,500 76,912
Selling, general and
administrative 14,382 7,521
Taxes other than income taxes 3,613 3,562
Depreciation, depletion and
amortization 15,928 12,769
149,423 100,764
INCOME FROM OIL AND NATURAL GAS OPERATIONS 9,046 15,580
INDEPENDENT POWER:
REVENUES:
Revenues 54,533 52,225
Earnings from unconsolidated
investments 29,180 7,938
Intersegment revenues 1,625 1,572
85,338 61,735
EXPENSES:
Operations and maintenance 47,909 47,275
Selling, general and
administrative 3,028 3,092
Taxes other than income taxes 1,363 1,468
Depreciation, depletion and amortization 8,229 1,914
60,529 53,749
INCOME FROM INDEPENDENT POWER OPERATIONS $ 24,809 $ 7,986
NONUTILITY OPERATIONS (continued)
Nine Months Ended
September 30,
1998 1997
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 63,049 $ 23,844
Earnings from unconsolidated
investments 6,873 54
Intersegment revenues 800 587
70,722 24,485
EXPENSES:
Operations and maintenance 19,245 15,568
Selling, general and
administrative 7,318 4,927
Taxes other than income taxes 3,874 570
Depreciation, depletion and
amortization 5,255 1,013
35,692 22,078
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 35,030 2,407
OTHER OPERATIONS:
REVENUES:
Revenues 29,599 1,690
Intersegment revenues 1,025 2,031
30,624 3,721
EXPENSES:
Operations and maintenance 31,829 1,854
Selling, general and
administrative 1,921 3,881
Taxes other than income taxes 835
Depreciation, depletion and
amortization 3,231 399
37,816 6,134
LOSS FROM OTHER OPERATIONS (7,192) (2,413)
INTEREST EXPENSE AND OTHER:
Interest 7,036 4,234
Other (income) deductions - net (5,261) (16,305)
1,775 (12,071)
INCOME BEFORE INCOME TAXES 82,904 58,482
INCOME TAXES 25,350 17,603
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 57,554 $40,879
</TABLE>
<PAGE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations was comparable to the same period last year.
Revenues from the Rosebud Mine increased $8,400,000 including revenues from a
synthetic fuel project. Due to the acquisition of the remaining 50% ownership
of the project in 1997, project revenues are now being consolidated with coal
operations. Volume of coal sold to the Colstrip Units in 1998 was 26% higher
due to less down time for repairs and scheduled maintenance at the Colstrip
generating plants. These increased volumes were partially offset by lower
prices resulting from contract dispute settlements with Puget in February 1997
and with the other non-operating owners in the current quarter. In addition,
the Unit 3&4 coal supply and transportation agreements were amended in the
third quarter of 1998 resulting in lower prices. As discussed in Note 2, these
changes will result in modest profit reductions until mid-year 2000 with
significant price reductions thereafter. Revenues from the Jewett mine rose
$2,800,000 primarily as a result of an increase in reimbursable mining
expenses, partially offset by a 6% decrease in tons of coal sold.
Operation and maintenance (O&M) expense increases due primarily to
higher volumes at the Rosebud Mine and increased stripping costs at the Jewett
Mine were partially offset by lower royalties caused by the contract
adjustments discussed above and decreased volumes at Jewett. Selling, general
and administrative (SG&A) costs fell due to lower legal costs. Depreciation,
depletion and amortization was up as a result of the increased tons at the
Rosebud mine.
Oil and Natural Gas Operations:
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenue (excluding intersegment
revenues) and the related percentage changes in volumes sold and prices
received:
Oil -revenue $ (11)
-volume (44)%
-price/bbl (38)%
Natural gas -revenue $ 53
-volume 92%
-price/Mcf (17)%
Income from oil and natural gas operations decreased due to lower market
prices in the first nine months of 1998. In addition to lower prices, revenues
from oil operations decreased due to the sale of production properties in
conjunction with the Company's increased emphasis on its natural gas
operations. Natural gas revenues increased due to the sale of production from
the Colorado properties acquired in the second quarter of 1997 and from
formerly regulated assets transferred to oil and natural gas operations in the
fourth quarter of 1997. In addition, marketing to wholesale customers in
California started in the second quarter of 1998. These increases were
partially offset by the lower prices in 1998.
Operation and maintenance expense increased due to the costs of operating
the acquired properties and transferred regulated assets. This increase was
partially offset by lower prices for purchased gas. These new operations also
accounted for the increases in selling, general and administrative and
depreciation, depletion and amortization expenses.
<PAGE>
Independent Power Operations:
The Company, through one of its unconsolidated partnership investments,
is a party to an agreement with the purchaser of the electricity from a
generating facility owned by the partnership. Under the terms of the contract
settlement, the purchaser paid the partnership to terminate the power purchase
agreement that was in place between the two entities.
Total revenues from independent power operations for 1998 increased
$23,600,000. Earnings from unconsolidated investments increased $21,200,000
primarily due to the recognition, in the third quarter, of the Company's share
of the contract settlement discussed above and higher earnings from other
unconsolidated investments resulting from improved operations. Offsetting the
earnings increase was a related $6,300,000 increase in the amortization of
independent power investments. In addition, revenues from power sales
increased $2,100,000 due to increased long-term sales volumes, which was
offset by higher power supply expense of $2,000,000.
Telecommunications Operations:
Revenues from telecommunications operations increased primarily due to
sales on the Company's Washington to Minnesota, Colorado to Canada fiber optic
network and a higher volume of long-distance minutes sold. Revenues from the
fiber optic network did not begin until late in the third quarter of 1997. The
Company also has a one-third interest in a limited liability company, which
made dark fiber sales in the first nine months of 1998 on a Portland to Los
Angeles fiber optic network currently under construction. These sales account
for the $6,800,000 increase in earnings from unconsolidated investments.
Expenses for the first nine months are higher due to the operation of
the Washington to Minnesota, Colorado to Canada fiber optic network mentioned
above, increased marketing expenses and costs related to the increased long-
distance service.
Other Operations:
Changes to revenues and expenses in other operations are primarily the
result of including the electric trading activities of Montana Power Trading
and Marketing Company (MPT&MC) and the Company's shared administrative
services functions in this section for 1998. From January through June MPT&MC
results reflect the purchase and resale of electricity that did not utilize
the Utility's electric system. Beginning in July 1998, all purchases and
resale of power in the secondary market are in other operations.
Interest Expense and Other:
Interest expense increased primarily due to increases in the amount of
outstanding borrowings to provide short-term financing for the Company's
expansion of telecommunications and oil and natural gas operations.
Other (income) and deductions - net decreased due to a $13,000,000 gain
realized on dispositions of oil and natural gas properties in the first nine
months of 1997. This gain was partially offset by increased costs associated
with a discontinued coal project in the first quarter of 1997.
Quarter Ended September 30, 1998 and 1997:
<PAGE>
Net Income Per Share of Common Stock:
The Company had consolidated net income of $0.65 per share in the third
quarter ended September 30, 1998, an increase of 37 cents or 132 percent over
third-quarter 1997 earnings of $0.28 per share.
Nonutility earnings increased to 45 cents per share, compared to
23 cents in the third quarter of 1997. Utility earnings increased to 20 cents
per share from 5 cents per share in the same quarter of 1997.
Growth in telecommunications continues to lead the improvement in the
Company's consolidated earnings. Coupled with the impact of events in the
independent power operations, Nonutility operations earned 45 cents per share
in the third quarter, compared to 23 cents in the third quarter of 1997.
The Touch America telecommunications unit had an earnings improvement of
10 cents a share, reflecting operations on the in-service segments of its
10,000-mile fiber-optic network.
Earnings from the independent power operations increased by 19 cents,
largely as a result of two transactions: settlement of a contractual dispute
on a project in New York state, and the return of amounts expensed earlier in
1998 on a Texas project now under construction.
Coal volumes were up by 9 percent, but the retroactive impact of charges
for the previously announced settlement of a contract dispute and amendments
to coal supply and transportation agreements resulted in a reduction of income
by 3 cents a share. Oil and gas income was down, reflecting both lower prices
and lower oil volumes.
The significant increase in Utility earnings, to 20 cents per share,
compared to 5 cents in the third quarter of 1997 resulted primarily from
customer growth, generation increases from the hydroelectric plants and
increased rates for electricity, as well as reduced maintenance expenses, and
an increase in gas revenues.
Quarter Ended
September 30,
1998 1997
Utility Operations $ 0.20 $ 0.05
Nonutility Operations 0.45 0.23
Consolidated $ 0.65 $ 0.28
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Quarter Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $108,585 $106,118
Intersegment revenues 2,258 1,140
110,843 107,258
EXPENSES:
Power supply 28,242 33,649
Transmission and distribution 9,913 9,274
Selling, general and
administrative 10,953 12,337
Taxes other than income taxes 11,764 12,356
Depreciation and amortization 13,185 13,067
74,057 80,683
INCOME FROM ELECTRIC OPERATIONS 36,786 26,575
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 11,331 12,342
Gas supply cost revenues 2,447 1,201
Intersegment revenues 184 113
13,962 13,656
EXPENSES:
Gas supply costs 2,447 1,201
Other production, gathering and
exploration 404 1,923
Transmission and distribution 3,651 3,560
Selling, general and
administrative 4,786 4,391
Taxes other than income taxes 3,251 3,989
Depreciation, depletion and
amortization 2,207 3,120
16,746 18,184
LOSS FROM GAS OPERATIONS (2,784) (4,528)
INTEREST EXPENSE AND OTHER:
Interest 13,570 13,541
Distributions on QUIPS 1,373 1,373
Other (income) deductions - net (1,138) (29)
13,805 14,885
INCOME BEFORE INCOME TAXES AND DIVIDENDS 20,197 7,162
INCOME TAXES 8,344 3,227
DIVIDENDS ON PREFERRED STOCK 923 923
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 10,930 $ 3,012
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS:
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of mWh) (Quarterly Average)
9/30/98 9/30/97 9/30/98 9/30/97 9/30/98 9/31/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 66,452 $ 61,398 8% 1,094 1,032 6% 279,832 275,554 2%
Industrial 26,982 27,532 -2% 650 696 -7% 4,731 4,597 3%
General Business 93,434 88,930 5% 1,744 1,728 1% 284,563 280,151 2%
Sales to Other
Utilities 11,044 12,425 -11% 360 720 -50% 62 86 -28%
Other 4,107 4,763 -14%
Intersegment 2,258 1,140 98% 31 34 -9% 228 230 -1%
Total $110,843 $107,258 3% 2,135 2,482 -14% 284,853 280,467 2%
Power Supply
Expenses:
Hydroelectric $ 4,520 $ 5,667 -20% 1,020 979 4%
Steam 12,016 15,628 -23% 1,258 1,227 3%
Purchases
and Other 11,706 12,354 -5% 357 624 -43%
Total Power Supply $ 28,242 $ 33,649 -16% 2,635 2,830 -7%
Dollars Per mWh $1.072 $1.189
</TABLE>
<PAGE>
Third quarter revenues from general business customers increased due to
the items mentioned in the nine months ended discussion. As mentioned in the
nine months ended discussion, the Utility is no longer buying and selling
electricity in the secondary markets. Consequently, sales to other utilities
decreased due to the transfer of the electric trading activity to Nonutility
operations, partially offset by an increase in average prices and increased
hydroelectric and steam generation.
Power supply expenses decreased primarily due to lower steam maintenance.
Purchased power costs decreased due to less power purchased through electric
trading activities as a result of the transfer of the electric trading
activity to Nonutility operations, offset by an increase in prices. During
July 1997, the Corette thermal plant was down for scheduled maintenance.
Selling, general and administrative expenses decreased for the period
primarily due to reduced employee benefit expenses resulting from the funded
status of the pension plan, which is offset by a corresponding decrease in
revenue.
<PAGE>
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Quarterly Average)
9/30/98 9/30/97 9/30/98 9/30/97 9/30/98 9/30/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 9,872 $9,773 1% 1,653 1,778 -7% 144,371 139,347 4%
Industrial 167 331 -50% 33 76 -57% 355 355 0%
Subtotal 10,039 10,104 -1% 1,686 1,854 -9% 144,726 139,702 4%
Gas Supply Cost
Revenues (GSC) (2,447) (1,201) -104%
General Business
without GSC 7,592 8,903 -15% 1,686 1,854 -9% 144,726 139,702 4%
Sales to Other
Utilities 71 71 0% 7 7 0% 3 4 -25%
Transportation 3,376 2,143 58% 6,376 5,705 12% 23 37 -38%
Other 292 1,225 -76%
Total $ 11,331 $12,342 -8% 8,069 7,566 7% 144,752 139,743 4%
</TABLE>
<PAGE>
Revenues from general business customers were comparable with the prior
year as lower volumes sold due to warmer weather was offset by higher rates
and customer growth.
Gas supply costs and selling, general and administrative expense
increased due to the items mentioned in the nine months ended discussion.
Taxes other than income taxes and depreciation, depletion and
amortization decreased due to the transfer of the natural gas production
properties as discussed in the nine months ended discussion.
Interest Expense and Other:
Other income increased as a result of costs associated with the change
in carrying cost capitalized on Utility construction, the change in interest
and dividend income, and costs associated with strategy and restructuring
studies in 1997.
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Quarter Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 40,391 $ 44,131
Intersegment revenues 8,645 9,223
49,036 53,354
EXPENSES:
Operations and maintenance 32,839 31,838
Selling, general and
administrative 3,663 4,767
Taxes other than income taxes 3,894 6,367
Depreciation, depletion and
amortization 1,995 2,282
42,391 45,254
INCOME FROM COAL OPERATIONS 6,645 8,100
OIL AND NATURAL GAS:
REVENUES:
Revenues 55,396 39,306
Intersegment revenues 5,927 35
61,323 39,341
EXPENSES:
Operations and maintenance 46,380 28,974
Selling, general and
administrative 4,378 2,515
Taxes other than income taxes 1,300 909
Depreciation, depletion and
amortization 5,080 4,334
57,138 36,732
INCOME FROM OIL AND NATURAL GAS OPERATIONS 4,185 2,609
INDEPENDENT POWER:
REVENUES:
Revenues 18,154 18,007
Earnings from unconsolidated
investments 20,829 3,266
Intersegment revenues 444 358
39,427 21,631
EXPENSES:
Operations and maintenance 12,068 16,615
Selling, general and
administrative 873 896
Taxes other than income taxes 464 222
Depreciation, depletion and
amortization 5,857 948
19,262 18,681
INCOME FROM INDEPENDENT POWER OPERATIONS $ 20,165 $ 2,950
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS (continued)
Quarter Ended
September 30,
1998 1997
Thousands of Dollars
<S> <C> <C>
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 21,394 $ 8,807
Earnings from unconsolidated
Investments 1,229 17
Intersegment revenues 297 201
22,920 9,025
EXPENSES:
Operations and maintenance 6,779 5,204
Selling, general and
administrative 2,234 1,401
Taxes other than income taxes 1,315 241
Depreciation, depletion and
amortization 2,026 472
12,354 7,318
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 10,566 1,707
OTHER OPERATIONS:
REVENUES:
Revenues 24,930 985
Intersegment revenues 265 917
25,195 1,902
EXPENSES:
Operations and maintenance 26,124 1,159
Selling, general and
administrative 584 1,232
Taxes other than income taxes 266
Depreciation, depletion and amortization 937 133
27,911 2,524
LOSS FROM OTHER OPERTAIONS (2,716) (622)
INTEREST EXPENSE AND OTHER:
Interest 2,447 1,335
Other (income) deductions - net (1,397) (2,128)
1,050 (793)
INCOME BEFORE INCOME TAXES 37,795 15,537
INCOME TAXES 12,845 3,231
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 24,950 $ 12,306
</TABLE>
<PAGE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations decreased $1,500,000 compared to the same
period last year. Revenues from the Rosebud Mine decreased $5,400,000 including
revenues from the synthetic fuel project. Volume of coal sold to the Colstrip
Units in 1998 was 11% higher, but this was more than offset by price changes
discussed in the nine months ended section. Revenues from the Jewett mine
increased $1,100,000 on a 9% increase in tons sold.
Higher operation and maintenance expense due to increased volumes and
higher stripping costs at the Jewett mine were partially offset by decreased
royalties caused by the Colstrip contract price changes discussed in the nine
months ended discussion. SG&A expenses decreased primarily as a result of
lower legal costs. Decreased taxes other than income taxes caused by the
reduced prices and a property tax refund at the Jewett mine were partially
offset by higher volumes at the Rosebud mine.
Oil and Natural Gas Operations:
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenue (excluding intersegment
revenues) and the related percentage changes in volumes sold and prices
received:
Oil -revenue $ (3)
-volume (49)%
-price/bbl (40)%
Natural gas -revenue $ 26
-volume 139%
-price/Mcf (22)%
Miscellaneous -revenue $ (1)
Income from oil and natural gas operations increased by $1,600,000 over
the third quarter of 1997. Revenues and expenses were higher for the same
reasons mentioned in the nine months ended discussion above.
Independent Power Operations:
Revenues from independent power operations, for the third quarter 1998,
increased $17,800,000 primarily as a result of the contract settlement and
higher earnings from other unconsolidated investments mentioned in the nine
months ended discussion. In addition, there was a $4,600,000 reduction in
operating expenses due to the reimbursement of project development costs of a
new domestic investment opportunity which were expensed during the first six
months of 1998. Offsetting the increase was an increase in the amortization
of independent power investments of $5,000,000.
Telecommunications Operations:
For the quarter, revenues and expenses from telecommunications
operations increased for the same reasons presented in the nine months ended
discussion.
<PAGE>
Other Operations:
As discussed above, changes to revenues and expenses in other operations
are primarily the result of the electric trading activities of Montana Power
Trading and Marketing Company and the Company's shared administrative service
functions.
Interest Expense and Other:
Interest expense increased for the same reasons noted in nine months
ended discussion above.
Other (income) and deductions - net decreased primarily due to lower
interest income.
Income Taxes:
The increase in income taxes resulted from the increase in pre-tax income
and an increase in the effective tax rate.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Activities --
Net cash provided by operating activities was $197,823,000 during the
period compared to $143,624,000 in the first nine months of 1997. The current
year increase of $54,199,000 was due primarily to higher 1998 Nonutility
revenues and a $30,000,000 loan to a third party made in 1997 which were
partially offset by 1998 construction costs which will be reimbursed in future
periods.
An arbitration panel ruled July 28, 1998 that the Bonneville Power
Administration (BPA) breached its purchase power contract with Tenaska
Washington Partners II, L.P. The Montana Power Company's wholly owned
subsidiary, Continental Energy Services, owns a 25 percent interest in the
Tenaska partnership. The Company received $43,800,000 on November 12, 1998.
The settlement will be recognized as income in the fourth quarter results of
operations.
The Company has received interest from customers in exercising options to
prepay for capacity on Touch America's fiber network. Such prepayments would
result in a benefit to the Company in accelerated cash flows and to customers
who earn a discount.
One Touch America customer has provided notice to exercise an option
allowing prepayment of all amounts due for the remaining initial term of the
contract. If the lump sum payment is received as anticipated in early January
1999, the Company expects to record the amount, currently estimated between
$200,000,000 and $300,000,000, as deferred revenue to be amortized over the
remaining term. The income tax impacts on such prepayments are usually
incurred at the time the prepayment is received.
Investing Activities --
Net cash used for investing activities was $103,665,000 during the
period compared to $152,636,000 in the first nine months of 1997. The current
year decrease of $48,971,000 was due primarily to the decrease in capital
expenditures resulting from a 1997 oil and gas plant acquisition and
hydroelectric license costs capitalized in 1997. The current year decrease was
partially offset by the lack of property sales which occurred in 1997.
<PAGE>
Forecasted capital expenditures for 1998 are as follows:
Forecasted
1998
Thousands of Dollars
Utility $ 83,000
Nonutility 143,000
Total $ 226,000
Financing Activities --
On January 2, 1998, the Company used short-term borrowings to retire
$16,000,000 in sinking fund debentures.
On April 6, 1998, the Company issued $60,000,000 of floating rate Medium
Term Notes, Series B, due April 6 2001, the proceeds of which were used to
reduce outstanding debt.
The Company's consolidated borrowing ability under its Revolving Credit
and Term Loan Agreements was $178,400,000, of which $94,100,000 was unused at
September 30, 1998. The unused amount excludes $50,000,000 under the
Agreements which is currently being used to back a like amount of commercial
paper.
The Company is evaluating the potential uses for the proceeds from the
sale of generation assets including investing in current businesses, primarily
telecommunications, as well as a repurchase of common stock and possible debt
repayment.
The Company's Board of Directors has authorized a share repurchase
program over the next five years to repurchase up to 10 million shares, or 18
percent, of the Company's outstanding common stock. As of the end of the
third quarter 1998, Montana Power had 55,024,778 common shares outstanding.
The repurchase of common stock may be made, from time to time, on the open
market or in privately negotiated transactions. The number of shares to be
purchased and the timing of the purchases will be based on the level of cash
balances, general business conditions and other factors, including alternative
investment opportunities.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended September 30, 1998, the Company's ratio of
earnings to fixed charges was 3.15 times. Fixed charges include interest,
distributions on preferred securities of a subsidiary trust, the implicit
interest of the Colstrip Unit 4 rentals and one-third of all other rental
payments.
NEW ACCOUNTING PRONOUNCEMENTS:
During February 1998, the FASB issued SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits". SFAS No. 132
revises employers' disclosures about pension and other postretirement plans
currently provided under the provisions of SFAS Nos. 87, 88 and 106. Although
the statement will affect the presentation of the information, it does not
change the measurement or recognition of those plans, and therefore it will
not affect the Company's financial position or results of operations. The
statement is effective for fiscal years beginning after December 15, 1997.
<PAGE>
In June 1998, the FASB also issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities". SFAS No. 133 requires that
all derivative instruments be recorded on an entity's balance sheet at fair
value. Changes in the fair value of the derivatives are recognized each
period either in current earnings or as a component of comprehensive income,
depending on whether the derivative is designated as part of a hedge
transaction, and if so, what type of hedge transaction. The statement
distinguishes between fair-value hedges, defined as hedges of the Company's
assets, liabilities or firm commitments, and cash-flow hedges, defined as
hedges of future cash flows related to a variable rate asset or liability or a
forecasted transaction. Recognition of changes in the fair value of a hedge,
determined to be a fair-value hedge, will generally be offset in the income
statement by the recognition of the change in the fair value of the hedged
item. Recognition of changes in the fair value of a cash-flow hedge will be
reported as a component of comprehensive income. The gains or losses on the
derivative instruments that are reported in comprehensive income will be
reclassified into current earnings in the periods in which the earnings are
impacted by the variability of the cash flows of the hedged item. The
ineffective portion of all hedges will be recognized in current earnings.
The new statement is effective for all fiscal quarters of all fiscal
years beginning after June 15, 1999. The Company has not yet determined the
impact that the adoption of the new standard will have on its earnings or
financial position.
YEAR 2000 COMPLIANCE:
As the year 2000 approaches, most companies face a potentially serious
problem resulting from the possible failure of computer software programs and
other operational electronic systems to recognize calendar dates beyond the
year 1999. The Year 2000 issue relates to the ability of systems, including
computer hardware, software, and embedded microprocessors, to properly
interpret date information relating to the year 2000 and beyond. Many
existing systems, including some of the Company's systems, use only the last
two digits to refer to a year. Therefore, these systems may not properly
recognize a year that begins with "20" instead of "19". If not corrected,
these systems could fail or create erroneous results.
The Company has developed a corporate-wide strategy and has established
an executive Year 2000 Steering Committee to oversee the "Year 2000" issue.
The corporate-wide strategy is broken into four phases. The first phase is to
develop an inventory of all information technology (IT) systems, including
third party computer hardware and software vendors, and non-information (non-
IT) systems, including embedded electronic microprocessors. The second phase
of the plan is to conduct certain analysis to determine the system's Year 2000
readiness. The third phase is to replace/repair and test the systems to
ensure the availability and integrity of the systems. The fourth phase is to
implement the changes made during previous phases, which also includes
developing a contingency plan to address further potential failures of the
systems. The Company expects all necessary modifications and testing of its
critical IT and critical non-IT systems to be completed by July 1, 1999.
The Company established a project team within its central Information
Services (IS) Department to ensure that all of its critical IT systems will be
year 2000 ready before 2000. The IS Department began addressing the issue in
1993. Currently, the inventorying of the IT systems is 90 to 100 percent
completed. Analysis of the inventory is 80 to 90 percent completed.
Replacement/repair and testing of the IT systems is 50 to 75 percent
completed, and contingency plans are being developed.
In January 1998, the Company formally began the process of identifying
the non-IT systems that could be affected by this issue. The senior vice
<PAGE>
presidents of the Company's two divisions and the officers of the various
business units have been given the responsibility for addressing these
operational/process control issues as they relate to the year 2000. Currently,
inventorying of non-IT systems is 80 percent completed. Analysis of the
inventory is 70 percent completed. Replacement/repair and testing of the non-
IT systems is estimated to be 40 percent completed, and approximately 50
percent of the contingency plans are in place while other plans are still
being developed.
The year 2000 issue may also impact other entities with which the
Company transacts business or with which the Company's electric and natural
gas systems are interconnected. Currently, the Company is approximately 25%
complete in contacting suppliers, vendors, and key customers to assess their
year 2000 readiness. The Company and other electric and natural gas service
providers are evaluating potential Year 2000 risks resulting from
interconnected electric, natural gas, and informational systems. Such
interconnected systems are critical to the reliability and integrity of each
interconnected service provider. It is possible that the failure of one such
interconnected provider to achieve Year 2000 compliance could disrupt the
provision of service by others. The Company and other providers are working
together in an effort to avoid such disruptions. The North American Electric
Reliability Council (NERC) is facilitating the preparations of electric
systems in North America for operation into the year 2000. As part of its
Year 2000 program, NERC monitors the monthly progress of industry efforts to
prepare critical systems for the year 2000. NERC has proposed national drills
in April and September 1999 to assess industry preparation. It is anticipated
that the Company will participate in such drills.
The Company has spent approximately $2,000,000 in the aggregate to
address the Year 2000 issue. Although it is not currently possible to estimate
the overall cost of required modifications, the Company presently believes that
the ultimate cost of this work will not have a material effect on the Company's
current financial position, liquidity or results of operations.
As previously discussed above, the IS Department is finalizing
contingency plans for their critical IT systems. Critical non-IT portions of
the Company have, or are preparing, contingency plans. Since service
procedures exist for equipment failures, the contingency plans will rely on
procedures that are already in place. The worst case Year 2000 scenario would
be that customers experience short interruptions in service.
<PAGE>
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
Houston Lighting and Power Lignite Sales Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 2" for additional information pertaining to legal proceedings.
ITEM 5. Other Information
(a) Arbitration Panel Rules Against Bonneville Power Administration
An arbitration panel ruled July 28, 1998 that the Bonneville Power
Administration (BPA) breached its purchase power contract with
Tenaska Washington Partners II, L.P. (Tenaska). The panel ruled
that Tenaska was entitled to lost profit damages and awarded
monetary damages, including interest to date, of approximately
$160,000,000. BPA was also required to pay all arbitration costs
associated with the three-judge panel who heard the matter. The
Montana Power Company's wholly owned subsidiary, Continental
Energy Services (Continental), owns a 25 percent interest in the
Tenaska partnership. The Company received $43,800,000 on November
12, 1998. The settlement will be recognized in income in the
fourth quarter results of operations.
The dispute arose in 1995 when BPA informed Tenaska that it would
not honor its obligation under the contract. At the time of the
breach, approximately 70% of the project costs had been committed
by Tenaska to build the 248-megawatt natural gas-fired electric
generating plant at Frederickson, Washington. During the past
three years, all of the third party damage issues that were part
of Tenaska's original claim were resolved or settled by a payment
from BPA. Earlier this year, BPA accepted assignment of the
partially completed plant and physical assets on the site, which
helped resolve another significant issue in dispute.
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
Exhibit 2 Asset purchase agreement 1-4566 2a
Form 8-K
Dated
November 2,
1998
Exhibit 10a Colstrip Unit #3 Wholesale 1-4566 10a
Transmission Service Agreement Form 8-K
(Exhibit F-1 to the Asset Dated
Purchase Agreement) November 2,
1998
<PAGE>
Exhibit 10b Non-Colstrip Unit #3 Wholesale 1-4566 10b
Transmission Service Agreement Form 8-K
(Exhibit F-2 to the Asset Dated
Purchase Agreement) November 2,
1998
Exhibit 10c Generation Interconnection 1-4566 10c
Agreement (Exhibit G to the Form 8-K
Asset Purchase Agreement) Dated
November 2,
1998
Exhibit 10d Equity Contribution Agreement 1-4566 10d
Form 8-K
Dated
November 2,
1998
Exhibit 12 Computation of ratio of earnings
to fixed charges for the twelve
months ended September 30, 1998.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K
DATED SUBJECT
July 28, 1998 Item 5. Other Events. Discussion of
Second Quarter Net Income.
Item 7. Exhibits. Consolidated Statements
of Income for the Quarters Ended June 30,
1998 and 1997 and for the Twelve Months
Ended June 30, 1998 and 1997. Utility
Operations Schedule of Revenues and
Expenses for the Quarters Ended June 30,
1998 and 1997 and the Twelve Months Ended
June 30, 1998 and 1997. Nonutility
Operations Schedule of Revenues and
Expenses for the Quarters Ended June 30,
1998 and 1997 and the Years Twelve Months
Ended June 30, 1998 and 1997.
August 24, 1998 Resolution of Colstrip Units 3 & 4 coal
price disputes and decision to exit
electric commodity trading and marketing
activities.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE MONTANA POWER COMPANY
(Registrant)
By /s/ J. P. Pederson
J. P. Pederson
Vice President and Chief
Financial and Information
Officer
Dated: November 16, 1998
<PAGE>
EXHIBIT INDEX
Exhibit 2
Asset purchase agreement
Exhibit 10a
Colstrip Unit #3 Wholesale
Transmission Service Agreement
(Exhibit F-1 to the Asset
Purchase Agreement)
Exhibit 10b
Non-Colstrip Unit #3 Wholesale
Transmission Service Agreement
(Exhibit F-2 to the Asset
Purchase Agreement)
Exhibit 10c
Generation Interconnection
Agreement (Exhibit G to the
Asset Purchase Agreement)
Exhibit 10d
Equity Contribution Agreement
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended September 30, 1998
Exhibit 27
Financial data schedule
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
September 30,1998
Net Income $ 153,058
Income Taxes 64,385
$ 217,443
Fixed Charges:
Interest $ 64,486
Amortization of Debt Discount,
Expense and Premium 1,568
Rentals 34,875
$ 100,929
Earnings Before Income Taxes
and Fixed Charges $ 318,372
Ratio of Earning to Fixed Charges 3.15 x
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consoidated Balance Sheet at 9/30/98, the Consolidated Income Statement and the
Consolidated Statement of Cash Flows for the nine months ended 9/30/98 and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,518,605
<OTHER-PROPERTY-AND-INVEST> 680,602
<TOTAL-CURRENT-ASSETS> 285,319
<TOTAL-DEFERRED-CHARGES> 365,631
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,850,157
<COMMON> 701,107
<CAPITAL-SURPLUS-PAID-IN> 2,216
<RETAINED-EARNINGS> 336,403
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,039,726
65,000
57,654
<LONG-TERM-DEBT-NET> 705,312
<SHORT-TERM-NOTES> 66,921
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 60,124
0
<CAPITAL-LEASE-OBLIGATIONS> 622
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 854,798
<TOT-CAPITALIZATION-AND-LIAB> 2,850,157
<GROSS-OPERATING-REVENUE> 873,926
<INCOME-TAX-EXPENSE> 46,813
<OTHER-OPERATING-EXPENSES> 687,236
<TOTAL-OPERATING-EXPENSES> 734,049
<OPERATING-INCOME-LOSS> 139,877
<OTHER-INCOME-NET> 3,026
<INCOME-BEFORE-INTEREST-EXPEN> 142,903
<TOTAL-INTEREST-EXPENSE> 47,682
<NET-INCOME> 95,221
2,768
<EARNINGS-AVAILABLE-FOR-COMM> 92,453
<COMMON-STOCK-DIVIDENDS> 65,984
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 197,823
<EPS-PRIMARY> 1.68
<EPS-DILUTED> 1.68
</TABLE>
