UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
________________________________________
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 1997
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _______________
________________________________________
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
________________________________________________________
(Former name, former address and former fiscal year,
if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
On August 4, 1997, the Company had 54,641,970 shares of common stock
outstanding.
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PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Six Months Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
REVENUES $ 497,421 $ 462,324
EXPENSES:
Operations 190,357 187,862
Maintenance 38,558 31,450
Selling, general and
administrative 58,806 50,449
Taxes other than income taxes 49,306 42,810
Depreciation, depletion and
amortization 45,919 42,106
382,946 354,677
INCOME FROM OPERATIONS 114,475 107,647
INTEREST EXPENSE AND OTHER:
Interest 25,436 23,678
Distributions on preferred
securities of subsidiary trust 2,746
Other (income) deductions - net (12,504) (2,451)
15,678 21,227
INCOME TAXES 37,840 31,819
NET INCOME 60,957 54,601
DIVIDENDS ON PREFERRED STOCK 1,845 3,614
NET INCOME AVAILABLE FOR
COMMON STOCK $ 59,112 $ 50,987
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 54,632 54,635
NET INCOME PER SHARE OF
COMMON STOCK $ 1.08 $ 0.93
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Quarter Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
REVENUES $216,369 $ 197,919
EXPENSES:
Operations 86,015 82,831
Maintenance 20,594 15,357
Selling, general and
administrative 31,683 25,965
Taxes other than income taxes 24,008 20,130
Depreciation, depletion and
amortization 22,963 21,351
185,263 165,634
INCOME FROM OPERATIONS 31,106 32,285
INTEREST EXPENSE AND OTHER:
Interest 12,873 11,692
Distributions on preferred
securities of subsidiary trust 1,373
Other (income) deductions - net (7,687) (1,710)
6,559 9,982
INCOME TAXES 9,795 8,017
NET INCOME 14,752 14,286
DIVIDENDS ON PREFERRED STOCK 922 1,807
NET INCOME AVAILABLE FOR
COMMON STOCK $ 13,830 $ 12,479
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 54,630 54,632
NET INCOME PER SHARE OF
COMMON STOCK $ 0.25 $ 0.23
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
June 30, December 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $45,328 and $52,125
plant under construction)
Electric $ 1,837,851 $ 1,764,702
Natural gas 520,870 516,693
2,358,721 2,281,395
Less - accumulated depreciation and depletion 739,738 705,119
1,618,983 1,576,276
NONUTILITY PROPERTY (includes $60,344 and $39,252
property under construction) 690,572 666,679
Less - accumulated depreciation and depletion 244,684 256,489
445,888 410,190
2,064,871 1,986,466
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 51,547 53,035
Reclamation fund 45,745 43,001
Other 40,234 39,531
137,526 135,567
CURRENT ASSETS:
Cash and temporary cash investments 7,547 32,404
Accounts receivable 106,300 142,347
Notes receivable (Note 1) 30,817
Materials and supplies (principally at average cost) 38,657 39,322
Prepayments and other assets 46,184 46,408
Deferred income taxes 10,892 11,095
240,397 271,576
DEFERRED CHARGES:
Advanced coal royalties 20,008 19,298
Regulatory assets related to income taxes 149,162 149,150
Regulatory assets - other 65,551 66,688
Other deferred charges 71,088 69,470
305,809 304,606
$ 2,748,603 $ 2,698,215
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
June 30, December 31,
1997 1996
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,639,640 and
54,630,994 shares issued) $ 692,245 $ 691,853
Retained earnings and other shareholders' equity 322,404 307,804
Unallocated stock held by trustee for retirement
savings plan (27,180) (28,360)
987,469 971,297
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 710,820 633,339
1,820,943 1,727,290
CURRENT LIABILITIES:
Short-term borrowing 67,494 104,702
Long-term debt - portion due within one year 80,235 69,268
Dividends payable 22,553 22,707
Income taxes 16,720 11,083
Other taxes 43,312 41,667
Accounts payable 45,337 62,218
Interest accrued 14,372 11,909
Other current liabilities 42,378 41,155
332,401 364,709
DEFERRED CREDITS:
Deferred income taxes 339,519 332,861
Investment tax credit 43,632 44,467
Accrued mining reclamation costs 127,376 129,878
Other deferred credits 84,732 99,010
595,259 606,216
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,748,603 $ 2,698,215
The accompanying notes are an integral part of these statements.
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
For Six Months Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 60,957 $ 54,601
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 45,919 42,106
Deferred income taxes 6,044 3,005
Noncash earnings form unconsolidated
independent power investments. (4,415) (5,475)
Reclamation expensed and paid - net (2,502) 2,594
Other noncash charges to net income - net 4,312 12,116
Changes in other assets and liabilities:
Accounts and notes receivable 5,230 40,597
Materials and supplies 665 384
Accounts payable (16,881) (20,053)
Other - net (10,849) (12,033)
Net cash provided by operating activities 88,480 117,842
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (144,884) (60,715)
Reclamation funding (2,744)
Sales of property 29,870 5,212
Additional investments (1,211) (1,031)
Net cash used by investing activities (118,969) (56,534)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (45,547) (47,352)
Sales of common stock 340 815
Issuance of long-term debt 96,452 125
Retirement of long-term debt (8,340) (16,871)
Issuance of mandatorily redeemable preferred
securities of subsidiary trust (65)
Net change in short-term borrowing (37,208) (6,847)
Net cash used by financing activities 5,632 (70,130)
CHANGE IN CASH FLOWS (24,857) (8,822)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 32,404 15,541
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 7,547 $ 6,719
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Three Months For:
Income taxes $ 26,481 $ 26,210
Interest 25,720 24,322
The accompanying notes are an integral part of these statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying financial statements of the Company for the interim
periods ended June 30, 1997 and 1996 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, 1996.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1997 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1 -- CONTINGENCIES AND COMMITMENTS:
In July 1985, the Federal Energy Regulatory Commission (FERC) issued to
the Company a new license for the 180 megawatt Kerr Project (Project) and
required the subsequent adoption of conditions to mitigate the impact of
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 Company's plan. This
matter has been pending FERC's consideration. For further information, see
Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements" in the Company's Annual Report on Form
10-K for the year ended December 31, 1996.
On June 25, 1997, FERC approved a mitigation plan, substantially adopting
the Department's conditions. FERC's order requires the Company to change
Project operations from peaking and load following to "baseload" generation.
The order requires the Company to make payments, beginning within 60 days of
the date of the order, to a fish and wildlife mitigation fund (fund). The
funds are to be deposited in a separate interest-bearing account jointly held
by the Tribes and the Company and managed by a fiduciary according to the terms
of an escrow agreement. The Tribes, in consultation with the Company, may use
moneys in the fund for the benefit of fish and wildlife. Required payments
include a payment of approximately $15,600,000 for the period from 1985 to
1997, a two-part "start-up" payment of $2,800,000 and $1,100,000, the second
part due a year from the date of the order, and annual payments of
approximately $1,400,000 payable through the end of the license term in 2035 or
until the Tribes elect to accept transfer of the license on or after 2015. In
addition, the order requires the Company to purchase approximately 6,800 acres
of habitat and build a revetment to minimize erosion at the north end of
Flathead Lake. The net present value of the total amount attributed to the
mitigation plan is approximately $57,000,000, which the Company recognized as
license costs in plant and long-term debt in the Consolidated Balance Sheet at
June 30, 1997. FERC concluded that the Department's conditions adversely
affect the Project's economics, but that, under the Federal Power Act, it has
no authority to reject or modify them. FERC noted, however, that the
reasonableness of the Department's conditions may be appealed to the Federal
Court of Appeals for review.
On July 30, 1997, the Company obtained from FERC a stay of the
obligation to make the $15,600,000 payment. The Company, the Tribes and the
Department have requested rehearing. In the event that FERC does not alter
the order to correct the unreasonableness of the Department's conditions, the
Company expects to seek judicial review, the outcome of which cannot be
predicted at this time.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. The estimated net present value of relicensing and proposed
environmental mitigation is approximately $158,000,000. The majority of the
cost is capital for physical improvements, which is not expected to be spent
before 2006. The FERC staff's draft environmental impact statement is
expected in late 1997. The Company expects to receive a license order in
late 1998 or early 1999.
In 1994, the Company entered an agreement to purchase 98 megawatts of
capacity during the winter months from Basin Electric Power Cooperative
(Basin), delivery of which was to begin in November 1996. The purchase
obligation under the agreement was from November 1, 1996 to April 30, 2010.
Under the terms of the agreement, the Company would have purchased seasonal
power between November and April of each year at a cost estimated to be
approximately $11,200,000 in 1997 and escalating annually, pursuant to the
contract. In October 1996, the Company requested that Basin prepare to
deliver the electricity to be purchased under the terms of the agreement at
alternative delivery points. Basin refused, breaching the agreement. On
October 31, 1996, the Company rescinded the agreement.
On November 5, 1996, Basin sued the Company in the Federal District
Court for the Southwestern District of North Dakota seeking specific
performance, a stay of the litigation and an order compelling the Company to
arbitrate the dispute. On March 20, 1997, the court ordered that all claims
and counterclaims, except counterclaims against Basin regarding antitrust and
wrongful interference with business or trade, be sent immediately to
arbitration. All litigation is stayed pending further order of the court.
While the Company is continuing to prepare for arbitration scheduled for
October 1997, it is discussing with Basin potential settlement of the matter.
As of June 30, 1997, the Company had not accrued $7,700,000 that would have
been payable under the terms of the rescinded agreement. The outcome of this
dispute cannot be predicted at this time.
Western Energy Company (Western), a subsidiary of the Company, is a
party in a dispute concerning the Coal Supply Agreement 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 a 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 Coal Supply Agreement was executed. Under the terms of
the Coal Supply Agreement, this change in the CPI allows any party to seek a
modification of the coal price if that party can demonstrate that an "unusual
condition" has occurred causing a "gross inequity." These NOOs are asserting
that a number of "unusual conditions" have 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 Coal Supply Agreement. These NOOs claim these "unusual
conditions" have created a "gross inequity" that must be remedied by a
reduction in the coal price. Western does not believe that under the terms
of the contract any "unusual condition" or "gross inequity" has occurred.
Western, the Company and these NOOs are seeking to resolve this dispute
as part of an on-going mediation to restructure the relationship of the NOOs,
including Puget, the Company and Western at the Colstrip Project. The outcome
of this dispute or the restructuring mediation cannot be predicted at this
time.
Houston Lighting & Power (HL&P), the purchaser of lignite produced by
Northwestern Resources Co. (Northwestern), a Company subsidiary, has filed
litigation in the District Court of the 157th Judicial District, Harris
County, Texas, seeking, among other remedies, a declaratory judgment that
changed conditions require 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 approximately $25,000,000
per year from these fees. HL&P alleges Northwestern failed to renegotiate
these fees in good faith as HL&P alleges the agreement requires. As its
remedy, HL&P seeks to terminate the LSA or, alternatively, asks the court to
declare reasonable fees. HL&P is seeking a reduction in excess of 60% in the
LSA fees and alleges that the reduction should be retroactive to September 1,
1995. Additionally, HL&P is seeking a declaration that it may substitute
other fuels for lignite without violating the LSA. If HL&P does not have
this right, it further seeks a declaration that the absence of this right
constitutes a gross inequity, which entitles HL&P to have the court reform
the LSA to provide the right to substitute fuels.
Northwestern disputes HL&P's claims. Northwestern and HL&P have filed
motions for summary judgment, seeking to narrow the issues subject to trial.
Trial will begin in September 1997. The outcome of this litigation cannot be
predicted.
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.
On February 28, 1997, the Company, through a Nonutility oil and natural
gas subsidiary, North American Resources Company (NARCO), signed agreements
for the acquisition of $85,000,000 of oil and natural gas assets from Vessels
Energy, Inc. (Vessels). These assets, in the Denver-Julesburg Basin north of
Denver, will allow NARCO to double its production of oil, natural gas and
natural gas liquids in that area. On April 23, 1997, NARCO acquired
$41,000,000 of Vessels' gathering, transmission and processing assets and
also acquired an option, exercisable through year-end, to purchase
$44,000,000 of Vessels' exploration and production assets. The acquisition
will be financed internally from the oil and natural gas operations and by
the use of bank financing. The Company intends to sell non-strategic oil and
natural gas assets in a manner that allows it to acquire the exploration and
production properties of Vessels in a transaction that will qualify as a
like-kind exchange under the Internal Revenue Code. At June 30, 1997, the
Company had a short-term note receivable from an unrelated party associated
with the acquisition of Vessel's exploration and production assets which is
expected to be realized before year-end 1997.
NOTE 2 - RATES, REGULATORY AND LEGISLATIVE MATTERS:
Electric:
The Company is pursuing a transition to retail electric competition
over the next several years. Montana's "Electric Industry Restructuring and
Customer Choice Act", which was supported by the Company and others, has been
passed by the Montana Legislature and was signed into law by the Governor in
May 1997.
The legislation provides for choice of electricity supplier for the
Company's customers; by July 1, 1998 for large customers, for pilot programs
for residential and small commercial customers by July 1, 1998 and choice for
all customers no later than July 1, 2002. Transmission and distribution
services will remain fully regulated by FERC and the Montana Public Service
Commission (PSC). Generation assets will be removed from rate base on July 1,
1998 and costs will be reflected in utility operations through a cost-based
contract through July 1, 2002 for those customers that do not have choice or
have not selected a competitive based supplier. The Company's Supply Division
will compete for customers that have choice during and after the transition
period is complete. Subject to the legislation's rate moratorium, electric
rates for all customers will be fixed at current levels for two years
beginning July 1, 1998, with the electric-energy supply component fixed for
an additional two years for smaller customers, with some limited exceptions.
The legislation provides for the recovery of non-mitigatable transition
costs, specifically recovery of above-market qualifying facility power-
purchase contract costs and regulatory assets, and a four-year recovery
period for utility-owned above-market generation costs. The legislation
authorizes the use of transition bonds, subject to the approval of a
financing order by the PSC, as a method of financing transition obligations
at lower costs. The legislation also defines the role the PSC will have in
regulating distribution services, licensing electricity suppliers in the
state, and promulgating rules regarding anti-competitive and abusive
practices. Finally, the legislation provides for reciprocity between utility
companies.
As required by the legislation, the Company filed a comprehensive
transition plan with the PSC on July 1, 1997. The filing contains the
Company's transition plan, including the proposed handling and resolution of
transition costs, and addresses other issues required by the legislation. The
Company expects the PSC to render a decision in May 1998, subject to the
above-mentioned legislative guidelines, on the amount of transition costs
that will be recoverable. The PSC will consider the Company's efforts to
mitigate transition costs in making its determination.
As a result of a three-year rate plan approved by the PSC, electric
rates increased 4.2% or approximately $14,800,000 on July 1, 1996. The plan
also included a revenue increase of 2.4% or approximately $8,800,000,
effective January 1, 1997, and an additional 2.4% increase or approximately
$9,000,000 is scheduled on January 1, 1998.
Natural Gas:
The Natural Gas Restructuring Act was also passed by the Montana
Legislature and signed into law in May 1997. This legislation allows for
natural gas utilities to open their systems to full customer choice and
authorizes the issuance of transition bonds to lower transition costs. The
legislation will facilitate the resolution of the Company's natural gas
restructuring filing now before the PSC. The July 1996 filing had requested
an increase in natural gas revenues of $4,800,000 or 3.8% annually to recover
increased costs of service and had included a formal open-access and
restructuring plan. The plan proposed an immediate increase in the number of
customers eligible to choose their own natural gas supplier, with all
customers having choice by mid-2002. The plan also requested recovery of
natural gas production and regulatory assets that will be uneconomic or
stranded under full customer choice. The procedural schedule for the filing
was suspended to allow continuing settlement efforts among the parties to the
filing. Stipulations addressing various items, including stranded costs and
regulatory assets, have been agreed-to by many of the contesting parties to
the filing and have been submitted to the PSC for approval. A hearing is
scheduled for September 16, 1997, with a final decision expected in the
fourth quarter of 1997.
On July 1, 1996, natural gas rates increased 5.3% or approximately
$6,700,000 annually as a result of a PSC-approved rate order.
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS:
The Company has a formal policy regarding the execution, recording, and
reporting of derivative instruments. The purpose of the policy is to manage
a portion of the price risk associated with its Nonutility producing assets
and firm supply commitments. The Company uses derivatives as hedging
instruments to meet budgeted earnings, reduce earnings volatility, and
provide stable cash flow. When fluctuations in natural gas and crude oil
market prices result in the Company realizing gains on the price swap
agreements into which it has entered, the Company is exposed to credit risk
relating to the nonperformance by counterparties of their obligation 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,
collar, and cap agreements to hedge revenue from anticipated production of
crude oil and natural gas reserves and supply costs 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 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. Under collar agreements, the Company makes or receives monthly
payments at the settlement date when the actual price of oil or natural gas
exceeds the ceiling or drops below the floor established in the agreement.
Under cap 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 cap established in the agreement depending on whether the
Company sells or buys a cap. At June 30, 1997, the Company had cap
agreements on approximately 276,000 barrels of crude oil, or 56% of its
expected production from proved, developed and producing oil reserves through
December 1997. The Company had cap and swap agreements on approximately 2.5
Bcf of Nonutility natural gas; or 57% of its expected production from proved,
developed and producing Nonutility natural gas reserves through October 1997.
In addition, the Company had swap and collar agreements to hedge
approximately 2.2 Bcf of Nonutility natural gas, or 25% of its expected
delivery obligations under long-term natural gas sales contracts through
March 1998.
The Company accounts for derivative transactions through hedge
accounting. The Company designates all 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 price swap agreements are reflected in
operating revenues on the Consolidated Statement of Income at the time of
settlement with the other parties. The Company uses the accrual method to
record its gains or losses. If the Company terminates a price swap agreement
prior to the date of the anticipated natural gas or crude oil production, the
gain or loss from the agreement is deferred in the Consolidated Balance Sheet
at the termination date. When the anticipated natural gas or crude oil
production occurs, the gain or loss from the price swap agreement is
recognized in the Consolidated Statement of Income. If the Company
determines that a portion of its anticipated natural gas or crude oil
production will not occur, thus creating a matching problem between the price
swap agreements and the anticipated production, any such unmatched price swap
agreements are marked-to-market and any unrealized gain or loss is recorded
in the Consolidated Statement of Income. At June 30, 1997, 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 June 30, 1997, the Company believes it would not
experience any materially adverse impacts from the risks inherent in these
instruments.
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 will use interest payments received on the Subordinated
Debentures it holds to make the quarterly cash distributions on the QUIPS.
NOTE 5 - LONG-TERM DEBT
During the second quarter of 1997, the Company borrowed $75,000,000
under a Revolving Credit Agreement, a portion of which was used to fund the
Vessels acquisition discussed in Note 1 to the Consolidated Financial
Statements.
In June 1997, in response to FERC's decision regarding the Kerr
mitigation plan discussed in Note 1 to the Consolidated Financial Statements,
the Company recognized long-term debt of approximately $57,000,000.
Approximately $38,000,000 is classified as due within one year in the
Consolidated Balance Sheet at June 30, 1997.
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, 1996.
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.
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 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, planned capital expenditures,
financing needs, and availability 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.
For the Six Months Ended June 30, 1997 and 1996:
Net Income Per Share of Common Stock:
Consolidated net income per share for the six months ended June 30, 1997
was $1.08, a 16% increase over the same period last year.
Nonutility earnings increased 20 cents per share primarily due to
increased earnings from oil and natural gas operations as a result of
significantly higher prices for oil and natural gas in the U.S. and Canada and
increased production during the first quarter of 1997. During the second
quarter, market prices returned to levels nearer those that were experienced in
the second quarter of 1996. Earnings from coal operations also increased as the
increase in coal volumes more than offset the decrease in price resulting from
the settlement of a dispute with Puget earlier this year. The Colstrip units,
which were displaced during the second quarter of 1996 due to low-cost power
available in the region, are operating normally this year. Nonutility earnings
include an after-tax gain of $4,400,000 on the sale of a Canadian oil property.
Net income from independent power operations decreased three cents per share
principally due to a decrease in long-term power sales revenue resulting from
the settlement with Puget.
Utility earnings for the six months ended decreased five cents per share
over last year principally due to a $3,600,000 before-tax metering correction
recorded in the second quarter of 1996 and higher-than-anticipated expenses for
a major overhaul at the Billings steam electric generating plant. The decrease
was partially offset by the Utility realizing better margins on its first
quarter electric wholesale activities and a decline in purchased power costs
primarily due to the expiration of two higher-priced firm contracts in 1996.
Warmer weather experienced during the earlier months of the year reduced
electric and natural gas volumes sold.
Six Months Ended
June 30, June 30,
1997 1996
Utility Operations $ 0.56 $ 0.61
Nonutility Operations 0.52 0.32
Consolidated $ 1.08 $ 0.93
</TABLE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Six Months Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 217,517 $ 205,297
Intersegment revenues 2,263 3,515
219,780 208,812
EXPENSES:
Power supply 66,234 66,745
Transmission and distribution 15,909 15,021
Selling, general and
administrative 27,693 22,055
Taxes other than income taxes 26,187 23,416
Depreciation and amortization 26,462 23,095
162,485 150,332
INCOME FROM ELECTRIC OPERATIONS 57,295 58,480
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 60,162 57,201
Gas supply cost revenues 9,934 13,980
Intersegment revenues 326 358
70,422 71,539
EXPENSES:
Gas supply costs 9,934 13,980
Other production, gathering and
exploration 4,675 4,691
Transmission and distribution 5,636 5,907
Selling, general and
administrative 9,509 8,682
Taxes other than income taxes 8,651 7,720
Depreciation, depletion and
amortization 6,503 5,860
44,908 46,840
INCOME FROM GAS OPERATIONS 25,514 24,699
INTEREST EXPENSE AND OTHER:
Interest 24,566 23,051
Distributions on QUIPS 2,746
Other (income) deductions - net (355) (1,461)
26,957 21,590
INCOME BEFORE INCOME TAXES AND DIVIDENDS 55,852 61,589
INCOME TAXES 23,468 24,758
DIVIDENDS ON PREFERRED STOCK 1,845 3,614
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 30,539 $ 33,217
</TABLE>
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 six months of
1997 in the Company's service territory were 7% warmer than 1996 and 1% warmer
than the historic average.
Weather, streamflow conditions and the wholesale power markets in the
Northwest and California influence the Company's electric wholesale revenues,
power-purchase expenses and output of thermal generation. The surplus of
hydroelectric power that existed in the region during the first six months of
1997 was managed more efficiently this year compared to 1996. Regional
opportunity purchased-power prices were higher than last year and
consequently, the Company's did not displace its thermal generation as it had
during the second quarter of 1996. Margins on off-system sales are tightening
as competition among suppliers increases.
As a result of the passage of electric and natural gas restructuring
legislation and the Company's restructuring filings, electric generation and
natural gas production assets of the Company will be removed from rate base.
Consequently, Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation" will no longer be
applicable to these electric generation and natural gas production assets of
the Company. The timing of this accounting change has not yet been
determined. The Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) met in July 1997 to discuss issues related to removing the
generation portion of a utility company from SFAS No. 71. Recovery of
Company's existing regulatory assets related to these generation and
production assets is provided in the electric restructuring legislation and
the agreed-upon stipulations in the natural gas restructuring case. Based
upon the EITF's conclusions regarding regulatory assets and liabilities and
the Company's anticipated recovery of its regulatory assets, the Company
believes that the discontinuation of regulatory accounting for these
generation and production assets will not have a material impact on the
Company's financial position or results of operations.
Preliminary calculations required by SFAS No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" do
not indicate a need for any material write-off of physical generation or
natural gas production assets.
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh)
6/30/97 6/30/96 6/30/97 6/30/96 6/30/97 6/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $135,773 $124,631 9% 2,165 2,163 0% 275,098 270,512 2%
Industrial 50,893 51,949 (2)% 1,210 1,199 1% 2,898 2,673 8%
General Business 186,666 176,580 6% 3,375 3,362 0% 277,996 273,185 2%
Sales to Other
Utilities 25,381 22,822 11% 1,392 1,327 5% 83 75 11%
Other 5,470 5,895 (7)%
Intersegment 2,263 3,515 (36)% 78 244 (68)% 229 231 (1)%
Total 219,780 208,812 5% 4,845 4,933 (2)% 278,308 273,491 2%
Power Supply
Expenses:
Hydroelectric 10,123 9,544 6% 2,116 2,245 (6)%
Steam 25,276 20,920 21% 1,870 1,704 10%
Purchases
and Other 30,835 36,281 (15)% 1,365 1,323 3%
Total Power Supply $ 66,234 $ 66,745 (1)% 5,351 5,272 1%
Cents Per kWh $1.244 $1.266
</TABLE>
Income from electric operations during the first six months of 1997
decreased approximately $1,200,000, or 2 percent, compared to 1996. The
decrease is primarily the result of higher than expected maintenance expenses
for a major overhaul at the Billings steam plant during the second quarter of
1997 and the recording of a $3,600,000 metering correction in 1996.
Revenues from general business customers increased $10,000,000
principally due to higher rates and customer growth. The increase was partially
offset by reduced volumes sold due to warmer weather experienced during the
earlier months of the year. The increases in secondary sales volumes and prices
more than offset the decrease in revenue resulting from the expiration of a
firm sales contract in early 1996. However, the margins realized on energy for
resale were not as high during the second quarter 1997 as those received in the
first quarter due in part to increased competition. Excluding the metering
correction mentioned above, purchased-power costs declined largely due to the
expiration of two higher-priced firm contracts. Selling, general and
administrative (SG&A) expenses increased primarily due to additional severance
costs recorded in 1997 and a reduction in credits for capitalized labor. Also,
as a result of the separation of transmission and generation functions per FERC
Order No. 888 certain costs previously recognized as operating expenses are now
classified as SG&A expenses. SG&A costs invoiced to the non-operating owners
decreased from 1996 as a result of reduced payroll costs at the Colstrip units.
Taxes other than income taxes increased due to increased property taxes
resulting from property additions. Depreciation expense increased as a result
of greater plant investment and a change in the PSC-approved depreciation rate.
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf)
6/30/97 6/30/96 6/30/97 6/30/96 6/30/97 6/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 60,547 $ 61,813 (2)% 13,403 13,750 (3)% 140,945 136,658 3%
Industrial 1,538 1,596 (4)% 359 375 (4)% 415 421 (1)%
Subtotal 62,085 63,409 (2)% 13,762 14,125 (3)% 141,360 137,079 3%
Gas Supply Cost
Revenues (GSC) (9,934) (13,980) (29)%
General Business
without GSC 52,151 49,429 6% 13,762 14,125 (3)% 141,360 137,079 3%
Sales to Other
Utilities 487 487 147 146 1% 4 3 33%
Transportation 4,818 4,867 (1)% 14,490 12,892 12% 38 32 19%
Other 2,706 2,418 12%
Total $ 60,162 $ 57,201 5% 28,399 27,163 5% 141,402 137,114 3%
</TABLE>
Customer growth and higher tariff rates resulted in an increase in
natural gas revenues from general business customers during the first six
months of 1997. Increased revenues were partially offset by reduced volumes
sold due to warmer weather. Gas supply cost revenues and expenses, which are
always equal due to rate and accounting procedures, decreased as a result of
reduced volumes sold and amortization of prior period over-collections.
Interest Expense and Other:
The change in interest expense is the result of increased borrowings
offset by lower rates. Since QUIPS have a mandatorily redeemable feature,
which causes the distributions to have characteristics of interest rather
than preferred stock dividends, these distributions are treated as interest
expense. Other income changed during the period due to costs associated with
the property transfer of Flint Creek Dam to Granite County, Montana during
the second quarter 1997.
<TABLE>
<CAPTION>
NONUTILTY OPERATIONS
Six Months Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 78,121 $ 69,709
Intersegment revenues 14,649 13,033
92,770 82,742
EXPENSES:
Operations and maintenance 54,936 52,830
Selling, general and
administrative 10,098 10,555
Taxes other than income taxes 10,238 8,842
Depreciation, depletion and
amortization 2,747 2,221
78,019 74,448
INCOME FROM COAL OPERATIONS 14,751 8,294
OIL AND NATURAL GAS:
REVENUES:
Revenues 76,808 58,469
Intersegment revenues 195 166
77,003 58,635
EXPENSES:
Operations and maintenance 47,938 35,451
Selling, general and
administrative 5,006 4,932
Taxes other than income taxes 2,653 1,758
Depreciation, depletion and
amortization 8,435 8,588
64,032 50,729
INCOME FROM OIL AND NATURAL GAS OPERATIONS 12,971 7,906
INDEPENDENT POWER:
REVENUES:
Revenues 34,218 38,000
Earnings from unconsolidated
investments 4,672 5,859
Intersegment revenues 1,214 421
40,104 44,280
EXPENSES:
Operations and maintenance 30,660 31,486
Selling, general and
administrative 2,196 1,866
Taxes other than income taxes 1,246 882
Depreciation, depletion and
amortization 966 1,568
35,068 35,802
INCOME FROM INDEPENDENT POWER OPERATIONS $ 5,036 $ 8,478
NONUTILITY OPERATIONS (continued)
Six Months Ended
June 30, June 30,
1997 1996
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $15,074 $12,879
Intersegment revenues 386
15,460 12,879
EXPENSES:
Operations and maintenance 10,364 8,499
Selling, general and
administrative 3,526 2,722
Taxes other than income taxes 329 192
Depreciation, depletion and
amortization 541 435
14,760 11,848
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 700 1,031
OTHER OPERATIONS:
REVENUES:
Revenues 705 545
Intersegment revenues 1,114 409
1,819 954
EXPENSES:
Operations and maintenance 695 555
Selling, general and
administrative 2,649 1,301
Depreciation, depletion and
amortization 266 339
3,610 2,195
LOSS FROM OTHER OPERATIONS (1,791) (1,241)
INTEREST EXPENSE AND OTHER:
Interest 2,899 1,978
Other (income) deductions - net (14,177) (2,341)
(11,278) (363)
INCOME BEFORE INCOME TAXES 42,945 24,831
INCOME TAXES 14,372 7,061
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $28,573 $17,770
</TABLE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations for the six months ended June 1997
increased due to significantly higher volumes of coal sold at the Rosebud
Mine and higher volumes of lignite sold at the Jewett Mines. Revenues from
the Rosebud Mine increased $7,700,000. Volume of coal sold to Colstrip Units
3 & 4 in 1997 increased more than 100% due to the plants being curtailed
during the same period in 1996 as a result of the availability of low-cost
hydroelectric power in the region. This increase was partially offset by a
price reduction resulting from the settlement of a dispute with Puget, a
slight decrease in volumes sold to Colstrip Units 1 & 2 and the reduction in
sales to the Corette Plant resulting from the 1996 switching of fuel
suppliers for early compliance with air quality standards. Coal volumes sold
to the Colstrip units throughout the remainder of the year are not expected
to be materially impacted by hydroelectric conditions in the region. Revenues
from the Jewett mine increased $2,300,000 due to a 17% increase in volumes of
lignite sold.
Operation and maintenance expense and taxes other than income taxes
increased primarily due to higher maintenance, royalties, and production
taxes resulting from the increased volumes sold at both mines.
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 $ 2
-volume (3)%
-price/bbl 26%
Natural gas -revenue $ 12
-volume 4%
-price/Mcf 21%
Miscellaneous $ 4
Income from the oil and natural gas operations improved due to
significantly higher market prices in the first quarter of 1997 and increased
U.S. oil production throughout the period. During the second quarter, market
prices for oil and natural gas returned to levels nearer those that were
experienced in the second quarter of 1996. Revenues from U.S. oil operations
increased $4,300,000 due to increased production resulting from a waterflood
injection project initiated in 1996 and other additional production from
existing wells along with higher market prices. The increase was partially
offset by decreased Canadian oil production resulting from the sale of
production properties in conjunction with the Company's increased emphasis on
its natural gas operations. Miscellaneous revenues increased primarily as a
result of increased processing and gathering revenues.
Operation and maintenance expense for oil and natural gas operations
increased due primarily to higher prices on natural gas purchases and
increased production costs.
Independent Power Operations:
The decrease in revenue from independent power operations is primarily
due to a $2,800,000 decrease in long-term power sales revenue resulting from
the settlement reached with Puget. The $1,200,000 decrease in earnings from
unconsolidated investments is largely the result of a change in the method of
accounting for one of the investments due to a change in the Company's
ownership interest and a back down of power at another project, which is not
expected to continue for the remainder of the year. These decreases were
partially offset by increased earnings from other unconsolidated investments.
Expenses for the six months ended decreased primarily due to lower
project development costs and reduced amortization of independent power
investments resulting from the accounting change previously discussed.
Telecommunications Operations:
Revenues from telecommunications operations increased primarily due to
higher volumes of long-distance minutes sold and the completion of equipment
sales projects during the year. The increases were offset primarily by
increased costs of sales. In the third quarter of 1997, the Company has begun
receiving revenues on its new Washington to Minnesota, Colorado to Canada
fiber optic network and these revenues are expected to increase in the fourth
quarter of 1997.
Other Operations:
In August 1997, the Company reached an agreement in principle to sell
its 16 percent interest in the Brasilia gold mine located in Paracatu,
Brazil, to TVX Gold Inc. of Toronto, Ontario for $20,000,000. The transaction
is expected to close in the fourth quarter 1997.
Interest Expense and Other:
Other income increased due to $12,800,000 of gains on dispositions of
oil and natural gas properties realized in the first and second quarters. The
increase was offset by costs associated with a discontinued SynCoal? project.
Quarter Ended June 30, 1997 and 1996:
Net Income Per Share of Common Stock:
Net income for the quarter ended June 30, 1997 was 25 cents per share, an
increase of two cents per share over the second quarter 1996.
Nonutility earnings increased eight cents per share due primarily to
increased earnings from coal operations as the increase in coal volumes sold
to the Colstrip generating units more than offset the decrease in coal prices
resulting from the settlement of a dispute with Puget earlier this year. The
Colstrip units are operating normally this quarter after being displaced
during the second quarter of 1996 due to the availability of low-cost power
in the region. Nonutility earnings include an after-tax gain of $4,400,000 on
the sale of a Canadian oil property. Net income from independent power
operations decreased three cents per share for the second quarter principally
due to a decrease in long-term power sales revenue resulting from the
settlement with Puget. Utility earnings for the second quarter of 1997
decreased six cents per share primarily due to a $3,600,000 before-tax
metering correction recorded in the second quarter of 1996 and unanticipated
1997 maintenance costs at the Billings steam plant.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Quarter Ended
June 30, June 30,
1997 1996
Utility Operations $ 0.05 $ 0.11
Nonutility Operations 0.20 0.12
Consolidated $ 0.25 $ 0.23
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Quarter Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 95,827 $ 85,410
Intersegment revenues 926 1,487
96,753 86,897
EXPENSES:
Power supply 30,668 24,999
Transmission and distribution 7,934 7,562
Selling, general and
administrative 13,488 10,742
Taxes other than income taxes 13,208 11,478
Depreciation and amortization 13,248 11,548
78,546 66,329
INCOME FROM ELECTRIC OPERATIONS 18,207 20,568
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 19,934 19,313
Gas supply cost revenues 3,082 3,904
Intersegment revenues 93 151
23,109 23,368
EXPENSES:
Gas supply costs 3,082 3,904
Other production, gathering and
exploration 2,208 2,325
Transmission and distribution 2,760 2,837
Selling, general and
administrative 4,752 4,334
Taxes other than income taxes 4,342 3,708
Depreciation, depletion and
amortization 3,247 2,929
20,391 20,037
INCOME FROM GAS OPERATIONS 2,718 3,331
INTEREST EXPENSE AND OTHER:
Interest 12,428 11,311
Distributions on QUIPS 1,373
Other (income) deductions - net 400 (966)
14,201 10,345
INCOME BEFORE INCOME TAXES AND DIVIDENDS 6,724 13,554
INCOME TAXES 3,259 5,731
DIVIDENDS ON PREFERRED STOCK 922 1,807
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 2,543 $ 6,016
</TABLE>
UTILITY OPERATIONS:
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh)
6/30/97 6/30/96 6/30/97 6/30/96 6/30/97 6/31/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 59,765 $ 52,185 15% 997 990 1% 274,853 270,263 2%
Industrial 24,573 22,258 10% 607 591 3% 3,461 3,053 13%
General Business 84,338 74,443 13% 1,604 1,581 1% 278,314 273,316 2%
Sales to Other
Utilities 8,766 8,415 4% 494 468 6% 82 75 9%
Other 2,723 2,552 7%
Intersegment 926 1,487 (38)% 31 102 (70)% 230 232 (1)%
Total 96,753 86,897 11% 2,129 2,151 (1)% 278,626 273,623 2%
Power Supply
Expenses:
Hydroelectric 5,066 4,901 3% 1,033 1,110 (7)%
Steam 13,817 9,433 46% 830 698 19%
Purchases
and Other 11,785 10,665 11% 518 438 18%
Total Power Supply $ 30,668 $ 24,999 23% 2,381 2,246 6%
Cents Per kWh $1.244 $1.113
</TABLE>
Income from electric operations during the second quarter 1997 decreased
approximately $2,300,000, compared to 1996 primarily due to the reasons
mentioned in the six months ended discussion.
Revenues from general business customers increased principally as a
result of higher tariffs, increased customer growth and a rate design change
which shifted revenue from the winter to the summer months. Revenues from sales
to other utilities increased only slightly as the increases in secondary sales
volumes and prices were mostly offset by the expiration of a firm sale contract
in 1996. The Colstrip steam generating units returned to normal operations this
year after being displaced during the second quarter of 1996 due to the
availability of low-cost hydroelectric power in the region. Excluding the
$3,600,000 metering correction recorded in the second quarter 1996, purchased-
power costs declined largely due to the expiration of a higher-priced firm
contract in 1996. Selling, general and administrative, taxes other than income
taxes and depreciation expenses increased for the same reasons discussed
previously.
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf)
6/30/97 6/30/96 6/30/97 6/30/96 6/30/97 6/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 18,866 $ 19,157 (2)% 4,023 4,145 (3)% 140,690 136,472 3%
Industrial 518 510 2% 121 120 1% 404 422 (4)%
Subtotal 19,384 19,667 (1)% 4,144 4,265 (3)% 141,094 136,894 3%
Gas Supply Cost
Revenues (GSC) (3,082) (3,904) (21)%
General Business
without GSC 16,302 15,763 3% 4,144 4,265 (3)% 141,094 136,894 3%
Sales to Other
Utilities 134 130 3% 33 32 3% 4 3 33%
Transportation 2,273 2,291 (1)% 6,475 6,133 6% 34 30 13%
Other 1,225 1,129 9%
Total $ 19,934 $ 19,313 3% 10,652 10,430 2% 141,132 136,927 3%
</TABLE>
Natural gas revenues from general business customers increased slightly
in comparison to the second quarter 1996. Gas supply cost revenues and
expenses, which are always equal due to rate and accounting procedures,
decreased as a result of reduced volumes sold and amortization of prior
period over-collections. The decrease was partially offset by higher
commodity costs.
Interest Expense and Other:
The change in interest expense and other is due to the reasons
discussed previously in the six month ended discussion.
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Quarter Ended
June 30, June 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 35,547 $ 31,319
Intersegment revenues 6,773 4,836
42,320 36,155
EXPENSES:
Operations and maintenance 25,228 25,294
Selling, general and
administrative 5,487 5,420
Taxes other than income taxes 4,419 3,467
Depreciation, depletion and
amortization 1,253 1,078
36,387 35,259
INCOME FROM COAL OPERATIONS 5,933 896
OIL AND NATURAL GAS:
REVENUES:
Revenues 34,452 29,406
Intersegment revenues 89 67
34,541 29,473
EXPENSES:
Operations and maintenance 23,469 17,802
Selling, general and
administrative 2,756 2,506
Taxes other than income taxes 1,093 924
Depreciation, depletion and
amortization 4,135 4,635
31,453 25,867
INCOME FROM OIL AND NATURAL GAS OPERATIONS 3,088 3,606
INDEPENDENT POWER:
REVENUES:
Revenues 17,020 18,283
Earnings from unconsolidated
investments 1,647 3,150
Intersegment revenues 397 352
19,064 21,785
EXPENSES:
Operations and maintenance 14,756 14,874
Selling, general and
administrative 1,107 1,044
Taxes other than income taxes 751 451
Depreciation, depletion and
amortization 661 784
17,275 17,153
INCOME FROM INDEPENDENT POWER OPERATIONS $ 1,789 $ 4,632
NONUTILITY OPERATIONS (continued)
Quarter Ended
June 30, June 30,
1997 1996
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 8,070 $ 6,564
Intersegment revenues 205
8,275 6,564
EXPENSES:
Operations and maintenance 5,529 4,335
Selling, general and
administrative 1,891 1,427
Taxes other than income taxes 193 101
Depreciation, depletion and
amortization 287 212
7,900 6,075
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 375 489
OTHER OPERATIONS:
REVENUES:
Revenues 543 310
Intersegment revenues 824 273
1,367 583
EXPENSES:
Operations and maintenance (1,003) 291
Selling, general and
administrative 3,239 1,365
Depreciation, depletion and
amortization 133 165
2,369 1,821
LOSS FROM OTHER OPERATIONS (1,002) (1,238)
INTEREST EXPENSE AND OTHER:
Interest 1,787 1,049
Other (income) deductions - net (9,427) (1,412)
(7,640) (363)
INCOME BEFORE INCOME TAXES 17,823 8,748
INCOME TAXES 6,536 2,285
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 11,287 $ 6,463
</TABLE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations for the quarter increased due to the
significantly higher volumes of coal sold to Colstrip Units 3 & 4 as
presented in the six months ended discussion. Revenues from the Rosebud Mine
increased $5,600,000 mostly due to the increase in volume of coal sold to
Colstrip Units 3 & 4 as a result of plant curtailments in the second quarter
of 1996 offset by price decreases resulting from the Puget settlement.
Revenues increases at the Jewett mine resulting from higher volumes were
partially offset by a reduction in reimbursable mining expenses primarily due
to non-recurring relocation costs incurred the second quarter in 1996.
The increase in operations and maintenance due to higher volumes at both
mines was offset by the decrease in reimbursable mining expenses mentioned
above. Taxes other than income taxes increased primarily due to higher
production taxes resulting from the increased volumes and revenues.
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 $ -
-volume (14)%
-price/bbl 8%
Natural gas -revenue $ 3
-volume 2%
-price/Mcf 8%
Miscellaneous $ 2
Income from the oil and natural gas operations for the quarter
decreased as slightly higher market prices and increased U.S. oil production
were more than offset by higher natural gas purchase costs and lower Canadian
oil and natural gas production. For the quarter, miscellaneous revenues
increased primarily as a result of increased processing and gathering
revenues.
Independent Power Operations:
Second quarter income from independent power operations decreased
primarily as a result of decreased revenue from Colstrip Unit 4 long-term
power sales and a decrease in earnings from unconsolidated investments as
presented in the six months ended discussion.
Telecommunications Operations:
For the quarter, increases in revenues from telecommunications
operations increased primarily due to higher volumes of long-distance minutes
sold and equipment sales were offset by increased costs of sales.
Interest Expense and Other:
Other income increased primarily due to $7,800,000 gains on the
disposition of oil properties in Canada.
LIQUIDITY AND CAPITAL RESOURCES:
On January 2, 1997, $5,000,000 of the 8.9% Series A Unsecured Medium-
Term Notes matured. The Company used short-term borrowings to retire the
Notes.
During the first quarter 1997, $35,000,000 borrowed under a Nonutility
Revolving Credit Agreement was repaid using short-term borrowings.
In April 1997, the Company entered into a Revolving Credit Agreement
for certain of its Nonutility operations. As a result, the Company's
consolidated borrowing capacity increased from $135,000,000 to $220,000,000.
Under terms of the agreement, the amount of the facility decreases on March
31, 1998, reducing the consolidated borrowing capacity to $160,000,000. At
June 30, 1997, $75,000,000 had been borrowed under the new Agreement; a
portion of which was used to fund the acquisition of Vessels' assets. See
Note 1 to the Consolidated Financial Statements for further discussion of
Vessels.
As discussed in Notes 1 and 5 to the Consolidated Financial Statements,
the Company recorded approximately $57,000,000 in long-term debt related to the
Kerr mitigation decision. Of this amount approximately $38,000,000 has been
classified as due within one year. The Company is obligated to make a payment
of $4,200,000 on or before August 24, 1997 to a fish and wildlife
implementation fund in accordance with the FERC order.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended June 30, 1997, the Company's ratio of
earnings to fixed charges was 3.26 times. Fixed charges include interest,
distributions on QUIPS, the implicit interest of the Colstrip Unit 4 rentals
and one-third of all other rental payments.
NEW ACCOUNTING PRONOUNCEMENTS:
The FASB has issued SFAS No. 128, "Earnings Per Share", which is
effective for financial statements issued for periods ending after December
15, 1997, including interim periods. The new standard requires entities with
complex capital structures to present "basic EPS" and "dilutive EPS" on the
face of the income statement. Basic EPS is the same EPS presentation that is
currently included in the Company's consolidated income statement. The
computation of dilutive EPS includes all dilutive potential common shares
that were outstanding during the period. Based upon the computation methods
included in the new standard, the Company expects that dilutive EPS will not
differ significantly from basic EPS.
During June 1997, the FASB released SFAS No. 130, "Reporting
Comprehensive Income". SFAS No. 130 requires the reporting in the financial
statements of all items recognized as components of comprehensive income
which is defined as changes in equity during the period from transactions,
events or circumstances from nonowner sources. The statement is effective
for fiscal years beginning after December 15, 1997.
Also during June 1997, the FASB released SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information". SFAS No. 131
requires the disclosure of certain operating information in complete
financial statements as well as condensed statements for interim periods
issued to shareholders. The statement is effective for financial statements
for periods beginning after December 15, 1997.
The Company is evaluating SFAS No. 130 and SFAS No. 131 at this time to
determine the effects on the financial statements and related disclosures.
Although the statements will affect the presentation of the information, they
are not expected to materially affect the Company's financial position or
results of operations.
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
Basin Electric Power Cooperative Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Houston Power & Light Lignite Sales Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits
Exhibit 3(b)(2) Amendment to By-laws dated May 12, 1997.
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
June 30, 1997.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K
DATE SUBJECT
April 21, 1997 Item 5. Other Events. Discussion of First
Quarter Net Income.
Item 7. Exhibits. Consolidated Statements
of Income for the Quarters Ended March 31,
1997 and 1996 and for the Twelve Months
Ended March 31, 1997 and 1996. Utility
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1997 and 1996 and the Twelve Months Ended
March 31, 1997 and 1996. Nonutility
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1997 and 1996 and the Years Twelve Months
Ended March 31, 1997 and 1996.
June 25, 1997 Item 5. Other Events. FERC decision on
Kerr Project mitigation.
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: August 14, 199
EXHIBIT INDEX
Exhibit 3(b)(2)
Amendment to By-laws dated May 12, 1997
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended June 30, 1997
Exhibit 27
Financial data schedule
- -14-
- -32-
- -35-
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 6/30/97, the Consolidated Income Statement and the
Consolidated Statement of Cash Flows for the six months ended 6/30/97 and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,618,983
<OTHER-PROPERTY-AND-INVEST> 583,414
<TOTAL-CURRENT-ASSETS> 240,397
<TOTAL-DEFERRED-CHARGES> 305,809
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,748,603
<COMMON> 692,245
<CAPITAL-SURPLUS-PAID-IN> 2,158
<RETAINED-EARNINGS> 293,066
<TOTAL-COMMON-STOCKHOLDERS-EQ> 987,469
65,000
57,654
<LONG-TERM-DEBT-NET> 629,977
<SHORT-TERM-NOTES> 67,494
<LONG-TERM-NOTES-PAYABLE> 79,604
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 79,486
0
<CAPITAL-LEASE-OBLIGATIONS> 1,239
<LEASES-CURRENT> 749
<OTHER-ITEMS-CAPITAL-AND-LIAB> 779,931
<TOT-CAPITALIZATION-AND-LIAB> 2,748,603
<GROSS-OPERATING-REVENUE> 497,421
<INCOME-TAX-EXPENSE> 37,840
<OTHER-OPERATING-EXPENSES> 382,946
<TOTAL-OPERATING-EXPENSES> 420,786
<OPERATING-INCOME-LOSS> 76,635
<OTHER-INCOME-NET> 12,504
<INCOME-BEFORE-INTEREST-EXPEN> 89,139
<TOTAL-INTEREST-EXPENSE> 28,182
<NET-INCOME> 60,957
1,845
<EARNINGS-AVAILABLE-FOR-COMM> 59,112
<COMMON-STOCK-DIVIDENDS> 43,706
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 88,480
<EPS-PRIMARY> 1.08
<EPS-DILUTED> 1.08
</TABLE>
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
June 30,1997
Net Income $ 127,655
Income Taxes 77,996
$ 205,651
Fixed Charges:
Interest $ 55,325
Amortization of Debt Discount,
Expense and Premium 1,624
Rentals 34,212
$ 91,161
Earnings Before Income Taxes
and Fixed Charges $ 296,812
Ratio of Earning to Fixed Charges 3.26 x
- -39-
Exhibit 3(b)(2)
BYLAWS
OF
THE MONTANA POWER COMPANY
Adopted on : August 22, 1995
As Amended on : August 27, 1996 & May 12, 1997
THE MONTANA POWER COMPANY
AMENDED BYLAWS
Article Amendment Date of Amendment
11 The affairs of the Corporation shall be managed by May 12, 1997
a Board of fourteen (14) Directors.
THE MONTANA POWER COMPANY
CERTIFICATION OF RESOLUTION
I, R. M. Ralph, Assistant Secretary of The Montana Power Company, a
corporation, hereby certify that the following is a full, true and correct
copy of Resolution duly adopted by the Board of Directors of The Montana
Power Company at a meeting duly called and held May 12, 1997 and that said
Resolution is in full force and effect as of the date of this certificate.
RESOLVED, that effective May 14, 1997, the first sentence of Section 11
of the Bylaws of The Montana Power Company is hereby amended to reduce the
number of Directors to fourteen (14) as follows:
SECTION 11. The affairs of the Corporation shall be managed by a
Board of fourteen (14) Directors.
IN WITNESS WHEREOF, I have hereunto set my hand and the Seal of said
Corporation this 6th day of August 1997.
/s/ R. M. Ralph
R. M. Ralph, Assistant Secretary
(SEAL)
