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, 1999
-- 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 9, 1999, the Company had 110,201,392 shares of common stock
outstanding.
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PART I
FINANCIAL INFORMATION
ITEM 1 - FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Nine Months Ended
September 30,
1999 1998
Thousands of Dollars
<S> <C> <C>
REVENUES $966,956 $869,579
EXPENSES:
Operations 479,512 374,288
Maintenance 61,918 60,724
Selling, general, and administrative 100,222 89,222
Taxes other than income taxes 76,625 72,582
Depreciation, depletion, and amortization 82,955 86,072
801,232 682,888
INCOME FROM OPERATIONS 165,724 186,691
INTEREST EXPENSE AND OTHER:
Interest 38,989 43,564
Distributions on company obligated mandatorily
redeemable preferred securities of subsidiary trust 4,119 4,119
Other (income) deductions - net (6,371) (3,026)
36,737 44,657
INCOME TAXES 40,702 46,813
NET INCOME 88,285 95,221
DIVIDENDS ON PREFERRED STOCK 2,768 2,768
NET INCOME AVAILABLE FOR
COMMON STOCK $ 85,517 $ 92,453
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - BASIC (000) 110,177 109,914*
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.78 $ 0.84*
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - DILUTED (000) 110,984 110,083*
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.77 $ 0.84*
The accompanying notes are an integral part of these statements.
? 1998 figures adjusted for the two-for-one stock split effective August 6, 1999.
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Quarter Ended
September 30,
1999 1998
Thousands of Dollars
<S> <C> <C>
REVENUES $335,687 $313,172
EXPENSES:
Operations 171,103 139,762
Maintenance 21,971 20,738
Selling, general, and administrative 36,049 26,284
Taxes other than income taxes 25,519 22,256
Depreciation, depletion, and amortization 27,600 31,285
282,242 240,325
INCOME FROM OPERATIONS 53,445 72,847
INTEREST EXPENSE AND OTHER:
Interest 12,489 14,662
Distributions on company obligated mandatorily
redeemable preferred securities of subsidiary trust 1,373 1,373
Other deductions (income) - net 123 (1,179)
13,985 14,856
INCOME TAXES 10,248 21,188
NET INCOME 29,212 36,803
DIVIDENDS ON PREFERRED STOCK 923 923
NET INCOME AVAILABLE FOR COMMON STOCK $ 28,289 $ 35,880
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - BASIC (000) 110,201 110,026*
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.26 $ 0.33*
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - DILUTED (000) 110,934 110,254*
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.26 $ 0.33*
The accompanying notes are an integral part of these statements.
* 1998 figures adjusted for the two-for-one stock split effective August 6, 1999.
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
ASSETS
September 30, December 31,
1999 1998
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $42,288 and $37,966
plant under construction)
Electric $ 1,872,481 $ 1,841,855
Natural gas 416,644 404,992
2,289,125 2,246,847
Less - accumulated depreciation and depletion 777,330 732,385
1,511,795 1,514,462
NONUTILITY PROPERTY (includes $91,064 and $10,990
property under construction) 968,963 864,981
Less - accumulated depreciation and depletion 336,436 297,933
632,527 567,048
2,144,322 2,081,510
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 21,090 24,268
Reclamation fund 42,937 41,542
Other 91,409 84,256
155,436 150,066
CURRENT ASSETS:
Cash and temporary cash investments - 10,116
Accounts receivable 159,017 170,652
Notes receivable - 29,089
Prepaid income taxes 88,276 -
Materials and supplies (principally at average cost) 46,124 42,292
Prepayments and other assets 61,288 57,331
Deferred income taxes 25,206 18,755
379,911 328,235
DEFERRED CHARGES:
Advanced coal royalties 12,813 14,312
Regulatory assets related to income taxes 121,720 121,735
Regulatory assets - other 154,822 154,193
Other deferred charges 80,184 78,044
369,539 368,284
$ 3,049,208 $ 2,928,095
The accompanying notes are an integral part of these statements.
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, December 31,
1999 1998
Thousands of Dollars
<S> <C> <C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (240,000,000 shares authorized;
110,201,392 and 110,121,040* shares issued) $ 703,647 $ 702,511
Retained earnings and other shareholders' equity 449,642 430,309
Accumulated other comprehensive income (loss) (18,621) (20,717)
Unallocated stock held by trustee for Retirement
Savings Plan (21,091) (23,298)
1,113,577 1,088,805
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 650,433 698,329
1,886,664 1,909,788
CURRENT LIABILITIES:
Short-term borrowings 37,600 69,820
Long-term debt - portion due within one year 80,397 96,292
Dividends payable 22,757 22,765
Income taxes - 24,857
Other taxes 69,290 51,777
Accounts payable 103,015 97,197
Interest accrued 12,330 13,156
Other current liabilities 52,685 40,087
378,074 415,951
DEFERRED CREDITS:
Deferred income taxes 268,918 323,906
Investment tax credit 32,412 35,175
Accrued mining reclamation costs 133,553 129,558
Other deferred credits 349,587 113,717
784,470 602,356
CONTINGENCIES AND COMMITMENTS (Notes 2 and 5)
$ 3,049,208 $ 2,928,095
The accompanying notes are an integral part of these statements.
* 1998 shares adjusted for the two-for-one stock split effective August 6, 1999
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THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
For Nine Months Ended
September 30,
1999 1998
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 88,285 $ 95,221
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, and amortization 82,955 86,072
Deferred income taxes (54,988) 2,522
Noncash earnings from unconsolidated investments. (12,300) (15,611)
Deferred revenue and other 235,870 3,132
Other noncash charges to net income - net 11,394 11,412
Changes in current assets and liabilities:
Accounts and notes receivable 40,724 (41,367)
Materials and supplies (3,832) (1,850)
Prepayments and other assets (3,957) (4,498)
Income taxes (113,133) 12,082
Deferred income taxes (6,451) 1,684
Accounts payable 5,818 10,036
Other assets and liabilities - net 17,286 32,142
Net cash provided by operating activities 287,671 190,977
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (159,794) (123,774)
Proceeds from property and investments 28,067 21,931
Additional investments (1,538) 5,024
Net cash used by investing activities (133,265) (96,819)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (68,872) (68,662)
Sales of common stock 652 6,619
Issuance of long-term debt 25,766 64,490
Retirement of long-term debt (89,848) (33,456)
Net change in short-term borrowing (32,220) (67,037)
Net cash used by financing activities (164,522) (98,046)
CHANGE IN CASH FLOWS (10,116) (3,888)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 10,116 16,706
CASH AND CASH EQUIVALENTS, END OF PERIOD $ - $ 12,818
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during nine months for:
Income taxes $ 212,280 $ 38,292
Interest 46,541 61,692
The accompanying notes are an integral part of these statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements of The Montana Power
Company for the interim periods ended September 30, 1999 and 1998 are unaudited
but, in the opinion of management, reflect all normally recurring accruals
necessary for a fair statement of the results of operations for those interim
periods. Results of operations for the interim periods are not necessarily
indicative of the results to be expected for the full year, and these financial
statements do not contain the detail or footnote disclosure concerning
accounting policies and other matters that would be included in full fiscal
year financial statements. Therefore, these statements should be read in
conjunction with our audited financial statements included in our Annual Report
on Form 10-K for the year ended December 31, 1998.
We have made reclassifications to certain prior-year amounts to make them
comparable to the 1999 presentation. These changes had no effect on previously
reported results of operations or shareholders' equity.
NOTE 1 - DEREGULATION, REGULATORY MATTERS, AND ASSET DIVESTITURE
Deregulation
The electric and natural gas utility businesses are in transition to a
competitive market in which energy commodity products and related services are
sold directly to wholesale and retail customers. The Montana electric and
natural gas restructuring and customer choice laws, passed in 1997, provide
that all customers will be able to choose their electricity and natural gas
suppliers by July 1, 2002.
Through September 1999, approximately 135 electric customers
representing more than 450 accounts crossing all customer sectors - or
approximately 25% of our pre-choice electric load, predominately industrial
and large commercial loads - have moved to competitive supply since the
inception of customer choice on July 1, 1998. Through September 1999,
approximately 240 natural gas customers with annual consumption of 5,000
dekatherms or more - or 54% of our pre-choice natural gas supply load - have
chosen alternate suppliers since the transition to a competitive natural gas
environment began in 1991.
As required by the electric legislation, we filed a comprehensive
transition plan with the Montana Public Service Commission (PSC) in July 1997.
Initial hearings on the filing began in April 1998, and the issues were
separated into two groups: Tier I and Tier II.
Tier I issues relate to customer choice for the large industrial
customer group and to pilot programs for the remaining customers. Tier II
issues deal with the recovery and treatment of the qualifying facility power-
purchase contract costs, which are above-market costs; regulatory assets
associated with the electric generating business; and a review of our electric
generating assets sale, including the treatment of sale proceeds above book
value of the assets.
In June 1998, the PSC rendered a decision on the Tier I issues. On
July 1, 1999, we filed a case with the PSC to resolve the Tier II issues. The
PSC had scheduled hearings on Tier II issues beginning in March 2000. On
September 2, 1999, the PSC suspended all hearings scheduled on Tier II issues
pending resolution of legal interpretations of customer-choice laws.
<PAGE>
Regulatory Matters
On March 30, 1998, we filed a request with the Federal Energy Regulatory
Commission (FERC) to increase our open access transmission rates and the rates
for bundled wholesale electric service to two rural electric cooperatives. In
January 1999, we reached a rate settlement with one of the cooperatives and in
March 1999 we reached a separate settlement with FERC, the intervenors, and
the other cooperative. As a result of the settlement, rates charged for
bundled wholesale electric service will change slightly for one cooperative,
not at all for the other cooperative, and rates charged for transmission
service have been increased on an interim basis pending final approval from
FERC. Increased transmission rates will have a positive effect on the results
of our transmission operations. As part of the settlement, one of the rural
electric cooperative customers retained the right to continue with its rate-
reduction complaint filed with FERC. We recently reached a settlement with
this customer and agreed to assist the customer in moving to choice of
electric supply when its full-service wholesale contract expires in June 2000
in exchange for its agreement to dismiss the rate-reduction complaint.
On August 12, 1999, we filed a natural gas rate case with the PSC
requesting increased annual revenues of $15,400,000, with a proposed interim
increase of $11,500,000. After PSC review, an interim increase is expected to
become effective before the end of the year and will remain in effect until
the final order is received. The filing also proposes (1) an alternative rate
plan, (2) "trackers" to reflect property taxes and replacement facilities in
rates on a more timely basis, (3) a change in the allocation of costs to
customer classes, and (4) rate-design changes that include recovery of
distribution charges through a fixed monthly system charge. We expect a
decision on this filing, which represents our first transmission and
distribution gas filing since Montana's Natural Gas Utility Restructuring and
Customer Choice Act (Natural Gas Act) was passed in 1997, before the end of
the second quarter 2000.
As required by Montana's Electric Industry Restructuring and Customer
Choice Act (Electric Act), a rate moratorium was established for all electric
customers pursuant to which rates cannot be increased, except under limited
circumstances, until July 1, 2000. We expect to submit a filing with the PSC
in the first half of 2000 to request increased rates as appropriate.
Asset Divestiture
We continue our work to complete the sale of electric generating assets
to PP&L Global, Inc. (PP&L Global), and we still expect to complete the sale
by the end of the year. We have completed all filings necessary to obtain
required regulatory approvals, and we continue to obtain required third-party
consents. In August, we exercised our contractual right to exclude Colstrip
Unit No. 4 generation and transmission assets from the sale. The exclusion of
these assets will reduce sales proceeds by $96,000,000.
NOTE 2 - CONTINGENCIES
Kerr Project and Project 2188
A FERC order requires us to implement a plan to mitigate the effect of
Kerr Project operations on fish, wildlife, and habitat. We are required to
make payments of approximately $135,000,000 between 1985 and 2020, the license
term, to implement this plan. The net present value of the total payments,
assuming a 9.5% discount rate, is approximately $57,000,000, an amount that we
recognized as license costs in plant and long-term debt in the Consolidated
Balance Sheet in 1997. A payment of approximately $15,600,000 for the period
from 1985 to 1997 is included in this amount.
<PAGE>
We have appealed FERC's order, requesting the United States Court of
Appeals for the District of Columbia Circuit to direct FERC to re-determine
several of the provisions in the order. FERC, through a related order, has
stated that we are not obligated to pay the $15,600,000 for the 1985 - 1997
period while the appeal is pending.
In November 1992, we applied to FERC to renew the license for nine
Madison River and Missouri River hydroelectric projects, with a generating
capacity of 292 MWs (Project 2188). The net present value of the cost of
environmental mitigation proposed by FERC's staff in this license proceeding
is approximately $162,000,000. We expect the license order from FERC in late
1999 or early 2000.
The Kerr Project and Project 2188 are assets that we agreed to sell to
PP&L Global under the terms of the Asset Purchase Agreement dated as of
October 31, 1998. At closing of the sale, PP&L Global will assume the
obligation to make payments required to comply with the license conditions. We
retained, however, the obligation to make (1) the disputed $15,600,000 payment
referred to above and, (2) other payments regarding "pre-closing" license
compliance expenditures, to the extent not reimbursed by PP&L Global.
Reliant Energy
Reliant Energy (Reliant), formerly known as Houston Lighting and Power,
is the purchaser of lignite produced by our subsidiary, Northwestern Resources
Co. (Northwestern). The Lignite Supply Agreement (LSA) requires Northwestern
to produce for Reliant approximately 9,000,000 tons of lignite per year until
July 29, 2015. Northwestern realizes revenues of approximately $25,000,000
per year from the payment of management and dedication fees charged under the
LSA pricing terms.
In late 1998, Reliant and Northwestern settled litigation regarding the
pricing terms of the LSA. Under the terms of the LSA, lignite prices will
continue to be set under pre-settlement pricing terms until June 30, 2002.
From July 1, 2002 through July 30, 2015, lignite prices will be the lesser of
(1) a re-determined price set to be competitive with Powder River Basin coal
supplies, or (2) the price that would have otherwise been paid under the pre-
settlement pricing terms. We expect that, if the market value of fuel stays
flat until the agreement is fully implemented, the competitive-pricing
structure could result in a reduction of our annual pretax income of
approximately $7,000,000 beginning July 1, 2002 through July 30, 2015. We can
mitigate this effect through efficiency and cost-savings measures.
Miscellaneous
We and our subsidiaries are parties to various other legal claims,
actions and complaints arising in the ordinary course of business. We do not
expect the conclusion of any of these matters to have a material adverse
effect on our consolidated financial position, results of operations, or cash
flows.
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS
Trading and Marketing of Electricity
Although we are exiting the electric trading and marketing businesses as
we announced in August 1998, our subsidiary, The Montana Power Trading &
Marketing Company (MPT&M), remains a party to one three-year derivative
financial instrument. MPT&M entered into this derivative financial instrument
<PAGE>
in June 1998 with an electric retail customer to manage a portion of the
customer's commodity price risk. We do not expect this instrument to have a
material effect on our consolidated financial position, results of operations,
or cash flows.
Trading and Marketing of Natural Gas, Crude Oil, and Natural Gas Liquids
We produce, purchase, transport, and sell natural gas, crude oil, and
natural gas liquids. Changes in the prices of these commodities can affect
our financial results. We manage this exposure to price risk, in part,
through MPT&M's use of derivative financial instruments. We discuss how we
manage our market risks in more detail in Part I, Item 3, "Quantitative and
Qualitative Disclosures About Market Risk."
Kinds of Derivative Financial Instruments
We use derivative financial instruments to reduce earnings volatility
and stabilize cash flows by hedging some of the price risk associated with our
nonutility energy commodity-producing assets, contractual commitments for firm
supply, and natural gas transportation agreements. We also use derivative
financial instruments in speculative transactions to seek enhanced
profitability based on expected market movements, as discussed below in
"Speculative Transactions." In all cases, financial swap and option
agreements constitute the principal kinds of derivative financial instruments
used for these purposes.
Swap Agreements
Under a typical swap agreement, we make or receive payments based
on the difference between a specified fixed price and a variable price
of natural gas or crude oil at the time of settlement. The variable
price is either a natural gas or crude oil price quoted on the New York
Mercantile Exchange (NYMEX) or a natural gas price quoted in Inside
FERC's Gas Market Report (IFGMR) or other recognized industry index.
Option Agreements
Under a typical option agreement, we make or receive monthly
payments based on the difference between the actual price of natural gas
or crude oil and the price established in a private agreement at the
time of execution. Receiving or making payments is dependent on whether
we buy (own or hold) or sell (write or issue) the option. Buying
options involves paying a premium - the price of the option - and
selling options involves receiving a premium. When we use options as
hedges, we defer all premiums paid or received and recognize the
applicable expenses or revenues monthly throughout the option term. At
September 30, 1999, we had deferred revenues of approximately $1,100,000
from option premiums related to these transactions.
Hedged Transactions
Hedged transactions are those in which we have a position (either
current or anticipated) in an underlying commodity or derivative of that
commodity that exposes us to risk if the price of the underlying item changes.
We enter into these transactions primarily to reduce earnings volatility and
stabilize cash flows. We recognize gains or losses from these derivative
financial instruments in the Consolidated Statement of Income at the same time
that we recognize the revenues or expenses associated with the underlying
hedged item; until then, we do not reflect these gains or losses in our
financial statements. Through September 30, 1999, we had unrecognized gains
of approximately $7,500,000 related to these transactions. If we terminate a
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hedging instrument before the date of the anticipated (1) commodity
production, (2) commodity purchase or sale, or (3) natural gas transportation
commitment, we immediately recognize the gain or loss from the derivative
financial instrument in the Consolidated Statement of Income.
At September 30, 1999, we had swap and option agreements to hedge
approximately 4.7 bcf of nonutility natural gas, or 16% of our expected
delivery obligations under long-term natural gas sales contracts through
December 2000. At September 30, 1999, we also had sold swap and option
agreements to hedge approximately 21.6 bcf of our nonutility natural gas
pipeline transportation obligations under contracts through October 2001 and
had purchased swap and option agreements to hedge approximately 21.3 bcf of
these obligations.
Speculative Transactions
We also enter into derivative financial transactions in which we have no
underlying price risk exposure nor any interest in making or taking delivery
of natural gas or oil commodities. We try, by these "speculative"
transactions, to profit from the market movements of the prices of these
commodities. In accordance with Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10), we mark to market all of our speculative
transactions and recognize any corresponding gain or loss in the Consolidated
Statement of Income. Through September 30, 1999, we recorded gains of
approximately $1,500,000 related to these transactions. (We discuss EITF 98-
10 more fully in Part I, Item 2, "Management's Discussion and Analysis of
Financial Condition and Results of Operations, New Accounting
Pronouncements.")
Counterparty Credit Risk
Part I, Item 3, "Quantitative and Qualitative Disclosures About Market
Risk," contains a summary of how we seek to address counterparty credit risk.
Independent Power Operations
One of our subsidiaries, Continental Energy Services, Inc. (CES), has
investments in independent power partnerships, some of which have entered into
derivative financial instruments to hedge interest rate exposure on floating-
rate debt and natural gas price fluctuations. We believe that, as of
September 30, 1999, we have not been exposed to any material adverse effects
from the risks inherent in these instruments.
NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST
We established Montana Power Capital I (Trust) as a wholly owned
business trust to issue common and preferred securities and hold Junior
Subordinated Deferrable Interest Debentures (Subordinated Debentures) that we
issue. 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 our Subordinated Debentures, 8.45% Series due 2036. The
Trust will use interest payments received on the Subordinated Debentures that
it holds to make the quarterly cash distributions on the QUIPS.
<PAGE>
NOTE 5 - COMMITMENTS
Purchase and Sale Commitments
We and our subsidiaries have entered into various contracts, with terms
expiring over the next five years, to purchase and sell power. The pricing
structure in one of our sales contracts provides that a portion of the
deliveries are at a fixed price and a portion of the deliveries are at an
index-based price. Approximately three years from now, all prices under the
contract become index based. All prices in this contract, which includes a
cap on the total volume of electricity that the customer can purchase, include
delivery of electricity to the customer's site.
When the sale of our electric generating assets is completed, and to the
extent that the electric restructuring transition process does not address
this contract, we will be subject to commodity price risk associated with
supplying the fixed-price portion of the contract. After closing, we plan to
fulfill our contractual obligations to this customer by supplying electricity
delivered to our transmission system pursuant to an index-based purchase
contract entered into by MPT&M that remains effective through July 2001. The
customer to which we must deliver electricity has provided us with usage
estimates through this time that do not exceed the volume of electricity that
MPT&M is committed to purchase.
We will continue to examine options and take steps to mitigate the
commodity price risk that we face because of our fixed-price sales contract.
With the uncertainties surrounding various arrangements that would allow us to
serve the contractual demand, we are unable to determine the effects that this
contract ultimately may have on our future consolidated financial position,
results of operations, or cash flows.
Touch America's Commitments
Construction Contract and Entech, Inc. Guarantee
In late October 1999, our subsidiary, Touch America, entered into a
contract to construct a high-speed, long-haul, fiber-optic network for a third
party. The contract allows Touch America to install its own fiber-optic
network as it constructs the third party's network. The network will span
more than 4,300 miles and will cover six different routes in the West, Pacific
Northwest, North Rocky Mountains, and Midwest. The contract contains capped
performance incentives if we meet, and capped penalties if we do not meet,
aggressive completion targets. The first route is scheduled for completion in
the fourth quarter of 2000, and the last route is scheduled for completion by
the end of the second quarter of 2001.
Touch America's estimated cost to construct the entire six-route network
is approximately $500,000,000. We expect various third parties to cover
approximately $250,000,000 (50%) of these costs. The third party for which
Touch America is constructing the network will reimburse Touch America the
majority of this 50% in stages as the construction is completed.
One of Touch America's parent companies, Entech, Inc. - our wholly owned
nonutility subsidiary company - guaranteed Touch America's performance of its
construction-related obligations related to the contract to construct the
4,300-mile fiber-optic network discussed above.
Joint Ventures
On July 1, 1999, Touch America and Iowa Network Services, Inc. formed
Iowa Telecommunications Services (ITS). ITS will purchase 280,422 domestic
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access lines in Iowa from a third party, involving 296 telephone exchanges.
Touch America holds a non-controlling interest in ITS and will invest
approximately $46,000,000 of capital in ITS. ITS will fund the purchase of
domestic access lines and telephone exchanges primarily through long-term
nonrecourse debt at the ITS level. We expect this transaction to close in
early 2000.
Touch America has loaned ITS $2,600,000, at an annual interest rate of
8%, to purchase computers and licenses. This note is payable on demand. In
November 1999, Touch America will loan ITS another $2,600,000 on the same
terms and for the same purposes.
On July 1, 1999, Touch America and US West Wireless entered into a joint
venture, TW Wireless (TWW), to provide "one number" digital wireless service
in a seven-state region of the Pacific Northwest and Upper Midwest. Touch
America holds a non-controlling interest in TWW. We expect that Touch America
will contribute approximately $53,000,000 over the next three years toward
construction of TWW's physical infrastructure.
On August 1, 1999, Touch America and New Century Energies (NCE) formed a
joint venture to provide dedicated telecommunication channels, or private-line
service, to enterprises in the Denver metropolitan area by the middle of 2000.
NCE will lease indefeasible rights to use its existing fiber-optic network to
the venture for twenty-five years at a cost of $10,000,000. Touch America
will contribute an estimated $3,000,000 in 1999 and $7,000,000 in 2000 to the
venture to construct six miles of fiber-optic cable and optronics. Touch
America owns a 50% interest in the venture.
FTV Communications LLC (FTV), the limited liability company formed by
Touch America, Williams Communications, and Enron Communications to construct
a fiber-optic route from Portland to Los Angeles, completed the construction
in late June. During construction, Touch America loaned FTV up to $35,000,000
in separate notes of various amounts at fixed rates of interest averaging
approximately 6% per year. FTV repaid the principal of the notes in
July 1999.
NOTE 6 - LONG-TERM DEBT
On February 1, 1999, we used the proceeds from asset-backed securities
issued by the MPC Natural Gas Funding Trust to retire $55,000,000 of our 7.7%
First Mortgage Bonds.
On September 3, 1999, we retired $10,000,000 of our 7.875% Series B
Unsecured Medium-Term Notes (MTNs) due December 23, 2026. We retired an
additional $5,000,000 of these MTNs on October 13, 1999. These amounts were
part of the long-term debt targeted for repurchase in the Tier II rate filing.
This filing is discussed in Part I, Item 1, "Notes to Consolidated Financial
Statements, Note 1 - Deregulation, Regulatory Matters, and Asset Divestiture."
NOTE 7 - COMPREHENSIVE INCOME
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income," defines comprehensive income as a change in equity of a
business enterprise from transactions and other events and circumstances from
nonowner sources. SFAS No. 130 requires that an enterprise report all
components of comprehensive income in the period in which the enterprise
recognizes these components.
<PAGE>
Components of comprehensive income are net income and other
comprehensive income. Net income includes income from continuing operations,
discontinued operations, extraordinary items, and cumulative effects of
changes in accounting principles. Other comprehensive income includes foreign
currency translations, adjustments of minimum pension liability, and
unrealized gains or losses on certain investments in debt and equity
securities.
For the nine months ended September 30, 1999 and 1998, our only item of
other comprehensive income was foreign currency translation adjustments to
retained earnings. These adjustments resulted in increases to retained
earnings of $2,096,000 in 1999 and decreases to retained earnings of
$7,306,000 in 1998. No current income tax effects resulted from the
adjustments. The 1998 adjustment included both the change in the valuation of
the assets of our Canadian operations and a change in the rate used to adjust
certain Canadian assets. When these Canadian assets were transferred from our
utility operations to our nonutility operations, and removed from utility rate
base, the assets were converted to United States dollars at current rates
rather than the historic rates used in the regulated environment. This
conversion accounted for approximately $5,100,000 of the 1998 decrease in
retained earnings.
<PAGE>
[This page intentionally left blank.]
<PAGE>
<TABLE>
<CAPTION>
NOTE 8 - INFORMATION ON INDUSTRY SEGMENTS
Operations Information
Nine Months Ended
September 30, 1999
Thousands of Dollars
UTILITY
Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 326,876 $ 75,915
Intersegment sales 9,706 448
Earnings from unconsolidated investments - -
Pretax operating income 80,482 7,203
Capital expenditures 37,181 10,090
Identifiable assets 1,671,608 386,293
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 144,806 $ 242,476 $ 55,727
Intersegment sales 29,523 12,863 1,139
Earnings from unconsolidated investments - - 15,028
Pretax operating income 25,119 13,491 1,674
Capital expenditures 3,740 30,262 412
Identifiable assets 241,243 314,959 107,427
NONUTILITY (continued)
Tele-
Communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 60,295 $ 35,565
Intersegment sales 639 1,453
Earnings from unconsolidated investments 10,268 -
Pretax operating income (loss) 17,057 (4,598)
Capital expenditures 76,504 13
Identifiable assets 214,715 91,585
CORPORATE
<S> <C>
Capital expenditures $ 1,592
Identifiable assets 21,378
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $ 941,660 $ - $ 941,660
Intersegment sales 55,771 (55,771) -
Earnings from unconsolidated investments 25,296 - 25,296
Pretax operating income 140,428 - 140,428
Capital expenditures 159,794 - 159,794
Identifiable assets 3,049,208 - 3,049,208
* The loss of revenues pursuant to one contract with a single customer would have a
material adverse effect on the segment.
** The loss of revenues pursuant to contracts with two customers would have a material
adverse effect on the segment.
*** The amounts indicated include certain eliminations between the business segments.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Operations Information
Nine Months Ended
September 30, 1998
Thousands of Dollars
UTILITY
Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 327,820 $ 74,127
Intersegment sales 4,712 531
Earnings from unconsolidated investments - -
Pretax operating income 94,208 7,803
Capital expenditures 42,979 16,168
Identifiable assets 1,551,658 391,224
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 128,869 $ 155,273 $ 54,534
Intersegment sales 28,501 13,396 1,626
Earnings from unconsolidated investments - - 29,179
Pretax operating income (loss) 22,986 9,046 (4,370)
Capital expenditures 5,541 38,376 465
Identifiable assets 243,329 286,351 135,694
NONUTILITY (continued)
Tele-
Communications*** Other
<S> <C> <C>
Sales to unaffiliated customers $ 63,924 $ 28,980
Intersegment sales 800 770
Earnings from unconsolidated investments 6,873 -
Pretax operating income (loss) 27,540 (6,574)
Capital expenditures 18,779 1,283
Identifiable assets 148,983 59,265
CORPORATE
<S> <C>
Capital expenditures $ 183
Identifiable assets 33,653
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments**** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $ 833,527 $ - $ 833,527
Intersegment sales 50,336 (50,336) -
Earnings from unconsolidated investments 36,052 - 36,052
Pretax operating income 150,639 - 150,639
Capital expenditures 123,774 - 123,774
Identifiable assets 2,850,157 - 2,850,157
* The loss of revenues pursuant to one contract with a single customer would have a
material adverse effect on the segment.
** The loss of revenues pursuant to contracts with two customers would have a material
adverse effect on the segment.
*** The loss of revenues pursuant to one contract with a single customer would have had
a material adverse effect on the segment.
**** The amounts indicated include certain eliminations between the business segments.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Operations Information
Quarter Ended
September 30, 1999
Thousands of Dollars
UTILITY
Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 104,899 $ 13,180
Intersegment sales 3,238 112
Earnings from unconsolidated investments - -
Pretax operating income (loss) 24,035 (3,876)
Capital expenditures 15,021 7,572
Identifiable assets 1,671,608 386,293
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 52,589 $ 96,922 $ 18,759
Intersegment sales 9,783 4,551 476
Earnings from unconsolidated investments - - 5,564
Pretax operating income 8,484 7,748 245
Capital expenditures 1,808 13,378 205
Identifiable assets 241,243 314,959 107,427
NONUTILITY (continued)
Tele-
Communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 19,167 $ 16,440
Intersegment sales 285 452
Earnings from unconsolidated investments 8,167 -
Pretax operating income (loss) 5,022 (1,944)
Capital expenditures 45,198 -
Identifiable assets 214,715 91,585
CORPORATE
<S> <C>
Capital expenditures $ 471
Identifiable assets 21,378
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $ 321,956 $ - $ 321,956
Intersegment sales 18,897 (18,897) -
Earnings from unconsolidated investments 13,731 - 13,731
Pretax operating income 39,714 - 39,714
Capital expenditures 83,653 - 83,653
Identifiable assets 3,049,208 - 3,049,208
* Sales under one contract with a single customer amounted to approximately
$34,110,000 and $28,455,000 for the quarters ended September 30, 1999 and September 30,
1998, respectively.
** The loss of revenues pursuant to contracts with two customers would have a material
adverse effect on the segment.
*** The amounts indicated include certain eliminations between the business segments.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Operations Information
Quarter Ended
September 30, 1998
Thousands of Dollars
UTILITY
Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 108,585 $ 13,777
Intersegment sales 2,258 179
Earnings from unconsolidated investments - -
Pretax operating income (loss) 36,786 (2,784)
Capital expenditures 18,293 9,473
Identifiable assets 1,551,658 391,224
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 40,391 $ 63,823 $ 18,154
Intersegment sales 8,645 3,763 444
Earnings from unconsolidated investments - - 20,829
Pretax operating income (loss) 6,643 4,185 (664)
Capital expenditures 4,143 11,048 235
Identifiable assets 243,329 286,351 135,694
NONUTILITY (continued)
Tele-
Communications*** Other
<S> <C> <C>
Sales to unaffiliated customers $ 21,716 $ 24,668
Intersegment sales 297 206
Earnings from unconsolidated investments 1,229 -
Pretax operating income (loss) 9,155 (2,532)
Capital expenditures 7,721 614
Identifiable assets 148,983 59,265
CORPORATE
<S> <C>
Capital expenditures $ 3
Identifiable assets 33,653
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments**** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $ 291,114 $ - $ 291,114
Intersegment sales 15,792 (15,792) -
Earnings from unconsolidated investments 22,058 - 22,058
Pretax operating income 50,789 - 50,789
Capital expenditures 51,530 - 51,530
Identifiable assets 2,850,157 - 2,850,157
* Sales under one contract with a single customer amounted to approximately
$34,110,000 and $28,455,000 for the quarters ended September 30, 1999 and September 30,
1998, respectively.
** The loss of revenues pursuant to contracts with two customers would have a material
adverse effect on the segment.
*** The loss of revenues pursuant to one contract with a single customer would have had
a material adverse effect on the segment.
**** The amounts indicated include certain eliminations between the business segments.
</TABLE>
<PAGE>
NOTE 9 - COMMON STOCK
On June 22, 1999, our Board of Directors approved a two-for-one split of
our outstanding common stock. As a result of the split, which was effective
August 6, 1999 for all shareholders of record on July 16, 1999, 55,099,015
outstanding shares of common stock were converted to 110,198,030 shares of
common stock. Unless otherwise noted, all outstanding common stock
information for 1998 reflected in this report is presented on a post-split
basis.
In 1998, our Board of Directors authorized a share-repurchase program
over the next five years to repurchase up to 20,000,000 shares (adjusted for
the stock split), or approximately 18%, of our outstanding common stock. As
of November 9, 1999, the Company had 110,201,392 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.
As a result of this authorization, we entered into a Forward Equity
Acquisition Transaction (FEAT) program with a bank that committed to purchase
on our behalf up to 5,000,000 shares, but not to exceed $125,000,000. On
November 12, 1999, we amended the FEAT program to increase the monetary limit
to $200,000,000. The expiration date of the program is October 31, 2000.
Until that date, when all transactions must be settled, we can elect to fully
or partially settle either on a full physical (cash) or a net share basis. A
full physical settlement would be the purchase of shares from the bank for
cash at the bank's average purchase price, including interest costs less
dividends. A net share settlement would be the exchange of shares between the
parties so that the bank receives shares with value equivalent to its original
purchase price, including interest costs less dividends. Only at the time
that the transactions are settled can our capital or outstanding stock be
affected.
Since the FEAT program began and through November 9, 1999, the bank had
acquired for us approximately 4,000,000 shares of our stock. The purchase of
these shares, including interest costs less dividends, averaged approximately
$30.81 per share and ranged from $27.02 per share to $33.50 per share for a
total cost of approximately $123,000,000.
If we had fully settled with the bank on November 9, 1999, when the
market price of our stock closed at approximately $28.06 per share, the
settlement would have cost us approximately $123,000,000 (approximately
4,000,000 shares times average cost of approximately $30.81 per share). A
net-share settlement on that date would have diluted our outstanding shares of
common stock by approximately 400,000 shares ($123,000,000 total cost divided
by $28.06 per share market price, less approximately 4,000,000 shares
purchased).
<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Please read the following discussion in conjunction with the statements
included in our Annual Report on Form 10-K for the year ended December 31, 1998
at Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
Safe Harbor for Forward-Looking Statements
This Quarterly Report on Form 10-Q may contain forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934. Forward-looking statements are qualified by and should be read together
with the cautionary statements and important factors included in our Annual
Report on Form 10-K for the year ended December 31, 1998 at Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Safe Harbor for Forward-Looking Statements." We are 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 us, or on our behalf, in this
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, we or one
of our 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 us or on our behalf
or by or on behalf of one of our subsidiaries, are expressly qualified by
these cautionary statements and any other cautionary statements that may
accompany the forward-looking statements. In addition, we disclaim any
obligation to update any forward-looking statements to reflect events or
circumstances after the date of this Form 10-Q.
Forward-looking statements that we make 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 our
revenue and cost trends, cost recovery, cost-reduction strategies and
anticipated outcomes, pricing strategies, planned capital expenditures,
financing needs and availability, changes in the utility industry, and the
effects of the year 2000 issue. Investors or other users of the forward-
looking statements are cautioned that such statements are not a guarantee of
our future performance 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 we have operations; competitive factors and the effects
of restructuring in the electric, natural gas, and telecommunications
industries; sanctity and enforceability of contracts; 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.
Strategy
We regularly assess our business units and evaluate opportunities to
create, develop, and maximize the value of our diverse businesses. We are
<PAGE>
focused on expanding Touch America's telecommunications business and taking
advantage of changes in the energy industry to gain regional advantages in the
electric and natural gas transmission and distribution businesses. In pursuing
this strategy, we will continue to investigate different approaches, including
asset purchases and sales, the issuance of securities, and other transactions
that may materially affect our results of operations, liquidity, and capital
resources.
Results of Operations
The following discussion describes significant events or trends that have
had an effect on our operations or which we expect to have an effect on our
future operating results.
For the Nine Months Ended September 30, 1999 and 1998:
Net Income Per Share of Common Stock (Basic)
Consolidated net income was $0.78 per share, compared with $0.84 for the
comparable period in 1998 (adjusted for the two-for-one stock split effective
August 6, 1999). Utility earnings were $0.19 per share, compared with $0.32
for the nine months ended September 30, 1998. Nonutility earnings were $0.59
per share, up $0.07 from the $0.52 figure for the nine months ended
September 30, 1998.
Utility
? Income from our electric utility operations decreased compared with
the nine months ended September 30, 1998.
? Revenues increased despite the rate moratorium and industrial
customers choosing other commodity suppliers as part of customer
choice. This exercise of choice reflects our ongoing exit from
the electric generation and supply business. Revenues increased
primarily due to increased volumes of surplus power sold in the
secondary markets, even though prices were down slightly.
? Higher expenses, especially selling, general, and administrative
expenses and electric transmission and distribution expenses, more
than offset these increased revenues. Approximately $2,800,000 of
the increase in the selling, general, and administrative expenses
was attributable to costs associated with implementing information
systems. The higher transmission and distribution expenses
resulted from the increased sales of surplus power.
? Income from our natural gas utility operations decreased during the
period mainly because higher expenses more than offset higher
transportation revenues, growth in residential and commercial
customers, and increased prices to recover gas-supply costs.
Nonutility
? Strong operating performance from all nonutility business units led
to overall improvement in this sector of our business.
? Income from coal operations increased due to higher revenues.
These higher revenues resulted from increased tons sold and
reimbursable mining expenses at the Jewett Mine and the effects of
a one-time refund issued by Western Energy in the third quarter of
1998.
<PAGE>
? Increased oil and natural gas income resulting from higher oil and
natural gas prices and increased natural gas volumes more than
offset a decrease in oil volumes sold.
? A third quarter 1998 contract settlement between an independent
power partnership in which CES was a partner and the power
purchaser had a material positive effect on third quarter 1998
income from independent power operations. As a result, income
from independent power operations decreased, though we continue to
benefit from improved operations at projects in which we hold
interests.
? Touch America continues to grow and to contribute solid earnings.
In January 1999, a telecommunications customer of Touch America
exercised its option to prepay all amounts due for the remaining
twelve-year initial term of a capacity agreement. Income from our
telecommunications operations for the nine months ended September
30, 1999 was approximately $17,000,000 lower than it would have
been without the prepayment because the amount of the prepayment
was discounted for early payment.
? Our investment income for the first nine months of this year
increased by approximately $4,400,000, and our interest expense
decreased, because of the prepayment.
For comparative purposes, the following table shows consolidated basic
net income per share by principal business segment.
Nine Months Ended
September 30
1999 1998*
Utility Operations $ 0.19 $ 0.32
Nonutility Operations 0.59 0.52
Consolidated $ 0.78 $ 0.84
* Adjusted for the two-for-one stock split effective August 6, 1999.
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Nine Months Ended
September 30,
1999 1998
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES:
Revenues $ 326,876 $ 327,820
Intersegment revenues 9,706 4,712
336,582 332,532
EXPENSES:
Power supply 98,688 97,405
Transmission and distribution 34,419 27,036
Selling, general, and administrative 44,448 38,393
Taxes other than income taxes 37,815 35,936
Depreciation and amortization 40,730 39,554
256,100 238,324
INCOME FROM ELECTRIC OPERATIONS 80,482 94,208
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 51,995 51,364
Gas supply cost revenues 23,920 22,763
Intersegment revenues 448 531
76,363 74,658
EXPENSES:
Gas supply costs 23,920 22,763
Other production, gathering, and exploration 1,650 1,557
Transmission and distribution 10,509 11,091
Selling, general, and administrative 15,621 14,877
Taxes other than income taxes 10,500 9,953
Depreciation, depletion, and amortization 6,960 6,614
69,160 66,855
INCOME FROM GAS OPERATIONS 7,203 7,803
INTEREST EXPENSE AND OTHER:
Interest 43,669 40,695
Distributions on company obligated mandatorily
redeemable preferred securities of subsidiary trust 4,119 4,119
Other (income) deductions - net (2,545) (1,932)
45,243 42,882
INCOME BEFORE INCOME TAXES AND DIVIDENDS 42,442 59,129
INCOME TAXES 19,289 21,462
DIVIDENDS ON PREFERRED STOCK 2,768 2,768
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 20,385 $ 34,899
</TABLE>
<PAGE>
UTILITY OPERATIONS
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Colder weather increases demand,
while warmer 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 Fahrenheit.
Heating degree days result when the average daily actual temperature is less
than this baseline.
As measured by heating degree days, weather for the third quarter 1999
was 156% colder than the same period last year. However, the temperatures for
the nine months ended September 30, 1999 in our service territory were only 4%
colder than 1998 and 5% warmer than normal. (For these purposes, "normal"
means the historic average.) Winter weather for the primary heating months of
January and February was 15% warmer than normal.
Our customers are billed on a cycle basis. As a result, some of the
monthly service that we provide has not been billed and recognized in
revenues. We record an "unbilled revenue" adjustment to reflect the change in
the level of this service. Due to changes in billing cycles, changes in rates
and weather may not affect this adjustment at the same time as they affect
billed revenues.
For our regulated operations, we follow SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." Pursuant to this pronouncement, we
recognize certain expenses and credits as they are reflected in revenues
collected through rates established by cost-based regulation. Changes in
regulation or changes in the competitive environment could result in our not
meeting the criteria of SFAS No. 71. If we were to discontinue application of
SFAS No. 71 for some or all of our regulated operations, we would have to
eliminate the related regulatory assets and liabilities from the balance sheet
and include the associated expenses and credits in income in the period when
the discontinuation occurred, unless recovery of those costs was provided
through rates charged to those customers in portions of the business that were
to remain regulated. In conjunction with the ongoing changes in the electric
industry and the sale of our electric generating assets, we will continue to
evaluate the applicability of this accounting principle to that portion of our
business. Based upon the anticipated recovery of our regulatory assets in
accordance with the electric restructuring legislation and the amounts that we
expect to receive from the sale of our electric generating assets, we believe
that discontinuing regulatory-accounting treatment for our electric generating
assets would not have a material adverse effect on our future consolidated
financial position, results of operations, or cash flows.
We have entered into various long-term contracts to purchase and sell
electricity. As discussed in Part I, Item 1, "Notes to Consolidated Financial
Statements, Note 5 - Commitments," we entered into a contract to sell
electricity which provides that a portion of the deliveries are at a fixed
price and a portion of the deliveries are at an index-based price. The
pricing structure requires us to deliver all electricity that the customer
wishes to purchase, subject to volume caps. The contract subjects us to
commodity price risk for the fixed-price deliveries, which continue through
2002. Until uncertainties are resolved with respect to other arrangements to
serve the contract, we are unable to determine the effects that this contract
may have on our future consolidated financial position, results of operations,
or cash flows.
<PAGE>
<TABLE>
<CAPTION>
Electric Utility
Revenues and
Power Supply Expenses Volumes
(Thousands of Dollars) (Thousands of MWh)
9/30/99 9/30/98 9/30/99 9/30/98
REVENUES:
<S> <C> <C> <C> <C> <C> <C>
RESIDENTIAL:
Non-choice $ 95,744 $ 92,916 3% 1,446 1,434 1%
Choice - - - - - -
Total Residential 95,744 92,916 3% 1,446 1,434 1%
SMALL COMMERCIAL, SMALL INDUSTRIAL,
AND GOVERNMENT AND MUNICIPAL:
Non-choice 120,621 121,694 (1%) 2,007 2,085 (4%)
Choice 1,848 14 13100% 85 - -
Total Small Commercial, Small
Industrial, and Government and
Municipal 122,469 121,708 1% 2,092 2,085 0%
LARGE COMMERCIAL, LARGE INDUSTRIAL:
Non-choice 26,415 63,863 (59%) 765 1,673 (54%)
Choice 9,770 873 1019% 1,048 115 811%
Total Large Commercial, Large
Industrial, and Government and
Municipal 36,185 64,736 (44%) 1,813 1,788 1%
IRRIGATION AND STREET LIGHTING:
Non-choice 11,735 11,860 (1%) 125 120 4%
Choice 615 - - - - -
Total Irrigation and
Street Lighting 12,350 11,860 4% 125 120 4%
UNBILLED REVENUE ADJUSTMENT (4,261) (5,382) 21% 45 (71) 163%
GENERAL BUSINESS REVENUES 262,487 285,838 (8%) 5,521 5,356 3%
SALES TO OTHER UTILITIES 50,362 32,005 57% 2,490 1,326 88%
OTHER 14,027 9,977 41% - - -
INTERSEGMENT 9,706 4,712 106% 62 98 (37%)
TOTAL 336,582 332,532 1% 8,073 6,780 19%
POWER SUPPLY EXPENSES:
HYDROELECTRIC 16,497 15,793 4% 2,932 2,879 2%
STEAM 41,580 36,142 15% 3,559 3,263 9%
PURCHASED POWER AND OTHER 40,611 45,470 (11%) 2,030 1,417 43%
TOTAL $ 98,688 $ 97,405 1% 8,521 7,559 13%
DOLLARS PER MWh $ 11.58 $ 12.89
</TABLE>
General Business Revenues
See Part I, Item 1, "Notes to the Consolidated Financial Statements,
Note 1 - "Deregulation, Regulatory Matters, and Asset Divestiture," for
information regarding the rate moratorium establish by the Electric Act.
<PAGE>
Revenues from electric utility operations increased for the nine months
ended September 30, 1999, even though general business revenues decreased,
primarily because of a decrease in revenues from the "large" industrial-
customer classification. Revenues from "large" industrial customers decreased
due to a number of these customers choosing other commodity suppliers. An
increase in general business prices to recover the cost of public-purpose
programs in accordance with the Electric Act lessened the effects of decreased
revenues from large industrial customers.
The State of Montana's Electric Act, signed into law in May 1997,
provided for choice of electricity supplier for large customers by July 1,
1998; for pilot programs for residential and small commercial customers by
July 1, 1998; and choice for all customers no later than July 1, 2002. Even
though we no longer supply the electricity for customers that chose other
commodity suppliers, we still earn distribution and transmission revenues for
moving their electricity across our distribution and transmission lines. The
distribution revenues are reflected as "Choice" revenues and the transmission
revenues are reflected as "Other" revenues in the table above. For customers
that have not chosen other suppliers, "Non-choice" revenues reflect fully
bundled rates for generating, transmitting, and distributing electricity.
Sales to Other Utilities
Before the Electric Act, our utility bought and sold electric generation
in excess of the needs of our general business customers in the secondary
markets outside Montana. We reflected these transactions as "sales to other
utilities" in the table above. Because of the electric restructuring,
beginning July 1, 1998, our nonutility now performs this activity for our
utility. However, sales in the secondary markets are still reflected as
"sales to other utilities" in the table above.
Revenues from sales to other utilities increased because of increased
volumes sold in the secondary markets, even though prices were down slightly
compared with year-to-date 1998. We had more electricity available to sell in
the secondary markets because of increased plant availability and lower
consumption attributable to customers continuing to choose other suppliers.
Other
Other revenues increased mainly because of revenues earned for
transmitting energy for customers that chose other suppliers. Prior to the
Electric Act, we classified transmission revenues from customers that chose
other suppliers as general business revenues; we now reflect these
transmission revenues as "other" revenues.
Intersegment
Intersegment revenues increased because of the revenues associated with
transmitting across our lines the electricity sold in the secondary markets.
Although we continue to reflect sales in the secondary markets as "sales to
other utilities," as discussed above, beginning July 1, 1998, we began
reflecting revenues earned from the transmission of the electricity sold to
other utilities in the "intersegment" line of the segmented schedule of
revenues and expenses. The associated transmission volumes are the same
volumes associated with the sale of energy in the secondary markets.
Therefore, these volumes are reported in the "sales to other utilities" line
in the table above. In addition, as a result of the Electric Act, the
intersegment sale of energy to Colstrip Unit No. 4 is now performed by our
nonutility. Although the difference in intersegment revenues is not as
apparent, the effect on total intersegment volumes, in conjunction with the
absence of related transmission volumes, is more pronounced.
<PAGE>
Expenses
Power-supply expenses increased primarily due to increased steam
maintenance and generation costs. Our utility's termination of secondary
purchases partially offset these increases. Transmission and distribution
expenses increased because of the costs associated with transmitting outside
our service territory the electricity sold in the secondary markets. Taxes
other than income taxes and depreciation expense increased, representing
additional plant and higher property values.
Selling, general, and administrative expenses increased approximately
$6,000,000 mainly because of the following items:
? Costs of approximately $1,500,000 incurred to train staff and to
adapt business processes to implement a new Enterprise Resource-
Planning (ERP) information system and similar costs of approximately
$1,300,000 for a new Enterprise Customer-Care (E-CIS) information
system.
? The ERP system will provide future benefits through an integrated
system that will maximize efficiencies in business processes. We
expect the electric utility to incur approximately $400,000 in
expense in the fourth quarter of 1999 and approximately $1,000,000
of expense in 2000 as we continue to implement the ERP system,
which we expect to have fully implemented by September 2000;
? We implemented the E-CIS system in September 1999. It is Y2K-
ready and will provide future benefits by allowing us to better
manage our transition to customer choice of energy supply;
? An increase of approximately $2,500,000 relating to energy efficiency
and public-purpose programs in compliance with the Universal System
Benefits Charge (USBC) requirements of the Electric Act. In
accordance with the Electric Act, we collect the costs associated
with the energy efficiency and public-purpose programs through a
separate component of rates;
? An increase of approximately $1,100,000 in rent expense for our
automated meter-reading equipment. The amount of rent increased in
proportion to the amount of equipment purchased and installed during
the implementation schedule. Because the automated meter-reading
program was fully implemented on June 1, 1999, we expect annual rent
expense to remain relatively steady throughout the remaining five-
year term of the lease;
? An increase of approximately $1,400,000 in incentive compensation
accruals; and
? Increases in other administrative costs of approximately $600,000,
which were more than offset by reduced pension expense of
approximately $2,400,000. Accounting pronouncements calculate
pension expense independent of current funding, which serves as the
basis for rates. The difference between expense and funding is
reflected as miscellaneous revenues and either a regulatory asset or
liability. Due to the strong performance of the assets in the
pension trust, no funding was required in 1998 and none is expected
in 1999. Therefore, the change in pension expense between 1998 and
1999 is completely offset by an adjustment to miscellaneous revenues.
<PAGE>
<TABLE>
<CAPTION>
Natural Gas Utility
Revenues Volumes*
(Thousands of Dollars) (Thousands of Dkts)
9/30/99 9/30/98 9/30/99 9/30/98
REVENUES:
<S> <C> <C> <C> <C> <C> <C>
RESIDENTIAL $ 46,388 $ 43,991 5% 8,651 8,721 (1%)
SMALL COMMERCIAL, SMALL INDUSTRIAL,
AND GOVERNMENT AND MUNICIPAL 22,873 23,541 (3%) 4,334 4,488 (3%)
UNBILLED REVENUE ADJUSTMENT (6,164) (5,911) (4%) (1,070) (1,024) (4%)
GENERAL BUSINESS REVENUES 63,097 61,621 2% 11,915 12,185 (2%)
LESS: GAS SUPPLY COST REVENUES (GSC) 23,920 22,763 5% - - -
GENERAL BUSINESS REVENUES
WITHOUT GSC 39,177 38,858 1% 11,915 12,185 (2%)
SALES TO OTHER UTILITIES 536 463 16% 182 155 17%
TRANSPORTATION 11,545 10,990 5% 18,595 19,802 (6%)
OTHER 737 1,053 (30%) - - -
TOTAL $ 51,995 $ 51,364 1% 30,692 32,142 (5%)
* In September 1996, we began billing our natural gas customers on a thermal method
rather than a volumetric method. The thermal method measures the heat content of
natural gas from the different sources that enter our system and applies heat and
altitude factors to the Mmcfs (thousands of cubic feet) of natural gas consumed to
determine the heat used (Dekatherms or Dkts). Our former customer-billing system was
Mmcf-based and, as a result, our financial reports analyzed natural gas revenues in
terms of Mmcfs. With the implementation of our E-CIS this quarter, we can analyze
natural gas revenues in terms of Dkts - the basis of how we now bill our customers.
</TABLE>
See Part I, Item 1, "Notes to the Consolidated Financial Statements,
Note 1 - Deregulation, Regulatory Matters, and Asset Divestiture" for
information regarding the August 12, 1999 natural gas rate case filed with the
PSC.
Since 1991, the natural gas utility business has been in transition to a
competitive environment to provide commodity and related services to wholesale
and retail customers. The State of Montana's Natural Gas Act, signed into law
in May 1997, allowed natural gas utilities to open their systems to full
customer choice for gas supply. In October 1997, the PSC approved an order
(Order) allowing natural gas customers with annual loads greater than 5,000
dekatherms the right to choose their own suppliers. At this time, all of our
"large" industrial and "large" commercial customers have chosen other
commodity suppliers. Even though we no longer supply the natural gas for
those customers, we still earn transportation revenues from moving their
natural gas along our pipelines. These revenues are reflected as
"transportation" revenues in the table above.
Natural gas revenues increased for the nine months ended September 30,
1999 mainly because of customer growth and a weather-related increase in
volumes sold. Revenues from industrial customers decreased as a result of
<PAGE>
customers continuing to choose other commodity suppliers in accordance with
the PSC Order. Although revenues from industrial customers decreased, we
experienced customer growth in the "small" industrial-customer classification.
Transportation revenues increased principally because of transportation of gas
for customers that chose other suppliers. An actuarial pension plan
adjustment related to the difference between pension expense and current
funding, as discussed above in the electric utility section, negatively
affected other revenues.
Selling, general, and administrative expenses increased chiefly because
of expensed costs for implementing the ERP system and the E-CIS system and
increased rent expense associated with the automated meter-reading program, as
discussed above. A decrease in pension plan payments resulting from higher-
than-expected pension plan earnings partially offset the increase. Taxes
other than income taxes increased largely as a result of increased property
taxes, representing higher property values and additional plant.
Utility Interest Expense and Other
Interest expense increased primarily due to the intersegment interest
expense of approximately $4,100,000 associated with increased loans from
nonutility operations to utility operations. Decreased short-term borrowing in
1999 and the retirement of Medium-Term Notes late in 1998 partially offset this
increased interest expense.
<PAGE>
<TABLE>
<CAPTION>
NONUTILTY OPERATIONS
Nine Months Ended
September 30,
1999 1998
Thousands of Dollars
COAL:
<S> <C> <C>
REVENUES:
Revenues $144,806 $128,869
Intersegment revenues 29,523 28,501
174,329 157,370
EXPENSES:
Operations and maintenance 109,630 97,030
Selling, general, and administrative 14,415 13,085
Taxes other than income taxes 19,575 17,007
Depreciation, depletion, and amortization 5,590 7,262
149,210 134,384
INCOME FROM COAL OPERATIONS 25,119 22,986
OIL AND NATURAL GAS:
REVENUES:
Revenues 242,476 155,273
Intersegment revenues 12,863 13,396
255,339 168,669
EXPENSES:
Operations and maintenance 206,554 125,700
Selling, general, and administrative 13,812 14,382
Taxes other than income taxes 4,229 3,613
Depreciation, depletion, and amortization 17,253 15,928
241,848 159,623
INCOME FROM OIL AND NATURAL GAS OPERATIONS 13,491 9,046
INDEPENDENT POWER:
REVENUES:
Revenues 55,727 54,534
Earnings from unconsolidated investments 15,028 29,179
Intersegment revenues 1,139 1,626
71,894 85,339
EXPENSES:
Operations and maintenance 48,434 47,910
Selling, general, and administrative 3,032 3,028
Taxes other than income taxes 1,384 1,363
Depreciation and amortization 2,342 8,229
55,192 60,530
INCOME FROM INDEPENDENT POWER OPERATIONS $ 16,702 $24,809
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS (continued)
Nine Months Ended
September 30
1999 1998
Thousands of Dollars
TELECOMMUNICATIONS:
<S> <C> <C>
REVENUES:
Revenues $60,295 $63,924
Earnings from unconsolidated investments 10,268 6,873
Intersegment revenues 639 800
71,202 71,597
EXPENSES:
Operations and maintenance 25,842 19,937
Selling, general, and administrative 8,887 8,089
Taxes other than income taxes 2,332 3,874
Depreciation and amortization 6,816 5,284
43,877 37,184
INCOME FROM TELECOMMUNICATIONS OPERATIONS 27,325 34,413
OTHER OPERATIONS:
REVENUES:
Revenues 35,565 28,980
Intersegment revenues 1,453 770
37,018 29,750
EXPENSES:
Operations and maintenance 36,026 31,137
Selling, general, and administrative 1,536 1,150
Taxes other than income taxes 790 836
Depreciation and amortization 3,264 3,201
41,616 36,324
LOSS FROM OTHER OPERATIONS (4,598) (6,574)
INTEREST EXPENSE AND OTHER:
Interest 4,083 7,037
Other (income) deductions - net (12,589) (5,262)
(8,506) 1,775
INCOME BEFORE INCOME TAXES 86,545 82,905
INCOME TAXES 21,413 25,351
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 65,132 $57,554
</TABLE>
<PAGE>
NONUTILITY OPERATIONS
Coal Operations
Income from our coal operations for the nine months ended September 30,
1999 increased approximately $2,100,000 compared with the same period last
year. Revenues from the Jewett Mine increased approximately $12,200,000 as a
result of a 3% increase in tons sold and an increase in reimbursable mining
expenses. Revenues from the Rosebud Mine, including revenues from a synthetic
fuel project, increased approximately $4,800,000 despite a 5% decrease in tons
of coal sold to the Colstrip Units. Revenues increased primarily because
Western Energy paid approximately $7,900,000 in one-time refunds in the third
quarter of 1998 to the owners of Colstrip Units No. 3 and No. 4 to settle
contract disputes. This increase was partially offset by a nonrecurring
second quarter 1999 refund of approximately $2,700,000 issued by Western
Energy to one of its customers for final pit reclamation funds previously
collected. That customer has assumed responsibility for a portion of all
final pit reclamation expenses in the future.
Coal operations and maintenance expenses increased at the Jewett Mine
because of higher royalties, increased overburden stripping costs, and rental
expenses incurred on additional equipment needed to meet demand. Operations
and maintenance expenses increased at the Rosebud Mine due to higher
royalties, costs associated with a pit extension, and unanticipated equipment
repairs. A $2,700,000 credit to reclamation expense associated with the
refund discussed above partially offset these increases. Taxes other than
income rose due to the increased revenue received for coal sold in 1999 and a
property tax refund received at the Jewett Mine in the third quarter of 1998.
Depreciation, depletion, and amortization decreased because some equipment at
the Rosebud Mine became fully depreciated in the first quarter of 1998 and
additional depreciation on idle equipment was recorded in the second quarter
of 1998.
Oil and Natural Gas Operations
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenues and the related percentage
changes in volumes sold and prices received:
Oil -revenue $ -
-volume (19%)
-price/bbl 11%
Natural gas -revenue $ 79
-volume 45%
-price/Mcf 8%
Natural gas liquids -revenue $ 7
-volume 20%
-price/bbl 26%
Miscellaneous $ 1
Income from our oil and natural gas operations increased approximately
$4,400,000 due to increased marketing activities and higher prices in the
first nine months of 1999 compared with 1998. Natural gas revenues increased
because marketing and trading revenues and volumes were significantly higher
as a result of increased sales into California and Midwestern markets. In
addition, gas production and prices both were higher. Revenues from oil
<PAGE>
operations were flat because higher prices were offset by lower production as
a result of our ongoing strategy to focus more on natural gas and to reduce
our oil position. Natural gas liquids revenues were higher, again because of
increased marketing and trading activities and higher prices.
Operations and maintenance expense increased mainly because of increased
purchased gas costs associated with the California and Midwestern gas sales
discussed above and higher gas prices. Taxes other than income increased
because of the higher value of the gas produced from our reserves, and
depreciation, depletion, and amortization increased because of increased gas
production.
Independent Power Operations
Revenues from unconsolidated investments decreased approximately
$14,200,000 compared with 1998 primarily because of CES' receipt of proceeds
of approximately $17,300,000 as a result of a contract settlement between one
of its independent power project partnerships and the project's power
purchaser during the third quarter of 1998. However, CES continues to benefit
in 1999 from higher revenues in generating projects in which it holds equity
interests, which revenues increased approximately $5,900,000 mainly as a
result of improved operations. This increase was somewhat offset by the loss
of approximately $4,800,000 in revenues as a result of the fourth quarter 1998
sale of a project in which CES held an equity interest. CES also received
approximately $2,000,000 in proceeds during 1999 relating to two events: (1)
the contract settlement discussed above, and (2) the reimbursement of
development costs associated with a domestic investment opportunity currently
under construction.
Amortization expense was approximately $5,900,000 lower than in 1998. In
the third quarter of 1998, CES amortized approximately $5,200,000 to properly
reflect the reduced value of the investment as a result of the contract
settlement discussed above.
Telecommunications Operations
In January 1999, a Touch America customer exercised an option and made a
$257,000,000 prepayment of all amounts due for the remaining twelve-year
initial term of a capacity agreement. The amount of the prepayment was
discounted for early payment and results in approximately $24,000,000 less in
annual operating revenues than we would have realized had the customer not
exercised its option. As a result, private-line revenues (revenues from sales
on Touch America's fiber-optic network) under that contract for the nine-
months ended September 30, 1999 were approximately $17,000,000 less than they
would have been without the prepayment.
Revenues from dark-fiber sales were approximately $3,400,000 higher
compared with the same period in 1998. These revenues increased primarily
because Touch America recognized approximately $8,000,000 in dark-fiber
revenues from existing agreements during the third quarter 1999.
Touch America expects dark-fiber sales in the fourth quarter from other
agreements under negotiation. With recent interpretations issued by the
Financial Accounting Standards Board, we are evaluating the accounting for
these future sales. See the discussion below in Part I, Item 2, "New
Accounting Pronouncements." We expect Touch America to eventually sell dark
fiber on the 4,300-mile fiber-optic network that it will begin constructing
later this year as a result of the contract discussed in Part I, Item 1,
"Notes to Consolidated Financial Statements, Note 5 - Commitments."
<PAGE>
After adjusting private-line revenues for the accounting effects of the
prepayment and after excluding the dark-fiber sales revenues, Touch America's
1999 year-to-date operating revenues increased approximately 20% when compared
with its 1998 year-to-date operating revenues. With the same adjustments,
Touch America's 1999 year-to-date operating income increased approximately 22%
versus its 1998 year-to-date operating income.
After adjusting private-line revenues for the accounting effects of the
prepayment and after excluding the dark-fiber sales revenues, revenues from
telecommunications operations increased approximately $12,500,000. The
increase in operating revenues, after the above adjustments, consists of
several elements. First, it reflects increased private-line revenues of
approximately $6,000,000 due to higher sales of fiber capacity. Second, long
distance revenues, including internet service and equipment service revenues
increased approximately $6,500,000 as a result of increased long distance
customer and minute sales and customer growth.
Private-line, equipment service, and long distance operations and
maintenance expenses increased approximately $5,900,000 chiefly as a result of
increased sales. Taxes other than income taxes decreased approximately
$1,500,000 principally because of lower property taxes. In June 1999, we
received state property tax assessed values for 1998 and 1999 and reviewed the
amounts accrued for Touch America for the year. Based on this review, we
reduced 1999 property tax expense by approximately $700,000.
Other Operations
Revenues and expenses of other operations increased primarily because of
MPT&M's increased electric-trading activities during the first six months of
1999 compared with the same period in 1998. Electric-trading activities
increased mainly because of contractual commitments entered into by MPT&M in
mid-1998, before we decided in late August 1998 to exit the electric trading
and marketing businesses. These increases were partially offset by decreased
electric-trading activity in the third quarter of 1999 and slightly lower year-
to-date market prices for electricity. (See Part I, Item 3, "Quantitative and
Qualitative Disclosures About Market Risk," for a brief discussion of our
electric-trading business.)
Nonutility Interest Expense and Other
Interest expense decreased primarily because we used funds from the
telecommunications prepayment discussed above to reduce nonutility debt and
meet nonutility cash needs.
Other income - net increased by approximately $7,300,000, of which
approximately $4,400,000 was attributable to interest income received on the
prepayment funds. The remaining increase is largely attributable to increased
intersegment interest income of approximately $4,100,000 on loans from
nonutility operations to utility operations. These increases were partially
offset by immaterial decreases in numerous miscellaneous items.
Income Taxes
Due to an estimated lower effective tax rate for 1999, we reduced income
tax expense in the third quarter.
<PAGE>
Quarter Ended September 30, 1999 and 1998:
Net Income Per Share of Common Stock (Basic)
Third quarter earnings were $0.26 per share, $0.07 less than third
quarter 1998 (adjusted for the two-for-one stock split effective August 6,
1999). Utility earnings were $0.01, compared with $0.10 last year. Nonutility
earnings were $0.25, up $0.02 from the $0.23 figure of a year earlier.
Utility
? Income from electric utility operations decreased compared with the
third quarter of 1998 because of the ongoing rate moratorium and
"large" industrial customers choosing other commodity suppliers as
part of customer choice. Despite lower prices in the secondary
markets, increased sales of surplus power in these markets - and the
associated transmission revenues - reduced the effects of overall
lower revenues. Higher expenses, especially selling, general, and
administrative expenses, and electric transmission and distribution
expenses associated with the higher surplus sales, adversely affected
income for the quarter.
? Income from our natural gas utility operations decreased during the
period mainly because of price and volume decreases.
Nonutility
? Income from our coal operations increased because of higher revenues,
mainly resulting from the effects of a one-time refund issued by
Western Energy in the third quarter of 1998 and higher reimbursable
mining expenses at the Jewett Mine.
? Oil and natural gas operating income increased, resulting from higher
oil and natural gas prices and increased natural gas volumes sold,
which more than offset a decrease in oil volumes sold.
? Our independent power operations again contributed to earnings, but
quarter-to-quarter income decreased because of the third quarter 1998
contract settlement.
? Although income from our telecommunications operations was
approximately $6,000,000 lower than it would have been otherwise
because of the effects of the discounted prepayment, this growing
sector of our business also continued to contribute solid earnings.
For comparative purposes, the following table shows consolidated basic
net income per share by principal business segment.
Quarter Ended
September 30,
1999 1998*
Utility Operations $ 0.01 $ 0.10
Nonutility Operations 0.25 0.23
Consolidated $ 0.26 $ 0.33
* Adjusted for the two-for-one stock split effective August 6, 1999.
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Quarter Ended
September 30,
1999 1998
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES:
Revenues $104,899 $108,585
Intersegment revenues 3,238 2,258
108,137 110,843
EXPENSES:
Power supply 29,123 28,242
Transmission and distribution 12,011 9,913
Selling, general, and administrative 16,885 10,953
Taxes other than income taxes 12,526 11,764
Depreciation and amortization 13,557 13,185
84,102 74,057
INCOME FROM ELECTRIC OPERATIONS 24,035 36,786
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 10,374 11,330
Gas supply cost revenues 2,806 2,447
Intersegment revenues 112 179
13,292 13,956
EXPENSES:
Gas supply costs 2,806 2,447
Other production, gathering, and exploration 516 398
Transmission and distribution 3,206 3,651
Selling, general, and administrative 5,090 4,786
Taxes other than income taxes 3,230 3,251
Depreciation, depletion, and amortization 2,320 2,207
17,168 16,740
(LOSS) INCOME FROM GAS OPERATIONS (3,876) (2,784)
INTEREST EXPENSE AND OTHER:
Interest 14,789 13,570
Distributions on company obligated manditorily
Redeemable preferred securities of subsidiary trust 1,373 1,373
Other (income) deductions - net (228) (1,138)
15,934 13,805
INCOME BEFORE INCOME TAXES AND DIVIDENDS 4,225 20,197
INCOME TAXES 2,620 8,344
DIVIDENDS ON PREFERRED STOCK 923 923
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 682 $ 10,930
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Electric Utility
Revenues and
Power Supply Expenses Volumes
(Thousands of Dollars) (Thousands of MWh)
9/30/99 9/30/98 9/30/99 9/30/98
REVENUES:
<S> <C> <C> <C> <C> <C> <C>
RESIDENTIAL:
Non-choice $ 28,429 $ 28,238 1% 437 444 (2%)
Choice - - - - - -
Total Residential 28,429 28,238 1% 437 444 (2%)
SMALL COMMERCIAL, SMALL INDUSTRIAL,
AND GOVERNMENT AND MUNICIPAL:
Non-choice 39,511 41,054 (4%) 682 727 (6%)
Choice 995 14 7007% 46 - -
Total Small Commercial, Small
Industrial, and Government and
Municipal 40,506 41,068 (1%) 728 727 0%
LARGE COMMERCIAL, LARGE INDUSTRIAL:
Non-choice 7,409 18,751 (60%) 209 509 (59%)
Choice 3,720 873 326% 471 115 310%
Total Large Commercial, Large
Industrial, and Government and
Municipal 11,129 19,624 (43%) 680 624 9%
IRRIGATION AND STREET LIGHTING:
Non-choice 5,565 5,478 2% 81 68 19%
Choice 615 - - - -
Total Irrigation and
Street Lighting 6,180 5,478 13% 81 68 19%
UNBILLED REVENUE ADJUSTMENT (1,380) (765) (80%) (18) (5) (260%)
GENERAL BUSINESS REVENUES 84,864 93,643 (9%) 1,908 1,858 3%
SALES TO OTHER UTILITIES 15,820 11,044 43% 751 360 109%
OTHER 4,215 3,898 8% - - -
INTERSEGMENT 3,238 2,258 43% 3 31 (90%)
TOTAL $ 108,137 $ 110,843 (2%) 2,662 2,249 18%
POWER SUPPLY EXPENSES:
HYDROELECTRIC $ 5,766 $ 4,520 28% 932 1,020 (9%)
STEAM 14,586 12,016 21% 1,308 1,258 4%
PURCHASED POWER AND OTHER 8,771 11,706 (25%) 593 162 266%
TOTAL $ 29,123 $ 28,242 3% 2,833 2,440 16%
DOLLARS PER MWh $ 10.28 $ 11.57
</TABLE>
General business revenues decreased in the third quarter primarily
because of a decrease in industrial revenues. While industrial customers
continue to choose other commodity suppliers - through the exercise of choice,
which began in July 1998 in accordance with the Electric Act - sales of
surplus power in the secondary markets increased, even though prices were down
compared with the third quarter 1998. These increased sales also contributed
to increased transmission revenues and - in addition to an increase in prices
to recover the cost of public-purpose programs in accordance with the Electric
Act - partially reduced the effects of decreased revenues from industrial
customers.
Third quarter expenses changed overall largely for the same reasons
mentioned above in the nine-months-ended section.
<PAGE>
<TABLE>
<CAPTION>
Natural Gas Utility
Revenues Volumes*
(Thousands of Dollars) (Thousands of Dkts)
9/30/99 9/30/98 9/30/99 9/30/98
REVENUES:
<S> <C> <C> <C> <C> <C> <C>
RESIDENTIAL $ 6,596 $ 5,977 10% 968 1,224 (21%)
SMALL COMMERCIAL, SMALL INDUSTRIAL,
AND GOVERNMENT AND MUNICIPAL 3,568 3,351 6% 551 525 5%
UNBILLED REVENUE ADJUSTMENT (460) 711 (165%) (68) 105 (165%)
GENERAL BUSINESS REVENUES 9,704 10,039 (3%) 1,451 1,854 (22%)
LESS: GAS SUPPLY COST REVENUES (GSC) 2,806 2,447 15% - - -
GENERAL BUSINESS REVENUES
WITHOUT GSC 6,898 7,592 (9%) 1,451 1,854 (22%)
SALES TO OTHER UTILITIES 78 71 10% 11 9 22%
TRANSPORTATION 3,534 3,574 (1%) 5,221 6,269 (17%)
OTHER (136) 93 (246%) - - -
TOTAL $ 10,374 $ 11,330 (8%) 6,683 8,132 (18%)
? See the nine-months-ended discussion in Item 2, "Management's Discussion and Analysis
of Financial Condition and Results of Operations, Natural Gas Utility," for a
discussion of why we now present volumes in Dekatherms.
</TABLE>
Natural gas revenues decreased overall in the third quarter even though
customer growth contributed to increased revenues. Decreased unbilled
revenues, mainly because of a change in billing cycles, more than offset these
increases. Transportation revenues increased for the same reasons mentioned
above in the nine-months-ended section. Other revenues decreased mainly
because of an actuarial pension plan adjustment.
Utility Interest Expense and Other
Interest expense increased primarily due to intersegment interest expense
of approximately $1,800,000 associated with increased loans from nonutility
operations to utility operations. Lower interest expense due to the retirement
of Medium-Term Notes late in 1998 reduced the effects of this increased
interest expense.
Income Taxes
The income tax rate for our utility in the third quarter was
comparatively high because of nondeferred differences between book income and
tax income. These differences, which are principally associated with plant
depreciation, do not vary with income before income taxes. Because utility
income before income taxes decreased approximately $16,000,000 in the third
quarter of 1999 compared with the third quarter of 1998, these nondeferred
differences between book income and tax income amounted to a higher percentage
of income before income taxes (62% in the third quarter of 1999 versus 41% in
the third quarter of 1998).
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Quarter Ended
September 30,
1999 1998
Thousands of Dollars
COAL:
<S> <C> <C>
REVENUES:
Revenues $ 52,589 $ 40,391
Intersegment revenues 9,783 8,645
62,372 49,036
EXPENSES:
Operations and maintenance 40,768 32,839
Selling, general, and administrative 4,653 3,664
Taxes other than income taxes 6,561 3,895
Depreciation, depletion, and amortization 1,906 1,995
53,888 42,393
INCOME FROM COAL OPERATIONS 8,484 6,643
OIL AND NATURAL GAS:
REVENUES:
Revenues 96,922 63,823
Intersegment revenues 4,551 3,763
101,473 67,586
EXPENSES:
Operations and maintenance 81,487 52,643
Selling, general, and administrative 4,852 4,377
Taxes other than income taxes 1,652 1,301
Depreciation, depletion, and amortization 5,734 5,080
93,725 63,401
INCOME FROM OIL AND NATURAL GAS OPERATIONS 7,748 4,185
INDEPENDENT POWER:
REVENUES:
Revenues 18,759 18,154
Earnings from unconsolidated investments 5,564 20,829
Intersegment revenues 476 444
24,799 39,427
EXPENSES:
Operations and maintenance 16,523 12,068
Selling, general, and administrative 1,221 873
Taxes other than income taxes 465 464
Depreciation and amortization 781 5,857
18,990 19,262
INCOME FROM INDEPENDENT POWER OPERATIONS $ 5,809 $ 20,165
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS (continued)
Quarter Ended
September 30,
1999 1998
Thousands of Dollars
TELECOMMUNICATIONS:
<S> <C> <C>
REVENUES:
Revenues $ 19,167 $ 21,716
Earnings from unconsolidated investments 8,167 1,229
Intersegment revenues 285 297
27,619 23,242
EXPENSES:
Operations and maintenance 8,014 7,025
Selling, general, and administrative 3,217 2,483
Taxes other than income taxes 907 1,315
Depreciation and amortization 2,292 2,035
14,430 12,858
INCOME FROM TELECOMMUNICATIONS OPERATIONS 13,189 10,384
OTHER OPERATIONS:
REVENUES:
Revenues 16,440 24,668
Intersegment revenues 452 206
16,892 24,874
EXPENSES:
Operations and maintenance 17,139 25,879
Selling, general, and administrative 509 335
Taxes other than income taxes 178 266
Depreciation and amortization 1,010 926
18,836 27,406
LOSS FROM OTHER OPERATIONS (1,944) (2,532)
INTEREST EXPENSE AND OTHER:
Interest 725 2,448
Other (income) deductions - net (2,674) (1,397)
(1,949) 1,051
INCOME BEFORE INCOME TAXES 35,235 37,794
INCOME TAXES 7,628 12,844
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 27,607 $ 24,950
</TABLE>
<PAGE>
NONUTILITY OPERATIONS
Coal Operations
Income from our coal operations for the quarter ended September 30, 1999
increased approximately $1,800,000 compared with the same period last year.
Revenues from the Rosebud Mine, including revenues from a synthetic fuel
project, increased approximately $7,700,000. A 5% decrease in tons sold to the
Colstrip Units was more than offset by the effects of the $7,900,000 third
quarter 1998 refund discussed in the nine-months-ended section. Revenues from
the Jewett Mine increased approximately $5,600,000 as increased reimbursable
mining expenses more than offset a 5% decrease in tons sold.
Coal operations and maintenance expenses increased for the same reasons
discussed above in the nine-months-ended section. In addition, reclamation
expenses were higher in the third quarter of 1999 compared with the same
period last year. Taxes other than income rose due to the increased revenues
received for coal sold in 1999 and a property tax refund received at the
Jewett Mine in the third quarter 1998.
Oil and Natural Gas Operations
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenue and the related percentage
changes in volumes sold and prices received:
Oil -revenue $ 1
-volume (10%)
-price/bbl 63%
Natural gas -revenue $ 28
-volume 27%
-price/Mcf 17%
Natural gas liquids -revenue $ 4
-volume -
-price/bbl 86%
Miscellaneous $ 1
Income from oil and natural gas operations increased approximately
$3,600,000 due to increased marketing activities and higher prices in the
third quarter of 1999. Natural gas and natural gas liquids revenues increased
for the same reasons discussed in the nine-months-ended section. Revenues
from oil operations were up slightly because increased prices more than offset
lower production.
Operations and maintenance expense; taxes other than income; and
depreciation, depletion, and amortization changed for the same reasons
discussed above in the nine-months-ended section.
Independent Power Operations
Revenues from unconsolidated investments decreased approximately
$15,300,000 compared with the third quarter of 1998 primarily because of CES'
receipt of proceeds of approximately $17,300,000 in the third quarter of 1998
from the contract settlement discussed in the nine-months-ended section.
However, CES continues to benefit in 1999 from higher revenues in generating
projects in which it holds equity interests, which revenues increased
<PAGE>
approximately $2,200,000 mainly as a result of improved operations. This
increase was offset by the loss of approximately $1,100,000 in revenues as a
result of the fourth quarter 1998 sale of a project in which CES held an
equity interest. CES also received approximately $900,000 in proceeds during
the third quarter 1999 relating to: (1) the contract settlement discussed
above, and (2) the reimbursement of development costs associated with a new
project currently under construction.
Operations and maintenance expenses was approximately $4,500,000 higher
compared with 1998 because, in the third quarter of 1998, CES capitalized
previously expensed project development costs associated with the development
of a domestic investment opportunity. This effectively reduced third quarter
1998 operations and maintenance expenses. Amortization expense was
approximately $5,100,000 lower compared with 1998 because of the recognition
of amortization expense of approximately $5,200,000 in the third quarter of
1998 associated with the contract settlement discussed above.
Telecommunications Operations
Private-line revenues for the quarter ended September 30, 1999, were
approximately $6,000,000 less than they would have been without the prepayment
discussed in the nine-months-ended discussion.
Revenues from dark-fiber sales were approximately $7,000,000 higher
compared with the same period in 1998. These revenues increased because Touch
America recognized approximately $8,000,000 in dark-fiber revenues from
existing agreements during the third quarter 1999.
After adjusting private-line revenues for the accounting effects of the
prepayment and after excluding the dark-fiber sales revenues, revenues from
telecommunications operations increased approximately $3,200,000. The
increase in operating revenues, after the above adjustments, principally
consists of several elements. First, it reflects increased private-line
revenues of approximately $2,000,000 due to higher sales of fiber capacity.
Second, long distance revenues increased approximately $900,000 as a result of
(1) long distance customer and minute sales, and (2) internet service revenues
resulting from customer growth.
Operations and maintenance expenses increased approximately $1,000,000.
The increased expense is attributable primarily to increased private-line and
long distance sales.
Other Operations
Revenues and expense of other operations decreased primarily because of
MPT&M's decreased electric-trading activities during the third quarter of 1999
compared with the same period in 1998. This decreased activity reflects our
preparations to exit the electric trading and marketing businesses as the sale
of electric generating assets approaches closing. In addition, market prices
for electricity were significantly lower through the third quarter of 1999
compared with the same period for the prior year.
Nonutility Interest Expense and Other
Interest expense decreased for the same reasons discussed above in the
nine-months-ended section.
Other income - net increased by approximately $1,300,000, which was
chiefly attributable to increased intersegment interest income of $1,800,000
on loans from nonutility operations to utility operations. These increases
were offset by immaterial decreases in numerous miscellaneous items.
<PAGE>
Income Taxes
Due to an estimated lower effective tax rate for 1999, we reduced income
tax expense in the third quarter.
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
Net cash provided by operating activities was $287,671,000 for the nine
months ended September 30, 1999 compared with $190,977,000 in the first nine
months of 1998. The current-year increase of $96,694,000 was attributable
mainly to the $257,000,000 prepayment received in January 1999 from a Touch
America customer. We are recognizing the $257,000,000 prepayment in revenues
over the remaining term of the twelve-year agreement. Cash from the
prepayment was used to reduce long-term debt and short-term borrowings and pay
taxes on the prepayment and expected gains resulting from the sale of our
electric generating assets.
Investing Activities
Net cash used for investing activities was $133,265,000 for the nine
months ended September 30, 1999 compared with $96,819,000 in the first nine
months of 1998. The current-year increase of $36,446,000 was attributable
mainly to an increase in capital expenditures by our telecommunications
operations, partially offset by a decrease in capital expenditures by our
utility and oil and gas operations. Increased proceeds received from property
sales and investments were offset by a decrease in additional investments.
For information regarding Touch America's investments in domestic access
lines, one-number digital wireless services, dedicated telecommunication
channels, and planned expenditures in constructing fiber-optic networks, refer
to Part 1, "Notes to Consolidated Financial Statements, Note 5 - Commitments."
We expect that a combination of funds from operations, asset sales, and the
issuance of securities will be the source of funds for these investments and
expenditures.
Financing Activities
On February 1, 1999, we used the proceeds from asset-backed securities
issued by the Montana Power Natural Gas Funding Trust to retire $55,000,000 of
our 7.7% First Mortgage Bonds.
On September 3, 1999, we retired $10,000,000 of our 7.875% Series B
Unsecured MTNs due December 23, 2026. We retired an additional $5,000,000 of
these MTNs on October 13, 1999. These amounts were part of the long-term debt
targeted for repurchase in the Tier II rate filing. This filing is discussed
in Part I, Item 1, "Notes to Consolidated Financial Statements, Note 1 -
Deregulation, Regulatory Matters, and Asset Divestiture."
Our consolidated borrowing ability under our Revolving Credit and Term
Loan Agreements was $179,048,000, of which $164,245,000 was unused at
September 30, 1999. We also have short-term borrowing facilities with
commercial banks that provide committed and uncommitted lines of credit and
the ability to sell commercial paper.
For information regarding our authorization to repurchase common stock,
refer to Part I, Item 1, "Notes to Consolidated Financial Statements, Note 9 -
Common Stock."
<PAGE>
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended September 30, 1999, our ratio of earnings to
fixed charges was 3.20 times. Fixed charges include interest, distributions on
preferred securities of a subsidiary trust, the implicit interest of the
Colstrip Unit No. 4 rentals, and one-third of all other rental payments.
YEAR 2000 COMPLIANCE
The Y2K issue relates to the ability of systems - including computer
hardware, software, and embedded microprocessors - to properly interpret date
information relating to the year 2000. Many systems, including some of our
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" rather than
"19". If not corrected, these systems could fail or create erroneous results.
Strategy
Our strategy to address Y2K included completion of a three-step process
and the development of contingency plans. The first step involved
inventorying critical information technology (IT) systems and non-information
(non-IT) systems, including third-party computer hardware and software and
embedded electronic microprocessors. During the second step, we analyzed the
systems to determine their Y2K readiness. The third step consisted of
replacing or repairing and testing the systems to ensure their availability
and integrity. We have completed all three steps. As a result, we believe
that all of our critical systems are Y2K ready. In the event of an
unanticipated failure of systems - in spite of our readiness efforts - we have
developed contingency plans to help ensure business continuity.
The Year 2000 issue also may affect other entities with which we
transact business or with which our electric and natural gas systems are
interconnected. Our business units have contacted suppliers, vendors, and key
customers to assess Year 2000 readiness. Currently, we have not been advised
that Y2K effects to vendors, customers, or suppliers' systems will
significantly affect our operations. In addition, because of the
interconnected nature of electric systems, the North American Electric
Reliability Council (NERC) is facilitating the preparedness 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. In addition, NERC held national
drills on April 9, 1999 and September 9, 1999 to assess industry preparation.
We participated in both drills and deemed our performance successful.
Y2K Expenditures
We did not establish a formal process to track Y2K expenditures. Many
of the measures that will mitigate Y2K effects coincide with normal operations
and maintenance and, therefore, are not accounted for separately as Y2K
expenditures. For example, a capital upgrade to the energy management system
(EMS) that cost $460,000 was necessary to provide additional functionality and
also resulted in a Y2K benefit. Likewise, we implemented a new method of
customer billing at a cost of $3,100,000 and, although it will address the Y2K
issue, the new method was planned for reasons other than Y2K. Our Information
Services Department did track its Y2K expenditures. It estimates that it has
spent approximately $2,400,000 to address the Y2K issue and anticipates
spending only another $100,000 before year-end. Although we are unable to
estimate the overall cost of required modifications, the ultimate cost of Y2K
modifications will not have a material adverse effect on our consolidated
financial position, results of operations, or cash flows.
<PAGE>
Most Reasonably Likely "Worst-Case" Scenario
The process of inventorying, analyzing, modifying, and testing our
critical IT and critical non-IT systems is complete. Also, as previously
discussed, we have contingency plans in place should an unforeseen Y2K problem
arise. Nonetheless, the most reasonably likely "worst-case" Y2K scenario is
that customers could experience interruptions in service.
The above information is a Year 2000 Readiness Disclosure pursuant to
the Federal Year 2000 Information and Readiness Disclosure Act.
NEW ACCOUNTING PRONOUNCEMENTS
New requirements associated with the accounting for derivative
instruments and hedging and trading activities eventually will affect us and
MPT&M. In addition, a recent interpretation of how to account for future dark-
fiber sales may affect Touch America.
SFAS No. 133; SFAS No. 137; and EITF 98-10
In June 1998, the Financial Accounting Standards Board (FASB) 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. The statement also expands the
definition of a derivative.
Changes in the fair value of derivatives will be 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. The statement distinguishes between (1) fair-value hedges,
defined as hedges of assets, liabilities, or firm commitments, and (2) 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 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
affected by the variability of the cash flows of the hedged item. The
ineffective portions of all hedges will be recognized in current earnings.
In July 1999, the FASB issued SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities: Deferral of the Effective Date of FASB
Statement No. 133." SFAS No. 137 delays for one year the effective date of
SFAS No. 133. This delay means that we are not required to adopt SFAS No. 133
until January 1, 2001. However, we can adopt it earlier if we choose to do
so. We have not yet determined the effect that adopting SFAS No. 133 will
have on our consolidated financial position, results of operations, or cash
flows.
EITF 98-10 requires that energy contracts entered into under "trading
activities" be marked to market with the gains or losses shown net in the
income statement. EITF 98-10 is effective for fiscal years beginning after
December 15, 1998. We adopted EITF 98-10 as of January 1, 1999 and
accordingly mark to market energy contracts that qualify as "trading
activities." As a result, we recognized an immaterial loss in the results of
operations for the first quarter, an immaterial gain in the results of
operations for the second quarter, and an immaterial gain in the results of
<PAGE>
operations for the third quarter. The cumulative effect of the adoption of
EITF 98-10 on our prior year's financial position, results of operations, and
cash flows also was immaterial.
FASB Interpretation No. 43
On July 8, 1999, the FASB issued Interpretation No. 43, "Real Estate
Sales," which is an interpretation of SFAS No. 66, "Accounting for Sales of
Real Estate." This interpretation, which requires entities to recognize
revenues from dark-fiber sales over the period of the lease rather than at the
time of sale if title to the rights of use do not transfer to the lessee at
the end of the lease, applies to transactions entered into after June 30,
1999. We are reviewing this interpretation to determine if it affects how we
must account for our future dark-fiber sales.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our energy commodity-producing, trading, and marketing activities and
other investments and agreements expose us to the market risks associated with
fluctuations in commodity prices, interest rates, and changes in foreign
currency translation rates.
Trading Instruments
Because we do not use derivative financial instruments to hedge against
exposure to fluctuations in interest rates or foreign currency exchange rates,
commodity price risk represents the primary market risk to which our non-
regulated energy-commodity producing, trading, and marketing operations are
exposed. We discuss the derivative financial instruments that we use to
manage this risk in Part I, Item 1, "Notes to Consolidated Financial
Statements, Note 3 - Derivative Financial Instruments."
Electricity
We have remained in the electric-trading business since our August 1998
announcement to exit this business mainly to (1) efficiently sell surplus
power from our generating plants, (2) efficiently buy power needed to serve
our native utility load, and (3) fulfill our contractual commitments. Upon
the sale of our electric generating assets, we will exit the electric-trading
business, although we are making arrangements to contract with a third party
for real-time scheduling services needed to fulfill contractual commitments
related to Colstrip Unit No. 4 and the electric purchase and sale contracts
discussed in Part I, Item 1, "Notes to Consolidated Financial Statements,
Note 5 - Commitments."
In June 1998, MPT&M entered into a derivative financial transaction in
conjunction with one of our electric retail sales contracts. The negative
mark-to-market value of this derivative financial instrument is recaptured
when netted against the positive mark-to-market value of a related offsetting
physical purchase transaction with another counterparty. The offsetting
effect of these related transactions essentially neutralizes hypothetical
adverse changes in market prices.
Natural Gas, Crude Oil, and Natural Gas Liquids
In December 1998, our Audit Committee adopted commodity risk-management
policies and practices to govern the execution, recording, and reporting of
derivative financial instruments and physical transactions associated with the
trading and marketing activity of natural gas, crude oil, and natural gas
liquids engaged in by MPT&M. These policies and practices require MPT&M to
<PAGE>
identify, quantify, and report commodity risks and to hold regular Risk
Management Committee meetings. To the extent feasible, MPT&M began following
these policies and practices earlier in 1998. Our Risk Management Committee
(1) approves the risk-related trading activities in which MPT&M participates
and the kinds of instruments that MPT&M may use, and (2) recommends to our
Audit Committee specific limits for MPT&M's trading activity.
MPT&M's value-at-risk (VaR) is based on J.P. Morgan's RiskMetricsT
approach, variance/co-variance. This approach uses historical estimates of
volatility and correlation and values optionality using delta equivalents.
Because actual future changes in markets (prices, volatilities and
correlations) may be inconsistent with historical observations, MPT&M's VaR
may not accurately reflect the potential for future adverse changes in fair
values.
On June 21, 1999, our Audit Committee increased MPT&M's VaR limit. The
former VaR limit of $1,000,000 was based only on natural gas physical and
financial transactions. The revised VaR limit of $2,000,000 includes these
transactions as well as such transactions relating to crude oil and natural
gas liquids, and it also includes forecasts of affiliate-owned production. We
now use VaR, therefore, to measure some of the price risk associated with our
crude oil and natural gas exploration and production activities.
MPT&M's VaR is based on a forward 24-month time period and assumes a
one-day holding period and a 95% confidence level. As of September 30, 1999,
MPT&M's VaR calculation for physical and financial natural gas, crude oil and
natural gas liquids transactions, including forecasts of affiliate-owned
production, was slightly less than $2,000,000.
From June 21, 1999 through the end of the second quarter, MPT&M reported
no daily adverse changes in fair values in excess of its $2,000,000 VaR limit.
During the third quarter, MPT&M reported daily adverse changes in fair values
in excess of its VaR limit on two occasions. During the period from
October 1, 1999 through November 9, 1999, MPT&M reported daily adverse changes
in fair values in excess of its VaR limit on two occasions.
Counterparty Credit Risk
Commodity price changes may provide an incentive to our counterparties
to default on their delivery or payment obligations to us under our physical
and financial natural gas, crude oil and natural gas liquids trading
instruments. Our corporate credit risk policy seeks to address counterparty
credit risk and requires us to investigate and monitor the creditworthiness of
our physical and financial trading counterparties. We do not expect
nonperformance by these trading counterparties to have a material adverse
effect on our consolidated financial position, results of operations, or cash
flows.
Other-Than-Trading Agreements
We are exposed to commodity price risks through our utility and
nonutility operations. Our utility has entered into purchase, sale, and
transportation contracts for electricity and natural gas. Our nonutility has
entered into similar kinds of contracts for coal, lignite, natural gas, crude
oil, and natural gas liquids. Since December 31, 1998, there has been no
material change in these other instruments or the corresponding commodity
price risk associated with these instruments.
Our primary interest rate exposure with respect to other-than-trading
instruments relates to items that SFAS No. 107, "Disclosures about Fair Value
of Financial Instruments," defines as "financial instruments," which are
instruments readily convertible to cash. Since December 31, 1998, there has
<PAGE>
been no material change in these instruments or the corresponding interest
rate risk associated with these instruments.
Our primary foreign currency exposure results from (1) our Canadian
subsidiaries - Altana Exploration Company, Altana Exploration Ltd. and
Canadian Montana Gas Company - exploring for, producing, gathering,
processing, transporting, and marketing natural gas and crude oil in Canada,
and (2) MPT&M trading and marketing natural gas in Canada. Since December 31,
1998, there has been no material change in these activities or the
corresponding foreign currency risk associated with these activities.
<PAGE>
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
For information regarding the (1) Kerr Project fish, wildlife and
habitat mitigation plan, (2) Project 2188 relicensing, and (3) the Reliant
Energy Lignite Supply Agreement dispute, refer to Part I, Item 1, "Notes to
Consolidated Financial Statements, Note 2 - Contingencies."
ITEM 2. Changes in Securities and Use of Proceeds
On June 22, 1999, our Board of Directors approved a two-for-one stock
split of our outstanding common stock. As a result of the split, which was
effective August 6, 1999 for all shareholders of record on July 16, 1999,
55,099,015 outstanding shares of common stock were converted to 110,198,030
shares of common stock.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
September 30, 1999.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K Filed During the Quarter Ended September 30,
1999.
DATE SUBJECT
July 27, 1999 Item 5 Other Events. Discussion of Second
Quarter Net Income.
Item 7 Exhibits. Preliminary Consolidated
Statements of Income for the Quarters
Ended June 30, 1999 and 1998, for the Six
Months Ended June 30, 1999 and 1998, and
for the Twelve Months Ended June 30, 1999
and 1998. Preliminary Utility Operations
Statements of Income for the Quarters
Ended June 30, 1999 and 1998, for the Six
Months Ended June 30, 1999 and 1998, and
for the Twelve Months Ended June 30, 1999
and 1998. Preliminary Nonutility
Operations Statements of Income for the
Quarters Ended June 30, 1999 and 1998, for
the Six Months Ended June 30, 1999 and
1998, and for the Twelve Months Ended
June 30, 1999 and 1998.
<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, a duly authorized signatory.
THE MONTANA POWER COMPANY
(Registrant)
By /s/ J. P. Pederson
J. P. Pederson
Vice President and
Chief Financial Officer
Dated: November 15, 1999
<PAGE>
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended September 30, 1999
Exhibit 27
Financial data schedule
<PAGE>
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
September 30,1999
Net Income $146,118
Income Taxes 72,064
$218,182
Fixed Charges:
Interest $ 62,214
Amortization of Debt Discount,
Expense, and Premium 1,320
Rentals 35,658
$ 99,192
Earnings Before Income Taxes
and Fixed Charges $317,374
Ratio of Earning to Fixed Charges 3.20 x
- -6-
- -32-
- -55-
- -56-
- -59-
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 09/30/99, the Consolidated Income
Statement and the Consolidated Statement of Cash Flows for the twelve
months ended 09/30/99 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-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,511,795
<OTHER-PROPERTY-AND-INVEST> 787,963
<TOTAL-CURRENT-ASSETS> 379,911
<TOTAL-DEFERRED-CHARGES> 369,539
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,049,208
<COMMON> 703,647
<CAPITAL-SURPLUS-PAID-IN> 2,134
<RETAINED-EARNINGS> 407,796
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,113,577
65,000
57,654
<LONG-TERM-DEBT-NET> 650,213
<SHORT-TERM-NOTES> 37,600
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 79,981
0
<CAPITAL-LEASE-OBLIGATIONS> 220
<LEASES-CURRENT> 416
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,044,547
<TOT-CAPITALIZATION-AND-LIAB> 3,049,208
<GROSS-OPERATING-REVENUE> 966,956
<INCOME-TAX-EXPENSE> 40,702
<OTHER-OPERATING-EXPENSES> 801,232
<TOTAL-OPERATING-EXPENSES> 841,934
<OPERATING-INCOME-LOSS> 125,022
<OTHER-INCOME-NET> 6,371
<INCOME-BEFORE-INTEREST-EXPEN> 131,393
<TOTAL-INTEREST-EXPENSE> 43,108
<NET-INCOME> 88,285
2,768
<EARNINGS-AVAILABLE-FOR-COMM> 85,517
<COMMON-STOCK-DIVIDENDS> 22,040
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 287,671
<EPS-BASIC> .78
<EPS-DILUTED> .77
</TABLE>
