UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
________________________________________
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 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 August 11, 1999, the Company had 110,199,430 shares of common stock
outstanding.
PART I
FINANCIAL INFORMATION
ITEM 1 - FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Six Months Ended
June 30, June 30,
1999 1998
Thousands of Dollars
REVENUES $ 631,268 $ 553,160
EXPENSES:
Operations 308,409 231,280
Maintenance 39,947 39,986
Selling, general, and administrative 64,173 62,937
Taxes other than income taxes 51,106 50,326
Depreciation, depletion, and amortization 55,355 54,787
518,990 439,316
INCOME FROM OPERATIONS 112,278 113,844
INTEREST EXPENSE AND OTHER:
Interest 26,500 28,901
Distributions on mandatorily redeemable preferred
securities of subsidiary trust 2,746 2,746
Other (income) deductions - net (6,495) (1,847)
22,751 29,800
INCOME TAXES 30,454 25,625
NET INCOME 59,073 58,419
DIVIDENDS ON PREFERRED STOCK 1,845 1,845
NET INCOME AVAILABLE FOR
COMMON STOCK $ 57,228 $ 56,574
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - BASIC (000)* 110,166 109,858
BASIC EARNINGS PER SHARE OF COMMON STOCK* $ 0.52 $ 0.51
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - DILUTED (000)* 110,940 110,010
DILUTED EARNINGS PER SHARE OF COMMON STOCK* $ 0.51 $ 0.51
The accompanying notes are an integral part of these statements.
* Adjusted for the 2-for-1 stock split effective August 6, 1999.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Quarter Ended
June 30, June 30,
1999 1998
Thousands of Dollars
REVENUES $ 309,501 $ 262,357
EXPENSES:
Operations 154,848 106,099
Maintenance 20,317 20,204
Selling, general, and administrative 31,030 33,571
Taxes other than income taxes 25,338 24,802
Depreciation, depletion, and amortization 27,603 27,701
259,136 212,377
INCOME FROM OPERATIONS 50,365 49,980
INTEREST EXPENSE AND OTHER:
Interest 12,871 14,398
Distributions on company obligated mandatorily
redeemable preferred securities of subsidiary trust 1,373 1,373
Other (income) deductions - net (2,626) (118)
11,618 15,653
INCOME TAXES 13,498 11,777
NET INCOME 25,249 22,550
DIVIDENDS ON PREFERRED STOCK 922 922
NET INCOME AVAILABLE FOR COMMON STOCK $ 24,327 $ 21,628
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - BASIC (000)* 110,184 109,966
BASIC EARNINGS PER SHARE OF COMMON STOCK* $ 0.22 $ 0.20
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - DILUTED (000)* 111,098 110,130
DILUTED EARNINGS PER SHARE OF COMMON STOCK* $ 0.22 $ 0.20
The accompanying notes are an integral part of these statements.
* Adjusted for the 2-for-1 stock split effective August 6, 1999.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
ASSETS
June 30, December 31,
1999 1998
Thousands of Dollars
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $40,560 and $37,966
plant under construction)
Electric $ 1,859,035 $ 1,841,855
Natural gas 409,138 404,992
2,268,173 2,246,847
Less - accumulated depreciation and depletion 761,905 732,385
1,506,268 1,514,462
NONUTILITY PROPERTY (includes $46,622 and $10,990
property under construction) 921,127 864,981
Less - accumulated depreciation and depletion 324,170 297,933
596,957 567,048
2,103,225 2,081,510
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 24,374 24,268
Reclamation fund 42,442 41,542
Other 86,343 84,256
153,159 150,066
CURRENT ASSETS:
Cash and temporary cash investments - 10,116
Accounts receivable 130,278 170,652
Notes receivable 17,514 29,089
Prepaid income taxes 112,426 -
Materials and supplies (principally at average cost) 43,334 42,292
Prepayments and other assets 63,759 57,331
Deferred income taxes 22,108 18,755
389,419 328,235
DEFERRED CHARGES:
Advanced coal royalties 13,769 14,312
Regulatory assets related to income taxes 121,734 121,735
Regulatory assets - other 154,531 154,193
Other deferred charges 80,782 78,044
370,816 368,284
$ 3,016,619 $ 2,928,095
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, December 31,
1999 1998
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock* (240,000,000 shares authorized;
110,198,030* and 110,121,040* shares issued) $ 703,611 $ 702,511
Retained earnings and other shareholders' equity 443,427 430,309
Accumulated other comprehensive income (18,455) (20,717)
Unallocated stock held by trustee for retirement
savings plan (21,882) (23,298)
1,106,701 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 671,488 698,329
1,900,843 1,909,788
CURRENT LIABILITIES:
Short-term borrowing 16,100 69,820
Long-term debt - portion due within one year 71,801 96,292
Dividends payable 22,755 22,765
Income taxes - 24,857
Other taxes 51,021 51,777
Accounts payable 84,704 97,197
Interest accrued 12,955 13,156
Other current liabilities 39,023 40,087
298,359 415,951
DEFERRED CREDITS:
Deferred income taxes 295,090 323,906
Investment tax credit 32,807 35,175
Accrued mining reclamation costs 132,214 129,558
Other deferred credits 357,306 113,717
817,417 602,356
CONTINGENCIES AND COMMITMENTS (Notes 2 and 5)
$ 3,016,619 $ 2,928,095
The accompanying notes are an integral part of these statements.
? Adjusted for the 2-for-1 stock split effective August 6, 1999.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
For Six Months Ended
June 30, June 30,
1999 1998
Thousands of Dollars
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 59,073 $ 58,419
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, and amortization 55,355 54,787
Deferred income taxes (28,816) 464
Noncash earnings from unconsolidated investments. (7,704) (10,886)
Other noncash charges to net income - net 3,765 13,785
Changes in other assets and liabilities:
Accounts and notes receivable 51,949 (20,785)
Income taxes (140,636) (4,800)
Accounts payable (12,493) (25,021)
Prepayments and other assets (6,428) 6,130
Deferred revenue and other 243,589 2,085
Other - net (8,018) 16,318
Net cash provided by operating activities 209,636 90,496
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (76,141) (72,244)
Proceeds from property and investments 10,238 16,920
Additional investments (3,310) (2,098)
Net cash used by investing activities (69,213) (57,422)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (45,909) (45,739)
Sales of common stock 590 6,141
Issuance of long-term debt 24,902 73,616
Retirement of long-term debt (76,402) (19,275)
Net change in short-term borrowing (53,720) (49,019)
Net cash used by financing activities (150,539) (34,276)
CHANGE IN CASH FLOWS (10,116) (1,202)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 10,116 16,706
CASH AND CASH EQUIVALENTS, END OF PERIOD $ - $ 15,504
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Six Months For:
Income taxes $ 196,068 $ 23,419
Interest 30,835 29,477
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements of The Montana Power
Company for the interim periods ended June 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 AND OTHER REGULATORY MATTERS
The electric and natural gas utility businesses are in transition to a
competitive market under 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
for all customers to have choice of electricity and natural gas suppliers no
later than July 1, 2002.
Through June 1999, approximately 70 electric customers representing more
than 300 accounts - or 25% of our prechoice electric load - have chosen
alternate suppliers since the inception of customer choice on July 1, 1998.
Also through June 1999, approximately 240 natural gas customers - or 54% of
our prechoice natural gas supply load - have chosen alternate suppliers since
the transition to a competitive 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
has scheduled hearings on these issues beginning in March 2000. We expect a
PSC decision on the Tier II issues approximately one month after the
conclusion of the hearings.
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. We
reached a settlement in this rate filing in March 1999 with FERC and the
intervenors. As a result of the settlement, rates charged for bundled
wholesale electric service will not change, but transmission rates have been
increased on an interim basis and await final approval from FERC. Although we
expect the increased transmission rates to have a positive effect on the
results of our transmission operations, one of the rural electric cooperative
customers retained the right to continue with its rate-reduction complaint
filed with FERC. We are currently negotiating with this customer to try to
resolve the issue.
On August 12, 1999, we filed a natural gas rate case with the PSC that
reflects a request for increased annual revenues of $15,400,000, with an
interim increase of $11,500,000. This interim increase will become effective
after the two-year rate moratorium ends in October 1999. The filing also
proposes an alternative rate plan, "trackers" to reflect property taxes and
replacement facilities in rates on a more timely basis, a change in the
allocation of costs to customer classes, and rate-design changes that include
recovery of distribution charges through a fixed monthly system charge. We
expect a PSC decision on this filing before the end of the second quarter
2000.
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.
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, 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, Inc. (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 Energy), 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 Energy 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 Energy 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 pretax income of
approximately $7,000,000. 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
In August 1998, we announced our intention to exit the electric trading
and marketing businesses. As a result, our subsidiary, The Montana Power
Trading & Marketing Company (MPT&M), no longer enters into derivative
financial instruments relating to the trading or marketing of electricity.
MPT&M remains a party, however, to one three-year derivative financial
instrument, entered into in June 1998 with an electric retail customer to
manage a portion of the customer's commodity price risk. We do not expect
this derivative financial 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, 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. 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 the agreement at the time of
execution. Making or receiving 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 as a result of buying options and all premiums
received as a result of selling options and recognize the applicable
expenses or revenues monthly throughout the option term. At June 30,
1999, we had no material deferred expenses or revenues 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
as 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 June 30, 1999, we had unrecognized gains of approximately
$5,000,000 related to these transactions. If we terminate a 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 June 30, 1999, we had swap and option agreements to hedge
approximately (1) 11.5 bcf of Nonutility natural gas, or 32% of our expected
delivery obligations under long-term natural gas sales contracts through
December 2000, and (2) approximately 3.8 bcf, or 7% of our Nonutility natural
gas pipeline transportation obligations under contracts through March 2001.
Speculative Transactions
Speculative transactions are those in which we have no position in an
underlying commodity or derivative of that commodity exposing us to price
risk. We enter into these transactions primarily to try to enhance
profitability based on expected market movements. 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. We recognize any corresponding gain or
loss in the Consolidated Statement of Income. Through June 30, 1999, we had
recognized gains of approximately $800,000 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. (Continental
Energy), 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 June 30, 1999, we would not experience 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.
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, which became effective in 1998,
provides that a portion of the deliveries are at a fixed price and a portion
of the deliveries are at an index-based price. (In approximately three years,
all prices under the contract become index based.) All prices in this
contract include delivery of power to the customer's site. When the sale of
our generating assets closes, 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. Because of uncertainties surrounding other
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
Our subsidiary, Touch America, joined with Iowa Network Services, Inc.
to create Iowa Telecommunications Services (ITS) on July 1, 1999. ITS will
purchase from GTE Midwest Incorporated (GTE) all of GTE's 280,422 domestic
access lines in Iowa, involving 296 telephone exchanges. Touch America will
hold a non-controlling interest in ITS and will invest approximately
$46,000,000 of equity in ITS. ITS will fund the purchase from GTE primarily
through long-term nonrecourse debt at the ITS level. We expect this
transaction to close in late 1999 or early 2000.
On July 1, 1999, Touch America and US West Wireless entered into a joint
venture to provide "one number" digital wireless service in a seven-state
region of the Pacific Northwest and Upper Midwest. We expect the joint
venture, in which Touch America holds a non-controlling interest, to make an
initial investment over the next three years, during which construction will
be ongoing, of approximately $88,000,000 in the aggregate.
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 $28,500,000
in separate notes of various amounts at fixed rates of interest averaging
approximately 6% per year. At June 30, 1999, the balance of these notes was
$16,000,000. FTV fully repaid 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 7.7%
First Mortgage Bonds.
NOTE 7 - COMPREHENSIVE INCOME
SFAS No. 130, "Reporting Comprehensive Income," defines comprehensive
income during the applicable period 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.
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 six months ended June 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
$2,262,000 in 1999 and decreases to retained earnings of $5,644,000 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 U.S. dollars using current foreign currency exchange rates. This
conversion accounted for approximately $5,100,000 of the 1998 decrease in
retained earnings.
NOTE 8 - INFORMATION ON INDUSTRY SEGMENTS
Operations Information
Six Months Ended
June 30, 1999
Thousands of Dollars
UTILITY
Electric Natural Gas
Sales to unaffiliated customers $ 221,977 $ 62,735
Intersegment sales 6,468 336
Earnings from unconsolidated investments - -
Pretax operating income 56,447 11,078
Capital expenditures 22,160 2,518
Identifiable assets 1,683,778 390,590
NONUTILITY
Oil and Independent
Coal Natural Gas Power*
Sales to unaffiliated customers $ 92,217 $ 145,554 $ 36,968
Intersegment sales 19,740 8,312 663
Earnings from unconsolidated investments - - 9,464
Pretax operating income 16,635 5,743 1,429
Capital expenditures 1,932 16,884 207
Identifiable assets 234,691 310,000 99,483
NONUTILITY (continued)
Tele-
Communications Other
Sales to unaffiliated customers $ 41,129 $ 19,124
Intersegment sales 354 1,002
Earnings from unconsolidated investments 2,100 -
Pretax operating income (loss) 12,036 (2,654)
Capital expenditures 31,307 12
Identifiable assets 210,984 67,638
CORPORATE
Capital expenditures $ 1,121
Identifiable assets 19,455
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments** Total
Sales to unaffiliated customers $ 619,704 - $ 619,704
Intersegment sales 36,875 $ (36,875) -
Earnings from unconsolidated investments 11,564 - 11,564
Pretax operating income 100,714 - 100,714
Capital expenditures 76,141 - 76,141
Identifiable assets 3,016,619 - 3,016,619
* The Independent Power segment is dependent on two customers, the losses of which
would have a material adverse effect on this segment.
** The amounts include certain eliminations between the business segments.
Operations Information
Six Months Ended
June 30, 1998
Thousands of Dollars
UTILITY
Electric Natural Gas
Sales to unaffiliated customers $ 219,235 $ 60,350
Intersegment sales 2,454 352
Earnings from unconsolidated investments - -
Pretax operating income 57,422 10,587
Capital expenditures 24,686 6,694
Identifiable assets 1,572,714 391,479
NONUTILITY
Oil and Independent
Coal Natural Gas Power*
Sales to unaffiliated customers $ 88,478 $ 88,203 $ 36,379
Intersegment sales 19,856 9,633 1,181
Earnings from unconsolidated investments - - 8,351
Pretax operating income (loss) 16,343 4,861 (3,707)
Capital expenditures 1,398 27,327 230
Identifiable assets 249,390 285,441 122,678
NONUTILITY (continued)
Tele-
Communications Other
Sales to unaffiliated customers $ 42,208 $ 4,312
Intersegment sales 503 564
Earnings from unconsolidated investments 5,644 -
Pretax operating income (loss) 18,385 (4,042)
Capital expenditures 11,059 670
Identifiable assets 131,286 38,424
CORPORATE
Capital expenditures $ 180
Identifiable assets 35,621
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments** Total
Sales to unaffiliated customers $ 539,165 - $ 539,165
Intersegment sales 34,543 $ (34,543) -
Earnings from unconsolidated investments 13,995 - 13,995
Pretax operating income 99,849 - 99,849
Capital expenditures 72,244 - 72,244
Identifiable assets 2,827,033 - 2,827,033
* The Independent Power segment is dependent on two customers, the losses of which
would have a material adverse effect on this segment.
** The amounts include certain eliminations between the business segments.
Operations Information
Quarter Ended
June 30, 1999
Thousands of Dollars
UTILITY
Electric Natural Gas
Sales to unaffiliated customers $ 105,443 $ 22,390
Intersegment sales 2,778 137
Earnings from unconsolidated investments - -
Pretax operating income 26,773 938
Capital expenditures 14,136 4,933
Identifiable assets 1,683,778 390,590
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
Sales to unaffiliated customers $ 48,779 $ 76,745 $ 18,734
Intersegment sales 9,836 3,912 425
Earnings from unconsolidated investments - - 4,131
Pretax operating income 8,889 2,302 761
Capital expenditures 298 6,570 -
Identifiable assets 234,691 310,000 99,483
NONUTILITY (continued)
Tele-
Communications Other
Sales to unaffiliated customers $ 21,354 $ 11,248
Intersegment sales 126 561
Earnings from unconsolidated investments 677 -
Pretax operating income (loss) 6,716 (822)
Capital expenditures 25,767 -
Identifiable assets 210,984 67,638
CORPORATE
Capital expenditures $ 712
Identifiable assets 19,455
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
Sales to unaffiliated customers $ 304,693 - $ 304,693
Intersegment sales 17,775 $ (17,775) -
Earnings from unconsolidated investments 4,808 - 4,808
Pretax operating income 45,557 - 45,557
Capital expenditures 52,416 (39) 52,377
Identifiable assets 3,016,619 - 3,016,619
* Sales under one contract to Reliant Energy amounted to $30,316,000 for the three-
month period ended June 30, 1999.
** The Independent Power segment is dependent on two customers, the losses of which
would have a material adverse effect on this segment.
*** The amounts include certain eliminations between the business segments.
Operations Information
Quarter Ended
June 30, 1998
Thousands of Dollars
UTILITY
Electric Natural Gas
Sales to unaffiliated customers $ 102,437 $ 19,306
Intersegment sales 1,458 222
Earnings from unconsolidated investments - -
Pretax operating income 26,767 (1,786)
Capital expenditures 13,400 8,047
Identifiable assets 1,572,714 391,479
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
Sales to unaffiliated customers $ 45,052 $ 42,823 $ 17,803
Intersegment sales 9,658 4,887 612
Earnings from unconsolidated investments - - 6,798
Pretax operating income (loss) 8,961 1,387 (1,820)
Capital expenditures 389 14,477 88
Identifiable assets 249,390 285,441 122,678
NONUTILITY (continued)
Tele-
Communications Other
Sales to unaffiliated customers $ 21,528 $ 3,046
Intersegment sales 252 300
Earnings from unconsolidated investments 3,564 -
Pretax operating income (loss) 8,892 (2,783)
Capital expenditures 6,330 435
Identifiable assets 131,286 38,424
CORPORATE
Capital expenditures $ 178
Identifiable assets 35,621
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
Sales to unaffiliated customers $ 251,995 - $ 251,995
Intersegment sales 17,389 $ (17,389) -
Earnings from unconsolidated investments 10,362 - 10,362
Pretax operating income 39,618 - 39,618
Capital expenditures 43,344 - 43,344
Identifiable assets 2,827,033 - 2,827,033
* Sales under one contract to Reliant Energy amounted to $26,711,000 for the three-
month period ended June 30, 1998.
** The Independent Power segment is dependent on two customers, the losses of which
would have a material adverse effect on this segment.
*** The amounts include certain eliminations between the business segments.
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 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 18%, of our outstanding common stock. As of August 11,
1999, the Company had 110,199,430 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 provides us with an
option to acquire up to 5,000,000 shares (adjusted for the stock split) of our
common stock, but not to exceed $125,000,000. In accordance with this
agreement, through August 11, 1999, the bank had acquired for us 1,202,200
shares of our stock at prices ranging from $31.73 to $33.50 (adjusted for the
stock split). The FEAT can be settled from time to time, at our election, on
either a full physical or net share settlement basis. The amount at which
these agreements can be settled depends principally upon the market price of
our common stock as compared with the forward purchase price per share and the
number of shares to be settled. The maturity date on the FEAT program is
October 31, 2000.
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.
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 Six Months Ended June 30, 1999 and 1998:
Net Income Per Share of Common Stock (Basic)*
We reported consolidated net income, adjusted for the stock split, of
$0.52 per share, $0.01 more than the comparable period in 1998. Utility
earnings were $0.18, compared with $0.22 for the six months ended June 30,
1998. Nonutility earnings were $0.34, compared with $0.29 for the six months
ended June 30, 1998.
Income from our electric Utility operations decreased compared with the
six months ended June 30, 1998. Revenues increased, despite industrial
customers choosing other commodity suppliers, primarily due to higher rates in
the secondary markets and increased sales of surplus power. However, higher
expenses, especially increased electric transmission and distribution expenses
associated with the higher surplus sales, more than offset these increased
revenues. Income from our natural gas Utility operations increased during the
period mainly because of higher transportation revenues, growth in residential
and commercial customers, and increased prices to recover gas supply costs.
In our Nonutility operations, increased oil and natural gas income
resulting from higher natural gas volumes and prices more than offset a
decrease in oil prices and volumes sold. Improved operations at projects in
which we hold interests contributed to increased income from our independent
power operations. In January 1999, a telecommunications customer of our
subsidiary, Touch America, exercised its option to prepay the remaining
twelve-year initial term of a capacity agreement. We are recognizing the
$257,000,000 prepayment in revenues over the remaining term of the agreement,
but income from our telecommunications operations for the first half of the
year was approximately $11,000,000 lower than it would have been because the
amount of the prepayment was discounted for early payment. Our investment
income for the first half of the year increased by approximately $4,400,000
because of the prepayment.
For comparative purposes, the following table shows consolidated basic
net income per share by principal business segment.
Six Months Ended*
June 30, June 30,
1999 1998
Utility Operations $ 0.18 $ 0.22
Nonutility Operations 0.34 0.29
Consolidated $ 0.52 $ 0.51
* Adjusted for the 2-for-1 stock split effective August 6, 1999.
UTILITY OPERATIONS
Six Months Ended
June 30, June 30,
1999 1998
Thousands of Dollars
ELECTRIC UTILITY:
REVENUES:
Revenues $ 221,977 $ 219,235
Intersegment revenues 6,468 2,454
228,445 221,689
EXPENSES:
Power supply 69,565 69,163
Transmission and distribution 22,408 17,123
Selling, general, and administrative 27,563 27,440
Taxes other than income taxes 25,289 24,172
Depreciation and amortization 27,173 26,369
171,998 164,267
INCOME FROM ELECTRIC OPERATIONS 56,447 57,422
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 41,621 40,034
Gas supply cost revenues 21,114 20,316
Intersegment revenues 336 352
63,071 60,702
EXPENSES:
Gas supply costs 21,114 20,316
Other production, gathering and exploration 1,134 1,159
Transmission and distribution 7,303 7,440
Selling, general, and administrative 10,532 10,091
Taxes other than income taxes 7,270 6,702
Depreciation, depletion, and amortization 4,640 4,407
51,993 50,115
INCOME FROM GAS OPERATIONS 11,078 10,587
INTEREST EXPENSE AND OTHER:
Interest 28,880 27,125
Distributions on company obligated mandatorily
redeemable preferred securities of subsidiary trust 2,746 2,746
Other (income) deductions - net (2,318) (795)
29,308 29,076
INCOME BEFORE INCOME TAXES AND DIVIDENDS 38,217 38,933
INCOME TAXES 16,669 13,119
DIVIDENDS ON PREFERRED STOCK 1,845 1,845
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 19,703 $ 23,969
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, the temperatures for the six months
ended June 30, 1999 in our service territory were 3% warmer than 1998 and 7%
warmer than normal. (For these purposes, "normal" means the historic
average.) In addition, winter weather for the primary heating months of
January and February was 15% warmer than normal. While the weather was warmer
overall for the first six months of 1999, weather was 14% colder than normal
for the second quarter.
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 consolidated financial
position, results of operations or cash flows.
We and our subsidiaries have entered into various long-term contracts to
purchase and sell electricity. Some of these contracts contain fixed prices.
To the extent that the electric restructuring transition process does not
address these contracts, our obligations under these contracts will expose us
to commodity price risk.
As discussed in Part I, "Notes to Consolidated Financial Statements,
Note 5 - Commitments," we entered into a contract, effective in 1998, to sell
electricity. The contract 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 taken by the
customer. The contract subjects us to commodity price risk for the fixed-
price deliveries, which continue for approximately three more years. 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 consolidated financial position, results of operations or cash flows.
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Year to Date Average)
6/30/99 6/30/98 6/30/99 6/30/98 6/30/99 6/30/98
Revenues:
Residential,
Commercial &
Government $141,237 $136,405 4 % 2,187 2,139 2 % 282,968 279,145 1 %
Industrial 36,266 55,430 (35)% 1,421 1,355 5 % 3,035 3,134 (3)%
General Business 177,503 191,835 (7)% 3,608 3,494 3 % 286,003 282,279 1 %
Sales to Other
Utilities 34,542 20,961 65 % 1,781 976 82 % 62 85 (27)%
Other 9,932 6,439 54 %
Intersegment 6,468 2,454 164 % 58 58 0 % 228 230 0 %
Total $228,445 $221,689 3 % 5,447 4,528 20 % 286,293 282,594 1 %
Power Supply
Expenses:
Hydroelectric $ 10,731 $ 11,273 (5)% 2,000 1,859 8 %
Steam 26,994 24,147 12 % 2,249 2,005 12 %
Purchases
and Other 31,840 33,743 (6)% 924 1,256 (26)%
Total Power Supply $ 69,565 $ 69,163 1 % 5,173 5,120 1 %
Dollars Per MWh $ 13.45 $ 13.51
General business revenues decreased for the six months ended June 30,
1999 primarily because of a decrease in industrial revenues. Revenues from
industrial customers decreased due to customers that chose other commodity
suppliers beginning in July 1998, in accordance with Montana's Electric
Industry Restructuring and Customer Choice Act passed in 1997 (Electric Act).
Customer growth in the residential and commercial classifications and an
increase in prices to recover the cost of public-purpose programs in
accordance with the Electric Act lessened the effects of decreased revenues
from industrial customers.
Before the Electric Act, our Utility bought and sold electricity in the
secondary markets. 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. Although we continue to reflect sales in the secondary markets as
"sales to other utilities" in the table above, we reflect revenues earned from
the transmission of the electricity sold to other utilities in the
"intersegment" line.
Revenues from sales to other utilities increased because of higher
prices and increased sales in the secondary markets. We had more electricity
available to sell in the secondary markets because of increased plant
availability, higher-than-normal spring runoff, and lower consumption caused
by customers choosing other suppliers.
Intersegment revenues and transmission and distribution expenses
increased as a result of transmitting the electricity sold in the secondary
markets. Other revenues increased mainly because of transmitting energy for
customers that chose other suppliers.
Power-supply expenses increased chiefly because of increased steam
maintenance and higher contractual prices paid to small-power producers. The
elimination of secondary purchases by our Utility mitigated the effects of
these increased costs. Taxes other than income taxes and depreciation expense
increased, representing higher property values and additional plant.
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Year to Date Average)
6/30/99 6/30/98 6/30/99 6/30/98 6/30/99 6/30/98
Revenues:
Residential
and Commercial $ 52,687 $ 50,750 4 % 11,554 11,145 4 % 148,006 144,879 2 %
Industrial 706 832 (15)% 160 192 (17)% 401 395 2 %
Subtotal 53,393 51,582 4 % 11,714 11,337 3 % 148,407 145,274 2 %
Less: Gas Supply
Cost Revenues (GSC) 21,114 20,316 4 %
General Business
without GSC 32,279 31,266 3 % 11,714 11,337 3 % 148,407 145,274 2 %
Sales to Other
Utilities 459 392 17 % 129 114 13 % 3 3 0 %
Transportation 8,011 6,269 28 % 13,466 13,056 3 % 20 23 (13)%
Other 872 2,107 (59)%
Total $ 41,621 $ 40,034 4 % 25,309 24,507 3 % 148,430 145,300 2 %
Natural gas revenues increased for the six months ended June 30, 1999
predominately because of customer growth and increased rates to recover higher
gas supply costs. Revenues from industrial customers decreased as a result of
customers choosing other commodity suppliers in accordance with a November 1,
1997 PSC order allowing natural gas customers with annual loads greater than
5,000 dekatherms the right to choose suppliers. Although revenues from
industrial customers decreased, we experienced customer growth in the
"smaller" industrial-customer classification. Transportation revenues
increased principally because of transportation of gas for customers that
chose other suppliers.
Taxes other than income taxes increased largely as a result of increased
property taxes, representing higher property values and additional plant.
Selling, general, and administrative expenses increased primarily because of
adjustments to the regulatory liability relating to the MPC Natural Gas
Funding Trust. Because revenues of this trust offset corresponding expenses,
activity of the trust does not affect operating income.
Utility Interest Expense and Other
Interest expense increased primarily due to the expense associated with
increased loans from Nonutility Operations to Utility Operations. Decreased
short-term borrowings partially offset this increased interest expense.
Income taxes increased in the first six months of 1999 due to a higher
effective tax rate. In addition, the PSC authorized our accelerated
recognition of tax credits in the first quarter 1998.
NONUTILTY OPERATIONS
Six Months Ended
June 30, June 30,
1999 1998
Thousands of Dollars
COAL:
REVENUES:
Revenues $ 92,217 $ 88,478
Intersegment revenues 19,740 19,856
111,957 108,334
EXPENSES:
Operations and maintenance 68,862 64,191
Selling, general, and administrative 9,762 9,421
Taxes other than income taxes 13,014 13,112
Depreciation, depletion, and amortization 3,684 5,267
95,322 91,991
INCOME FROM COAL OPERATIONS 16,635 16,343
OIL AND NATURAL GAS:
REVENUES:
Revenues 145,554 88,203
Intersegment revenues 8,312 9,633
153,866 97,836
EXPENSES:
Operations and maintenance 125,067 69,810
Selling, general, and administrative 8,960 10,005
Taxes other than income taxes 2,577 2,312
Depreciation, depletion, and amortization 11,519 10,848
148,123 92,975
INCOME FROM OIL AND NATURAL GAS OPERATIONS 5,743 4,861
INDEPENDENT POWER:
REVENUES:
Revenues 36,968 36,379
Earnings from unconsolidated investments 9,464 8,351
Intersegment revenues 663 1,181
47,095 45,911
EXPENSES:
Operations and maintenance 31,911 35,841
Selling, general, and administrative 1,811 2,155
Taxes other than income taxes 919 899
Depreciation, depletion, and amortization 1,561 2,372
36,202 41,267
INCOME FROM INDEPENDENT POWER OPERATIONS $ 10,893 $ 4,644
NONUTILITY OPERATIONS (continued)
Six Months Ended
June 30, June 30,
1999 1998
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 41,129 $42,208
Earnings from unconsolidated investments 2,100 5,644
Intersegment revenues 354 503
43,583 48,355
EXPENSES:
Operations and maintenance 17,828 12,912
Selling, general, and administrative 5,670 5,606
Taxes other than income taxes 1,425 2,559
Depreciation, depletion, and amortization 4,524 3,249
29,447 24,326
INCOME FROM TELECOMMUNICATIONS OPERATIONS 14,136 24,029
OTHER OPERATIONS:
REVENUES:
Revenues 19,124 4,312
Intersegment revenues 1,002 564
20,126 4,876
EXPENSES:
Operations and maintenance 18,887 5,258
Selling, general, and administrative 1,027 815
Taxes other than income taxes 612 570
Depreciation, depletion, and amortization 2,254 2,275
22,780 8,918
LOSS FROM OTHER OPERATIONS (2,654) (4,042)
INTEREST EXPENSE AND OTHER:
Interest 3,358 4,589
Other (income) deductions - net (9,915) (3,865)
(6,557) 724
INCOME BEFORE INCOME TAXES 51,310 45,111
INCOME TAXES 13,785 12,506
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 37,525 $ 32,605
NONUTILITY OPERATIONS
Coal Operations
Income from our coal operations for the six months ended June 30, 1999
increased slightly compared with the same period last year. Revenues from the
Jewett Mine increased $6,500,000 as a result of an 8.9% increase in tons sold
and an increase in reimbursable mining expenses. Revenues from the Rosebud
Mine, including revenues from a synthetic fuel project, decreased $2,900,000.
Volume of coal sold to the Colstrip Units decreased by approximately 4.2% and
related prices decreased by 4.3%. The price reduction was mainly the result
of a $2,700,000 refund to a customer for final pit reclamation funds
previously collected. That customer has assumed responsibility for a portion
of all final pit reclamation expenses in the future. Sales to a midwestern
utility for purposes of conducting test burns partially offset these
decreases.
Coal operation and maintenance expense increased at the Jewett Mine
because of the higher production, increased stripping costs, and rental
expenses incurred on additional equipment needed to meet demand. Decreased
costs at the Rosebud Mine due to a $2,700,000 credit to reclamation expense
associated with the refund discussed above partially offset these increases.
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:
Natural gas -revenue $ 54
-volume 66 %
-price/Mcf 2 %
Natural gas liquids -revenue $ 3
-volume 34 %
-price/bbl (2)%
Oil -revenue $ (1)
-volume (22)%
-price/bbl (9)%
Income from our oil and natural gas operations increased due to
increased marketing activities and higher gas prices in the first half of
1999. Natural gas revenues increased because marketing revenues and volumes
more than doubled as a result of increased sales into California and
midwestern markets. In addition, gas production from our properties and gas
prices both were higher. Revenues from oil operations decreased because of
lower prices and lower production as a result of our on-going strategy to
focus more on natural gas and to reduce our oil position. Natural gas liquids
revenues were higher, again because of increased marketing activity.
Operation and maintenance expense increased mainly because of increased
purchased gas costs associated with the California and midwestern gas sales
discussed earlier. Selling, general, and administrative expense decreased due
to reduced incentive compensation accruals and lower expenditures for outside
services. Depreciation, depletion, and amortization increased because of
increased gas production.
Independent Power Operations
Income from our independent power operations increased approximately
$6,200,000 because of improved operations at generating plants in which
Continental Energy holds equity interests, and Continental Energy's receipt in
the second quarter of additional proceeds relating to the late 1998 contract
settlement of a project in which it held an interest. The absence of earnings
resulting from both the late 1998 sale of a project in which Continental
Energy held an interest and the contract settlement mentioned above lessened
the effects of the improved operations.
Operations and maintenance expense was approximately $3,900,000 lower
compared with 1998 because of lower project-development expenses related to
Continental Energy's development of a domestic investment opportunity.
Continental Energy capitalized these costs in the third quarter 1998.
Amortization expense was approximately $800,000 lower compared with 1998
because of the contract settlement in the fourth quarter 1998.
Telecommunications Operations
Income from our telecommunications operations was approximately
$9,900,000 less than it was for the same period one year ago primarily because
one of Touch America's customers exercised its option to prepay amounts due
for the remaining twelve-year initial term of a capacity agreement. The
amount of the prepayment was discounted for early payment and will result in
approximately $24,000,000 less in annual operating revenues than we would have
realized had the customer not exercised its option. Consequently, operating
revenues for the six months ended June 30, 1999 were approximately $11,000,000
less than they would have been absent the prepayment.
Revenues from dark-fiber sales were approximately $3,500,000 lower than
those revenues during the same period in 1998. We expect to recognize
approximately $3,000,000 in dark-fiber revenues from existing agreements
during the remainder of 1999. We also expect to recognize additional revenues
from dark-fiber sales during the third and fourth quarters from other
agreements that we are negotiating.
After adjusting private-line revenues for the accounting effects of the
prepayment and excluding the dark-fiber sales revenues, revenues from
telecommunications operations increased approximately 23%. With the same
adjustments, income from telecommunications operations increased approximately
25%.
The increase in operating revenues, after the above adjustments,
consists of several elements. It includes increased private-line revenues of
approximately $4,000,000 because of higher sales of fiber capacity. It also
includes increased long-distance and equipment-service revenues of
approximately $5,500,000. Long-distance revenues increased as a result of
increased long-distance customer and minute sales. Equipment-service revenues
increased as a result of customer growth and Touch America providing customer
service for Y2K upgrades.
Long-distance and equipment-service operations and maintenance expense
increased approximately $4,000,000 because of increased sales. Taxes other
than income taxes decreased approximately $1,100,000 primarily 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 released $700,000 in June 1999,
reducing property tax expense.
Other Operations
Revenues and expenses of other operations increased primarily because of
MPT&M's increased electric-trading activities. 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, and comparatively higher market prices for
electricity. (See Part I, Item 3, "Quantitative and Qualitative Disclosures
About Market Risk," for a brief discussion of why we have remained in the
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) and deductions - net increased by approximately
$6,000,000, of which approximately $4,400,000 was attributable to interest
received on the prepayment funds. The remaining increase is largely
attributable to increased interest income on loans from Nonutility Operations
to Utility Operations.
Quarter Ended June 30, 1999 and 1998
Net Income Per Share of Common Stock (Basic)*
Second quarter earnings, adjusted for the stock split, were $0.22 per
share, $0.03 more than second quarter 1998. Utility earnings were $0.05,
compared with $0.04 last year. Nonutility earnings were $0.17, compared with
$0.15 a year earlier.
Income from our electric Utility operations was flat compared with the
six months ended June 30, 1998. Electric Utility revenues increased, despite
industrial customers choosing other suppliers, due primarily to higher rates
in the secondary markets and increased sales of surplus power. However,
higher expenses, particularly increased electric transmission and distribution
expenses associated with the higher surplus sales, offset these increased
revenues. Income from our natural gas Utility operations increased during the
period mainly because of a weather-related increase in volumes sold.
In our Nonutility operations, our oil and natural gas operating income
increased, resulting from higher natural gas prices and volumes sold, more
than offsetting a decrease in oil volumes sold. Because of the discounted
prepayment discussed in the six-months-ended section, income from our
telecommunications operations for the second quarter was approximately
$6,000,000 lower than it would have been otherwise. The prepayment improved
our investment income for the quarter by approximately $1,900,000.
For comparative purposes, the following table shows consolidated basic
net income per share by principal business segment.
Six Months Ended*
June 30, June 30,
1999 1998
Utility Operations $ 0.05 $ 0.04
Nonutility Operations 0.17 0.15
Consolidated $ 0.22 $ 0.19
* Adjusted for the 2-for-1 stock split effective August 6, 1999.
UTILITY OPERATIONS
Quarter Ended
June 30, June 30,
1999 1998
Thousands of Dollars
ELECTRIC UTILITY:
REVENUES:
Revenues $105,443 $102,437
Intersegment revenues 2,778 1,458
108,221 103,895
EXPENSES:
Power supply 30,878 29,196
Transmission and distribution 10,731 8,539
Selling, general, and administrative 13,810 14,134
Taxes other than income taxes 12,535 12,075
Depreciation and amortization 13,494 13,184
81,448 77,128
INCOME FROM ELECTRIC OPERATIONS 26,773 26,767
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 15,328 13,368
Gas supply cost revenues 7,062 5,938
Intersegment revenues 137 222
22,527 19,528
EXPENSES:
Gas supply costs 7,062 5,938
Other production, gathering, and exploration 341 514
Transmission and distribution 3,667 3,805
Selling, general, and administrative 4,776 5,524
Taxes other than income taxes 3,453 3,330
Depreciation, depletion, and amortization 2,290 2,203
21,589 21,314
INCOME FROM GAS OPERATIONS 938 (1,786)
INTEREST EXPENSE AND OTHER:
Interest 14,442 13,680
Distributions on company obligated manditorily
Redeemable preferred securities of subsidiary trust 1,373 1,373
Other (income) deductions - net (1,033) (678)
14,782 14,375
INCOME BEFORE INCOME TAXES AND DIVIDENDS 12,929 10,606
INCOME TAXES 5,994 4,662
DIVIDENDS ON PREFERRED STOCK 922 922
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 6,013 $ 5,022
UTILITY OPERATIONS
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Quarterly Average)
6/30/99 6/30/98 6/30/99 6/30/98 6/30/99 6/30/98
Revenues:
Residential
and Commercial $ 65,313 $ 61,916 5 % 1,059 1,008 5 % 282,447 278,817 1 %
Industrial 16,773 27,143 (38)% 711 699 2 % 3,766 3,929 (4)%
General Business 82,086 89,059 (8)% 1,770 1,707 4 % 286,213 282,746 1 %
Sales to Other
Utilities 18,099 11,626 56 % 910 528 72 % 61 85 (28)%
Other 5,258 1,752 200 %
Intersegment 2,778 1,458 91 % 25 37 (32)% 229 230 0 %
Total $ 108,221 $103,895 4 % 2,705 2,272 19 % 286,503 283,061 1 %
Power Supply
Expenses:
Hydroelectric $ 5,270 $ 5,609 (6)% 1,130 1,041 9 %
Steam 14,007 12,440 13 % 980 984 0 %
Purchases
and Other 11,601 11,147 4 % 373 460 (19)%
Total Power Supply $ 30,878 $ 29,196 6 % 2,483 2,485 0 %
Dollars Per MWh $ 12.44 $ 11.75
Second quarter revenues and expenses changed overall for the same reasons
mentioned above in the six-months-ended section.
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Quarterly Average)
6/30/99 6/30/98 6/30/99 6/30/98 6/30/99 6/30/98
Revenues:
Residential
and Commercial $17,838 $14,870 20 % 3,734 3,030 23 % 147,693 144,515 2 %
Industrial 240 190 26 % 53 41 29 % 399 390 2 %
Subtotal 18,078 15,060 20 % 3,787 3,071 23 % 148,092 144,905 2 %
Less: Gas Supply
Cost Revenues (GSC) 7,062 5,938 19 %
General Business
without GSC 11,016 9,122 21 % 3,787 3,071 23 % 148,092 144,905 2 %
Sales to Other
Utilities 171 142 20 % 35 20 75 % 3 3 0 %
Transportation 3,819 3,205 19 % 6,364 6,178 3 % 20 23 (13)%
Other 322 899 (64)%
Total $15,328 $13,368 14 % 10,186 9,269 10 % 148,115 144,931 2 %
Natural gas revenues increased in the second quarter mainly because of
an increase in volumes sold associated with colder-than-normal weather.
Transportation revenues increased for the same reason mentioned above in the
six-months-ended section.
Utility Interest Expense and Other
Interest expense increased primarily due to the expense associated with
increased loans from Nonutility Operations to Utility Operations and interest
associated with amended tax returns for prior years. Decreased interest on
long-term debt lessened the effects of these higher expenses.
NONUTILITY OPERATIONS
Quarter Ended
June 30, June 30,
1999 1998
Thousands of Dollars
COAL:
REVENUES:
Revenues $ 48,779 $ 45,052
Intersegment revenues 9,836 9,658
58,615 54,710
EXPENSES:
Operations and maintenance 36,530 32,426
Selling, general, and administrative 4,740 4,369
Taxes other than income taxes 6,657 6,423
Depreciation, depletion, and amortization 1,799 2,531
49,726 45,749
INCOME FROM COAL OPERATIONS 8,889 8,961
OIL AND NATURAL GAS:
REVENUES:
Revenues 76,745 42,823
Intersegment revenues 3,912 4,887
80,657 47,710
EXPENSES:
Operations and maintenance 66,116 34,248
Selling, general, and administrative 4,732 5,643
Taxes other than income taxes 1,553 961
Depreciation, depletion, and amortization 5,954 5,471
78,355 46,323
INCOME FROM OIL AND NATURAL GAS OPERATIONS 2,302 1,387
INDEPENDENT POWER:
REVENUES:
Revenues 18,734 17,803
Earnings from unconsolidated investments 4,131 6,798
Intersegment revenues 425 612
23,290 25,213
EXPENSES:
Operations and maintenance 16,177 17,168
Selling, general, and administrative 981 1,181
Taxes other than income taxes 456 433
Depreciation, depletion, and amortization 784 1,453
18,398 20,235
INCOME FROM INDEPENDENT POWER OPERATIONS $ 4,892 $ 4,978
NONUTILITY OPERATIONS (continued)
Quarter Ended
June 30, June 30,
1999 1998
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $21,354 $ 21,528
Earnings from unconsolidated investments 677 3,564
Intersegment revenues 126 252
22,157 25,344
EXPENSES:
Operations and maintenance 9,382 6,725
Selling, general, and administrative 2,888 3,142
Taxes other than income taxes 385 1,314
Depreciation, depletion, and amortization 2,109 1,707
14,764 12,888
INCOME FROM TELECOMMUNICATIONS OPERATIONS 7,393 12,456
OTHER OPERATIONS:
REVENUES:
Revenues 11,248 3,046
Intersegment revenues 561 300
11,809 3,346
EXPENSES:
Operations and maintenance 11,456 3,742
Selling, general, and administrative (297) 969
Taxes other than income taxes 299 266
Depreciation, depletion, and amortization 1,173 1,152
12,631 6,129
LOSS FROM OTHER OPERATIONS (822) (2,783)
INTEREST EXPENSE AND OTHER:
Interest 1,254 2,360
Other (income) deductions - net (4,418) (1,082)
(3,164) 1,278
INCOME BEFORE INCOME TAXES 25,818 23,721
INCOME TAXES 7,504 7,115
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $18,314 $16,606
NONUTILITY OPERATIONS
Coal Operations
Income from our coal operations for the quarter ended June 30, 1999 was
flat compared with the same period last year. Revenues from the Jewett Mine
increased $3,600,000 as a result of a 3.5% increase in tons sold and an
increase in reimbursable mining expenses. Revenues from the Rosebud Mine,
including revenues from a synthetic fuel project, increased $300,000. Volumes
of coal sold to the Colstrip Units decreased by approximately 1.2% and related
prices decreased by 2.1%. Other coal sales more than offset these decreases.
Coal operation and maintenance expense increased at the Jewett Mine for
the same reasons discussed above in the six-months-ended section. Operation
and maintenance expenses were higher at the Rosebud Mine due to increased
production. Depreciation, depletion, and amortization decreased principally
because of additional depreciation recorded on idle equipment at the Rosebud
Mine 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:
Natural gas -revenue $ 29
-volume 35 %
-price/Mcf 29 %
Natural gas liquids -revenue $ 3
-volume 38 %
-price/Mcf 22 %
Oil -revenue $ 0
-volume (22)%
-price/Mcf 18 %
Miscellaneous $ 1
Income from oil and natural gas operations increased due to increased
marketing activities and higher prices in the second quarter of 1999. Natural
gas and natural gas liquids revenues increased for the same reasons discussed
in the six-months-ended section. Revenues from oil operations were flat
because lower production offset increased prices.
Increases and decreases in operation and maintenance expense; selling,
general, and administrative expense; and depreciation, depletion, and
amortization changed for the same reasons discussed above in the six-months-
ended section. Taxes other than income increased because of the higher value
of the gas produced from our reserves.
Independent Power Operations
Income from our independent power operations was relatively stable.
Earnings from unconsolidated investments decreased approximately $2,700,000
primarily because of the absence of earnings resulting from Continental
Energy's late 1998 sale of a project and contract settlement of another
project in which it held interests. Improved operations in other generating
plants in which Continental Energy holds equity interests, Continental
Energy's second-quarter receipt of additional proceeds relating to the
contract settlement mentioned above, and lower operations and maintenance
expense for the reasons mentioned above in the six-months-ended section,
partially offset the effects of these events.
Telecommunications Operations
For the quarter, revenues and expenses from our telecommunications
operations changed for the same reasons presented above in the six-months-
ended section.
Other Operations
As discussed above in the six-months-ended section, revenues and
expenses of other operations increased primarily because of MPT&M's increased
electric-trading activities.
Nonutility Interest Expense and Other
Interest expense decreased for the same reasons discussed above in the
six-months-ended section.
Other (income) and deductions - net increased by approximately
$3,300,000, of which approximately $1,900,000 was attributable to interest
income received from the telecommunications prepayment discussed above. The
remaining increase was primarily attributable to increased interest income on
loans from Nonutility Operations to Utility Operations.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities --
Net cash provided by operating activities was $209,636,000 for the six
months ended June 30, 1999 compared with $90,496,000 in the first six months
of 1998. The current-year increase of $119,140,000 was attributable mainly to
the $257,000,000 prepayment received in January 1999 from a Touch America
customer. Cash from the prepayment was used to reduce long-term debt and
short-term borrowing 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 $69,213,000 for the six
months ended June 30, 1999 compared with $57,422,000 in the first six months
of 1998. The current-year increase of $11,791,000 was attributable mainly to
an increase in capital expenditures by our telecommunications operations,
partially offset by a decrease in capital expenditures by the Utility and oil
and gas operations, along with a current-year decrease in proceeds received
from property sales and investments.
For information regarding Touch America's investments in domestic access
lines and one-number digital wireless services, refer to Part 1, "Notes to
Consolidated Financial Statements, Note 5 - Commitments." While we have not
expended any funds at this time, we expect our source of funds for these
investments to be generated internally or borrowed from third parties.
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
7.7% First Mortgage Bonds.
Our consolidated borrowing ability under our Revolving Credit and Term
Loan Agreements was $179,023,000, of which $164,240,000 was unused at June 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 1, "Notes to Consolidated Financial Statements, Note 9 - Common
Stock."
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended June 30, 1999, our ratio of earnings to fixed
charges was 3.36 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 Year 2000 issue, known as Y2K, relates to the ability of systems -
including computer hardware, software and embedded microprocessors - to
properly interpret date information relating to the year 2000. Many existing
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" instead of "19". If not corrected, these systems could fail
or create erroneous results.
Strategy
We have a corporate-wide strategy to address Y2K issues. We established
an Executive Steering Committee to coordinate and oversee implementation of
the strategy in our business units. The strategy includes a three-step
process and a contingency plan. The first step involves 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 conduct certain analyses to
determine the systems' Y2K readiness. The third step consists of
replacing/repairing and testing the systems to ensure the availability and
integrity of the systems. Simultaneous with those three steps, we are
developing contingency plans to address unanticipated failure of the systems.
Inventorying, analysis, modifications and testing of the critical IT
systems are complete. These systems involve computer systems within our main
business office, such as accounting systems, human resource systems, materials
management systems, and work-management systems. Currently, we believe that,
of the systems inventoried, two critical IT systems are not yet Y2K-ready: (1)
the Customer Information System, which provides Utility customer billing and
field operations support, and (2) the Interval Meter Programming and Data
Collection Software, needed for our customer billing process. We are pursuing
a billing outsourcing solution that we expect to have in place no later than
September 30, 1999. We have received, and are testing and installing, Y2K-
ready versions of the Meter Programming and Data Collection Software. We
expect to complete this testing and installation no later than September 30,
1999. In the event that this or any other critical system fails in spite of
our readiness efforts, we are developing contingency plans.
Inventorying, analysis, modifications and testing of critical non-IT
systems are also complete. The continuous emission monitoring systems, which
monitor stack gas emissions at the Corette and Colstrip Plants, are scheduled
for a software upgrade from the vendor. We expect the vendor to complete this
software upgrade no later than September 30, 1999. We are developing
contingency plans in the event that these systems fail in spite of our
readiness efforts.
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 preparations of electric
systems in North America for operation into the year 2000. As part of its
Year 2000 program, NERC monitors the monthly progress of industry efforts to
prepare critical systems for the year 2000. NERC held a national drill on
April 9, 1999 to assess industry preparation. We participated in the drill
and deemed our performance successful. NERC plans another drill in September
1999, and we plan to participate in that session as well.
Y2K Expenditures
We have not established a formal process to track either external or
internal 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, the capital
upgrade to the energy management system (EMS), which is necessary in any event
to provide additional functionality, will also result in a Y2K benefit and
cost $460,000. An additional $36,000 to test custom software associated with
the EMS and the upgrade software is accounted for as a Y2K expense. Likewise,
we are implementing 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 to satisfy deregulation requirements. In addition, our
Information Services Department 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, we presently believe that the ultimate cost of Y2K
modifications will not have a material adverse effect on our consolidated
financial position, results of operations or cash flows.
Most Reasonably Likely "Worst-Case" Scenario
Except as described above, we believe that all necessary modifications
and testing of our critical IT and critical non-IT systems are complete. Also,
as previously discussed, we expect to have contingency plans in place. The
most reasonably likely "worst-case" Y2K scenario that we envision is that some
of our 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
In June 1998, the Financial Accounting Standards Board 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 Financial Accounting Standards Board 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 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 marked to market energy contracts that qualified as "trading
activities." As a result, we recognized an immaterial loss in the results of
operations for the first quarter and an immaterial gain in the results of
operations for the second 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.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to the market risks associated with fluctuations in
commodity prices, interest rates, and changes in foreign currency translation
rates. We are exposed to these market risks through our non-regulated energy
commodity-producing, trading, and marketing activities and through other
investments that we own and agreements that we have entered.
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, "Notes to Consolidated Financial Statements, Note
3 - Derivative Financial Instruments."
Electricity
In August 1998, we announced that we would exit the electric trading and
marketing business. We have remained in the electric-trading 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 closing of the sale of our electric
generating assets, we will exit the electric-trading business.
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
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) for physical and financial natural gas,
crude oil and natural gas liquids transactions 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.
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 June 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 less than $2,000,000.
On June 21, 1999, our Audit Committee approved a proposed increase to
MPT&M's VaR limit. Since then, and through August 11, 1999, MPT&M has
reported no daily adverse changes in fair values in excess of its revised VaR
limit. While the former limit was in effect, MPT&M reported daily adverse
changes in fair values in excess of that VaR amount on (1) seven occasions for
the period from January 1, 1999 through June 21, 1999, and (2) four occasions
for the period from April 1, 1999 through June 21, 1999. The former VaR limit
was based only on natural gas physical and financial transactions. The
revised VaR limit includes these transactions as well as physical and
financial transactions relating to crude oil and natural gas liquids.
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." Since December
31, 1998, there has 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.
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 1, Item 1, "Notes to
Consolidated Financial Statements, Note 2 - Contingencies."
ITEM 2. Changes in Securities and Use of Proceeds
On May 11, 1999, our security holders approved at our Annual Meeting of
Shareholders an amendment to our Articles of Incorporation to increase the
authorized shares of common stock from 120,000,000 shares to 240,000,000
shares.
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 4. Submission of Matters to a Vote of Security Holders
(a) Our Annual Meeting of Shareholders was held on May 11, 1999.
(b) Security holders elected four persons to our Board of Directors at
our Annual Meeting. The results of the vote were as follows:
Director For Against Abstentions
Tucker Hart Adams 47,899,305 -- 1,362,104
Alan F. Cain 47,681,826 -- 1,578,583
John G. Connors 47,971,361 -- 1,289,048
Robert P. Gannon 47,869,301 -- 1,391,108
Directors whose term of office as a director continued after the
meeting are as follows:
R. D. Corette Carl Lehrkind, III
Kay Foster Jerrold P. Pederson
Beverly D. Harris N. E. Vosburg
John R. Jester
(c) Security holders approved an amendment to The Montana Power Company
Long-Term Incentive Plan (the Plan) at our Annual Meeting of
Shareholders. The purpose of the Plan is to reward employees who
make important contributions to our continued growth, development,
and financial success or that of our subsidiaries and to attract
and retain such employees. The results of the vote were as
follows:
For Against Abstentions
25,086,275 15,315,822 866,229
(d) Security holders approved an amendment to the Articles of
Incorporation to increase the authorized shares of common stock
from 120,000,000 shares to 240,000,000 shares at our Annual
Meeting. The increased number of shares will provide shares for
the Rights Plan, as well as additional shares for issuance from
time to time, without further action or authorization by the
shareholders, if needed for such proper corporate purposes as may
be determined by our Board of Directors. Such purposes may
include stock splits, the raising of additional capital through
the sale of additional shares, and acquisitions by the Company.
The result of the vote were as follows:
For Against Abstentions
43,684,962 4,866,037 709,410
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 3 Amendment to the Articles of Incorporation
*Exhibit 10 The Montana Power Company Amended Long-
Term Incentive Plan
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
June 30, 1999.
Exhibit 27 Financial data schedule
*Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
DATE SUBJECT
April 27, 1999 Item 5 Other Events. Discussion of First
Quarter Net Income.
Item 7 Exhibits. Preliminary Consolidated
Statements of Income for the Quarters
Ended March 31, 1999 and 1998 and for the
Twelve Months Ended March 31, 1999 and
1998. Preliminary Utility Operations
Schedule of Revenues and Expenses for the
Quarters Ended March 31, 1999 and 1998
and for the Twelve Months Ended March 31,
1999 and 1998. Preliminary Nonutility
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1999 and 1998 and for the Twelve Months
Ended March 31, 1999 and 1998.
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: August 16, 1999
EXHIBIT INDEX
Exhibit 3
Amendment to the Articles of Incorporation
Exhibit 10
The Montana Power Company
Amended Long-Term Incentive Plan
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended June 30, 1999
Exhibit 27
Financial data schedule
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
June 30,1999
Net Income $153,153
Income Taxes 83,002
$236,155
Fixed Charges:
Interest $ 64,052
Amortization of Debt Discount,
Expense, and Premium 1,414
Rentals 34,620
$100,086
Earnings Before Income Taxes
and Fixed Charges $336,241
Ratio of Earning to Fixed Charges 3.36x
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