<PAGE>
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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended: September 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to ____________________
Commission file number: 1-10216
CHIEFTAIN INTERNATIONAL, INC.
-----------------------------
(Exact name of registrant as specified in its charter)
Alberta, Canada None
- --------------------------------- -----------------------------------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1201 TD Tower, 10088 - 102 Avenue,
Edmonton, Alberta, Canada T5J 2Z1
- --------------------------------- ------------------------------------
(Address of principal executive (Zip Code/Postal Code)
offices)
Registrant's telephone number, including area code: (780) 425-1950
Not Applicable
- --------------------------------------------------------------------------------
(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) have 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 class of
common stock, as of the latest practicable date.
Title of each class Date Number Outstanding
- ------------------- --------------------------- ------------------
Common shares October 8 , 1999 13,349,059
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CHIEFTAIN INTERNATIONAL, INC.
SEPTEMBER 30, 1999 FORM 10-Q QUARTERLY REPORT
TABLE OF CONTENTS
PART I
<TABLE>
<CAPTION>
Page No.
Item 1. Financial Statements
<S> <C>
Consolidated Condensed Balance Sheet -
September 30, 1999 and December 31, 1998 3
Consolidated Condensed Statement of Income (Loss) -
Nine months ended September 30, 1999 and 1998 and
Three months ended September 30, 1999 and 1998 4
Consolidated Condensed Statement of Cash Flows -
Nine months ended September 30, 1999 and 1998 5
Notes to Consolidated Condensed Financial Statements 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 9
PART II
Item 1. Legal Proceedings 13
Item 2. Changes in Securities 13
Item 3. Defaults Upon Senior Securities 13
Item 4. Submission of Matters to a Vote of Security Holders 13
Item 5. Other Information 13
Item 6. Exhibits and Reports on Form 8-K 13
Signatures 13
</TABLE>
<PAGE>
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEET
(Full Cost Method of Accounting)
<TABLE>
<CAPTION>
SEPTEMBER 30, December 31,
1999 1998
- --------------------------------------------------------------------------------------------
(unaudited) (US $ in thousands)
ASSETS
<S> <C> <C>
Current assets:
Cash and short-term deposits $ 597 $ 10,613
Accounts receivable 20,111 14,030
Other 792 282
------------------ ------------------
21,500 24,925
Capital assets - net 275,471 288,477
Deferred income taxes 10,892 5,182
------------------ ------------------
$ 307,863 $ 318,584
------------------ ------------------
------------------ ------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued $ 16,791 $ 22,533
Long-term debt 45,000 40,000
Abandonment cost accrual 8,305 7,421
Deferred income taxes 13,978 13,684
Shareholders' equity:
Preferred shares of a subsidiary 63,403 63,403
Common shares 189,010 189,108
Contributed surplus 26 --
Deficit (28,650) (17,565)
------------------ ------------------
223,789 234,946
------------------ ------------------
$ 307,863 $ 318,584
------------------ ------------------
------------------ ------------------
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE>
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF INCOME (LOSS)
<TABLE>
<CAPTION>
Nine months Three months
Period ended September 30 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
(unaudited) (US $ in thousands except number of shares and per share amounts)
<S> <C> <C> <C> <C>
Production revenue, net of royalties $ 52,954 $ 44,852 $ 22,569 $ 13,822
Interest and other revenue (Note 2) 570 2,613 194 121
------------ ------------ ------------ ------------
53,524 47,465 22,763 13,943
------------ ------------ ------------ ------------
Production costs 10,985 12,219 3,623 4,206
General and administrative expenses 3,354 3,668 981 917
Interest 1,867 285 666 260
Depletion and amortization 38,711 30,096 13,619 9,905
Additional depletion: Libyan properties (Note 3) 11,393 -- -- --
------------ ------------ ------------ ------------
66,310 46,268 18,889 15,288
------------ ------------ ------------ ------------
Income (loss) before income taxes
and dividends on preferred shares
of a subsidiary (12,786) 1,197 3,874 (1,345)
Income taxes (Note 4) (5,408) 1,141 1,356 (109)
------------ ------------ ------------ ------------
Income (loss) before dividends on
preferred shares of a subsidiary (7,378) 56 2,518 (1,236)
Dividends on preferred shares of a
subsidiary 3,707 3,707 1,236 1,236
------------ ------------ ------------ ------------
Net income (loss) applicable to
common shares $ (11,085) $ (3,651) $ 1,282 $ (2,472)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Net income (loss) per common share (Note 5)
- Basic $ (0.83) $ (0.27) $ 0.10 $ (0.18)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
- Fully diluted $ (0.83) $ (0.27) $ 0.10 $ (0.18)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Weighted average number of common shares outstanding:
- Basic 13,350,383 13,520,786 13,348,645 13,438,005
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
- Fully diluted 13,350,383 13,520,786 13,348,645 13,438,005
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE>
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
(unaudited) (US $ in thousands)
<S> <C> <C>
Operating activities:
Net income (loss) applicable to common shares $ (11,085) $ (3,651)
Items not requiring a current cash outlay 44,688 31,210
-------------- -----------------
33,603 27,559
Net change in non-cash operating working capital (Note 6) (6,358) (713)
-------------- -----------------
27,245 26,846
Financing activities:
Increase in long-term debt 5,000 25,000
Purchase of common shares for cancellation (80) (5,355)
Issue of common shares 9 437
-------------- -----------------
4,929 20,082
Investing activities:
Lease acquisition, exploration and drilling costs (30,270) (55,847)
Pipelines and production equipment acquired (6,072) (10,351)
Sale of producing properties 155 --
-------------- -----------------
(36,187) (66,198)
Purchase of other capital assets (28) (87)
Change in investing accounts payable and accrued (5,975) (1,465)
-------------- -----------------
(42,190) (67,750)
-------------- -----------------
Change in cash and short term deposits (10,016) (20,822)
Beginning cash and short-term deposits 10,613 26,925
-------------- -----------------
Ending cash and short-term deposits $ 597 $ 6,103
-------------- -----------------
-------------- -----------------
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE>
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
1. Basis of Presentation:
---------------------
In the opinion of Chieftain International, Inc. (the "Company" and
together with its subsidiaries "Chieftain"), the accompanying unaudited
consolidated condensed financial statements contain all adjustments
(consisting of only normal recurring accruals) necessary to present
fairly the financial position as at September 30, 1999 and December 31,
1998 and the results of operations and statement of cash flow for the
nine month periods ended September 30, 1999 and 1998. Certain
information and notes normally included in Chieftain's financial
statements prepared in conformity with Canadian generally accepted
accounting principles have been condensed or omitted pursuant to the
rules and regulations of the Securities and Exchange Commission. These
consolidated condensed financial statements should be read in
conjunction with the audited consolidated financial statements and the
notes thereto included in Chieftain's Annual Report on Form 10-K for
the year ended December 31, 1998.
Preparation of financial statements in conformity with generally
accepted accounting principles requires management to make informed
judgements and estimates. Actual results may differ from those
estimates.
The results of operations and cash flows for the nine month period
ended September 30, 1999 are not necessarily indicative of the results
to be expected for the full year.
Material differences between Canadian and US accounting principles that
affect Chieftain are referred to in Note 7, which provides the effects
of such differences on earnings and balance sheet accounts.
2. Interest and Other Revenue:
--------------------------
Interest and other revenue for the first quarter of 1998 included $1.6
million awarded by the courts pursuant to a successful claim for
recovery of excess transportation charges incurred from 1990 through
1997. The award comprises transportation charges, legal fees and
judgement interest in the amounts of $1,129,000, $282,000 and $189,000,
respectively.
3. Additional Depletion:
--------------------
Additional depletion of $11.4 million arises from the termination of an
exploration program and production test in Libya.
4. Income Taxes:
------------
The provision for income taxes differs from the amount of income tax
determined by applying the Canadian statutory rate to pre-tax income
(loss) before dividends paid on preferred shares of a subsidiary as a
result of the following:
<TABLE>
<CAPTION>
Nine months Three months
Period ended September 30 1999 1998 1999 1998
--------------------------------------------------------------------------------------------------------------------------
(unaudited) (US $ in thousands)
<S> <C> <C> <C> <C>
Tax at statutory Canadian rate 44.62% $ (5,705) $ 534 $ 1,729 $ (603)
Lower income tax rate on earnings of US
subsidiaries (76) (144) (407) 95
Canadian income tax on exchange loss (gain)
which is eliminated upon consolidation 634 220 41 47
Prior years' tax reassessments -- 208 -- 208
Exchange revaluation of Canadian
deferred tax assets (289) 222 (9) 105
Other 28 101 2 39
----------- ----------- ------------ -----------
Tax at effective rate $ (5,408) $ 1,141 $ 1,356 $ (109)
----------- ----------- ------------ -----------
----------- ----------- ------------ -----------
Effective tax rate 42.3% 95.3% 35.0% 8.1%
----------- ----------- ------------ -----------
----------- ----------- ------------ -----------
</TABLE>
<PAGE>
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5. Per Share Amounts:
-----------------
Net income (loss) per common share is computed by dividing net income
(loss) applicable to common shares, by the weighted average number of
common shares outstanding during the period.
In the calculation of fully diluted earnings per share, shares
outstanding are adjusted for share options and shares issuable on
conversion of preferred shares where dilutive. Earnings are adjusted by
the amount of imputed interest on share option proceeds and preferred
share dividends.
6. Supplemental Cash Flow Information:
----------------------------------
Cash outflows for (inflows from) income taxes during the 1999 third
quarter were $ (29,000) (year-to-date-($12,000)) (1998-third quarter -
$14,000; year-to-date - $41,000). Cash outflows for long-term debt
interest during the 1999 third quarter were $653,000 (year-to-date -
$1,804,000); (1998-third quarter - $156,000; year-to-date - $156,000).
7. United States Accounting Principles:
-----------------------------------
(a) Full cost accounting
US full cost accounting rules differ materially from the
Canadian full cost accounting guidelines followed by Chieftain.
The US rules require an impairment test to be conducted
quarterly whereas the Canadian guidelines require this test
only at year-end. In determining the limitation on carrying
values, US rules require the discounting of future net revenues
at 10%, and Canadian guidelines require the use of undiscounted
future net revenues and the deduction of estimated future
administrative and financing costs. The quarterly test required
by U.S. accounting rules, using a March 31, 1999 U.K. natural
gas price of $0.84 per mcf to determine future net revenues,
would have resulted in a write-down of U.K. property carrying
costs at March 31, 1999 of $7.1 million and, after providing
for tax recoveries of $3.1 million, a net charge to operations
of $4.0 million. Using June 30, 1998 U.S. gas and oil prices of
$2.09 per mcf and $12.40 per barrel to determine future net
revenues would have resulted in a write-down of U.S. property
carrying costs at June 30, 1998 of $24.7 million and, after
providing for tax recoveries of $8.6 million, a net charge to
operations of $16.1 million.
(b) Effect on earnings
The effect on consolidated earnings of these differences is
summarized as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30 1999 1998
-----------------------------------------------------------------------------------------------------------
(US$ in thousands except number of
shares and per share amounts)
<S> <C> <C>
Net income (loss) applicable to common shares
as reported $ (11,085) $ (3,651)
Additional depletion (7,104) (24,725)
----------------- -----------------
(18,189) (28,376)
Add reduction in depletion expense 13,122 2,631
Decrease (increase) in deferred tax provision (1,656) 7,449
----------------- -----------------
Net income (loss) applicable to common shares
under US accounting principles $ (6,723) $ (18,296)
----------------- -----------------
----------------- -----------------
Net income (loss) per common share under US accounting principles:
- Basic $ (0.50) $ (1.35)
----------------- -----------------
----------------- -----------------
- Fully diluted $ (0.50) $ (1.35)
----------------- -----------------
----------------- -----------------
Fully diluted number of common shares
outstanding 13,350,383 13,520,786
----------------- -----------------
----------------- -----------------
</TABLE>
<PAGE>
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<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30 1999 1998
-----------------------------------------------------------------------------------------------------------
(US$ in thousands except number of shares
and per share amounts)
<S> <C> <C>
Net income (loss) applicable to common shares
as reported $ 1,282 $ (2,472)
----------------- -----------------
Add reduction in depletion expense 4,926 1,212
Decrease (increase) in deferred tax provision (1,830) (708)
----------------- -----------------
Net income (loss) applicable to common shares
under US accounting principles $ 4,378 $ (1,968)
----------------- -----------------
----------------- -----------------
Net income (loss) per common share under US
accounting principles:
- Basic $ 0.33 $ (0.15)
----------------- -----------------
----------------- -----------------
- Fully diluted $ 0.32 $ (0.15)
----------------- -----------------
----------------- -----------------
Fully diluted number of common shares
outstanding 13,493,458 13,438,005
----------------- -----------------
----------------- -----------------
</TABLE>
(c) Effect on balance sheet
The effect on the Consolidated Condensed Balance Sheet of the
differences between Canadian and US accounting principles is as
follows:
<TABLE>
<CAPTION>
AS AT SEPTEMBER 30, 1999 December 31, 1998
-----------------------------------------------------------------------------------------------------------------
(US$ in thousands)
Under US Under US
As reported Accounting As reported Accounting
Principles Principles
-------------- ----------------- ---------------- -----------------
<S> <C> <C> <C> <C>
Net capital assets $ 275,471 $ 178,529 $ 288,477 $ 185,517
Deferred tax - asset $ 10,892 $ 31,993 $ 5,182 $ 28,233
Deferred tax - liability $ 13,978 $ -- $ 13,684 $ --
Deficit $ (28,650) $ (90,513) $ (17,565) $ (83,790)
</TABLE>
Additionally, for US reporting purposes, the preferred shares
shown as shareholders' equity in these consolidated condensed
financial statements would be shown outside the equity section.
(d) Stock-based compensation
The Company applies the intrinsic value method prescribed by APB
Opinion 25 and related interpretations in accounting for share
option transactions. Accordingly, no compensation cost is
recognized in the accounts. US accounting principles require
disclosure of the impact on earnings and earnings per share of the
value of options granted after 1994, calculated in accordance with
FAS 123. For the nine months ended September 30, 1999 such impact
would amount to a net of tax charge to income (loss) of $946,000
(1998 - $1,270,000) and for the three months ended September 30
such impact would amount to a net of tax charge to income (loss)
of $355,000 (1998 - $397,000). Under US accounting principles
after reflecting this charge, for the nine months ended September
30, pro forma net income (loss) applicable to common shares would
be $(7,669,000) (1998 - ($19,566,000)); net income (loss) per
common share would be $(0.57) (1998 - $(1.45)); and pro forma
fully diluted earnings (loss) per common share would be $(0.57)
(1998 - $(1.45)). For the three months ended September 30, pro
forma net income (loss) applicable to common shares under US
accounting principles would be $4,023,000 (1998 - $(2,365,000));
pro forma net income (loss) per common share would be $0.30 (1998
- $(0.18)); and pro forma fully diluted earnings (loss) per common
share would be $0.30 (1998 - $(0.18)). These effects are not
necessarily indicative of those to be expected in future periods.
<PAGE>
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
You should read the following discussion and analysis in conjunction with our
accompanying unaudited consolidated condensed financial statements.
We produce and sell natural gas and oil acquired through exploration and
development or through the purchase of producing properties. Our properties
are located in the United States Gulf of Mexico, onshore in Utah and
Louisiana and also in the U.K. sector of the North Sea. The majority of our
attention and resources is focused on the U.S. Gulf of Mexico area where we
hold interests in 143 offshore lease blocks.
Our financial statements and information are reported in U.S. dollars.
Substantially all of our revenues and a significant portion of our operating
expenses are realized or incurred in U.S. dollars.
Our financial statements are prepared based upon Canadian generally accepted
accounting principles. For a discussion of the effect of differences in
generally accepted accounting principles in Canada and the United States on our
financial statements, see Note 11 to our 1998 consolidated financial statements
and Note 7 to our accompanying unaudited consolidated condensed financial
statements.
OPERATING RESULTS
FIRST NINE MONTHS 1999 COMPARED TO FIRST NINE MONTHS 1998
PRODUCTION AND PRICING. Our average daily combined natural gas and oil
production increased 15% to 93.9 MMcfe (113.7 MMcfe before royalties) for the
first nine months of 1999 from 81.4 MMcfe (98.6 MMcfe before royalties) for the
corresponding period in 1998. Natural gas comprised 74% of our production for
the first nine months of 1999 and 79% of our production for the corresponding
period in 1998. For the first nine months of 1999, our natural gas production
increased 9% to 19.1 Bcf (23.3 Bcf before royalties) compared to 17.5 Bcf (21.4
Bcf before royalties) for the corresponding period in 1998. For the first nine
months of 1999, our oil and natural gas liquids production increased 38% to
1,091 MBbls (1,285 MBbls before royalties) compared to 792 MBbls (912 MBbls
before royalties) for the corresponding period in 1998. Natural gas prices
averaged $1.89 per Mcf for the first nine months of 1999 compared to $2.02 per
Mcf for the corresponding period in 1998. Oil and natural gas liquids prices
averaged $15.62 per barrel for the first nine months of 1999 compared to $12.39
per barrel for the corresponding period in 1998.
PRODUCTION REVENUES. For the first nine months of 1999, our combined natural gas
and oil production volumes increased 15% from the corresponding period in 1998.
A 26% recovery in oil prices was partially offset by a 6% decrease in natural
gas prices. As a result, our production revenues for the first nine months of
1999 increased 18% ($8.1 million), to $53.0 million from the corresponding
period in 1998.
Eighty-four percent of our natural gas production for the first nine months of
1999 resulted from our interests in 92 wells in the Gulf of Mexico. Our natural
gas production increased 9% in the first nine months of 1999 over the
corresponding period in 1998. This increase in production resulted primarily
from the commencement of production from South Marsh Island 39 at the end of the
first quarter of 1999 and from the commencement of initial natural gas
production from Main Pass 250 B during the latter half of the second quarter of
1999. We expect to add production in the fourth quarter of 1999 from a discovery
made at South Marsh Island 39 during the third quarter of 1999 and from Main
Pass 225 D.
At September 30, 1999, we were producing 68.6 MMcf per day of natural gas (82.9
MMcf per day before royalties), of which 57.9 MMcf per day (72.2 MMcf per day
before royalties) was from the U.S. and 10.7 MMcf per day (before and after
royalties) was from the North Sea. At September 30, 1999, oil production was
4,301 barrels per day (5,089 barrels per day before royalties) of which 1,770
barrels per day (2,027 barrels per day
<PAGE>
Page 10 of 13
before royalties) was from the Aneth and Ratherford Units in Utah and 2,493
barrels per day (3,022 barrels per day before royalties) was from the Gulf of
Mexico.
PRODUCTION COSTS. Our production costs for the first nine months of 1999
decreased 10% from the corresponding period in 1998. This decrease primarily
reflects significant pipeline repair costs in the South Pass area during the
first quarter of 1998 and a succession of weather induced evacuations of manned
facilities in the Gulf of Mexico in the third quarter of 1998. Production costs
on a per unit basis decreased to $0.43 per Mcfe ($0.35 per Mcfe before
royalties), down 22% from the first nine months' average for 1998 of $0.55 per
Mcfe ($0.45 per Mcfe before royalties).
For the first nine months of 1999, production costs were $0.30 per Mcfe ($0.24
per Mcfe before royalties) for Gulf of Mexico area properties, $1.36 per Mcfe
($1.19 per Mcfe before royalties) for the Utah oil producing properties where
secondary and tertiary recovery methods are being used, and $0.08 per Mcfe
(before and after royalties) for the United Kingdom properties.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses for
the first nine months of 1999 decreased 9% from the corresponding period in
1998. This decrease reflects higher performance-based compensation payments made
during the first quarter of 1998 than during the corresponding period in 1999.
General and administrative costs for the first nine months of 1999, on a per
unit basis, decreased 21% to $0.13 per Mcfe ($0.11 per Mcfe before royalties)
compared to $0.17 per Mcfe ($0.14 per Mcfe before royalties) for the
corresponding period of 1998.
INTEREST EXPENSE. Our interest expense for the first nine months of 1999
increased compared to the corresponding 1998 period due to greater credit
facility utilization. Our weighted average debt outstanding for the nine months
ended September 30, 1999 was $43.3 million compared to $6.1 million for the
corresponding period in 1998. The effective interest rate on our outstanding
debt for the nine months ended September 30, 1999 was 5.76% compared to 6.19%
for the corresponding period in 1998. The weighted average interest rate on our
debt at September 30, 1999 was 6.24%.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the first
nine months of 1999 increased 29% from the corresponding period in 1998 as a
result of a 15% increase in our production and an 11% increase in our average
depletion rate to $1.51 per Mcfe ($1.25 per Mcfe before royalties). The
significant downward revision in our proved reserves at December 31, 1998 that
resulted from the low oil prices on that date is primarily responsible for the
increase in our effective depletion rate in the first nine months of 1999
compared to the corresponding period in 1998.
In Libya, Chieftain and its partners concluded that a multi-year exploration
program and production test is not commercial under the terms of the concession
and will therefore terminate the program. As a result, additional depletion of
$11.4 million was recorded in the second quarter of 1999 to eliminate this
investment, resulting in a charge to operations, net of income taxes, of $6.3
million.
THREE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 1998
PRODUCTION AND PRICING. Our average daily combined natural gas and oil
production increased 29% to 98.3 MMcfe (118.4 MMcfe before royalties) for the
third quarter of 1999 from 76.2 MMcfe (93.6 MMcfe before royalties) for the
corresponding period in 1998. Natural gas comprised 73% of our production for
the third quarter of 1999 and 78% of our production for the corresponding period
in 1998. For the third quarter of 1999, our natural gas production increased 21%
to 6.6 Bcf (8.0 Bcf before royalties) compared to 5.5 Bcf (6.8 Bcf before
royalties) for the corresponding period in 1998. For the third quarter of 1999,
our oil and liquids production increased 56% to 404 MBbls (478 MBbls before
royalties) compared to 260 MBbls (300 MBbls before royalties) for the
corresponding period in 1998. Natural gas prices averaged $2.26 per Mcf for the
third quarter of 1999 compared to $1.96 per Mcf for the corresponding period in
1998. Oil and natural gas liquids prices averaged $19.31 per barrel for the
third quarter of 1999 compared to $11.86 per barrel for the corresponding period
in 1998.
<PAGE>
Page 11 of 13
PRODUCTION REVENUES. For the third quarter of 1999, our combined natural gas and
oil production volumes increased by 29% from the corresponding period in 1998.
Oil prices for the quarter increased 63% and natural gas prices increased 15%
from the corresponding period in 1998. As a result, our production revenues
increased 63% ($8.7 million), to $22.6 million from the corresponding period in
1998.
PRODUCTION COSTS. Our production costs for the third quarter of 1999 decreased
14% from the corresponding period in 1998. This decrease primarily reflects a
succession of weather induced evacuations of manned facilities in the Gulf of
Mexico in the third quarter of 1998. Production costs on a per unit basis
decreased to $0.40 per Mcfe ($0.33 per Mcfe before royalties), down 33% from the
1998 third quarter average of $0.60 per Mcfe ($0.49 per Mcfe before royalties).
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses for
the third quarter of 1999 increased 7% from the corresponding period in 1998.
General and administrative costs on a per unit basis decreased 18% to $0.11 per
Mcfe ($0.09 per Mcfe before royalties) compared to $0.13 per Mcfe ($0.11 per
Mcfe before royalties) for the corresponding period of 1998.
INTEREST EXPENSE. Our interest expense for the third quarter of 1999 increased
compared to the corresponding 1998 period due to greater credit facility
utilization. $45 million of our $100 million revolving credit facility was
utilized at September 30, 1999 compared to $25 million at September 30, 1998.
Our weighted average debt outstanding for the third quarter of 1999 was $45.0
million compared to $16.7 million for the corresponding period in 1998. The
effective interest rate on our outstanding debt for the third quarter of 1999
was 5.87% compared to 6.16% for the corresponding period in 1998.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the third
quarter increased 37% from the corresponding period in 1998 as a result of a 29%
increase in our production and a 7% increase in the average depletion rate to
$1.51 per Mcfe ($1.25 per Mcfe before royalties).
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of cash are funds generated from our operations and
financing activities. Our primary cash outflows are for exploration and
development activities.
Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is derived by adjusting net income (loss)
attributable to common shares to eliminate the effects of depletion and
amortization, additional depletion and deferred income taxes. We generated
discretionary cash flow of $33.6 million during the first nine months of 1999
compared to $27.5 million for the corresponding period in 1998. This increase of
22% is primarily a result of our higher operating revenues.
Our financing activities in the first nine months of 1999 provided $4.9 million
of cash, the net result of the drawdown of $5 million of our revolving credit
facility, the exercise of employee stock options and the purchase for
cancellation of 7,500 common shares under our share repurchase program, which
expires on November 1, 1999. Financing activities during the corresponding
period in 1998 provided $20.1 million of cash, which was the net result of:
o the drawdown of $25 million of our revolving credit facility,
o the exercise of employee stock options for $0.4 million, and
o the purchase for cancellation of 264,600 common shares at the cost of
$5.3 million under our stock repurchase program.
Cash used in investing activities decreased 38% to $42.2 million for the first
nine months of 1999 from $67.8 million for the corresponding period in 1998. Our
capital expenditures during the first nine months of 1999
<PAGE>
Page 12 of 13
totaled $36.2 million. Of this amount, $1.8 million was expended on
development drilling, $23.0 million on exploratory drilling, $4.7 million on
capital field development and the balance was expended on leasehold, seismic
and geological costs. Of the 15 wells in which we participated in 1999, ten
were in the Gulf of Mexico (four of which were still being drilled at
September 30, 1999), three were onshore in the U.S. and two were in Libya.
Five additional wells were drilled on our Gulf of Mexico acreage at no cost
to us, one of which resulted in a natural gas well and four of which were
unsuccessful. We are currently participating or plan to participate in the
drilling of approximately 15 exploratory and development wells during the
fourth quarter of 1999.
Our September 30, 1999 cash balance of $0.6 million was down $5.5 million from
the balance at September 30, 1998. We had outstanding borrowings of $45 million
on our $100 million revolving credit facility at September 30, 1999. The
weighted average interest rate for our borrowings during the first nine months
was 5.76%.
OUTLOOK
Currently, we have budgeted approximately $18.6 million for exploration and
development capital expenditures for the fourth quarter of 1999. Our
preliminary 2000 capital expenditure budget is estimated at $86 million. We
expect to fund most of these expenditures from our operational cash flow.
These capital expenditures can vary significantly as a result of exploration
success, availability of equipment and services and opportunities. We will
monitor capital spending and adjust investment levels based on cash flow
projections. We will continue to focus on natural gas production in the Gulf
of Mexico.
YEAR 2000 DISCLOSURE
We have completed our assessment of our internal Year 2000 issues and have made
the changes and employed the testing procedures that we deemed necessary. At
this time, we are confident that no internal issues remain that could have a
material effect on our financial condition or results of operations. We
substantially completed our assessment of the readiness of third parties by the
end of the second quarter of 1999. We continue to monitor the readiness of
significant third parties in order to obtain assurances that interruptions, if
any, will be held to a minimum. We do not consider the costs that we have
incurred to date and which we expect to incur in the future to be material.
We have interests in a substantial number of offshore oil and gas production
facilities that are operated by others. We are required to rely on assessments
by others as to Year 2000 readiness of such facilities. Production volumes are
transported through pipelines and processed through facilities that are also
operated by others. Computers are used extensively to control and operate such
pipelines and facilities in the oil and natural gas industry and it is
reasonably likely that one or more of such facilities will experience a computer
related event which could result in the shut down of production, transportation
or processing facilities for such time as is required to effect alternative
controls. We cannot reasonably quantify the estimated lost revenue, if any,
which would result from such an interruption. To mitigate the effect of any
interruptions, we intend to continue our review of contingency plans prepared by
our various operating partners.
FORWARD LOOKING INFORMATION
This 10-Q contains forward-looking statements that are subject to risk factors
associated with the oil and gas business. The Company believes that the
expectations reflected in these statements are reasonable, but may be affected
by a number of factors including, but not limited to: price fluctuations,
currency fluctuations, drilling and production results, imprecision of reserve
estimates, loss of market, industry competition, environmental risks, political
risks and capital restrictions.
<PAGE>
Page 13 of 13
PART II
Item 1. Legal Proceedings
Chieftain is not party to, and none of its properties is the subject
of, any material legal proceedings.
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
There have been no defaults upon senior securities of Chieftain.
Item 4. Submission of Matters to a Vote of Security Holders
No matters have been submitted to a vote of the security holders of the
Company during the third quarter of 1999.
Item 5. Other Information
None
Item 6. Exhibits and Reports of Form 8-K
None
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Chieftain International, Inc.
- -----------------------------
(Registrant)
/s/ E. L. Hahn
- --------------------------------------------
E. L. Hahn
Senior Vice President, Finance and Treasurer
(Chief Financial Officer)
Dated: October 8, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
SEPTEMBER 30, 1999 BALANCE SHEET AND THE STATEMENT OF INCOME (LOSS) FOR THE NINE
MONTHS ENDED SEPTEMBER 30, 1999 INCLUDED IN THE COMPANY'S SEPTEMBER 30, 1999
10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 597
<SECURITIES> 0
<RECEIVABLES> 20,111
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 21,500
<PP&E> 590,704<F1>
<DEPRECIATION> 315,233
<TOTAL-ASSETS> 307,863<F2>
<CURRENT-LIABILITIES> 16,791
<BONDS> 45,000<F3>
0
0
<COMMON> 189,010
<OTHER-SE> 34,779<F4>
<TOTAL-LIABILITY-AND-EQUITY> 307,863<F5>
<SALES> 52,954
<TOTAL-REVENUES> 53,524
<CGS> 0
<TOTAL-COSTS> 64,443<F6>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,867
<INCOME-PRETAX> (12,786)
<INCOME-TAX> (5,408)
<INCOME-CONTINUING> (7,378)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (7,378)
<EPS-BASIC> (0.83)
<EPS-DILUTED> (0.83)
<FN>
<F1>The Company accounts for gas and oil properties in accordance with Canadian
guidelines on full cost accounting.
<F2>Deferred income taxes of $10,892 have been included in total assets.
<F3>Unsecured revolving credit facility with a syndicate of banks, in the amount of
US $100 million, fully revolving for 364 day periods with extensions at the
option of the lenders upon notice from the Company. If not extended, the
facility converts to term loans repayable over a period not exceeding four
years. Advances under the facility bear interest at Canadian prime or US base
rate, or at Bankers' Acceptance rates or LIBOR plus applicable margins.
<F4>Preferred shares of a subsidiary of $63,403, contributed surplus of $26
(attributable to common shares), and retained earnings (deficit) of $(28,650),
have been combined in calculating other stockholders' equity.
<F5>Abandonment cost accrual of $8,305 and deferred income taxes of $12,397 have
been included in total liabilities and stockholders' equity.
<F6>Production costs of $10,985, general and administrative expenses of $3,354,
depletion and amortization of $38,711, and additional depletion of $11,393 have
been combined in calculating total costs.
</FN>
</TABLE>
