<PAGE> 1
Page 1 of 21
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, 2000
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)
<TABLE>
<S> <C>
Alberta, Canada None
----------------------------------------------------- ---------------------------------------------------
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
1201 TD Tower, 10088 - 102 Avenue,
Edmonton, Alberta, Canada T5J 2Z1
-------------------------------------------- ---------------------------------------------------
(Address of principal executive offices) (Zip Code/Postal Code)
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)
</TABLE>
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 13, 2000 [16,111,492]
<PAGE> 2
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CHIEFTAIN INTERNATIONAL, INC.
SEPTEMBER 30, 2000 FORM 10-Q QUARTERLY REPORT
TABLE OF CONTENTS
PART I
<TABLE>
<CAPTION>
Page No.
--------
<S> <C> <C>
Item 1. Financial Statements
Consolidated Condensed Balance Sheet -
September 30, 2000 and December 31, 1999 3
Consolidated Condensed Statement of Income (Loss) -
Nine months ended September 30, 2000 and 1999 and
Three months ended September 30, 2000 and 1999 4
Consolidated Condensed Statement of Cash Flows -
Nine months ended September 30, 2000 and 1999 5
Notes to Consolidated Condensed Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 10
PART II
Item 1. Legal Proceedings 21
Item 2. Changes in Securities 21
Item 3. Defaults Upon Senior Securities 21
Item 4. Submission of Matters to a Vote of Security Holders 21
Item 5. Other Information 21
Item 6. Exhibits and Reports of Form 8-K 21
Signatures 21
</TABLE>
<PAGE> 3
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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,
2000 1999
------------- ------------
(unaudited) (US $ in thousands)
<S> <C> <C>
ASSETS
Current assets:
Cash and short-term deposits $ 10,911 $ 19,368
Accounts receivable 26,757 18,855
Other 1,126 750
--------- ---------
38,794 38,973
Capital assets - net 311,757 277,149
Deferred income taxes 12,987 14,636
--------- ---------
$ 363,538 $ 330,758
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued $ 24,381 $ 25,369
Long-term debt 20,000 10,000
Abandonment cost accrual 9,382 8,595
Deferred income taxes 25,932 15,693
Shareholders' equity:
Preferred shares of a subsidiary 63,403 63,403
Common shares (Note 2) 235,646 237,076
Contributed surplus -- 26
Deficit (15,206) (29,404)
--------- ----------
283,843 271,101
--------- ---------
$ 363,538 $ 330,758
========= =========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE> 4
Page 4 of 21
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF INCOME (LOSS)
<TABLE>
<CAPTION>
Nine months Three months
-------------------------- -------------------------
Period ended September 30, 2000 1999 2000 1999
-------------------------- ----------- ----------- ----------- -----------
(unaudited) (US $ in thousands except number of shares
and per share amounts)
<S> <C> <C> <C> <C>
Revenue:
Production revenue $ 92,880 $ 64,236 $ 38,465 $ 27,391
Less: royalties 16,529 11,282 7,010 4,822
----------- ----------- ----------- -----------
Production revenue, after royalties 76,351 52,954 31,455 22,569
Interest and other revenue (Note 3) 2,305 570 1,541 194
----------- ----------- ----------- ----------
78,656 53,524 32,996 22,763
----------- ----------- ----------- ----------
Expenses:
Production costs 10,530 10,985 3,551 3,623
General and administrative 4,447 3,354 1,253 981
Interest 749 1,867 343 666
Depletion and amortization 32,234 38,711 11,497 13,619
Additional depletion: Libyan properties
(Note 4) -- 11,393 -- --
----------- ----------- ----------- -----------
47,960 66,310 16,644 18,889
----------- ----------- ----------- -----------
Income (loss) before income taxes and dividends on 30,696 (12,786) 16,352 3,874
preferred shares of a subsidiary
Income taxes (Note 5) 12,032 (5,408) 6,176 1,356
----------- ----------- ----------- -----------
Income (loss) before dividends on preferred shares
of a subsidiary 18,664 (7,378) 10,176 2,518
Dividends on preferred shares of a subsidiary 3,707 3,707 1,236 1,236
----------- ----------- ----------- -----------
Net income (loss) applicable to common shares $ 14,957 $ (11,085) $ 8,940 $ 1,282
=========== =========== =========== ===========
Net income (loss) per common share
(Note 6) - Basic $ 0.92 $ (0.83) $ 0.55 $ 0.10
=========== =========== =========== ===========
- Fully diluted $ 0.88 $ (0.83) $ 0.49 $ 0.10
=========== =========== =========== ===========
Weighted average number of common shares
outstanding: - Basic 16,221,269 13,350,383 16,215,756 13,348,645
=========== =========== =========== ===========
- Fully diluted 17,411,462 13,350,383 20,954,287 13,348,645
=========== =========== =========== ===========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE> 5
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 2000 1999
------------------------------- -------- --------
(unaudited) (US $ in thousands)
<S> <C> <C>
Operating activities:
Net income (loss) applicable to common shares $ 14,957 $(11,085)
Items not requiring a current cash outlay 44,122 44,688
-------- --------
Cash flow from operations 59,079 33,603
Net change in non-cash operating working capital (Note 7) (6,079) (6,358)
-------- --------
Net cash inflows from operating activities 53,000 27,245
Financing activities:
Increase in long-term debt 10,000 5,000
Purchase of common shares for cancellation (2,485) (80)
Issue of common shares 270 9
-------- --------
Net cash inflows from financing activities 7,785 4,929
-------- --------
Net cash inflows from operating and financing activities 60,785 32,174
Investing activities:
Lease acquisition, exploration and drilling costs (47,353) (30,270)
Pipelines and production equipment acquired (18,702) (6,100)
Sale of producing properties -- 155
-------- --------
Natural resource investing activities (66,055) (36,215)
Change in investing accounts payable and accrued (3,187) (5,975)
-------- --------
Net cash outflows for investing activities (69,242) (42,190)
-------- --------
Change in cash and short-term deposits (8,457) (10,016)
Beginning cash and short-term deposits 19,368 10,613
-------- --------
Ending cash and short-term deposits $ 10,911 $ 597
======== ========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE> 6
Page 6 of 21
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2000 and 1999
(unaudited)
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, 2000 and December 31,
1999 and the results of operations for the nine month and three month
periods ended September 30, 2000 and 1999 and cash flows for the nine
month periods ended September 30, 2000 and 1999. 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 for interim reporting pursuant to the rules and
regulations of the Securities and Exchange Commission. These consolidated
condensed financial statements should be read in conjunction with the
consolidated financial statements and the notes thereto included in
Chieftain's Annual Report on Form 10-K for the year ended December 31,
1999.
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, 2000 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 9, which describes the effects
of such differences on earnings and balance sheet accounts.
2. Common Shares:
(a) Common shares outstanding
At September 30, 2000, 16,127,892 (December 31, 1999 - 16,224,059)
common shares of the Company were issued and outstanding.
(b) Common shares reserved
At September 30, 2000, 1,479,967 (December 31, 1999 - 1,130,207) of
the authorized but unissued common shares of the Company were
reserved for issuance under the Share Option Plan. At September 30,
2000, 3,408,375 (December 31, 1999 - 3,408,375) common shares were
reserved for issuance pursuant to the conversion provisions of the
preferred shares of a subsidiary. See Note 2(c).
(c) Preferred shares of a subsidiary
Chieftain International Funding Corp. ("Funding"), a subsidiary of
Chieftain International (U.S.) Inc., sold 2,726,700 shares of $1.8125
cumulative convertible redeemable preferred shares at $25.00 per
share in a 1992 public offering in the US. The preferred shares are
redeemable, at the option of Funding, at $25.4028 per share during
2000, $25.2014 per share during 2001 and $25.00 per share after
December 31, 2001, plus accumulated and unpaid dividends. Each
preferred share has a liquidation preference of $25.00 and is
convertible at any time into 1.25 common shares of Chieftain
International, Inc. at the option of the holder.
<PAGE> 7
Page 7 of 21
3. Interest and Other Revenue:
Interest and other revenue for the third quarter of 2000 included a
non-recurring $1.3 million revenue item arising from the Libyan venture
which was terminated in the second quarter of 1999. Under the terms of
the concession, the Libyan National Oil Company ("NOC") reimbursed
Chieftain and its partners in kind for NOC's share of production test
expenditures. The non-recurring revenue item arose due to the increase in
oil prices between the time when production test expenditures were
incurred and when the reimbursement was effected.
4. Additional Depletion:
Additional depletion of $11.4 million arose from the termination in 1999
of an exploration program and production test in Libya.
5. Income Taxes:
The provision for income taxes differs from the amount of income tax
determined by applying the Canadian statutory rate to pre-tax income
(loss) before dividends paid on preferred shares of a subsidiary as a
result of the following:
<TABLE>
<CAPTION>
Nine months Three months
------------------- ------------------
Period ended September 30, 2000 1999 2000 1999
-------------------------- ------- ------- ------- ------
(US$ in thousands)
<S> <C> <C> <C> <C>
Tax at statutory Canadian rate of 44.62% $13,697 $(5,705) $ 7,297 $1,729
Lower income tax rate on earnings of US subsidiaries (2,665) (76) (1,392) (407)
Canadian income tax on exchange loss (gain) which is
eliminated upon consolidation 77 634 36 41
Reduction in value of deferred tax assets resulting
from reduction in future Canadian rate 329 -- -- --
Other 594 (261) 235 (7)
------- ------- ------- ------
Tax at effective rate $12,032 $(5,408) $ 6,176 $1,356
======= ======= ======= ======
Effective tax rate 39.2% 42.3% 37.8% 35.0%
======= ======= ======= ======
</TABLE>
6. 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.
7. Supplemental Cash Flow Information:
Cash outflows for (inflows from) income taxes during the nine months
ended September 30, 2000 were $136,000 (1999 - $(12,000)). Cash outflows
for interest on long-term debt during the nine months ended September 30,
2000 were $655,000 (1999 - $1,804,000).
8. Subsequent Event:
Subsequent to September 30, 2000, the Company purchased, at a cost of $5
million, 4,852,258 Gulfstream Resources Canada Limited treasury common
shares, representing approximately eight percent of the then issued and
outstanding common shares of Gulfstream Resources Canada Limited.
<PAGE> 8
Page 8 of 21
9. 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%; 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 US accounting rules, using a March 31, 1999 UK
natural gas price of $0.84 per Mcf to determine future net revenues,
would have resulted in a write-down of UK 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 $4.0
million.
(b) Effect on earnings
The effect on consolidated earnings of these differences is
summarized as follows:
<TABLE>
<CAPTION>
Nine months Three months
-------------------------- --------------------------
Period ended September 30, 2000 1999 2000 1999
-------------------------- ---------- ---------- ---------- ----------
(US$ in thousands except number of shares
and per share amounts)
<S> <C> <C> <C> <C>
Net income (loss) applicable to common shares,
as reported $ 14,957 $ (11,085) $ 8,940 $ 1,282
Additional depletion difference -- (7,104) -- --
---------- ---------- ---------- ----------
14,957 (18,189) 8,940 1,282
Reduction in depletion expense 8,054 13,122 2,801 4,926
Decrease (increase) in deferred tax provision (2,569) (1,656) (996) (1,830)
---------- ---------- ---------- ----------
Net income (loss) applicable to common shares
under US accounting principles $ 20,442 $ (6,723) $ 10,745 $ 4,378
========== ========== ========== ==========
Net income (loss) per common share under
US accounting principles:
- Basic $ 1.26 $ (0.50) $ 0.66 $ 0.33
========== ========== ========== ==========
- Fully diluted $ 1.22 $ (0.50) $ 0.60 $ 0.32
========== ========== ========== ==========
Fully diluted number of common shares
outstanding 19,846,934 13,350,383 19,844,309 13,493,458
========== ========== ========== ==========
</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, 2000 December 31, 1999
----- ------------------------ ------------------------
(US$ in thousands) Under US Under US
Accounting Accounting
As reported Principles As reported Principles
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Net capital assets $311,757 $232,163 $277,149 $189,501
Deferred tax - asset $ 12,987 $ 15,781 $ 14,636 $ 30,238
Deferred tax - liability $ 25,932 $ -- $ 15,693 $ --
Deficit $(15,206) $(66,074) $(29,404) $(85,757)
</TABLE>
For US reporting purposes, the preferred shares would not be included
in shareholders' equity in these consolidated condensed financial
statements.
<PAGE> 9
Page 9 of 21
(d) Stock-based compensation
The Company accounts for its stock-based compensation plan under APB
Opinion 25 and related interpretations, under which no compensation
costs have been recognized in the financial statements for share
option transactions. If compensation costs had been recorded in
accordance with FAS 123, the Company's net income (loss) applicable
to common shares and net income (loss) per common share would
approximate the following pro forma amounts:
<TABLE>
<CAPTION>
Nine months Three months
------------------- ------------------
Period ended September 30, 2000 1999 2000 1999
-------------------------- ------- ------- ------- ------
(US$ in thousands except per share amounts)
<S> <C> <C> <C> <C>
Compensation costs, net of tax $ 990 $ 946 $ 363 $ 355
Net income (loss) applicable to common shares
- as reported $20,442 $(6,723) $10,745 $4,378
- pro forma $19,452 $(7,669) $10,382 $4,023
Net income (loss) per common share
Basic
- as reported $ 1.26 $ (0.50) $ 0.66 $ 0.33
- pro forma $ 1.20 $ (0.57) $ 0.64 $ 0.30
Fully diluted
- as reported $ 1.22 $ (0.50) $ 0.60 $ 0.32
- pro forma $ 1.18 $ (0.57) $ 0.59 $ 0.30
</TABLE>
<PAGE> 10
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ITEM 2. 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. The
information contains forward looking statements that are subject to risk factors
associated with the oil and gas business. Forward looking statements typically
contain words such as "anticipate", "believe", "expect", "plan" or similar words
suggesting future outcomes. We believe that the expectations reflected in these
statements are reasonable, but may be affected by a variety 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 and capital restrictions.
Our financial statements and information are reported in US dollars and are
prepared based upon Canadian generally accepted accounting principles.
Substantially all of our revenues and a significant portion of our operating
expenses are realized or incurred in US dollars. For a discussion of the effect
of differences in generally accepted accounting principles in Canada and the US
on our financial statements, see Note 12 to our 1999 consolidated financial
statements and Note 9 to our accompanying unaudited consolidated condensed
financial statements.
OVERVIEW
Production in the third quarter of 2000 averaged 101.3 MMcfe per day (82.8 MMcfe
per day after royalties), a 7% increase from the second quarter of 2000. Strong
natural gas and oil prices contributed to our record first nine months revenues
of $95.2 million ($78.7 million after royalties), net income applicable to
common shares of $15.0 million and cash flow from operations of $59.1 million.
FIRST NINE MONTHS 2000 COMPARED TO FIRST NINE MONTHS 1999
PRODUCTION
On an energy equivalent basis our average production rate for the first nine
months of 2000 decreased 13% to 98.4 MMcfe per day (81.1 MMcfe per day after
royalties) from 113.7 MMcfe per day (93.9 MMcfe per day after royalties) for the
corresponding period in 1999. Natural gas comprised 75% (74% after royalties) of
our production for the first nine months of 2000, unchanged from the
corresponding period in 1999. For the first nine months of 2000, our natural gas
production decreased 13% to 20.2 Bcf (16.5 Bcf after royalties) compared to 23.3
Bcf (19.1 Bcf after royalties) for the corresponding period in 1999. Of the 3.1
Bcf (2.6 Bcf after royalties) decrease in natural gas production, 42% (1.3 Bcf
before and after royalties) is attributable to production declines in the UK.
Oil and natural gas liquids production for the same period decreased 13% to
1,123 MBbls (948 MBbls after royalties) compared to 1,285 MBbls (1,091 MBbls
after royalties) for the corresponding period in 1999. Of the 162 MBbls (143
MBbls after royalties) decrease in oil and natural gas liquids production, 43%
(70 MBbls (58 MBbls after royalties)) is attributable to production declines at
South Marsh Island 39, where, at the end of the third quarter of 2000,
production rates had stabilized at approximately 900 barrels per day (750
barrels per day after royalties).
The decrease in our production is attributed to natural reservoir declines in
our existing offshore Gulf of Mexico and UK fields and the timing of new
production which commenced in the second and third quarters. New
--------------------------------------------------------------------------------
Unless the context indicates another meaning, the terms "Chieftain", "the
Company", "we", "us" and "our" refer to Chieftain International, Inc., a company
organized under the laws of the Province of Alberta, Canada, and its
subsidiaries.
As used in this Form 10-Q, "BCF" means 1,000,000,000 cubic feet of natural gas,
"BCFE" means 1,000,000,000 cubic feet of natural gas equivalent, "MBBLS" means
1,000 barrels of crude oil, condensate and natural gas liquids, "MCF" means
1,000 cubic feet of natural gas, "MCFE" means 1,000 cubic feet of natural gas
equivalent using a ratio of 1 barrel = 6,000 cubic feet of natural gas, "MMCF"
means 1,000,000 cubic feet and "MMCFE" means 1,000,000 cubic feet of natural gas
equivalent.
<PAGE> 11
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production from Vermilion 267, South Timbalier 196, Chacahoula and two wells at
Northeast Wright added a combined average volume of 29.9 MMcfe per day (27.1
MMcfe per day after royalties), net to us, for September 2000.
Ninety-three percent of our natural gas production for the first nine months of
2000 came from the US Gulf of Mexico region compared to 88% in the corresponding
period in 1999. Our interests in this region accounted for 54% of our oil and
ngls production compared to 53% in the 1999 period. Substantially all of the
remainder of our oil and ngls production is from our interests in the Aneth and
Ratherford Units in southeast Utah.
During the month of September, 2000, we produced 102.4 MMcfe per day (83.5 MMcfe
per day after royalties). Of this amount, 79.6 MMcf per day was natural gas
(64.2 MMcf per day after royalties), of which 79.5 MMcf per day (64.1 MMcf per
day after royalties) was from the US and 0.1 MMcf per day (before and after
royalties) was from the UK. In September, 2000, oil production was 3,779 barrels
per day (3,193 barrels per day after royalties) of which 1,623 barrels per day
(1,417 barrels per day after royalties) was from the Aneth and Ratherford Units
in Utah and 2,142 barrels per day (1,764 barrels per day after royalties) was
from the US Gulf of Mexico region.
<TABLE>
<CAPTION>
PRODUCTION SUMMARY Before royalties After royalties
---------------- ---------------
Nine months ended September 30, 2000 1999 2000 1999
------------------------------- ----- ----- ----- ------
<S> <C> <C> <C> <C>
Natural gas (MMcf per day)
US 68.9 75.7 55.4 60.3
UK 4.9 9.7 4.9 9.7
----- ----- ----- -----
Total 73.8 85.4 60.3 70.0
===== ===== ===== =====
Oil and ngls (barrels per day) 4,099 4,706 3,459 3,995
===== ===== ===== =====
Total natural gas equivalent (MMcfe per day) 98.4 113.7 81.1 93.9
===== ===== ===== =====
Total period equivalent (Bcfe) 27.0 31.0 22.2 25.6
===== ===== ===== =====
</TABLE>
NATURAL GAS AND OIL MARKETING
NATURAL GAS. Natural gas prices averaged $3.10 per Mcf for the first nine months
of 2000 compared to $1.89 per Mcf for the corresponding period in 1999. For the
first nine months of 2000, we received average natural gas prices of $3.21 per
Mcf in the US and $1.46 per Mcf in the UK compared to $2.02 and $0.93,
respectively, for the corresponding period in 1999. We believe that this
strengthening of prices, in both markets, reflects increasingly tight
supply-demand equations. The Energy Information Administration ("EIA") of the
U.S. Department of Energy has reported that US end-use consumption, through the
first eight months of 2000, was similar to that of the comparative 1999 period.
In its September outlook, the EIA forecasted US natural gas demand to increase
6.4% in the fourth quarter this year from the 1999 fourth quarter, and 2.5%
growth in the 2001 year. The EIA is forecasting annual domestic natural gas
production increases of 0.5% and 1.0% in 2000 and 2001, respectively.
At September 30, 2000, we had entered into natural gas forward sales for the
physical delivery of natural gas volumes totaling 3.2 Bcf (34.8 MMcf per day) at
an average price, net of transportation, of $4.41 per Mcf for the last quarter
of 2000 and 5.9 Bcf (16.1 MMcf per day) at an average price of $4.64 per Mcf for
2001.
OIL AND NGLS. Oil and natural gas liquids prices averaged $26.92 per barrel for
the first nine months of 2000 compared to $15.62 per barrel in the 1999 period.
Oil prices in the 2000 period benefited from supply constrictions arising from
the Organization of Petroleum Exporting Countries' ("OPEC") adherence to
production quotas and from increased worldwide demand for oil.
REVENUE
PRODUCTION REVENUE. For the first nine months of 2000, a 72% increase in oil
prices was complemented by a 64% increase in natural gas prices. The increased
prices more than offset the production decline with the result that production
revenues for the first nine months of 2000 increased 45% ($28.6 million) to
$92.9 million ($76.4 million after royalties) from the corresponding period in
1999.
<PAGE> 12
Page 12 of 21
<TABLE>
<CAPTION>
NET REVENUE
Nine months ended September 30, 2000 1999
------------------------------- ------- -------
(in thousands)
<C> <C>
Natural gas, after royalties $50,972 $35,922
Oil and ngls, after royalties 25,379 17,032
------- -------
Production revenue, after royalties 76,351 52,954
Interest and other revenue 2,305 570
------- -------
Total net revenue $78,656 $53,524
======= =======
</TABLE>
<TABLE>
<CAPTION>
PRICE/VOLUME VARIANCES Natural gas
------------------------------
Nine months ended September 30, US UK Total Oil and ngls Total
------------------------------- ------- -------- -------- ------------ -------
(in thousands)
<S> <C> <C> <C> <C> <C>
1999 production revenue, after
royalties $33,452 $ 2,470 $35,922 $17,032 $52,954
Price variance 18,119 702 18,821 10,579 29,400
Volume variance (2,549) (1,222) (3,771) (2,232) (6,003)
------- ------- ------- ------- -------
2000 production revenue, after
royalties $49,022 $ 1,950 $50,972 $25,379 $76,351
======= ======= ======= ======= =======
</TABLE>
INTEREST AND OTHER REVENUE. Interest and other revenue for the third quarter of
2000 included a non-recurring $1.3 million revenue item arising from the Libyan
venture which was terminated in the second quarter of 1999. Under the terms of
the concession, the Libyan National Oil Company ("NOC") reimbursed us and our
partners in kind for NOC's share of production test expenditures. The
non-recurring revenue item arose due to the increase in oil prices between the
time when production test expenditures were incurred and when the reimbursement
was effected.
EXPENSES
ROYALTIES. Our composite royalty rate was comparable on a period over period
basis.
Our US Gulf of Mexico properties in federal waters generally carry a fixed
one-sixth (16-2/3%) royalty rate. Some of these offshore properties carry
overriding royalties ranging from 1.1% to 10%. UK production carries no royalty
obligations.
We pay no overriding royalties to management or staff.
<TABLE>
<CAPTION>
ROYALTIES
Nine months ended September 30, 2000 1999
------------------------------- ------- -------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Natural gas $11,673 $ 8,195
Oil and ngls 4,856 3,087
------- -------
Total $16,529 $11,282
======= =======
Royalties per Mcfe $ 0.61 $ 0.36
Composite royalty rate 17.8% 17.6%
</TABLE>
PRODUCTION COSTS. Our aggregate production costs for the first nine months of
2000 decreased 4% compared to the corresponding period in 1999. Per unit
production costs increased as the result of a decrease in the volume of
equivalent production and an increase in production taxes (28% on a per unit
basis), primarily on Utah oil production, the amount of such taxes being
dependent upon prices of natural gas and oil.
<PAGE> 13
Page 13 of 21
<TABLE>
<CAPTION>
PRODUCTION COSTS
Nine months ended September 30, 2000 1999
------------------------------- ------- -------
(in thousands except per unit amounts)
<S> <C> <C>
Lifting costs $ 9,169 $ 9,783
Production taxes 1,361 1,202
------- -------
Production costs $10,530 $10,985
======= =======
Production costs ($ per Mcfe)
Before royalty volumes $ 0.39 $ 0.35
After royalty volumes $ 0.47 $ 0.43
</TABLE>
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
for the first nine months of 2000 in creased 33% from the corresponding period
in 1999. This increase is primarily the result of performance-based compensation
payments which were higher during the first quarter of 2000 than during the
corresponding 1999 period.
<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE
Nine months ended September 30, 2000 1999
------------------------------- ------- -------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Gross general and administrative expenses $ 8,611 $ 6,431
Capitalized expenses (4,134) (3,077)
------- -------
General and administrative expenses $ 4,477 $ 3,354
======= =======
General and administrative expenses ($ per Mcfe)
Before royalty volumes $ 0.16 $ 0.11
After royalty volumes $ 0.20 $ 0.13
Capitalization ratio 48% 48%
</TABLE>
INTEREST EXPENSE. Our interest expense for the first nine months of 2000
decreased compared to the corresponding 1999 period due to reduced credit
facility utilization. Our weighted average debt outstanding for the nine months
ended September 30, 2000 was $13.6 million compared to $43.3 million for the
corresponding period in 1999. The effective interest rate on our outstanding
debt for the nine months ended September 30, 2000 was 7.25% compared to 5.76%
for the corresponding period in 1999. The weighted average interest rate on our
debt at September 30, 2000 was 7.38%.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the first
nine months of 2000 decreased 17% from the corresponding period in 1999 as a
result of a 13% decrease in our production and a 4% decrease in our average
depletion rate to $1.20 per Mcfe ($1.45 per Mcfe after royalties). Our depletion
rate decreased for a number of reasons:
o drilling success which contributed to our 1999 finding and development cost
for proved reserves of $0.68 per Mcfe ($0.84 per Mcfe after royalties);
o the recovery in oil prices which resulted in upward revisions in our proved
reserves at December 31, 1999 compared to December 31, 1998; and
o the ceiling test write-down of the UK properties that occurred at December
31, 1999 due to low spot market prices for natural gas as at that date.
In Libya, we and our partners concluded that the multi-year exploration program,
and the production test which commenced in December 1997, were not commercial
under the terms of the concession and therefore terminated the venture. As a
result, additional depletion of $11.4 million was recorded in the second quarter
of 1999 to eliminate the investment.
NET INCOME (LOSS) APPLICABLE TO COMMON SHARES
After provision of $3.7 million for dividends on preferred shares of a
subsidiary in both periods, net income (loss) applicable to common shares for
the first nine months of 2000 was $15.0 million, an improvement of $26.0 million
compared to the year earlier period. The most significant factors responsible
for the improvement were the improvement in natural gas and oil prices in the
current year and the non-recurring nature of the 1999 write-off of the Libyan
investment.
<PAGE> 14
Page 14 of 21
<TABLE>
<CAPTION>
NETBACK ANALYSIS ($ per Mcfe) Before royalties After royalties
---------------- ----------------
Nine months ended September 30, 2000 1999 2000 1999
------------------------------- ------ ------ ------ ------
<S> <C> <C> <C> <C>
Gross production revenue $ 3.45 $ 2.07
Royalties (0.61) (0.36)
------ ------
Production revenue, after royalties 2.84 1.71 $ 3.44 $ 2.07
Production costs (0.39) (0.35) (0.47) (0.43)
------ ------ ------ ------
Gross margin 2.45 1.36 2.97 1.64
General and administrative expenses (0.16) (0.11) (0.20) (0.13)
------ ------ ------ ------
Gross profit 2.29 1.25 2.77 1.51
Interest and other 0.04 (0.05) 0.06 (0.06)
Preferred share dividends (0.14) (0.12) (0.17) (0.14)
------ ------ ------ ------
Cash flow from operations $ 2.19 $ 1.08 $ 2.66 $ 1.31
====== ====== ====== ======
Total production volume (Bcfe) 27.0 31.0 22.2 25.6
====== ====== ====== ======
</TABLE>
THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO THREE MONTHS ENDED
SEPTEMBER 30, 1999
Strong natural gas and oil prices contributed to the achievement of record
revenues of $33.0 million, net income applicable to common shares of $8.9
million and cash flow from operations of $26.5 million.
PRODUCTION
On an energy equivalent basis, our average production rate decreased 14% to
101.3 MMcfe per day (82.8 MMcfe per day after royalties) for the third quarter
of 2000 from 118.4 MMcfe per day (98.3 MMcfe per day after royalties) for the
corresponding period in 1999. Natural gas comprised 77% (76% after royalties) of
our production for the third quarter of 2000 and 74% (73% after royalties) of
our production for the corresponding period in 1999. As compared to the
corresponding period in 1999, our third quarter 2000 US natural gas production
increased 1% to 7.1 Bcf (5.7 Bcf after royalties). For the third quarter of
2000, our composite natural gas production decreased 11% to 7.1 Bcf (5.8 Bcf
after royalties) compared to 8.0 Bcf (6.6 Bcf after royalties) for the
corresponding period in 1999. Oil and natural gas liquids production for the
quarter decreased 24% to 365 MBbls (308 MBbls after royalties) compared to 478
MBbls (404 MBbls after royalties) for the 1999 third quarter.
During the third quarter of 2000, our UK natural gas volumes were lower than in
the comparative 1999 period as we were able to sell our allowable annual volume
earlier than in the preceding UK natural gas year. The significance of this on
the quarterly production revenues is shown in the Price/Volume Variances table
on the following page. Effective October 1, when the 2001 UK natural gas year
commenced, our sales volumes resumed at approximately 6.0 MMcf per day. Of the
113 MBbls (96 MBbls) decrease in oil and natural gas liquids production, 70% (79
MBbls (66 MBbls after royalties)) is attributable to production declines at
South Marsh Island 39.
Ninety-nine percent of our natural gas production for the third quarter of 2000
came from our interests in the US Gulf of Mexico region compared to 87% in the
corresponding period in 1999. Our interests in this region accounted for 56% of
our oil and ngls production compared to 60% in the corresponding 1999 period.
Substantially all of the remainder of our oil and ngls production is from our
interests in the Aneth and Ratherford Units in southeast Utah.
<TABLE>
<CAPTION>
PRODUCTION SUMMARY Before royalties After royalties
---------------- ---------------
Three months ended September 30, 2000 1999 2000 1999
-------------------------------- ----- ----- ----- -----
<S> <C> <C> <C> <C>
Natural gas (MMcf per day)
US 77.2 76.7 62.4 61.4
UK 0.3 10.5 0.3 10.5
----- ----- ----- -----
Total 77.5 87.2 62.7 71.9
===== ===== ===== =====
Oil and ngls (barrels per day) 3,964 5,200 3,351 4,394
===== ===== ===== =====
Total natural gas equivalent (MMcfe per day) 101.3 118.4 82.8 98.3
===== ===== ===== =====
Total period equivalent (Bcfe) 9.3 10.9 7.6 9.0
===== ===== ===== =====
</TABLE>
<PAGE> 15
Page 15 of 21
NATURAL GAS AND OIL MARKETING
NATURAL GAS. Natural gas prices averaged $3.83 per Mcf for the third quarter of
2000 compared to $2.26 per Mcf for the corresponding period in 1999. For the
third quarter of 2000, we received average natural gas prices of $3.84 per Mcf
in the US and $1.92 per Mcf in the UK compared to $2.46 and $0.81, respectively,
for the corresponding period in 1999.
OIL AND NGLS. Oil and natural gas liquids prices averaged $30.53 per barrel for
the third quarter of 2000 compared to $19.31 per barrel for the corresponding
period in 1999.
REVENUE
PRODUCTION REVENUE. For the third quarter of 2000, a 58% increase in oil prices
was complemented by a 69% increase in natural gas prices. The increase in prices
more than offset the production decline with the result that production revenues
for the third quarter of 2000 increased 40% ($11.1 million) to $38.5 million
($31.5 million after royalties) from the corresponding period in 1999.
<TABLE>
<CAPTION>
NET REVENUE
Three months ended September 30, 2000 1999
-------------------------------- ------- -------
(in thousands)
<S> <C> <C>
Natural gas, after royalties $22,131 $14,960
Oil and ngls, after royalties 9,324 7,609
------- -------
Production revenue, after royalties 31,455 22,569
Interest and other revenue 1,541 194
------- -------
Total net revenue $32,996 $22,763
======= =======
</TABLE>
<TABLE>
<CAPTION>
PRICE/VOLUME VARIANCES Natural gas
--------------------------
Three months ended September 30, US UK Total Oil and ngls Total
-------------------------------- ------- ----- ------- ------------ -------
(in thousands)
<S> <C> <C> <C> <C> <C>
1999 production revenue, after
royalties $14,177 $ 783 $14,960 $ 7,609 $22,569
Price variance 7,696 29 7,725 3,569 11,294
Volume variance 207 (761) (554) (1,854) (2,408)
------- ----- ------- ------- -------
2000 production revenue, after
royalties $22,080 $ 51 $22,131 $ 9,324 $31,455
======= ===== ======= ======= =======
</TABLE>
INTEREST AND OTHER REVENUE. Interest and other revenue for the third quarter of
2000 included a non-recurring $1.3 million revenue item arising from the Libyan
venture which was terminated in the second quarter of 1999.
EXPENSES
ROYALTIES. Our composite royalty rate, which is largely comparable on a period
over period basis, reflects a lower proportion of UK production, which carries
no royalty obligations, in the current quarter's production mix.
<TABLE>
<CAPTION>
ROYALTIES
Three months ended September 30, 2000 1999
-------------------------------- ------ ------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Natural gas $5,197 $3,373
Oil and ngls 1,813 1,449
------ ------
Total $7,010 $4,822
====== ======
Royalties per Mcfe $ 0.75 $ 0.44
Composite royalty rate 18.2% 17.6%
</TABLE>
PRODUCTION COSTS. Our production costs for the third quarter of 2000 decreased
2% compared to the corresponding period in 1999. The increase in per unit
production costs is the result of a decrease in the volume of equivalent
production.
<PAGE> 16
Page 16 of 21
<TABLE>
<CAPTION>
PRODUCTION COSTS
Three months ended September 30, 2000 1999
-------------------------------- ------ ------
(in thousands except per unit amounts)
<S> <C> <C>
Lifting costs $3,103 $3,167
Production taxes 448 456
------ ------
Production costs $3,551 $3,623
====== ======
Production costs ($ per Mcfe)
Before royalty volumes $ 0.38 $ 0.33
After royalty volumes $ 0.47 $ 0.40
</TABLE>
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses for
the third quarter of 2000 increased $272,000 (28%) from the corresponding period
in 1999. This increase is a composite of a number of items, the most significant
being increased staffing levels and, to a lesser degree, increased insurance
costs and office rent.
<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE
Three months ended September 30, 2000 1999
-------------------------------- ------ ------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Gross general and administrative expenses $ 2,564 $1,868
Capitalized expenses (1,311) (887)
------- ------
General and administrative expenses $ 1,253 $ 981
======= ======
General and administrative expenses ($ per Mcfe)
Before royalty volumes $ 0.13 $ 0.09
After royalty volumes $ 0.16 $ 0.11
Capitalization ratio 51% 47%
</TABLE>
INTEREST EXPENSE. Our interest expense for the third quarter of 2000 decreased
compared to the corresponding 1999 period due to reduced credit facility
utilization. Our weighted average debt outstanding for the three months ended
September 30, 2000 was $18.2 million compared to $45.0 million for the
corresponding period in 1999. The effective interest rate on our outstanding
debt for the quarter ended September 30, 2000 was 7.40% compared to 5.87% for
the corresponding period in 1999.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the third
quarter of 2000 decreased 16% from the corresponding period in 1999 as a result
of a 14% decrease in our production and a 1% decrease in our average depletion
rate to $1.23 per Mcfe ($1.51 per Mcfe after royalties).
NET INCOME (LOSS) APPLICABLE TO COMMON SHARES
After provision of $1.2 million for dividends on preferred shares of a
subsidiary in both periods, net income (loss) applicable to common shares for
the third quarter of 2000 was $8.9 million, an improvement of $7.7 million
compared to the year earlier period. The two most significant factors
responsible for the improvement were the improvement in natural gas and oil
prices in the current year and the non-recurring revenue item arising from the
Libyan venture which was terminated in the second quarter of 1999.
<TABLE>
<CAPTION>
NETBACK ANALYSIS ($ per Mcfe) Before royalties After royalties
---------------- ----------------
Three months ended September 30, 2000 1999 2000 1999
-------------------------------- ------ ------ ------ ------
<S> <C> <C> <C> <C>
Gross production revenue $ 4.13 $ 2.52
Royalties (0.75) (0.44)
------ ------
Production revenue, after royalties 3.38 2.08 $ 4.13 $ 2.50
Production costs (0.38) (0.33) (0.47) (0.40)
------ ------ ------ ------
Gross margin 3.00 1.75 3.66 2.10
General and administrative expenses (0.13) (0.09) (0.16) (0.11)
------ ------ ------ ------
Gross profit 2.87 1.66 3.50 1.99
Interest and other 0.10 (0.06) 0.14 (0.05)
Preferred share dividends (0.13) (0.11) (0.16) (0.14)
------ ------ ------ ------
Cash flow from operations $ 2.84 $ 1.49 $ 3.48 $ 1.80
====== ====== ====== ======
Total production volume (Bcfe) 9.3 10.9 7.6 9.0
====== ====== ====== ======
</TABLE>
<PAGE> 17
Page 17 of 21
CAPITAL EXPENDITURES
Our capital expenditures during the first nine months of 2000 totaled $66.1
million compared to $36.2 million for the corresponding period in 1999.
LEASE AND LAND HOLDINGS. There were two lease sales during the first nine months
of 2000. We participated in high bids for 11 offshore blocks, 5 as operator,
covering 55,700 acres (28,500 net acres) at the Federal US Central Gulf of
Mexico Lease Sale held on March 15, 2000. Our share of the bids on the 11
blocks, all of which have been awarded, was $3.7 million.
We participated in high bids for 3 offshore blocks, none as operator, covering
17,280 acres (5,184 net acres) at the Federal US Western Gulf of Mexico Lease
Sale held on August 23, 2000. Our share of the bids on the 3 blocks was $0.6
million. As of October 17, 2000, 2 of the blocks had been awarded; the remaining
bid was pending.
DRILLING RESULTS. For the first nine months of 2000, our exploratory drilling
success rate in the US Gulf of Mexico region was 47% compared to 83% for the
corresponding period in 1999. Including development wells, our success rate in
the region was 56% for the first nine months of 2000 compared to 88% for the
corresponding period in 1999. Drilling in all areas resulted in success rates of
56% for the first nine months of 2000 and 73% for the first nine months of 1999.
<TABLE>
<CAPTION>
DRILLING RESULTS (WELLS)
Nine months ended September 30, 2000 1999
------------------------------- ------------- -------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
US - Gulf of Mexico region
Successful 10 4.07 8 3.54
Dry 8 2.54 1 0.20
-- ---- -- ----
18 6.61 9 3.74
-- ---- -- ----
Foreign
Dry -- -- 2 0.25
-- ---- -- ----
Total wells drilled
Successful 10 4.07 8 3.54
Dry 8 2.54 3 0.45
-- ---- -- ----
18 6.61 11 3.99
== ==== == ====
Chieftain operated wells 4 2.00 2 1.00
== ==== == ====
</TABLE>
In addition to the wells described above, at September 30, 2000 we had interests
in 5 (2.05 net) wells which were drilling compared to 4 (2.10 net) at September
30, 1999.
Two additional wells were successfully drilled in the nine months ended
September 30, 2000 on our US Gulf of Mexico acreage at no cost to us. For the
nine months ended September 30, 1999, four additional wells were drilled on our
US Gulf of Mexico acreage at no cost to us, one of which resulted in a natural
gas well and three of which were unsuccessful.
CAPITAL FIELD DEVELOPMENT ACTIVITY. Our principal offshore development
activities during the first nine months of 2000 were at High Island A-530,
Matagorda Island 704, South Timbalier 196, Vermilion 267, West Cameron 300 and
West Cameron 613 where production facilities and pipelines were installed.
Onshore, facilities were completed for the Langlinais #1 well in the Northeast
Wright Field.
<PAGE> 18
Page 18 of 21
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES SUMMARY
Nine months ended September 30, 2000 1999
------------------------------- ------- -------
(in thousands)
<S> <C> <C>
Property acquisition costs:
US $ 6,636 $ 2,519
UK 32 28
------- -------
6,668 2,547
------- -------
Sale of producing properties:
US -- (155)
------- -------
Exploration costs:
US 30,996 18,615
UK (2) (6)
Foreign -- 1,531
------- -------
30,994 20,140
------- -------
Development costs:
US 28,391 13,689
UK 2 (6)
------- -------
28,393 13,683
------- -------
$66,055 $36,215
======= =======
</TABLE>
Subsequent to September 30, 2000, we announced that we had entered into an
agreement with Gulfstream Resources Canada Limited and its wholly-owned
subsidiaries (collectively "Gulfstream") giving us the option to purchase 50% of
Gulfstream's petroleum and natural gas interests in the Middle East State of
Qatar.
The option is exercisable for a term of three months, which may be extended for
an additional three months in certain circumstances. It is subject to other
terms and conditions including government and partner approvals.
Gulfstream's interests in Qatar include a 42.5% interest in the 1976 Exploration
and Production Sharing Agreement which in turn includes the Al Rayyan oil
development area and a 27.5% interest in the 1997 Block 11 Exploration and
Production Sharing Agreement.
In addition, we purchased, at a cost of $5 million, 4,852,258 Gulfstream
Resources Canada Limited treasury common shares representing approximately eight
percent of the then issued and outstanding common shares of Gulfstream Resources
Canada Limited. We are not contemplating the purchase of additional shares of
Gulfstream Resources Canada Limited.
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of funds are operations and financing activities. Our
primary cash outflows are for exploration and development activities.
Cash flow from operations, 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 and deferred income taxes. We generated cash flow from operations
of $59.1 million during the first nine months of 2000 compared to $33.6 million
for the corresponding period in 1999. The variance is primarily a function of
increased commodity prices in the first nine months of 2000.
In 1997, a third party sold its interests in producing properties that we
currently operate and since that time neither the vendor nor the purchaser has
reimbursed us on a timely basis for expenditures made by us, as operator, for
their account. Accordingly, we have commenced an action in the Louisiana courts
against both the vendor and the purchaser to recover the amounts currently owing
to us, approximately $4.3 million, plus interest and costs. Although the
purchaser filed for Chapter 11 bankruptcy in the first half of 2000, we
currently expect to recover all current and future amounts outstanding and have
therefore made no allowance for doubtful collectability.
<PAGE> 19
Page 19 of 21
Financing activities during the nine months ended September 30, 2000 provided
$7.8 million of cash, the net result of:
o the drawdown of $10 million of our revolving bank credit facility;
o the purchase for cancellation of 116,200 common shares at a cost of $2.5
million under our share repurchase program announced August 11, 2000; and
o the exercise of employee share options for $0.3 million.
Through September 30, 2000, 116,200 common shares had been purchased and
cancelled pursuant to our current normal course issuer bid, announced August 11,
2000, for up to 1,000,000 common shares.
Financing activities during the corresponding period in 1999 provided $4.9
million of cash, the net result of:
o the drawdown of $5 million of our revolving bank credit facility; and
o the purchase for cancellation of 7,500 common shares at the cost $0.1 million
under a share repurchase program, which expired on November 1, 1999.
Cash used in investing activities increased 82% to $66.1 million for the first
nine months of 2000 from $36.2 million for the corresponding period in 1999.
<TABLE>
<CAPTION>
COMPOSITION OF NATURAL RESOURCE INVESTING ACTIVITIES
Nine months ended September 30, 2000 1999
------------------------------- ------- -------
(in thousands)
<S> <C> <C>
Leasehold and seismic $ 8,982 $ 4,551
Sale of producing properties -- (155)
Exploratory drilling 28,681 18,136
Development drilling 8,830 6,984
Capital field development 19,562 6,699
------- -------
Total $66,055 $36,215
======= =======
</TABLE>
Our September 30, 2000 cash balance of $10.9 million was up $10.3 million from
the balance at September 30, 1999. At September 30, 2000, $20 million was
outstanding on our reduced revolving bank credit facility of $70 million. The
weighted average interest rate for our borrowings during the first nine months
was 7.25%.
OUTLOOK
Four projects are expected to commence production during the fourth quarter of
2000: High Island A-530, Matagorda Island 704, West Cameron 300 and West Cameron
613. Additionally, three projects are currently expected to commence production
during the first half of 2001: Eugene Island 189, High Island A-510/A-531 and
South Timbalier 250. At Eugene Island 189, our partner in the project exchanged
their 25% working interest in the project for a 4% overriding royalty.
Although our average daily production in 2000 will be lower than in 1999, our
September 2000 US production exit rate was 102.2 MMcfe per day (83.3 MMcfe per
day after royalties), 3% higher than our December 1999 US production exit rate
of 99.5 MMcfe per day (81.1 MMcfe per day after royalties). With four new fields
expected to commence production in the last quarter of 2000, our December 2000
production exit rate is expected to be significantly higher than the year prior
rate and should give us a strong start to 2001.
We expect record revenues, net income and cash flow in 2001 based on the current
NYMEX future prices for natural gas and oil (which are higher than what will be
realized in 2000) and our anticipated increase in annual equivalent production
volume. At September 30, 2000, we had entered into natural gas forward contracts
for the physical delivery of natural gas volumes totaling 5.9 Bcf (16.1 MMcf per
day) at an average price, net of transportation, of $4.64 per Mcf for 2001. This
represents approximately 16% of our forecast 2001 US natural gas production and
crystallizes, for us, some of the benefits of these prices.
During the nine months ended September 30, 2000, demand for, and utilization of,
drilling rigs in the US Gulf of Mexico has continued to increase, putting
significant upward pressure on day rates. The Gulf of Mexico Newsletter
<PAGE> 20
Page 20 of 21
reported an 84% utilization rate of the 205 rig fleet at October 2, 2000
compared to a 74% utilization rate of a 187 rig fleet a year earlier. Although
this has resulted in an increase in the cost of drilling wells, we have availed
ourselves of the current opportunities to procure fixed price ("turnkey")
drilling contracts, which effectively limit the costs of drilling and evaluating
a well.
We currently expect that our 2000 capital expenditure program, which will
include the drilling of approximately 33 wells in the US Gulf of Mexico region
will modestly exceed the $86 million amount previously forecasted. Our 2001
capital expenditure budget may include the drilling of approximately 40 wells
and may exceed the 2000 program.
<TABLE>
<CAPTION>
FORECAST DRILLING (wells) All operated Chieftain operated
--------------- ------------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
Forecast 2000 wells
Nine months ended September 30 18 6.61 4 2.00
Fourth quarter 15 5.75 5 2.40
-- ----- -- -----
Total 33 12.36 9 4.40
== ===== == =====
Forecast 2001 wells 40 16.98 20 10.27
== ===== == =====
</TABLE>
We expect to fund these capital expenditures from operating cash flow and our
unsecured revolving bank credit facility. Capital expenditures can vary
significantly as a result of exploration success, availability of equipment and
services and opportunities. As an active explorer of internally generated
natural gas and oil prospects, we are in a strong position to compete in the
current environment.
<PAGE> 21
Page 21 of 21
PART II
ITEM 1. LEGAL PROCEEDINGS
We are, in the ordinary course of business, party to various legal
proceedings. In the opinion of our management, none of these
proceedings, either individually or in the aggregate, is material.
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 2000.
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/ STANLEY A. MILNER
--------------------------------------------
Stanley A. Milner, A.O.E., LL.D.
President and Chief Executive Officer
Principal Executive and Financial Officer
Dated: October 17, 2000
