<PAGE> 1
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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: March 31, 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)
Alberta, Canada None
- ---------------------------------- ----------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) 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)
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.
<TABLE>
<CAPTION>
Title of each class Date Number Outstanding
- ------------------- --------------------------- ------------------
<S> <C> <C>
Common shares April 17, 2000 16,224,059
</TABLE>
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CHIEFTAIN INTERNATIONAL, INC.
MARCH 31, 2000 FORM 10-Q QUARTERLY REPORT
TABLE OF CONTENTS
PART I
Page No.
Item 1. Financial Statements
Consolidated Condensed Balance Sheet -
March 31, 2000 and December 31, 1999 3
Consolidated Condensed Statement of Income (Loss) -
Three months ended March 31, 2000 and 1999 4
Consolidated Condensed Statement of Cash Flows -
Three months ended March 31, 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 9
PART II
Item 1. Legal Proceedings 16
Item 2. Changes in Securities 16
Item 3. Defaults Upon Senior Securities 16
Item 4. Submission of Matters to a Vote of Security Holders 16
Item 5. Other Information 16
Item 6. Exhibits and Reports on Form 8-K 16
Signatures 16
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEET
(Full Cost Method of Accounting)
<TABLE>
<CAPTION>
MARCH 31 December 31,
2000 1999
- --------------------------------------------------------------------------------
(unaudited) (U.S. $ in thousands)
<S> <C> <C>
ASSETS
Current assets:
Cash and short-term deposits $ 7,463 $ 19,368
Accounts receivable 19,549 18,855
Other 649 750
--------- ---------
27,661 38,973
Capital assets - net 286,344 277,149
Deferred income taxes 14,404 14,636
--------- ---------
$ 328,409 $ 330,758
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued $ 18,862 $ 25,369
Long-term debt 10,000 10,000
Abandonment cost accrual 8,847 8,595
Deferred income taxes 17,494 15,693
Shareholders' equity:
Preferred shares of a subsidiary 63,403 63,403
Common shares (Note 2) 237,076 237,076
Contributed surplus 26 26
Deficit (27,299) (29,404)
--------- ---------
273,206 271,101
--------- ---------
$ 328,409 $ 330,758
========= =========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF INCOME (LOSS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2000 1999
- --------------------------------------------------------------------------------------------------------------
(unaudited) (U.S. $ in thousands except number of
shares and per share amounts)
<S> <C> <C>
Production revenue, net of royalties $ 20,774 $ 13,034
Interest and other revenue 450 184
------------ ------------
21,224 13,218
------------ ------------
Production costs 3,360 3,312
General and administrative expenses 1,793 1,329
Interest 178 565
Depletion and amortization 10,517 12,181
------------ ------------
15,848 17,387
------------ ------------
Income (loss) before income taxes and dividends
on preferred shares of a subsidiary 5,376 (4,169)
Income taxes (Note 3) 2,036 (1,544)
------------ ------------
Income (loss) before dividends on preferred shares of a subsidiary 3,340 (2,625)
Dividends on preferred shares of a subsidiary 1,235 1,235
------------ ------------
Net income (loss) applicable to common shares $ 2,105 $ (3,860)
============ ============
Net income (loss) per common share (Note 4)
- Basic $ 0.13 $ (0.29)
============ ============
- Fully diluted $ 0.13 $ (0.29)
============ ============
Weighted average number of common shares outstanding:
- Basic 16,224,059 13,354,174
============ ============
- Fully diluted 17,343,248 13,354,174
============ ============
</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>
THREE MONTHS ENDED MARCH 31, 2000 1999
- ------------------------------------------------------------------------------------------------
(unaudited) (U.S. $ in thousands)
<S> <C> <C>
Operating activities:
Net income (loss) applicable to common shares $ 2,105 $ (3,860)
Items not requiring a current cash outlay 12,550 10,627
-------- --------
14,655 6,767
Net change in non-cash operating working capital (Note 5) (3,188) 1,239
-------- --------
11,467 8,006
-------- --------
Financing activity:
Purchase of common shares for cancellation -- (80)
-------- --------
Investing activities:
Lease acquisition, exploration and drilling costs (14,324) (9,414)
Pipelines and production equipment acquired (5,112) (971)
-------- --------
(19,436) (10,385)
Purchase of other capital assets (24) (4)
Change in investing accounts payable and accrued (3,912) (5,204)
-------- --------
(23,372) (15,593)
-------- --------
Change in cash and short-term deposits (11,905) (7,667)
Beginning cash and short-term deposits 19,368 10,613
-------- --------
Ending cash and short-term deposits $ 7,463 $ 2,946
======== ========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 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 March 31, 2000 and December 31,
1999 and the results of operations and cash flows for the three month
periods ended March 31, 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 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 three month period
ended March 31, 2000 are not necessarily indicative of the results to
be expected for the full year.
Material differences between Canadian and U.S. accounting principles
that affect Chieftain are referred to in Note 6, which provides the
effects of such differences on earnings and balance sheet accounts.
2. Common Shares:
(a) Common shares outstanding
At March 31, 2000, 16,224,059 (December 31, 1999 - 16,224,059)
common shares of the Company were issued and outstanding.
(b) Common shares reserved
At March 31, 2000, 1,130,207 (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 March 31,
2000, the Company had reserved 3,408,375 (December 31, 1999 -
3,408,375) common shares 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 U.S.. 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.
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3. 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>
Three months ended March 31, 2000 1999
-------------------------------------------------------------------------------------------
<S> <C> <C>
Tax at statutory Canadian rate of 44.62% $ 2,399 $(1,860)
Lower income tax rate on earnings of U.S. subsidiaries (463) 325
Other 100 (9)
------- -------
Tax at effective rate $ 2,036 $(1,544)
======= =======
Effective tax rate 37.9% 37.0%
======= =======
</TABLE>
4. 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.
5. Supplemental Cash Flow Information:
Cash outflows for (inflows from) income taxes during the first quarter
of 2000 were $(1,000) (1999 first quarter - $10,000). Cash outflows for
long-term debt interest during the first quarter of 2000 were $177,000
(1999 first quarter - $567,000).
6. United States Accounting Principles:
(a) Full cost accounting
U.S. full cost accounting rules differ materially from the
Canadian full cost accounting guidelines followed by Chieftain.
The U.S. 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,
U.S. 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 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 $4.0 million.
<PAGE> 8
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(b) Effect on earnings
The effect on consolidated earnings of these differences is
summarized as follows:
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2000 1999
--------------------------------------------------------------------------------------------------------
(U.S.$ in thousands except number of
shares and per share amounts)
<S> <C> <C>
Net income (loss) applicable to common shares, as reported $ 2,105 $ (3,860)
Additional depletion difference -- (7,104)
------------ ------------
2,105 (10,964)
Reduction in depletion expense 2,648 3,697
Decrease (increase) in deferred tax provision (962) 1,831
------------ ------------
Net income (loss) applicable to common shares
under U.S. accounting principles $ 3,791 $ (5,436)
============ ============
Net income (loss) per common share under U.S.
accounting principles:
- Basic $ 0.23 $ (0.41)
============ ============
- Fully diluted $ 0.23 $ (0.41)
============ ============
Fully diluted number of common shares outstanding 16,421,203 13,354,174
============ ============
</TABLE>
(c) Effect on balance sheet
The effect on the Consolidated Condensed Balance Sheet of the
differences between Canadian and U.S. accounting principles is
as follows:
<TABLE>
<CAPTION>
As at MARCH 31, 2000 December 31, 1999
-----------------------------------------------------------------------------------------------------
(U.S.$ in thousands) Under U.S. Under U.S.
Accounting Accounting
As reported Principles As reported Principles
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Net capital assets $ 286,344 $ 201,344 $ 277,149 $ 189,501
Deferred tax - asset $ 14,404 $ 27,243 $ 14,636 $ 30,238
Deferred tax - liability $ 17,494 $ -- $ 15,693 $ --
Deficit $ (27,299) $ (81,966) $ (29,404) $ (85,757)
</TABLE>
For U.S. 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. U.S. 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 three months ended March 31, 2000 such impact
would amount to a net of tax charge to income (loss) of $350,000
(1999 - $261,000). Under U.S. accounting principles after
reflecting this charge, for the three months ended March 31, pro
forma net income (loss) applicable to common shares would be
$3,441,000 (1999 - ($5,697,000)); net income (loss) per common
share would be $0.21 (1999 - $(0.43)); and pro forma fully diluted
earnings (loss) per common share would be $0.21 (1999 - $(0.43)).
These effects are not necessarily indicative of those to be
expected in future periods.
<PAGE> 9
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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. 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 U.S. 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 U.S. dollars. For a discussion of the
effect of differences in generally accepted accounting principles in Canada and
the U.S. on our financial statements, see Note 12 to our 1999 consolidated
financial statements and Note 6 to our accompanying unaudited consolidated
condensed financial statements.
FIRST THREE MONTHS 2000 COMPARED TO FIRST THREE MONTHS 1999
PRODUCTION
On an energy equivalent basis our average daily production decreased 9% to 99.5
mmcfe per day (82.4 mmcfe per day after royalties) for the first three months of
2000 from 109.2 mmcfe per day (90.1 mmcfe per day after royalties) for the
corresponding period in 1999. Natural gas comprised 75% (before and after
royalties) of our production for the first three months of 2000 and 80% (79%
after royalties) of our production for the corresponding period in 1999. For the
first three months of 2000, our natural gas production decreased 13% to 6.8 bcf
(5.6 bcf after royalties) compared to 7.8 bcf (6.4 bcf after royalties) for the
corresponding period in 1999. For the first three months of 2000, our oil and
natural gas liquids production increased 14% to 378 mbbls (318 mbbls after
royalties) compared to 331 mbbls (284 mbbls after royalties) for the
corresponding period in 1999.
Eighty-eight per cent of our natural gas production for the first three months
of 2000 came from our interests in the U.S. Gulf of Mexico region compared to
87% in the corresponding period in 1999. Our interests in this region accounted
for 46% of our oil and ngls production compared to 37% in the corresponding
period in 1999.
Main Pass 225 D and Main Pass 250 B, which had no production during the first
quarter of 1999, contributed 243 mmcf (203 mmcf after royalties) and 233 mmcf
(194 mmcf after royalties), respectively, to natural gas production during the
first quarter of 2000, but, as a whole, natural gas production in the Main Pass
area decreased 490 mmcf (332 mmcf after royalties), due to normal production
declines, to 1,290 mmcf (999 mmcf after royalties). Increased natural gas
production volumes also came from various areas including Northeast Wright,
which increased 169 mmcf (125 mmcf after royalties) to 242 mmcf (179 mmcf after
royalties); South Marsh Island 39, which increased 306 mmcf (255 mmcf after
royalties) to 312 mmcf (260 mmcf after royalties); and East Cameron 34, which
increased 123 mmcf (102 mmcf after royalties) to 294 mmcf (245 mmcf after
royalties). However, in total, increases in natural gas volumes were more than
offset by normal production declines. Nine projects are expected to commence
production during the remainder of 2000: South Timbalier 196, Vermilion 267
and the onshore Chacahoula well during the second quarter; and High Island
A-510/A-531, High Island A-530, West Cameron 613, West Cameron 300, Matagorda
Island 704 and Eugene Island 189 in the second half of the year.
- --------------------------------------------------------------------------------
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, "BOE" means
barrel of oil equivalent using a ratio of 6,000 cubic feet of natural gas = 1
barrel,"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> 10
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Comparing the first quarters of 2000 and 1999, the single most significant
factor affecting increased production volumes of oil and ngls was a full
quarter's production from South Marsh Island 39 which increased 75 mbbls (62
mbbls after royalties) to 83 mbbls (69 mbbls after royalties).
<TABLE>
<CAPTION>
PRODUCTION SUMMARY Before royalties After royalties
----------------------------- --------------------------
Three months ended March 31, 2000 1999 2000 1999
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Natural gas (mmcf per day)
U.S 66.1 76.1 52.9 60.1
U.K 8.5 11.0 8.5 11.0
---------------------------------------------------------
Total 74.6 87.1 61.4 71.1
=========================================================
Oil and ngls (barrels per day) 4,154 3,679 3,494 3,156
=========================================================
Total natural gas equivalent (mmcfe per day) 99.5 109.2 82.4 90.1
=========================================================
Total period equivalent (bcfe) 9.1 9.8 7.5 8.1
=========================================================
</TABLE>
NATURAL GAS AND OIL MARKETING
Natural gas. Natural gas prices averaged $2.38 per mcf for the first three
months of 2000 compared to $1.54 per mcf for the corresponding period in 1999,
reflecting U.S. supply/demand imbalances. The U.S. Energy Information Agency
("EIA") reported that 1999 natural gas demand increased by about one per cent
while production was essentially unchanged. The EIA has indicated that it
expects 2000 demand for natural gas to increase almost five per cent and
production to increase about one per cent. For the first quarter of 2000, we
received average natural gas prices of $2.51 per mcf in the U.S. and $1.35 per
mcf in the U.K. compared to $1.60 and $1.13, respectively, for the corresponding
period in 1999.
Oil and ngls. Oil and natural gas liquids prices averaged $24.06 per barrel for
the first three months of 2000 compared to $10.94 per barrel for the
corresponding period in 1999. Oil prices in the 2000 first quarter benefited
from the Organization of Petroleum Exporting Countries' ("OPEC") adherence to
production quotas whereas oil prices in the comparative quarter suffered from
aggressive international competition for market share.
At March 31, 2000, we had entered into natural gas forward contracts through
Highland Energy, an independent aggregator for several U.S. natural gas
producers. The forward contracts, all of which are for 2000 production, are for
the physical delivery of natural gas volumes totaling 5.9 bcf at an average
price, net of transportation, of $2.67 per mcf.
REVENUE
For the first three months of 2000, our combined daily natural gas and oil
production volumes decreased 9% from the corresponding period in 1999. A 120%
recovery in oil prices was complemented by a 55% increase in natural gas prices.
The increase in prices more than offset the production decline with the result
that production revenues for the first three months of 2000 increased 60% ($9.5
million) to $25.2 million ($20.8 million after royalties) from the corresponding
period in 1999.
<PAGE> 11
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<TABLE>
<CAPTION>
NET REVENUE
Three months ended March 31, 2000 1999
- -------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Natural gas, after royalties $13,119 $ 9,801
Oil and ngls, after royalties 7,655 3,233
----------------------------
Production revenue, after royalties 20,774 13,034
Interest and other revenue 450 184
----------------------------
Total net revenue $21,224 $13,218
============================
</TABLE>
<TABLE>
<CAPTION>
PRICE/VOLUME VARIANCES Natural gas
----------------------------------------
Three months ended March 31, U.S. U.K. Total Oil and ngls Total
- -----------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1999 production revenue, after royalties $ 8,683 $ 1,118 $ 9,801 $ 3,233 $ 13,034
Price variance 4,351 171 4,522 4,050 8,572
Volume variance (962) (242) (1,204) 372 (832)
--------------------------------------------------------------------
2000 production revenue, after royalties $ 12,072 $ 1,047 $ 13,119 $ 7,655 $ 20,774
====================================================================
</TABLE>
EXPENSES
Royalties. As expected, our composite royalty rate increased on a period over
period basis due to the lower proportion of U.K. production, which carries no
royalty obligations.
Our U.S. Gulf of Mexico properties in federal waters generally carry a one-sixth
(16-2/3%) royalty rate. Some of these offshore properties carry overriding
royalties ranging from 1.1% to 10%. Reflecting the varying contributions of our
producing properties, our effective overriding royalty rate for the first three
months of 2000 was 2.2% compared to 2.5% in the corresponding period in 1999.
We pay no overriding royalties to management or staff.
<TABLE>
<CAPTION>
ROYALTIES
Three months ended March 31, 2000 1999
- ---------------------------------------------------------------
(in thousands except per unit
amounts and percentages)
<S> <C> <C>
Natural gas $3,052 $2,172
Oil and ngls 1,401 518
------------------------------
Total $4,453 $2,690
==============================
Royalties ($ per mcfe) $ 0.49 $ 0.27
Composite royalty rate 17.7% 17.1%
</TABLE>
Production costs. Our production costs for the first three months of 2000 were
largely comparable to the corresponding period in 1999.
Production costs were $0.25 per mcfe ($0.31 per mcfe after royalties) for U.S.
Gulf of Mexico region properties for the first three months of 2000, essentially
unchanged from $0.25 per mcfe ($0.32 per mcfe after royalties) in the
corresponding period in 1999. Production costs for the Aneth and Ratherford
Units, where secondary and tertiary recovery methods are being used, were $8.16
per boe ($9.36 per boe after royalties) for the first three months of 2000
compared to $5.88 per boe ($6.72 per boe after royalties) in the corresponding
period in 1999. This variance in per unit production costs is the composite
result of a 7% decrease in the volume of equivalent production and a 16%
increase in production taxes, the amount of such taxes being dependent upon the
price of oil.
<PAGE> 12
Page 12 of 16
<TABLE>
<CAPTION>
PRODUCTION COSTS
Three months ended March 31, 2000 1999
- ------------------------------------------------------------------
(in thousands except per
unit amounts)
<S> <C> <C>
Lifting costs $2,917 $2,946
Production taxes 443 366
--------------------------
Production costs $3,360 $3,312
==========================
Production costs ($ per mcfe)
Before royalty volumes $ 0.37 $ 0.34
After royalty volumes $ 0.45 $ 0.41
</TABLE>
General and administrative expenses. Our general and administrative expenses for
the first three months of 2000 increased 35% from the corresponding period in
1999. This increase reflects higher performance-based compensation payments made
during the first quarter of 2000 than during the corresponding period in 1999.
<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE
Three months ended March 31, 2000 1999
- -----------------------------------------------------------------------------------------
(in thousands except per unit
amounts and percentages)
<S> <C> <C>
Gross general and administrative expenses $ 3,553 $ 2,565
Capitalized expenses (1,760) (1,236)
------------------------------
General and administrative expenses $ 1,793 $ 1,329
==============================
General and administrative expenses ($ per mcfe)
Before royalty volumes $ 0.20 $ 0.14
After royalty volumes $ 0.24 $ 0.16
Capitalization ratio 50% 48%
</TABLE>
Interest expense. Our interest expense for the first three months 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 March 31, 2000 was $10.0 million compared to $40.0 million for the
corresponding period in 1999. The effective interest rate on our outstanding
debt for the three months ended March 31, 2000 was 7.00% compared to 5.59% for
the corresponding period in 1999. The weighted average interest rate on our debt
at March 31, 2000 was 7.00%.
Depletion and amortization. Our depletion and amortization expense for the first
three months of 2000 decreased 14% from the corresponding period in 1999 as a
result of an 8% decrease in our production and a 7% decrease in our average
depletion rate to $1.16 per mcfe ($1.40 per mcfe after royalties). Our depletion
rate decreased for a number of reasons:
o our 1999 proved reserve finding and development costs of $0.68 per mcfe
($0.84 per mcfe after royalties) compared to $1.54 per mcfe ($2.04 per mcfe
after royalties) in 1998;
o the recovery in oil prices which resulted in upward revisions in our proved
reserves at December 31, 1999 compared to December 31, 1998; and
o the significant ceiling test write-down of the U.K. properties that
occurred at December 31, 1999 due to very low spot market prices for
natural gas as at that date.
<PAGE> 13
Page 13 of 16
NETBACK
<TABLE>
<CAPTION>
NETBACK ANALYSIS ($ per mcfe) Before royalties After royalties
-------------------------- ------------------------
Three months ended March 31, 2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Gross production revenue $ 2.78 $ 1.60
Royalties (0.49) (0.27)
-------------------------
Production revenue, after royalties 2.29 1.33 $ 2.77 $ 1.61
Production costs (0.37) (0.34) (0.45) (0.41)
----------------------------------------------------
Gross margin 1.92 0.99 2.32 1.20
General and administrative expenses (0.20) (0.14) (0.24) (0.16)
----------------------------------------------------
Gross profit 1.72 0.85 2.08 1.04
Interest and other 0.04 (0.03) 0.03 (0.06)
Preferred share dividends (0.14) (0.13) (0.16) (0.15)
----------------------------------------------------
Cash flow from operations $ 1.62 $ 0.69 $ 1.95 $ 0.83
====================================================
Period production volume (bcfe) 9.1 9.8 7.5 8.1
====================================================
</TABLE>
CAPITAL EXPENDITURES
Our capital expenditures during the first three months of 2000 totaled $19.5
million compared to $10.4 million for the corresponding period in 1999.
Lease and land holdings. During the first three months of 2000, we participated
in high bids for 11 offshore blocks, 5 as operator, covering 55,700 (28,500 net)
acres at the Federal U.S. Central Gulf of Mexico Lease Sale held on March 15,
2000. Our share of the bids on the 11 blocks was $3.7 million. As of April 17,
2000, five of the blocks had been awarded; the remaining bids were pending.
Drilling results. For the first three months of 2000, our exploratory drilling
success rate in the U.S. Gulf of Mexico region was 60% compared to 100% for the
corresponding period in 1999. Including development wells, our success rate in
the region was 100% for the first three months of 1999; no development wells
were drilled in the region in the corresponding period in 2000. Drilling in all
areas resulted in success rates of 60% for the first three months of 2000 and
75% for the first three months of 1999.
<TABLE>
<CAPTION>
DRILLING RESULTS (WELLS)
2000 1999
-------------------------------- ------------------------------
Three months ended March 31, GROSS NET Gross Net
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
U.S. - Gulf of Mexico region
Successful 3 1.10 3 1.50
Dry 2 0.65 -- --
-----------------------------------------------------------------
5 1.75 3 1.50
-----------------------------------------------------------------
Foreign
Dry -- -- 1 0.13
-----------------------------------------------------------------
Total wells drilled
Successful 3 1.10 3 1.50
Dry 2 0.65 1 0.13
-----------------------------------------------------------------
5 1.75 4 1.63
=================================================================
Chieftain operated wells 2 0.70 -- --
=================================================================
</TABLE>
In addition to the wells described above, at March 31, 2000 we had interests in
6 (1.71 net) wells which were drilling compared to 3 (0.37 net) at March 31,
1999.
In addition, one unsuccessful well was drilled in the three months ended March
31, 1999 on our U.S. Gulf of Mexico acreage at no cost to us. There was no
corresponding activity in the 2000 period.
<PAGE> 14
Page 14 of 16
Capital field development activity. Our principal development activity during
the first quarter of 2000 centred on Vermilion 267 where the platform jacket was
loaded out and installed and the platform topsides (containing the production
facilities) were completed.
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES SUMMARY
Three months ended March 31, 2000 1999
- ----------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Property acquisition costs:
U.S $ 1,435 $ 335
U.K 22 28
------------------------------------
1,457 363
------------------------------------
Exploration costs:
U.S 10,295 4,825
U.K (7) (9)
Foreign -- 518
------------------------------------
10,288 5,334
------------------------------------
Development costs:
U.S 7,689 4,701
U.K 2 (13)
------------------------------------
7,691 4,688
------------------------------------
$ 19,436 $ 10,385
====================================
</TABLE>
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of cash are funds generated from operations and from
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 and deferred income taxes. We generated discretionary cash flow of
$14.7 million during the first three months of 2000 compared to $6.8 million for
the corresponding period in 1999. The variance is primarily a function of
increased commodity prices in the first quarter of 2000.
We engaged in no financing activities in the first three months of 2000.
Financing activity during the corresponding period in 1999 used $0.1 million of
cash, the result of the purchase for cancellation of 7,500 common shares under a
share repurchase program which expired on November 1, 1999.
Cash used in investing activities increased 87% to $19.4 million for the first
three months of 2000 from $10.4 million for the corresponding period in 1999.
<TABLE>
<CAPTION>
COMPOSITION OF NATURAL RESOURCE INVESTING ACTIVITIES
Three months ended March 31, 2000 1999
- -------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Leasehold and seismic $ 2,310 $ 1,375
Exploratory drilling 9,435 4,322
Development drilling 2,202 3,603
Capital field development 5,489 1,085
----------------------------------
Total $19,436 $10,385
==================================
</TABLE>
Our March 31, 2000 cash balance of $7.5 million was up $4.5 million from the
balance at March 31, 1999. We had outstanding borrowings of $10 million on our
$100 million revolving credit facility at March 31, 2000. The weighted average
interest rate for our borrowings during the first three months was 7.00%.
<PAGE> 15
Page 15 of 16
OUTLOOK
Our 2000 annual production target remains unchanged at a 5 to 10% increase over
1999 levels. During the second quarter of 2000, production is expected to
commence onshore Louisiana at Chacahoula and offshore at South Timbalier 196 and
Vermilion 267. In addition to second-half 2000 production contributions from
1999 discoveries at High Island A-510/A-531, High Island A-530 and West Cameron
613, current year production is expected from 2000 discoveries at Matagorda
Island 704 and West Cameron 300 and a prior year's discovery at Eugene Island
189.
We continue to expect that our 2000 capital expenditure program will be
approximately $86 million and will include the drilling of approximately 27
wells in the U.S. Gulf of Mexico region. We expect to fund these expenditures
from operating cash flow and our unsecured revolving 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. With natural gas prices
approaching historical highs, we will continue to focus on natural gas
development and production in the U.S. Gulf of Mexico region.
<PAGE> 16
Page 16 of 16
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 first 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: April 17, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE MARCH
31, 2000 BALANCE SHEET AND THE STATEMENT OF INCOME (LOSS) FOR THE THREE MONTHS
ENDED MARCH 31, 2000 INCLUDED IN THE COMPANY'S MARCH 31, 2000 10-Q AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<CASH> 7,463
<SECURITIES> 0
<RECEIVABLES> 19,549
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 27,661
<PP&E> 629,002<F1>
<DEPRECIATION> 342,658
<TOTAL-ASSETS> 328,409<F2>
<CURRENT-LIABILITIES> 18,862
<BONDS> 10,000<F3>
0
0
<COMMON> 237,076
<OTHER-SE> 36,200<F4>
<TOTAL-LIABILITY-AND-EQUITY> 328,409<F5>
<SALES> 20,774
<TOTAL-REVENUES> 21,224
<CGS> 0
<TOTAL-COSTS> 15,670<F6>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 178
<INCOME-PRETAX> 5,376
<INCOME-TAX> 2,036
<INCOME-CONTINUING> 3,340
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,340
<EPS-BASIC> 0.13
<EPS-DILUTED> 0.13
<FN>
<F1>THE COMPANY ACCOUNTS FOR GAS AND OIL PROPERTIES IN ACCORDANCE WITH CANADIAN
GUIDELINES ON FULL COST ACCOUNTING.
<F2>DEFERRED INCOME TAXES OF $14,404 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 $(27,229),
HAVE BEEN COMBINED IN CALCULATING OTHER STOCKHOLDERS' EQUITY.
<F5>ABANDONMENT COST ACCRUAL OF $8,847 AND DEFERRED INCOME TAXES OF $17,494 HAVE
BEEN INCLUDED IN TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.
<F6>PRODUCTION COSTS OF $3,360, GENERAL AND ADMINISTRATIVE EXPENSES OF $1,793, AND
DEPLETION AND AMORTIZATION OF $10,517, HAVE BEEN COMBINED IN CALCULATING TOTAL
COSTS.
</FN>
</TABLE>
