10-Q 1 o05580e10-q.txt FORM 10-Q 1 Page 1 of 15 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, 2001 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 (I.R.S. Employer of 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. Title of each class Date Number Outstanding ------------------- -------------- ------------------ Common shares April 30, 2001 16,034,477 2 Page 2 of 15 CHIEFTAIN INTERNATIONAL, INC. MARCH 31, 2001 FORM 10-Q QUARTERLY REPORT TABLE OF CONTENTS PART I

3 Page 3 of 15 CONSOLIDATED BALANCE SHEET CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

See accompanying notes to consolidated financial statements. 4 Page 4 of 15 CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS (DEFICIT) CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

See accompanying notes to consolidated financial statements. 5 Page 5 of 15 CONSOLIDATED STATEMENT OF CASH FLOWS CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

See accompanying notes to consolidated financial statements. 6 Page 6 of 15 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES* March 31, 2001 and 2000 (unaudited) 1. BASIS OF PRESENTATION: In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as at March 31, 2001 and December 31, 2000 and the results of operations for the three month periods ended March 31, 2001 and 2000 and cash flows for the three month periods ended March 31, 2001 and 2000. Certain information and notes normally included in our annual financial statements prepared in conformity with Canadian generally accepted accounting principles have been condensed or omitted for interim reporting. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2000. 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, 2001 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 6, which describes the effects of such differences on earnings and balance sheet accounts. 2. COMMON SHARES: (a) COMMON SHARES RESERVED At March 31, 2001, 1,355,382 (December 31, 2000 - 1,394,632) of the authorized but unissued common shares of the Company were reserved for issuance under the Share Option Plan. At March 31, 2001, 3,408,375 (December 31, 2000 - 3,408,375) common shares were reserved for issuance pursuant to the conversion provisions of the preferred shares of a subsidiary. See Note 2(b). (b) 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 $25.2014 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. -------- * Unless the context indicates another meaning, the terms "we", "us" and "our" refer to Chieftain International, Inc., a company organized under the laws of the Province of Alberta, Canada, and its subsidiaries. 7 Page 7 of 15 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 before dividends paid on preferred shares of a subsidiary as a result of the following:

4. PER SHARE AMOUNTS: Basic net income per common share is calculated by dividing net income applicable to common shares by the weighted average number of common shares outstanding during the period. Diluted income per common share is calculated to give effect to share options and shares issuable on conversion of preferred shares.

5. SUPPLEMENTAL CASH FLOW INFORMATION: Net cash inflows from income taxes during the three months ended March 31, 2001 were $NIL (2000 -- $1,000). Cash outflows for interest on long-term debt during the three months ended March 31, 2001 were $326,000 (2000 -- $177,000). 6. UNITED STATES ACCOUNTING PRINCIPLES: (a) FULL COST ACCOUNTING US full cost accounting rules differ materially from the Canadian full cost accounting guidelines we follow. In determining the limitation on carrying values, US rules require the discounting of future net revenues at 10%, and Canadian guidelines require the use of undiscounted future net revenues and the deduction of estimated future administrative and financing costs. 8 Page 8 of 15 (b) EFFECT ON EARNINGS The effect on consolidated earnings of the differences between Canadian and US accounting principles is summarized as follows:

(c) EFFECT ON BALANCE SHEET The effect on the Consolidated Balance Sheet of the differences between Canadian and US accounting principles is as follows:

Additionally, for US reporting purposes, the preferred shares shown as shareholders' equity in these consolidated financial statements would be shown outside the equity section. (d) STOCK-BASED COMPENSATION We apply the intrinsic value method prescribed by APB Opinion 25 and related interpretations in accounting for share option transactions. Accordingly, no compensation costs have been recognized in the accounts. US accounting principles require disclosure of the impact on earnings and earnings per share of the value of options granted after 1994, calculated in accordance with FAS 123. Such impact would approximate the following pro forma amounts:

9 Page 9 of 15 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 2000 consolidated financial statements and Note 6 to our accompanying unaudited consolidated financial statements. OVERVIEW Production in the first quarter of 2001 averaged a record 127.0 mmcfe per day (104.1 mmcfe per day after royalties), a 19% increase from the fourth quarter of 2000 and a 28% increase from the first quarter of 2000. Strong natural gas and oil prices contributed to our record first three months revenues of $64.5 million ($52.4 million after royalties), net income applicable to common shares of $17.9 million and cash flow from operations of $45.5 million. Capital expenditures during the quarter were $39.2 million, of which $9.6 million was for capital field development. We participated in high bids for 17 offshore blocks, 12 as operator, at the Federal US Central Gulf of Mexico Lease Sale held on March 28, 2001. FIRST THREE MONTHS 2001 COMPARED TO FIRST THREE MONTHS 2000 PRODUCTION

On an energy equivalent basis our average production rate for the first three months of 2001 increased 28% to 127.0 mmcfe per day (104.1 mmcfe per day after royalties) from 99.5 mmcfe per day (82.4 mmcfe per day after royalties) for the corresponding period in 2000. Natural gas comprised 83% (82% after royalties) of our production for the first three months of 2001, compared to 75% (before and after royalties) in the corresponding period in 2000. For the first three months of 2001, our natural gas production increased 40% to 9.5 bcf (7.7 bcf after royalties) compared to 6.8 bcf (5.6 bcf after royalties) for the corresponding period in 2000. Oil and natural gas liquids production for the same period decreased 14% to 326 mbbls (274 mbbls after royalties) compared to 378 mbbls (318 mbbls after royalties) for the corresponding period in 2000. -------------------------------------------------------------------------------- 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. 10 Page 10 of 15 Ninety-four percent of our natural gas production for the first three months of 2001 came from the US Gulf of Mexico region compared to 88% in the corresponding period in 2000. Our interests in this region accounted for 54% of our oil and ngls production compared to 46% in the 2000 period. Substantially all of the remainder of our oil and ngls production was from our interests in the Aneth and Ratherford Units in southeast Utah. NATURAL GAS AND OIL MARKETING NATURAL GAS. Natural gas prices averaged $5.83 per mcf for the first three months of 2001 compared to $2.38 per mcf for the corresponding period in 2000. For the first three months of 2001, we received average natural gas prices of $5.98 per mcf in the US and $3.40 per mcf in the UK compared to $2.51 and $1.35, respectively, for the corresponding period in 2000. We believe that these prices, in both markets, reflect continuing tight supply-demand equations. The Energy Information Administration ("EIA") of the U.S. Department of Energy has forecast that US natural gas demand will increase 1.9% and that domestic natural gas production will increase 2.7% in the current year. As at March 31, 2001, we had entered into second and third quarter natural gas forward sales for the physical delivery of volumes totaling approximately 22.6 mmcf per day at an average price of $4.83 per mcf, net of transportation. OIL AND NGLS. Oil and natural gas liquids prices averaged $27.22 per barrel for the first three months of 2001 compared to $24.06 per barrel in the 2000 period. Oil prices in both periods benefited from supply constrictions arising from the Organization of Petroleum Exporting Countries' ("OPEC") production quotas. REVENUE PRODUCTION REVENUE. For the first three months of 2001, a 145% increase in natural gas prices and a 13% increase in oil prices were complemented by a 28% increase in equivalent production volumes. Higher prices and production volumes resulted in production revenues for the first three months of 2001 increasing 154% or $38.9 million to $64.1 million or $51.9 million after royalties from the corresponding period in 2000.

ROYALTIES. As expected, our composite royalty rate increased on a period over period basis due to the UK production, which carries no royalty obligations, having a lesser significance in our production mix. 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%. WE PAY NO OVERRIDING ROYALTIES TO MANAGEMENT OR STAFF. 11 Page 11 of 15

EXPENSES PRODUCTION COSTS. Our aggregate production costs for the first three months of 2001 increased 3% compared to the corresponding period in 2000. On a per unit basis production costs decreased as a result of the increased proportion of our production from the Gulf of Mexico region, which has lower per unit production costs than our interests in the Aneth and Ratherford Units in Utah. Also contributing to the decrease in per unit production costs is the increased proportion of our production which is natural gas, which generally has lower production costs than oil and ngls. Production taxes, which increased 34% on a per unit basis, are levied primarily on Utah oil production, the amount of such taxes being dependent upon prices of natural gas and oil.

GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses for the first three months of 2001 decreased 9% from the corresponding period in 2000. This decrease is primarily the result of performance-based compensation costs which were lower during the first quarter of 2001 than during the corresponding 2000 period.

INTEREST EXPENSE. Our interest expense for the first three months of 2001 increased compared to the corresponding 2000 period due to increased credit facility utilization. Our weighted average debt outstanding for the three months ended March 31, 2001 was $15.1 million compared to $10.0 million for the corresponding period in 2000. The effective interest rate on our outstanding debt for the three months ended March 31, 2001 was 6.82% compared to 7.00% for the corresponding period in 2000. The weighted-average interest rate on our debt at March 31, 2001 was 6.09%. DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the first three months of 2001 increased 47% from the corresponding period in 2000 as a result of a 28% increase in our production and the previously expected increase in our average depletion rate, 16%, to $1.35 per mcfe ($1.65 per mcfe after royalties). 12 Page 12 of 15 NET INCOME APPLICABLE TO COMMON SHARES After provision of $1.2 million for dividends on preferred shares of a subsidiary in both periods, net income applicable to common shares for the first three months of 2001 was $17.9 million, an improvement of $15.8 million compared to the year earlier period. The most significant factors responsible for the improvement were the increased production volumes and the improvement in natural gas prices in the current year. CAPITAL EXPENDITURES Our capital expenditures during the first three months of 2001 totaled $39.2 million compared to $19.5 million for the corresponding period in 2000.

LEASE AND LAND HOLDINGS. At the March 28, 2001 Federal US Gulf of Mexico Lease Sale, Chieftain and its partners submitted high bids for 17 offshore lease blocks, 14 on the Continental Shelf and 3 in the deep water. The lease blocks cover 87,000 gross (62,000 net) acres and Chieftain is designated operator of 12 of the blocks. Subject to US Minerals Management Service acceptance of these bids Chieftain's cost will be $6.3 million. DRILLING RESULTS. For the first three months of 2001, our exploratory drilling success rate in the US Gulf of Mexico region was 60%, unchanged from the corresponding period in 2000. No development wells were drilled in either period.

In addition to the wells described above, at March 31, 2001 we had interests in 2 (0.87 net) wells which were drilling compared to 6 (1.71 net) at March 31, 2000. CAPITAL FIELD DEVELOPMENT ACTIVITY. During the first quarter of 2001, design, construction and/or installation of production facilities and pipelines totaled $9.6 million and were conducted at East Cameron 83, Eugene Island 189, High Island A-467, High Island A-510/A-531, South Timbalier 250, West Cameron 300 and West Cameron 370. 13 Page 13 of 15 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 attributable to common shares to eliminate the effects of depletion and amortization, write-down of marketable securities and deferred income taxes. We generated cash flow from operations of $45.5 million during the first three months of 2001 compared to $14.7 million for the corresponding period in 2000. The variance is primarily a function of increased production and commodity prices in the first three months of 2001.

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. In 1999 we commenced an action in the Louisiana courts against both the vendor and the purchaser to recover the amounts currently owing to us, approximately $4.7 million, plus interest and costs. There have been no material developments in respect of this matter since December 31, 2000. Financing activities during the first three months of 2001 used $11.8 million of cash, the net result of: o the repayment of $10 million of our revolving bank credit facility; o the exercise of employee stock options for $0.6 million; and o the purchase for cancellation of 101,300 common shares at the cost of $2.4 million under a share repurchase program, announced August 11, 2000; such purchases were suspended on March 8, 2001. We engaged in no financing activities during the first three months of 2000. Cash used in investing activities increased 102% to $39.2 million for the first three months of 2001 from $19.4 million for the corresponding period in 2000.

14 Page 14 of 15 Our March 31, 2001 cash balance of $20.1 million was up $12.7 million from the balance at March 31, 2000. At March 31, 2001, $10 million was outstanding on our unsecured revolving bank credit facility of $70 million. The weighted-average interest rate for our borrowings during the first three months was 6.82%. OUTLOOK Increased levels of drilling and development activity during the past year brought our first quarter production to 127 mmcfe per day. Our 2001 capital expenditure program, substantially all in the Gulf of Mexico region, will include the drilling of approximately 36 wells and the start up of production from 10 natural gas and oil fields. During the second quarter of 2001, drilling is expected to commence on approximately 9-12 wells and production is forecast to commence at 6 new fields. Our estimated 2001 capital expenditure budget remains at $105 million. We expect to fund these capital expenditures from operating cash flow. 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. On March 8, 2001, our Board of Directors announced that it had authorized CIBC World Markets, Inc., our financial adviser, to examine strategic alternatives to enhance shareholder value, including a possible merger or sale of the Company. As part of this process, data rooms have been opened in Dallas and Edmonton. 15 Page 15 of 15 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 2001. ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON 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 30, 2001

CHIEFTAIN INTERNATIONAL INC 10-Q