UNITED STATES SECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
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x
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Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. | |
| For the quarterly period ended September 30, 2002 | ||
| or | ||
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o
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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 000-30586
IVANHOE ENERGY INC.
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Yukon, Canada
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98- 0372413 | |
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(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
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Suite 654 – 999 Canada Place Vancouver, British Columbia, Canada V6C 3E1 (Address of principal executive office) |
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(604) 688-8323 (registrant’s telephone number, including area code) |
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Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report:
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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Yes x
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No o |
The number of shares of the registrant’s capital stock outstanding as of September 30, 2002 was 144,630,818 Common Shares, no par value.
Page 1 of 22
TABLE OF CONTENTS
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PART I
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Financial Information | |||
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Item 1.
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Financial Statements | |||
| Consolidated Condensed Balance Sheets at September 30, 2002 (unaudited) and December 31, 2001 | 3 | |||
| Unaudited Consolidated Condensed Statements of Loss and Deficit for the Three Month and Nine Month Periods Ended September 30, 2002 and 2001 | 4 | |||
| Unaudited Consolidated Condensed Statements of Cash Flow for the Three Month and Nine Month Periods Ended September 30, 2002 and 2001 | 5 | |||
| Notes to the Unaudited Consolidated Condensed Financial Statements | 6 | |||
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Item 2.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | 11 | ||
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Item 3.
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Quantitative and Qualitative Disclosures About Market Risks | 16 | ||
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Item 4.
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Controls and Procedures | 16 | ||
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PART II
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Other Information | |||
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Item 1.
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Legal Proceedings | 17 | ||
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Item 2.
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Changes in Securities and Use of Proceeds | 17 | ||
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Item 3.
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Defaults Upon Senior Securities | 17 | ||
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Item 4.
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Submission of Matters To a Vote of Securityholders | 17 | ||
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Item 5.
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Other Information | 17 | ||
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Item 6.
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Exhibits and Reports on Form 8-K | 17 |
Page 2 of 22
Part I — Financial Information
Item 1 Financial Statements
IVANHOE ENERGY INC.
| September 30, 2002 | December 31, 2001 | |||||||
| (unaudited) | (audited) | |||||||
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Assets
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||||||||
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Current Assets
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||||||||
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Cash
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$ | 2,981 | $ | 9,697 | ||||
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Accounts receivable
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2,898 | 1,938 | ||||||
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Other
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731 | 375 | ||||||
| 6,610 | 12,010 | |||||||
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Long Term Assets
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457 | 397 | ||||||
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Oil and gas properties, equipment and
GTL investments
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99,597 | 91,596 | ||||||
| $ | 106,664 | $ | 104,003 | |||||
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Liabilities and Stockholders’
Equity
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||||||||
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Current Liabilities
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||||||||
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Accounts payable and accrued liabilities
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$ | 3,770 | $ | 5,974 | ||||
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Convertible debenture
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1,000 | 1,000 | ||||||
| 4,770 | 6,974 | |||||||
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Provision for site restoration
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219 | 132 | ||||||
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Shareholders’ Equity
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||||||||
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Share capital, issued 144,631,000 common shares;
December 31, 2001 139,267,000
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130,862 | 120,392 | ||||||
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Deficit
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(29,187 | ) | (23,495 | ) | ||||
| 101,675 | 96,897 | |||||||
| $ | 106,664 | $ | 104,003 | |||||
(see accompanying notes)
Page 3 of 22
IVANHOE ENERGY INC.
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2002 | 2001 | 2002 | 2001 | |||||||||||||
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Revenue
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||||||||||||||||
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Oil and gas revenue
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$ | 2,328 | $ | 2,708 | $ | 5,972 | $ | 7,141 | ||||||||
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Interest income
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22 | 26 | 94 | 512 | ||||||||||||
| 2,350 | 2,734 | 6,066 | 7,653 | |||||||||||||
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Expenses
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||||||||||||||||
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Operating costs
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1,070 | 1,198 | 2,938 | 3,213 | ||||||||||||
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General and administrative
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1,095 | 1,436 | 4,083 | 6,277 | ||||||||||||
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Depletion and depreciation
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813 | 770 | 2,301 | 1,689 | ||||||||||||
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Write offs and provision for impairment
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2,436 | 9,000 | 2,436 | 14,000 | ||||||||||||
| 5,414 | 12,404 | 11,758 | 25,179 | |||||||||||||
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Net loss
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3,064 | 9,670 | 5,692 | 17,526 | ||||||||||||
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Deficit, beginning of period
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26,123 | 10,229 | 23,495 | 2,373 | ||||||||||||
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Deficit, end of period
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$ | 29,187 | $ | 19,899 | $ | 29,187 | $ | 19,899 | ||||||||
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Net Loss per share
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$ | 0.02 | $ | 0.08 | $ | 0.04 | $ | 0.14 | ||||||||
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Weighted Average Number of Shares
(in thousands)
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144,631 | 127,981 | 141,546 | 127,436 | ||||||||||||
(see accompanying notes)
Page 4 of 22
IVANHOE ENERGY INC.
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2002 | 2001 | 2002 | 2001 | |||||||||||||
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Operating Activities
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||||||||||||||||
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Net loss
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$ | (3,064 | ) | $ | (9,670 | ) | $ | (5,692 | ) | $ | (17,526 | ) | ||||
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Items not requiring use of cash
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||||||||||||||||
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Depletion and depreciation
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813 | 770 | 2,301 | 1,689 | ||||||||||||
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Write offs and provision for impairment
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2,436 | 9,000 | 2,436 | 14,000 | ||||||||||||
| 185 | 100 | (955 | ) | (1,837 | ) | |||||||||||
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Changes in non-cash working capital items
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(757 | ) | 2,441 | (3,133 | ) | 5,633 | ||||||||||
| (572 | ) | 2,541 | (4,088 | ) | 3,796 | |||||||||||
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Investing Activities
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||||||||||||||||
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Capital spending
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(4,639 | ) | (7,766 | ) | (16,471 | ) | (33,502 | ) | ||||||||
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Proceeds from sale of assets
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2,560 | — | 3,760 | — | ||||||||||||
| (2,079 | ) | (7,766 | ) | (12,711 | ) | (33,502 | ) | |||||||||
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Financing Activities
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||||||||||||||||
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Shares issued on private placement
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— | — | 9,964 | — | ||||||||||||
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Shares issued on exercise of options
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— | 98 | 119 | 327 | ||||||||||||
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Proceeds from demand loan
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— | 1,000 | — | 1,000 | ||||||||||||
| — | 1,098 | 10,083 | 1,327 | |||||||||||||
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Increase (Decrease) in cash for the period
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(2,651 | ) | (4,127 | ) | (6,716 | ) | (28,379 | ) | ||||||||
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Cash, beginning of period
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5,632 | 5,442 | 9,697 | 29,694 | ||||||||||||
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Cash, end of period
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$ | 2,981 | $ | 1,315 | $ | 2,981 | $ | 1,315 | ||||||||
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Supplementary Information Regarding Non-Cash
Transactions
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Investing activities, net assets acquired:
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||||||||||||||||
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Oil and gas properties
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$ | — | $ | — | $ | — | $ | 2,978 | ||||||||
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Accounts receivable
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— | — | — | 200 | ||||||||||||
| $ | — | $ | — | $ | — | $ | 3,178 | |||||||||
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Financing activities, non-cash:
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||||||||||||||||
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Shares issued as consideration
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$ | — | $ | — | $ | — | $ | 3,178 | ||||||||
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Included in the above are the
following:
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||||||||||||||||
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Interest paid
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$ | 21 | $ | 27 | $ | 56 | $ | 84 | ||||||||
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Decrease (increase) in non-cash working
capital items
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||||||||||||||||
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Accounts receivable
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$ | (853 | ) | $ | 719 | $ | (960 | ) | $ | 2,314 | ||||||
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Other current assets
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(503 | ) | 102 | (356 | ) | 153 | ||||||||||
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Accounts payable and accrued liabilities
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599 | 1,619 | (1,817 | ) | 3,165 | |||||||||||
| $ | (757 | ) | $ | 2,441 | $ | (3,133 | ) | $ | 5,633 | |||||||
(see accompanying notes)
Page 5 of 22
Notes to the Consolidated Condensed Financial Statements
| 1. | General |
| The unaudited consolidated condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2001 consolidated financial statements, except for a change in the policy of accounting for stock based compensation plan (see note 6), and should be read in conjunction therewith. The December 31, 2001 consolidated balance sheet was derived from the audited consolidated financial statements, but does not include all disclosures required by generally accepted accounting principles (“GAAP”) in Canada and the U.S. All adjustments which are, in the opinion of management, necessary for a fair presentation of the Company’s financial position as at September 30, 2002 and December 31, 2001 and the results of operations and cash flows for the three and nine month periods ended September 30, 2002 and 2001 have been included. The results of operations and cash flows are not necessarily indicative of the results for a full year. | |
| The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts and other disclosure in these condensed consolidated financial statements. Actual results may differ from those estimates. |
| 2. | Accounting Principles |
| The consolidated condensed financial statements have been prepared in accordance with Canadian GAAP, which conforms to U.S. GAAP except as below: | |
| Consolidated Condensed Balance Sheets |
| As at | As at | ||||||||||||||||
| September 30, 2002 | December 31, 2001 | ||||||||||||||||
| Oil and Gas | Shareholders’ | Oil and Gas | Shareholders’ | ||||||||||||||
| Properties | Equity | Properties | Equity | ||||||||||||||
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Canadian GAAP
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$ | 99,597 | $ | 101,675 | $ | 91,596 | $ | 96,897 | |||||||||
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Adjustment to ascribed value of shares issued for
royalty interests
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1,358 | 1,358 | 1,358 | 1,358 | |||||||||||||
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Impairment provision for China properties
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(10,000 | ) | (10,000 | ) | (10,000 | ) | (10,000 | ) | |||||||||
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Depletion adjustment — China
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56 | 56 | — | — | |||||||||||||
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GTL development costs written off
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(6,421 | ) | (6,421 | ) | (5,142 | ) | (5,142 | ) | |||||||||
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OCI — Derivative Mark-to-Market
adjustment
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— | (142 | ) | — | — | ||||||||||||
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U.S. GAAP
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$ | 84,590 | $ | 86,526 | $ | 77,812 | $ | 83,113 | |||||||||
| Under U.S. GAAP, changes in the fair value of derivative instruments that meet specific cash-flow hedge accounting criteria are reported in other comprehensive income (OCI). The gains and losses on cash-flow hedge transactions that are reported in OCI are reclassified to earnings in the period in which earnings are affected by changes in the cash flow of the underlying hedged item. The mark-to- |
Page 6 of 22
| market value of the derivative as at September 30, 2002 is a liability of $0.1 million. It has been determined that there is no ineffectiveness in the derivative thus none of the hedging loss has been reclassified from OCI to current period earnings. | |
| Under U.S. GAAP, the transfer of deficit to share capital, which occurred in 1999, would not be recognized and would comprise the following Shareholders’ Equity: |
| September 30 | December 31 | |||||||
| 2002 | 2001 | |||||||
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Share capital (including adjustments above)
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$ | 206,675 | $ | 196,205 | ||||
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Deficit (Including adjustments above)
|
(120,007 | ) | (113,092 | ) | ||||
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Accumulated other comprehensive income
|
(142 | ) | — | |||||
| $ | 86,526 | $ | 83,113 | |||||
Consolidated Condensed Statements of Loss and Deficit
| Nine Month Periods Ended September 30 | |||||||||||||||||
| 2002 | 2001 | ||||||||||||||||
| Net | Net Loss | Net Loss | |||||||||||||||
| Loss | Per Share | Net Loss | Per Share | ||||||||||||||
|
Canadian GAAP
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$ | 5,692 | $ | 0.04 | $ | 17,526 | $ | 0.14 | |||||||||
|
Depletion adjustment — China
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(56 | ) | — | — | — | ||||||||||||
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GTL development costs written off
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1,279 | 0.01 | 2,870 | 0.02 | |||||||||||||
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U.S. GAAP
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$ | 6,915 | $ | 0.05 | $ | 20,396 | $ | 0.16 | |||||||||
| Three Month Periods Ended September 30 | |||||||||||||||||
| 2002 | 2001 | ||||||||||||||||
| Net | Net Loss | Net Loss | |||||||||||||||
| Loss | Per Share | Net Loss | Per Share | ||||||||||||||
|
Canadian GAAP
|
$ | 3,064 | $ | 0.02 | $ | 9,670 | $ | 0.08 | |||||||||
|
Depletion adjustment — China
|
(18 | ) | — | — | — | ||||||||||||
|
GTL development costs written off
|
(70 | ) | — | 910 | 0.01 | ||||||||||||
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U.S. GAAP
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2,976 | $ | 0.02 | $ | 10,580 | $ | 0.09 | ||||||||||
| 3. | Oil and Gas Properties, Equipment and GTL Investments |
| Effective August 2002, the Company sold its interest in seven non-core producing wells in the Spraberry field to an unrelated party for $1.4 million. Additionally, in September 2002 the Company collected the final payment of $1.2 million from its sale of the Daqing project, which was sold in January 2002. | |
| In June 2002, the Company signed a letter of intent with Syntroleum to participate in the Syntroleum – U.S. Department of Energy Fuels Project at a cost of $5 million. The DOE project cost is to be offset by $2 million of the Company’s investment in Syntroleum’s Sweetwater project in Australia, which Syntroleum recently cancelled. As Sweetwater is not proceeding and participation in the DOE project is contingent upon the Company successfully signing a GTL contract, which is not assured, the Company has written off its $2.4 million investment in the Sweetwater project. |
Page 7 of 22
| 4. | Derivative Activities |
| The Company’s results of operations are sensitive mainly to fluctuations in oil and natural gas prices. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows. | |
| In September 2002, the Company entered into a costless collar derivative to hedge the cash flow from the sale of 91,000 barrels of oil production over a six-month period starting October 2002. The hedge has a ceiling price of $28.95 per barrel and a floor price of $24.00 per barrel using WTI as the index traded on the NYMEX. Gains and losses on derivatives are recognized in earnings as they are realized. As at September 30, 2002, the Company had no realized gains or losses on derivative transactions. |
| 5. | Segment Information |
| The following tables present the Company’s interim segment information: |
| Nine Month Periods Ended September 30: | ||||||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||||
| U.S. | China | Total | U.S. | China | Total | |||||||||||||||||||
|
Oil and gas revenue
|
$ | 3,759 | $ | 2,213 | $ | 5,972 | $ | 4,004 | $ | 3,137 | $ | 7,141 | ||||||||||||
|
Interest income
|
94 | — | 94 | 512 | — | 512 | ||||||||||||||||||
| 3,853 | 2,213 | 6,066 | 4,516 | 3,137 | 7,653 | |||||||||||||||||||
|
Operating costs
|
1,880 | 1,058 | 2,938 | 1,522 | 1,691 | 3,213 | ||||||||||||||||||
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Depletion and depreciation
|
1,415 | 886 | 2,301 | 1,579 | 110 | 1,689 | ||||||||||||||||||
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Provision for impairment
|
— | — | — | 14,000 | — | 14,000 | ||||||||||||||||||
| 3,295 | 1,944 | 5,239 | 17,101 | 1,801 | 18,902 | |||||||||||||||||||
|
Segmented (income) loss before
the following
|
$ | (558 | ) | $ | (269 | ) | (827 | ) | $ | 12,585 | $ | (1,336 | ) | 11,249 | ||||||||||
|
Write off of GTL assets
|
2,436 | — | ||||||||||||||||||||||
|
General and administrative
|
4,083 | 6,277 | ||||||||||||||||||||||
|
Net loss
|
$ | 5,692 | $ | 17,526 | ||||||||||||||||||||
Page 8 of 22
| Three Month Periods Ended September 30: | ||||||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||||
| U.S. | China | Total | U.S. | China | Total | |||||||||||||||||||
|
Oil and gas revenue
|
$ | 1,454 | $ | 874 | $ | 2,328 | $ | 1,487 | $ | 1,221 | $ | 2,708 | ||||||||||||
|
Interest income
|
22 | — | 22 | 26 | 26 | |||||||||||||||||||
| 1,476 | 874 | 2,350 | 1,513 | 1,221 | 2,734 | |||||||||||||||||||
|
Operating costs
|
710 | 360 | 1,070 | 509 | 689 | 1,198 | ||||||||||||||||||
|
Depletion and depreciation
|
518 | 295 | 813 | 728 | 42 | 770 | ||||||||||||||||||
|
Provision for impairment
|
— | — | — | 9,000 | — | 9,000 | ||||||||||||||||||
| 1,228 | 655 | 1,883 | 10,237 | 731 | 10,968 | |||||||||||||||||||
|
Segmented (income) loss before
the following
|
$ | (248 | ) | $ | (219 | ) | (467 | ) | $ | 8,724 | $ | (490 | ) | 8,234 | ||||||||||
|
Write off of GTL assets
|
2,436 | — | ||||||||||||||||||||||
|
General and administrative
|
1,095 | 1,436 | ||||||||||||||||||||||
|
Net loss
|
$ | 3,064 | $ | 9,670 | ||||||||||||||||||||
| 6. | Share Capital |
| Following is a summary of the changes in share capital and stock options outstanding for the nine-month period ended September 30, 2002: |
| Stock Options | |||||||||||||||||
| Common Shares | Weighted | ||||||||||||||||
| Average | |||||||||||||||||
| Number | Amount | Number | Exercise Price | ||||||||||||||
| (thousands) | (thousands) | Cdn.$ | |||||||||||||||
|
Balance December 31, 2001
|
139,267 | $ | 120,392 | 8,635 | $ | 2.66 | |||||||||||
|
Shares issued on private placement
|
5,000 | 9,964 | |||||||||||||||
|
Shares issued on exercise of options
|
163 | 119 | (163 | ) | 1.57 | ||||||||||||
|
Shares issued for service
|
201 | 387 | |||||||||||||||
|
Options granted
|
2,095 | 2.86 | |||||||||||||||
|
Options cancelled/ forfeited
|
(236 | ) | 3.50 | ||||||||||||||
|
Balance September 30, 2002
|
144,631 | $ | 130,862 | 10,331 | $ | 2.70 | |||||||||||
| In June 2002, the Company granted a service provider a six-month option to purchase 250,000 shares at US$4.00 per share. | |
| The Company accounts for its stock-based compensation plans using intrinsic-values. Compensation costs are not recognized in the financial statements for options granted to employees and directors when granted at market value. Compensation costs are, however, recognized in the financial statements for options granted to non-employees based on the fair value of the options at the date granted. | |
| Effective January 2002, Canadian accounting standards require disclosure on a pro forma basis of the impact on net income of using the fair value method for stock options granted to employees and directors on or after that date. Had compensation expense been determined based on the fair value at the option grant date, the Company’s net loss and net loss per share for the nine-month period ended September 30, 2002 would have been $6.1 million and $.04 per |
Page 9 of 22
| share, respectively. The foregoing is calculated in accordance with Black-Scholes, using the following data and assumptions: 72% price volatility, using the prior two-year weekly average prices of the Company’s common shares; expected dividend yield of 0%; option terms to expiry of 0.5 to 5 years, as defined by the option agreements; risk-free rate of return of 3.04% to 4.35%, based on one and five year Government of Canada Bond yields. |
| 7. | Commitments |
| In September 2002 the Company, through its 100% owned subsidiary Sunwing Energy Ltd (Sunwing), signed a 30-year petroleum-sharing agreement with PetroChina for the exploitation of natural gas deposits in the approximate 900,000 acre Zitong Block located in the Sichuan Basin of southwestern China. The Company is obligated to conduct exploration activities in this block, which will include acquiring new 2-D seismic data, reprocessing existing seismic data and drilling of four exploratory wells over the next six years. |
| 8. | Subsequent Events |
| As part of a private placement in October 2000, the Company issued 5,000,000 common shares and warrants exercisable into 2,500,000 common shares at Cdn$5.375 until October 2002. The warrants were not exercised and have been cancelled. | |
| Our $1 million unsecured convertible debenture was originally due within 90 days following written demand and was convertible (including principal and accrued interest) into common shares of the Company at Cdn. $2.75 per share until August 2002. In October 2002, the Company entered into an agreement in which the lender agreed not to demand repayment of the debenture until March 2003. Thereafter, the debenture is due at any time within 90 days following written demand and principal and accrued interest will be convertible, at lender’s option, into common shares of the Company at Cdn $1.21 per share. | |
| Sunwing has entered into an agreement with CITIC Energy Inc. (CITIC), a subsidiary of China International Trust & Investment Corporation, to form a strategic alliance to seek out and develop oil and gas projects in China and around the world. CITIC has also agreed to assist Sunwing in its efforts to negotiate a petroleum-sharing agreement with PetroChina covering the Yudong Block in Sichuan Province. Should such a contract for the block be obtained, Sunwing and CITIC will jointly participate in the development of the project on a 70/30 basis. Within 180 days after the effective date of the contract, either party can elect to convert CITIC’s 30% participating interest in the project into a 20% equity interest in Sunwing. |
Page 10 of 22
| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following should be read in conjunction with the Company’s consolidated financial statements contained herein and in the Form 10-K for the year ended December 31, 2001, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained therein. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K.
Results of Operations
Oil and gas revenues for the three and nine month periods ended September 30, 2002 were $2.3 million and $6.0 million, respectively. This represents a decrease of $0.4 million and $1.2 million, respectively, for the comparable periods in 2001. The revenue decrease for the third quarter is primarily a result of a reduction in production volumes as further described in Production below which are partially offset by higher oil and gas prices. The revenue decrease for the nine-month period ended September 30, 2002 is primarily a result of a decline in oil prices in addition to a reduction in volumes as further described in Production below.
For the three-month period ended September 30, 2002, the net loss was $3.1 million ($.02 per share) compared to a net loss of $9.7 million ($.08 per share) for the comparable period in 2001. Our net loss for the nine-month period ended September 30, 2002 was $5.7 million ($.04 per share) compared to a net loss of $17.5 million ($.14 per share) during the comparable period of 2001. The net loss for the three and nine month periods ended September 30, 2002 includes a $2.4 million write off of our investment in Syntroleum’s Sweetwater project in Australia. The net loss for the three and nine month periods ended September 30, 2001 includes a $9.0 million and $14.0 million provision for impairment, respectively, resulting from a comparison of depletable capitalized costs for our U.S. oil and gas properties, which include exploration costs, with future net cash flows.
Production
For the three-month period ended September 30, 2002, net U.S. production declined 13% over the comparable period in 2001 primarily due to a natural decline in Spraberry. For the nine-month period ended September 30, 2002, net production in the U.S. increased 4% over the comparable period in 2001. This increase is attributed to a 26% increase in production at South Midway as a result of our cyclic steam program and drilling of 6 additional wells during the second quarter of 2002. This was partially offset by a 16% decline in oil production in Spraberry primarily due to a natural decline as well as an increase in downtime for routine maintenance and workover of wells and the sale of our interest in seven producing wells in August 2002. To date we have cycle steamed 13 wells in South Midway achieving increased oil production rates ranging from 2.5 to 4 times. By the end of 2002 we plan to have at least 20 wells responding to steam injection. Our plan is to double our ultimate recoverable reserves in South Midway through this program.
For the three and nine month periods ended September 30, 2002, net production in China decreased 24% and 14%, respectively, over the comparable periods in 2001. Production volumes from the Dagang project declined 19% and 8%, respectively, primarily due to routine maintenance and workovers as well as problems during the third quarter with water injection facilities. This decrease was partially offset by having regained an additional 20% interest in the Dagang field from Nippon Oil in mid-2001. The sale of our interest in the Daqing project in January 2002 accounted for the remaining decline in production volumes.
Page 11 of 22
Operating costs in the U.S. are up 28% and 7% per barrel for the three and nine month periods of 2002, respectively, compared to the same periods in 2001. Primary operating costs per barrel in the South Midway have decreased as a result of having installed permanent production and electrical facilities during 2001. This decrease was offset by an increase in costs incurred for cyclic steam activities in South Midway, including an increase in engineering support, and the cost of workovers and routine maintenance in Spraberry. U.S. depletion costs per barrel decreased 10% in 2002 primarily due to the impairment write offs recorded in 2001, partially offset by the reduction in our reserves as a result of the sale of Spraberry wells.
Operating costs per barrel in China decreased 37% and 39% for the three and nine month periods of 2002, respectively, compared to the same periods in 2001 as a result of having installed electrical facilities on certain wells in the Dagang field in late 2001. In addition, we benefited from operating efficiencies as the wells mature. For each of the quarters presented in 2001, future development costs for China were inadvertently excluded from the depletion calculation. Depletion for the first nine months of 2002 of $8.34 has increased $1.55 per barrel, compared to 2001, primarily as a result of anticipated increases in Dagang future development costs.
Production and operating information are detailed below:
| Nine Month Periods Ended September 30, | |||||||||||||||||||||||||
| 2002 | 2001 | ||||||||||||||||||||||||
| U.S. | China | Total | U.S. | China | Total | ||||||||||||||||||||
|
Net Production:
|
|||||||||||||||||||||||||
|
BOE
|
170,774 | 106,303 | 277,077 | 163,567 | 123,634 | 287,201 | |||||||||||||||||||
|
BOE/day during period
|
626 | 389 | 1,015 | 599 | 453 | 1,052 | |||||||||||||||||||
| Per BOE | Per BOE | |||||||||||||||||||||||
|
Oil and gas revenue
|
$ | 22.01 | $ | 20.82 | $ | 21.55 | $ | 24.48 | $ | 25.37 | $ | 24.87 | ||||||||||||
|
Operating costs
|
7.04 | 5.93 | 6.61 | 6.56 | 9.78 | 7.95 | ||||||||||||||||||
|
Production taxes
|
1.42 | — | 0.88 | 0.80 | — | 0.46 | ||||||||||||||||||
|
Engineering support
|
2.55 | 4.02 | 3.11 | 1.95 | 3.90 | 2.79 | ||||||||||||||||||
| 11.01 | 9.95 | 10.60 | 9.31 | 13.68 | 11.20 | |||||||||||||||||||
|
Net Revenue before depletion
|
11.00 | 10.87 | 10.95 | 15.17 | 11.69 | 13.67 | ||||||||||||||||||
|
Depletion
|
7.80 | 8.34 | 8.01 | 8.65 | 0.89 | 5.31 | ||||||||||||||||||
|
Net Revenue from operations
|
$ | 3.20 | $ | 2.53 | $ | 2.94 | $ | 6.52 | $ | 10.80 | $ | 8.36 | ||||||||||||
Page 12 of 22
| Three Month Periods Ended September 30, | |||||||||||||||||||||||||
| 2002 | 2001 | ||||||||||||||||||||||||
| U.S. | China | Total | U.S. | China | Total | ||||||||||||||||||||
|
Net Production:
|
|||||||||||||||||||||||||
|
BOE
|
58,566 | 35,858 | 94,424 | 66,467 | 47,293 | 113,760 | |||||||||||||||||||
|
BOE/day during period
|
637 | 390 | 1,026 | 722 | 514 | 1,237 | |||||||||||||||||||
| Per BOE | Per BOE | |||||||||||||||||||||||
|
Oil and gas revenue
|
$ | 24.83 | $ | 24.38 | $ | 24.66 | $ | 22.38 | $ | 25.83 | $ | 23.81 | ||||||||||||
|
Operating costs
|
7.86 | 6.31 | 7.27 | 6.14 | 10.05 | 7.77 | ||||||||||||||||||
|
Production taxes
|
1.79 | — | 1.11 | (0.06 | ) | — | (0.04 | ) | ||||||||||||||||
|
Engineering support
|
2.48 | 3.71 | 2.94 | 1.58 | 4.52 | 2.81 | ||||||||||||||||||
| 12.13 | 10.02 | 11.32 | 7.66 | 14.57 | 10.54 | |||||||||||||||||||
|
Net Revenue before depletion
|
12.70 | 14.36 | 13.34 | 14.72 | 11.25 | 13.28 | ||||||||||||||||||
|
Depletion
|
8.25 | 8.24 | 8.25 | 9.21 | 0.89 | 5.75 | ||||||||||||||||||
|
Net Revenue from operations
|
$ | 4.45 | $ | 6.12 | $ | 5.09 | $ | 5.51 | $ | 10.37 | $ | 7.52 | ||||||||||||
General and Administrative Costs
These costs include project identification costs, which are costs associated with pursuing and investigating new international projects and the cost of investment banking services in some periods. General and administrative costs for the three and nine month periods ended September 30, 2002 were $1.1 million and $4.1 million, respectively, down $0.3 million and $2.2 million, respectively, from the comparable periods in 2001, as a result of a reduction in project identification activities and implementation of a cost reduction program in September 2002. The program is expected to reduce overhead by approximately 25%.
Exploration and Development Activities
Spending on these activities for the three and nine month periods ended September 30, 2002 was $4.3 million and $14.8 million, respectively, a decrease of $2.6 million and $15.9 million over the amounts spent during the comparable periods in 2001. U.S. spending was down $13.4 million in the first nine months of 2002, primarily due to a reduction in our development drilling in Spraberry and South Midway and the completion of our significant acreage acquisition in the Bossier Trend at the end of 2001. This is partially offset by an increase in spending in California primarily on the drilling of our deep gas well, Northwest Lost Hills #1–22. Spending in China was down $2.6 million for the first nine months of 2002 as a result of the pilot test in Dagang being completed in February 2001 and the sale of Daqing in January 2002.
Currently, Unocal has spent approximately $8.1 million of the $10.1 million needed to earn a 50% interest in our holdings in the Bossier Trend. Of the three wells drilled to date, one well is producing minimal levels of gas from the Bossier and the other wells are suspended pending Unocal’s assessment of the data and its plans for the Bossier prospects. We continue to be optimistic about the shallower Cotton Valley, Travis Peak, Pettet and Rodessa zones some of which had encouraging shows of gas in the wells drilled.
At Lost Hills in California, the NWLH 1-22 well was successfully drilled to a measured depth of 21,000 feet and a liner set to 19,620 feet. The operator, Aera Energy LLC, has recommended a testing and completion program for the well, which encountered natural gas in the Temblor formation. We own a 42% working interest in this well and are currently looking for partners to participate in this next phase of the well.
Page 13 of 22
Upon completion of our analysis of the data from the three Kentucky wells drilled in 2001 we decided not to perform further tests on any of the wells and to relinquish our interests.
We received approval of our environmental impact study in the third quarter of 2002 and now anticipate that approval of our overall development program for Dagang will be received from PetroChina next year.
In September 2002 we signed a 30-year petroleum-sharing agreement with PetroChina covering approximately 900,000 acres with a gross natural gas resource potential of five trillion cubic feet located in the northwestern portion of the Sichuan Basin, China’s largest gas-producing region. Under the terms of the agreement, we will develop natural gas deposits within the block and in return will receive approximately 80% of the revenue before costs are recovered and approximately 45% after costs are fully recovered. PetroChina has the option to participate in any successful developments, with up to a 51% working interest. We will also conduct exploration activities over the block, which will include acquiring seismic data and reprocessing existing seismic. The seismic programs and drilling of two exploratory wells will take place in the first 3-year exploration period at an estimated cost of $18 million. Following the first phase, if we elect to continue, the next 3-year exploration period will require two additional exploratory wells and additional seismic at an estimated cost of $16 million.
In addition, pursuant to existing exclusive arrangements, we have the right to negotiate a petroleum-sharing agreement for the one-million-acre Yudong block located on the eastern edge of the Sichuan Basin. We expect these negotiations to begin before the end of the year.
Gas-to-Liquids Activities
Spending on GTL projects for the three and nine month periods ended September 30, 2002 was $0.3 million and $1.7 million, respectively, a decrease of $0.6 million and $1.1 million, respectively, over the amounts spent during the comparable periods in 2001. These decreases are due to the completion of technical and commercial feasibility studies for both the Qatar and Egypt projects.
Negotiations in Qatar for an agreement to build a 185,000 barrels per day GTL plant and 118,000 barrels per day natural gas liquids (NGL) plant continue and are currently at an advanced and detailed stage. We cannot guarantee, however, that such an agreement will be realized.
In Egypt, we are currently studying alternative scenarios that could improve economics for a 90,000 barrels per day GTL plant. Continued discussions have resulted in the Ministry of Petroleum’s willingness to consider alternative configurations to the plant design. In Oman, we have made preliminary proposals for plant sizes ranging from 45,000 — 90,000 barrels per day. The Ministry of Oil and Gas has been studying our proposals and are expected to shortly conclude their deliberations.
We continue to work with Japanese companies on a commercialization study to optimize the commercial structure for utilization of GTL and NGL products produced in our planned Qatar project. As part of the study, testing of the GTL diesel has been completed by various Japanese automotive interests in an effort to gain acceptance of GTL fuel in that marketplace. A market analysis for the Asia/Pacific region and for a portion of Europe has been completed. Remaining analysis of western and eastern Europe and U.S. markets will be completed before the end of November 2002.
Page 14 of 22
Development of a project-financing plan utilizing Japanese and global resources is continuing.
In June 2002 we signed a letter of intent with Syntroleum to participate in the Syntroleum — U.S. Department of Energy Fuels Project at a cost of $5 million. Participation is contingent upon our finalizing and signing the GTL agreement in Qatar. The goal of the project is to establish GTL diesel production from a demonstration plant in such volumes so as to supply adequate quantities to various GTL fuel field trials. Participation allows us sufficient supplies of GTL diesel and naphtha to provide samples to potential buyers. Additionally, we will have access to the demonstration plant for the purpose of gaining operational experience and training future operations personnel. The project cost is to be offset by $2 million of our investment in Syntroleum’s Sweetwater project in Australia, which was recently cancelled.
Non-Cash Working Capital
Our non-cash working capital decreased $0.8 million and $3.1 million for the three and nine month periods ended September 30, 2002, respectively. Receivables and other current assets increased $1.3 million during the first nine months of 2002, primarily as a result of advances to Aera for the purchase of items required to complete the NWLH 1-22 well and the payment of a refundable guarantee for our six-month hedge contract. Payables decreased $1.8 million during the first nine months of 2002, primarily as a result of payment of all Daqing liabilities prior to its sale in January 2002, employee compensation deferred from 2001 and other trade payables.
Liquidity and Capital Resources:
As at September 30, 2002, our 2002 capital expenditure budget is $18.0 million, a reduction of $27.0 million from earlier budget estimates, largely due to delays in finalizing the Sichuan and GTL agreements as well as the current unfavorable capital market environment, which has hindered our ability to fund exploration and development activities. Our capital expenditure budget for the fourth quarter of 2002 of $1.5 million will be funded from existing cash balances, cash flows from operations and further sales of non-core assets.
We view the Sunwing and CITIC strategic alliance as a key step in potentially accessing the Asian capital markets to fund our China exploration and development programs. The alliance is expected to raise Sunwing’s profile and enhance its credibility among Asian institutional investors with the objective of listing Sunwing’s shares on the Stock Exchange of Hong Kong.
We undertook measures during the third quarter of 2002 to better position ourselves for the next several months when we believe one or more of our three major upside potential projects will materialize and access to capital markets will become more accommodating. This included employee and overhead cost reductions, sale of non-core wells in the Spraberry field and the hedging of crude oil prices for a portion of our U.S. production. Additionally, we are optimistic that our cyclic steam program in South Midway will continue to generate good cash flow levels and that these results will be further enhanced by our plans to drill another 20 wells in the coming year. We will continue to pursue sales of non-core assets and pursue joint venture partners to implement our capital programs when opportunities arise.
During the nine months ended September 30, 2002 we raised $10.0 million through the issuance of common shares. Additional funding will be required to complete future capital programs through a combination of equity, debt and joint venture partner participation. We cannot assure you that we will be successful in raising the additional
Page 15 of 22
funds necessary or securing joint venture partners to complete our capital programs. If we are unsuccessful, we will have to prioritize our capital programs, which may result in delaying and potentially losing some valuable business opportunities.
Forward-Looking Statements
With the exception of historical information, certain matters discussed in this Form 10-Q are forward looking statements that involve risks and uncertainties. Certain statements contained in this Form 10-Q, including statements which may contain words such as “could”, “should”, “expect”, “believe”, “will” and similar expressions and statements relating to matters that are not historical facts are forward-looking statements. Such forward-looking statements involve known and unknown risks and uncertainties which may cause our actual results, performances or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, our ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of gas-to-liquids development technology, the prices of goods and services, the availability of drilling rigs and other support services, legislative and government regulations, political and economic factors in countries in which we operate and implementation of our capital investment program.
| Item 3. | Quantitative and Qualitative Disclosures About Market Risk |
During the quarter ended September 30, 2002 we took steps to mitigate fluctuations in our cash flows as a result of changes in oil prices by entering into a costless collar hedge with a ceiling price of $28.95 per barrel and a floor price of $24.00 per barrel using WTI as the index traded on the NYMEX. The hedge is on the first 500 barrels of oil produced per day in the U.S. for a six-month period starting October 2002. We will continue to use our hedge strategy in a prudent manner to take advantage of high oil prices and to manage our cash flows from large fluctuations in commodity prices.
| Item 4. | Controls and Procedures |
Within 90 days prior to the date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s CEO and CFO, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to the 1934 Securities Exchange Act. Based upon that evaluation, the CEO and CFO concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information required to be included in the Company’s periodic SEC filings relating to the Company (including its consolidated subsidiaries). There were no significant changes in our internal controls or in other factors that could significantly affect our internal controls subsequent to the date of their evaluation, nor any significant deficiencies or material weaknesses in such internal controls requiring corrective actions. As a result, no corrective actions were taken.
Page 16 of 22
Part II – Other Information
| Item 1. | Legal Proceedings: None |
| Item 2. | Changes in Securities and Use of Proceeds: None |
| Item 3. | Defaults Upon Senior Securities: None |
| Item 4. | Submission of Matters To a Vote of Securityholders: None |
| Item 5. | Other Information: None |
| Item 6. | Exhibits and Reports on Form 8-K |
(a) Exhibits
| Exhibit | ||||
| Number | Description | |||
| 99.1 | Certification by the Chief Executive Officer Relating to a Periodic Report Containing Financial Statements | |||
| 99.2 | Certification by the Chief Financial Officer Relating to a Periodic Report Containing Financial Statements | |||
(b) Reports on Form 8-K.
None
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
IVANHOE ENERGY INC.
|
By:
|
/s/ John O’Keefe | ||
|
Name:
|
John O’Keefe | ||
|
Title:
|
Executive Vice-President and Chief Financial Officer |
Dated: November 12, 2002
Page 17 of 22
CERTIFICATION BY THE CHIEF EXECUTIVE OFFICER AND
I, E. Leon Daniel, certify that:
| 1. | I have reviewed this quarterly report on Form 10-Q of Ivanhoe Energy Inc.; |
| 2. | Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; |
| 4. | The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: |
| a.) | designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; |
| b.) | evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and |
| c.) | presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
| 5. | The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): |
| a.) | all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and |
| b.) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and |
| 6. | The registrant’s other certifying officers and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. |
Date: November 12, 2002
Chief Executive Officer
|
By:
|
/s/ E. Leon Daniel | ||
| E. Leon Daniel |
Page 18 of 22
I, John O’Keefe, certify that:
| 1 | I have reviewed this quarterly report on Form 10-Q of Ivanhoe Energy Inc.; |
| 2 | Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report. |
| 3 | Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; |
| 4 | The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: |
| a. | designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; |
| b. | evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and |
| c. | presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
| 5 | The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): |
| a. | all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and |
| b. | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and |
| 6 | The registrant’s other certifying officers and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. |
Date: November 12, 2002
Chief Financial Officer
|
By:
|
/s/ John O’Keefe | ||
| John O’Keefe |
Page 19 of 22
INDEX TO EXHIBITS
| Exhibit | ||||
| Number | Description | |||
| 99.1 | Certification by Chief Executive Officer Relating to a Periodic Report Containing Financial Statements | |||
| 99.2 | Certification by Chief Financial Officer Relating to a Periodic Report Containing Financial Statements | |||
Page 20 of 22