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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

     
x   Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
For the quarterly period ended September 30, 2004
     
or    
     
o   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.

(Exact name of registrant as specified in its charter)
     
Yukon, Canada
(State or other jurisdiction of
incorporation or organization)
  98-0372413
(I.R.S. Employer
Identification No.)

Suite 654 — 999 Canada Place
Vancouver, British Columbia, Canada
V6C 3E1

(Address of principal executive office)

(604) 688-8323

(registrant’s telephone number, including area code)

Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report: Not Applicable

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.

Yes     x                     No     o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)

Yes     x                     No     o

The number of shares of the registrant’s capital stock outstanding as of September 30, 2004 was 169,604,911 Common Shares, no par value.

 


 

TABLE OF CONTENTS

                 
            Page
PART I  
Financial Information
       
Item 1  
Financial Statements
       
       
Unaudited Consolidated Balance Sheets as at September 30, 2004 and December 31, 2003 (restated)
    3  
       
Unaudited Consolidated Statements of Loss and Deficit for the Three-Month and Nine-Month Periods Ended September 30, 2004 and 2003 (restated)
    4  
       
Unaudited Consolidated Statements of Cash Flow for the Three-Month and Nine-Month Periods Ended September 30, 2004 and 2003 (restated)
    5  
       
Notes to the Unaudited Consolidated Financial Statements
    6  
Item 2.  
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    13  
Item 3.  
Quantitative and Qualitative Disclosures About Market Risks
    22  
Item 4.  
Controls and Procedures
    22  
               
PART II  
Other Information
       
Item 1.  
Legal Proceedings
    23  
Item 2.  
Unregistered Sales of Equity Securities and Use of Proceeds
    23  
Item 3.  
Defaults Upon Senior Securities
    23  
Item 4.  
Submission of Matters To a Vote of Securityholders
    23  
Item 5.  
Other Information
    23  
Item 6.  
Exhibits and Reports on Form 8-K
    23  

2


 

Part I — Financial Information

Item 1 Financial Statements

IVANHOE ENERGY INC.
Unaudited Consolidated Balance Sheets

(stated in thousands of U.S. Dollars except share amounts)

                 
    September 30, 2004
  December 31, 2003
            (restated
            Notes 2 and 7)
Assets
               
Current Assets
               
Cash and cash equivalents
  $ 18,571     $ 14,491  
Accounts receivable
    4,923       2,720  
Other
    338       409  
 
   
 
     
 
 
 
    23,832       17,620  
Long term assets
    4,222       998  
Oil and gas properties, equipment and investments, net
    102,821       87,956  
 
   
 
     
 
 
 
  $ 130,875     $ 106,574  
 
   
 
     
 
 
Liabilities and Shareholders’ Equity
               
Current Liabilities
               
Accounts payable and accrued liabilities
  $ 5,148     $ 4,516  
Note payable — current portion
    1,667       167  
 
   
 
     
 
 
 
    6,815       4,683  
 
   
 
     
 
 
Note payable
    3,056       833  
 
   
 
     
 
 
Asset retirement obligations
    659       521  
 
   
 
     
 
 
Commitments and contingencies
               
                 
Shareholders’ Equity
               
Share capital, issued 169,604,911 common shares; December 31, 2003 161,359,339 common shares
    183,528       161,075  
Contributed surplus
    1,412       516  
Deficit
    (64,595 )     (61,054 )
 
   
 
     
 
 
 
    120,345       100,537  
 
   
 
     
 
 
 
  $ 130,875     $ 106,574  
 
   
 
     
 
 

(See accompanying notes)

3


 

IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Loss and Deficit

(stated in thousands of U.S. Dollars except per share amounts)

                                 
    Three Months   Nine Months
    Ended September 30,
  Ended September 30,
    2004
  2003
  2004
  2003
        (restated       (restated
        Notes 2 and 7)       Notes 2 and 7)
Revenue
                               
Oil and gas revenue
  $ 4,874     $ 2,405     $ 11,638     $ 7,269  
Interest income
    58       18       147       60  
 
   
 
     
 
     
 
     
 
 
 
    4,932       2,423       11,785       7,329  
 
   
 
     
 
     
 
     
 
 
Expenses
                               
Operating costs
    1,257       1,148       3,688       2,993  
General and administrative
    2,336       1,689       6,149       5,453  
Depletion and depreciation
    2,290       915       5,239       2,586  
Write down of GTL investments
                250       3,321  
 
   
 
     
 
     
 
     
 
 
 
    5,883       3,752       15,326       14,353  
 
   
 
     
 
     
 
     
 
 
Net Loss
    951       1,329       3,541       7,024  
 
   
 
     
 
     
 
     
 
 
Deficit, beginning of period, as previously reported
    63,644       36,027       60,267       30,564  
Retroactive application of change in accounting policy for stock based compensation
          543       787       311  
 
   
 
     
 
     
 
     
 
 
Deficit, beginning of the period, as restated
    63,644       36,570       61,054       30,875  
 
   
 
     
 
     
 
     
 
 
Deficit, end of period
  $ 64,595     $ 37,899     $ 64,595     $ 37,899  
 
   
 
     
 
     
 
     
 
 
Net Loss per share — Basic and Diluted
  $ 0.01     $ 0.01     $ 0.02     $ 0.05  
 
   
 
     
 
     
 
     
 
 
Weighted Average Number of Shares (in thousands)
    169,534       151,088       166,935       146,940  
 
   
 
     
 
     
 
     
 
 

(See accompanying notes)

4


 

IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Cash Flow

(stated in thousands of U.S. Dollars)

                                 
    Three Months   Nine Months
    Ended September 30,
  Ended September 30,
    2004
  2003
  2004
  2003
            (restated           (restated
            Notes 2 and 7)           Notes 2 and 7)
Operating Activities
                               
Net loss
  $ (951 )   $ (1,329 )   $ (3,541 )   $ (7,024 )
Items not requiring use of cash
                               
Depletion and depreciation
    2,290       915       5,239       2,586  
Write down of GTL investments
                250       3,321  
Stock based compensation
    430       123       911       355  
Changes in non-cash working capital items
    (1,969 )     (468 )     (1,725 )     1,182  
 
   
 
     
 
     
 
     
 
 
 
    (200 )     (759 )     1,134       420  
 
   
 
     
 
     
 
     
 
 
Investing Activities
                               
Capital spending
    (8,389 )     (4,097 )     (33,745 )     (8,870 )
Equity investment and other related costs
    (653 )           (3,153 )      
Proceeds from sale of assets
                13,458        
Changes in non-cash working capital items
    (4,559 )     (790 )     572       (81 )
 
   
 
     
 
     
 
     
 
 
 
    (13,601 )     (4,887 )     (22,868 )     (8,951 )
 
   
 
     
 
     
 
     
 
 
Financing Activities
                               
Shares issued on private placements, net of share issue costs
          11,603       20,428       11,603  
Shares issued on exercise of options
    289       134       1,664       134  
Proceeds from notes and advances
    2,000             14,000       1,750  
Payments of notes
    (278 )     (1,250 )     (278 )     (1,250 )
Redemption of advance payable
                (10,000 )      
 
   
 
     
 
     
 
     
 
 
 
    2,011       10,487       25,814       12,237  
 
   
 
     
 
     
 
     
 
 
Increase (decrease) in cash and cash equivalents, for the period
    (11,790 )     4,841       4,080       3,706  
Cash and cash equivalents, beginning of period
    30,361       2,845       14,491       3,980  
 
   
 
     
 
     
 
     
 
 
Cash and cash equivalents, end of period
  $ 18,571     $ 7,686     $ 18,571     $ 7,686  
 
   
 
     
 
     
 
     
 
 
Included in the above are the following:
                               
Taxes paid
  $     $     $ 3     $ 6  
 
   
 
     
 
     
 
     
 
 
Interest paid
  $ 52     $ 43     $ 80     $ 85  
 
   
 
     
 
     
 
     
 
 
Changes in non-cash working capital items Operating Activities:
                               
Accounts receivable
  $ (849 )   $ (423 )   $ (1,705 )   $ (43 )
Other current assets
    40       51       71       563  
Accounts payable and accrued liabilities
    (1,160 )     (96 )     (91 )     662  
 
   
 
     
 
     
 
     
 
 
 
    (1,969 )     (468 )     (1,725 )     1,182  
 
   
 
     
 
     
 
     
 
 
Investing Activities
Accounts receivable
    655             (498 )      
Accounts payable and accrued liabilities
    (5,214 )     (790 )     1,070       (81 )
 
   
 
     
 
     
 
     
 
 
 
    (4,559 )     (790 )     572       (81 )
 
   
 
     
 
     
 
     
 
 
 
  $ (6,528 )   $ (1,258 )   $ (1,153 )   $ 1,101  
 
   
 
     
 
     
 
     
 
 

(See accompanying notes)

5


 

Notes to the Consolidated Financial Statements
September 30, 2004

(all tabular amounts are expressed in thousands of U.S. dollars except per share data)
(Unaudited)

1. BASIS OF PRESENTATION

The Company’s accounting policies are in accordance with accounting principles generally accepted in Canada. These policies are consistent with accounting principles generally accepted in the U.S., except as outlined in Note 13. The unaudited consolidated financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2003 consolidated financial statements, except for a change in the policy of accounting for stock based compensation which has been implemented retroactively with a restatement of prior period financial statements, and should be read in conjunction therewith. These interim consolidated financial statements do not include all disclosures normally provided in annual consolidated financial statements and should be read in conjunction with the most recent annual consolidated financial statements. The December 31, 2003 consolidated balance sheet, as restated, 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. In the opinion of management, all adjustments (which included normal recurring adjustments) necessary for the fair presentation for the interim periods have been made. 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 disclosures in these consolidated financial statements. Actual results may differ from those estimates.

2. CHANGE IN ACCOUNTING POLICY

Prior to January 1, 2004, the Company accounted for options granted to employees and directors using the intrinsic-value of the options. Under this method, compensation costs were not recognized in the financial statements for share options granted at market value but rather disclosure was required, on a pro forma basis, of the impact on net income of using the fair value at the option grant date. The Company does, however, recognize compensation costs in its financial statements for options granted to non-employees after January 1, 2002 based on the fair value of the options at the date granted. The Company uses the Black-Scholes option pricing model for determining the fair value of options issued at grant date.

For fiscal years beginning on or after January 1, 2004, Canadian GAAP requires compensation costs to be recognized in the financial statements using the fair value based method of accounting for all stock options granted after January 1, 2002. Implementation of this change in accounting policy requires retroactive application with the option of restating financial statements of prior periods.

Accordingly, effective January 1, 2004, the Company changed its accounting policy, for Canadian GAAP purposes, to recognize compensation costs using the fair value based method of accounting for stock options granted to employees and directors after January 1, 2002. This change has been adopted retroactively and the Company has elected to restate the financial statements of prior periods (See Note 7).

6


 

3. OIL AND GAS PROPERTIES, EQUIPMENT AND INVESTMENTS

Capital assets categorized by geographical location are as follows:

                                                 
    As at September 30, 2004
  As at December 31, 2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Oil and Gas Properties and Equipment:
  $ 98,472     $ 38,016     $ 136,488     $ 85,079     $ 32,840     $ 117,919  
Accumulated depletion
    (9,812 )     (5,564 )     (15,376 )     (6,442 )     (3,804 )     (10,246 )
Provision for impairment
    (34,000 )           (34,000 )     (34,000 )           (34,000 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    54,660       32,452       87,112       44,637       29,036       73,673  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
GTL Investments:
                                               
Master License
    10,000             10,000       10,000             10,000  
Feasibility studies and other deferred costs
    3,765             3,765       3,947             3,947  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    13,765             13,765       13,947             13,947  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
EOR Investments:
                                               
Feasibility studies and other deferred costs
    1,748             1,748       125             125  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Support Equipment
    459       35       494       433       31       464  
Accumulated depreciation
    (298 )           (298 )     (253 )           (253 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    161       35       196       180       31       211  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 70,334     $ 32,487     $ 102,821     $ 58,889     $ 29,067     $ 87,956  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

In January 2004, the Company signed farm-out and joint operating agreements with Richfirst Holdings Limited (“Richfirst”), a wholly owned subsidiary of China International Trust & Investment Company to jointly develop the Dagang oil project. Richfirst acquired a 40% working interest in the project for $20.0 million following Chinese regulatory approvals, which were finalized in June 2004 (See Note 9). The carrying value of the Company’s oil and gas assets was reduced by $13.5 million for the amount of the proceeds associated with the sale of the working interest. The reduction in the carrying value does not significantly alter the depletion rate of the China oil and gas assets. The $6.5 million balance of the proceeds will fund a portion of Richfirst’s share of future Dagang oil project costs and the unspent balance was $0.8 million as at September 30, 2004.

As a result of the Company’s on-going evaluation of its GTL investments, $0.3 million of its investments were written down for the three-month period ended June 30, 2004 as the opportunity to build a 45,000-barrels per day GTL fuels plant in Oman failed to materialize due to a lack of sufficient uncommitted gas volumes to support a plant of that size.

4. LONG TERM ASSETS

In January 2004, the Company signed a Stock Purchase and Shareholders’ Agreement with Ensyn Group Inc. (“Ensyn Group”) and its subsidiary, Ensyn Petroleum International Ltd. (“Ensyn”), pursuant to which the Company acquired a 10% equity interest in Ensyn and exclusive rights to deploy the proprietary Ensyn RTPTM Process in several key international markets. The Company paid $2.0 million and will grant Ensyn rights to acquire equity interests in the Company’s international oil development projects that use the Ensyn RTPTM Process.

In August 2004, the Company acquired an additional 5% equity interest in Ensyn for $1.0 million. As at September 30, 2004, the 15% investment in Ensyn and related costs of $0.7 million are included in long-term assets (See Note 12).

7


 

5. SEGMENT INFORMATION

The following tables present the Company’s interim segment information for the three-month and nine-month periods ended September 30, 2004 and 2003 and identifiable assets as at September 30, 2004 and December 31, 2003:

                                                 
    Three Month Periods Ended September 30,
    2004
  2003
                            (restated Notes 2 and 7)
    U.S.
  China
  Total
  U.S.
  China
  Total
Oil and gas revenue
  $ 2,628     $ 2,246     $ 4,874     $ 1,385     $ 1,020     $ 2,405  
Interest income
    46       12       58       18             18  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    2,674       2,258       4,932       1,403       1,020       2,423  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    863       394       1,257       630       518       1,148  
Depletion and depreciation
    1,605       685       2,290       588       327       915  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    2,468       1,079       3,547       1,218       845       2,063  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Segment income before the following
  $ 206     $ 1,179       1,385     $ 185     $ 175       360  
 
   
 
     
 
             
 
     
 
         
General and administrative
                    2,336                       1,689  
 
                   
 
                     
 
 
Net loss
                  $ 951                     $ 1,329  
 
                   
 
                     
 
 
Capital Expenditures:
                                               
Oil and gas
  $ 3,400     $ 4,480     $ 7,880     $ 2,831     $ 1,144     $ 3,975  
Gas-to-liquids and EOR Investments
    509             509       122             122  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 3,909     $ 4,480     $ 8,389     $ 2,953     $ 1,144     $ 4,097  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
                                                 
    Nine Month Periods Ended September 30,
    2004
  2003
                            (restated Notes 2 and 7)
    U.S.
  China
  Total
  U.S.
  China
  Total
Oil and gas revenue
  $ 6,428     $ 5,210     $ 11,638     $ 4,074     $ 3,195     $ 7,269  
Interest income
    135       12       147       60             60  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    6,563       5,222       11,785       4,134       3,195       7,329  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    2,294       1,394       3,688       1,643       1,350       2,993  
Depletion and depreciation
    3,479       1,760       5,239       1,576       1,010       2,586  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    5,773       3,154       8,927       3,219       2,360       5,579  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Segment income before the following
  $ 790     $ 2,068       2,858     $ 915     $ 835       1,750  
 
   
 
     
 
             
 
     
 
         
Write down of GTL investments
                    250                       3,321  
General and administrative
                    6,149                       5,453  
 
                   
 
                     
 
 
Net loss
                  $ 3,541                     $ 7,024  
 
                   
 
                     
 
 
Capital expenditures:
                                               
Oil and gas
  $ 13,423     $ 18,632     $ 32,055     $ 5,500     $ 2,835     $ 8,335  
Gas-to-liquids and EOR Investments
    1,690             1,690       535             535  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 15,113     $ 18,632     $ 33,745     $ 6,035     $ 2,835     $ 8,870  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
                                                 
    As at September 30, 2004
  As at December 31, 2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Identifiable Assets:
                                               
Oil & gas
  $ 79,441     $ 35,526     $ 114,967     $ 61,379     $ 30,766     $ 92,145  
Gas-to-liquids and EOR Investments
    15,908             15,908       14,429             14,429  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 95,349     $ 35,526     $ 130,875     $ 75,808     $ 30,766     $ 106,574  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

8


 

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, 2004:

                                 
    Common Shares
  Stock Options
                            Weighted
                            Average
                            Exercise
    Number           Number   Price
    (thousands)
  Amount
  (thousands)
  Cdn.$
        (restated Notes 2        
        and 7)        
Balance December 31, 2003, as previously reported
    161,359     $ 160,804       8,949     $ 2.64  
Retroactive application of change in accounting policy for stock based compensation
          271                  
 
   
 
     
 
     
 
         
Balance December 31, 2003, as restated
    161,359       161,075       8,949     $ 2.64  
Shares issued on private placements, net of share issue costs
    7,173       20,428                
Shares issued for services
    158       347                
Shares issued on exercise of options
    915       1,678       (915 )   $ 2.49  
Options granted
                458     $ 2.38  
Options expired
                (240 )   $ 2.35  
 
   
 
     
 
     
 
         
Balance September 30, 2004
    169,605     $ 183,528       8,252     $ 2.65  
 
   
 
     
 
     
 
         

In the first quarter of 2004, the Company closed two special warrant financings to advance its international and North American oil and gas operations and for general corporate purposes. The financings consisted of 7,172,414 special warrants at $2.90 per special warrant. Each special warrant entitles the holder to acquire one common share and one common-share purchase warrant at no additional cost. Two common-share purchase warrants are exercisable to purchase an additional common share at $3.00 at any time on or prior to the first anniversary date following the special warrant date of issue and at $3.20 thereafter until the second anniversary date of the special warrant date of issue. The net proceeds from the special warrant financings have been apportioned to the common shares. No amounts have been apportioned to the purchase warrants.

The following common-share purchase warrants are outstanding and exercisable as at September 30, 2004:

                                         
Remaining   Number of   First Anniversary
  Second Anniversary
Number of   Equivalent           Price per           Price per
Purchase   Common           Share           Share
Warrants
  Shares
  Date
  (US$)
  Date
  (US$)
(thousands)
                               
3,000
    1,500                 July 3, 2005     $1.10  
3,000
    1,500                 August 18, 2005     $1.10  
3,029
    1,515                 August 21, 2005     $1.87  
1,250
    1,250     October 31, 2004     $4.00     October 31, 2005     $4.30  
5,448
    2,724     February 18, 2005     $3.00     February 18, 2006     $3.20  
1,724
       862     March 5, 2005     $3.00     March 5, 2006     $3.20  

 
   
 
                                 
17,451
    9,351                                  

 
   
 
                                 

7. STOCK BASED COMPENSATION

The Company accounts for all stock options granted using the fair value based method of accounting. This method was adopted retroactively effective January 1, 2004 for stock options granted to employees and directors after January 1, 2002. Under this method, compensation costs are recognized in the financial statements over the options’ vesting period using an option-pricing model for determining the fair value of the options at the grant date.

9


 

The effect of the accounting change on the net loss for the three-month and nine-month periods ended September 30, 2004 was an increase of $0.4 million and $0.9 million, respectively, and on the net loss for the three-month and nine-month periods ended September 30, 2003, as previously reported, was an increase of $0.1 million and $0.4 million, respectively. There is negligible effect on the net loss per share for the periods presented. The deficit as at the beginning of the nine-month periods ended September 30, 2004 and 2003 has increased $0.8 million and $0.3 million, respectively, to reflect the retroactive adoption of the fair value based method of accounting for stock options granted to employees and directors after January 1, 2002. Additionally, 0.3 million options granted to employees and directors after January 1, 2002 were exercised during the third and fourth quarters of 2003 resulting in a $0.3 million increase in share capital as at December 31, 2003 with a corresponding reduction in contributed surplus.

The fair values were calculated in accordance with the Black-Scholes option pricing model, using the following data and assumptions: 72% to 110% expected price volatility, using the prior two years weekly average prices of the Company’s common shares; expected dividend yield of 0%; option terms to expiry of 5 years, as defined by the option agreements; risk-free rate of return as of the date of the grant of 3.5% to 5.6%, based on five year Canada Bond yields.

8. NOTE PAYABLE

In February 2003, the Company obtained a bank facility for up to $5.0 million to drill 30 new oil wells and upgrade surface transmission and steam injection facilities in the southern expansion of South Midway. The loan is repayable over three years plus interest at 0.50% above the bank’s prime rate or 3.0% over LIBOR, at the option of the Company. The loan is secured by all the Company’s rights and interests in the South Midway properties. The loan balance as at September 30, 2004 is $4.7 million with a six month LIBOR interest rate of 5.25%.

9. ADVANCE PAYABLE

In March 2004, the Company received a $10.0 million advance as part of the $20.0 million up-front payment due from Richfirst for their farm-in to the Dagang oil project (See Note 3). Upon finalization of the farm-in agreement in June 2004, Richfirst elected to apply $10.0 million of the up-front payment due to the Company against the advance.

10. ASSET RETIREMENT OBLIGATION

The undiscounted amount of expected cash flows required to settle the Company’s asset retirement obligations is estimated at $1.2 million to be settled over a twelve-year period starting in 2010. The liability for the expected cash flows, as reflected in the financial statements, has been discounted at 5% to 7%.

11. COMMITMENTS AND CONTINGENCIES

With the signing of the production-sharing contract in September 2002 for the Zitong block, the Company is obligated to conduct a minimum exploration program during the first three years, which will include acquiring seismic data, reprocessing existing seismic and drilling two exploration wells. At the end of the three-year period, if the Company does not complete the minimum exploration program, and elects not to continue, it will be obligated to pay, to PetroChina within 30 days, a cash equivalent of the deficiency in the work program. The remaining cost of the minimum exploration program is estimated to be at least $10.7 million as at September 30, 2004.

10


 

The Company has temporarily abandoned the Northwest Lost Hills #1-22 well pending the identification of one or more partners to share the costs of the testing program. If the well were permanently abandoned, the Company would be obligated for its share of the costs to plug and abandon the well, which is estimated to be $1.1 million. There is no provision in the balance sheet for this contingent obligation.

12. SUBSEQUENT EVENT

In October 2004, the Company signed an agreement with Ensyn Group and Ensyn pursuant to which the Company will pay $1.0 million as consideration for an option to acquire an additional 5% equity interest in Ensyn for $4.0 million. The option expires 15 business days after December 31, 2004.

13. ADDITIONAL DISCLOSURE REQUIRED UNDER U.S. GAAP

The consolidated financial statements have been prepared in accordance with Canadian GAAP, which conforms to U.S. GAAP except as below:

Consolidated Balance Sheets

As discussed under “Stock Based Compensation” in Note 7, the Company changed its accounting policy, for Canadian GAAP, to recognize compensation costs using the fair value based method of accounting for stock options granted to employees and directors after January 1, 2002. For U.S. GAAP, the Company continues to apply APB Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for its stock option plan and does not recognize compensation costs in its financial statements for stock options issued to employees and directors. Accordingly, for U.S. GAAP purposes, share capital would be reduced by $0.3 million as at September 30, 2004 and December 31, 2003 related to the employees’ and directors’ exercise of options in 2003; contributed surplus would be reduced by $1.4 million and $0.5 million as at September 30, 2004 and December 31, 2003, respectively, for stock options issued to employees and directors, but not yet exercised; and the deficit as at September 30, 2004 and December 31, 2003 would be reduced by $1.7 million and $0.8 million, respectively, for the amount of stock based compensation expense recognized for Canadian GAAP.

The application of U.S. GAAP has the following effect on oil and gas properties and shareholders’ equity:

                                 
    As at September 30, 2004
  As at December 31, 2003
    Oil and Gas   Shareholders’   Oil and Gas   Shareholders’
    Properties
  Equity
  Properties
  Equity
Canadian GAAP
  $ 102,821     $ 120,345     $ 87,956     $ 100,537  
Adjustment to ascribed value of shares issued for royalty interests
    1,358       1,358       1,358       1,358  
Impairment provision for China properties, net of depletion
    (9,690 )     (9,690 )     (9,834 )     (9,834 )
GTL and EOR development costs written off
    (5,513 )     (5,513 )     (4,074 )     (4,074 )
Adjustment for change in accounting for stock based compensation:
                               
Share capital
          (271 )           (271 )
Contributed surplus
          (1,393 )           (516 )
Deficit
          1,664             787  
 
   
 
     
 
     
 
     
 
 
U.S. GAAP
  $ 88,976     $ 106,500     $ 75,406     $ 87,987  
 
   
 
     
 
     
 
     
 
 

11


 

Under U.S. GAAP, the transfer of deficit to share capital, which occurred in 1999, would not be recognized and shareholders’ equity would be presented as follows:

                 
    September 30,   December 31,
    2004
  2003
Share capital (including adjustments above)
  $ 259,071     $ 236,617  
Contributed surplus (non-employee stock based compensation)
    19        
Deficit (Including adjustments above)
    (152,590 )     (148,630 )
 
   
 
     
 
 
 
  $ 106,500     $ 87,987  
 
   
 
     
 
 

Consolidated Statements of Loss and Deficit

As discussed under “Oil and Gas Properties” in Note 20 of the Company’s December 31, 2003 consolidated financial statements, there is a difference in performing the ceiling test evaluation under full cost accounting between U.S. and Canadian GAAP. Application of the ceiling test evaluation under U.S. GAAP as at December 31, 2001 required an additional $10.0 million provision for impairment with respect to the Company’s China properties. This difference results in a lower depletion rate for U.S. GAAP.

The capitalization of development costs permitted under Canadian GAAP in connection with our GTL and EOR prospects is not permitted under U.S. GAAP.

The application of U.S. GAAP has the following effect on net loss and net loss per share:

                                 
    Three Month Periods Ended September 30,
    2004
  2003
    Net   Net Loss   Net   Net Loss
    Loss
  Per Share
  Loss
  Per Share
Canadian GAAP
  $ 951     $ 0.01     $ 1,329     $ 0.01  
Stock based compensation expense
    (416 )           (123 )      
Depletion adjustment — China
    (64 )           (22 )      
GTL and EOR development costs written off, net
    509             122        
 
   
 
     
 
     
 
     
 
 
U.S. GAAP
  $ 980     $ 0.01     $ 1,306     $ 0.01  
 
   
 
     
 
     
 
     
 
 
Weighted Average Number of Shares under U.S. GAAP (in thousands)
            169,534               151,088  
 
           
 
             
 
 
                                 
    Nine Month Periods Ended September 30,
    2004
  2003
    Net   Net Loss   Net   Net Loss
    Loss
  Per Share
  Loss
  Per Share
Canadian GAAP
  $ 3,541     $ 0.02     $ 7,024     $ 0.05  
Stock based compensation expense
    (877 )           (355 )      
Depletion adjustment — China
    (144 )           (66 )      
GTL and EOR development costs written off, net
    1,440             (2,786 )     (0.02 )
 
   
 
     
 
     
 
     
 
 
U.S. GAAP
  $ 3,960     $ 0.02     $ 3,817     $ 0.03  
 
   
 
     
 
     
 
     
 
 
Weighted Average Number of Shares under U.S. GAAP (in thousands)
            166,935               146,940  
 
           
 
             
 
 

Stock Based Compensation

Had compensation expense been determined based on the fair value of options issued to employees and directors at the stock option grant date, including those granted prior to January 1, 2002, consistent with the method of SFAS No. 123, “Accounting for Stock-Based Compensation”, the Company’s net loss and net loss per share would have been as follows:

12


 

                                 
    Three Month Periods   Nine Month Periods
    Ended September 30,
  Ended September 30,
    2004
  2003
  2004
  2003
Net loss under U.S. GAAP
  $ 980     $ 1,306     $ 3,960     $ 3,817  
Stock-based compensation expense determined under the fair value based method for employee and director awards
    507       428       1,499       1,235  
 
   
 
     
 
     
 
     
 
 
Pro forma net loss under U.S. GAAP
  $ 1,487     $ 1,734     $ 5,459     $ 5,052  
 
   
 
     
 
     
 
     
 
 
Basic and diluted loss per common share under U.S. GAAP:
                               
As reported
  $ 0.01     $ 0.01     $ 0.02     $ 0.03  
Pro forma
  $ 0.01     $ 0.01     $ 0.03     $ 0.03  
Weighted Average Number of Shares under U.S. GAAP (in thousands)
    169,534       151,088       166,935       146,940  

Impact of New and Pending U.S. GAAP Accounting Standards

In March 2004, the FASB issued an exposure draft “Share-Based Payment”. This exposure draft proposes to revoke the alternative of accounting for employee stock based compensation under the intrinsic value method. As the Company is currently using the provision under SFAS 123 that allow the use of the intrinsic method of accounting for share-based payments, it is anticipated that the adoption of this exposure draft may have a material impact on the Company’s results of operations or financial position. However, at this time the exposure draft has neither been accepted nor rejected by the FASB. If adopted, the application of this policy is expected to be for interim or annual periods beginning after June 15, 2005.

In June 2004, the FASB issued an exposure draft of a proposed statement, “Fair Value Measurements” to provide guidance on how to measure the fair value of financial and non-financial assets and liabilities when required by other authoritative accounting pronouncements. The proposed statement attempts to address concerns about the ability to develop reliable estimates of fair value and inconsistencies in fair value guidance provided by current U.S. GAAP, by creating a framework that clarifies the fair value objective and its application in GAAP. In addition, the proposal expands disclosures required about the use of fair value to re-measure assets and liabilities. The standard would be effective for financial statements issued for fiscal years beginning after June 15, 2005.

In September of 2004, the SEC released Staff Accounting Bulletin No. 106, which provides guidance regarding the interaction of Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations (SFAS 143) with the full cost accounting rules in Article 4-10 of Regulation S-X. This bulletin clarifies the treatment of assets and liabilities resulting from the implementation of SFAS 143 on the full cost ceiling test and the calculation of depletion, depreciation and amortization. The Company is in compliance with the provisions of Staff Accounting Bulletin No. 106.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 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

13


 

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 heavy-to-light and gas-to-liquids development technologies, 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.

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, 2003, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. 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

For the three-month period ended September 30, 2004, the net loss was $1.0 million ($0.01 per share) compared to a net loss of $1.3 million ($0.01 per share) for the same period in 2003. The net loss for the nine-month period ended September 30, 2004 was $3.5 million ($0.02 per share) compared to a net loss of $7.0 million ($0.05 per share) for the same period in 2003. The net loss for the nine-month period ended September 30, 2003 includes a $3.3 million ($0.02 per share) write down of our investment in the Qatar gas-to-liquids project as a result of the termination of contract negotiations in May 2003.

Cash deficiency from operating activities for the three-month period ended September 30, 2004 was $0.2 million compared to cash deficiency from operating activities of $0.8 million for the same period in 2003. Our cash from operations for the nine-month period ended September 30, 2004 was $1.1 million compared to cash from operations of $0.4 million for the same period in 2003. Our cash position increased $4.1 million for the first nine months of 2004 primarily due to net proceeds of $20.4 million received from private placements in the first quarter of 2004, $20.0 million from Richfirst related to its farm-in to the Dagang oil project development program, $3.7 million in net proceeds from the Wells Fargo loan related to the development of our South Midway field, $1.7 million from the exercise of stock options and $1.1 million of cash from operating activities. This is partially offset by $33.7 million in capital spending for the first nine months of 2004, a $5.8 million reduction in working capital resulting from investing activities related to our China drilling program and $3.2 million related to our investment in Ensyn. Our cash position increased $3.7 million for the comparable period in 2003 primarily due to net proceeds received from private placements of $11.6 million and net loan proceeds of $0.5 million. This is partially offset by $8.9 million of capital spending.

Production and Operations

Oil and gas revenues for the three-month and nine-month periods ended September 30, 2004 were $4.9 million and $11.6 million, respectively. These represent increases of $2.5 million and $4.4 million from the comparable periods in 2003. Half of the increase in revenue for the three-month period ended September 30, 2004 is due to a 38% or $9.92 per boe increase in oil and gas prices from the comparable period in 2003. Increases in production volumes account for the remaining 50% increase in revenues. The increase in production is a result of additional development programs initiated in 2003 at the Dagang, South Midway and Daqing fields and the start up of production in 2004 at our Citrus and Knights Landing fields. Net production volumes from the Dagang field development, initiated at the end of 2003, increased 49% during the three-month period ended September 30, 2004 from the

14


 

comparable period in 2003 after giving effect to the 40% farm-in by Richfirst in the second quarter of 2004. The Dagang field achieved two sales records during the third quarter of 2004 by posting its first million-dollar month in gross oil sales of $1.2 million and topping one-million-barrels of cumulative oil sales. The increase in revenues for the nine-month period ended September 30, 2004 was mainly due to increases in production volumes, which contributed 54% or $2.3 million to the increase in total revenues for the period. Increases in production volume from the Dagang and Daqing fields contributed $1.4 million to the increase in total revenues for the period in addition to increases in production from the southern expansion of our South Midway field and the start up of production operations at our Citrus and Knights Landing fields in 2004. Additionally, a 24% or $6.46 per boe increase in oil and gas prices contributed to the remaining 46% increase in revenues for the nine-month period ended September 30, 2004.

Operating costs decreased 18% or $1.53 per boe for the three-month period ended September 30, 2004 compared to the same period in 2003. Operating costs in China decreased 43% or $3.81 per boe for the third quarter of 2004 due mainly to an increase in production from the Dagang field in relation to the level of fixed operating costs required to operate the field and reduced well workover and power costs during the third quarter 2004. Operating costs in the U.S. increased 5% or $0.38 per boe for the third quarter of 2004 as compared to the same period in 2003 due mainly to the start up of production operations at our Knights Landing and Sledge Hamar fields in the second quarter of 2004 as well as increased costs to treat the hydrogen sulfide levels in the gas produced from the South Midway field. For the nine-month period ended September 30, 2004, operating costs per boe decreased slightly compared to the same period in 2003. Operating costs in China decreased 22% or $1.81 per boe due mainly to an increase in production from the Dagang field in relation to the level of fixed operating costs required to operate the field and a reduction in well workovers and decreased power costs during 2004. Operating costs in the U.S. increased 18% or $1.29 per boe for the nine-month period ended September 30, 2004 due mainly to an increase in fuel costs incurred for the cyclic steam operations in the southern expansion of South Midway, increased costs to treat the hydrogen sulfide levels in the gas produced from the South Midway field and the start up of production operations at our Citrus, Knights Landing, and Sledge Hamar fields. This is partially offset by a reduction in workover costs at our Spraberry field from the comparable period in 2003.

Our depletion rate increased $6.97 and $5.37 per boe for the three-month and nine-month periods ended September 30, 2004, respectively, compared to the same periods in 2003. The depletion rate in China increased $2.34 and $2.07 per boe for the three-month and nine-month periods ended September 30, 2004, respectively, due mainly to anticipated increases in Dagang future development costs. The depletion rate in the U.S. increased $11.11 and $8.11 per boe for the three-month and nine-month periods ended September 30, 2004, respectively, due mainly to an increase in the carrying costs of our evaluated U.S. oil and gas assets primarily in Northwest Lost Hills, East Texas and North South Forty. In addition, the increase in the U.S. depletion rate for the three-month and nine month periods ended September 30, 2004 is due to an increase in Knights Landing exploration costs and a decrease in estimated reserves for Knights Landing as a result of reduced success in the current exploration drilling program as six dry holes had been drilled as at September 30, 2004.

15


 

Production and operating information are detailed below:

                                                 
    Three Month Periods Ended September 30,
    2004
  2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Net Production:
                                               
BOE
    72,627       62,289       134,916       53,929       37,850       91,779  
BOE/day for the year
    789       677       1,466       586       411       998  
                                                 
    Per BOE
  Per BOE
Oil and gas revenue
  $ 36.19     $ 36.05     $ 36.13     $ 25.69     $ 26.96     $ 26.21  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    8.70       4.96       6.98       8.32       8.77       8.51  
Production taxes
    0.95             0.51       0.91             0.53  
Engineering support
    2.23       1.36       1.83       2.45       4.91       3.46  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    11.88       6.32       9.32       11.68       13.68       12.50  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue before depletion
    24.31       29.73       26.81       14.01       13.28       13.71  
Depletion
    21.58       10.99       16.69       10.47       8.65       9.72  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue from operations
  $ 2.73     $ 18.74     $ 10.13     $ 3.54     $ 4.63     $ 3.99  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
                                                 
    Nine Month Periods Ended September 30,
    2004
  2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Net Production:
                                               
BOE
    191,841       158,153       349,994       159,713       111,606       271,319  
BOE/day for the year
    700       577       1,277       585       409       994  
                                                 
    Per BOE
  Per BOE
Oil and gas revenue
  $ 33.51     $ 32.94     $ 33.25     $ 25.51     $ 28.63     $ 26.79  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    8.58       6.37       7.58       7.29       8.18       7.65  
Production taxes
    1.07             0.59       0.94             0.55  
Engineering support
    2.30       2.45       2.37       2.07       3.92       2.83  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    11.95       8.82       10.54       10.30       12.10       11.03  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue before depletion
    21.56       24.12       22.71       15.21       16.53       15.76  
Depletion
    17.56       11.12       14.66       9.45       9.05       9.29  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue from operations
  $ 4.00     $ 13.00     $ 8.06     $ 5.76     $ 7.48     $ 6.47  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

Changes in Non-Cash Working Capital

Non-cash working capital decreased $6.5 million for the three-month period ended September 30, 2004 compared to a decrease of $1.3 million for the comparable period in 2003 and decreased $1.2 million compared to an increase of $1.1 million for the nine-month periods ended September 30, 2004 and 2003, respectively. The $4.5 million decrease in non-cash working capital for investing activities during the three-month period ended September 30, 2004 is mainly due to the use of advances from CITIC to fund the joint development program at Dagang as well as the decrease in our accounts payable associated with the completion of our current drilling programs at South Midway, Citrus and Knights Landing during the quarter. This is partially offset by a decrease in accounts receivable from investing activities as we have utilized advances made to our joint venture partners to fund our U.S. development and Iraq EOR capital expenditure activities. Additionally, non-cash working capital for operating activities for the three-month period ended September 30, 2004 decreased $2.0 million as a result of the use of advances from CITIC to fund the joint operating expenses at Dagang and the increase in revenue receivable associated with the increased production levels at the Dagang and Citrus fields. The $1.2 million decrease in non-cash working capital for the nine-month period ended September 30, 2004 is primarily due to increased revenue receivable associated with increased production levels at the Dagang and Citrus fields, which is partially offset by an increase in accounts payable associated with the development program at Dagang.

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General and Administrative

General and administrative expenses increased $0.6 million and $0.7 million for the three-month and nine-month periods ended September 30, 2004, respectively. The increases are mainly due to $0.3 million of costs incurred during the current quarter to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 in addition to smaller increases associated with stock based compensation related to the issuance of stock options, increased costs for directors and officers liability insurance and project identification activities.

Exploration and Development Activities

Capital spending on exploration and development activities for the three-month and nine-month periods ended September 30, 2004 was $7.9 million and $32.1 million, respectively, an increase of $3.9 million and $23.7 million from the amounts spent during the comparable periods in 2003. These increases are due mainly to our development programs in our Dagang, Citrus and Knights Landing fields and our Zitong seismic acquisition program in China.

Capital spending at Dagang increased $4.0 million and $11.1 million during the three-month and nine-month periods ended September 30, 2004, respectively, compared to the same periods in 2003. During the first nine months of 2004, we drilled thirteen development wells at the Dagang project, with ten wells placed on production and three wells awaiting completion. Three drilling rigs are under contract and currently in operation. Over the three-year life of the Dagang development program, we expect to drill 115 new wells and work over 28 existing wells.

During the second quarter of 2004, we completed phases one and two of our 1,100-kilometer seismic acquisition program in the Zitong project, which had begun in the third quarter of 2003, and commenced interpretation of the seismic data in August 2004. This resulted in a decrease of $0.7 million in our capital spending for the third quarter of 2004 compared to the same period in 2003. Capital spending for the nine-month period ended September 30, 2004 increased by $4.6 million compared to the same period in 2003 as a result of the initiation of the seismic acquisition program in the third quarter of 2003. We are continuing with the interpretation of the seismic data that was acquired in the first half of 2004. We expect the drilling of our first exploration well to commence in late 2004 or early 2005. In 2005, we anticipate completion of the final stage of the seismic acquisition program followed by the drilling of a second well.

Development of our Citrus field increased our capital spending program $2.6 million and $5.1 million during the three-month and nine-month periods ended September 30, 2004, respectively, compared to the same periods in 2003. We are the operator of the Citrus field and currently have a 100% working interest before payout in three Citrus wells, which are producing 170 gross boe’s per day. A one-year extension to the end of 2005 was obtained covering the area south of our current producing wells, which will provide us the opportunity to observe production for the next few months prior to resuming development of this area to determine the best drilling and completion methods.

We farmed into the Knights Landing gas project in northern California in February 2004, which resulted in increases of $0.3 million and $4.7 million in our capital spending program for the three-month and nine-month periods ended September 30, 2004, respectively, compared to the same periods in 2003. We acquired a 50% non-operating interest in four gas wells in that area and agreed to fund the cost of a gas gathering and surface facilities system to the four wells at a combined cost of $1.6 million. We also hold a 50% interest in 14,000 acres of leases in the surrounding area for further exploration drilling. In May 2004, the pipeline

17


 

gathering system and facilities were completed and the four gas wells were placed on production. In late May 2004, the 10 well drilling program commenced. Nine of the ten wells have been drilled resulting in three gas discoveries and six dry holes. The final well will be drilled in the fourth quarter of 2004. Gross production is averaging 440mcf per day.

In January 2004, we farmed into the LAK Ranch Field, a thermal recovery/horizontal well oil project in Weston County, Wyoming. Facility modifications for the pilot phase were completed in the second quarter of 2004 increasing our capital spending program $0.8 million for the nine-month period ended September 30, 2004 compared to the same period in 2003. Minimal capital spending was incurred during the three-month period ended September 30, 2004. We completed a second cycle of steam injection in September 2004. Over 13,000 barrels of steam were injected into the horizontal well. Approximately 3,500 barrels of steam water have been recovered and initial production is being observed. The ultra-high resolution 3D seismic survey needed to better define the optimum reservoir development locations should begin in November with evaluation results expected during the second quarter of 2005. In addition, a small group of vertical wells may be drilled before 2005 for data collection purposes. Depending on the observed data, some or all of the wells could later become permanent injectors or remain as observation wells. After completion of the 3D seismic survey we plan to drill injection wells to prove up oil-in-place reserves and commerciality of a full steam injection project. Following completion of the pilot phase, the development program is scheduled to include additional horizontal producing wells, new steam injection wells and the extension of surface facilities. We estimate that, at the low end of the recovery range, the initial development program could grow to more than 20 producing wells. During the pilot phase, our working interest has increased from an initial 30% working interest to 33.4%. Should we decide to enter the next two phases of the contract, our working interest will increase to a maximum of 60%. Should we elect not to proceed beyond the pilot phase, our working interest will be reduced to 15% and we would no longer be the operator.

Capital spending in South Midway decreased $2.1 million and $2.7 million during the three-month and nine-month periods ended September 30, 2004, respectively, compared to the same periods in 2003. These decreases are due mainly to the completion of the construction of our facilities for the first phase of the southern expansion in the third quarter of 2003 and the drilling of nineteen development wells in the first nine months of 2003 compared to six development wells and one exploratory well drilled in the second quarter of 2004. Gross production in the South Midway field area continued at 525 barrels per day. We are continuing to add cyclic steam to the reservoirs at increasing injection rates and volumes in order to improve production rates. We will use the current historical data with modern computer simulation models to project rates with the addition of permanent steam injection in the southern expansion area of the field. Additional development and delineation wells are planned for 2005. We currently have 55 producing wells in South Midway, with a working interest of 100%.

Exploration and development of Sledge Hamar increased our capital spending program $0.1 million and $0.5 million during the three-month and nine-month periods ended September 30, 2004, respectively, compared to the same periods in 2003. We have one producing discovery well, the Sledge Hamar 1-7 with a working interest of 40%. A second appraisal well, the Sledge Hamar 2-7, was drilled in May 2004 and was unsuccessful in establishing production from the Stevens sand that produces in the Sledge Hamar 1-7 well. We are evaluating a test program for shallower Diatomite zones where shows were encountered in the Sledge Hamar 2-7 well to determine if sufficient gas production will be available to enter into a gas sales contract. The Diatomite is a producing formation in the adjacent South Belridge field.

Our capital spending program for the fourth quarter of 2004 includes an additional North South Forty well in the San Joaquin Valley of California and Malakoff and Catfish Creek wells in East Texas, as follows:

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We hold an 80% working interest in the Peach oil and gas prospect in the North South Forty seismic area. We have agreed in principle to a 50% farm-out of our interest in a 4,500 foot well, which is planned for November 2004. The farm-in partner will carry our interest in the well and will be the operator.

In East Texas, we plan to farm-out the drilling of one well each in the Malakoff and Catfish Creek prospects in which we have a 25% carried interest. The Malakoff well is planned to be drilled to a depth of 8,700 feet and the Catfish Creek well to a depth of 11,000 feet.

Heavy-to-Light Activities (HTL)

During 2004, we acquired, for $3.0 million, a 15% equity interest in Ensyn Petroleum Ltd (“Ensyn”) and exclusive rights to use the proprietary Ensyn RTPTM Process in several key international markets.

Ensyn is currently installing a commercial demonstration facility in the South Belridge field near Bakersfield, California to demonstrate the commercial viability of the Ensyn RTPTM Process. The 1,000-barrels per day plant is mechanically complete and is in the commissioning process. Ensyn has advised us that it expects the facility to be processing oil by the end of November 2004.

The Ensyn RTPTM Process upgrades the quality of heavy oil by producing lighter, more valuable crude oil. Ensyn reports that this process yields up to a three-fold economic improvement in heavy-oil projects. The heaviest hydrocarbon fraction is consumed as fuel to generate the steam used to enhance recovery of heavy crude. This lowers costs by reducing or eliminating the need to purchase high-priced natural gas for steam generation and improves revenue since the higher quality light-crude fraction can be sold at higher prices. The lighter crude has improved viscosity that permits more efficient pumping through pipeline networks and significantly reduces transportation costs to marketing points. The Ensyn RTPTM Process uses readily available plant and process components. The technology already has been successfully applied to continuous wood/biomass processing, with several commercial plants in operation in Canada and the U.S. An Ensyn pilot plant in Ontario, Canada, has completed more than 90 test runs on heavy oil.

We have exclusive rights to deploy the Ensyn RTPTM Process in China, Mongolia, Iraq, Oman and all countries in South America except Venezuela. In these countries, our rights will be exclusive for an initial term of five years until January 2009, subject to extension if and when commercial plants are constructed. We have non-exclusive rights to the process in other countries. For each project we develop using the Ensyn RTPTM Process in our exclusive territories, Ensyn may elect to receive an equity participation in the project for the same proportionate cost as paid by the Company. The participation that may be obtained by Ensyn is no more than 10%, except for each such project that we develop in South America, other than in Venezuela and Peru, where Ensyn may elect to receive an equity interest equal to 25% of our interest. Ensyn’s equity position will offset and eliminate the payment of license fees for use of the Ensyn RTPTM Process in the project.

Gas-to-Liquids Activities (GTL)

There was no capital spending on GTL projects for the three-month period ended September 30, 2004, representing a decrease of $0.1 million spent during the comparable period in 2003.

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In the second quarter of 2004, we wrote down our $0.3 million investment in the Oman GTL project as our opportunity to build a 45,000-barrels per day GTL fuels plant in Oman failed to materialize due to a lack of sufficient uncommitted gas volumes.

There have been no significant changes in the status of our active GTL projects during the three-month period ended September 30, 2004. Our proposal for a 45,000-barrels per day GTL plant in Egypt is still under consideration by the government of Egypt, and its agencies responsible for the development and monetization of its natural gas reserves. The government is currently evaluating alternatives for monetization of its uncommitted gas reserves including pipelines to neighboring countries and liquefied natural gas plants. We will continue to work with the Ministry of Petroleum in pursuit of a commercially viable GTL project in Egypt.

We completed the initial phase of the commercialization study for the GTL plant in Bolivia in the first quarter of 2004. The results indicate that under the current tax regulations pertaining to the Bolivian hydrocarbon sector, a 90,000 barrels-per-day GTL plant could be commercial in the southern region of Bolivia. New legislation affecting the hydrocarbon sector is currently being drafted and is expected to be ratified by the end of 2004. As soon as the new laws are enacted, we will make a further economic evaluation to test our proposed project for commerciality. Assuming the results are positive, we plan to complete a detailed commercialization study and consider a definitive joint venture agreement with Syntroleum and Repsol YPF to proceed with the construction of a plant.

As new opportunities present themselves to convert hydrocarbon gases to Fischer-Tropsch liquids and ultimately to diesel and naphtha we will respond by undertaking feasibility studies. One such opportunity is converting coal into liquids. We are currently studying available conversion processes to convert coal into synthesis gas and to use the Syntroleum process to convert the synthesis gas into Fischer-Tropsch liquids. Areas such as China are particularly suited to coal-to-liquids (CTL) processing.

Enhanced Oil Recovery (EOR)

Capital spending on EOR related activities for the three-month and nine-month periods ended September 30, 2004 was $0.5 million and $1.6 million, respectively, primarily on Iraqi EOR projects.

In October 2004, we signed a memorandum of understanding with the Ministry of Oil of the Government of Iraq to study and evaluate the shallow Qaiyarah Oil Field in Iraq. The fields’ reservoirs contain a large proven accumulation of 17.1o API heavy oil at a depth of about 1,000 feet.

We will evaluate the potential response of the Qaiyarah Field to the latest in EOR techniques, along with the potential value that could be added using the Ensyn RTPTM Process to produce higher quality, more valuable crude oil. The work will include an assessment of the oil-in-place in the reservoirs, and the optimum EOR/HTL methods to establish economically recoverable reserves at Qaiyarah.

If the evaluation studies indicate development of the field is economically viable, we will present a development plan and offer a commercial proposal to implement an EOR program for Qaiyarah. The Iraqi Ministry of Oil is under no obligation to execute the project or to enter into formal commercial negotiations at the completion of our study.

Liquidity and Capital Resources

As at September 30, 2004, our cash position was $18.6 million as a result of closing two special warrant financings in the first quarter of 2004, which generated net proceeds of $20.4

20


 

million. Additionally, we received $20.0 million from Richfirst related to its 40% farm-in to the Dagang oil project development program and $4.0 million in proceeds from the Wells Fargo loan related to the development of our South Midway field.

The budget for our capital spending program for the remainder of 2004 is estimated to be $12.0 million and $79.0 for 2005. Our current cash position, expected cash flows, bank credit facility and funding from third-party agreements will enable us to complete our 2004 capital spending program. We continue to pursue acquisitions of proven and probable reserves and technologies that enhance the recovery of oil and gas reserves as a means of supplementing our growth strategy. However, in order to successfully pursue acquisition opportunities, develop our existing assets and execute our medium and long-term growth strategies, we will require significant additional funding. We plan to seek financing, on an as needed basis, from equity markets, project lenders, joint ventures or other potential financing sources. The Company and its 40% joint venture partner, Richfirst, are currently in active discussions with European and Chinese lending banks to provide funding for the development of the Dagang oil field in China. We cannot assure you that we will be successful in raising the additional funds necessary or securing joint venture partners to complete our expansion and capital spending programs. If we are unsuccessful, we will have to prioritize our business opportunities and objectives. As a result, we may lose some valuable business opportunities, which may adversely affect our business and prospects.

Contractual Obligations

The table below summarizes the contractual obligations that are reflected in our Unaudited Consolidated Balance Sheet as at September 30, 2004 and/or disclosed in the accompanying Notes:

                                                 
    Payments Due by Year
    (stated in thousands of U.S. dollars)
                                            After
    Total
  2004
  2005
  2006
  2007
  2007
Purchase Agreements:
  $     $     $     $     $     $  
Consolidated Balance Sheets:
                                               
Note payable — current portion ( Note 8 )
    1,667       417       1,250                    
Note payable — long term portion ( Note 8 )
    3,056             417       1,667       972        
Other Commitments:
                                             
Interest payable
    362       60       186       99       17        
Operating leases
    1,779       146       520       488       338       287  
Exploration commitment (a)
    10,700       1,400       9,300                    
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total
  $ 17,564     $ 2,023     $ 11,673     $ 2,254     $ 1,327     $ 287  
 
   
 
     
 
     
 
     
 
     
 
     
 
 


a)    This represents our estimate of the remaining expenditure commitment for the minimum work program during the first phase of Zitong. This is a total spending commitment and not a commitment per year. The amounts per year are based on our current estimate.

Off Balance Sheet Arrangements

As at September 30, 2004 and December 31, 2003, we did not have any relationships with unconsolidated entities or financial partnerships, such as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships. We do not have relationships and transactions with persons or entities that derive benefits from their non-independent relationship with us, or our related parties, except as disclosed herein.

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Outstanding Share Data

As of October 29, 2004, there were 169,604,911 common shares of the Company issued and outstanding, 17,451,826 share purchase warrants outstanding and exercisable to purchase 9,350,913 common shares and incentive stock options outstanding to purchase 8,252,016 common shares.

Quarterly Financial Data In Accordance With Canadian and U.S. GAAP (Unaudited)

                                                                 
    QUARTER ENDED
(stated in thousands of U.S. Dollars except per share amounts)

    2004
  2003
  2002
    Q3
  Q2
  Q1
  Q4
  Q3
  Q2
  Q1
  Q4
Total revenue
  $ 4,932     $ 3,521     $ 3,332     $ 2,330     $ 2,423     $ 2,338     $ 2,568     $ 2,371  
Net loss — Canadian GAAP
  $ 951     $ 1,298     $ 1,292     $ 23,154     $ 1,330     $ 4,587     $ 1,108     $ 1,227  
Net loss — U.S. GAAP
  $ 980     $ 1,510     $ 1,470     $ 23,270     $ 1,306     $ 1,325     $ 1,185     $ 1,287  
Net loss per share — Canadian GAAP
  $ 0.01     $ 0.01     $ 0.01     $ 0.15     $ 0.01     $ 0.03     $ 0.01     $ 0.01  
Net loss per share — U.S. GAAP
  $ 0.01     $ 0.01     $ 0.01     $ 0.15     $ 0.01     $ 0.01     $ 0.01     $ 0.01  

The 2003 and 2002 quarterly earnings have been adjusted to give effect to the retroactive application of the new Canadian Institute of Chartered Accountants Handbook Section 3870 — Stock Based Compensation, which is described in Note 2 to the unaudited consolidated financial statements. The net loss in the fourth quarter of 2003 includes an impairment charge of $20.0 million for U.S. oil and gas assets. The net loss under Canadian GAAP for the second quarter of 2003 includes a $3.3 million write down of costs associated with the unsuccessful negotiations of a GTL contract in Qatar. For U.S. GAAP, these costs were written off as they were incurred.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

No material changes since December 31, 2003.

Item 4. Controls and Procedures

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 Securities Exchange Act of 1934. Based upon that evaluation, the CEO and CFO concluded that, as of September 30, 2004, 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 the Company’s internal control over financial reporting or in other factors that could significantly affect its internal control over financial reporting during the period ended September 30, 2004 nor any significant deficiencies or material weaknesses in such internal control over financial reporting requiring corrective actions. As a result, no corrective actions were taken.

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Part II — Other Information

Item 1.     Legal Proceedings: None

Item 2.     Unregistered Sales of Equity 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
  31.1    
Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  31.2    
Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  32.1    
Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  32.2    
Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  (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/ W. Gordon Lancaster
Name: W. Gordon Lancaster
Title: Chief Financial Officer

Dated: November 2, 2004

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INDEX TO EXHIBITS

         
Exhibit    
Number
  Description
  31.1    
Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  31.2    
Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  32.1    
Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  32.2    
Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

24