Back to GetFilings.com



 



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

     
þ
  Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
  For the quarterly period ended June 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     þ   No     o

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

     
Yes     þ   No     o

The number of shares of the registrant’s capital stock outstanding as of June 30, 2004 was 169,419,911 Common Shares, no par value.



 


 

TABLE OF CONTENTS

                 
            Page
PART I  
Financial Information
       
Item 1.  
Financial Statements
       
       
Unaudited Consolidated Balance Sheets as at June 30, 2004 and December 31, 2003 (restated)
    3  
       
Unaudited Consolidated Statements of Loss and Deficit for the Three-Month and Six-Month Periods Ended June 30, 2004 and 2003 (restated)
    4  
       
Unaudited Consolidated Statements of Cash Flow for the Three-Month and Six-Month Periods Ended June 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
    21  
Item 4.  
Controls and Procedures
    21  
PART II  
Other Information
       
Item 1.  
Legal Proceedings
    22  
Item 2.  
Changes in Securities and Use of Proceeds
    22  
Item 3.  
Defaults Upon Senior Securities
    22  
Item 4.  
Submission of Matters To a Vote of Securityholders
    22  
Item 5.  
Other Information
    22  
Item 6.  
Exhibits and Reports on Form 8-K
    22  

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)

                 
    June 30,   December 31,
    2004
  2003
            (restated
            Notes 2 and 7)
Assets
               
Current Assets
               
Cash and cash equivalents
  $ 30,361     $ 14,491  
Accounts receivable
    4,729       2,720  
Other
    378       409  
 
   
 
     
 
 
 
    35,468       17,620  
Long term assets
    3,677       998  
Oil and gas properties, equipment and investments, net
    96,577       87,956  
 
   
 
     
 
 
 
  $ 135,722     $ 106,574  
 
   
 
     
 
 
Liabilities and Shareholders’ Equity
               
Current Liabilities
               
Accounts payable and accrued liabilities
  $ 11,522     $ 4,516  
Note payable – current portion
    917       167  
 
   
 
     
 
 
 
    12,439       4,683  
 
   
 
     
 
 
Note payable
    2,083       833  
 
   
 
     
 
 
Asset retirement obligations
    623       521  
 
   
 
     
 
 
 
               
Commitments and contingencies
               
 
               
Shareholders’ Equity
               
Share capital, issued 169,419,911 common shares; December 31, 2003 161,359,339 common shares
    183,225       161,075  
Contributed surplus
    996       516  
Deficit
    (63,644 )     (61,054 )
 
   
 
     
 
 
 
    120,577       100,537  
 
   
 
     
 
 
 
  $ 135,722     $ 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   Six Months
    Ended June 30,
  Ended June 30,
    2004
  2003
  2004
  2003
            (restated           (restated
            Notes 2 and 7)           Notes 2 and 7)
Revenue
                               
Oil and gas revenue
  $ 3,472     $ 2,332     $ 6,764     $ 4,864  
Interest income
    49       6       89       42  
 
   
 
     
 
     
 
     
 
 
 
    3,521       2,338       6,853       4,906  
 
   
 
     
 
     
 
     
 
 
Expenses
                               
Operating costs
    1,157       948       2,431       1,845  
General and administrative
    1,909       1,905       3,813       3,764  
Depletion and depreciation
    1,503       751       2,949       1,671  
Write down of GTL investments
    250       3,321       250       3,321  
 
   
 
     
 
     
 
     
 
 
 
    4,819       6,925       9,443       10,601  
 
   
 
     
 
     
 
     
 
 
Net Loss
    1,298       4,587       2,590       5,695  
 
   
 
     
 
     
 
     
 
 
Deficit, beginning of period, as previously reported
    62,346       31,562       60,267       30,564  
Retroactive application of change in accounting policy for stock based compensation
          421       787       311  
 
   
 
     
 
     
 
     
 
 
Deficit, beginning of the period, as restated
    62,346       31,983       61,054       30,875  
 
   
 
     
 
     
 
     
 
 
Deficit, end of period
  $ 63,644     $ 36,570     $ 63,644     $ 36,570  
 
   
 
     
 
     
 
     
 
 
Net Loss per share – Basic and Diluted
  $ 0.01     $ 0.03     $ 0.02     $ 0.04  
 
   
 
     
 
     
 
     
 
 
Weighted Average Number of Shares (in thousands)
    169,116       145,055       165,622       144,832  
 
   
 
     
 
     
 
     
 
 

(See accompanying notes)

4


 

IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Cash Flow

(stated in thousands of U.S. Dollars)

                                 
    Three Months   Six Months
    Ended June 30,
  Ended June 30,
    2004
  2003
  2004
  2003
            (restated           (restated
            Notes 2 and 7)           Notes 2 and 7)
Operating Activities
                               
Net loss
  $ (1,298 )   $ (4,587 )   $ (2,590 )   $ (5,695 )
Items not requiring use of cash
                               
Depletion and depreciation
    1,503       751       2,949       1,671  
Write down of GTL investments
    250       3,321       250       3,321  
Stock based compensation
    242       122       481       232  
Changes in non-cash working capital items
    602       1,300       244       1,650  
 
   
 
     
 
     
 
     
 
 
 
    1,299       907       1,334       1,179  
 
   
 
     
 
     
 
     
 
 
Investing Activities
                               
Capital spending
    (14,933 )     (2,856 )     (25,356 )     (4,774 )
Deposit on investment
    (2,000 )           (2,500 )      
Proceeds from sale of assets
    13,458             13,458        
Changes in non-cash working capital items
    5,614       511       5,131       710  
 
   
 
     
 
     
 
     
 
 
 
    2,139       (2,345 )     (9,267 )     (4,064 )
 
   
 
     
 
     
 
     
 
 
Financing Activities
                               
Shares issued on private placements, net of share issue costs
                20,428        
Shares issued on exercise of options
    1,236             1,375        
Proceeds from notes and advances
    2,000       1,500       12,000       1,750  
Redemption of advance payable
    (10,000 )           (10,000 )      
 
   
 
     
 
     
 
     
 
 
 
    (6,764 )     1,500       23,803       1,750  
 
   
 
     
 
     
 
     
 
 
Increase (decrease) in cash and cash equivalents, for the period
    (3,326 )     62       15,870       (1,135 )
Cash and cash equivalents, beginning of period
    33,687       2,783       14,491       3,980  
 
   
 
     
 
     
 
     
 
 
Cash and cash equivalents, end of period
  $ 30,361     $ 2,845     $ 30,361     $ 2,845  
 
   
 
     
 
     
 
     
 
 
Financing activities, non-cash
                               
Shares issued on conversion of debenture
  $     $ 1,000     $     $ 1,000  
 
   
 
     
 
     
 
     
 
 
Included in the above are the following:
                               
Taxes paid
  $     $     $ 3     $ 6  
 
   
 
     
 
     
 
     
 
 
Interest paid
  $ 14     $ 23     $ 28     $ 42  
 
   
 
     
 
     
 
     
 
 
Changes in non-cash working capital items
                               
Operating Activities:
                               
Accounts receivable
  $ (266 )   $ 495     $ (856 )   $ 380  
Other current assets
    3       575       31       512  
Accounts payable and accrued liabilities
    865       230       1,069       758  
 
   
 
     
 
     
 
     
 
 
 
    602       1,300       244       1,650  
 
   
 
     
 
     
 
     
 
 
Investing Activities
                               
Accounts receivable
    (831 )           (1,153 )      
Accounts payable and accrued liabilities
    6,445       511       6,284       710  
 
   
 
     
 
     
 
     
 
 
 
    5,614       511       5,131       710  
 
   
 
     
 
     
 
     
 
 
 
  $ 6,216     $ 1,811     $ 5,375     $ 2,360  
 
   
 
     
 
     
 
     
 
 

(See accompanying notes)

5


 

Notes to the Consolidated Financial Statements
June 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 12. 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

Oil and gas properties, equipment and investments are net of accumulated depletion and depreciation of $13.4 million and $10.5 million as well as a provision for impairment of oil and gas properties of $34.0 million as at June 30, 2004 and December 31, 2003, respectively.

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 balance of the $20.0 million proceeds will be used to fund a portion of Richfirst’s share of future Dagang oil project costs.

In February 2004, the Company farmed into the Knights Landing project in northern California. Under this exploration and development farm-in agreement, the Company purchased, for $1.0 million, a 50% non-operated interest in four recent discoveries in the contract area and agreed to fund, for $0.6 million, gas gathering, surface treatment facilities and meters to connect the four wells to an existing pipeline system. Additionally, the Company agreed to fund 100% of the drilling costs for 10 exploratory gas wells at an estimated cost of $2.3 million to earn a 40% working interest in this prospect.

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 bpd 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 use 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 April 2004, the Company signed an agreement with Ensyn Group and Ensyn pursuant to which the Company advanced to Ensyn an additional $1.0 million in consideration for the right to elect to either take an additional 5% equity interest in Ensyn or consider the advance as a loan to be repaid with interest over a period of 90 days commencing on July 31, 2005.

As at June 30, 2004, all amounts paid to Ensyn under the above agreements are included in long-term assets.

5.   SEGMENT INFORMATION

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

7


 

                                                 
    Three Month Periods Ended June 30,
    2004
  2003
                            (restated Notes 2 and 7)
    U.S.
  China
  Total
  U.S.
  China
  Total
Oil and gas revenue
  $ 2,006     $ 1,466     $ 3,472     $ 1,247     $ 1,085     $ 2,332  
Interest income
    49             49       6             6  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    2,055       1,466       3,521       1,253       1,085       2,338  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    677       480       1,157       511       437       948  
Depletion and depreciation
    1,002       501       1,503       423       328       751  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    1,679       981       2,660       934       765       1,699  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Segment income before the following
  $ 376     $ 485       861     $ 319     $ 320       639  
 
   
 
     
 
             
 
     
 
         
Write down of GTL investments
                    250                       3,321  
General and administrative
                    1,909                       1,905  
 
                   
 
                     
 
 
Net loss
                  $ 1,299                     $ 4,587  
 
                   
 
                     
 
 
Capital Expenditures:
                                               
Oil and gas
  $ 6,905     $ 7,277     $ 14,182     $ 1,556     $ 1,097     $ 2,653  
 
   
 
     
 
             
 
     
 
         
Gas-to-liquids and EOR Investments
                    751                       203  
 
                   
 
                     
 
 
 
                  $ 14,933                     $ 2,856  
 
                   
 
                     
 
 
                                                 
    Six Month Periods Ended June 30,
    2004
  2003
                            (restated Notes 2 and 7)
    U.S.
  China
  Total
  U.S.
  China
  Total
Oil and gas revenue
  $ 3,800     $ 2,964     $ 6,764     $ 2,689     $ 2,175     $ 4,864  
Interest income
    89             89       42             42  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    3,889       2,964       6,853       2,731       2,175       4,906  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    1,431       1,000       2,431       1,013       832       1,845  
Depletion and depreciation
    1,873       1,076       2,949       988       683       1,671  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    3,304       2,076       5,380       2,001       1,515       3,516  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Segment income before the following
  $ 585     $ 888       1,473     $ 730     $ 660       1,390  
 
   
 
     
 
             
 
     
 
         
Write down of GTL investments
                    250                       3,321  
General and administrative
                    3,813                       3,764  
 
                   
 
                     
 
 
Net loss
                  $ 2,590                     $ 5,695  
 
                   
 
                     
 
 
Capital expenditures:
                                               
Oil and gas
  $ 10,023     $ 14,152     $ 24,175     $ 2,670     $ 1,691     $ 4,361  
 
   
 
     
 
             
 
     
 
         
Gas-to-liquids and EOR Investments
                    1,181                       413  
 
                   
 
                     
 
 
 
                  $ 25,356                     $ 4,774  
 
                   
 
                     
 
 
                                                 
    As at June 30, 2004
  As at December 31, 2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Identifiable Assets:
                                               
Oil & gas
  $ 89,054     $ 30,934     $ 119,988     $ 61,379     $ 30,766     $ 92,145  
 
   
 
     
 
             
 
     
 
         
Gas-to-liquids and EOR Investments
                    15,734                       14,429  
 
                   
 
                     
 
 
 
                  $ 135,722                     $ 106,574  
 
                   
 
                     
 
 

6.   SHARE CAPITAL

Following is a summary of the changes in share capital and stock options outstanding for the six-month period ended June 30, 2004:

8


 

                                 
    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 on exercise of options
    730       1,375       (730 )   $ 2.58  
Shares issued for services
    158       347              
Options granted
                    30     $ 3.06  
 
   
 
     
 
     
 
         
Balance June 30, 2004
    169,420     $ 183,225       8,249     $ 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 consist 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 June 30, 2004:

                                     
                First Anniversary
  Second Anniversary
Remaining                    
Number of   Number of       Price per       Price per
Purchase   Common       Share       Share
Warrants
  Shares
  Date
  (US$)
  Date
  (US$)
(thousands)                        
  3,000       1,500     July 3, 2004   $ 1.00     July 3, 2005   $ 1.10  
  3,000       1,500     August 18, 2004   $ 1.00     August 18, 2005   $ 1.10  
  3,029       1,515     August 21, 2004   $ 1.70     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.

The effect of the accounting change on the net loss for the three-month and six-month periods ended June 30, 2004 was an increase of $0.2 million and $0.5 million, respectively, and on the net loss for the three-month and six-month periods ended June 30, 2003, as previously

9


 

reported, was an increase of $0.2 million and $0.1 million, respectively. There is negligible effect on the net loss per share for the periods presented. The deficit as at the beginning of the six-month periods ended June 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 109% 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. Interest only is payable until July 15, 2004 at 0.25% above the bank’s prime rate or 2.75% over the London Inter-Bank Offered Rate (“LIBOR”), at the option of the Company. After July 15, 2004, 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 June 30, 2004 is $3.0 million with a blended interest rate of 4.375%. The Company borrowed the final $2.0 million in July 2004.

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 $1.1 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 $10.9 million as at June 30, 2004.

10


 

The Company has temporarily abandoned Northwest Lost Hills #1-22 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.   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 June 30, 2004 and December 31, 2003 related to the employees’ and directors’ exercise of options in the third and fourth quarters of 2003; contributed surplus would be reduced by $1.0 million and $0.5 million as at June 30, 2004 and December 31, 2003, respectively, for stock options issued to employees and directors, but not yet exercised; and the deficits as at June 30, 2004 and December 31, 2003 would be reduced by $1.2 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 June 30, 2004
  As at December 31, 2003
    Oil and Gas   Shareholders'   Oil and Gas   Shareholders'
    Properties
  Equity
  Properties
  Equity
Canadian GAAP
  $ 96,577     $ 120,577     $ 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
    (9,755 )     (9,755 )     (9,834 )     (9,834 )
GTL and EOR development costs written off
    (5,004 )     (5,004 )     (4,074 )     (4,074 )
Adjustment for change in accounting for stock based compensation:
                               
Share capital
          (271 )           (271 )
Contributed surplus
          (977 )           (516 )
Deficit
          1,248             787  
 
   
 
     
 
     
 
     
 
 
U.S. GAAP
  $ 83,176     $ 107,176     $ 75,406     $ 87,987  
 
   
 
     
 
     
 
     
 
 

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:

                 
    June 30,   December 31,
    2004
  2003
Share capital (including adjustments above)
  $ 258,767     $ 236,617  
Contributed surplus (non-employee stock based compensation)
    19        
Deficit (Including adjustments above)
    (151,610 )     (148,630 )
 
   
 
     
 
 
 
  $ 107,176     $ 87,987  
 
   
 
     
 
 

11


 

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 June 30,
    2004
  2003
    Net   Net Loss   Net   Net Loss
    Loss
  Per Share
  Loss
  Per Share
Canadian GAAP
  $ 1,298     $ 0.01     $ 4,587     $ 0.03  
Stock based compensation expense
  $ (232 )           (122 )      
Depletion adjustment – China
    (57 )           (22 )      
GTL development costs written off, net
    501             (3,118 )     (0.02 )
 
   
 
     
 
     
 
     
 
 
U.S. GAAP
  $ 1,510     $ 0.01     $ 1,325     $ 0.01  
 
   
 
     
 
     
 
     
 
 
Weighted Average Number of Shares under U.S. GAAP (in thousands)
            169,116               145,055  
 
           
 
             
 
 
                                 
    Six Month Periods Ended June 30,
    2004
  2003
    Net   Net Loss   Net   Net Loss
    Loss
  Per Share
  Loss
  Per Share
Canadian GAAP
  $ 2,590     $ 0.02     $ 5,695     $ 0.04  
Stock based compensation expense
    (461 )           (232 )      
Depletion adjustment – China
    (80 )           (45 )      
GTL development costs written off, net
    931             (2,908 )     (0.02 )
 
   
 
     
 
     
 
     
 
 
U.S. GAAP
  $ 2,980     $ 0.02     $ 2,510     $ 0.02  
 
   
 
     
 
     
 
     
 
 
Weighted Average Number of Shares under U.S. GAAP (in thousands)
            165,622               144,832  
 
           
 
             
 
 

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   Six Month Periods
    Ended June 30,
  Ended June 30,
    2004
  2003
  2004
  2003
Net loss under U.S. GAAP
  $ 1,510     $ 1,325     $ 2,980     $ 2,510  
Stock-based compensation expense determined under the fair value based method for employee and director awards
    498       409       992       807  
 
   
 
     
 
     
 
     
 
 
Pro forma net loss under U.S. GAAP
  $ 2,008     $ 1,734     $ 3,972     $ 3,317  
 
   
 
     
 
     
 
     
 
 
Basic and diluted loss per common share under U.S. GAAP:
                               
As reported
  $ 0.01     $ 0.01     $ 0.02     $ 0.02  
Pro forma
  $ 0.01     $ 0.01     $ 0.02     $ 0.02  
Weighted Average Number of Shares under U.S. GAAP (in thousands)
    169,116       145,055       165,622       144,832  

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 fiscal years beginning after December 2004.

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.

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 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

13


 

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 June 30, 2004, the net loss was $1.3 million ($0.01 per share) compared to a net loss of $4.6 million ($0.03 per share) for the same period in 2003. The net loss for the six-month period ended June 30, 2004 was $2.6 million ($0.02 per share) compared to a net loss of $5.7 million ($0.04 per share) for the same period in 2003. The net loss for the three-month and six-month periods ended June 30, 2003 include a $3.3 million ($0.02 per share) write down of our investment in the Qatar gas-to-liquids (GTL) project as a result of the termination of contract negotiations in May 2003.

Cash from operating activities for the three-month and six-month periods ended June 30, 2004 was $1.3 million compared to cash from operating activities of $0.9 million and $1.2 million for the same periods in 2003. Our cash position increased $15.9 million for the first six 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, $2.0 million in proceeds from the Wells Fargo loan related to the development of our South Midway field and $1.4 million from the exercise of stock options. This is partially offset by $25.4 million for capital spending for the first six months of 2004 and $2.5 million paid to Ensyn under our agreements with that company. Our cash position decreased $1.1 million for the comparable period in 2003 primarily due to $4.1 million of net cash required for capital spending partially offset by $1.2 million in cash from operating activities and an increase in notes payable of $1.8 million.

Production and Operations

Oil and gas revenues for the three-month and six-month periods ended June 30, 2004 were $3.5 million and $6.8 million, respectively. This represents increases of $1.1 million and $1.9 million from the comparable periods in 2003. Half of the increase in revenue for the three-month period ended June 30, 2004 is due to a 21% or $5.68 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 as a result of additional development programs initiated in 2003 at the South Midway and Daqing fields and the start up of production in 2004 at our Citrus and Knights Landing fields. Production volumes from the Dagang field development, initiated at the end of 2003, increased 44% from the comparable period in 2003 but these increases are mostly offset by CITIC’s participation in its 40% share of production related to finalizing the farm-out agreement in the second quarter of 2004. The increase in revenues for the six-month period ended June 30, 2004 was mainly due to more than a four-fold increase in production volumes from the Daqing field, in which we own a royalty interest, 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 16% or $4.36 per boe increase in oil and gas prices contributed to a 45% increase in revenues for the six-month period ended June 30, 2004.

14


 

Operating costs decreased 5% or $0.37 per boe for the three-month period ended June 30, 2004 compared to the same period in 2003. Operating costs in China decreased 17% or $1.51 per boe for the second quarter of 2004 due mainly to a reduction in well workovers and decreased power costs in 2004. Operating costs in the U.S. increased 6% or $0.47 per boe for the second 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 partially offset by a reduction in workover costs at our Spraberry field. For the six-month period ended June 30, 2004, operating costs increased 10% or $0.75 per boe compared to the same period in 2003. Operating costs in China decreased 8% or $0.59 per boe due mainly to a reduction in well workovers and decreased power costs during the second quarter of 2004. Operating costs in the U.S. increased 26% or $1.76 per boe for the six-month period ended June 30, 2004 due mainly to an increase in costs incurred for the cyclic steam operations in the southern expansion of South Midway in the first quarter of 2004 and the start up of production operations at our Citrus, Knights Landing and Sledge Hamar fields during 2004. This is partially offset by a reduction in workover costs at our Spraberry field from the comparable period in 2003.

Our depletion rate increased $5.39 and $4.33 per boe for the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. The depletion rate in China increased $2.07 and $1.96 per boe for the three-month and six-month periods ended June 30, 2004, respectively, due mainly to anticipated increases in Dagang future development costs. The depletion rate in the U.S. increased $7.86 and $6.22 per boe for the three-month and six-month periods ended June 30, 2004, respectively, due mainly to an increase in the carrying costs of our evaluated U.S. oil and gas assets during the fourth quarter of 2003 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 period ended June 30, 2004 is due to an increase in Knights Landing exploration costs and a decrease in estimated reserves for Knights Landing a result of reduced success in the current exploration drilling program as five dry holes had been drilled as at June 30, 2004.

Production and operating information are detailed below:

                                                 
    Three-Month Periods Ended June 30,
    2004
  2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Net Production:
                                               
BOE
    60,848       45,502       106,350       49,806       36,698       86,504  
BOE/day for the year
    669       500       1,169       547       403       950  
                                                 
    Per BOE
  Per BOE
Oil and gas revenue
  $ 32.97     $ 32.21     $ 32.65     $ 25.04     $ 29.55     $ 26.96  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    7.87       7.17       7.57       7.40       8.68       7.94  
Production taxes
    1.12             0.64       0.98             0.57  
Engineering support
    2.12       3.38       2.66       1.87       3.22       2.44  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    11.11       10.55       10.87       10.25       11.90       10.95  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue before depletion
    21.86       21.66       21.78       14.79       17.65       16.01  
Depletion
    15.85       11.01       13.78       7.99       8.94       8.39  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue from operations
  $ 6.01     $ 10.65     $ 8.00     $ 6.80     $ 8.71     $ 7.62  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

15


 

                                                 
    Six-Month Periods Ended June 30,
    2004
  2003
    U.S.
  China
  Total
  U.S.
  China
  Total
Net Production:
                                               
BOE
    119,214       95,864       215,078       105,783       73,757       179,540  
BOE/day for the year
    655       527       1,182       584       407       991  
                                                 
    Per BOE
  Per BOE
Oil and gas revenue
  $ 31.88     $ 30.92     $ 31.45     $ 25.42     $ 29.48     $ 27.09  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Operating costs
    8.51       7.28       7.96       6.75       7.87       7.21  
Production taxes
    1.15             0.64       0.95             0.56  
Engineering support
    2.34       3.15       2.70       1.87       3.40       2.50  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
 
    12.00       10.43       11.30       9.57       11.27       10.27  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue before depletion
    19.88       20.49       20.15       15.85       18.21       16.82  
Depletion
    15.11       11.22       13.37       8.89       9.26       9.04  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Revenue from operations
  $ 4.77     $ 9.27     $ 6.78     $ 6.96     $ 8.95     $ 7.78  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

Changes in Non-Cash Working Capital

Non-cash working capital increased $6.2 million and $5.4 million for the three-month and six-month periods ended June 20, 2004, respectively, compared to increases of $1.8 million and $2.4 million for the same periods in 2003. The increases in non-cash working capital for investing activities for the three-month and six-month periods ended June 20, 2004 are mainly due to increases of $6.4 million and $6.3 million, respectively, in our payables and accruals as a result of our capital programs in China and the U.S. The increase in non-cash working capital for investing activities for the three-month and six-month periods ended June 30, 2004 is partially offset by increases of $0.8 million and $1.1 million, respectively, in accounts receivable primarily as a result of advances made to our joint venture partners to fund our U.S. development and Iraq EOR activities.

Exploration and Development Activities

Capital spending on exploration and development activities for the three-month and six-month periods ended June 30, 2004 was $14.1 million and $24.2 million, respectively, an increase of $11.5 million and $19.8 million from the amounts spent during the comparable periods in 2003. This increase is 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 $3.3 million and $7.1 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. By the end of the second quarter of 2004, we had drilled seven development wells in Dagang, four of which are on production and the remaining three wells are in various stages of completion or testing. Three drilling rigs are now under contract for the Dagang project and the development program is on schedule for a year-end 2004 gross production target of 2,500 bopd. Over the next three years, we expect to drill 115 new wells and work over 28 existing wells.

During the second quarter of 2004, we completed phase one of our 1,100-kilometer seismic acquisition program in the Zitong project, which increased our capital spending for the three-month and six-month periods ended June 30, 2004 by $3.0 million and $5.0 million, respectively, compared to the same periods in 2003. In our Zitong project we are continuing with the interpretation of the seismic and plan to drill one exploration well in late 2004.

16


 

We farmed into the Knights Landing gas project in northern California in February 2004, which resulted in increases of $2.9 million and $4.4 million in our capital spending program for the first three-month and six-month periods ended June 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 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 10 wells have been drilled resulting in three gas discoveries and 6 dry holes. The three gas discoveries have been tested and are now being tied in to the gathering system. The final well remains to be drilled under the initial drilling program, and we are evaluating drilling additional follow up wells to develop the three discoveries drilled thus far.

Development of our Citrus field increased our capital spending program $1.6 million and $2.4 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. After having placed Citrus #1 on production in January 2004, additional work was conducted on the well in the second quarter of 2004 to add the Lower Reef Ridge zone to the existing horizontal Antelope zone. Both zones are currently flowing about 50 barrels of oil per day. A downhole pump will be installed in the near future to increase total rates. The Citrus #2 well is currently being completed in four combined oil zones with fracture stimulation of each interval. The Citrus #3 well has finished drilling and should be completed by mid-August. We plan to observe production for a few months prior to resuming development of this area to determine the best drilling and completion methods.

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 $0.3 million and $0.8 million for the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. The first cycle of steam injection into the horizontal producer was completed by the end of May 2004. Approximately 70% of the steam has been recovered to date and oil cuts are improving as anticipated. The oil is high-quality, 19-degree API gravity, and contains high levels of naphtha. Plans are underway to commence a second steam cycle in the third quarter of 2004, using a larger quantity of steam at a higher pressure to further stimulate oil production. Progress continues with the planned ultra-high resolution 3D seismic survey scheduled for the last quarter of 2004. The survey is designed to provide the necessary detail for targeting future horizontal well development at LAK Ranch. After completion of the 3D seismic survey we plan to drill additional delineation 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, we will have an initial 30% working interest. 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 $0.2 million and $0.6 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003 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. We drilled five delineation wells in South Midway in the second quarter of 2003 compared to six delineation wells and one exploratory well in the second quarter of 2004, resulting in the completion of four producing oil wells. The production from the southern expansion area is showing more favorable response to steam with total South Midway production currently averaging about 600 barrels of oil per

17


 

day compared to an average of 530 barrels of oil per day for the second quarter of 2004. We will monitor production from the southern expansion area to determine optimum well locations before resuming development. We have 55 producing wells in South Midway, with a working interest of 100%.

Exploration and development of Sledge Hamar increased our capital spending program $0.3 million and $0.4 million during the three-month and six-month periods ended June 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. The Diatomite is a producing formation in the adjacent South Belridge field. Follow up wells may be drilled in the latter part of 2004 to further develop both the Stevens and the Diatomite zones.

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

We hold a 50% working interest in two shallow gas prospects that have been defined in the North South Forty seismic area as a result of an extensive 3-D seismic acquisition program conducted on lands west of the Belridge oil field. In May 2004, we drilled the first prospect to 1,500 feet resulting in increase in capital spending of $0.1 million for the three-month and six-month periods ended June 30, 2004. The well was a dry hole and was abandoned. The second of the two prospects will be drilled in the third quarter of 2004. In addition, we hold a 100% working interest in a third oil and gas prospect in the North South Forty seismic area. We plan to drill a 3,500 foot well late in 2004. We are currently seeking a partner to participate with us in the latter prospect.

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

In January 2004, we signed a Stock Purchase and Shareholders’ Agreement with Ensyn Group Inc. (“Ensyn Group”) and its subsidiary, Ensyn Petroleum International Ltd. (“Ensyn”), pursuant to which, for a total payment of $2 million, we acquired a 10% equity interest in Ensyn and exclusive rights to use the proprietary Ensyn RTPTM Process in several key international markets.

In April 2004, we signed an agreement with Ensyn Group and Ensyn pursuant to which we advanced Ensyn an additional $1.0 million in consideration for the right to elect to either take an additional 5% equity interest in Ensyn or consider the advance as a loan to be repaid with interest over a period of 90 days commencing on July 31, 2005.

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 at the facility in mid-September, 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

18


 

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 use 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 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, 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 Process in the project.

Gas-to-Liquids Activities

There was no additional capital spending on GTL projects for the three-month period ended June 30, 2004.

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 bpd GTL fuels plant in Oman failed to materialize due to a lack of sufficient uncommitted gas volumes to support a 45,000 bpd GTL plant in Oman.

Although 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 liquid natural gas plants. We await the outcome of their evaluations.

We have completed the initial phase of the commercialization study for the GTL plant in Bolivia. The results indicate that under the current tax regulations pertaining to the Bolivian hydrocarbon sector, a 90,000 barrel-per-day GTL plant could be commercial in the southern region of Bolivia. However, given the current political climate and the uncertainty surrounding the impact that newly proposed tax regulations could have on the viability of a GTL plant, we, and our partners in the commercialization study, have elected not to proceed any further until all hydrocarbon legislation has been finalized which is expected during the third quarter of 2004.

EOR

Capital spending on EOR related activities for the three-month and six-month periods ended June 30, 2004 was $0.8 million and $1.2 million, respectively. Several of our senior executives and technical personnel have had prior experience working on oil projects at various fields in Iraq. We are utilizing this prior experience and the experience of consultants with extensive knowledge of, and background in, Iraq to plan and pursue development

19


 

activities that, if successful, would result in increased oil production and reserves in that country.

Liquidity and Capital Resources

As at June 30, 2004, our cash position was $30.4 million as a result of closing two special warrant financings in the first quarter of 2004, which generated net proceeds of $20.4 million, we received $20.0 million from Richfirst related to their 40% farm-in to the Dagang oil project development program and $2.0 million in proceeds from the Wells Fargo loan related to the development of our South Midway field. We borrowed the final $2.0 million on the Wells Fargo loan in July 2004 bringing the total loan amount to $5.0 million.

The budget for our capital program for the remainder of 2004, is estimated to be $28.5 million. Our current cash position, expected cash flows, bank credit facility and funding from third-party agreements will enable us to complete our 2004 capital 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, to complete the development of our fields and to execute our medium and long-term growth strategies we will require additional funding. We plan to seek such financing through a combination of equity, convertible debentures, debt, mezzanine financing and joint venture partner participation. The Company and its 40% joint venture partner, CITIC, are currently in active discussions with leading European and Chinese lenders for a project bank loan 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 programs. If we are unsuccessful, we will have to prioritize such programs, which may result in delaying and potentially losing some valuable business opportunities.

Contractual Obligations

The table below summarizes the contractual obligations that are reflected in our Unaudited Consolidated Balance Sheet as at June 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)
    917       417       500                    
Note payable – long term portion (Note 8)
    2,083             500       1,000       583        
Other Commitments:
                                             
Operating leases
    1,926       292       520       488       338       287  
Exploration commitment (a)
    10,900       1,600       9,300                    
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total
  $ 15,826     $ 2,309     $ 10,820     $ 1,488     $ 921     $ 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 June 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

20


 

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.

Outstanding Share Data

As of July 30, 2004, there were 169,534,911 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 8,048,343 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
    Q2
  Q1
  Q4
  Q3
  Q2
  Q1
  Q4
  Q3
  Q2
Total revenue
  $ 3,521     $ 3,332     $ 2,330     $ 2,423     $ 2,338     $ 2,568     $ 2,371     $ 2,350     $ 2,024  
Net loss – Canadian GAAP
  $ 1,298     $ 1,292     $ 23,154     $ 1,330     $ 4,587     $ 1,108     $ 1,227     $ 3,164     $ 1,204  
Net loss – U.S. GAAP
  $ 1,510     $ 1,470     $ 23,270     $ 1,306     $ 1,325     $ 1,185     $ 1,287     $ 2,976     $ 1,808  
Net loss per share – Canadian GAAP
  $ 0.01     $ 0.01     $ 0.15     $ 0.01     $ 0.03     $ 0.01     $ 0.01     $ 0.02     $ 0.01  
Net loss per share – U.S. GAAP
  $ 0.01     $ 0.01     $ 0.15     $ 0.01     $ 0.01     $ 0.01     $ 0.01     $ 0.02     $ 0.02  

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. The net loss for the third quarter of 2002 includes a $2.4 million write down of the Sweetwater, Australia GTL assets.

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 June 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

21


 

financial reporting or in other factors that could significantly affect its internal control over financial reporting during the period ended June 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.

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

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: August 3, 2004

22


 

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

23