ENTERRA ENERGY CORP.

The interim consolidated financial statements of Enterra Energy Corp. (the "Company") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods used in preparing the consolidated financial statements for the fiscal year ended December 31, 2002, and should be read in conjunction with those statements. The other disclosures below are incremental to those reflected in the annual statements.

1. Series 1 preferred shares

As at June 30, 2003 there were 677,277 (June 30, 2002 – 1,294,466) Series 1 preferred shares outstanding. These shares are non-voting and transferable. These shares are redeemable at any time by the Company or the holders for $0.85 per share. There is no market for these shares and none is expected to develop. A dividend of $11,388 was paid in the second quarter for a total of $23,368 paid on the preferred shares in the first six months of 2003. This amount is included in interest expense because the preferred shares are classified as debt since they are redeemable at the option of the holder.

Bank indebtedness represents the outstanding balance under a line of credit of $36,000,000 with the Alberta Treasury Branches. Drawings bear interest at 0.25% above the bank’s prime lending rate. Security is provided by a first charge over all of the Company’s assets. The balance is repayable on demand. While the loan is due on demand, the Company is not subject to scheduled repayments.

Assets secured with long-term debt are tangible oil and gas equipment with a cost of $5,217,500. These assets are subject to depletion.

(a) Issued :

(b) Options :

The following table presents a summary of our consolidated statement of operations derived from our financial statements for the three and six months ended June 30, 2003 and 2002. The monetary amounts in the table are based on Canadian GAAP. All data presented below should be read in conjunction with the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and our financial statements and accompanying notes included elsewhere in this Form 10-QSB.

The following table indicates a summary of our consolidated balance sheets as of June 30, 2003 and December 31, 2002. The monetary amounts in the table are based on Canadian GAAP.

Exchange Rate Information

We publish our consolidated financial statements in Canadian dollars. In this annual report, except where otherwise indicated, all dollar amounts are stated in Canadian dollars. References to "$" or "C$" are to Canadian dollars and references to "US$" are to U.S. dollars. The following table sets forth for each period indicated the period end exchange rates for conversion of U.S. dollars to Canadian dollars, the average exchange rates on the last day of each month during such period and the high and low exchange rates during such period. These rates are based on the noon buying rate in New York City, expressed in U.S. dollars, for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York. The exchange rates are presented as Canadian dollars per $1.00.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion of our results of operations and financial condition should be read in conjunction with the financial statements, other financial information included in this quarterly report and with management’s discussion and analysis contained in the 2002 Annual Report and Form 10-KSB. The statements that relate to matters that are not historical facts are "forward-looking statements". Words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "project", "will", "should" "could", "may", "predict" and similar expressions are intended to identify forward-looking statements. Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements. Factors that might cause such a difference such as those discussed under "Risk factors" and elsewhere, include:

• fluctuations in worldwide prices of oil and natural gas and demand for oil and natural gas;
• fluctuations in levels of oil and gas exploration and development activities;
• the existence of competitors, technological changes and developments in the industry;
• the existence of operating risks and hazards inherent in the industry, such as blowouts, oil spills, fires, adverse weather, natural disasters, injury to third parties, oil spills and other environmental damages;
• the existence of regulatory uncertainties;
• possible insufficient liquidity to meet the Company’s expansion plans; and
• general economic conditions.

Cash flow, expressed before changes in non-cash working capital, is used by the Company to measure and evaluate operating performance and liquidity. Earnings from operations, which is calculated before income taxes and before gains or losses on disposal of assets, is used by the Company to measure and evaluate operating performance. Cash flow and earnings from operations do not have any standardized meaning prescribed by the Canadian Generally Accepted Accounting Principles ("GAAP") and therefore may not be comparable with the calculation of similar measures for other companies.

At June 30, 2003 Enterra’s working capital was a deficit of $16.7 million (December 31, 2002 - $38.0 million). Included as part of current liabilities at June 30, 2003 is bank debt of $19.5 million (December 31, 2002 - $24.4 million). The classification of our bank debt as a current liability is the result of Canadian accounting rules which came into effect January 1, 2002. These rules specify that all borrowings where, among other things, the lender has a right to demand repayment within 12 months (which is the case with our revolving production facility) are to be classified as current liabilities. We are not subject to principal repayments under our banking arrangement. Other than in the event of a default or a breach of covenants, the Company does not expect any principal payments in 2003.

Cash flow from operations for the three months ended June 30, 2003 was $8.7 million (2002 - $2.2 million) for a 286% increase. Cash flow from operations for the six months ended June 30, 2003 was $21.4 million (2002 - $4.7 million) for a 357% increase. The 2003 cash flow was higher because of higher production ( 5,002 boe/day average production for the three months ended June 30, 2003 compared to 1,881 boe/day in 2002 and 5,090 boe/day average production for the six months ended June 30, 2003 compared to 2,150 boe/day in 2002), higher prices (up 38% for the three months ended June 30, 2003 and 81% for the six months ended June 30, 2002) .

Enterra’s ability to maintain and grow its operating income and cash flow is dependent upon continued capital spending to replace depleting assets. Enterra believes its future cash flow from operations, borrowing capacity and future equity issues should be sufficient to fund capital expenditures and to service debt. However, our ability to raise additional funds at all, or to do so on acceptable terms, depends largely on factors beyond our control, such as world prices for oil and gas, prevailing interest rates and general economic conditions.

Enterra’s bank debt at June 30, 2003 was $19.5 million (December 31, 2002 - $24.4 million). Our bank debt is used to acquire capital assets and support ongoing operations. At June 30, 2003 Enterra’s bank facility consisted of a line of credit of $36 million (December 31, 2002 - $26.7 million) of which $19.5 million was drawn (December 31, 2002 - $24.4 million). Interest on amounts drawn is based on the bank’s prime rate plus 0.25%.

Security is provided by a first charge over all of the Company’s assets. While the loan is repayable on demand, Enterra is not subject to scheduled repayments. The lender has advised the Company that, subject to annual review of the borrowing base and the Company continuing to comply with the terms of the loan agreement, no payments will be required in 2003.

At June 30, 2003 the Company had 9,241,836 common shares outstanding (December 31, 2002 – 9,176,325).

During the first six months of 2003 the Company sold several non-core properties for net proceeds of $15.6 million, which were used to reduce our bank debt and to reduce our working capital deficit.

The Company has approximately $45 million in tax pools available at June 30, 2003 (December 31, 2002 - $63 million).

The bank debt to equity ratio at June 30, 2003 was 0.41 to 1 (December 31, 2002 – 0.63 to 1).

The timing of most of Enterra’s capital expenditures is discretionary. Enterra has no material long-term commitments associated with its capital expenditure plans or operating agreements. Consequently, the Company has a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The level of capital expenditures will vary in future periods depending on the success we experience on planned drilling activities, oil and gas price conditions and other related economic factors.

Capital expenditures for the three and six months ended March 31, 2003 were $8.3 million and $15.4 million respectively (June 30, 2002 - $2.8 million and $5.6 million).

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The Company drilled 13 wells in the quarter and one well in the second quarter, resulting in 9 (9.0 net) oil wells and 3 (1.5 net) gas wells, for a success rate of 91% on a net basis.

Proceeds on disposal of oil and gas properties were $15.6 million during the first six months of 2003. These proceeds were applied to reduce bank debt and improve working capital.

The following discussion of our results of operations and financial condition should be read in conjunction with the financial statements, other financial information included in this quarterly report and with management’s discussion and analysis contained in the 2002 Annual Report. The following discussion is to inform you about our financial conditions, liquidity and capital resources as of June 30, 2003 and the results of operations for the three and six months ended June 30, 2003 and 2002.

Earnings were $5.0 million for the three months ended June 30, 2003 (2002 - $398,000) for an increase of 1,146%. Earnings for the six months ended June 30, 2003 were $9.2 million (2002 - $3.5 million) for a 158% increase. The 2002 earnings include a $2.9 million gain on redemption of preferred shares. Enterra redeemed 6,123,870 of its Series 1 preferred shares with a face redemption price of $5,205,290 for $2.3 million, resulting in a gain of $2.9 million. Without this gain, earnings for the six months ended June 30, 2002 would have been $643,000. The 2003 earnings include a $2.7 million future income tax adjustment. Without this adjustment, earnings for the three and six months ended June 30, 2003 would have been respectively $2.3 million and $6.5 million.

Earnings per share for the three months ended June 30, 2003 were $0.54 (2002 - $0.04) and $1.00 for the six months ended June 30, 2003 (2002 - $0.39). Cash flow per share for the three months ended June 30, 2003 was $0.94 (2002 - $0.24) and $2.32 for the six months ended June 30, 2003 (2002 - $0.51). The weighted average number of shares outstanding for the three months ended June 30, 2003 was 9,205,733 and six months ended June 30, 2003 was 9,194,089 (2002 – 9,150,622 for three months and six months). Without the gain on redemption of preferred shares, the earnings per share for the six months ended June 30, 2002 would have been $0.07. Without the future income tax adjustment in 2003, the earnings per share for the three and six months ended June 30, 2003 would have been $0.25 and $0.70 respectively.

Cash flow from operations for the three months ended June 30, 2003 was $8.7 million (2002 - $2.2 million) for a 290% increase. Cash flow from operations for the six months ended June 30, 2003 was $21.4 million (2002 - $4.7 million) for a 355% increase. The 2003 cash flow increased due to higher production volumes, stronger commodity prices and lower operating costs in 2003 compared to 2002.

Production volumes for the three months ended June 30, 2003 were 5,002 boe/day (2002 – 1,881 boe/day) for a 166% increase. Production volumes for the six months ended June 30, 2003 were 5,090 boe/day (2002 – 2,150 boe/day) for a 137% increase. The development of the Clair property is the main reason behind the higher production volumes.

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Average oil prices increased by 46% during the first half of 2003 and average gas prices increased by 96% over the same period compared to their respective 2002 levels. The Company received an average of $43.90 per barrel for its oil production during the six months ended June 30, 2003, compared with $29.98 in 2002. The Company received an average of $7.59 per mcf for its natural gas production during the six months ended June 30, 2003, compared with $3.71 in 2002. As a result, Enterra’s revenue per boe increased by $16.58 (or 61%) per boe in the first half of 2003 compared to 2002.

Royalties for the three months ended June 30, 2003 were $5.3 million (2002 - $0.8 million) and $10.2 million for the six months ended June 30, 2003 (2002 - $1.6 million). As a percentage of oil and gas revenues, royalties were 29% for the three months ended June 30, 2003 (2002 – 16%) and 25% for the six months ended June 30, 2003 (2002 – 15%). The increase in royalties is due to higher commodity prices and a decrease, as a percentage of royalties, of the Alberta Royalty Tax Credit.

Operating expenses for the three months ended June 30, 2003 were $3.1 million (2002 - $1.0 million) and $6.1 million for the six months ended June 30, 2003 (2002 - $2.8 million). On a barrel of oil equivalent basis, operating costs for the three months ended June 30, 2003 were $6.90 (2002 - $6.12) and $6.67 for the six months ended June 30, 2003 (2002 - $7.11). Operating costs are expected to decrease over the next quarters with the construction of a pipeline to transport oil from the Clair property. This pipeline connection will significantly reduce operating costs by eliminating trucking and terminal charges. The pipeline is scheduled to be in operation before the end of the third quarter.

General and administrative expenses for the three months ended June 30, 2003 were $0.8 million (2002 - $0.6 million) and $1.6 million for the six months ended June 30, 2003 (2002 - $0.8 million). On a barrel of oil equivalent basis, administrative costs were $1.85 for the three months ended June 30, 2003 (2002 - $3.21) and $1.70 for the six months ended June 30, 2003 (2002 - $2.05). The Company’s goal is to keep general and administrative expenses at a level between $1.00 and $1.50 per boe for 2003.

Interest expense for the three months ended June 30, 2003 was $0.47 million (2002 - $0.23 million) and $0.96 million for the six months ended June 30, 2003 (2002 - $0.44 million). The increase in interest expense is due to higher debt levels in 2003, including bank debt, capital leases and vendor financing arrangements. Included in interest expense in the three and six months ended June 30, 2003 were respectively $11,388 and $23,368 (2002 – NIL) of dividends paid to the preferred shareholders.

Depletion and depreciation for the three months ended June 30, 2003 was $6.0 million (2002 - $1.8 million) and $11.4 million for the six months ended June 30, 2003 (2002 - $4.1 million). The increase reflects the higher cost base of our capital assets in 2003 and increased production volumes. The Company also amortized $0.3 million in deferred financing charges during the six months ended June 30, 2003 (2002 – NIL) related to a proposed financing transaction. These costs were fully amortized by March 31, 2003.

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Current income tax expense for the three months ended June 30, 2003 was $30,000 (2002 - $33,000) and future income tax for the three months ended June 30, 2003 was a $2.3 million recovery (2002 – $189,000). The same categories for the six months ended June 30, 2003 are $60 thousand and $0.68 million (2002 - $66,000 and $238,000). The 2002 income tax expense was low because the 2003 earnings of $3.9 million included a non-taxable gain on redemption of preferred shares of $2.9 million. This gain was excluded from the 2002 tax calculation as it is not subject to income tax. The 2003 future income tax expense includes a $2.7 million adjustment to reflect the reduction in corporate income tax rates from 42.12% in 2003 to 34.62% by 2007. The future income tax liability balance has been adjusted as at June 30, 2003 to reflect the recent changes in corporate tax rates. Combined federal and Alberta corporate tax rates are expected to decline from their current level of 42.12% to 34.62% by 2007. As a result of these rate changes the future income tax liability was decreased by $2,675,000 in the quarter ended June 30, 2003 with a corresponding offset recorded as a recovery of future income taxes on the statement of earnings. For reporting under US GAAP the tax rate adjustment will not be recorded in the financial statements until such time as the income tax legislation is formally into law.

The Company had 9,241,836 common shares outstanding at June 30, 2003 (December 31, 2002 - 9,150,622).

Enterra’s bank facility consists of a line of credit of $36 million (December 31, 2002 - $26.7 million) of which $19.5 million was drawn (December 31, 2002 - $24.4 million). Interest on amounts drawn is based on the bank’s prime rate plus 0.25%.

In the second quarter of 2003, the Company sold some non-core properties for proceeds of $0.6 million, which combined with the first quarter dispositions results in net proceeds for the first six months of 2003 of $15.6 million. Proceeds from this sale were used to reduce bank debt and to fund ongoing capital requirements.

The Company is not currently taxable and has approximately $45 million in tax pools available at June 30, 2003 (December 31, 2002 - $63 million).

Capital expenditures for the three months period ended June 30, 2003 were $8.3 million (June 30, 2002 - $2.8 million). Capital expenditures for the six months ended June 30, 2003 were $15.4 million (June 30, 2002 - $5.6 million). The Company drilled 13 well in the first quarter and 1 well in the second quarter resulting in nine oil wells (9.0 net) and three gas wells (1.5 net) for a success ratio of 91% on a net basis. Drilling activity is typically at its lowest level in the second quarter because of spring breakup when movement of heavy equipment such as drilling rigs is restricted due to potential damage to the roads as the ground thaws. As a result, drilling of new wells was minimal during the second quarter. The Company focused instead on setting up the waterflood program at Clair and upgrading equipment and pumps at its Sounding Lake property. The Company expects to resume its drilling activity in the next two quarters of 2003 by focusing its efforts in the Clair and Sylvan Lake areas.

Effective January 1, 2002 the Company prospectively adopted the new recommendations of the CICA with respect to the accounting for stock-based compensation and other stock-based payments. In accordance with the new standard, the Company elected to continue its policy that no compensation is recorded on the grant of employee stock options and consideration paid on the exercise of such options is recorded as share capital. In addition, the new standard requires a fair value based method of accounting for other stock-based payments. Had compensation expense for the Company’s stock-based compensation plan been determined based on the fair value at the grant dates for awards under the plan after January 1, 2002, the Company’s net income and earnings per share would not have been materially different than those reported.

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On March 28, 2002 the Company agreed to issue 300,000 share purchase warrants to an arm’s length U.S.-based consulting firm in connection with a potential debt financing in the United States. The warrants are to have a two-year term and are subject to different pricing (100,000 warrants at US$2.60, 100,000 at US$3.30 and 100,000 at US$4.00). The US$2.60 warrants are to vest upon the execution of a non-binding letter of intent relating to the proposed financing. The US$3.30 and US$4.00 warrants are to vest only on the successful closing and funding of the proposed financing. A value of $125,000 was assigned to the 100,000 warrants at US$2.60. This value was determined using the Black Scholes Option Pricing model using an interest rate of 5% and a volatility factor of 50%. The $125,000 was credited to the Company’s contributed surplus account in 2002.

During the first quarter of 2003 the Company entered into several contracts to deliver 2,000 barrels of oil per day for the period April 1, 2003 and December 31, 2003. The prices and volumes are as follows:

In February 2003, the Canadian Institute of Chartered Accountants (CICA) issued Accounting Guideline 14, "Disclosure of Guarantees" (AcG-14). AcG-14 elaborates on the disclosures required with respect to any obligations as a result of issuing guarantees. The disclosure requirements are effective for interim and annual periods beginning on or after January 1, 2003. FASB Interpretation No. 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others", is the US equivalent of AcG-14. Enterra did not have any guarantees outstanding at December 31, 2002 or June 30, 2003.

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This report may contain forward-looking statements and other prospective information relating to future events. These forward-looking statements and other information are subject to certain risks and uncertainties that could cause results to differ materially from historical or anticipated results, including the following:

At June 30, 2003, we had a working capital deficiency of $16.7 million, which means our current liabilities exceeded our current assets by that amount. Our credit facilities are all on a demand basis and, although we are not subject to principal repayments under our current banking arrangement, they could be called for repayment at any time. Other than in the event of a default or a breach of covenants, the Company does not expect any principal payments in 2003.

We have incurred a high amount of debt relative to our assets. A decrease in the amount of our production or the price we receive for it could make it difficult for us to service our loan or may cause the bank that issued our loan to determine that our assets are insufficient security for our bank debt.

Crude oil and natural gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the following:

• that no commercially productive crude oil or natural gas reservoirs will be found;

• that crude oil and natural gas drilling and production activities may be shortened, delayed or canceled; and

• that our ability to develop, produce and market our reserves may be limited by:

• title problems,

• weather conditions,

• compliance with governmental requirements, and

• mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment.

In the past, we have had difficulty securing drilling equipment in certain of our core areas. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for crude oil and natural gas may be unprofitable. Dry wells and wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable. In addition, our properties may be susceptible to hydrocarbon draining from production by other operations on adjacent properties.

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Our industry also experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

We operate in a highly competitive environment. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of such undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase such properties, and the financial resources necessary to acquire and develop such properties. We compete with major and independent crude oil and natural gas companies for properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

The principal resources necessary for the exploration and production of crude oil and natural gas are leasehold prospects under which crude oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We must compete for such resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future we cannot assure you that such materials and resources will be available to us.

The rate of production from crude oil and natural gas properties declines as reserves are depleted. Our proved reserves will decline as reserves are produced unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. Our future crude oil and natural gas production is therefore highly dependent upon our level of success in acquiring or finding additional reserves. We cannot assure you that our exploration and development activities will result in increases in reserves. Our operations may be curtailed, delayed or cancelled if we lack necessary capital and by other factors, such as title problems, weather, compliance with governmental regulations, mechanical problems or shortages or delays in the delivery of equipment. Our ability to continue to acquire producing properties or companies that own such properties assumes that major integrated oil companies and independent oil companies will continue to divest many of their crude oil and natural gas properties. We cannot assure you that such divestitures will continue or that we will be able to acquire such properties at acceptable prices or develop additional reserves in the future.

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Our revenue, profitability and future rate of growth depend substantially upon prevailing prices for crude oil and natural gas. Crude oil and natural gas prices fluctuate and until recently have declined significantly. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In 1998 and 1999, we reduced our capital expenditures budget because of lower crude oil and natural gas prices. In addition, we may have ceiling test write-downs when prices decline. At December 31, 2001 the Company would have realized a U.S. GAAP ceiling test write-down of C$17.5 million (after tax). Lower prices may also reduce the amount of crude oil and natural gas that we can produce economically.

We may enter into hedge agreements and other financial arrangements at various times to attempt to minimize the effect of crude oil and natural gas price fluctuations. We cannot assure you that such transactions will reduce risk or minimize the effect of any decline in crude oil or natural gas prices. Any substantial or extended decline in crude oil or natural gas prices would have a material adverse effect on our business and financial results. Hedging activities may limit the risk of declines in prices, but such arrangements may also limit additional revenues from price increases.

The Company uses the "full cost" method of accounting for petroleum and natural gas properties. All costs related to the exploration for and the development of oil and gas reserves are capitalized into a single cost centre representing the Company’s activity which is undertaken exclusively in Canada. Costs capitalized include land acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling productive and non-productive wells. Proceeds from the disposal of properties are applied as a reduction of cost without recognition of a gain or loss except where such disposals would result in a major change in the depletion rate. Capitalized costs are depleted and depreciated using the unit-of-production method based on the estimated gross proven oil and natural gas reserves before royalties as determined by independent engineers. Units of natural gas are converted into barrels of equivalents on a relative energy content basis. Capitalized costs, net of accumulated depletion and depreciation, are limited to estimated future net revenues from proven reserves, based on year-end prices, undiscounted, less estimated future abandonment and site restoration costs, general and administrative expenses, financing costs and income taxes. Estimated future abandonment and site restoration costs are provided for over the life of proven reserves on a unit-of-production basis. The annual charge is included in depletion and depreciation expense and actual abandonment and site restoration costs are charged to the provision as incurred. The amounts recorded for depletion and depreciation and the provision for future abandonment and site restoration costs are based on estimates of proven reserves and future costs. The recoverable value of capital assets is based on a number of factors including the estimated proven reserves and future costs. By their nature, these estimates are subject to measurement uncertainty and the impact on financial statements of future periods could be material.

The Company performs a cost recovery ceiling test which limits net capitalized costs to the undiscounted estimated future net revenue from proven oil and gas reserves plus the cost of unproven properties less impairment, using year-end prices or average prices in that year, if appropriate. In addition, the value is further limited by including financing costs, administration expenses, future abandonment and site restoration costs and income taxes. Under U.S. GAAP, companies using the "full cost" method of accounting for oil and gas producing activities perform a ceiling test using discounted estimated future net revenue from proven oil and gas reserves using a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. Financing and administration costs are excluded from the calculation under U.S. GAAP.

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The risk that the Company will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are low or volatile. The Company may experience additional ceiling test write-downs in the future.

A component of future growth will depend on the ability to identify, negotiate, and acquire additional companies and assets that complement or expand existing operations. However we may be unable to complete any acquisitions, or any acquisitions we may complete may not enhance our business. Any acquisitions could subject us to a number of risks, including:

• diversion of management's attention;

• amortization of substantial goodwill, adversely affecting our reported results of operations;

• inability to retain the management, key personnel and other employees of the acquired business;

• inability to establish uniform standards, controls, procedures and policies;

• inability to retain the acquired company's customers;

• exposure to legal claims for activities of the acquired business prior to acquisition; and inability to integrate the acquired company and its employees into our organization effectively.

We may be subject to claims for damages related to any impact that our operations have on the environment. An environmental claim could materially adversely affect our business because of the costs of defending against these types of lawsuits, the impact on senior management's time and the potential damage to our reputation. Our oil and gas operations are subject to government regulations and control. Failure to comply with applicable government rules could restrict our ability to engage in further oil and gas exploration and development opportunities.

Our revenue is subject to volatile oil and gas prices that could reduce our revenue and profitability.

The price we receive for oil and gas production is subject to significant volatility. Our revenue, cash flow and profitability are substantially dependent on prevailing prices for oil and gas. Historically oil and gas prices and markets have been volatile and they are likely to continue to be volatile in the future. Some factors that contribute to volatility include:

• political conditions in the Middle East, the former Soviet Union and other regions;

• domestic and foreign supplies of oil and gas;

• the level of consumer demand;

• weather conditions;

• domestic and foreign government regulations;

• the availability and prices of alternative fuels; and

• overall economic conditions.

 

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To counter this volatility from time to time we may enter into agreements to receive fixed prices on its oil and gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, We will not benefit from such increases.

The price we receive for oil and gas production is expressed in U.S. dollars, which is the standard for the oil and gas industry worldwide. However, we pay operating expenses, drilling expenses and general overhead expenses in Canadian dollars. Changes to the exchange rate between U.S. and Canadian dollars can adversely affect us. When the value of the U.S. dollar increases, we receive higher revenue and when the value of the U.S. dollar declines, we receive lower revenue on the same amount of production sold at the same prices.

We are dependent upon the continued services of our management team. We do not have employment contracts with any of these executives and do not carry key person insurance on their lives. The loss of the services of our executive officers, through incapacity or otherwise, could have a material adverse effect on our business and would require us to seek and retain other qualified personnel.

We have not paid any cash dividends on our common stock and do not expect to pay any cash or other dividends in the foreseeable future. We have paid dividends of $11,380 to our preferred shareholders in the quarter ended June 30, 2003 and $23,368 for the six months ended June 30, 2003. Dividends will be paid to our preferred shareholders at a rate of $0.85 per share (on an annual basis). This dividend will decrease over time as the Company is gradually redeeming these preferred shares. At June 30, 2003 there were 677,277 preferred shares outstanding. The terms of our current banking credit facility prohibit us from declaring and paying dividends except from assets that are in excess of the required amount of security under our credit facility, and Alberta corporate law prohibits the payment of dividends unless stated solvency tests are met. The Company’s banker is aware of the dividends being paid to the preferred shareholders and will allow such payments as long as all our bank covenants are being met.

Trading volume in our common stock has historically been limited. Accordingly, the trading price of our common stock could be subject to wide fluctuations in response to quarterly variations in operating results, changes in financial estimates by securities analysts, an imbalance of purchasers and sellers, or other factors.

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The Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures. They concluded that our disclosure controls and procedures were adequate and effective in ensuring that material information relating to the Company is properly recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to allow timely decisions regarding required disclosure.

We currently have in place systems relating to internal controls and procedures with respect to our financial information. Management reviews and evaluates these internal control systems on an on-going basis. Based on these evaluations, there were no significant deficiencies or material weaknesses in these internal controls requiring corrective actions. As a result, no corrective actions were taken. There have been no significant changes in these internal controls or in other factors that could significantly affect these internal controls subsequent to the review and evaluation.

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Not Applicable.

Not Applicable.

Not Applicable.

Not Applicable

Not Applicable.

Exhibits

Enterra Energy Corp.

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