ENTERRA ENERGY CORP.

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The interim consolidated financial statements 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, 2001, except as described below, and should be read in conjunction with those statements. The other disclosures below are incremental to those reflected in the annual statements.

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, 2002 and 2001. 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.

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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 and other financial information included in this annual report. 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.

At June 30, 2002 Enterra’s working capital was a deficit of $18.5 million (December 31, 2001 - $2.2 million). Included as part of current liabilities at June 30, 2002 is bank debt of $21.1 million (December 31, 2001 - NIL). The Company’s bank debt now appears on our balance sheet as a current liability. This same bank debt was classified as a long-term liability at December 31, 2001. Nothing has changed with the nature or the terms of our banking arrangement with our lender. The reclassification of our bank debt from long-term liability to current liability is the result of new 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 the in the event of a default or a breach of covenants, our lender has advised us that no principal payments are required in 2002.

Since January 1, 2002 the Canadian GAAP rules mirror the U.S. GAAP rules: the calculation and presentation of working capital is now consistent under both Canadian and U.S. GAAP.

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Cash flow from operations for the three months ended June 30, 2002 was $2.2 million (2001 - $795,378) for a 182% increase. Cash flow from operations for the six months ended June 30, 2002 was $4.7 million (2001 - $4.1 million) for a 14% increase. In both cases, the increase is the result of the additional production gained with the Big Horn acquisition which was effective August 1, 2001. Commodity prices were lower in 2002 than 2001 but the additional production volumes more than offset the decline in prices, resulting in higher cash flow from operations in 2002. The Company also received approximately $1.68 million in the first quarter of 2001 upon the settlement of a hedging contract, which is why the cash flow increase is only 14% for the six months ended June 30, 2002 compared to 182% for the three 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, 2002 was $21.1 million (December 31, 2001 - $18.4 million). Our bank debt is used to acquire capital assets and support ongoing operations. At June 30, 2002 Enterra’s bank facility consisted of a line of credit of $24 million (December 31, 2001 - $21.5 million) of which $21.1 million was drawn (December 31, 2001 - $18.4 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 2002.

The Company currently has 9,150,622 common shares outstanding.

In the second quarter of 2002, the Company sold its Grand Forks property for $5.3 million. Proceeds from this sale were used to reduce our bank debt and to repurchase some of the preferred shares. The preferred shares were redeemed for $2.3 million, paid for with cash of $1.75 million and a note of $550,000. Subsequent to June 30, 2002 the note was settled for $325,000, resulting in a gain of $225,000.

The Company has in excess of $45 million in tax pools available at June 30, 2002.

The bank debt to equity ratio at June 30, 2002 was 0.57 to 1 (December 31, 2001 – 0.55 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 months period ended June 30, 2002 were $2.8 million (June 30, 2001 - $2 million). Capital expenditures for the six months end June 30, 2002 were $5.6 million (June 30, 2001 - $7.8 million). Drilling activity has been minimal so far in 2002. Most of our capital expenditures have been for land , equipment upgrades and workovers. Less than 20% of the $5.6 million in capital expenditures in 2002 was for drilling and completion activities.

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Proceeds on disposal of oil and gas properties were $5.9 million for the six months ended June 30, 2002 (June 30, 2001 – NIL). These proceeds relate almost exclusively to the sale of the Grand Forks properties, which occurred in the second quarter of 2002 and which accounted for $5.3 million of the $5.9 million total proceeds for the first half of the year.

Gross revenue for the three months ended June 30, 2002 was $5 million (2001 - $4.7 million) for a 8% increase. Revenue for the six months ended June 30, 2002 was $10.6 million (2001 - $8.9 million) for a 19% increase. In both cases the impact of the higher production volumes was mitigated by the lower commodity prices in 2002. Production volumes for the three months ended June 30, 2002 were 1,881 boe/day (2001 – 1,465 boe/day) for a 28% increase. However, prices declined on average by 16% over the same period, reducing the revenue increase to only 8%. Production volumes for the six months ended June 30, 2002 were 2,150 boe/day (2001 – 1,349 boe/day) for a 59% increase. Again, commodity prices during that period declined by 26%, resulting in a lower revenue increase of only 19%.

Average oil prices declined by 12% during the first half of 2002 and average gas prices declined by 55% over the same period compared to their respective 2001 levels. The Company received an average of $29.98 per barrel for its oil production during the six months ended June 30, 2002, compared with $34.08 in 2001. The Company received an average of $3.71 per mcf for its natural gas production during the six months ended June 30, 2002, compared with $8.17 in 2001. As a result, Enterra’s revenue per boe declined by $9.32 (or 25%) per boe in the first half of 2002 compared to 2001.

Royalties for the three months ended June 30, 2002 were $803,889 (2001 - $719,384) and $1.6 million for the six months ended June 30, 2002 (2001 - $1.4 million). As a percentage of oil and gas revenues, royalties were 16% for the three months ended June 30, 2002 (2001 – 15%) and 15% for the six months ended June 30, 2002 (2001 – 16%).

Operating expenses for the three months ended June 30, 2002 were $1.05 million (2001 - $1.03 million) and $2.8 million for the six months ended June 30, 2002 (2001 - $$2.4 million). This increase is the result of the increased production in 2002. On a barrel of oil equivalent basis operating costs for the three months ended June 30, 2002 were $6.12 (2001 - $7.72) and $7.11 for the six months ended June 30, 2002 (2001 - $9.83). The decrease is manly due to the Big Horn acquisition. Big Horn’s properties, on average, experienced lower operating expenses than Enterra’s. By consolidating the two groups, and with Big Horn’s management being the surviving management group, the Company was able to reduce overall operating expenses.

General and administrative expenses for the three months ended June 30, 2002 were $550,169 (2001 - $252,666) and $796,629 for the six months ended June 30, 2002 (2001 - $509,394). On a barrel of oil equivalent basis administrative costs were $3.21 for the three months ended June 30, 2002 (2001 - $1.89) and $2.05 for the six months ended June 30, 2002 (2001 - $2.09). The increase in the second quarter of 2002 is due to corporate expenditures (e.g. audit fees, reserve report, bank renewal fee financing costs) and to a small increase in payroll costs from 2001.

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Interest expense for the three months ended June 30, 2002 was $228,533 (2001 - $ 102,845) and $436,656 for the six months ended June 30, 2002 (2001 - $143,064). The increase in interest expense is due to higher debt levels in 2002.

Depletion and depreciation for the three months ended June 30, 2002 was $1.8 million (2001 - $1.07 million) and $4.09 million for the six months ended June 30, 2002 (2001 - $2.02 million). The increase reflects the higher cost base in our capital assets in 2002.

Enterra incurred $721,650 of one-time restructuring charges (mainly severance and termination payments) in the second quarter of 2001 as a result of the Big Horn acquisition. There were no such costs in 2002.

Current and future income tax expense for the three months ended June 30, 2002 were $33,000 and $189,000 respectively (2001 – $760,140 and ($455,456)) and $66,000 and $238,000 respectively for the six months ended June 30, 2002 (2001 – $874,140 and ($215,456)). The higher level of income taxes in 2001 is due to the gain on settlement of hedges (which occurred in the first quarter of 2001, thereby increasing the income of Enterra for tax purposes) and to the fact that there were less tax pools available to Enterra in 2001. The future income tax expenses are calculated based on the timing of deductions for accounting purposes and tax on petroleum and gas assets.

The Company’s earnings were $398,445 for the three months ended June 30, 2002 (2001 - $470,427) for a decrease of 15%. The earnings for the six months ended June 30, 2002 were $3.5 million (2001 - $1.08 million) for a 228% increase. This large increase was caused by a $2.9 million gain on redemption of preferred shares which occurred in the first quarter of 2002. 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 $2,905,290. Without this gain, earnings for the six months ended June 30, 2002 would have been $642,892, a decrease of 41%. The lower earnings in 2002 are due to lower prices, higher depletion charges and higher general and administrative costs in the case of the three months results.

Earnings per share for the three months ended June 30, 2002 were $0.04 (2001 - $0.08) and $0.39 for the six months ended June 30, 2002 (2001 - $0.19). The weighted average number of shares outstanding for the three and six months ended June 30, 2002 was 9,150,622 (2001 – 5,678,321 for three months and 5,580,454 for six months).

The Company had 9,150,622 common shares outstanding at June 30, 2002 (December 31, 2001 - 9,150,622)

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.

Options:

Subsequent to June 30, 2002 Enterra settled a note payable of $550,000 for $325,000, resulting in a gain of $225,000.

This report contains 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, 2002, we had a working capital deficiency of $18.5 million, which means our current liabilities exceeded our current assets by that amount. Our credit facilities are all on a demand basis and could be called for repayment at any time.

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.

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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.

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.

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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.

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 changed its method of accounting for petroleum and natural gas properties from the "successful efforts" method to the "full cost" method in 2001. 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.

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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. At December 31, 2001 the Company would have realized a U.S. GAAP ceiling test write-down of $17.5 million (after tax).

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.

Prior to 2001, the Company followed the "successful efforts" method of accounting for our oil and gas exploration and development costs. The initial acquisition costs of oil and gas properties and the costs of drilling and equipping development wells and successful exploratory wells were capitalized. The costs of exploration wells classified as unsuccessful were charged to expense. All other exploration expenditures, including geological and geophysical costs and annual rentals on exploratory acreage, were charged to expense as incurred. Under successful efforts accounting rules, the net capitalized cost of oil and gas properties could not exceed a "ceiling limit" which was based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceeded the ceiling limit, the amount of the excess was charged to earnings. This is called a "ceiling limitation write-down." This charge did not impact cash flow from operating activities, but did reduce stockholders' equity. In 1997 and 2000, the Company recorded a write-down of $ 3.8 million and $0.5 million respectively, as a result of a downward adjustment to our proved reserves in Canada.

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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.

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.

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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. 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.

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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Not Applicable.

Not Applicable.

Not Applicable.

Not Applicable

Not Applicable.

Exhibits