SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________

                                                                (Mark One)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Common Shares, without par value at December 31, 2001: 9,150,622

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 such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 [X ] Item 18 [  ]

Not applicable

Not applicable

Not Applicable

Not Applicable

At December 31, 2001, we had a working capital deficiency of C$2,229,431, which means our current liabilities exceeded our current assets by that amount. Using the principles of U.S. GAAP, all of our long-term debt would be classified as a current liability resulting in a working capital deficiency of C$20,728,629. 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.

This annual report contains estimates of future net cash flows from our oil and gas reserves, prepared by independent engineers, which are based upon the estimates of oil and gas reserves in the ground and the percentage of those reserves which can be recovered and produced with current technology. These estimates include assumptions as to the prices received for the sale of oil and gas. Any one or all of those estimates may be inaccurate, which could materially affect our estimate of future net cash flows. In addition, the cost of capital and operating expenses could be higher than estimated, resulting in a reduction in working capital and the need to raise additional capital.

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.

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.

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 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.

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.

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:

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.

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:

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. 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.

Enterra Energy Corp. (formerly Westlinks Resources Ltd.)("Enterra") was formed on June 30, 1998 by the amalgamation of Temba Resources Ltd. ("Temba") and PTR Resources ltd. ("PTR") in a share-for-share exchange. The combination was recorded using the purchase method of accounting with Temba being identified as the acquirer. An amalgamation is the consolidation of the two amalgamating companies, and is a continuation of both businesses. Our predecessor, Temba Resources Ltd., was incorporated in Alberta on July 31, 1996 and at the time of the amalgamation had acquired oil and gas production of approximately 27 barrels of oil per day and 106 thousand cubic feet of gas per day from 19 oil wells and one gas well. Immediately prior to the amalgamation which created Westlinks, Temba Resources amalgamated with its wholly owned subsidiary, Rainee Resources Ltd. Our predecessor, PTR Resources, was incorporated in Alberta on September 18, 1992 as 542275 Alberta Ltd.; changed its name to Ablevest Holdings Ltd. on June 14, 1993, and to PTR Resources on December 1, 1997. PTR Resources originally held a 2.5% working interest in mineral leases on 8.5 sections of land in Alberta.

Effective August 1, 2001 Enterra acquired 100% of the common shares of Big Horn Resources Ltd. ("Big Horn"), a junior oil and gas company listed on the Toronto Stock Exchange, by the way of a plan of arrangement. Consideration consisted of cash of C$2,205,447 (not including acquisition costs) and the issuance of 3,496,436 common shares and 7,418,332 preferred shares. In addition, approximately 460,915 Enterra options were issued in exchange for Big Horn options.

Effective December 10, 2001 Westlinks Resources Ltd. changed its name to Enterra Energy Corp.

We are an operating oil and gas company that drills, acquires, operates and exploits crude oil and natural gas wells in our core areas in Western Canada. Our capital budget for 2002 is approximately C$25 million, subject to available funds, earmarked for development and exploitation programs focused almost exclusively in Alberta, Canada. We anticipate drilling approximately 50 wells during 2002, subject to the results of our analysis of seismic studies and the results of our previous drilling, and the development of new opportunities as the year progresses.

The following definitions of certain terms used in the oil and gas industry will assist you in understanding our business:

"Developmental Wells" are wells drilled for oil or gas within a proven field for the purpose of completing the desired pattern of production;

"Infield and step-out wells" mean wells that have been drilled either in between or on the outside edge of other nearby producing wells;

"Non-operated property" means a well that is managed by a third party;

"Permeability" means the ability of a porous rock to transmit fluid through its pore spaces. A rock may be highly porous and yet be impermeable if it has no interconnecting pore network communication;

"Petrophysical data" means the rock parameters associated with a reservoir, including thickness, porosity, permeability;

"Porosity" means the ability of a rock to contain fluids. It is the volume of pore spaces between mineral grains, expressed as a percentage of the total rock volume;

"Reservoir" means a porous, permeable sedimentary rock structure or trap containing oil and/or gas;

"Spudding" means the commencement of the drilling of a well;

"Waterflood" means the injection of water into an oil reservoir in order to enhance production;

"Water injection well" means a well used to inject water into an oil reservoir in order to conduct a waterflood;

"Wildcat" means a well drilled in an area where oil and gas has not been previously found; and

"Working Interest" means the percent of production, before royalties, to which a party is entitled.

As a result of the Big Horn acquisition a new management team is in place at Enterra. Big Horn’s previous management was the surviving management group following the August 1, 2001 Big Horn acquisition. Prior to 2001, Enterra (then known as Westlinks) was an acquisition driven company. Big Horn, on the other hand, was a full cycle oil and gas producer, focused on exploration and development. The new management at Enterra will be more focused in 2002 on its exploration, development and exploitation programs than on corporate or property acquisitions.

We concentrate our efforts on oil and gas properties that offer opportunities for low risk development. Typical types of low risk developments are the drilling of infield and step-out wells, the installation of central facilities to handle higher production volumes and the completion of other productive zones within wells.

We seek property acquisitions and development opportunities on lands that are in close proximity to our producing fields. These close-in acquisitions create the ability to reduce operating costs by consolidating facilities. Moreover, drilling costs are lower when wells are drilled as part of a multi-well program, due to reduced rig moving costs and other efficiencies.

While our main focus is the exploitation and development of our properties, we will pursue acquisitions of oil and gas producing properties but only at prices that allow the base production for the property to pay the acquisition cost within a reasonable time frame. We attempt to avoid paying for unproven reserves in the purchase price.

We concentrate our drilling activities on low risk development wells located in or near our established core production areas. This strategy helps to reduce risk and costs, and enables new wells to be put on production more quickly. We do engage in exploratory drilling but only when the potential rewards justify the risks involved.

We use the analysis of seismic data, including three-dimensional seismic, whenever its use is appropriate for the geology and is cost effective, to further minimize drilling risk. We also use information from adjacent wells, including petrophysical data, production records and completion data to help reduce our risk and costs.

We select properties for acquisition and development where we believe we can become the operator and that we believe offer us the opportunity to reduce operating costs and maximize economies of scale, thereby improving operating profitability. We have used this strategy in the development of our core areas in Alberta and Saskatchewan, focusing on areas of moderate drilling costs, multi-zone potential, year round accessibility and good gas plant and pipeline infrastructure.

Enterra's core areas included the Peace River Arch area of Alberta, West Central Alberta and South West Saskatchewan, in addition to its core fields at Sounding Lake and Sylvan Lake. Enterra also has a substantial inventory of prospects, the development of which could potentially double the size of the Company’s existing production and reserve base. In accordance with the standard practice in the Canadian oil and gas industry, the working interests described below are the percentage ownership of the oil and gas production before payment of royalties.

NORTHWEST ALBERTA

A new Montney oil pool was discovered in Northwest Alberta in 1998. The Monte reservoir consists of light oil trapped above water. Enterra plans to develop this pool in 2002 utilizing horizontal drilling technology.  Solution gas will also be tied into existing gathering systems and processed at a nearby gas plant. The Company has a 50% working interest in this play. An analogous pool has been developed in the area resulting in the first horizontal well going on production in late 2000 at 300 bbls/day and has produced in excess of 75 mbbls of reserves to date.

Enterra acquired interests ranging from 30% to 100% in five contiguous sections of land in the Gordondale area of Northwest Alberta. This exploration area is gas prone in up to eight formations ranging from the Doe Creek at depths of less than 200 m to the Debolt formation at a depth of 2450 m. Enterra shot a 3-D seismic program over the area in 2001 and identified several locations with multi zone potential. In early 2002, the first well was drilled, encountering gas potential in the Kiskatinaw, Taylor Flats, Montney and Halfway formations. The Company completed the Kiskatinaw formation which had an initial production rate of approximately 2 mmcf/day. . Enterra has plans to drill several more development and exploration wells at Gordondale and estimates net deliverability from the area could exceed 500 boe/day.

A significant Dunvegan gas pool was discovered in Northwest Alberta in late 2000. Two wells were drilled in 2001 that are each capable of producing over 1 mmcf/day.  The gas was tied into a nearby plant in early 2002. The two wells are currently flowing a combined rate 1 mmcf/day net to Enterra. The Company has also identified other locations on its lands that will be drilled in 2002. Enterra has a 50% interest at Rolla.

CENTRAL ALBERTA

Sounding Lake continues to be Enterra’s largest area in terms of production, representing approximately 25% of the Company’s 2001 production. Enterra’s focus on the area will remain strong through 2002 with an aggressive drilling schedule combined with additional reduction in operating costs. The majority of production and future activity in the area will target Dina and Cummings oil. A highlight at Sounding Lake in 2001 was the discovery of a new Belly River gas pool. Two wells are now producing from this pool at facility restricted rates of 1.5 mmcf/day net to the Company.  Enterra also structured a unique farmout arrangement to construct a central facility, optimize and infill drill the Sounding Lake North oil pool. This farmout arrangement will maximize value to Enterra by eliminating required 2002 capital expenditures and reducing operating expenses. Enterra will also continue development of the Sounding Lake East, Rex oil discovery. The Company will shoot a 3-D seismic survey in mid 2002 to substantiate four geologically defined locations. The discovery well, drilled in 1997, has produced 65 mbbls of oil and is still producing 50 bbls/day.

Enterra continues to be excited about the Pekisko infill development potential at Sylvan Lake. Geological mapping and petrophysics suggest that there are at least six infill drilling locations. Defined by their proximity to an area of the reservoir that has undergone dolomitization. This process increases the porosity and permeability of the predominately limestone reservoir. Although the best producer at Sylvan Lake is capable of producing in excess of 100 bbl/d, Enterra is targeting production from the six infill wells to be 75 bbls/day of oil per well. Enterra also successfully recompleted a suspended well at Sylvan Lake to a Viking gas producer. This well is expected to be tied in and on stream by June 2002 at an initial rate of 1 mmcf/day.

SOUTHWEST SASKATCHEWAN

Enterra acquired a shut in Waseca oil pool in Southwest Saskatchewan for $2.8 million in June of 2001. The Company equipped and reactivated four existing producers. Combined gross production from these wells is 250 bbls/day. Late in 2001, Enterra added four Waseca infill oil wells.

NEW PROSPECTS

One of Enterra’s most valuable asset is its inventory of future projects. The development of these prospects has the potential to double the size of the Company’s existing production and reserve base. New prospects are constantly added to our inventory in order to maintain our growth from year to year. The Company’s strategy is to maintain a balanced inventory of exploration and development prospects. In accordance with the standard practice in the Canadian oil and gas industry, the working interests described below are the percentage ownership of the oil and gas production before payment of royalties.

The estimated oil and natural gas reserves of Enterra and the associated estimated present value of estimated future net cash flows have been evaluated in a report as of January 1, 2002 prepared by McDaniel & Associates Consultants Ltd. ("McDaniel"), independent petroleum engineers of Calgary, Alberta.

The following table is based on the McDaniel report that shows the estimated share of the remaining oil, natural gas and natural gas liquids attributable to Enterra and the estimated present value of estimated future net cash flows for these reserves, using constant prices and costs. All estimates of present value of future net cash flows are stated after provision for capital expenditures required to generate such revenues but prior to provision for indirect costs such as general and administrative overhead, income taxes or interest expense. It should not be assumed that the estimated present values of future net cash flows are representative of the fair market value of the reserves. These recovery and reserve estimates of Enterra’s interests in the described properties are estimates only; the actual reserves in the properties in which we have an interest may be more or less than those calculated. Assumptions and qualifications relating to costs, prices and other matters are summarized in the notes to the following table. The extent and character of the material information supplied by Enterra including, but not limited to, ownership, well data, production, price, revenues, operating costs and contracts were relied upon by McDaniel in preparing the report. In the absence of such information, McDaniel relied upon their opinion of reasonable practice in the industry. The McDaniel report may be examined at the office of Enterra located at Suite 2600, 500- 4^th Avenue S.W., Calgary, Alberta during normal business hours. All monetary amounts are expressed in Canadian dollars.

__________

Notes:

(1) Definitions:

"ARTC" means the Alberta Royalty Tax Credit.

"NGL" means natural gas liquids.

"Gross" means the total of Enterra’s working interest share of reserves before deduction of Royalties.

"Mbbl" means thousands of barrels.

"Mmcf" means millions of cubic feet.

"Net" means gross reserves after deduction of Royalties. In order to estimate reserves after giving effect to the deduction of provincial royalties, certain assumptions must be made including forecasts of future prices and production. The net reserves are based on forecasts by Sproule Associates of these and other factors necessary to estimate provincial and other royalties.

"Oil" means crude oil.

"Proved oil and gas reserves" are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

"Proved developed oil and gas reserves" are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included. Only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

"Royalties" means royalties paid to others. The royalties deducted from the reserves are based on the percentage royalties calculated by applying the applicable royalty rate or formula. In the case of Crown (the federal or provincial governments in Canada) sliding scale royalties which are dependent on selling price, the price forecasts for the individual properties in question have been employed.

"Sales Gas" means natural gas which is produced for commercial sale.

(2) The commodity prices used in the McDaniel report are based on average actual field prices in effect during 2001. These prices are being held unescalated throughout the term of the report. A summary of the constant prices used in the McDaniel report are shown below.

The following table sets out Enterra’s proved oil and gas reserves, before royalties, at December 31, 2001, 2000, 1999, 1998 and 1997 respectively. The amounts for December 31, 2001 are based upon a report prepared for Enterra by McDaniel at January 1, 2002. The monetary amounts are expressed in Canadian dollars. The reserve numbers for December 31, 1998 and 1997 were prepared internally by Enterra, based upon reserve reports prepared at various dates by independent engineering firms and adjusted for actual production. Present value amounts are not available as it is not feasible to redo such calculations after the fact.

At December 31, 2001 Enterra had the following land holdings

The following table summarizes Enterra’s working interest production, before royalties, during the periods indicated.

Definitions:

"BOEPD" means barrels of oil equivalent produced per day.

"MBOE" means thousands of barrels of oil equivalent, meaning one barrel of oil or one barrel of natural gas liquids or ten mcf of natural gas.

"MBbls" means thousands of barrels, with respect to production of crude oil or natural gas liquids.

"MMcf" means millions of cubic feet, with respect to production of natural gas.

"NGL’s" means natural gas liquids, being those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and pentanes plus, or a combination thereof.

Enterra’s drilling history is as follows (there were no wells drilled in 1997 and 1999) :

__________

Notes:

(1) "Gross" wells means the number of whole wells.

(2) "Net" wells means Enterra’s working interest in the gross wells.

 

The following table summarizes the capital expenditures made by Enterra during the periods indicated, expressed in Canadian dollars:

The following table summarizes Enterra’s interest in producing and non-producing oil and gas wells as at December 31, 2001 :

At December 31, 2001 the Company had approximately twelve employees and consultants working both in the Calgary head office and in its field operations.

The petroleum industry is highly competitive. Enterra competes with numerous other participants in the acquisition of oil and gas leases and properties, and the recruitment of employees. Any company can make acquisitions and bid on provincial leases in Alberta. Competitors include oil companies that have greater financial resources, staff and facilities than those of Enterra. Our ability to increase reserves in the future will depend not only on our ability to develop existing properties, but also on our ability to select and acquire suitable additional producing properties or prospects for drilling. We also compete with numerous other companies in the marketing of oil. Competitive factors in the distribution and marketing of oil include price and methods and reliability of delivery.

Enterra currently leases 10,450 square feet of office space at Suite 2600, 500 - 4th Avenue S.W. in Calgary, Alberta in a lease that commenced November 1, 2001. The lease has a three-year term (expiring on November 30, 2004) and the annual rental is C$27.26 per square foot (including operating costs and property taxes).

The oil and natural gas industry is subject to extensive controls and regulations governing its operations, including land tenure, exploration, development, production, refining, transportation and marketing, imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta and British Columbia, all of which should be carefully considered by investors in the Canadian oil and gas industry. It is not expected that any of these controls or regulations will affect the operations of Westlinks in a manner materially different from how they would affect other oil and gas companies of similar size operating in Western Canada. All current legislation is a matter of public record and Enterra is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends in part on oil quality, prices of competing oils, distance to market, the value of refined products and the supply/demand balance. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada, or NEB. Any oil export to be made pursuant to a contract of longer duration, to a maximum of 25 years, requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council. In addition, the prorationing of capacity on the interprovincial pipeline systems continues to limit oil exports.

The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices with purchasers, provided that the export contracts meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to twenty years, in quantities of not more than 30,000 m³/day, must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration, up to a maximum of 25 years, or a larger quantity, requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.

The governments of British Columbia and Alberta also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve ability, transportation arrangements and market considerations.

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry.

In the Province of Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit or, ARTC program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per thousand cubic metres and 25% at prices at and above $210 per thousand cubic metres. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate will be established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the previous quarterly period.

On December 22, 1997, the Alberta government announced that it was conducting a review of the ARTC program with the objective of setting out better-targeted objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Alberta government announced that it would not be reducing the size of the program but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying for the program. Such rules will not presently preclude Enterra from being eligible for the ARTC program.

Crude oil and natural gas royalty holidays for specific wells and royalty reductions reduce the amount of Crown royalties paid by Enterra to the provincial governments. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms from two years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act, or EPEA, which came into force on September 1, 1993. The EPEA imposes stricter environmental standards, requires more stringent compliance, reporting and monitoring obligations and significantly increases penalties for violations. Enterra is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. Enterra believes that it is in material compliance with applicable environmental laws and regulations. Enterra also believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

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.

The following discussion is to inform you about our financial conditions, liquidity and capital resources as of December 31, 2001 and December 31, 2000 and the results of operations for the years ended December 31, 2001 and 2000. The information is expressed in Canadian dollars.

At December 31, 2001, Enterra’s working capital was a deficit of $2,229,431 (2000 - $3,164,681). Under U.S. GAAP the deficit would be $20,728,629 (2000 - $11,567,681) due to the reclassification of the long-term debt to current liabilities. At December 31, 2001 Enterra had a revolving production loan with a Canadian bank. The production loan only requires the payment of interest and is reviewed annually to ensure Enterra’s reserves are sufficient to support the loan. Under Canadian GAAP, because the bank has indicated that it does not require payment of the facility in the next 12 months, the loan is classified as long term. Effective January 1, 2002 the Canadian GAAP rules will mirror the U.S. GAAP rules: the calculation and presentation of working capital will then be consistent under both Canadian and U.S. GAAP.

Cash flow from operations was $ 9,810,269 in 2001 (2000 - $5,875,500) . The increase was largely due to the added production as a result of the Big Horn acquisition, effective August 1, 2001, and the acquisition of the Grand Forks property, effective April 1, 2001. The Company also received approximately $1,680,000 in the first quarter of 2001 upon the settlement of a hedging contract.

During the year ended December 31, 2001 there was a decrease in non-cash working capital of $2.7 million. The decrease was the direct result of income tax payments of $1.2 million made in 2001 (which were accrued at December 31, 2000) an a decrease in accounts payable of $1.5 million.

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 December 31, 2001 was $18.4 million (2000 - $8.4 million). In both periods the funds were used to acquire capital assets and support ongoing operations. At December 31, 2001 Enterra’s bank facility consisted of a line of credit of $21.5 million (of which $18.4 was drawn). 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. Subsequent to December 31, 2001 the line of credit was increased to $24 million.

The Company completed a secondary public offering in the United States in January of 2001, consisting of 1,000,000 units of one common share and one share purchase warrant for US$4.55 per unit. The share purchase warrants have an expiry date of April 17, 2002 and are exercisable at US$3.50 per share. The proceeds from this offering were used to purchase the Grand Forks oil and gas assets for $5.5 million in March of 2001.

Effective August 1, 2001, Enterra acquired 100% of Big Horn for cash of $2.2 million (not including acquisition costs) and the issuance of 3,496,436 common shares and 7,418,332 preferred shares. Enterra has also repurchased, through its previously announced share buyback program, 232,500 of its common shares during 2001. The Company currently has 9,150,622 common shares outstanding.

The Company’s total debt, including working capital deficiency and preferred shares, at December 31, 2001 was $26.9 million.

Subsequent to December 31, 2001 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 Company was not taxable in 2001. It has $43.1 million in tax pools available at December 31, 2001.

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.

Investing activities for the year ended December 31, 2001 amounted to $15,047,667 (2000 - $15,358,176). In both years the majority of the funds were allocated to capital expenditures. The Big Horn acquisition required approximately $2 million in cash.

During 2001 several non-core properties were disposed of for $1,700,500 (2000 - $5,764,570). Enterra defines a "non-core property" as a property where management believes that opportunities to increase its value are limited and the property represents less than 20% of the Company’s total reserves.

Gross revenue from oil and gas production was $20,264,396 in 2001 (2000- $16,700,151) which represents an increase of 21%. The increase was mainly due to the Big Horn and Grand Forks acquisitions made during the year. The Company drilled 20 wells (10.59 net) in 2001, resulting in 9 oil wells (4.97 net) and 8 gas wells (3.78 net) for a success ratio of 85%. Enterra’s production in 2001 averaged 1,906 boe/day, consisting of 1,595 bbls/day of oil and 1,863 mcf/day of natural gas, for a mix of 84% oil and 16% natural gas.

Average oil prices declined by 23% during 2001 and average gas prices declined by 40% over the same period. The Company received an average of $30.53 per barrel for its oil production during 2001, compared with $39.79 in 2000. The Company received an average of $3.66 per mcf for its natural gas production during 2001, compared with $6.15 in 2000. As a result, Enterra’s revenue per boe declined by $10.58 (or 27%) per boe in 2001.

Royalties in 2001 were $3,182,341 (2000 - $3,310,138). As a percentage of oil and gas revenues, royalties were 16% during 2001 compared to 20% for 2000. The change is a function of lower prices being in effect during 2001 and to the fact that a larger portion of Enterra’s production was eligible to receive Alberta Royalty Tax Credits in 2001. This credit significantly reduces the impact of provincial Crown royalties.

In the Province of Alberta, a producer of oil and natural gas is entitled to a credit against the royalties payable to the province by virtue of the Alberta Royalty Tax Credit, or ARTC, program. The ARTC rate is based on a price-sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per thousand cubic metres and 25% at prices at and above $210 per thousand cubic metres. The ARTC rate is applied to a maximum of $2,000,000 of Alberta provincial royalties payable for each producer or associated group of producers. Provincial royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average "par price" as determined by the Alberta Department of Energy for the previous quarterly period.

Operating expenses were $5,829,614 in 2001 (2000 - $4,029,703). This increase is the result of the increased production in 2001. On a barrel of oil equivalent basis operating costs for 2001 and 2000 were $8.38 and $9.58, respectively. 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 in the second half of 2001.

General and administrative expenses decreased 59% from $1,391,297 in 2000 to $565,270 in 2001. On a barrel of oil equivalent basis administrative costs decreased 75% from $3.31 in 2000 to $0.81 in 2001. The decrease in administrative costs was largely due to the corporate synergies as a result of combining Enterra and Big Horn without increasing salaries, while eliminating redundancies.

Interest expense for 2001 was $589,169 compared to $833,342 in 2000. The decrease was a result of lower interest rates in 2001 in addition to the reduced debt levels in the first half of 2001 as a result of the equity financing which occurred in early 2001.

Depletion and depreciation for the years ended 2001 and 2000 was $6,869,912 and $4,493,223 respectively. As a percentage of revenue, depletion and depreciation was 34% and 18%. The increase reflects a higher cost base in our capital assets in 2001 and the impact of lower commodity prices.

Enterra incurred $929,000 of one-time restructuring charges (mainly severance and termination payments) during 2001 as a result of the Big Horn acquisition.

Current and future income tax expense at December 31, 2001 was $120,000 and $562,000 respectively, compared to $1,316,171 and $333,634 respectively at December 31, 2000. The reduction in current income taxes is due to the larger tax pools available to Enterra in 2001. The future income tax expenses were a result of the timing of deductions for accounting purposes and tax on petroleum and gas assets.

The Company’s earnings decreased by 34% in 2001 from $2.4 million in 2000 to $1.6 million in 2001. The reasons for this decline are threefold: lower commodity prices, higher depletion expense and one-time restructuring charges. Oil and gas prices declined sharply in 2001. Oil prices averaged $30.53 per bbl in 2001 compared with $39.79 in 2000 (a 23% decrease) and gas prices averaged $3.66 per mcf in 2001 compared with $6.15 in 2000 (a 40% decline). Depletion expense also increased in 2001 due to the increased production and the larger asset base. Depletion, which is a non-cash expense, increased to $6.87 million in 2001 from $2.96 million in 2000. Finally, Enterra incurred $929,000 of one-time restructuring charges (mainly severance and termination payments) during 2001.

Earnings per share declined as well from $0.55 per share in 2000 to $0.23 in 2001. The weighted average number of shares outstanding in 2001 increased by 58% from 4,421,844 in 2000 to 6,992,393 in 2001.

The Company entered into a zero cost collar arrangement during 2001 which provides a floor price of US$20 per barrel and a ceiling price of US$24 per barrel for 500 barrels of oil per day. The contract is effective from November 1, 2001 through April 30, 2002.

The Company had 9,150,622 common shares outstanding at December 31, 2001.

Critical Accounting Policy

The most significant accounting policy for Enterra is its method of accounting for its oil and gas properties.

Enterra follows the "full cost" method of accounting.   All costs of acquiring petroleum and natural gas properties and related development costs are capitalized and accumulated in one cost center.   Enterra places a limit on the aggregate cost of property, plant and equipment which may be carried forward for amortization against revenues of future periods (the "ceiling test").  The ceiling test is a cost recovery test whereby the capitalized costs less accumulated depletion and site restoration are limited to an amount equal to estimated undiscounted future net revenues from proved reserves less recurring general and administrative expenses, site restoration, future financing costs and income taxes.  Costs and prices at the balance sheet dates are used.  Any costs carried on the balance sheet in excess of the ceiling test limitation are charged to earnings.

Under the alternative "successful efforts" method, surrendered, abandoned and impaired leases, delay lease rentals, dry holes and overhead costs are expensed as incurred. Capitalized costs are depleted on a property by property basis. Impairments are assessed on a property by property basis and are charged to expenses when assessed.

We believe the "full cost" method, as described above and in the Risk Factors section of this document, as well as in the notes to the attached financial statements, is the appropriate method to use to account for Enterra’s oil and gas exploration and development activities. The Company’s strategy calls for substantial exploration and development activities in 2002 and subsequent years. We believe the "full cost" method is a more appropriate accounting policy for our oil and gas operations as it is better suited in recognizing that the costs of our exploration and development programs are part of an overall long-term investment in discovering and developing sustainable oil and gas reserves.

On March 26, 2002 the Company redeemed 6,123,870 of its Series 1 preferred shares for $2.3 million, resulting in a gain of $2,905,290.

On March 28, 2002 the Company agreed to issue 400,000 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 200,000 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.

On April 12, 2002 the Company was granted a 30-day extension for the 1,000,000 share purchase warrants which were exercisable until April 17, 2002. The expiry date was extended to May 17, 2002. The warrants expired on May 17, 2002 without being exercised.

Financial Condition, Liquidity and Capital Resources

At December 31, 2000, Enterra’s’ working capital was a deficit of $3,164,681. Under U.S. GAAP the deficit would be $11,567,681 due to the reclassification of the long-term debt to current liabilities. At December 31, 2000 Enterra had a revolving production loan with a Canadian bank. The production loan only requires the payment of interest and is reviewed annually to ensure Enterra’s reserves are sufficient to support the loan. Under Canadian GAAP, because the bank has indicated that it does not require payment of the facility in the next 12 months, the loan is classified as long term.

Cash flow from operations was $5,875,500 for the year ended December 31, 2000 compared to $293,767 for the year ended December 31, 1999. The increase was largely due to an increase in net income to approximately $2.3 million and the increase in the non-cash depletion, depreciation and site restoration to $4.5 million.

During the year ended December 31, 2000 there was an increase in non-cash working capital of $3.2 million. The increase was the result of an increase in accounts payable and accrued liabilities of $5.0 million offset in part by an increase in accounts receivable of $1.8 million.

Financing Activities

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 total debt was $8.4 million at December 31, 2000 and $2.6 million at December 31, 1999. In both periods the funds were used to acquire capital assets and in the year ended December 31, 2000 ten wells were drilled. At December 31, 2000, Enterra had drawn $8.4 million on its $9.0 million revolving operating facility. The facility bears interest at the bank’s prime commercial lending rate plus one quarter of one percent.

During the year ended December 31, 2000, Enterra had been technically in default under the covenants in the credit facility that require that the current asset ratio not fall below a ratio of one to one. At the time of the default the current asset ratio was 0.44. The bank had allowed Enterra to draw down the credit facility, knowing that draw down would cause the technical default. This technical default was cured by the end of the third quarter from current cash flows and the repayment of US$1,500,000 loan.

During the year, Enterra sold all of the assets in the Bigoray area in Alberta. At the close of the sale on November 15, 2000 the Company received proceeds of $4,494,500 which were principally used to reduce bank debt. In addition, the bank reduced the revolving operating facility from $12.5 million to $9.0 million.

During the year Enterra borrowed US$1,500,000 from six non-affiliated private lenders. The loans bore interest of 12% per annum plus a US$50,000 setup fee. We also issued to the lenders warrants to purchase 150,000 shares at US$4.00 per share. The loans were repaid in full and all of the warrants were exercised on September 30, 2000.

During the year ended December 31, 2000, $415,000 was raised from the exercise of common stock options, and applied to our operating activities.

Effective November 1, 2000 Enterra entered into a three year fixed price crude oil contract. In January 2001, the Company settled the fixed price contract eliminating the requirement to deliver set physical quantities of oil at fixed prices. Upon the cancellation of the contract the Company received approximately $1,680,000 which will be recognized over the terms of the contract.

Investing Activities

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, Enterra 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.

Investing activities for the year ended December 31, 2000 amounted to $15,358,176 compared to $3,373,539 for the year ended December 31, 1999. The increase in 2000 was principally due to the Mitsue and Sounding Lake acquisitions, drilling three wells in Bigoray, and drilling seven wells in Sylvan Lake, and was partially offset by the Bigoray area disposition.

During the years ended 2000 and 1999 several non-core properties were disposed of for $5,764,570 and $796,800, respectively. Enterra defines a "non-core property" as a property where management believes that opportunities to increase its value are limited and the property represents less than 20% of Enterra’s total reserves. The funds received from the sales are typically used either for future acquisitions or the drilling of new wells consequently the impact on the results of operations and future liquidity is minimized.

Results of Operations

Gross revenue from oil and gas production was $16,700,151 for the year ended December 31, 2000 compared to $2,515,456 for the year ended December 31, 1999 which represents an increase 564%. The increase was due to the Sylvan Lake acquisitions made late in 1999 and the Mitsue and Sounding Lake acquisitions during the first half of 2000, offset in part by the property dispositions during 2000.

Oil revenues before royalties increased 586% in 2000 to $16,312,523 from $2,379,417 in 1999. This was due to increased volumes and higher prices. As a result of project acquisitions and drilling activities, oil production increased 339% from 93,487 in 1999 to 409,958 barrels in 2000. During 2000 we received an average price of $39.79 per barrel compared to $25.45 per barrel during 1999.

Gas revenues before royalties increased 185% in 2000 to $387,629 from $136,039 in 1999. The increase was largely due to higher gas prices. Total volumes increased from 61,068 thousand cubic feet to 62,988 thousand cubic feet. The average price realized during 2000 was $6.15 per mcf compared to $2.23 per mcf in 1999.

Total net royalties for the first nine months of 2000 and 1999 were $3,310,138 and $442,335 respectively. As a percentage of oil and gas revenues, royalties were 20% during 2000 compared to 18% for 1999. The increase was mainly due to our purchase of producing properties that are not eligible to receive Alberta Royalty Tax Credits. This credit significantly reduces the impact of provincial Crown royalties.

In the Province of Alberta, a producer of oil and natural gas is entitled to a credit against the royalties payable to the province by virtue of the Alberta Royalty Tax Credit, or ARTC, program. The ARTC rate is based on a price-sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per thousand cubic metres and 25% at prices at and above $210 per thousand cubic metres. The ARTC rate is applied to a maximum of $2,000,000 of Alberta provincial royalties payable for each producer or associated group of producers. Provincial royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average "par price" as determined by the Alberta Department of Energy for the previous quarterly period.

Operating expenses increased 415% from $782,281 in 1999 to $4,029,703 in 2000. On a barrel of oil equivalent basis operating costs for 2000 and 1999 were $9.58 and $7.57, respectively. The overall increase was due to increased production from the recent acquisitions. Operating costs increased on a per barrel basis due to higher costs associated with the Mitsue and Sounding Lake acquisitions. The Company commonly experiences higher initial operating costs on acquisitions due to the fact that the prior owners of the properties, because they are selling the properties, do not provide the necessary ongoing repairs and maintenance. Once the properties are acquired, Enterra will incur costs to make repairs, put the properties in good operating condition and optimize production. Upon the completion of these activities, operating costs on a per barrel basis should generally decrease.

General and administrative expenses increased 61% from $862,546 during 1999 to $1,391,297 in 2000. On a barrel of oil equivalent basis administrative costs decreased from $8.32 in 1999 to $3.31 in 2000. The increase in administrative costs was largely due to increasing salaries for the existing staff and the hiring of additional staff. The decrease in administrative costs, on a barrel of equivalent basis, resulted from increased volumes and our efforts to maintain our current staff level while increasing production.

Interest expense for 2000 was $833,342 compared to $131,872 in 1999. The increase was a result of increased debt outstanding. At the end of 2000, total debt outstanding was $8.4 million as compared to $2.6 million at the end of 1999.

Depletion and depreciation for the years ended 2000 and 1999 was $4,493,223 and $841,580 respectively. On a barrel of equivalent basis depletion and deprecation was $10.68 and $8.45. The increase reflects a higher cost base in our capital assets.

During the year ended Enterra disposed of non-core oil and gas properties that resulted in a gain of $1,338,577 compared to a gain of $91,402 in the corresponding period in 1999.

Current and future income tax expense at December 31, 2000 was $1,316,171 and $333,634 respectively, compared to a future income tax recovery of $246,884 at December 31, 1999. The expenses were a result of the timing of deductions for accounting purposes and tax on petroleum and gas assets. The recovery in 1999 was attributable to loss carry forwards not previously recognized.

The directors and executive officers of Enterra as of December 31, 2001 were:

In 2002, John McGrain resigned as Director and Chairman, Don Almond resigned as Vice President Production, Thomas Jacobsen was appointed Chief Operating Officer and two new Directors ( Doug Paul and Norman W.G. Wallace) were elected to the Board:

Walter A. Dawson. Mr. Dawson was formerly the Executive Chairman of Enserco Energy Services Corp. He resigned in March 2001 after the merger with Tetonka was completed to pursue the creation of Simmons Energy Services. In 1993, Mr. Dawson, through his 100%-owned holding company, Perfco Investments Ltd., purchased control of Bonus Petroleum Corp., a public company that became Enserco. Enserco is now a leader in the Canadian workover and drilling market with 200 service rigs and 30 drilling rigs in Canada and Australia and will achieve revenue of $250 million along with over $80 million cash flow in 2001. Prior to Perfco Investments, Mr. Dawson founded and served 19 years as President, Chief Executive Officer, and director of Computalog Ltd. In 1972, Mr. Dawson purchased a cased-hole wireline unit from Gearhart Industries and incorporated Perfco Services Ltd., which later formed Computalog Gearhart Ltd. in 1978. He was instrumental in taking the company public on the Toronto Stock Exchange in 1980, negotiating an exclusive technology/supply agreement with Gearhart Industries for Canada. Afterwards, he entered the directional and fishing tool business, along with the incorporation of the company’s first research center where he hired 50 research and development experts to design and build state-of-the-art well logging equipment. Mr. Dawson led and completed several financings to achieve this goal. Mr. Dawson is currently a director of Integrated Production Services, a Toronto Stock Exchange listed company, and is a director of Action Energy Inc., a private company. He also held positions on several oil and gas boards over his career for both service and producing companies. Mr. Dawson became a Director of Enterra in August 2001.

Reg J. Greenslade. Mr. Greenslade became President of Big Horn in April 1995 and President and CEO and a Director of Enterra in August 2001. Prior to joining Big Horn, Mr. Greenslade held senior positions with several medium- and large-sized oil and gas companies. Most recently Mr. Greenslade was with CS Resources Limited in the areas of exploitation engineering and project management from 1993 to 1995. He was previously with Saskatchewan Oil and Gas Corporation in the capacities of project management, production, and reservoir engineering. He has extensive experience with secondary recovery schemes and is recognized for his work in the specialized field of horizontal well technology.

H.S. (Scobey) Hartley. Mr. Hartley was appointed a director of Enterra in May, 2000. He has been Chairman of Prism Petroleum Ltd. since January, 1997 and was formerly the President of Prism Petroleum Ltd. and a predecessor company from December, 1990 through December, 1996. Mr. Hartley has also served as the President of Faster Oilfield Services since June, 1995, and was the President of Cayenne Energy Corp. from 1990 through 1996. He received a Bachelor of Science degree in Geology from Texas Tech University in 1956.

Thomas J. Jacobsen. Mr. Jacobsen joined Enterra as a director in February 1999, and was appointed Executive Vice-President, Operations in October 1999. In October 2000 he resigned from this position and was appointed the Vice-Chairman of the Board of Directors. He was also appointed President of a U.S. subsidiary to be created, Westlinks Inc. As President of Westlinks Inc., Mr. Jacobsen will review oil and gas opportunities in the United States. Through his company, Wells Gray Resort & Resources Ltd., Enterra also granted him a consulting contract through April 15, 2001; pursuant to which Mr. Jacobsen was be in charge of Enterra’s drilling, completion and equipping projects. His more than 40 years of experience in the oil and gas industry in Alberta and Saskatchewan includes serving as the President and Chief Operating Officer of Americomm Resources Corporation since June 2001; President and Chief Executive Officer of Niaski Environmental Inc. from November, 1996 to February, 1999; President and Chief Executive Officer of International Pedco Energy Corporation from September, 1993 to February, 1996, and President of International Colin Energy Corporation from October, 1987 to June, 1993. Mr. Jacobsen currently serves as a director of Niaski Environmental Inc., a company listed on the Canadian Venture Exchange. Niaski has made a proposal to its creditors under the Bankruptcy and Insolvency Act (Canada). The proposal has been approved by the creditors but has not yet been funded and completed. Mr., Jacobsen became Enterra’s Chief Operating Officer in January 2002.

John P. McGrain. Mr. Mcgrain was appointed Chairman and acting President of Enterra in April 2001. Mr. McGrain has been Chairman and Interim Chief Executive Officer of Americomm Resources Corporation since June 2001 and served as Chairman and Chief Executive Officer of International Colin Energy from 1991 to 1994, and Chairman and Chief Executive Officer of Conversion Industries from 1984 to 1994. In 1997 Mr. McGrain filed for protection under personal bankruptcy Chapter 11 and was discharged in 1998. Since 1998 he has been a private investor. Mr. McGrain graduated from UCLA with a Bachelor of Arts degree in 1967. Mr. McGrain resigned as Chairman and Director in June 2002.

Don Almond. Mr. Almond has accumulated 25 years of oil industry experience. His career began with Husky Oil in field operations. He then moved on to PanCanadian Petroleum and Wascana Energy where he gained extensive experience with all aspects of production, exploitation, and operations engineering. In 1997, Mr. Almond joined Opal Energy Inc. as Vice President of Operations and remained in this role until the corporation was sold at the end of 1998. In mid-1999, Mr. Almond was a founder and Vice President of Operations of Ranchero Oil & Gas Ltd. He remained in this role until early 2001 when another oil and gas company acquired his corporation. Mr. Almond joined Enterra as Vice President Production in November 2001 and resigned in April 2002.

Luc Chartrand. Mr. Chartrand worked for KPMG as a Chartered Accountant from 1985 to 1988 when he became a tax manager in their Calgary office. He left shortly thereafter and worked as a consultant to several Calgary companies. He moved to Toronto in 1990 to assist in the relocation and takeover of Financial Trust by Central Capital. He remained in Toronto until 1992 when he returned to Calgary with Morgan Financial Corporation. Shortly thereafter, he joined Bonus Resource Services Corp. as its Chief Financial Officer. Mr. Chartrand joined Big Horn Resources Ltd. in the fall of 1994 and became Chief Financial Officer in 1996. He became Chief Financial Officer of Enterra in August 2001.

Rick McHardy. Mr. McHardy has been a partner with the law firm of McCarthy Te'trault LLP since July, 2002. Prior to joining McCarthy Te'trault, from August, 1999, Mr. McHardy practised law with the firm of Donahue LLP, an associated firm of Ernst & Young LLP. From July, 1995 to August, 1999, Mr. McHardy practised law with the firm of Code Hunter. Mr. McHardy specializes in mergers and acquisitions matters involving both public and private companies and has experience in a wide variety of corporate finance and securities transactions. Mr. McHardy obtained a Bachelor of Commerce degree from the University of Saskatchewan in 1990 and a Bachelor of Laws degree from the University of Saskatchewan in 1993.

Trevor Spagrud. Mr. Spagrud started his professional career with Saskatchewan Oil and Gas (SaskOil) in 1990, gaining progressive experience in production, completions, and reservoir engineering. He remained at SaskOil, which became Wascana Energy, until 1996 when he held the position of Senior Development Engineer. In this position, Mr. Spagrud was responsible for all engineering functions in both development and exploration prospects. In 1996, he became the Engineering Manager at Truax Resources and remained there until the company was taken over in June 1997, at which time he moved to Big Horn. He became Big Horn’s Vice President of Operations in 1998 and Enterra’s Vice President of Operations in August 2001.

Doug Paul. Mr. Paul had a career spanning over 30 years with the Royal Bank of Canada, during which time he held a number of administrative and lending positions. His assignments with the bank included the position of Senior Auditor, which entailed assessment of the quality of the bank’s loan portfolio both domestically and internationally. Most recently Mr. Paul worked in the bank’s oil and gas division where he administered a loan portfolio of some $500MM, which included domestic and international exploration and development companies, drilling and service companies. In that capacity, Mr. Paul supported the growth and development of the largest drilling and services companies in Western Canada. Currently as Vice President of Canada West Corporate Finance, where he has been engaged for some two years, Mr. Paul holds associate membership in C.A.O.D.C. and P.S.A.C.

Norman W.G. Wallace. Mr. Wallace was elected a director of Enterra in May 2000. He has been the owner of Wallace Construction Specialties Ltd. since 1972. Mr. Wallace received a Bachelor of Commerce degree from the University of Saskatchewan in 1968. Mr. Wallace resigned as Director in August 2001 and was re-appointed in June 2002.

Enterra is authorized to have a board of at least three directors and no more than ten. We currently have six directors. Our directors are elected for a term of about one year, from annual meeting to annual meeting, or until an earlier resignation, death or removal. Each officer serves at the discretion of the board or until an earlier resignation or death. There are no family relationships among any of our directors or officers. Alberta corporate law requires that we have at least two independent outside directors who are not officers or employees of Enterra.

Currently directors receive an annual retainer of $7,500. In addition, directors receive fees in the amount of $750 for each directors' meeting which they personally attend and $250 for each conference call which they participate in which exceeds 1 hour in duration. Directors are also entitled to be compensated for their out-of-pocket costs, including travel and accommodation, relating to their attendance at any directors' meeting. Finally, the directors are entitled to participate in the Corporation's stock option plan. During the year ended December 31, 2001, options to acquire a total of 240,000 common shares were granted to the current directors of the Corporation (not including options granted to a director who is also a named executive officer). Except as described herein, no compensation by way of annual retainer or meeting fees was paid to directors for acting in such capacity in the year ended December 31, 2001.

Enterra’s Board of Directors currently has an audit committee, a compensation committee, a corporate governance committee and a reserves committee.

Audit Committee. Our audit committee consists of Mr. Dawson (Chairman), Mr. Paul and Mr. Wallace, all three being independent directors. The audit committee reviews in detail and recommends approval of the full board of our annual and quarterly financial statements; recommends approval of the remuneration of our auditors to the full board; reviews the scope of the audit procedures and the final audit report with the auditors, and reviews our overall accounting practices and procedures and internal controls with the auditors.

Compensation Committee. Our compensation committee consists of Mr. Hartley (Chairman), Mr. Wallace and Mr. Dawson. The compensation committee recommends approval to the full board of the compensation of the Chief Executive Officer, the annual compensation budget for all other employees, bonuses, grants of stock options and any changes to our benefit plans.

Corporate Governance Committee. Our corporate governance committee consists of Mr. Wallace (Chairman), Mr. Dawson and Mr. Hartley. The corporate governance committee determines the scope and frequency of periodic reports to the board concerning issues relating to overall financial reporting, disclosure and other communications with all stakeholders.

Reserves Committee. Our reserves committee consists of Mr. Paul (Chairman) and Mr. Hartley. The reserves committee reviews and recommends approval to the full board of Enterra’s annual reserve report as prepared by independent reservoir engineers.

The following table provides a summary of compensation earned during the last fiscal year ended December 31, 2001 by the Corporation's executive officers during 2001. These officers were appointed to their positions in August 2001. The compensation shown below is based on a calendar 2001 year, including the months prior to August 2001.

All monetary amounts are in Canadian dollars.

Management Contracts

Enterra has employment contracts with Reginald Greenslade and Trevor Spagrud which provide that the named executive officer will be paid a severance payment if: (a) the named executive officer's employment is terminated; or (b) a change of control occurs in the Corporation and the named executive officer does not continue to be employed by the Corporation at a level of responsibility or a level of base salary and compensation at least commensurate with the named executive officer's level of responsibility, base salary and compensation immediately prior to the change of control and the named executive officer elects to terminate his employment within twelve (12) months of the change of control. The severance payment is based upon the named executive officer's monthly salary. Mr. Greenslade and Mr. Spagrud are entitled up to a maximum of 30 months and 24 months severance payment, respectively. Additionally, both Mr. Greenslade and Mr. Spagrud are entitled to additional allocation of benefits for past bonus amounts paid to each of them.

Enterra grants stock options from time to time to its directors, officers, key employees, and consultants. The terms and conditions of the options, in accordance with resolutions of our board of directors and the policies of the Canadian Venture Exchange, will not exceed a term of five years. The option price may be at a discount to market price, which discount will not, in any event, exceed that permitted by any stock exchange on which our shares are listed for trading.

Ten percent of Enterra’s shares of issued and outstanding common stock from time to time are reserved for issuance pursuant to stock options. The aggregate number of shares reserved for issuance under option grants, together with any other employee stock option plans, options for services and employee stock purchase plans, will not exceed ten percent of the issued and outstanding shares of common stock. In addition, the aggregate number of shares so reserved for issuance to any one person shall not exceed five percent of the issued and outstanding shares of common stock.

If an optionee ceases to be eligible due to the loss of corporate office or employment for any reason other than death, the option terminates not later than 30 days after the loss of such corporate office; provided that in the event of termination of employment for cause, the board of directors may resolve that the option shall terminate on the date of such termination. Option agreements also provide that estates of deceased participants can exercise their options for a period not exceeding one year following death.

The following table discloses the grants of options to purchase or acquire shares of common stock to our executive officers during the fiscal year ended December 31, 2001. All monetary amounts are in Canadian dollars.

A total of 990,000 options were granted by Enterra during the fiscal year ended December 31, 2001.

The following table sets forth the aggregate of options exercised by our executive officers during the year ended December 31, 2001 and the December 31, 2001 year-end values for options granted to the executive officers. All monetary amounts are in Canadian dollars.

The following table sets forth information regarding beneficial ownership of our common stock as of December 31, 2001, by:

• each person who is known by Enterra to beneficially own more than 5% of our outstanding common stock;

• each of our executive officers and directors; and

• all executive officers and directors as a group.

Shares of common stock not outstanding but deemed beneficially owned because an individual has the right to acquire the shares of common stock within 60 days are treated as outstanding when determining the amount and percentage of common stock owned by that individual and by all directors and executive officers as a group.

__________

Notes:

(1) The address of each officer and director is Suite 2600, 500 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6. The address of Mr. McGrain is 233 South Orange Grove, Pasadena, California 91105.

(2) In the foregoing table, the common stock beneficially owned by:

• Mr. Greenslade includes stock options to purchase 144,000 common shares at an exercise price of $4.00.

• Mr. Spagrud includes stock options to purchase 100,000 common shares at an exercise price of $4.00.

• Mr. Jacobsen includes stock options to purchase 60,000 common shares at an exercise price of $4.00 and 322,947 shares held by Wells Gray Resort & Resources Ltd.

• Mr. Dawson includes stock options to purchase 60,000 common shares at an exercise price of $4.00 and 362,763 shares held by Perfco Investments Ltd.

• Mr. Chartrand includes stock options to purchase 72,500 common shares at an exercise price of $4.00 and 32,861 shares held by Chevalier Financial Corporation.

• Mr. McHardy includes stock options to purchase 15,000 common shares at an exercise price of $4.00.

• Mr. Hartley consists of stock options to purchase 60,000 common shares at an exercise price of $4.00.

•Mr.McGrain includes stock options to purchase 60,000 common shares at an exercise price of $4.00.

None of Enterra’s directors or executive officers, nor any person who beneficially owns directly or indirectly or exercises control or direction over securities carrying more than 5% of the voting rights attaching to our shares of common stock, nor any known associate or affiliate of these persons had any material interest, direct or indirect in any transaction since January 1, 1997 which has materially affected Enterra, or in any proposed transaction which will materially affect Enterra, except as follows:

In August, 1999, Enterra acquired 759795 Alberta Ltd. from Wells Gray Resort & Resources Ltd. for cash consideration of $400,000. Wells Gray Resort & Resources Ltd. is wholly-owned by Thomas J. Jacobsen. At the time of the acquisition, Mr. Jacobsen was an outside independent director of Enterra. 759795 Alberta held all of the oil and gas interests and expertise of Wells Gray Resort & Resources Ltd., including the services of Thomas J. Jacobsen. 759795 Alberta also had the option to acquire any oil and gas acquisition offer made through Wells Gray Resort & Resources Ltd.

Between September 27 and December 16, 1999 we issued an aggregate of 1,175,000 shares of common stock at $1.00 per share as a private placement to 19 residents of Alberta, Canada. Our directors and officers and their spouses purchased 665,000 shares of common stock, being 57% of the private placement.

On February 16, 2000, Enterra loaned an aggregate of $390,000 to its then officers and directors to exercise outstanding stock options at $1.00 per share. The loans were without interest, payable in full on or before December 31, 2000 and secured by the stock purchased with the proceeds. The loans have all been repaid. The following table sets out the names and positions with Enterra of the borrowers, the amount of the loans and the number of shares purchased with the proceeds.

John P. McGrain, holder of over 5% of our outstanding common stock, was granted options by Enterra’s officers and directors to purchase an aggregate of 500,000 shares of common stock at a price of US $1.50 per share. The options were granted March 15, 2000 and expired October 31, 2000. For administrative convenience, the shares underlying the options were transferred by the directors and officers into a holding company, 855710 Alberta Ltd., which granted the options to Mr. McGrain. Prior to October 31, 2000, Mr. McGrain had exercised all of the options to purchase 500,000 shares of common stock, of which he retains 371,300 shares.

On June 5, 2000, Enterra borrowed US$1,500,000 from six private investors, including US$925,000 from Patrick Williams Advisors, a partnership, in which John P. McGrain is a 50% partner. The lenders received interest at the rate of 12% per annum. Enterra also granted the lenders a set-up fee of US$50,000, of which Patrick Williams Advisors received US$30,833. Enterra issued a total of 150,000 warrants to the lenders, including 92,500 warrants to Patrick Williams Advisors. On September 30, 2000, the loans were repaid in full and all of the warrants were exercised at the exercise price of US$4.00 per share.

During 2000 Enterra purchased 2,500,000 shares of common stock of Raptor Capital Corporation plus warrants to purchase 1,250,000 Raptor shares at an exercise price of $0.15 per share, for aggregate consideration of $250,000. Norman J. Mackenzie, Chairman of Raptor, was a director of Enterra at the time.

Westlinks has entered into a Consulting Agreement with Wells Gray Resort & Resources Ltd. in October 2000 that ended in April 2001. Under the contract Thomas J. Jacobsen, the principal of Wells Gray Resort & Resources Ltd., was in charge of Westlinks’ drilling, completion and equipping projects, for consulting fees of $8,333 per month.

Not Applicable

Pages F-1 to F-14.

See "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and the attached consolidated financial statements for a description of the Big Horn acquisition.

Not Applicable, except for Item 9A (4).

Our shares of common stock commenced trading on the Canadian Venture Exchange ("CVE") under the symbol "WLX" during the quarter ended September 30, 1998. Our shares of common stock traded on the National Quotation Bureau's pink sheets ("Pink Sheets") under the symbol "WLKSF" from April 26, 2000 to January 10, 2001 when the shares of common stock commenced trading on the NASDAQ SmallCap Market. The shares currently trade under the symbol "EENC" on the NASDAQ SmalCap Market and under the symbol "ENT" on the TSX Venture Exchange ("TSX"). The following table sets forth the bid prices, in Canadian and U.S. dollars, as reported by the TSX and NASDAQ SmallCap Market /pink sheets, for the periods shown.

Not Applicable

See Item 9.A

Not Applicable

Not Applicable

The authorized capital stock of Enterra consists of an unlimited number of shares of common stock and an unlimited number of shares of preferred stock without nominal or par value. The preferred stock may be issued in one or more series as determined by the board of directors.

Each holder of record of common stock is entitled to one vote for each share held on all matters properly submitted to the stockholders for their vote, except matters which are required to be voted on as a particular class or series of stock. Cumulative voting for directors is not permitted.

Holders of outstanding shares of common stock are entitled to those dividends declared by the board of directors out of legally available funds. In the event of liquidation, dissolution or winding up of the affairs of Enterra, holders of common stock are entitled to receive, pro rata, the net assets of Enterra available after provision has been made for the preferential rights of the holders of preferred stock. Holders of outstanding common stock have no preemptive, conversion or redemption rights. All of the issued and outstanding shares of common stock are, and all unissued shares of common stock, when offered and sold will be, duly authorized, validly issued, fully paid and non-assessable. To the extent that additional shares of common stock may be issued in the future, the relative interests of the then existing stockholders may be diluted.

In December, 1999, Enterra filed a notice to purchase up to 195,782 of its shares of common stock through the facilities of the TSX Venture Exchange and in accordance with the by-laws and rules of the TSX Venture Exchange on or before December 16, 2000. No shares were purchased by Enterra under this bid. Enterra filed a second notice in August 2001 to purchase up to 5% of its common shares for cancellation. Enterra had 5,673,639 issued and outstanding common shares at the time. Enterra would buy back its common shares through the facilities of the NASDAQ during the twelve month period commencing on August 20, 2001 and ending on August 20, 2002. At December 31, 2001 232,500 common shares had been repurchased under this second bid.

Our board of directors is authorized to issue from time to time, without stockholder authorization, in one or more designated series, unissued shares of preferred stock with such dividends, redemption, conversion and exchange provisions as may be provided by the board of directors with regard to such particular series. Any series of preferred stock may possess voting, dividend, liquidation and redemption rights superior to those of the common stock.

The rights of the holders of common stock will be subject to and may be adversely affected by the rights of the holders of any preferred stock that we may issue in the future. Our issuance of a new series of preferred stock could make it more difficult for a third party to acquire, or discourage a third party from acquiring, the outstanding shares of common stock of Enterra and make removal of the board of directors more difficult.

On March 26, 2002 the Company redeemed 6,123,870 of its Series 1 preferred shares for $2.3 million, resulting in a gain of $2,905,290.

Warrants entitle the holder to purchase one share of common stock at an stipulated price for a defined period of time. The warrants were issued under the terms of a warrant trust indenture between Enterra and Montreal Trust Company of Canada, as trustee for the warrant holders. Enterra has authorized and reserved for issuance the shares of common stock issuable on exercise of the warrants.

The warrant exercise price and the number of shares of common stock that may be purchased upon exercise of the warrants are subject to adjustment in the event of:

• a stock dividend on the common stock;

• a subdivision of the common stock;

• a split of the common stock;

• a reorganization of the common stock

• a merger of Enterra with or into another corporation; or

• a sale of common stock at a price which is discounted greater than 10% to the market price at the time the company approves the sale.

Enterra must have on file a current registration statement with the SEC pertaining to the common stock underlying the warrants for a holder to exercise the warrants. In the absence of an exemption, shares of common stock underlying the warrants must also be registered or qualified for sale under the securities laws of the states in which the warrant holders reside. We intend to use our best efforts to keep the registration statement presently underlying the warrants current. If the registration statement is not kept current, or if the common stock underlying the warrants is not registered or qualified for sale in the state in which a warrantholder resides, the warrants may not be exercised.

The warrants do not confer upon the warrant holder any voting or other rights of a stockholder of Enterra.

On January 17, 2001, Enterra completed a public offering in the United States. The offering consisted of 1,000,000 units of one common share and one share purchase warrant for U.S. $4.55 per unit. The share purchase warrants were exercisable at U.S. $3.50 per share. They expired unexercised on May 17, 2002. In addition, 100,000 share purchase warrants related to the underwriters agreement were issued and are exercisable at U.S. $5.40 per share starting January 16, 2002 and may be exercised for a four year period thereafter.

On March 28, 2002 Enterra agreed to issue 400,000 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 200,000 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

Future sales of substantial amounts of our common stock in the public market, in either Canada or the United States, or even the perception that such sales could occur, could adversely affect the market price for our common stock and could impair our future ability to raise capital through an offering of our equity securities.

We have outstanding 9,150,622 shares of common stock, assuming no exercise of outstanding warrants and options. Of these shares, 8,937,575 are freely tradable, without restrictions imposed by applicable securities laws.

We intend to register the shares of our common stock issuable pursuant to our stock option plan. At December 31, 2002 there were outstanding under the plan options to purchase 800,000 shares, all of which would be eligible for immediate resale in Canada, and in the United States by persons who are not affiliates of Enterra.

Our affiliates may reoffer and resell shares of our common stock in Canada, in accordance with the foregoing, provided that such shares are offered and sold by them pursuant to Rule 903 of Regulation S under the Securities Act and that at the time the TSX Venture continues to be the principal market for our common stock.

Enterra is incorporated in Canada (corporation number 207913385). The Articles of Amalgamation and by-laws provide no restrictions as to the nature of the business operations of Enterra.

The governing legislation requires a director to inform the Company, at a meeting of the Board of Directors, of any interest in a material contract or proposed material contract with the Company. No director may vote in respect of any such contract made by them with the Company or in any such contract in which they are interested, and such director shall not be counted for purposes of determining a quorum. However, these provisions do not apply to (i) an arrangement by way of security for money lent to or obligations undertaken by them: (ii) a contract relating primarily to their remuneration as a director, officer, employee or agent of the Company or an affiliate: (iii) a contract for indemnity or insurance of the director as allowed under the governing legislation: or (iv) a contract with an affiliate.

The Board of Directors may exercise all powers of the Company to borrow or raise money, and to give guarantees, and to mortgage or charge its properties and assets, and to issue debentures, debenture stock and other securities, outright or as security for any debt, liability or obligation of the Company or any third party.

There are no age limit requirements regarding retirement of directors and there is no minimum share ownership required for a director’s election to the board.

Enterra is authorized to issue an unlimited number of common and preferred shares. See "Item 10 A Share Capital." The shareholders have no rights to share in Enterra’s profits, are subject to no redemption or sinking fund provisions, have no liability for further capital calls and are not subject to any discrimination due to number of shares owned.

By not more than 50 days or less than seven days in advance of a dividend, the board may establish a record date for the determination of the persons entitled to such dividend. Any dividend unclaimed after a period of six years from the record date shall be forfeited and revert to Enterra.

All directors are elected at each annual meeting of Enterra and cumulative voting is not permitted.

The rights of common shareholders can be changed at any time in a shareholder meeting where the modifications are approved by 66 2/3% of the shareholders represented by proxy or in person at the meeting.

All common shareholders are entitled to vote at annual or special meetings of shareholders, provided that they were shareholders as of the record date. The record date for shareholder meetings may precede the meeting date by no more than 50 days and not less than 21 days, providing that notice by way of advertisement is given to shareholders at least seven days before such record date. Notice of the time and place of meetings of shareholders may not be less than 21 or greater than 50 days prior to the date of the meeting.

There are no:

• limitations on share ownership,

• provisions of the Articles of Amalgamation or by-laws that would have the effect of delaying, deferring or preventing a change of control of Enterra,

• by-law provisions that govern the ownership threshold above which shareholder ownership must be disclosed, and

• conditions imposed by the Articles of Amalgamation or by-laws governing changes in capital, but the governing legislation requires any changes to the terms of share capital be approved at a meeting of the shareholders affected by the change by 66 2/3% of the shareholders represented by proxy or in person at such meeting.

None

There is no law or governmental decree or regulation in Canada that restricts the export or import of capital, or affects the remittance of dividends, interest or other payments to non-resident holders of our subordinate voting shares, other than withholding tax requirements.

There is no limitation imposed by Canadian law or by our articles of incorporation or our other charter documents on the right of a non-resident to hold or vote subordinate voting shares, other than as provided by the "Investment Canada Act", the "North American Free Trade Agreement Implementation Act (Canada)" and the "World Trade Organization Agreement Implementation Act."

The Investment Canada Act requires notification and, in certain cases, advance review and approval by the Government of Canada of the acquisition by a "non-Canadian" of "control" of a "Canadian business", all as defined in the Investment Canada Act. Generally, the threshold for review will be higher in monetary terms for a member of the World Trade Organization or North American Free Trade Agreement.

The information set forth below is a summary of the material U.S. federal income tax consequences of the ownership and disposition of common stock by a U.S. Holder, as defined below. These discussions are not a complete analysis or listing of all of the possible tax consequences of such transactions and do not address all tax considerations that may be relevant to particular holders in light of their personal circumstances or to persons that are subject to special tax rules. In particular, the information set forth deals only with U.S. Holders that will hold common stock as capital assets within the meaning of the Internal Revenue Code of 1986, as amended, and who do not at any time own individually, nor are treated as owning 10% or more of the total combined voting power of all classes of our stock entitled to vote. In addition, this description of U.S. tax consequences does not address the tax treatment of special classes of U.S. Holders, such as banks, tax-exempt entities, insurance companies, persons holding subordinate voting shares as part of a hedging or conversion transaction or as part of a "straddle," U.S. expatriates, persons subject to the alternative minimum tax, dealers or traders in securities or currencies and holders whose "functional currency" is not the U.S. dollar. This summary does not address estate and gift tax consequences or tax consequences under any foreign, state or local laws other than as provided in the section entitled "Canadian Federal Income Tax Considerations" provided below.

As used in this section, the term "U.S. Holder" means:

• an individual citizen or resident of the United States;

• a corporation created or organized under the laws of the United States or any state thereof including the District of Columbia;

• an estate the income of which is subject to United States federal income taxation regardless of its source;

• a trust if a court within the United States is able to exercise primary jurisdiction over its administration and one or more U.S. persons have authority to control all substantial decisions of the trust; or

• a partnership to the extent the interests therein are owned by any of the persons described in clauses (a), (b), (c) or (d) above.

Holders of common stock who are not U.S. Holders, sometimes referred to as "Non-U.S. Holders", should also consult their own tax advisors, particularly as to the applicability of any tax treaty.

The following discussion is based upon:

• the Internal Revenue Code;

• U.S. judicial decisions;

• administrative pronouncements;

• existing and proposed Treasury regulations; and

• the Canada/ U.S. Income Tax Treaty.

Any of the above is subject to change, possibly with retroactive effect. We have not requested, and will not request, a ruling from the U.S. Internal Revenue Service with respect to any of the U.S. federal income tax consequences described below, and as a result, there can be no assurance that the U.S. Internal Revenue Service will not disagree with or challenge any of the conclusions we have reached and describe here.

Subject to the discussion of passive foreign investment companies below, the gross amount of any distribution paid by us to a U.S. Holder will generally be subject to U.S. federal income tax as foreign source dividend income to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. The amount of any distribution of property other than cash will be the fair market value of such property on the date of the distribution. Dividends received by a U.S. Holder will not be eligible for the dividends received deduction allowed to corporations. To the extent that an amount received by a U.S. Holder exceeds such holder's allocable share of our current and accumulated earnings and profits, such excess will be applied first to reduce such U.S. Holder's tax basis in his subordinate voting shares, thereby increasing the amount of gain or decreasing the amount of loss recognized on a subsequent disposition of the subordinate voting shares. Then, to the extent such distribution exceeds such U.S. Holder's tax basis, it will be treated as capital gain. We do not currently maintain calculations of our earnings and profits for U.S. federal income tax purposes.

The gross amount of distributions paid in Canadian dollars, or any successor or other foreign currency, will be included in the income of such U.S. Holder in a dollar amount calculated by reference to the spot exchange rate in effect on the day the distributions are paid regardless of whether the payment is in fact converted into U.S. dollars. If the Canadian dollars, or any successor or other foreign currency, are converted into U.S. dollars on the date of the payment, the U.S. Holder should not be required to recognize any foreign currency gain or loss with respect to the receipt of Canadian dollars as distributions. If, instead, the Canadian dollars are converted at a later date, any currency gains or losses resulting from the conversion of the Canadian dollars will be treated as U.S. source ordinary income or loss. Any amounts recognized as dividends will generally constitute foreign source "passive income" or, in the case of certain U.S. Holders, "financial services income" for U.S. foreign tax credit purposes. A U.S. Holder will have a basis in any Canadian dollars distributed equal to their dollar value on the payment date.

A Non-U.S. Holder of common stock generally will not be subject to U.S. federal income or withholding tax on dividends received on common stock unless such income is effectively connected with the conduct by such Non-U.S. Holder of a trade or business in the United States.

A U.S. Holder's initial tax basis in the common stock will generally be cost to the holder. A U.S. Holder's adjusted tax basis in the common stock will generally be the same as cost, but may differ for various reasons including the receipt by such holder of a distribution that was not made up wholly of earnings and profits as described above under the heading "Dividends." Subject to the discussion of passive foreign investment companies below, gain or loss realized by a U.S. Holder on the sale or other disposition of common stock will be subject to U.S. federal income taxation as capital gain or loss in an amount equal to the difference between the U.S. Holder's adjusted tax basis in the common stock and the amount realized on the disposition. In the case of a non-corporate U.S. Holder, the federal tax rate applicable to capital gains will depend upon:

• the holder's holding period for the common stock, with a preferential rate available for common stock held for more than one year; and

• the holder's marginal tax rate for ordinary income.

Any gain realized will generally be treated as U.S. source gain and loss realized by a U.S. Holder generally also will be treated as from sources within the United States.

The ability of a U.S. Holder to utilize foreign taxes as a credit to offset U.S. taxes is subject to complex limitations and conditions. The consequences of the separate limitation calculation will depend upon the nature and sources of each U.S. Holder's income and the deductions allocable thereto. Alternatively, a U.S. Holder may elect to claim all foreign taxes paid as an itemized deduction in lieu of claiming a foreign tax credit. A deduction does not reduce U.S. tax on a dollar-for-dollar basis like a tax credit, but the availability of the deduction is not subject to the same conditions and limitations applicable to foreign tax credits.

If a U.S. Holder receives any foreign currency on the sale of common stock, such U.S. Holder may recognize ordinary income or loss as a result of currency fluctuations between the date of the sale of common stock and the date the sale proceeds are converted into U.S. dollars.

A Non-U.S. Holder of common stock generally will not be subject to U.S. federal income or withholding tax on any gain realized on the sale or exchange of such common stock unless:

• such gain is effectively connected with the conduct by such Non-U.S. Holder of a trade or business in the United States; or

• in the case of any gain realized by an individual Non-U.S. Holder, such Non-U.S. Holder is present in the United States for 183 days or more in the taxable year of such sale and certain other conditions are met.

We could be classified as a personal holding company for U.S. federal income tax purposes if both of the following tests are satisfied:

• if at any time during the last half of our taxable year, five or fewer individuals own or are deemed to own more than 50% of the total value of our shares; and

• we receive 60% or more of our U.S. related gross income from specified passive sources, such as royalty payments.

A personal holding company is taxed on a portion of its undistributed U.S. source income, including specific types of foreign source income which are connected with the conduct of a U.S. trade or business, to the extent this income is not distributed to shareholders. We do not believe we are a personal holding company presently and we do not expect to become one. However, we cannot assure you that we will not qualify as a personal holding company in the future.

We could be classified as a foreign personal holding company if in any taxable year both of the following tests are satisfied:

• five or fewer individuals who are United States citizens or residents own or are deemed to own more than 50% of the total voting power of all classes of our shares entitled to vote or the total value of our shares; and

• at least 60%, 50% in some cases, of our gross income, as adjusted, consists of "foreign personal holding company income", which generally includes passive income such as dividends, interests, gains from the sale or exchange of shares or securities, rent and royalties.

If we are classified as a foreign personal holding company and if you hold shares in us, you may have to include in your gross income as a dividend your pro rata portion of our undistributed foreign personal holding company income. If you dispose of your shares prior to such date, you will not be subject to tax under these rules. We do not believe we are a foreign personal holding company presently and we do not expect to become one. However, we cannot assure you that we will not qualify as a foreign personal holding company in the future.

We believe that our common stock should not currently be treated as stock of a passive foreign investment company for United States federal income tax purposes, but this conclusion is a factual determination made annually and thus may be subject to change based on future operations and composition and valuation of our assets. In general, we will be a passive foreign investment company with respect to a U.S. Holder if, for any taxable year in which the U.S. Holder holds our subordinate voting shares, either:

• at least 75% of our gross income for the taxable year is passive income; or

• at least 50% of the average value of our assets is attributable to assets that produce or are held for the production of passive income.

For this purpose, passive income includes income such as:

• dividends;

• interest;

• rents or royalties, other than certain rents or royalties derived from the active conduct of trade or business;

• annuities; or

• gains from assets that produce passive income.

If a foreign corporation owns at least 25% by value of the stock of another corporation, the foreign corporation is treated for purposes of the passive foreign investment company tests as owning its proportionate share of the assets of the other corporation and as receiving directly its proportionate share of the other corporation's income.

If we are treated as a passive foreign investment company, a U.S. Holder that did not make a qualified electing fund election or, if available, a mark-to-market election, as described below, would be subject to special rules with respect to:

• any gain realized on the sale or other disposition of common stock; and

• any "excess distribution" by us to the U.S. Holder.

Generally, "excess distributions" are any distributions to the U.S. Holder in respect of the subordinate voting shares during a single taxable year that are greater than 125% of the average annual distributions received by the U.S. Holder in respect of the common stock during the three preceding taxable years or, if shorter, the U.S. Holder's holding period for the common stock.

Under the passive foreign investment company rules,

• the gain or excess distribution would be allocated ratably over the U.S. Holder's holding period for the common stock;

• the amount allocated to the taxable year in which the gain or excess distribution was realized would be taxable as ordinary income;

• the amount allocated to each prior year, with certain exceptions, would be subject to tax at the highest tax rate in effect for that year; and

• the interest charge generally applicable to underpayments of tax would be imposed in respect of the tax attributable to each such year.

A U.S. Holder owning actually or constructively "marketable stock" of a passive foreign investment company may be able to avoid the imposition of the passive foreign investment company tax rules described above by making a mark-to-market election. Generally, pursuant to this election, such holder would include in ordinary income, for each taxable year during which such stock is held, an amount equal to the increase in value of the stock, which increase will

be determined by reference to the value of such stock at the end of the current taxable year compared with their value as of the end of the prior taxable year. Holders desiring to make the mark-to-market election should consult their tax advisors with respect to the application and effect of making such election.

In the case of a U.S. Holder who does not make a mark-to-market election, the special passive foreign investment company tax rules described above will not apply to such U.S. Holder if the U.S. Holder makes an election to have us treated as a qualified electing fund and we provide certain required information to holders. For a U.S. Holder to make a qualified electing fund election, we would have to satisfy certain reporting requirements. We have not determined whether we will undertake the necessary measures to be able to satisfy such requirements in the event that we were treated as a passive foreign investment company.

A U.S. Holder that makes a qualified electing fund election will be currently taxable on its pro rata share of our ordinary earnings and net capital gain, at ordinary income and capital gains rates, respectively, for each of our taxable years, regardless of whether or not distributions were received. The U.S. Holder's basis in the common stock will be increased to reflect taxed but undistributed income. Distributions of income that had previously been taxed will result in a corresponding reduction of basis in the common stock and will not be taxed again as a distribution to the U.S. Holder. U.S. Holders desiring to make a qualified electing fund election should consult their tax advisors with respect to the advisability of making such election.

A U.S. Holder will generally be subject to information reporting with respect to dividends paid on, or proceeds of the sale or other disposition of, our subordinate voting shares, unless the U.S. Holder is a corporation or comes within certain other categories of exempt recipients. A U.S. Holder that is not an exempt recipient will generally be subject to backup withholding at a rate of 31% with respect to the proceeds from the sale or the disposition of, or with respect to dividends on, common stock unless the U.S. Holder provides a taxpayer identification number and otherwise complies with applicable requirements of the backup withholding rules. Any amount withheld under these rules will be creditable against the U.S. Holder's U.S. federal income tax liability or refundable to the extent that it exceeds such liability. A U.S Holder who does not provide a correct taxpayer identification number may be subject to penalties imposed by the United States Internal Revenue Service.

Non-U.S. Holders will generally be subject to information reporting and possible backup withholding with respect to the proceeds of the sale or other disposition of common stock effected within the United States, unless the holder certifies to its foreign status or otherwise establishes an exemption if the broker does not have actual knowledge that the holder is a U.S. holder. A payor within the United States will be required to withhold 31% of any payments of dividends on or proceeds from the sale of common stock within the United States to a non-exempt U.S. or Non-U.S. Holder if such holder fails to provide appropriate certification. In the case of such payments by a payor within the United States to a foreign partnership other than a foreign partnership that qualifies as a "withholding foreign partnership" within the meaning of such Treasury regulations, the partners of such partnership will be required to provide the certification discussed above in order to establish an exemption from backup withholding tax and information reporting requirements.

The following is a summary of the material Canadian federal income tax considerations generally applicable to a U.S. person who holds common stock and who, for the purposes of the Income Tax Act (Canada), or the "ITA", and the Canada-United States Income Tax Convention (1980), or the "Convention," as applicable and at all relevant times:

• is resident in the United States and not resident in Canada;

• holds the common stock as capital property;

• does not have a "permanent establishment" or "fixed base" in Canada, as defined in the Convention; and

• deals at arm's length with us. Special rules, which are not discussed below, may apply to "financial institutions", as defined in the ITA, and to non-resident insurers carrying on an insurance business in Canada and elsewhere.

This discussion is based on the current provisions of the ITA and the Convention and on the regulations promulgated under the ITA, all specific proposals to amend the ITA or the regulations promulgated under the ITA announced by or on behalf of the Canadian Minister of Finance prior to the date of this Annual Report and the current published administrative practices of the Canada Customs and Revenue Agency, or the Agency. It does not otherwise take into account or anticipate any changes in law or administrative practice nor any income tax laws or considerations of any province or territory of Canada or any jurisdiction other than Canada, which may differ from the Canadian federal income tax consequences described in this document.

Under the ITA and the Convention, dividends paid or credited, or deemed to be paid or credited, on the common stock to a U.S. person who owns less than 10% of the voting shares will be subject to Canadian withholding tax at the rate of 15% of the gross amount of those dividends or deemed dividends. If a U.S. person is a corporation and owns 10% or more of the voting shares, the rate is reduced from 15% to 5%. As described above and subject to specified limitations, a U.S. person may be entitled to credit against U.S. federal income tax liability for the amount of tax withheld by Canada.

Under the Convention, dividends paid to specified religious, scientific, charitable and similar tax exempt organizations and specified organizations that are resident and exempt from tax in the United States and that have complied with specified administrative procedures are exempt from this Canadian withholding tax.

A capital gain realized by a U.S. person on a disposition or deemed disposition of the common stock will not be subject to tax under the ITA unless the common stock constitute taxable Canadian property within the meaning of the ITA at the time of the disposition or deemed disposition. In general, the common stock will not be "taxable Canadian property" to a U.S. person if they are listed on a prescribed stock exchange, which includes The Toronto Stock Exchange, unless, at any time within the five-year period immediately preceding the dispositions, the U.S. person, persons with whom the U.S. person did not deal at arm's length, or the U.S. person together with those persons, owned or had an interest in or a right to acquire more than 25% of any class or series of our shares.

If the common stock are taxable Canadian property to a U.S. person, any capital gain realized on a disposition or deemed disposition of those common stock will generally be exempt from tax under the ITA by virtue of the Convention if the value of the common stock at the time of the disposition or deemed disposition is not derived principally from real property, as defined by the Convention, situated in Canada. The determination as to whether Canadian tax would be applicable on a disposition or deemed disposition of the common stock must be made at the time of the disposition or deemed disposition.

Not Applicable

Not Applicable

Any statement in this registration statement about any of our contracts or other documents is not necessarily complete. If the contract or document is filed as an exhibit, the contract or document is deemed to modify the description contained in this registration statement. You must review the exhibits themselves for a complete description of the contract or document.

Not Applicable

We are exposed to market risk from changes in currency exchange rates and interest rates. As a Canadian oil and gas company, we may be adversely affected by changes in the exchange rate between U.S. and Canadian dollars. 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 world-wide. However, we pay our 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.

Interest rate risk exists principally with respect to our indebtedness that bears interest at floating rates. At December 31, 2001, we had $18,408,904 of indebtedness bearing interest at floating rates.

We will regularly assess our exposure and monitor opportunities to manage these risks. Effective November 1, 2000 Westlinks entered into a three year fixed price crude oil contract. Subsequent to year-end we terminated the contract for consideration of approximately $1.68 million. The Company entered into a zero cost collar arrangement during 2001 which provides a floor price of US$20 per barrel and a ceiling price of US$24 per barrel for 500 barrels of oil per day. The contract is effective from November 1, 2001 through April 30, 2002.

Not Applicable

 

None

Not Applicable

The Consolidated Financial Statements of Enterra are attached as follows:

Auditors’ report to the shareholders                                                                       F-1

Enterra Energy Corp.’s Financial Statements as of and

for the years ended December 31, 2001, 2000 and 1999                                F-2 through F-14

Not Applicable.

Financial Statements

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this registration statement on its behalf.

                                                                                                                                Enterra Energy Corp.

                                                                                                                                Title: Chief Financial Officer

                                                                                                                                August 15, 2002

Year ended December 31, 2001

We conducted our audits in accordance with Canadian generally accepted auditing standards and auditing standards generally accepted in the United States of America. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2001 and 2000 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

We also audited the adjustments described in note 2(e) to the consolidated financial statements that were applied to restate the consolidated financial statements for the year ended December 31, 1999. In our opinion, such adjustments are appropriate and have been properly applied.

Canadian generally accepted accounting principles vary in certain significant respects from accounting principles generally accepted in the United States. Application of accounting principles generally accepted in the United States would have affected results of operations for each of the years in the three-year period ended December 31, 2001 and shareholders’ equity as at December 31, 2001 and 2000 to the extent summarized in note 12 to the consolidated financial statements.

Chartered Accountants

Calgary, Canada

____________________________________________________________________________________________

Enterra Energy Corp. (formerly Westlinks Resources Ltd.)("Enterra") was formed on June 30, 1998 by the amalgamation of Temba Resources Ltd. ("Temba") and PTR Resources ltd. ("PTR") in a share-for-share exchange. The combination was recorded using the purchase method of accounting with Temba being identified as the acquirer.

Effective August 1, 2001 Enterra acquired 100% of the common shares of Big Horn Resources Ltd. ("Big Horn"), a junior oil and gas company listed on the Toronto Stock Exchange, by the way of a plan of arrangement. Consideration consisted of cash of $2,205,447 (not including acquisition costs) and the issuance of 3,496,436 common shares and 7,418,332 preferred shares. The terms of the Series 1 preferred shares are described in note 9. In addition, approximately 460,915 Enterra options were issued in exchange for Big Horn options.

Effective December 10, 2001 Westlinks Resources Ltd. changed its name to Enterra Energy Corp. A new stock option plan was also adopted at that time.

These consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles. Substantially all of the exploration and production activities of the Company are conducted jointly with others and these financial statements reflect only the Company’s proportionate interest in such activities. The consolidated financial statements include the accounts of Big Horn effective from August 1, 2001.

1. Fair value of financial instruments:

The Company’s financial instruments consist of cash, accounts receivable, bank indebtedness, accounts payable, accrued liabilities and preferred shares. The fair values of all of the Company’s financial instruments approximate their carrying values.

2. Foreign currency exchange risk:

The Company is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices.

3. Credit risk:

A substantial portion of the Company’s accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company’s natural gas, crude oil and natural gas liquids are subject to an internal credit review to minimize the risk of non-payment.

500. Estimates and assumptions

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates.

The Canadian Institute of Chartered Accountants has approved a new standard for the computation, presentation and disclosure of per share amounts. The Corporation has retroactively adopted the new standard. The new standard has been applied retroactively with no effect on prior period per share calculations. Under the new standard, the treasury stock method is used instead of the imputed earnings method to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only "in the money" dilutive instruments impact the diluted calculations.

The weighted average number of common shares outstanding during the years ended December 31, 2001 and 2000 were 6,992,393 and 4,421,844, respectively. In computing diluted earnings per share 5,114 shares (2000 – 6,849 shares and 1999 – nil shares) were added to the weighted average number of common shares outstanding during the year as a result of the dilutive effect of stock options. No adjustments were required to reported earnings or funds from operations in computing diluted per share amounts.

7. Stock-based compensation

The Company has a stock option plan which is described in note 8. No compensation expense is recognized for this plan when stock options are issued to employees. Any consideration paid by employees on exercise of stock is credited to share capital. If stock or stock options are repurchased from employees, the excess of consideration paid over the carrying amount of the stock or stock option cancelled is charged to contributed surplus.

Revenue from the sale of oil and gas is recognized based on volumes delivered to customers at contractual delivery points and rates. The costs associated with the delivery, including operating and maintenance costs, transportation and production based royalty expenses are recognized in the same period in which the related revenue is earned and recorded.

.3. Business combination

4.  Property and equipment

			December 31, 2001
		Accumulated
		depletion and
	Cost	depreciation	Net
Petroleum and natural gas properties	$ 82,574,219	$ 9,939,258	$ 72,634,961
Office furniture and equipment	843,464	338,928	504,536
	$ 83,417,683	$ 10,278,186	$ 73,139,497
			December 31, 2000
		Accumulated
		depletion and
	Cost	depreciation	Net
Petroleum and natural gas properties	$ 21,858,219	$ 3,638,387	$ 18,219,832
Office furniture and equipment	156,295	40,653	115,642
	$ 22,014,514	$ 3,679,040	$ 18,335,474

In conducting its ceiling test evaluation the Company followed generally accepted accounting principles which provide for a two-year exemption from write-down where the purchase price of reserves had been determined on a basis which provided a higher amount than the ceiling test value, and where the excess was not considered to represent a permanent impairment in the ultimate recoverable amount. If the two-year exemption had not been used, the Company would have taken a write-down of $8.1 million based on prices at December 31, 2001 of $22.05 per bbl of oil and $3.42 per mcf of gas. Enterra qualified for the exemption in connection of its acquisition of Big Horn in August 2001.

At December 31, 2001 costs of undeveloped land of $8,053,000 (2000 - $60,253) were excluded from the calculation of depletion expense.

5. Investments

Investments in Red Raven Resources Inc. and Raptor Capital Corporation were disposed of during 2001 as part of the severence amounts paid to former directors and officers of the Company.

6. Bank indebtedness