SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________

FORM 20-F

                                                               (Mark One) 

| [ ] | Registration statement pursuant to    Section 12(b) or 12(g) of the Securities Exchange Act of 1934.                                                      |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------|
| or  |                                                                                                                                                           |
| [X] | Annual report pursuant to Section    13 or 15(d) of the Securities Exchange Act of 1934. For the fiscal year ended December 31,    2001.                  |
| Or  |                                                                                                                                                           |
| [ ] | Transition report pursuant to    Section 13 or 15(d) of the Securities Exchange Act of 1934. For the transition period from    ---------- to ---------- . |
|     | Commission file number 333-39826                                                                                                                          |

ENTERRA ENERGY CORP.

(Exact Name of Registrant as Specified in Its Charter)

Alberta, Canada

(Jurisdiction of Incorporation or Organization)

Suite 2600, 500 – 4th Avenue S.W.

Calgary, Alberta, Canada

T2P 2V6

(Address of Principal Executive Offices)

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

|  | **Title of Each Class** | **Name of Each Exchange    On Which RegisteredCommon Shares
Canadian Venture Exchange
NASDAQ
Securities registered or to be registered pursuant to Section 12(g) ofthe Act: None

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

Indicate the number of outstanding shares of each of the issuer’sclasses of capital or common stock as of the close of the period covered by the annualreport.

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

Indicate by check mark whether the registrant: (1) has filed allreports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934during the preceding 12 months (or such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirements for the past 90days.

Yes [X] No [ ] 

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

Item 17 [X ] Item 18 [  ] 
**PART I

ITEM 1. Identity of Directors, Senior Management and Advisors

Not applicable
**ITEM 2. Offer Statistics and Expected Timetable 

Not applicable**ITEM 3. Key Information - Selected Financial Data

SUMMARY CONSOLIDATED FINANCIAL DATA**
The following table presents a summary of ourconsolidated statement of operations derived from our financial statements for 1999, 2000and 2001. The monetary amounts in the table are based on Canadian GAAP. The 1999 and 2000results have been restated to reflect the change in its method of accounting for petroleumand natural gas properties from the "successful efforts" method to the"full costs" method. All data presented below should be read in conjunction withthe "Management’s Discussion and Analysis of Financial Condition and Results ofOperations" and our financial statements and accompanying notes included elsewhere inthis Form 20-F .**Consolidated statements of operations data: 

 
***(In thousand’s, except per share    data)*****2001**2000**1999**C$**C$**C$Net revenue
$20,264
$ 16,700
$ 2,515Royalties, net of ARTC
3,182
3,310
442Production expenses
5,830
4,030
782General and administrative expenses
565
1,391
862Interest
589 
833
132Depreciation and depletion
6,870
2,960
705
17,036
12,524
2,923Earnings (loss) from operations
$ 3,228 
$ 4,176
($ 408)Net earnings (loss) for the year
$ 1,617
$ 2,453
($ 249)Basic earnings (loss) per share
$ 0.23
$ 0.55
($ 0.10)
The following table indicates a summary of ourconsolidated balance sheets as of December 31, 2000 and 2001. The monetary amounts in thetable are based on Canadian GAAP. The 2000 results have been restated to reflect thechange in its method of accounting for petroleum and natural gas properties from the"successful efforts" method to the "full costs" method.**Consolidated balance sheet data: 

 
***(In thousand’s)*****2001**2000**C$**C$Cash and short term investments 
$    43
$     1Accounts receivable and prepaids
6,880
2,505Capital assets
73,139
18,868Total assets
80,063
22,634Total stockholders’ equity
33,524
7,677**Exchange Rate Information**
We publish our consolidated financial statementsin Canadian dollars. In this annual report, except where otherwise indicated, all dollaramounts are stated in Canadian dollars. References to "$" or "C$" areto Canadian dollars and references to "US$" are to U.S. dollars. The followingtable sets forth for each period indicated the period end exchange rates for conversion ofU.S. dollars to Canadian dollars, the average exchange rates on the last day of each monthduring such period and the high and low exchange rates during such period. These rates arebased on the noon buying rate in New York City, expressed in U.S. dollars, for cabletransfers in Canadian dollars as certified for customs purposes by the Federal ReserveBank of New York. The exchange rates are presented as Canadian dollars per $1.00. OnDecember 31, 2001, the noon buying rate was US$1.00 equals C$1.5911 and the inverse noonbuying rate was C$1.00 equals US$0.6285.
 
**2001**2000**1999**1998**1997End of period
0.6285
0.6669
0.6918
0.6538
0.6996Average for the period
0.6456
0.6732
0.6691
0.6693
0.7207High during the period
0.6714
0.6969
0.6935
0.7124
0.7497Low during the period
0.6227
0.6410
0.6464
0.6311
0.6938**B. Capitalization and Indebtedness**
Not Applicable
**C. Reasons for the Offer and Use of Proceeds**
Not Applicable
**D. Risk Factors

Risks related to our industry and business

We have a working capital deficiency at December 31, 2001; our Credit facilities can becalled at any time.**
At December 31, 2001, we had a working capital deficiency ofC$2,229,431, which means our current liabilities exceeded our current assets by thatamount. Using the principles of U.S. GAAP, all of our long-term debt would be classifiedas a current liability resulting in a working capital deficiency of C$20,728,629. Ourcredit facilities are all on a demand basis and could be called for repayment at any time.
**Our assets are highly leveraged.**
We have incurred a high amount of debt relative to our assets. Adecrease in the amount of our production or the price we receive for it could make itdifficult for us to service our loan or may cause the bank that issued our loan todetermine that our assets are insufficient security for our bank debt. 
**There is uncertainty about estimates used in this annual report andthey may prove to be inaccurate, resulting in a reduction of our working capital.**
This annual report contains estimates of future net cash flows from ouroil and gas reserves, prepared by independent engineers, which are based upon theestimates of oil and gas reserves in the ground and the percentage of those reserves whichcan be recovered and produced with current technology. These estimates include assumptionsas to the prices received for the sale of oil and gas. Any one or all of those estimatesmay be inaccurate, which could materially affect our estimate of future net cash flows. Inaddition, 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.
**Our operations are subject to numerous risks of crude oil and naturalgas drilling and production activities.**
Crude oil and natural gas drilling and production activities aresubject to numerous risks, many of which are beyond our control. These risks include thefollowing:
- 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 incertain of our core areas. We cannot assure you that the new wells we drill will beproductive or that we will recover all or any portion of our investment. Drilling forcrude oil and natural gas may be unprofitable. Dry wells and wells that are productive butdo not produce sufficient net revenues after drilling, operating and other costs areunprofitable. In addition, our properties may be susceptible to hydrocarbon draining fromproduction by other operations on adjacent properties.

Our industry also experiences numerous operating risks. These operatingrisks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressuredformations and environmental hazards. Environmental hazards include oil spills, gas leaks,ruptures or discharges of toxic gases. If any of these industry operating risks occur, wecould have substantial losses. Substantial losses also may result from injury or loss oflife, severe damage to or destruction of property, clean-up responsibilities, regulatoryinvestigation and penalties and suspension of operations. In accordance with industrypractice, 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 thatjustify its purchase. 
**We operate in a highly competitive industry which may adversely affectour operations.**
We operate in a highly competitive environment. Competition isparticularly intense with respect to the acquisition of desirable undeveloped crude oiland natural gas properties. The principal competitive factors in the acquisition of suchundeveloped crude oil and natural gas properties include the staff and data necessary toidentify, investigate and purchase such properties, and the financial resources necessaryto acquire and develop such properties. We compete with major and independent crude oiland natural gas companies for properties and the equipment and labor required to developand operate such properties. Many of these competitors have financial and other resourcessubstantially greater than ours.

The principal resources necessary for the exploration and production ofcrude oil and natural gas are leasehold prospects under which crude oil and natural gasreserves may be discovered, drilling rigs and related equipment to explore for suchreserves and knowledgeable personnel to conduct all phases of crude oil and natural gasoperations. We must compete for such resources with both major crude oil and natural gascompanies and independent operators. Although we believe our current operating andfinancial resources are adequate to preclude any significant disruption of our operationsin the immediate future we cannot assure you that such materials and resources will beavailable to us.
**Our ability to replace production with new reserves is highly dependenton acquisitions or successful development and exploration activities.**
The rate of production from crude oil and natural gas propertiesdeclines as reserves are depleted. Our proved reserves will decline as reserves areproduced unless we acquire additional properties containing proved reserves, conductsuccessful exploration and development activities or, through engineering studies,identify additional behind-pipe zones or secondary recovery reserves. Our future crude oiland natural gas production is therefore highly dependent upon our level of success inacquiring or finding additional reserves. We cannot assure you that our exploration anddevelopment activities will result in increases in reserves. Our operations may becurtailed, delayed or cancelled if we lack necessary capital and by other factors, such astitle problems, weather, compliance with governmental regulations, mechanical problems orshortages or delays in the delivery of equipment. Our ability to continue to acquireproducing properties or companies that own such properties assumes that major integratedoil companies and independent oil companies will continue to divest many of their crudeoil and natural gas properties. We cannot assure you that such divestitures will continueor that we will be able to acquire such properties at acceptable prices or developadditional reserves in the future. 
**Crude oil and natural gas price declines and volatility could adverselyaffect our revenue, cash flows and profitability.**
Our revenue, profitability and future rate of growth dependsubstantially upon prevailing prices for crude oil and natural gas. Crude oil and naturalgas prices fluctuate and until recently have declined significantly. Prices also affectthe amount of cash flow available for capital expenditures and our ability to borrow moneyor raise additional capital. In 1998 and 1999, we reduced our capital expenditures budgetbecause of lower crude oil and natural gas prices. In addition, we may have ceiling testwrite-downs when prices decline. At December 31, 2001 the Company would have realized aU.S. GAAP ceiling test write-down of C$17.5 million (after tax). Lower prices may alsoreduce the amount of crude oil and natural gas that we can produce economically.

We may enter into hedge agreements and other financial arrangements atvarious times to attempt to minimize the effect of crude oil and natural gas pricefluctuations. We cannot assure you that such transactions will reduce risk or minimize theeffect of any decline in crude oil or natural gas prices. Any substantial or extendeddecline in crude oil or natural gas prices would have a material adverse effect on ourbusiness and financial results. Hedging activities may limit the risk of declines inprices, but such arrangements may also limit additional revenues from price increases. 
**Lower crude oil and natural gas prices increase the risk of ceilinglimitation write-downs.**
The Company changed its method of accounting for petroleum and naturalgas 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 andgas reserves are capitalized into a single cost centre representing the Company’sactivity which is undertaken exclusively in Canada. Costs capitalized include landacquisition costs, geological and geophysical expenditures, lease rentals on undevelopedproperties and costs of drilling productive and non-productive wells. Proceeds from thedisposal of properties are applied as a reduction of cost without recognition of a gain orloss 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 basedon the estimated gross proven oil and natural gas reserves before royalties as determinedby independent engineers. Units of natural gas are converted into barrels of equivalentson a relative energy content basis. Capitalized costs, net of accumulated depletion anddepreciation, are limited to estimated future net revenues from proven reserves, based onyear-end prices, undiscounted, less estimated future abandonment and site restorationcosts, general and administrative expenses, financing costs and income taxes. Estimatedfuture abandonment and site restoration costs are provided for over the life of provenreserves on a unit-of-production basis. The annual charge is included in depletion anddepreciation expense and actual abandonment and site restoration costs are charged to theprovision as incurred. The amounts recorded for depletion and depreciation and theprovision for future abandonment and site restoration costs are based on estimates ofproven reserves and future costs. The recoverable value of capital assets is based on anumber of factors including the estimated proven reserves and future costs. By theirnature, these estimates are subject to measurement uncertainty and the impact on financialstatements of future periods could be material.

The Company performs a cost recovery ceiling test which limits netcapitalized costs to the undiscounted estimated future net revenue from proven oil and gasreserves plus the cost of unproven properties less impairment, using year-end prices oraverage prices in that year, if appropriate. In addition, the value is further limited byincluding financing costs, administration expenses, future abandonment and siterestoration costs and income taxes. Under U.S. GAAP, companies using the "fullcost" method of accounting for oil and gas producing activities perform a ceilingtest using discounted estimated future net revenue from proven oil and gas reserves usinga discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for thisreconciliation were those in effect at the applicable year-end. Financing andadministration 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 carryingvalue of crude oil and natural gas properties increases when crude oil and natural gasprices are low or volatile. The Company may experience additional ceiling test write-downsin the future.

Prior to 2001, the Company followed the "successful efforts"method of accounting for our oil and gas exploration and development costs. The initialacquisition costs of oil and gas properties and the costs of drilling and equippingdevelopment wells and successful exploratory wells were capitalized. The costs ofexploration wells classified as unsuccessful were charged to expense. All otherexploration expenditures, including geological and geophysical costs and annual rentals onexploratory acreage, were charged to expense as incurred. Under successful effortsaccounting 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 netcash flows from proved reserves, discounted at 10%, plus the lower of cost or fair marketvalue of unproved properties. If net capitalized costs of crude oil and natural gasproperties 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 impactcash flow from operating activities, but did reduce stockholders' equity. In 1997 and2000, the Company recorded a write-down of $ 3.8 million and $0.5 million respectively, asa result of a downward adjustment to our proved reserves in Canada. 
**We may undertake acquisitions that could limit our ability to manageand maintain our business, result in adverse accounting treatment and are difficult tointegrate into our business.**
A component of future growth will depend on the ability to identify,negotiate, and acquire additional companies and assets that complement or expand existingoperations. However we may be unable to complete any acquisitions, or any acquisitions wemay complete may not enhance our business. Any acquisitions could subject us to a numberof risks, including: 
- diversion of management's attention;   amortization of substantial goodwill, adversely affecting our      reported results of operations;
inability to retain the management, key personnel and other employees      of the acquired business;
inability to establish uniform standards, controls, procedures and      policies;
inability to retain the acquired company's customers;
exposure to legal claims for activities of the acquired business      prior to acquisition; and inability to integrate the acquired company and its employees      into our organization effectively.
**We may be subject to environmental liability claims that could resultin significant costs to us.**
We may be subject to claims for damages related to any impact that ouroperations have on the environment. An environmental claim could materially adverselyaffect our business because of the costs of defending against these types of lawsuits, theimpact on senior management's time and the potential damage to our reputation. Our oil andgas operations are subject to government regulations and control. Failure to comply withapplicable government rules could restrict our ability to engage in further oil and gasexploration and development opportunities.
**Our revenue is subject to volatile oil and gas prices that could reduceour revenue and profitability.**
The price we receive for oil and gas production is subject tosignificant volatility. Our revenue, cash flow and profitability are substantiallydependent on prevailing prices for oil and gas. Historically oil and gas prices andmarkets have been volatile and they are likely to continue to be volatile in the future.Some factors that contribute to volatility include:
- political conditions in the Middle East, the former Soviet Union and      other regions;  domestic and foreign supplies of oil and gas;
the level of consumer demand;
weather conditions;
domestic and foreign government regulations;  
the availability and prices of alternative fuels; and
overall economic conditions.

To counter this volatility from time to time we may enter intoagreements to receive fixed prices on its oil and gas production to offset the risk ofrevenue losses if commodity prices decline; however, if commodity prices increase beyondthe levels set in such agreements, We will not benefit from such increases.
**As a Canadian oil and gas company, we may be adversely affected bychanges 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 worldwide. However, we payoperating 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 valueof the U.S. dollar declines, we receive lower revenue on the same amount of productionsold at the same prices.
**We depend on key personnel for critical management decisions andindustry contacts but have no employment contracts or key person insurance.**
We are dependent upon the continued services of our management team. Wedo not have employment contracts with any of these executives and do not carry key personinsurance on their lives. The loss of the services of our executive officers, throughincapacity or otherwise, could have a material adverse effect on our business and wouldrequire us to seek and retain other qualified personnel.
**We have not paid dividends, do not intend to pay dividends in theforeseeable future and are currently restricted from paying dividends pursuant to theterms of our credit facility and Alberta corporate law.**
We have not paid any cash dividends on our common stock and do notexpect to pay any cash or other dividends in the foreseeable future. The terms of ourcurrent banking credit facility prohibit us from declaring and paying dividends exceptfrom assets that are in excess of the required amount of security under our creditfacility, and Alberta corporate law prohibits the payment of dividends unless statedsolvency tests are met.
**Our stock is thinly traded and is subject to price volatility.**
Trading volume in our common stock has historically been limited.Accordingly, the trading price of our common stock could be subject to wide fluctuationsin response to quarterly variations in operating results, changes in financial estimatesby securities analysts, an imbalance of purchasers and sellers, or other factors.
**ITEM 4. Information on the Company

BUSINESS

History**
Enterra Energy Corp. (formerly Westlinks ResourcesLtd.)("Enterra") was formed on June 30, 1998 by the amalgamation of TembaResources Ltd. ("Temba") and PTR Resources ltd. ("PTR") in ashare-for-share exchange. The combination was recorded using the purchase method ofaccounting with Temba being identified as the acquirer. An amalgamation is theconsolidation 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 atthe time of the amalgamation had acquired oil and gas production of approximately 27barrels of oil per day and 106 thousand cubic feet of gas per day from 19 oil wells andone gas well. Immediately prior to the amalgamation which created Westlinks, TembaResources amalgamated with its wholly owned subsidiary, Rainee Resources Ltd. Ourpredecessor, PTR Resources, was incorporated in Alberta on September 18, 1992 as 542275Alberta Ltd.; changed its name to Ablevest Holdings Ltd. on June 14, 1993, and to PTRResources on December 1, 1997. PTR Resources originally held a 2.5% working interest inmineral leases on 8.5 sections of land in Alberta.

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

Effective December 10, 2001 Westlinks Resources Ltd. changed its nameto Enterra Energy Corp. 
**Our Business**
We are an operating oil and gas company that drills, acquires, operatesand exploits crude oil and natural gas wells in our core areas in Western Canada. Ourcapital 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 resultsof our analysis of seismic studies and the results of our previous drilling, and thedevelopment of new opportunities as the year progresses.
**Glossary of Petroleum Industry Terms**
The following definitions of certain terms used in the oil and gasindustry will assist you in understanding our business:

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

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

"**Non-operated property**" means a well that is managedby a third party;

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

"**Petrophysical data**" means the rock parametersassociated with a reservoir, including thickness, porosity, permeability;

"**Porosity**" means the ability of a rock to containfluids. It is the volume of pore spaces between mineral grains, expressed as a percentageof the total rock volume;

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

"**Spudding**" means the commencement of the drilling of awell; 

"**Waterflood**" means the injection of water into an oilreservoir in order to enhance production;

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

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

"**Working Interest**" means the percent of production,before royalties, to which a party is entitled.
**Business Strategy**
As a result of the Big Horn acquisition a new management team is inplace at Enterra. Big Horn’s previous management was the surviving management groupfollowing the August 1, 2001 Big Horn acquisition. Prior to 2001, Enterra (then known asWestlinks) was an acquisition driven company. Big Horn, on the other hand, was a fullcycle oil and gas producer, focused on exploration and development. The new management atEnterra will be more focused in 2002 on its exploration, development and exploitationprograms than on corporate or property acquisitions.
*Low Risk Development Projects*
We concentrate our efforts on oil and gas properties that offeropportunities for low risk development. Typical types of low risk developments are thedrilling of infield and step-out wells, the installation of central facilities to handlehigher production volumes and the completion of other productive zones within wells.
*Consolidation of Adjacent Assets*
We seek property acquisitions and development opportunities on landsthat are in close proximity to our producing fields. These close-in acquisitions createthe ability to reduce operating costs by consolidating facilities. Moreover, drillingcosts are lower when wells are drilled as part of a multi-well program, due to reduced rigmoving costs and other efficiencies.
*Cost Effective Acquisitions*
While our main focus is the exploitation and development of ourproperties, we will pursue acquisitions of oil and gas producing properties but only atprices that allow the base production for the property to pay the acquisition cost withina reasonable time frame. We attempt to avoid paying for unproven reserves in the purchaseprice.
*Emphasis on Development Drilling*
We concentrate our drilling activities on low risk development wellslocated in or near our established core production areas. This strategy helps to reducerisk and costs, and enables new wells to be put on production more quickly. We do engagein exploratory drilling but only when the potential rewards justify the risks involved.
*Use of Seismic and Other Data in Site Selection*
We use the analysis of seismic data, including three-dimensionalseismic, whenever its use is appropriate for the geology and is cost effective, to furtherminimize drilling risk. We also use information from adjacent wells, includingpetrophysical data, production records and completion data to help reduce our risk andcosts.
*Selection of Properties*
We select properties for acquisition and development where we believewe can become the operator and that we believe offer us the opportunity to reduceoperating costs and maximize economies of scale, thereby improving operatingprofitability. We have used this strategy in the development of our core areas in Albertaand Saskatchewan, focusing on areas of moderate drilling costs, multi-zone potential, yearround accessibility and good gas plant and pipeline infrastructure.
**Properties**
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 atSounding Lake and Sylvan Lake. Enterra also has a substantial inventory of prospects, thedevelopment of which could potentially double the size of the Company’s existingproduction and reserve base. In accordance with the standard practice in the Canadian oiland gas industry, the working interests described below are the percentage ownership ofthe oil and gas production before payment of royalties.

NORTHWEST ALBERTA
*Worsley*
A new Montney oil pool was discovered in Northwest Alberta in 1998. TheMonte reservoir consists of light oil trapped above water. Enterra plans to develop thispool in 2002 utilizing horizontal drilling technology.  Solution gas will also betied into existing gathering systems and processed at a nearby gas plant. The Company hasa 50% working interest in this play. An analogous pool has been developed in the arearesulting in the first horizontal well going on production in late 2000 at 300 bbls/dayand has produced in excess of 75 mbbls of reserves to date.
*Gordondale*
Enterra acquired interests ranging from 30% to 100% in five contiguoussections of land in the Gordondale area of Northwest Alberta. This exploration area is gasprone in up to eight formations ranging from the Doe Creek at depths of less than 200 m tothe Debolt formation at a depth of 2450 m. Enterra shot a 3-D seismic program over thearea 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 hadan initial production rate of approximately 2 mmcf/day. . Enterra has plans to drillseveral more development and exploration wells at Gordondale and estimates netdeliverability from the area could exceed 500 boe/day.
*Rolla*
A significant Dunvegan gas pool was discovered in Northwest Alberta inlate 2000. Two wells were drilled in 2001 that are each capable of producing over 1mmcf/day.  The gas was tied into a nearby plant in early 2002. The two wells arecurrently flowing a combined rate 1 mmcf/day net to Enterra. The Company has alsoidentified other locations on its lands that will be drilled in 2002. Enterra has a 50%interest at Rolla.

CENTRAL ALBERTA
*Sounding Lake*
Sounding Lake continues to be Enterra’s largest area in terms ofproduction, representing approximately 25% of the Company’s 2001 production.Enterra’s focus on the area will remain strong through 2002 with an aggressivedrilling schedule combined with additional reduction in operating costs. The majority ofproduction and future activity in the area will target Dina and Cummings oil. A highlightat Sounding Lake in 2001 was the discovery of a new Belly River gas pool. Two wells arenow producing from this pool at facility restricted rates of 1.5 mmcf/day net to theCompany.  Enterra also structured a unique farmout arrangement to construct a centralfacility, optimize and infill drill the Sounding Lake North oil pool. This farmoutarrangement will maximize value to Enterra by eliminating required 2002 capitalexpenditures and reducing operating expenses. Enterra will also continue development ofthe Sounding Lake East, Rex oil discovery. The Company will shoot a 3-D seismic survey inmid 2002 to substantiate four geologically defined locations. The discovery well, drilledin 1997, has produced 65 mbbls of oil and is still producing 50 bbls/day. 
*Sylvan Lake*
Enterra continues to be excited about the Pekisko infill developmentpotential at Sylvan Lake. Geological mapping and petrophysics suggest that there are atleast six infill drilling locations. Defined by their proximity to an area of thereservoir that has undergone dolomitization. This process increases the porosity andpermeability of the predominately limestone reservoir. Although the best producer atSylvan Lake is capable of producing in excess of 100 bbl/d, Enterra is targetingproduction from the six infill wells to be 75 bbls/day of oil per well. Enterra alsosuccessfully recompleted a suspended well at Sylvan Lake to a Viking gas producer. Thiswell is expected to be tied in and on stream by June 2002 at an initial rate of 1mmcf/day. 

SOUTHWEST SASKATCHEWAN
*Superb*
Enterra acquired a shut in Waseca oil pool in Southwest Saskatchewanfor $2.8 million in June of 2001. The Company equipped and reactivated four existingproducers. 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 futureprojects. The development of these prospects has the potential to double the size of theCompany’s existing production and reserve base. New prospects are constantly added toour inventory in order to maintain our growth from year to year. The Company’sstrategy is to maintain a balanced inventory of exploration and development prospects. Inaccordance with the standard practice in the Canadian oil and gas industry, the workinginterests described below are the percentage ownership of the oil and gas productionbefore payment of royalties.
**Reserves and Present Value Summary**
The estimated oil and natural gas reserves of Enterra and theassociated estimated present value of estimated future net cash flows have been evaluatedin 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 theestimated share of the remaining oil, natural gas and natural gas liquids attributable toEnterra and the estimated present value of estimated future net cash flows for thesereserves, using constant prices and costs. All estimates of present value of future netcash flows are stated after provision for capital expenditures required to generate suchrevenues but prior to provision for indirect costs such as general and administrativeoverhead, income taxes or interest expense. It should not be assumed that the estimatedpresent values of future net cash flows are representative of the fair market value of thereserves. These recovery and reserve estimates of Enterra’s interests in thedescribed properties are estimates only; the actual reserves in the properties in which wehave an interest may be more or less than those calculated. Assumptions and qualificationsrelating to costs, prices and other matters are summarized in the notes to the followingtable. The extent and character of the material information supplied by Enterra including,but not limited to, ownership, well data, production, price, revenues, operating costs andcontracts were relied upon by McDaniel in preparing the report. In the absence of suchinformation, 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- 4thAvenue S.W., Calgary, Alberta during normal business hours. All monetary amounts areexpressed in Canadian dollars.

 
**Enterra Energy Corp.

Estimated Petroleum and Natural Gas Reserves and Net Present Value

January 1, 2002**
**Oil & NGL’s****Natural Gas****NPV****Gross****Net****Gross****Net****Mstb****Mtsb****MMcf****MMcf****0%****10%****15%**Proved Developed3,430.62,867.47,684.45,773.075,56853,33047,103Proved Developed Non-Producing 308.9264.0
2,221.31,624.210,7787,9136,975Proved Undeveloped393.1341.0801.0654.06,7854,5253,786Total Proved4,132.63,472.410,706.78,051.293,13165,76857,864
__________

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.
**Crude oil****Natural Gas Liquids (C$/bbl)**West Texas Intermediate (US$/bbl)
$25.97Propane
$29.17Edmonton Light Crude (C$/bbl)
$39.60Field butane
$28.46Bow River Medium Crude (C$/bbl)
$27.50NGL mix
$30.85Hardisty Heavy (C$/bbl)
$18.00Natural Gasolines & Condensate
$39.60**Natural Gas (C$/Mmbtu)**Alberta Average
$5.25Transcanada Gas Services Ltd.
$5.44Pan Alberta Gas Ltd.
$5.04Progas
$5.00Spot Sales
$5.28Saskatchewan Average
$5.70Can West Plant Gate (B.C.)
$6.55**Historical Reserves**
The following table sets out Enterra’s proved oil and gasreserves, 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 McDanielat January 1, 2002. The monetary amounts are expressed in Canadian dollars. The reservenumbers for December 31, 1998 and 1997 were prepared internally by Enterra, based uponreserve reports prepared at various dates by independent engineering firms and adjustedfor actual production. Present value amounts are not available as it is not feasible toredo such calculations after the fact.
**December 31,****2001**2000**1999**1998**1997Proved Producing Reserves:Oil and NGL’s (thousands of barrels) 
3,431
1,612
1,054
588
560Gas (millions of cubic feet)
7,684
713
107
417
2,957Proved reserves:Oil and NGL’s (thousands of barrels)
4,133
2,331
1,539
604
560Gas (millions of cubic feet)
10,707
976
617
417
5,873
 
**Land Holdings**
At December 31, 2001 Enterra had the following land holdings

Gross
Net
Developed acres
41,605
22,646
Undeveloped acres
89,296
58,590
Total acres
130,901
81,236
 
**Production**
The following table summarizes Enterra’s working interestproduction, before royalties, during the periods indicated.
**Years ended December 31,**2001**2000**1999**1998**1997Oil and NGL’s (MBbls)
582
410
93
86
79Gas (MMcf)
680
63
61
220
58Total (MBOE)
695
421
100
108
85Average Production in BOEPD 
1,906
1,150
274
296
233
Definitions: 

"*BOEPD*" means barrels of oil equivalent produced perday. 

"*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 toproduction of crude oil or natural gas liquids.

"*MMcf*" means millions of cubic feet, with respect toproduction of natural gas.

"*NGL’s*" means natural gas liquids, being thosehydrocarbon components recovered from raw natural gas as liquids by processing throughextraction plants or recovered from field separators, scrubbers or other gatheringfacilities. These liquids include the hydrocarbon components ethane, propane, butanes andpentanes plus, or a combination thereof.
**Drilling**
Enterra’s drilling history is as follows (there were no wellsdrilled in 1997 and 1999) :
**2001**2000**1998**Wells drilled****Gross (Net)**Gross (Net)**Gross (Net)Oil
9 (4.97)
9 (8.26)
0 (0.00)Natural Gas 
8 (3.78)
2 (1.27)
0 (0.00)Abandoned 
3 (1.84)
2 (1.14)
1 (0.13)Total
20 (10.59)
13 (10.67)
1 (0.13)
__________

Notes: 

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

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

 
**Capital Expenditures**
The following table summarizes the capital expenditures made by Enterraduring the periods indicated, expressed in Canadian dollars:
**Years ended December 31,****2001**2000**1999**1998**1997**(In    thousand’s)Property acquisitions (net)
$52,374 
$ 8,220
$ 1,879
$ 244
$ 500Drilling (exploration and development) 
5,821
6,922
341
27
50Facilities
1,412
56
728
4
0Miscellaneous
1,011
156
24
2
34Total
$68,618
$ 15,354
$2,972
$ 277
$ 584**Oil and Gas Wells**
The following table summarizes Enterra’s interest in producing andnon-producing oil and gas wells as at December 31, 2001 :
**Producing
Oil Wells**Producing
Gas Wells**Gross **Net**Gross **Net Campbell
1
0.12Deer Mountain
1
0.50Gull Lake South
6
2.28West Gull Lake
4
3.60Hazlet unit
8
1.60Lanaway
6
2.68
6
2.06Leduc
1
0.39Crossfield
6
0.16Cygnet
2
1.50Deanne
2
0.20Garden Plains
1
0.62Gartley
2
0.75Gilby
1
0.39Leedale
1
0.02Lubicon
1
0.23Progress
1
0.50Sinclair
1
0.44Webster
1
0.25St-Anne
1
0.65Willesden Green
1
0.43Worsley
1
0.50Mitsue
8
8.00Timber Draw
1
0.15Grand Forks
41
41.00Sounding Lake East 
15
14.50Sounding Lake West 
55
27.50Sounding Lake North 
21
6.72Sylvan Lake
13
11.75Total Wells
183
121.52
26
7.97** 

Employees**
At December 31, 2001 the Company had approximately twelve employees andconsultants working both in the Calgary head office and in its field operations.
**Competition**
The petroleum industry is highly competitive. Enterra competes withnumerous other participants in the acquisition of oil and gas leases and properties, andthe recruitment of employees. Any company can make acquisitions and bid on provincialleases in Alberta. Competitors include oil companies that have greater financialresources, staff and facilities than those of Enterra. Our ability to increase reserves inthe future will depend not only on our ability to develop existing properties, but also onour ability to select and acquire suitable additional producing properties or prospectsfor 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 andreliability of delivery.
**Office Facilities**
Enterra currently leases 10,450 square feet of office space at Suite2600, 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 annualrental is C$27.26 per square foot (including operating costs and property taxes).
**Government Regulation in Canada**
The oil and natural gas industry is subject to extensive controls andregulations governing its operations, including land tenure, exploration, development,production, refining, transportation and marketing, imposed by legislation enacted byvarious levels of government and with respect to pricing and taxation of oil and naturalgas by agreements among the governments of Canada, Alberta and British Columbia, all ofwhich should be carefully considered by investors in the Canadian oil and gas industry. Itis not expected that any of these controls or regulations will affect the operations ofWestlinks in a manner materially different from how they would affect other oil and gascompanies of similar size operating in Western Canada. All current legislation is a matterof public record and Enterra is unable to predict what additional legislation oramendments may be enacted. Outlined below are some of the principal aspects oflegislation, regulations and agreements governing the oil and gas industry.
*Pricing and Marketing — Oil and Natural Gas*
The producers of oil are entitled to negotiate sales contracts directlywith oil purchasers, with the result that the market determines the price of oil. Suchprice depends in part on oil quality, prices of competing oils, distance to market, thevalue of refined products and the supply/demand balance. Oil exporters are also entitledto enter into export contracts with terms not exceeding one year in the case of lightcrude oil and two years in the case of heavy crude oil, provided that an order approvingsuch export has been obtained from the National Energy Board of Canada, or NEB. Any oilexport 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 suchlicence requires the approval of the Governor in Council. In addition, the prorationing ofcapacity on the interprovincial pipeline systems continues to limit oil exports.

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

The governments of British Columbia and Alberta also regulate thevolume of natural gas which may be removed from those provinces for consumption elsewherebased on such factors as reserve ability, transportation arrangements and marketconsiderations.
*Provincial Royalties and Incentives*
In addition to federal regulation, each province has legislation andregulations which govern land tenure, royalties, production rates, environmentalprotection and other matters. The royalty regime is a significant factor in theprofitability of crude oil, natural gas liquids, sulphur and natural gas production.Royalties payable on production from lands other than Crown lands are determined bynegotiations between the mineral owner and the lessee, although production from such landsis subject to certain provincial taxes and royalties. Crown royalties are determined bygovernmental regulation and are generally calculated as a percentage of the value of thegross production. The rate of royalties payable generally depends in part on prescribedreference prices, well productivity, geographical location, field discovery date and thetype or quality of the petroleum product produced.

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

In the Province of Alberta, a producer of oil or natural gas isentitled to a credit against the royalties payable to the Crown by virtue of the AlbertaRoyalty Tax Credit or, ARTC program. The ARTC rate is based on a price sensitive formulaand the ARTC rate varies between 75% at prices at and below $100 per thousand cubic metresand 25% at prices at and above $210 per thousand cubic metres. The ARTC rate is applied toa maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associatedgroup of producers. Crown royalties on production from producing properties acquired froma corporation claiming maximum entitlement to ARTC will generally not be eligible forARTC. 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 wasconducting a review of the ARTC program with the objective of setting out better-targetedobjectives for a smaller program and to deal with administrative difficulties. On August30, 1999, the Alberta government announced that it would not be reducing the size of theprogram but that it would introduce new rules to reduce the number of persons who qualifyfor the program. The new rules will preclude companies that pay less than $10,000 inroyalties per year and non-corporate entities from qualifying for the program. Such ruleswill not presently preclude Enterra from being eligible for the ARTC program.

Crude oil and natural gas royalty holidays for specific wells androyalty reductions reduce the amount of Crown royalties paid by Enterra to the provincialgovernments. In general, the ARTC program provides a rebate on Alberta Crown royaltiespaid in respect of eligible producing properties.
*Land Tenure*
Crude oil and natural gas located in the western provinces is ownedpredominantly by the respective provincial governments. Provincial governments grantrights to explore for and produce oil and natural gas pursuant to leases, licences andpermits for varying terms from two years and on conditions set forth in provinciallegislation including requirements to perform specific work or make payments. Oil andnatural gas located in such provinces can also be privately owned and rights to explorefor and produce such oil and natural gas are granted by lease on such terms and conditionsas may be negotiated.
*Environmental Regulation*
The oil and natural gas industry is currently subject to environmentalregulations pursuant to a variety of provincial and federal legislation. Such legislationprovides for restrictions and prohibitions on the release or emission of varioussubstances produced in association with certain oil and gas industry operations. Inaddition, such legislation requires that well and facility sites be abandoned andreclaimed to the satisfaction of provincial authorities. Compliance with such legislationcan require significant expenditures and a breach of such requirements may result insuspension or revocation of necessary licenses and authorizations, civil liability forpollution damage and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has beenconsolidated into the *Environmental Protection and Enhancement Act*, or EPEA, whichcame into force on September 1, 1993. The EPEA imposes stricter environmental standards,requires more stringent compliance, reporting and monitoring obligations and significantlyincreases penalties for violations. Enterra is committed to meeting its responsibilitiesto protect the environment wherever it operates and anticipates making increasedexpenditures of both a capital and expense nature as a result of the increasinglystringent laws relating to the protection of the environment and will be taking such stepsas required to ensure compliance with the EPEA and similar legislation in otherjurisdictions in which it operates. Enterra believes that it is in material compliancewith applicable environmental laws and regulations. Enterra also believes that it isreasonably likely that the trend towards stricter standards in environmental legislationand regulation will continue.
**ITEM 5. Operating and Financial Review and Prospects

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS**
The following discussion of our results of operations and financialcondition should be read in conjunction with the financial statements and other financialinformation included in this annual report. The statements that relate to matters that arenot historical facts are "forward-looking statements". Words such as"anticipate", "believe", "expect", "plan","intend", "estimate", "project", "will","should" "could", "may", "predict" and similarexpressions are intended to identify forward-looking statements. Future events and actualresults may differ materially from the results set forth in or implied in theforward-looking statements. Factors that might cause such a difference such as thosediscussed 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 financialconditions, liquidity and capital resources as of December 31, 2001 and December 31, 2000and the results of operations for the years ended December 31, 2001 and 2000. Theinformation is expressed in Canadian dollars.
***Year ended December 31, 2001 Compared to Year Ended December 31, 2000**
Financial Condition, Liquidity and Capital Resources

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. AtDecember 31, 2001 Enterra had a revolving production loan with a Canadian bank. Theproduction loan only requires the payment of interest and is reviewed annually to ensureEnterra’s reserves are sufficient to support the loan. Under Canadian GAAP, becausethe bank has indicated that it does not require payment of the facility in the next 12months, the loan is classified as long term. Effective January 1, 2002 the Canadian GAAPrules will mirror the U.S. GAAP rules: the calculation and presentation of working capitalwill 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 Hornacquisition, 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 firstquarter of 2001 upon the settlement of a hedging contract. 

During the year ended December 31, 2001 there was a decrease innon-cash working capital of $2.7 million. The decrease was the direct result of income taxpayments of $1.2 million made in 2001 (which were accrued at December 31, 2000) an adecrease in accounts payable of $1.5 million.
**Financing Activities**
Enterra’s ability to maintain and grow its operating income andcash flow is dependent upon continued capital spending to replace depleting assets.Enterra believes its future cash flow from operations, borrowing capacity and futureequity 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 supportongoing operations. At December 31, 2001 Enterra’s bank facility consisted of a lineof credit of $21.5 million (of which $18.4 was drawn). Interest on amounts drawn is basedon the bank’s prime rate plus 0.25%.

Security is provided by a first charge over all of the Company’sassets. While the loan is repayable on demand, Enterra is not subject to scheduledrepayments. The lender has advised the Company that, subject to annual review of theborrowing 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 creditwas increased to $24 million.

The Company completed a secondary public offering in the United Statesin January of 2001, consisting of 1,000,000 units of one common share and one sharepurchase warrant for US$4.55 per unit. The share purchase warrants have an expiry date ofApril 17, 2002 and are exercisable at US$3.50 per share. The proceeds from this offeringwere used to purchase the Grand Forks oil and gas assets for $5.5 million in March of2001.

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 sharesand 7,418,332 preferred shares. Enterra has also repurchased, through its previouslyannounced share buyback program, 232,500 of its common shares during 2001. The Companycurrently has 9,150,622 common shares outstanding. 

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

Subsequent to December 31, 2001 the Company sold its Grand Forksproperty for $5.3 million. Proceeds from this sale were used to reduce our bank debt andto repurchase some of the preferred shares. 

The Company was not taxable in 2001. It has $43.1 million in tax poolsavailable at December 31, 2001.
**Investing Activities**
The timing of most of Enterra’s capital expenditures isdiscretionary. Enterra has no material long-term commitments associated with its capitalexpenditure plans or operating agreements. Consequently, the Company has a significantdegree 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 weexperience on planned drilling activities, oil and gas price conditions and other relatedeconomic 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 allocatedto capital expenditures. The Big Horn acquisition required approximately $2 million incash. 

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 wheremanagement believes that opportunities to increase its value are limited and the propertyrepresents less than 20% of the Company’s total reserves.
**Results of Operations**
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 tothe Big Horn and Grand Forks acquisitions made during the year. The Company drilled 20wells (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% oiland 16% natural gas.

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

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

In the Province of Alberta, a producer of oil and natural gas isentitled to a credit against the royalties payable to the province by virtue of theAlberta Royalty Tax Credit, or ARTC, program. The ARTC rate is based on a price-sensitiveformula and the ARTC rate varies between 75% at prices at and below $100 per thousandcubic metres and 25% at prices at and above $210 per thousand cubic metres. The ARTC rateis applied to a maximum of $2,000,000 of Alberta provincial royalties payable for eachproducer or associated group of producers. Provincial royalties on production fromproducing properties acquired from a corporation claiming maximum entitlement to ARTC willgenerally 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 previousquarterly period.

Operating expenses were $5,829,614 in 2001 (2000 - $4,029,703). Thisincrease is the result of the increased production in 2001. On a barrel of oil equivalentbasis operating costs for 2001 and 2000 were $8.38 and $9.58, respectively. The decreaseis 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 wasable to reduce overall operating expenses in the second half of 2001. 

General and administrative expenses decreased 59% from $1,391,297 in2000 to $565,270 in 2001. On a barrel of oil equivalent basis administrative costsdecreased 75% from $3.31 in 2000 to $0.81 in 2001. The decrease in administrative costswas largely due to the corporate synergies as a result of combining Enterra and Big Hornwithout 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 debtlevels in the first half of 2001 as a result of the equity financing which occurred inearly 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 anddepreciation was 34% and 18%. The increase reflects a higher cost base in our capitalassets in 2001 and the impact of lower commodity prices.

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

Current and future income tax expense at December 31, 2001 was $120,000and $562,000 respectively, compared to $1,316,171 and $333,634 respectively at December31, 2000. The reduction in current income taxes is due to the larger tax pools availableto Enterra in 2001. The future income tax expenses were a result of the timing ofdeductions for accounting purposes and tax on petroleum and gas assets. 

The Company’s earnings decreased by 34% in 2001 from $2.4 millionin 2000 to $1.6 million in 2001. The reasons for this decline are threefold: lowercommodity prices, higher depletion expense and one-time restructuring charges. Oil and gasprices 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 comparedwith $6.15 in 2000 (a 40% decline). Depletion expense also increased in 2001 due to theincreased 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 2001which provides a floor price of US$20 per barrel and a ceiling price of US$24 per barrelfor 500 barrels of oil per day. The contract is effective from November 1, 2001 throughApril 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 ofaccounting 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 developmentcosts are capitalized and accumulated in one cost center.   Enterra places a limit on the aggregate cost of property, plant andequipment which may be carried forward for amortization against revenues of future periods(the "ceiling test").  The ceiling test is a cost recovery test whereby thecapitalized costs less accumulated depletion and site restoration are limited to an amountequal to estimated undiscounted future net revenues from proved reserves less recurringgeneral and administrative expenses, site restoration, future financing costs and incometaxes.  Costs and prices at the balance sheet dates are used.  Any costs carriedon 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 overheadcosts are expensed as incurred. Capitalized costs are depleted on a property by propertybasis. Impairments are assessed on a property by property basis and are charged toexpenses when assessed.

We believe the "full cost" method, as described above and inthe Risk Factors section of this document, as well as in the notes to the attachedfinancial statements, is the appropriate method to use to account for Enterra’s oiland gas exploration and development activities. The Company’s strategy calls forsubstantial exploration and development activities in 2002 and subsequent years. Webelieve the "full cost" method is a more appropriate accounting policy for ouroil and gas operations as it is better suited in recognizing that the costs of ourexploration and development programs are part of an overall long-term investment indiscovering and developing sustainable oil and gas reserves.
**Subsequent Event – Repurchase of preferred shares**
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.
**Subsequent Event – Warrants**
On March 28, 2002 the Company agreed to issue 400,000 share purchasewarrants to an arm’s length U.S.-based consulting firm in connection with a potentialdebt financing in the United States. The warrants are to have a two-year term and aresubject to different pricing (100,000 warrants at US$2.60, 100,000 at US$3.30 and 200,000at US$4.00). The US$2.60 warrants are to vest upon the execution of a non-binding letterof intent relating to the proposed financing. The US$3.30 and US$4.00 warrants are to vestonly on the successful closing and funding of the proposed financing.
**Subsequent Event – Expiry of warrants**
On April 12, 2002 the Company was granted a 30-day extension for the1,000,000 share purchase warrants which were exercisable until April 17, 2002. The expirydate was extended to May 17, 2002. The warrants expired on May 17, 2002 without beingexercised.
**Year ended December 31, 2000 Compared to Year Ended December 31, 1999

Financial Condition, Liquidity and Capital Resources

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

Cash flow from operations was $5,875,500 for the year ended December31, 2000 compared to $293,767 for the year ended December 31, 1999. The increase waslargely due to an increase in net income to approximately $2.3 million and the increase inthe non-cash depletion, depreciation and site restoration to $4.5 million.

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

Enterra’s ability to maintain and grow its operating income andcash flow is dependent upon continued capital spending to replace depleting assets.Enterra believes its future cash flow from operations, borrowing capacity and futureequity 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 capitalassets 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. Thefacility bears interest at the bank’s prime commercial lending rate plus one quarterof one percent.

During the year ended December 31, 2000, Enterra had been technicallyin default under the covenants in the credit facility that require that the current assetratio not fall below a ratio of one to one. At the time of the default the current assetratio was 0.44. The bank had allowed Enterra to draw down the credit facility, knowingthat draw down would cause the technical default. This technical default was cured by theend 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 inAlberta. 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 reducedthe revolving operating facility from $12.5 million to $9.0 million.

During the year Enterra borrowed US$1,500,000 from six non-affiliatedprivate lenders. The loans bore interest of 12% per annum plus a US$50,000 setup fee. Wealso issued to the lenders warrants to purchase 150,000 shares at US$4.00 per share. Theloans 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 theexercise of common stock options, and applied to our operating activities.

Effective November 1, 2000 Enterra entered into a three year fixedprice crude oil contract. In January 2001, the Company settled the fixed price contracteliminating 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 whichwill be recognized over the terms of the contract.
**Investing Activities

The timing of most of Enterra’s capital expenditures isdiscretionary. Enterra has no material long-term commitments associated with its capitalexpenditure plans or operating agreements. Consequently, Enterra has a significant degreeof flexibility to adjust the level of such expenditures as circumstances warrant. Thelevel of capital expenditures will vary in future periods depending on the success weexperience on planned drilling activities, oil and gas price conditions and other relatedeconomic 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 in2000 was principally due to the Mitsue and Sounding Lake acquisitions, drilling threewells in Bigoray, and drilling seven wells in Sylvan Lake, and was partially offset by theBigoray area disposition.

During the years ended 2000 and 1999 several non-core properties weredisposed of for $5,764,570 and $796,800, respectively. Enterra defines a "non-coreproperty" as a property where management believes that opportunities to increase itsvalue are limited and the property represents less than 20% of Enterra’s totalreserves. The funds received from the sales are typically used either for futureacquisitions or the drilling of new wells consequently the impact on the results ofoperations and future liquidity is minimized.
**Results of Operations

Gross revenue from oil and gas production was $16,700,151 for the yearended December 31, 2000 compared to $2,515,456 for the year ended December 31, 1999 whichrepresents an increase 564%. The increase was due to the Sylvan Lake acquisitions madelate 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 $16,312,523from $2,379,417 in 1999. This was due to increased volumes and higher prices. As a resultof project acquisitions and drilling activities, oil production increased 339% from 93,487in 1999 to 409,958 barrels in 2000. During 2000 we received an average price of $39.79 perbarrel 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 volumesincreased from 61,068 thousand cubic feet to 62,988 thousand cubic feet. The average pricerealized 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, royaltieswere 20% during 2000 compared to 18% for 1999. The increase was mainly due to our purchaseof producing properties that are not eligible to receive Alberta Royalty Tax Credits. Thiscredit significantly reduces the impact of provincial Crown royalties.

In the Province of Alberta, a producer of oil and natural gas isentitled to a credit against the royalties payable to the province by virtue of theAlberta Royalty Tax Credit, or ARTC, program. The ARTC rate is based on a price-sensitiveformula and the ARTC rate varies between 75% at prices at and below $100 per thousandcubic metres and 25% at prices at and above $210 per thousand cubic metres. The ARTC rateis applied to a maximum of $2,000,000 of Alberta provincial royalties payable for eachproducer or associated group of producers. Provincial royalties on production fromproducing properties acquired from a corporation claiming maximum entitlement to ARTC willgenerally 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 previousquarterly period.

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

General and administrative expenses increased 61% from $862,546 during1999 to $1,391,297 in 2000. On a barrel of oil equivalent basis administrative costsdecreased from $8.32 in 1999 to $3.31 in 2000. The increase in administrative costs waslargely due to increasing salaries for the existing staff and the hiring of additionalstaff. The decrease in administrative costs, on a barrel of equivalent basis, resultedfrom increased volumes and our efforts to maintain our current staff level whileincreasing 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 debtoutstanding 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 anddeprecation was $10.68 and $8.45. The increase reflects a higher cost base in our capitalassets.

During the year ended Enterra disposed of non-core oil and gasproperties that resulted in a gain of $1,338,577 compared to a gain of $91,402 in thecorresponding 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 $246,884at December 31, 1999. The expenses were a result of the timing of deductions foraccounting purposes and tax on petroleum and gas assets. The recovery in 1999 wasattributable to loss carry forwards not previously recognized.
** 

ITEM 6. Directors, Senior Management and Employees**
The directors and executive officers of Enterra as of December 31, 2001were: 
**Name****Age****Position with Enterra**Walter Dawson61DirectorReg J. Greenslade38Director, President and Chief Executive    OfficerH.S. (Scobey) Hartley69DirectorThomas J. Jacobsen 67DirectorJohn P. McGrain56Director and ChairmanDon Almond46Vice President ProductionLuc Chartrand45Chief Financial OfficerRick McHardy33Corporate SecretaryTrevor Spagrud 33Vice-President Operations
In 2002, John McGrain resigned as Director and Chairman, Don Almondresigned as Vice President Production, Thomas Jacobsen was appointed Chief OperatingOfficer and two new Directors ( Doug Paul and Norman W.G. Wallace) were elected to theBoard: 
**Name****Age****Position with Enterra**Doug Paul53DirectorNorman W.G. Wallace63Director*Walter A. Dawson. Mr. Dawson was formerly the Executive Chairman ofEnserco Energy Services Corp. He resigned in March 2001 after the merger with Tetonka wascompleted to pursue the creation of Simmons Energy Services. In 1993, Mr. Dawson, throughhis 100%-owned holding company, Perfco Investments Ltd., purchased control of BonusPetroleum Corp., a public company that became Enserco. Enserco is now a leader in theCanadian workover and drilling market with 200 service rigs and 30 drilling rigs in Canadaand Australia and will achieve revenue of $250 million along with over $80 million cashflow in 2001. Prior to Perfco Investments, Mr. Dawson founded and served 19 years asPresident, Chief Executive Officer, and director of Computalog Ltd. In 1972, Mr. Dawsonpurchased a cased-hole wireline unit from Gearhart Industries and incorporated PerfcoServices Ltd., which later formed Computalog Gearhart Ltd. in 1978. He was instrumental intaking the company public on the Toronto Stock Exchange in 1980, negotiating an exclusivetechnology/supply agreement with Gearhart Industries for Canada. Afterwards, he enteredthe directional and fishing tool business, along with the incorporation of thecompany’s first research center where he hired 50 research and development experts todesign and build state-of-the-art well logging equipment. Mr. Dawson led and completedseveral financings to achieve this goal. Mr. Dawson is currently a director of IntegratedProduction Services, a Toronto Stock Exchange listed company, and is a director of ActionEnergy Inc., a private company. He also held positions on several oil and gas boards overhis career for both service and producing companies. Mr. Dawson became a Director ofEnterra in August 2001.
*Reg J. Greenslade. Mr. Greenslade became President of Big Horn inApril 1995 and President and CEO and a Director of Enterra in August 2001. Prior tojoining Big Horn, Mr. Greenslade held senior positions with several medium- andlarge-sized oil and gas companies. Most recently Mr. Greenslade was with CS ResourcesLimited 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 projectmanagement, production, and reservoir engineering. He has extensive experience withsecondary recovery schemes and is recognized for his work in the specialized field ofhorizontal well technology.
*H.S. (Scobey) Hartley. Mr. Hartley was appointed a director ofEnterra in May, 2000. He has been Chairman of Prism Petroleum Ltd. since January, 1997 andwas formerly the President of Prism Petroleum Ltd. and a predecessor company fromDecember, 1990 through December, 1996. Mr. Hartley has also served as the President ofFaster 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 TexasTech University in 1956.
*Thomas J. Jacobsen. Mr. Jacobsen joined Enterra as a director inFebruary 1999, and was appointed Executive Vice-President, Operations in October 1999. InOctober 2000 he resigned from this position and was appointed the Vice-Chairman of theBoard 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 gasopportunities in the United States. Through his company, Wells Gray Resort & ResourcesLtd., Enterra also granted him a consulting contract through April 15, 2001; pursuant towhich Mr. Jacobsen was be in charge of Enterra’s drilling, completion and equippingprojects. His more than 40 years of experience in the oil and gas industry in Alberta andSaskatchewan includes serving as the President and Chief Operating Officer of AmericommResources Corporation since June 2001; President and Chief Executive Officer of NiaskiEnvironmental Inc. from November, 1996 to February, 1999; President and Chief ExecutiveOfficer 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 listedon the Canadian Venture Exchange. Niaski has made a proposal to its creditors under the *Bankruptcyand Insolvency Act*(Canada). The proposal has been approved by the creditors but hasnot yet been funded and completed. Mr., Jacobsen became Enterra’s Chief OperatingOfficer in January 2002.
*John P. McGrain. Mr. Mcgrain was appointed Chairman and actingPresident of Enterra in April 2001. Mr. McGrain has been Chairman and Interim ChiefExecutive Officer of Americomm Resources Corporation since June 2001 and served asChairman and Chief Executive Officer of International Colin Energy from 1991 to 1994, andChairman and Chief Executive Officer of Conversion Industries from 1984 to 1994. In 1997Mr. McGrain filed for protection under personal bankruptcy Chapter 11 and was dischargedin 1998. Since 1998 he has been a private investor. Mr. McGrain graduated from UCLA with aBachelor of Arts degree in 1967. Mr. McGrain resigned as Chairman and Director in June2002.
*Don Almond. Mr. Almond has accumulated 25 years of oil industryexperience. His career began with Husky Oil in field operations. He then moved on toPanCanadian Petroleum and Wascana Energy where he gained extensive experience with allaspects of production, exploitation, and operations engineering. In 1997, Mr. Almondjoined Opal Energy Inc. as Vice President of Operations and remained in this role untilthe corporation was sold at the end of 1998. In mid-1999, Mr. Almond was a founder andVice President of Operations of Ranchero Oil & Gas Ltd. He remained in this role untilearly 2001 when another oil and gas company acquired his corporation. Mr. Almond joinedEnterra as Vice President Production in November 2001 and resigned in April 2002.
*Luc Chartrand. Mr. Chartrand worked for KPMG as a CharteredAccountant from 1985 to 1988 when he became a tax manager in their Calgary office. He leftshortly thereafter and worked as a consultant to several Calgary companies. He moved toToronto in 1990 to assist in the relocation and takeover of Financial Trust by CentralCapital. He remained in Toronto until 1992 when he returned to Calgary with MorganFinancial Corporation. Shortly thereafter, he joined Bonus Resource Services Corp. as itsChief Financial Officer. Mr. Chartrand joined Big Horn Resources Ltd. in the fall of 1994and became Chief Financial Officer in 1996. He became Chief Financial Officer of Enterrain August 2001.
*Rick McHardy. Mr. McHardy has been a partner with the law firm ofMcCarthy 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 firmof Code Hunter. Mr. McHardy specializes in mergers and acquisitions matters involving bothpublic and private companies and has experience in a wide variety of corporate finance andsecurities transactions. Mr. McHardy obtained a Bachelor of Commerce degree from theUniversity of Saskatchewan in 1990 and a Bachelor of Laws degree from the University ofSaskatchewan in 1993.
*Trevor Spagrud. Mr. Spagrud started his professional career withSaskatchewan Oil and Gas (SaskOil) in 1990, gaining progressive experience in production,completions, and reservoir engineering. He remained at SaskOil, which became WascanaEnergy, until 1996 when he held the position of Senior Development Engineer. In thisposition, Mr. Spagrud was responsible for all engineering functions in both developmentand exploration prospects. In 1996, he became the Engineering Manager at Truax Resourcesand remained there until the company was taken over in June 1997, at which time he movedto Big Horn. He became Big Horn’s Vice President of Operations in 1998 andEnterra’s Vice President of Operations in August 2001.
*Doug Paul. Mr. Paul had a career spanning over 30 years with the Royal Bank ofCanada, during which time he held a number of administrative and lending positions. Hisassignments with the bank included the position of Senior Auditor, which entailedassessment of the quality of the bank’s loan portfolio both domestically andinternationally. Most recently Mr. Paul worked in the bank’s oil and gas divisionwhere he administered a loan portfolio of some $500MM, which included domestic andinternational exploration and development companies, drilling and service companies. Inthat capacity, Mr. Paul supported the growth and development of the largest drilling andservices companies in Western Canada. Currently as Vice President of Canada West CorporateFinance, where he has been engaged for some two years, Mr. Paul holds associate membershipin C.A.O.D.C. and P.S.A.C.
*Norman W.G. Wallace. Mr. Wallace was elected a director of Enterrain 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 in1968. Mr. Wallace resigned as Director in August 2001 and was re-appointed in June 2002.
**Board of Directors**
Enterra is authorized to have a board of at least three directors andno more than ten. We currently have six directors. Our directors are elected for a term ofabout 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 earlierresignation or death. There are no family relationships among any of our directors orofficers. Alberta corporate law requires that we have at least two independent outsidedirectors 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 theypersonally attend and $250 for each conference call which they participate in whichexceeds 1 hour in duration. Directors are also entitled to be compensated for theirout-of-pocket costs, including travel and accommodation, relating to their attendance atany directors' meeting. Finally, the directors are entitled to participate in theCorporation's stock option plan. During the year ended December 31, 2001, options toacquire a total of 240,000 common shares were granted to the current directors of theCorporation (not including options granted to a director who is also a named executiveofficer). Except as described herein, no compensation by way of annual retainer or meetingfees was paid to directors for acting in such capacity in the year ended December 31,2001.
**Committees of the Board of Directors**
Enterra’s Board of Directors currently has an audit committee, acompensation 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 auditcommittee reviews in detail and recommends approval of the full board of our annual andquarterly financial statements; recommends approval of the remuneration of our auditors tothe full board; reviews the scope of the audit procedures and the final audit report withthe auditors, and reviews our overall accounting practices and procedures and internalcontrols with the auditors.
*Compensation Committee. Our compensation committee consists of Mr.Hartley (Chairman), Mr. Wallace and Mr. Dawson. The compensation committee recommendsapproval to the full board of the compensation of the Chief Executive Officer, the annualcompensation budget for all other employees, bonuses, grants of stock options and anychanges to our benefit plans.
*Corporate Governance Committee. Our corporate governance committeeconsists of Mr. Wallace (Chairman), Mr. Dawson and Mr. Hartley. The corporate governancecommittee determines the scope and frequency of periodic reports to the board concerningissues relating to overall financial reporting, disclosure and other communications withall stakeholders.
*Reserves Committee. Our reserves committee consists of Mr. Paul(Chairman) and Mr. Hartley. The reserves committee reviews and recommends approval to thefull board of Enterra’s annual reserve report as prepared by independent reservoirengineers.
**Executive Compensation**
The following table provides a summary of compensation earned duringthe last fiscal year ended December 31, 2001 by the Corporation's executive officersduring 2001. These officers were appointed to their positions in August 2001. Thecompensation shown below is based on a calendar 2001 year, including the months prior toAugust 2001.

All monetary amounts are in Canadian dollars.

 
**Name and Principal Position**Year**Annual Compensation**Long-Term Compensation**All Other Compensation    ($)**Salary    ($)**Bonus    ($)**Other Annual Compensation($)**Awards**Payouts**Securities    Under Options/ SARs Granted    (#)**Restricted    Shares or Restricted Share Units    ($)**LTIP    Payouts    ($)Reginald J.    Greenslade
President and Chief Executive Officer
2001
157,500
-
12,279
144,000
-
-
-Trevor R.    Spagrud
Vice-President, Operations
2001
131,250
-
10,195
100,000
-
-
-Luc Chartrand
Chief Financial Officer
2001
133,365
-
-
72,500
-
-
-
 

 

 
* *
 

 

 

 

 

 

 

 

*Management Contracts*

Enterra has employment contracts with Reginald Greenslade and TrevorSpagrud which provide that the named executive officer will be paid a severance paymentif: (a) the named executive officer's employment is terminated; or (b) a change of controloccurs in the Corporation and the named executive officer does not continue to be employedby the Corporation at a level of responsibility or a level of base salary and compensationat least commensurate with the named executive officer's level of responsibility, basesalary and compensation immediately prior to the change of control and the named executiveofficer elects to terminate his employment within twelve (12) months of the change ofcontrol. 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 monthsseverance payment, respectively. Additionally, both Mr. Greenslade and Mr. Spagrud areentitled to additional allocation of benefits for past bonus amounts paid to each of them.
*Stock Options*
Enterra grants stock options from time to time to its directors,officers, key employees, and consultants. The terms and conditions of the options, inaccordance with resolutions of our board of directors and the policies of the CanadianVenture Exchange, will not exceed a term of five years. The option price may be at adiscount to market price, which discount will not, in any event, exceed that permitted byany stock exchange on which our shares are listed for trading.

Ten percent of Enterra’s shares of issued and outstanding commonstock from time to time are reserved for issuance pursuant to stock options. The aggregatenumber of shares reserved for issuance under option grants, together with any otheremployee stock option plans, options for services and employee stock purchase plans, willnot 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 exceedfive percent of the issued and outstanding shares of common stock.

If an optionee ceases to be eligible due to the loss of corporateoffice or employment for any reason other than death, the option terminates not later than30 days after the loss of such corporate office; provided that in the event of terminationof employment for cause, the board of directors may resolve that the option shallterminate on the date of such termination. Option agreements also provide that estates ofdeceased participants can exercise their options for a period not exceeding one yearfollowing death.
*Stock Options Granted During the Most Recently Completed Financial Year*
The following table discloses the grants of options to purchase oracquire shares of common stock to our executive officers during the fiscal year endedDecember 31, 2001. All monetary amounts are in Canadian dollars.
**Option Grants During Fiscal Year Ended December 31, 2001****Number of****% of Total****Securities****Options****Unexercised****Under****Granted to****options at****Options****Employees in****Exercise****December 31,****Granted****FY Ended****Price****2001****Expiration****Name****(#)****Dec. 31, 2001****($/share)****(#)****Date**Reg J. Greenslade144,00014.5%$ 4.00144,000Nov 1-2006Trevor Spagrud100,00010.1%$ 4.00100,000Nov 1-2006Luc Chartrand72,5007.3%$ 4.0072,500Nov 1-2006
A total of 990,000 options were granted by Enterra during the fiscalyear ended December 31, 2001.
*Aggregated Option Exercises During the Most Recently Completed Financial Year andFinancial Year End Option Values*
The following table sets forth the aggregate of options exercised byour executive officers during the year ended December 31, 2001 and the December 31, 2001year-end values for options granted to the executive officers. All monetary amounts are inCanadian dollars.
**Value of****Unexercised****in-the-Money Options****Unexercised****at FY-End****Options at FY-End****Exercisable/****Securities****Aggregate Value****Exercisable/****Unexercisable ($)****Name****Exercised (#)****Realized ($)****Unexercisable (#)****(1)**Reg J. GreensladeNilNil144,000
Nil/NilTrevor SpagrudNilNil100,000
Nil/NilLuc ChartrandNilNil72,500
Nil/Nil
(1) The closing price of our shares of common stock on the TSX Venture  Exchange on the last trading day in December, 2001 was $3.00.
** 

ITEM 7. Major Shareholders and Related Party Transactions

Major Shareholders

PRINCIPAL STOCKHOLDERS

The following table sets forth information regarding beneficialownership 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 ownedbecause an individual has the right to acquire the shares of common stock within 60 daysare treated as outstanding when determining the amount and percentage of common stockowned by that individual and by all directors and executive officers as a group.
**Number of**
**Shares****Percentage****Beneficially**
**of shares**
**owned****outstanding**Reg J. Greenslade (1)(2)322,7033.32Trevor Spagrud (1)(2)125,3461.29Luc Chartrand (1)(2)191,4671.97H.S. (Scobey) Hartley (1)(2)60,0000.62Walter Dawson (1)(2)459,7964.73Rick McHardy (1)(2)16,5241.07Thomas J. Jacobsen (1)(2)382,9470.17John P. McGrain (2)
549,200
5.65All directors and executive officers as a    group (eight persons) 2,107,983
21.70
__________

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.
**Related Party Transactions

Interest of Management and Others in Certain Transactions**
None of Enterra’s directors or executive officers, nor any personwho beneficially owns directly or indirectly or exercises control or direction oversecurities carrying more than 5% of the voting rights attaching to our shares of commonstock, 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 affectedEnterra, or in any proposed transaction which will materially affect Enterra, except asfollows:
**Acquisition of 759795 Alberta Ltd.**
In August, 1999, Enterra acquired 759795 Alberta Ltd. from Wells GrayResort & 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 theoil and gas interests and expertise of Wells Gray Resort & Resources Ltd., includingthe services of Thomas J. Jacobsen. 759795 Alberta also had the option to acquire any oiland gas acquisition offer made through Wells Gray Resort & Resources Ltd. 
**Private Placement**
Between September 27 and December 16, 1999 we issued an aggregate of1,175,000 shares of common stock at $1.00 per share as a private placement to 19 residentsof Alberta, Canada. Our directors and officers and their spouses purchased 665,000 sharesof common stock, being 57% of the private placement.
**Loans to Officers and Directors**
On February 16, 2000, Enterra loaned an aggregate of $390,000 to itsthen officers and directors to exercise outstanding stock options at $1.00 per share. Theloans were without interest, payable in full on or before December 31, 2000 and secured bythe stock purchased with the proceeds. The loans have all been repaid. The following tablesets out the names and positions with Enterra of the borrowers, the amount of the loansand the number of shares purchased with the proceeds.
**Loan Amount****Financially Assisted****Name and Principal Position****($)****Securities Purchased**Peter R. Sekera100,000100,000 common sharesPresident and CEO and DirectorEdward C. McFeely80,00080,000 common sharesExecutive VP, Engineering and DirectorThomas J. Jacobsen80,00080,000 common sharesExecutive VP, Operations and DirectorDale N. Fisher20,00020,000 common sharesFormer DirectorThomas S. Bamford20,00020,000 common sharesFormer DirectorLynn W. Thurlow50,00050,000 common sharesVP FinanceMarcia L. Johnston40,00040,000 common sharesSecretary**Private Stock Options**
John P. McGrain, holder of over 5% of our outstanding common stock, wasgranted options by Enterra’s officers and directors to purchase an aggregate of500,000 shares of common stock at a price of US $1.50 per share. The options were grantedMarch 15, 2000 and expired October 31, 2000. For administrative convenience, the sharesunderlying the options were transferred by the directors and officers into a holdingcompany, 855710 Alberta Ltd., which granted the options to Mr. McGrain. Prior to October31, 2000, Mr. McGrain had exercised all of the options to purchase 500,000 shares ofcommon stock, of which he retains 371,300 shares. 
**Private Loan**
On June 5, 2000, Enterra borrowed US$1,500,000 from six privateinvestors, including US$925,000 from Patrick Williams Advisors, a partnership, in whichJohn P. McGrain is a 50% partner. The lenders received interest at the rate of 12% perannum. Enterra also granted the lenders a set-up fee of US$50,000, of which PatrickWilliams Advisors received US$30,833. Enterra issued a total of 150,000 warrants to thelenders, 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 priceof US$4.00 per share.
**Private Placement**
During 2000 Enterra purchased 2,500,000 shares of common stock ofRaptor Capital Corporation plus warrants to purchase 1,250,000 Raptor shares at anexercise 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.
**Consulting Agreement**
Westlinks has entered into a Consulting Agreement with Wells GrayResort & Resources Ltd. in October 2000 that ended in April 2001. Under the contractThomas J. Jacobsen, the principal of Wells Gray Resort & Resources Ltd., was in chargeof Westlinks’ drilling, completion and equipping projects, for consulting fees of$8,333 per month.
**C. Interests of Experts and Counsel**
Not Applicable
**ITEM 8. Financial Information

A. Consolidated Financial Statements and Other Financial Information**
Pages F-1 to F-14.
**B. Significant Changes**
See "Management’s Discussion and Analysis of FinancialCondition and Results of Operations" and the attached consolidated financialstatements for a description of the Big Horn acquisition.
**ITEM 9. The Offer and Listing

A. Offer and Listing details**
Not Applicable, except for Item 9A (4).
**Price Range of Common Stock and Trading Markets**
Our shares of common stock commenced trading on the Canadian VentureExchange ("CVE") under the symbol "WLX" during the quarter endedSeptember 30, 1998. Our shares of common stock traded on the National Quotation Bureau'spink 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 NASDAQSmallCap Market. The shares currently trade under the symbol "EENC" on theNASDAQ 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 periodsshown.

**TSX Venture    Exchange (Cdn. $’s)**
**NASDAQ SmallCap    Market/Pink Sheets****(U.S. $’s)****Five most recent full fiscal years:****High**Low**High**LowYear ended December 31, 2001
7.50
2.30
4.81
1.65Year ended December 31, 2000
7.80
4.45
4.61
3.41Year ended December 31, 1999
1.05
0.41
n/a
n/aYear ended December 31, 1998
0.65
0.21
n/a
n/a**Year ended December 31, 2001:**Quarter ended December 31, 2001
3.75
2.30
2.39
1.65Quarter ended September 30, 2001
5.00
2.75
3.40
1.75Quarter ended June 30, 2001
6.45
4.70
4.25****************************************************************************************************************************************************************** |
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