SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB

[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

OR

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

For the transition period from to

Commission file number 333-39826

ENTERRA ENERGY CORP.

(Name of Small Business Issuer in Its Charter)

Alberta, Canada
                                                              
n/a

(State or Other Jurisdiction of
                                             
(I.R.S. Employer

Incorporation or Organization)
                                                     
Identification No.)

Suite 2600, 500  4th Avenue S.W.

Calgary, Alberta, Canada
                                                  
T2P 2V6

(Address of Principal Executive Offices)
                                         
(Zip Code)

Issuer's Telephone Number: 403/213-2502
Securities registered under Section 12(b) of the Exchange Act:

None

Securities registered under Section 12(g) of the Exchange Act:

Common Stock, $0.001 Par Value

(Title of class)

Check whether the issuer: (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports) and (2) has been subject to
such filing requirements for the past 90 days. Yes XNo

Check if no disclosure of delinquent filers in response to Item 405 of
Regulation S-B is contained in this form, and no disclosure will be contained, to the best
of registrant's knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [x]

The issuer's revenues for the most recent fiscal year were Cdn. $
25,746,000.

The aggregate market value of the voting and non-voting common equity
held by non-affiliates, based upon the average bid and asked prices of the Common Stock on
March 25, 2003 was Cdn. $ 45,912,000. Shares of Common Stock held by each officer and
director and by each person who owns 5% or more of the outstanding Common Stock have been
excluded in that such persons may be deemed to be affiliates. This determination of
affiliate status is not necessarily a conclusive determination for other purposes.

The number of shares outstanding of the issuer's Common Stock, as of
March 25, 2003 was 9,183,325.

ENTERRA ENERGY CORP.

Table of Contents

|PART 1                                                                                               | Page
|---------------------------------------------------------------------------------------------------- | ----
|Description of Business                                                                              | 3   
|Description of Property                                                                              | 15  
|Legal Proceedings                                                                                    | 15  
|Submission of Matters to a Vote of Security
    Holders                                              | 16  
|PART II                                                                                              |     
|Market for Common Equity and Related
    Stockholder Matters                                         | 16  
|Managements Discussion and Analysis or
    Plan of Operations                                       | 20  
|Consolidated Financial Statements                                                                    | 31  
|Changes and Disagreements With Accountants on
    Accounting and Financial Disclosure                | 32  
|PART III                                                                                             |     
|Directors, Executive Officers, Promoters and
    Control Persons                                     | 32  
|Compliance with Section 16(a) of the Exchange
    Act                                                | 35  
|Executive Compensation                                                                               | 35  
|Security Ownership of Certain Beneficial Owners and Management and
      Related Stockholder Matters | 37  
|Certain Relationships and Related Transactions                                                       | 44  
|Exhibits and Reports on Form 8-K                                                                     | 44  
|Controls and Procedures                                                                              | 45  

Exchange Rate Information

We publish our consolidated financial statements in Canadian dollars.
In this annual report, except where otherwise indicated, all dollar amounts are stated in
Canadian dollars. References to "$" or "C$" are to Canadian dollars
and references to "US$" are to U.S. dollars. The following table sets forth for
each period indicated the period end exchange rates for conversion of U.S. dollars to
Canadian dollars, the average exchange rates on the last day of each month during such
period and the high and low exchange rates during such period. These rates are based on
the noon buying rate in New York City, expressed in U.S. dollars, for cable transfers in
Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New
York. The exchange rates are presented as Canadian dollars per $1.00. On December 31,
2002, the noon buying rate was US$1.00 equals C$1.5769 and the inverse noon buying rate
was C$1.00 equals US$0.6344.

|                       | 2002   | 2001   | 2000   | 1999   | 1998   | 1997  
|---------------------- | ------ | ------ | ------ | ------ | ------ | ------
|End of period          | 0.6344 | 0.6285 | 0.6669 | 0.6918 | 0.6538 | 0.6996
|Average for the period | 0.6372 | 0.6456 | 0.6732 | 0.6691 | 0.6693 | 0.7207
|High during the period | 0.6656 | 0.6714 | 0.6969 | 0.6935 | 0.7124 | 0.7497
|Low during the period  | 0.6175 | 0.6227 | 0.6410 | 0.6464 | 0.6311 | 0.6938

WE ARE REQUIRED TO FILE REPORTS AND OTHER INFORMATION WITH THE SEC
UNDER THE SECURITIES EXCHANGE ACT OF 1934. REPORTS AND OTHER INFORMATION FILED BY US WITH
THE SEC MAY BE INSPECTED AND COPIED AT THE SEC'S PUBLIC REFERENCE FACILITIES DESCRIBED
ABOVE. AS A FOREIGN PRIVATE ISSUER, WE ARE EXEMPT FROM THE RULES UNDER THE EXCHANGE ACT
PRESCRIBING THE FURNISHING AND CONTENT OF PROXY STATEMENTS AND OUR OFFICERS, DIRECTORS AND
PRINCIPAL SHAREHOLDERS ARE EXEMPT FROM THE REPORTING AND SHORT-SWING PROFIT RECOVERY
PROVISIONS CONTAINED IN SECTION 16 OF THE EXCHANGE ACT. UNDER THE EXCHANGE ACT, AS A
FOREIGN PRIVATE ISSUER, WE ARE NOT REQUIRED TO PUBLISH FINANCIAL STATEMENTS AS FREQUENTLY
OR AS PROMPTLY AS UNITED STATES COMPANIES.

- 2 -



Item 1. Description of Business

BUSINESS

History

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

> 

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

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

Our Business

We are an operating oil and gas company that drills, acquires, operates
and exploits crude oil and natural gas wells in our core areas in Western Canada. Our
capital budget for 2003 is approximately C$25 million, subject to available funds,
earmarked for development and exploitation programs focused almost exclusively in Alberta,
Canada. The magnitude of our 2003 drilling program will depend on the results of our
analysis of seismic studies and the results of our previous drilling, and the development
of new opportunities as the year progresses.

Glossary of Petroleum Industry Terms

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

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

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

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

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

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

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

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

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



- 3 -

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

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

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

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

Business Strategy

As a result of the Big Horn acquisition a new management team is in
place at Enterra. Big Horns previous management was the surviving management group
following the August 1, 2001 Big Horn acquisition. Prior to 2001, Enterra (then known as
Westlinks) was an acquisition driven company. Big Horn, on the other hand, was a full
cycle oil and gas producer, focused on exploration and development. The new management at
Enterra was more focused in 2002 on its exploration, development and exploitation programs
than on corporate or property acquisitions. This strategy will continue in 2003.

Low Risk Development Projects

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

Consolidation of Adjacent Assets

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

Cost Effective Acquisitions

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

Emphasis on Development Drilling

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

Use of Seismic and Other Data in Site Selection

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

Selection of Properties

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

Properties

Enterra's core areas included the Peace River Arch area of Alberta,
Central Alberta and East Central Alberta. Enterra also has a large inventory of prospects,
the development of which could significantly increase the size of the Companys
existing production and reserve base. In accordance with the standard practice in the
Canadian oil and gas industry, the working interests described below are the percentage
ownership of the oil and gas production before payment of royalties.

-  4 -

PEACE RIVER ARCH OF ALBERTA

Clair

The Clair property is located 13 km north of the city of Grande
Prairie, Alberta. The Companys assets include a 100% working interest in 4,480 acres
of land, 21 producing oil wells and an oil treating facility. Gas is conserved and
processed at the Encana Sexsmith gas plant.

Production is primarily from the Dunvegan formation with a small amount
of gas production from the Charlie Lake and Halfway. Production is light, 44 degree API
gravity crude and solution gas is produced from one Dunvegan oil pool. There are currently
21 oil wells producing a combined 3300 bbls/d of oil and 1.8 mmcf/d of solution gas.
Enterra has plans to drill an additional twelve infill wells, three re-drills (due to
mechanical problems), and up to three (3) horizontal injection wells. All these wells are
expected to be drilled and on stream by April 1, 2003. The Company will be submitting a
water flood application shortly thereafter and will be prepared for 100% voidage
replacement when approval is granted by the AEUB.

One dually completed Charlie Lake and Halfway gas well located at
13-7-73-5W6 produces combined daily gas of 400 mcf/d. Enterra has a 100% working interest
in this well.

Total proved reserves assigned to the Dunvegan are 2,156 mbbls of oil,
1,685 mmcf of gas and 134 mbbls of natural gas liquids. Total proved and probable reserves
assigned to the Dunvegan are 3,806 mbbls of oil, 2,115 mmcf of gas and 169 mbbls of
natural gas liquids. The probable reserves category contains the incremental reserves and
net present value of the water flood. McDaniel and Associates have stated that the
additional reserves associated with the water flood would be moved into the proven
category in a staged approach. Critical stages include the EUB water flood approval,
commencement of injection, achievement of 100% voidage replacement and performance. Total
proved reserves assigned to the 13-07-073-5W6 Charlie Lake / Halfway gas well are 359.0
mmcf of gas and 7.18 mbbls of natural gas liquids. Total proved and probable reserves
assigned to the 13-07-073-5W6 Charlie Lake / Halfway gas well are 471.5 mmcf of gas and
9.43 mbbls of natural gas liquids.

Enterra owns and operates a central oil treating facility located at
6-18-73-5W6. Gas is also gathered at this facility and compressed to the Encana Sexsmith
Gas Plant. Gas transportation and processing fees equate to $0.56/mcf. Clean oil is
currently trucked to the La Glace Peace Pipeline Terminal. Trucking and terminal charges
are $2.00/bbl and $1.70/bbl, respectively. Enterra is in the process of getting the 6-18
battery directly connected to the Peace Pipeline. This is expected to be in place by June
2003. The Company will eliminate the trucking costs and terminal charges but the crude oil
will be subject to a $1.50/bbl pipeline fee (based on delivering 2500 bbls/d).

Worsley East

Enterra has an 87.5% working interest in 11.75 sections of land (two
licenses) in the Worsley East area. Enterra has licensed a Montney well at 5-5-87-6W6,
which will evaluate the Notikewin, Bluesky, Doig and Montney sands. The Bluesky is the
primary zone and is a nine meter thick blanket sand that has gas trapped in structural
highs. Bluesky gas wells in the immediate area include 8-1-87-7W6 and 14-15-87-6W6, which
have produced 1.9 Bcf and .66 Bcf of gas, respectively. Both wells have gas over water.
Enterra has two trade seismic lines and six proprietary seismic lines over the two
licenses.

A Doig channel is present to the north at 14-34-87-6W6 and has produced
2.8 Bcf. A Montney sand to the west at 15-5-87-7W6 has produced 1.2 Bcf. Enterra cannot
map a Doig channel or the Montney sand at the 5-5 location, however, by drilling 200
meters deeper we will evaluate both zones. The 5-5 location drilled to 1050 meters will
validate seven sections and drill through four potential zones. The Granite wash may also
be prospective. A well at 4-33-87-7W6 has produced 16 Bcf of gas from the Granite Wash at
a depth of 2300 meters. The 4-33 well is fault controlled with throws of greater than 140
meters. Seismic that Enterra has access to, shows basement faulting on Company land with
throws of approximately 70 m. The Company intends to re-evaluate the seismic for basement
faulting and then either acquire more 2D lines and/or shoot a 3D program over the leads.



-  5 -

Gordondale

The Gordondale property is located 75 km northwest of the city of
Grande Prairie, Alberta. The Companys assets include an average working interest of
79% in 6,240 gross acres of land as well as two flowing gas wells, a gas well awaiting tie
in and one oil well.

This exploration area is gas prone in up to eight formations ranging
from the Doe Creek at depths of less than 200 m to the Debolt formation at a depth of 2450
m. Enterra shot a 3-D seismic program over the area in 2001 and identified several
locations with multi zone potential. In early 2002, the first well was drilled,
encountering gas potential in the Kiskatinaw, Taylor Flats, Montney and Halfway
formations.

Production is currently from the Upper Kiskatinaw and Halfway zones.
The three producing wells located at 02/06-01-, 04-17-, and 12-17-79-11W6 were brought on
production in the latter half of 2002. The Companys share of current production for
the property is 667 mcf/d of gas, 8.2 bbl/d of oil and 7.6 bbl/d of natural gas liquids.
The forecast of the Companys share of production from these three wells for 2003,
total proved case, is 521 mcf/d of gas, 19.5 bbl/d of oil and 8.4 bbl/d of natural gas
liquids. A fourth well, 03/07-16-79-11W6, is currently awaiting tie-in and is forecast to
produce 110 mcf/d gas and 1.9 bbl/d natural gas liquids for the final nine months of 2003
(total proved, Company share).

McDaniel and Associates have assigned total proved reserves to
Gordondale of 659.1 mmcf of gas, 24.52 mbbls of oil and 11.2 mbbls of natural liquids.
Probable reserves were 909.3 mmcf of gas, 33.67 mbbls of oil and 15.45 mbbls of natural
gas liquids.

There are several Halfway Pools in the Gordondale area and Enterra has
Halfway wells at 7-16-79-11W6, 4-17-79-11W6, and Halfway gas behind casing at
12-17-79-11W6 which is currently producing from the Upper Kiskatinaw zone. Enterraswell at 12-17-79-11W6 has 30 meters of gas charged Montney and 9 meters of net gas pay
similar to Encanas well at 7-34-78-11W6. Two meters were perforated and fraced in
Encanas well with initial deliverability exceeding 3.5 mmcf/d. The Montney at
7-34-78-11W6 and in the surrounding area, responds as a low permeability sand, which has
produced .4 Bcf and is still producing at 600 mcf/d. Two meters of potential gas pay
exists at 2196 2198m in Enterras 12-17-79-11W6 well. Enterra plans to complete
the Taylor Flat zone prior to perforating the Montney.

Enterra has two producing Upper Kiskatinaw gas wells at 6-1-79-11W6,
and 12-17-79-11W6 and one bypass Upper Kiskatinaw gas well at 10-20-79-11W6. Seismic
interpretation of 3D and 2D, have identified anomalies in the northeast corner of 16, the
southwest corner of 17, and in the northwest corner of section 20. Gas production from
12-17-79-11W6 is tied into a CNRL Pouce Coupe Gas Plant located at 11-19-79-11W6. All
other gas that is currently tied in (6-1-79-11W6) is processed at the Duke Midstream
Gordondale West Gas Plant located at 11-26-79-9W6. Oil production from 4-17-079-11W6 is
produced to on site tankage and trucked away for treating.

Rolla

The Rolla property is located 70 km north of the city of Grande
Prairie, Alberta. The Companys assets include a 50% working interest in 1,920 acres
of land, 3 operated producing gas wells and a 12.5% working interest in two field
compressors.

Current gas production is approximately 1 mmcf/d from three Dunvegan
gas wells. Enterra has identified two development opportunities in section 15-78-7W6 and
section 22-78-7W6. 8-15-78-7W6 has 5m of bypass Gething gas pay at 1320 1325m. The
Gething interval has greater than 18% porosity and 50 ohms resistivity, these are better
than the key well at 12-13-78-8W6, which has produced 3.5Bcf of gas. Upon completion, the
field Engineer reported extremely poor cement bond over the Gething zone to the Calgary
office and was told to go ahead and perforate the Gething. Water was recovered after
perforating and the Gething zone was abandoned. Section 22-78-7W6 is prospective for
Baldonnel gas. 8-16-78-7W6 an abandoned well, produced Baldonnel gas at 2mmcf/d before
watering out.

Total proved reserves assigned to the Dunvegan are 1213.0 mmcf of gas
and total proved and probable reserves assigned to the Dunvegan are 1414.8 mmcf of gas.
All of the proved reserves are in the proved producing category. The Dunvegan sand
development in the Rolla area is part of a large Delta complex from the northwest.
Enterras land, which consists of three sections is developed with three producing
gas wells. Enterra has a 12.5% working interest in two compressors located at 8-9-79-7W6.
Gas is compressed from this location into the Duke Midstream operated Gordondale East Gas
Plant.

-  6 -

EAST CENTRAL ALBERTA

Sounding Lake

The Sounding Lake package is located 10 km southwest of the town of
Provost, Alberta. The Companys assets include an average working interest of 67.5%
in 5,316 gross acres of land as well as 48 producing oil wells and 2 producing gas wells.

Production is obtained primarily from the Dina, Cummings and Belly
River formations. The three main oil pools are Sounding Lake West, Sounding Lake East, and
Sounding Lake North. The Companys share of current production for the entire area is
700 bbls/d of oil and 1,600 mcf/d of gas. Enterra completed an optimization program in the
Sounding Lake area in mid 2002 by commingling the Dina and Cummings production where
applicable, upgrading pump sizes to maximize oil production and upgrading oil batteries to
handle higher volumes of total fluid and injection water.

The Company has budgeted several more capital projects for 2003 that
are expected to add up to 320 bbls/d of oil and 300 mcf/d of associated gas production.
These projects includes six infill drilling locations at Sounding Lake North. All of the
wells are defined from geological mapping and 3-D seismic. Enterra was assigned proved
reserves at Sounding Lake of 1,115.8 mbbl of oil and 1,393.8 mmcf of natural gas. In
recognition of the Companys 2002 optimization program in the area, probable reserves
were also assigned for an expected performance enhancement.

Total proved and probable reserves are 1,372.8 mbbl oil and 1,597.6
mmcf natural gas.

Enterra has budgeted $900,000 for the drilling of six wells at Sounding
Lake North and $240,000 (gross) for the tie in of solution gas at Sounding Lake West and
East. Enterra operates a central oil treating battery at both Sounding Lake West
(11-27-37-4W4; 50.7% working interest) and Sounding Lake East (05-31-037-3W4; 100% working
interest). These facilities were recently optimized to handle larger volumes of produced
water resulting from the 2002 optimization program. Both of these areas are also equipped
water injection facilities.

At Sounding Lake North, all of the production is gathered to a central
location, where it is metered and flowlined to a major nearby oil treatment facility
operated by Calpine Canada. Enterra owns a 3-D seismic program over the Sounding Lake
North field. This 3-D seismic was recently used to identify six infill drilling locations
for 2003. The company controls a large percentage of the mature Dina PPP and T4T pools at
Sounding Lake East and West. The Dina Reservoir is a braided marine sand bar type. With
numerous stacked bar sands in succession surrounded and trapped by intermittent shales and
regionally tight non-channel Dina facies. Average net pay per well is 4-5m, with good
porosities of around 26%. The Lloydminster formation is of reservoir quality though no
evidence of hydrocarbon trapping has been found within the Company lands. Enterras
land at Sounding Lake North consists of a number of oil producing Mannville sands. The
Dina formation is locally productive from the braided fluvial bar type sands, as well as
well developed extra-fluvial sands in the regional facies. The Cummings formation is a
regionally developed near marine sand that is locally cut by a later time channel event
causing traps to form and large volumes of oil to accumulate. Development potential also
occurs in the Lloydminster, which pinches out trapping oil to the northwest, as well as a
thick Rex channel that cuts through the lands.

CENTRAL ALBERTA

Sylvan Lake

The property currently produces 300 bbls/d (gross), 225 bbls/day (net)
of 16 degree API oil from 7 wells. Production is gathered at individual well sites and
trucked to third party facilities for treating. In conjunction with Enterras plan to
drill infill wells at 40 acre spacing is the installation of a Company owned and operated
oil treating facility which will substantially drop operating expenses. Infill wells are
expected to average initial deliverability of 75 bbls/d per well.

McDaniel and Associates has assigned total proved reserves of 514.33
mbbls of oil and 96.8 mmcf of non-associated gas. Total proved and probable reserves are
811.66 mbbls of oil and 157.0 mmcf of non-associated gas. Probable reserves were assigned
based on an assumption that the wells will achieve a slightly higher oil recovery than
estimated. Non-associated gas volumes are assigned to the 13-21-038-02W5 Viking gas well
that produces into the nearby Husky operated Sylvan Lake Gas Plant. Enterra is planning to
down space the Sylvan Lake Pekisko to 10 acres, depending on the success of the 40 acre
infill program. This reservoir has net pays up to 40 m (130 ft). Enterra owns a 3-D
seismic program that covers the Sylvan Lake Pekisko G pool.



-  7 -

Kaybob

The Kaybob 12-14-058-17W5 horizontal oil well is capable of producing
in excess of 500 bbls/d of light crude oil and 0.5 mmcf/d of associated gas. The well is
currently shut in until June 2003 as the gathering system, operated by Chevron Canada, is
undergoing intensive corrosion inspection and repair. Because of this unscheduled and
lengthy downtime, Enterra has taken the opportunity to conduct a cement squeeze operation
in the structurally low and wet heel area of the horizontal. The cement squeeze operation
will be tested in June 2003 but should be effective in eliminating any produced water.

McDaniel and Associates have assigned total proved reserves to the
12-14-058-17W5 horizontal oil well of 513.58 mbbls of oil, 654.8 mmcf of gas and 13.09
mbbls of natural gas liquids. Total proved and probable reserves are 698.78 mbbls of oil,
890.90 mmcf of gas and 17.82 mbbls of natural gas liquids. Enterra acquired its interest
in the Kaybob South Nisku C Pool in the year 2000. This property is located 50 kilometers
north of Edson, Alberta and is pipeline connected to a major gas and oil processing
facility in the area. Reef production stopped in 1995 after a single, vertical well at
6-14-58-17W5, watered out after producing 400,000 bbls of oil. Although the vertical
producer watered out when produced at commercial quantities, at rates less than 30 bbls/d
the well continued to produce clean oil. Enterra acquired and reprocessed a 3-D seismic
program covering the entire reef. The new interpretation indicated that reef porosity grew
at least 7 meters higher than the porosity encountered in the vertical well. This was a
strong indicator that significant quantities of attic oil reserves remained in the
structurally higher portion of the reef. To exploit these reserves with the highest
possible recovery factor, Enterra drilled a horizontal well accessing the top of the reef.
This operation was conducted in early 2001 and was executed by kicking out of the existing
vertical producer. Horizontal drilling was terminated approximately 340 m from the
vertical well with a gain in porosity structure of 7 m. The 12-14-58-17W5 Hz well was
deliverability tested in June 2001. Results of this test indicated the well would
initially be produced into the flowline at a restricted rate of 500 bbls/d with a 30%
water cut.

Early in 2002, Chevron Canada notified Enterra that third party
production, utilizing their gathering system, would be shut in due to corrosion identified
from pipeline inspection. Although this corrosion was not from Enterras production
Chevron wanted to eliminate the possibility of third parties having responsibility for any
failures that could have resulted. Chevron also notified The Company that the earliest it
could bring its production back on line is in June 2003, after a major turnaround at the
Chevron K3 Gas Plant. Chevron has planned a significant gathering system inspection and
repair program during this turnaround. Despite continued efforts to bring the well back on
stream, Chevron has insisted that the earliest this would occur will be after the
gathering system, that Enterra uses, gets inspected and repaired in May 2003.

Realizing that the Kaybob 12-14 Hz well will be shut in for an extended
duration prompted Enterra to design a workover to eliminate the water production.
Decreasing the water cut would allow the well to flow at higher pressures and it would
also reduce operating costs. The Company conducted a successful, bull head cement squeeze
operation on August 10, 2002, which was designed to place a cement plug across the
structurally low heel of the horizontal. Unfortunately, Enterra is not able to evaluate
the decrease in water cut until the gathering system becomes operational in June 2003.
Enterra owns a 90% working interest in 320 acres of land, subject to a 7.5% NCORR on 100%
of production. The Company has a licensed copy of a 7 square mile 3-D program over the
12-14 horizontal well and adjacent lands.

OHER PROPERTIES

Bindloss

Enterra selectively fracture stimulated up to five gas bearing sands in
the Milk River formation and one in the Medicine Hat. Although the clean up period for
this type of stimulation is longer due to greater quantities of water introduced into the
formations, the benefit is higher long term production and reserves. The Bindloss field is
currently producing 0.5 mmcf/d of gas during the cleanup phase of development. This phase
is dominated by stimulation water slowly flowing back into the wellbore. Water will
continue to restrict the true potential of each well until the majority of this fluid is
produced back. As the water starts to dissipate the gas rate in each well will increase
until its full potential is realized. Enterra expects the cleanup phase for the field to
last until June 2003.

Beyond this date, The Company expects each well to produce at an
average gas rate of 80 mmcf/d. Total field production is expected to peak at 2.3 mmcf/d
from 30 wells. Reserves currently assigned to Bindloss are total proved of 1, 230.0 mmcf
and total proved plus probable of 1888.3 mmcf. Enterra expects these values to
substantially increase as the wells unload water and gas rates accelerate. No capital will
be spent on additional drilling until such time as the current wells demonstrate their
true productivity potential. The second stage of development consists of the full cycle
development of an additional 30 gas wells for a total cost of $5.3MM. This project is
expected to start in Q3, 2003.

Enterra owns and operates the only compression, dehydration and
gathering system in the Bindloss area, north of the South Saskatchewan River. This will
undoubtedly be a source of revenue in the future as other operators will pay Enterra fees
for use of this infrastructure. Gas is compressed into the nearby Nova gas pipeline
system. Medicine Hat and Milk River Formations blanket the area in thick interlaminated
and interbedded sandstones, siltstones and shales. Net pay is determined by a gas neutron
log response and gamma ray log cleanliness. Enterra acquired a shut in Waseca oil pool in
Southwest Saskatchewan for $2.8 million in June of 2001. The Company equipped and
reactivated four existing producers. Combined gross production from these wells is 250
bbls/day. Late in 2001, Enterra added four Waseca infill oil wells.



-  8 -

Deer Mountain

Enterra has a 50%, non-operated, working interest in the 10-24-70-12W5
well. Producing from a westward extension of the Beaver Hill Lake C Pool, 10-24
consistently achieves its maximum rate limitation (MRL) of 63 bbls/d (10 m3/d) each month.
Production is flat due to pressure support from the Beaver Hill Lake C Pool water flood.
Total proved reserves are 106.62 mbbls of oil and total proved and probable reserves are
128.31 mbbls of oil. Enterra has also purchased a 100% working interest in the south half
of section 24 by way of a crown land sale. Two potential infill drilling locations are
present on these lands at 160 acre spacing. These lands were not evaluated for potential
by McDaniel and Associates. Enterra also bid unsuccessfully on the NW/4 of Sec 24.

Ricinus

The Ricinus D3-A Pool is located approximately 80 kilometres west of
Red Deer, 24 kilometres south of the Keyspan Strachan Gas Plant. The pool encompasses
sections 17, 18 and 19 of land located in Township 35, Range 8 and section 24 in Township
35 Range 9 W5M. The Ricinus D3-A Pool contains approximately 6,957 E6m3 (245.7
BCF) of Original Gas In-Place. Currently the pool is abandoned, having removed only 43% of
the Original Gas In-Place. The pool resides in the Ricinus Reef Complex; whereby the other
analogous pools in the area have achieved gas recoveries averaging 75% and are still
producing.

An engineering feasibility study has been conducted on the Ricinus D3-A
Pool with positive economic results. The results indicate approximately 22 BCF of sales
gas and 62,000 bbls of natural gas liquids can be further recovered. This is a
conservative recovery value based off a reservoir model with no attic gas. The reservoir
gas is subject to a shrinkage of approximately 35% due to the acid gas content, and 10.16
m3/Em3 (1.8 bbls/mmcf) of natural gas condensate is liberated when
processed. These recovery values are based on a new well completed into the uppermost
section of the D3-A zone (4 metres penetration) with an offset of 250 metres from the
existing 11-17-35-8W5M wellbore. This infill location follows the analogous pools
production practices. The production profile for the proposed well is a sustained rate of
11 mmcf/d until 2011; at this time the well experiences water break-through and is
shut-in. Sensitivities were conducted on offset distance from the 11-17 well bore, depth
of penetration into the D3-A zone, potential structural lows, production rate, and cross
flow within the original well bores. Confidence in the reserve value is rated as very high
due to the production performance and the simulation model.

NEW PROSPECTS

One of Enterras most valuable asset is its inventory of future
projects. The development of these prospects has the potential to significantly increase
the size of the Companys existing production and reserve base. New prospects are
constantly added to our inventory in order to maintain our growth from year to year. The
Companys strategy is to maintain a balanced inventory of exploration and development
prospects.

Reserves and Present Value Summary

The estimated oil and natural gas reserves of Enterra and the
associated estimated present value of estimated future net cash flows have been evaluated
in a report as of January 1, 2003 prepared by McDaniel & Associates Consultants Ltd.
("McDaniel"), independent petroleum engineers of Calgary, Alberta.



-  9 -

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

Enterra Energy Corp.

Estimated Petroleum and Natural Gas Reserves and Net Present Value

January 1, 2003

|                               |             |             |         
|------------------------------ | ----------- | ----------- | --------
|                               | Oil & NGLs | Natural Gas | NPV     
|                               | Gross       | Net         | Gross   
|                               | Mstb        | Mtsb        | MMcf    
|Proved Developed               | 4,442.7     | 3,615.3     | 10,929.6
|Proved Developed Non-Producing | 77.8        | 51.9        | 1,531.6 
|Proved Undeveloped             | 1,282.5     | 943.6       | 825.8   
|Total Proved                   | 5,803.0     | 4,610.8     | 13,287.0

__________

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
actual field prices in effect at December 31, 2002. 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) | $31.23 |  | Propane                        | $26.20
|Edmonton Light Crude (C$/bbl)     | $49.78 |  | Field butane                   | $29.00
|Bow River Medium Crude (C$/bbl)   | $41.00 |  | NGL mix                        | $31.12
|Hardisty Heavy (C$/bbl)           | $34.00 |  | Natural Gasolines & Condensate | $46.82
|                                  |        |  |                                |       
|Natural Gas (C$/Mmbtu)            |        |  |                                |       
|Alberta Average                   | $5.20  |  |                                |       
|Transcanada Gas Services Ltd.     | $5.19  |  |                                |       
|Pan Alberta Gas Ltd.              | $4.51  |  |                                |       
|Progas                            | $5.36  |  |                                |       
|Spot Sales                        | $5.82  |  |                                |       
|Saskatchewan Average              | $5.06  |  |                                |       
|Can West Plant Gate (B.C.)        | $4.24  |  |                                |       

Historical Reserves

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

|                           | December 31,
|-------------------------- | ------------
|                           | 2002        
|Proved Producing Reserves: |             
|Oil and NGLs (mbbls)      | 4,443       
|Gas (mmcf)                 | 10,930      
|                           |             
|Proved Reserves:           |             
|Oil and NGLs (mbbls)      | 5,803       
|Gas (mmcf)                 | 13,287      

Land Holdings

At December 31 Enterra had the following land holdings

|                        | 2002   | 2001  
|----------------------- | ------ | ------
|Developed acres (net)   | 28,355 | 22,646
|Undeveloped acres (net) | 51,581 | 58,590
|Total acres (net)       | 79,936 | 81,236
|                        |        |       



-  11

Production

The following table summarizes Enterras working interest
production during the periods indicated:

|                            | Years ended December 31,
|--------------------------- | ------------------------
|                            | 2002                    
|Oil and NGLs (MBbls)       | 533                     
|Gas (MMcf)                  | 1,882                   
|Total (MBOE)                | 847                     
|Average Production in BOEPD | 2,320                   

Definitions:

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

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

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

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

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

Drilling

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

|              | 2002        | 2001        | 2000        | 1998       
|------------- | ----------- | ----------- | ----------- | -----------
|Wells drilled | Gross (Net) | Gross (Net) | Gross (Net) | Gross (Net)
|              |             |             |             |            
|Oil           | 25 (23.7)   | 9 (4.97)    | 9 (8.26)    | 0 (0.00)   
|Natural Gas   | 37 (34.0)   | 8 (3.78)    | 2 (1.27)    | 0 (0.00)   
|Abandoned     | 0 (00.0)    | 3 (1.84)    | 2 (1.14)    | 1 (0.13)   
|Total         | 62 (57.7)   | 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 Enterra
during the periods indicated, expressed in Canadian dollars:

|                                       | Years ended
    December 31,
|-------------------------------------- | ----------------------------
|                                       | 2002                        
|                                       | (In
    thousands)         
|Property acquisitions (net)            | $ 383                       
|Drilling (exploration and development) | 21,090                      
|Facilities                             | 9,347                       
|Miscellaneous                          | 235                         
|Total                                  | $ 30,289                    



-  12-

Oil and Gas Wells

The following table summarizes Enterras interest in producing and
non-producing oil and gas wells as at December 31, 2002 :

|PROPERTY            |  | PRODUCING | PRODUCING | PRODUCING | PRODUCING
|------------------- |  | --------- | --------- | --------- | ---------
|                    |  | OIL WELLS | OIL WELLS | GAS WELLS | GAS WELLS
|                    |  | GROSS     | NET       | GROSS     | NET      
|                    |  |           |           |           |          
|Saddle Hills        |  | -         | -         | 5         | 1.77     
|Highvale            |  | -         | -         | 2         | 0.75     
|West Gull Lake      |  | 4         | 3.60      | -         | -        
|Hazlet Unit         |  | 8         | 1.60      | -         | -        
|Lanaway             |  | 6         | 2.68      | 9         | 3.56     
|Leduc               |  | 1         | 0.39      | -         | -        
|Crossfield          |  | -         | -         | 6         | 0.16     
|Cygnet              |  | -         | -         | 2         | 1.50     
|Deanne              |  | -         | -         | 2         | 0.20     
|Garden Plains       |  | -         | -         | 1         | 0.62     
|Gilby               |  | -         | -         | 1         | 0.39     
|Leedale             |  | -         | -         | 1         | 0.02     
|Lubicon             |  | 1         | 0.23      | -         | -        
|Progress            |  | -         | -         | 1         | 0.50     
|Sinclair            |  | -         | -         | 1         | 0.44     
|Webster             |  | -         | -         | 1         | 0.25     
|St. Anne            |  | -         | -         | 2         | 1.22     
|Willesden Green     |  | -         | -         | 1         | 0.43     
|Worsley             |  | 2         | 1.50      | -         | -        
|Mitsue              |  | 8         | 8.00      | -         | -        
|Timber Draw         |  | 1         | 0.15      | -         | -        
|Sounding Lake East  |  | 16        | 15.50     | -         | -        
|Sounding Lake West  |  | 55        | 27.50     | -         | -        
|Sounding Lake North |  | 22        | 6.92      | -         | -        
|Sylvan Lake         |  | 13        | 11.75     | 1         | 0.32     
|Clair               |  | 21        | 21.00     | 5         | 5.00     
|Bindloss            |  | -         | -         | 25        | 25.00    
|Gordondale          |  | 1         | 0.50      | 2         | 1.00     
|Rolla               |  | -         | -         | 2         | 1.00     
|Superb              |  | 9         | 6.12      | -         | -        
|Swan Hills          |  | 1         | 0.50      | -         | -        
|Campbell            |  | 1         | 0.12      | -         | -        
|                    |  |           |           |           |          
|TOTAL WELLS         |  | 170       | 108.06    | 70        | 44.13    

Employees

At December 31, 2002 the Company had approximately thirty employees and
consultants working both in the Calgary head office and in its field operations.

Competition

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



-  13-

Government Regulation in Canada

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

Pricing and Marketing  Oil and Natural Gas

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

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

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

Provincial Royalties and Incentives

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

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



-  14-

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

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

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

Land Tenure

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

Environmental Regulation

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

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

Item 2. Description of Property

Office Facilities

Enterra currently leases 10,450 square feet of office space at Suite
2600, 500 - 4th Avenue S.W. in Calgary, Alberta in a lease that commenced November 1,
2001. The lease has a three-year term (expiring on November 30, 2004) and the annual
rental is currently C$28.39 per square foot (including operating costs and property
taxes).

Item 3. Legal Proceedings

The Company is not a party to any other pending legal proceedings that
management believes could have a material adverse effect on its financial position. There
can be no assurance, however, that third parties will not assert infringement or other
claims against us in the future, which, regardless of the outcome, could have an adverse
impact on the Company as a result of defense costs, diversion of management resources and
other factors.

-  15-

Item 4. Submission of Matters To a Vote of Security Holders

There have been no matters submitted to a vote of security holders
during the fourth quarter of the year ended December 31, 2002.



PART II

Item 5. Market For Common Equity and Related Stockholder Matters



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



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, 2002
    11.50
    2.60
    7.50
    1.47Year 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/aYear ended December 31, 2002:Quarter ended December 31, 2002
    11.50
    6.00
    7.50
    3.80Quarter ended September 30, 2002
    6.45
    4.6
    4.19
    2.95Quarter ended June 30, 2002
    5.49
    4.27
    3.48
    2.25Quarter ended March 31, 2002
    4.96
    2.60
    2.33
    1.47Year 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
    2.78Quarter ended March 31, 2001
    7.50
    5.00
    4.81
    3.22Year ended December 31, 2000:Quarter ended December 31, 2000
    7.80
    5.50
    5.15
    3.81Quarter ended September 30, 2000
    7.50
    6.50
    5.10
    3.50Quarter ended June 30, 2000
    7.05
    4.45
    4.79
    3.41Quarter ended March 31, 2000
    4.60
    4.45
    n/a
    n/aYear ended December 31, 1999:Quarter ended December 31, 1999
    1.05
    0.58
    n/a
    n/aQuarter ended September 30, 1999
    1.18
    0.41
    n/a
    n/aQuarter ended June 30, 1999
    1.70
    0.70
    n/a
    n/aQuarter ended March 31, 1999
    1.50
    0.50
    n/a
    n/aSix most recent calendar months:Month ended December 2001
    3.14
    2.30
    1.86
    1.65Month ended November 2001
    3.20
    2.68
    2.05
    1.72Month ended October 2001
    3.75
    2.80
    2.39
    1.78Month ended September 2001
    3.80
    2.75
    2.50
    1.75Month ended August 2001
    4.85
    3.30
    2.97
    2.36Month ended July 2001
    5.00
    5.00
    3.41
    2.75




-  16-

Number of Holders of Common Stock

At December 31, 2002 there were approximately 42 stockholders of record
of the Company's Common Stock. Based on information obtained from the Company's transfer
agent, the Company believes that the number of beneficial owners of its Common Stock is
approximately 1,517.

Dividends

The Company has never paid cash dividends on its Common Stock. The
Company currently intends to retain earnings for use in its business and, therefore, does
not anticipate paying cash dividends on its Common Stock in the foreseeable future.

Recent Sales of Unregistered Securities

None

Description of Securities

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

Common Stock

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

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

Normal Course Issuer Bid

Enterra filed a notice in August 2001 to purchase up to 5% of its
common shares for cancellation. Enterra had 5,673,639 issued and outstanding common shares
at the time. Enterra would buy back its common shares through the facilities of the NASDAQ
during the twelve month period commencing on August 20, 2001 and ending on August 20,
2002. Enterra repurchased 232,500 common shares during 2001 and 18,808 during 2002 under
this bid.

Preferred Stock

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

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

-  17-

Enterra issued 7,418,336 Series 1 preferred shares pursuant to the
acquisition of Big Horn.

On March 26, 2002 the Company purchased 6,123,870 of its Series 1
preferred shares for $2.3 million, resulting in a gain on redemption of $2,905,290. The
purchase was paid for with cash of $1,750,000 and a note payable of $550,000. This note
was repaid for $325,000 on August 15, 2002 resulting in an additional gain, net of legal
costs, of $206,181.

At December 31, 2002 there were 749,047 Series 1 preferred shares
outstanding (December 31, 2001  7,418,336). These shares are non-voting. They aretransferable. Subsequent to August 16, 2002 holders of these shares are entitled to
receive a fixed cumulative dividend of $0.085 per share per annum, payable quarterly.
These shares are redeemable at any time by the Company for $0.85 per share. Holders of
these shares may require the Company to redeem all or any of these shares, at $0.85 per
share. There is no market for these shares and none is expected to develop.

A dividend of $22,549 was paid on the preferred shares in 2002. This
amount is included in interest expense.

Warrants

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

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

 a stock dividend on the common stock;

 a subdivision of the common stock;

 a split of the common stock;

 a reorganization of the common stock

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

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

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

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

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

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



-  18-

Shares Eligible for Future Sale

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

Enterra currently has outstanding 9,183,325 shares of common stock,
assuming no exercise of outstanding warrants and options. These shares are freely
tradable, without restrictions imposed by applicable securities laws.

We intend to register the shares of our common stock issuable pursuant
to our stock option plan. At December 31, 2002 there were outstanding under the plan
options to purchase 871,703 shares, all of which would be eligible for immediate resale in
Canada, and in the United States by persons who are not affiliates of Enterra.

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

Memorandum and Articles of Association

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

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

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

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

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

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

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

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

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



-  19-

There are no:

> limitations on share ownership,
>   provisions of the Articles of Amalgamation or by-laws that would have
>   the effect of delaying, deferring or preventing a change of control of Enterra,
>   by-law provisions that govern the ownership threshold above which
>   shareholder ownership must be disclosed, and
>   conditions imposed by the Articles of Amalgamation or by-laws governing
>   changes in capital, but the governing legislation requires any changes to the terms of
>   share capital be approved at a meeting of the shareholders affected by the change by 66
>   2/3% of the shareholders represented by proxy or in person at such meeting.



Item 6. Management's Discussion and Analysis or Plan of Operation



SUMMARY CONSOLIDATED FINANCIAL DATA

The following table presents a summary of our consolidated statement of
operations derived from our financial statements for 2002, 2001, 2000 and 1999. The
monetary amounts in the table are based on Canadian general accounting principles
("Canadian GAAP"). The 2000 and 1999 results have been restated to reflect the
change in its method of accounting for petroleum and natural gas properties from the
"successful efforts" method to the "full costs" method. All data
presented below should be read in conjunction with the "Managements Discussion
and Analysis of Financial Condition and Results of Operations" and our financial
statements and accompanying notes included elsewhere in this Form 10-KSB .



Consolidated statements of operations data:



|(In thousands, except per share
    data) |          |          |          |         
|------------------------------------------ | -------- | -------- | -------- | --------
|                                           | 2002     | 2001     | 2000     | 1999    
|                                           | C$       | C$       | C$       | C$      
|Net revenue                                | $ 25,746 | $ 20,264 | $ 16,700 | $ 2,515 
|                                           |          |          |          |         
|Royalties, net of ARTC                     | 4,203    | 3,182    | 3,310    | 442     
|Production expenses                        | 6,018    | 5,830    | 4,030    | 782     
|General and administrative expenses        | 1,683    | 565      | 1,391    | 863     
|Interest                                   | 1,236    | 589      | 833      | 132     
|Amortization of deferred charges           | 391      | -        | -        | -       
|Depreciation and depletion                 | 9,306    | 6,870    | 2,960    | 705     
|                                           | 22,837   | 17,036   | 12,524   | 2,924   
|Earnings (loss) from operations            | $ 2,909  | $ 3,228  | $ 4,175  | ($ 408) 
|Net earnings (loss) for the year           | $ 4,977  | $ 1,617  | $ 2,453  | ($ 249) 
|Basic earnings (loss) per share            | $ 0.54   | $ 0.23   | $ 0.55   | ($ 0.10)

The following table indicates a summary of our consolidated balance
sheets as of December 31, 2002, 2001 and 2000. The monetary amounts in the table are based
on Canadian GAAP. The 2000 results have been restated to reflect the change 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)                  |        
|-------------------------------- | -------
|                                 | 2002   
|                                 | C$     
|Cash and short term investments  | $ 108  
|Accounts receivable and prepaids | 7,971  
|Capital assets                   | 94,354 
|Total assets                     | 102,717
|Total stockholders equity       | 38,663 



-  20-

Quarterly information:

|(In thousands, except per share
    data) |                 |                |                     |                   
|------------------------------------------ | --------------- | -------------- | ------------------- | ------------------
|                                           | Q1
    March 31 | Q2
    June 30 | Q3
    September 30 | Q4
    December 31
|                                           | C$              | C$             | C$                  | C$                
|Year 2002                                  |                 |                |                     |                   
|Revenue                                    | $ 5,598         | $ 5,051        | $ 5,036             | $ 10,060          
|                                           |                 |                |                     |                   
|Income from operations                     | $ 326           | $ 620          | $ 854               | $ 1, 109          
|Per share, basic                           | $ 0.04          | $ 0.07         | $ 0.09              | $ 0.12            
|Per share, diluted                         | $ 0.04          | $ 0.07         | $ 0.09              | $ 0.11            
|                                           |                 |                |                     |                   
|Net earnings                               | $ 3,150         | $ 398          | $ 714               | $ 715             
|Per share, basic                           | $ 0.34          | $ 0.04         | $ 0.08              | $ 0.08            
|Per share, diluted                         | $ 0.34          | $ 0.04         | $ 0.08              | $ 0.07            
|                                           |                 |                |                     |                   
|Year 2001                                  |                 |                |                     |                   
|Revenue                                    | $ 4,288         | $ 4,670        | $ 6,326             | $ 4,980           
|                                           |                 |                |                     |                   
|Income from operations                     | $ 946           | $ 1,497        | $ 991               | ($206)            
|Per share, basic                           | $ 0.17          | $ 0.26         | $ 0.13              | ($ 0.21)          
|Per share, diluted                         | $ 0.17          | $ 0.26         | $ 0.13              | ($ 0.21)          
|                                           |                 |                |                     |                   
|Net earnings                               | $ 610           | $ 470          | $ 648               | ($ 111)           
|Per share, basic                           | $ 0.11          | $ 0.08         | $ 0.09              | ($ 0.05)          
|Per share, diluted                         | $ 0.11          | $ 0.08         | $ 0.09              | ($ 0.05)          

Cautionary Note Regarding Forward-Looking Statements



The following discussion of our results of operations and financial
condition should be read in conjunction with the consolidated financial statements and
other financial information included in this annual report. The statements that relate to
matters that are not historical facts are "forward-looking statements" within
the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Words such as "anticipate",
"believe", "expect", "plan", "intend",
"estimate", "project", "will", "should"
"could", "may", "predict" and similar expressions are
intended to identify forward-looking statements. Future events and actual results may
differ materially from the results set forth in or implied in the forward-looking
statements. Factors that might cause such a difference such as those discussed under
"Risk factors" and elsewhere, include:

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

The following discussion is to inform you about our financial
conditions, liquidity and capital resources as of December 31, 2002 and 2001 and the
results of operations for the years ended December 31, 2002 and 2001. The information is
expressed in Canadian dollars.



-  21-

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Financial Condition, Liquidity and Capital Resources

At December 31, 2002 Enterras working capital was a deficit of
$37.98 million (2001 - $2.2 million). Included as part of current liabilities at December
31, 2002 is bank debt of $24.3 million (2001 - NIL). The Companys bank debt now
appears on our balance sheets as a current liability. This same bank debt was classified
as a long-term liability at December 31, 2001. Nothing has changed with the nature or the
terms of our banking arrangement with our lender. The reclassification of our bank debt
from long-term liability to current liability is the result of new Canadian accounting
rules which came into effect January 1, 2002. These rules specify that all borrowings
where, among other things, the lender has a right to demand repayment within 12 months
(which is the case with our revolving production facility) are to be classified as current
liabilities. We are not subject to principal repayments under our banking arrangement.
Other than in the event of a default or a breach of covenants, our lender has advised us
that no principal payments are required in 2002.

Cash flow from operations was $11.95 million in 2002 (2001 - $9.81
million) . The increase was largely due to the added production as a result of the Clair
project, which came on near the end of the year, and to a slightly better pricing
environment in 2002. Average commodity prices during 2002 were $30.41 per boe compared to
$29.14 per boe in 2001.

During the year ended December 31, 2002 there was an increase in
non-cash working capital of $10.57 million compared to a decrease in non-cash working
capital of $0.48 million in 2001. The 2002 increase was the direct result of the
accelerated drilling activity in November and December of 2002, which resulted in higher
accounts payables and accrued liabilities at the end of 2002.

Financing Activities

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

Enterras bank debt at December 31, 2002 was $24.3 million (2001 -
$18.4 million). In both periods the funds were used to acquire capital assets and support
ongoing operations. At December 31, 2002 Enterras bank facility consisted of a line
of credit of $26.7 million (of which $24.4 was drawn). Interest on amounts drawn is based
on the banks prime rate plus 0.25%.

Security is provided by a first charge over all of the Companys
assets. While the loan is repayable on demand, Enterra is not subject to scheduled
repayments. The lender has advised the Company that, subject to annual review of the
borrowing base and the Company continuing to comply with the terms of the loan agreement,
no payments will be required in 2002.



> 

In the second quarter of 2002, the Company sold its Grand Forks
property for $5.3 million. Proceeds from this sale were used to reduce our bank debt and
to repurchase some of the preferred shares. The preferred shares were redeemed for $2.3
million, paid for with cash of $1.75 million and a note of $550,000. On August 15, 2002
the note was settled for $325,000, resulting in a gain of $206,181 net of related legal
costs.

The Company has in excess of $60 million in tax pools available at
December 31, 2002.



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

-  22-

Effective August 1, 2001, Enterra acquired 100% of Big Horn for cash of
$2.2 million (not including acquisition costs) and the issuance of 3,496,436 common shares
and 7,418,336 preferred shares. Enterra has also repurchased, through its previously
announced share buyback program, 232,500 of its common shares during 2001.

The Companys total debt, including working capital deficiency and
preferred shares, at December 31, 2002 was $42.7 million (December 31, 2001 - $26.9
million).

Investing Activities

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

Capital expenditures for the year ended December 31, 2002 were $35.88
million (2001 - $14.96 million). Drilling activity was minimal in the first ten months of
2002 but increased substantially in November and December. Almost $20 million was spent in
the fourth quarter of 2002, representing over 50% of the entire 2002 capital expenditures.

The Company drilled 62 (57.7 net) wells in 2002, resulting in 25 (23.7
net) oil wells and 37 (34.0 net) gas wells. Only 8 wells were drilled in the first nine
months of 2002. The remaining 54 wells (87% of total wells drilled in 2002) were all
drilled in the fourth quarter of 2002.

Proceeds on disposal of oil and gas properties were $5.8 million in
2002 (2001 - $1.7 million). These proceeds relate almost exclusively to the sale of the
Grand Forks properties, which occurred in the second quarter of 2002 and which accounted
for $5.3 million of the total proceeds.

Results of Operations

Gross revenue for the year ended December 31, 2002 was $25.7 million
(2001 - $20.3 million) for a 27% increase. Production volumes for the year ended December
31, 2002 averaged 2,320 boe/day (2001  1,906 boe/day) for a 22% increase. The
increases in revenue and production volumes are consistent given that commodity prices, on
average, were only 4% higher in 2002 than 2001 ($30.41 per boe in 2002 compared with
$29.14 per boe in 2001).

The Company received an average of $33.86 per barrel for its oil
production in 2002 compared with $30.53 in 2001. The Company received an average of $4.08
per mcf for its natural gas production during 2002 compared with $3.66 in 2001.

Royalties for year ended December 31, 2002 were $4.2 million (2001 -
$3.2 million) for a 32% increase. As a percentage of oil and gas revenues, royalties were
16% for both 2002 and 2001.

Operating expenses for the year ended December 31, 2002 were $6.0
million (2001 - $5.8 million). Operating costs increased by only 3% in 2002 despite a 27%
increase in revenue. This is the result of the Companys commitment to reducing
operating expenses since the Westlinks/Big Horn merger in August 2001. On a barrel of oil
equivalent basis operating costs for the year ended December 31, 2002 were $7.11 per boe
(2001 - $8.38 per boe) for a 15% decrease. The reduction in operating costs on a per boe
basis should continue over the next quarters as the Company focuses its drilling on a few
selected areas, which makes it easier to manage and control costs.

General and administrative expenses for the year ended December 31,
2002 were $1.7 million (2001 - $0.6 million) for a 198% increase. On a barrel of oil
equivalent basis administrative costs were $1.99 per boe in 2002 (2001 - $0.81 per boe).
The 2001 general and administrative expenses only reflected the combined entities (Big
Horn and Westlinks) for five months of the year, from August to December. There were
additional costs in 2002 related to staffing levels and also increased marketing and
travel costs as the Company focused its attention on its larger U.S. shareholder base.
Overhead recoveries also decreased in 2002 as the Company maintained a much larger working
interest than it did in 2001. The Companys two largest projects in 2002, Clair and
Bindloss, were drilled with a 100% working interest. As the Companys production
continue to increase in 2003 the general and administrative expenses should settle to a
level between $1.00 and $2.00 per boe.

-  23-

Interest expense for the year ended December 31, 2002 was $1.2 million
(2001 - $0.6 million). The increase in interest expense is due to higher debt levels in
2002. Included in interest expense in 2002 is $22,549 of dividends paid to the preferred
shareholders. There were no dividends paid to preferred shareholders in 2001.

Depletion and depreciation for the year ended December 31, 2002 was
$9.3 million (2001 - $6.9 million). The increase reflects the higher cost base in our
capital assets in 2002. As a percentage of revenue, the depletion and depreciation expense
were 36% in 2002 and 34% in 2001.

The Company began amortizing its deferred financing charges in 2002. The provision was
$390,800. The balance remaining on the balance sheet at December 31, 2002 was $284,040.

Enterra incurred $0.9 million of one-time restructuring charges (mainly
severance and termination payments) in 2001 as a result of the Big Horn acquisition. There
were no such costs in 2002.

Current and future income tax expense for the year ended December 31,
2002 were $132,000 and $911,000 respectively (2001  $120,000 and $562,000). The
future income tax expense is calculated based on the timing of deductions for accounting
purposes and tax on the Companys assets.

The Companys earnings for the year ended December 31, 2002 were
$4.98 million (2001 - $$1.62 million). This large increase was caused mainly by a $3.1
million gain on redemption of preferred shares which occurred in the first quarter of
2002. Enterra redeemed 6,123,870 of its Series 1 preferred shares with a face redemption
price of $5,205,290 for $2.1 million, resulting in a gain of $3.1 million. Without this
gain, earnings would have been $1.86 million, an increase of 15%.

Earnings per share for the year ended December 31, 2002 were $0.54
(2001 - $0.23). The weighted average number of shares outstanding in 2002 was 9,154,491
(2001  6,992,393).

The Company had 9,176,325 common shares outstanding at December 31,
2002 (December 31, 2001 - 9,150,622)

Subsequent Event  Sale of Non-Core Properties

Subsequent to December 31, 2002 the Company sold some non-core oil and
gas properties for proceeds of $4.3 million.

Subsequent Event  Hedging Contracts

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

|Volumes (in barrels per
    day) | Price (in US dollars)
|-------------------------------- | ---------------------
|1,000                            | US$29.60             
|250                              | US$29.71             
|250                              | US$29.50             
|500                              | US$29.80             

Critical Accounting Policies

The Company follows the full cost method of accounting for oil and
natural gas properties and equipment whereby we capitalize all costs relating to its
acquisition of, exploration for and development of oil and natural gas reserves. The
Companys consolidated financial condition and results of operations are sensitive
to, and may be adversely affected by, a number of subjective or complex judgments relating
to methods, assumptions or estimates required under the full cost method of accounting
concerning the effect of matters that are inherently uncertain. For example:



-  24-

> (i) Capitalized costs under the full cost method are generally depleted
>     and depreciated using the unit-of-production method, based on estimated proved oil and gas
>     reserves as determined by independent engineers. In addition, capital costs are also
>     restricted from exceeding the sum of the estimated future net revenues of those
>     properties, plus the cost or estimated fair value of unproved properties less estimated
>     future abandonment and site restoration costs, general administrative expenses, financing
>     costs and income taxes (the "ceiling test"). Should this comparison indicate an
>     excess carrying value, a write-down would be recorded. To economically evaluate the
>     Companys proved oil and natural gas reserves, these independent engineers must
>     necessarily make a number of assumptions, estimates and judgments that they believe to be
>     reasonable based upon their expertise and professional and CICA and SEC guidelines. Were
>     the independent engineers to use differing assumptions, estimates and judgments, then the
>     Companys consolidated financial condition and results of operations would be
>     affected. For example, the Company would have lower revenues and net profits (or higher
>     net losses) in the event the revised assumptions, estimates and judgments resulted in
>     lower reserve estimates, since our depletion and depreciation rate would then be higher
>     and it might also result in a write-down under the ceiling test. Similarly, the Company
>     would have higher revenues and net profits (or lower net losses) in the event the revised
>     assumptions, estimates and judgments resulted in higher reserve estimates.
>     (ii) The Companys management also periodically assesses the
>     carrying values of unproved properties to ascertain whether any impairment in value has
>     occurred. This assessment typically includes a determination of the anticipated future net
>     cash flows based upon reserve potential and independent appraisal where warranted.
>     Impairment is recorded if this assessment indicates the future potential net cash flows
>     are less than the capitalized costs. Were the Companys management to use differing
>     assumptions, estimates and judgments, then the Companys consolidated financial
>     condition and results of operations would be affected. For example, the Company would have
>     lower net profits (or higher net losses) in the event the revised assumptions, estimates
>     and judgments resulted in increased impairment expense.

Qualitative and Quantitative Disclosures about Market and Credit Risk

We are exposed to all of the normal market risks inherent within the
oil and gas, including commodity price risk, foreign-currency rate risk, interest rate
risk and credit risk. We manage our operations in a manner intended to minimize our
exposure, as described in notes 12 and 13 to the consolidated financial statements, which
is incorporated by reference here.

Sensitivities

|(Cdn$)                                                  | Cash Flow | Net Income
|------------------------------------------------------- | --------- | ----------
|Estimated 2003 impact:                                  |           |           
|Crude Oil - US $1.00/bbl
    change in WTI              | $936,000  | $378,000  
|Natural Gas - US $0.50/mcf
    change                   | $817,000  | $330,000  
|Foreign Exchange - $0.01
    change in US to Cdn Dollar | $233,000  | $69,000   
|Interest Rates - 1% change                              | $250,000  | $145,000  

Credit Risk

Credit risk is the risk of loss resulting from non-performance of
contractual obligations by a customer or joint venture partner. A substantial portion of
our accounts receivable are with customers in the energy industry and are subject to
normal industry credit risk. We assess the financial strength of our customer and joint
venture partners through regular credit reviews in order to minimize the risk of
non-payment.

We believe these measures minimize our overall credit risk. However,
there can be no assurance that these processes will protect us against all losses from
non-performance.

Market Risk

We are exposed to market risk from changes in currency exchange rates
and interest rates. As a Canadian oil and gas company, we may be adversely affected by
changes in the exchange rate between U.S. and Canadian dollars. The price we receive for
oil and gas production is expressed in U.S. dollars, which is the standard for the oil and
gas industry world-wide. However, we pay our operating expenses, drilling expenses and
general overhead expenses in Canadian dollars. Changes to the exchange rate between U.S.
and Canadian dollars can adversely affect us. When the value of the U.S. dollar increases,
we receive higher revenue and when the value of the U.S. dollar declines, we receive lower
revenue on the same amount of production sold at the same prices.



-  25-

Interest rate risk exists principally with respect to our indebtedness
that bears interest at floating rates. At December 31, 2002, we had $24,436,640 of
indebtedness bearing interest at floating rates and $4,921,598 of long-term debt bearing
interest at fixed rates.

Enterra regularly assess its exposure and monitor opportunities to
manage these risks, as follows:

> (a) Effective January 31, 2001, the Company settled a fixed price
>     contract eliminating the requirement to deliver set physical quantities of oil at fixed
>     prices. Upon the cancellation of the contract the Company received approximately
>     $1,680,000, which is being recognized into income over the term of the contract. At
>     December 31, 2002 the remaining deferred gain related to this settlement was $237,463
>     (December 31, 2001 - $761,302).
>     (b) During 2002 and 2001, the Company entered into costless collars and
>     forward contracts to establish a minimum price for the Companys future sales of
>     crude oil and gas. The contracts are as follows:
>     (i) The Company entered into a zero cost collar arrangement during 2001
>         which provides a floor price of US$20 per barrel and a ceiling price of US$24 per barrel
>         for 500 barrels of oil per day. The contract is effective from November 1, 2001 through
>         April 30, 2002.
>         (ii) In July 2002, the Company entered into a zero cost collar
>         arrangement with a floor price of US$22 per barrel and a ceiling price of US$28 per barrel
>         for 500 barrels of oil per day. The contract is effective from October 1, 2002 through
>         March 31, 2003. At December 31, 2002 this contract had an estimated negative market value
>         of $216,000.
>         (iii) In July 2002, the Company entered into two contracts to deliver
>         natural gas. One is for 1,500 mcf per day, priced at CDN$4.60 per mcf. The other is for
>         1,500 mcf per day, priced at CDN$4.45 per mcf. Both contracts are effective from November
>         1, 2002 through March 31, 2003. At December 31, 2002 these contracts had an estimated
>         negative market value of $369,000.

Contractual Obligations and Commitments

The Company has assumed various contractual obligations and commercial
commitments in the normal course of its operations and financing activities. Contractual
obligations are financial in nature and are considered to represent known future cash
payments that we are required to make under existing contractual arrangements, such as
debt and lease arrangements.

The Company has commitments for the following payments over the next
five years:

Thereafter2003
    2004
    2005
    2006
    2007Capital lease obligations
    $1,118,994
    $1,118,994
    $1,070,068
    $1,065,620
    $1,799,215Note payable
    86,284Rental payments re-office
    space
    447,357
    429,854
    165,121
    114,894$1,652,635
    $1,548,848
    $1,235,189
    $1,180,514
    $1,799,215


New Accounting Pronouncements

In December 2001, the Canadian Institute of Chartered Accountants
(CICA) issued Accounting Guideline 13, "Hedging Relationships" (AcG-13). AcG-13
establishes certain conditions for when hedge accounting may be applied. The guideline is
effective for fiscal years beginning on or after July 1, 2003. Adoption of AcG-13 is not
expected to have a material impact on the Companys financial position or results of
operations.

In September 2002, the CICA approved Section 3063, "Impairment of
Long-Lived Assets" (S.3063). S.3063 establishes standards for the recognition,
measurement and disclosure of the impairment of long-lived assets, and applies to
long-lived assets held for use. An impairment loss is recognized when the carrying amount
of a long-lived asset is not recoverable and exceeds its fair value. The Company is
currently assessing the impact that adoption of this standard would have on its
consolidated financial position and results of operation.



-  26-

In December 2002, the CICA approved Section 3110, "Asset
Retirement Obligations" (S.3110). S.3110 requires liability recognition for
retirement obligations associated with our property, plant and equipment. These
obligations are initially measured at fair value, which is the discounted future value of
the liability. This fair value is capitalized as part of the cost of the related asset and
amortized to expense over its useful life. The liability accretes until we expect to
settle the retirement obligation. S.3110 is effective for fiscal years beginning on or
after January 1, 2004. The total impact on our financial statements has not yet been
determined.

The following standards and revisions issued by the CICA do not impact
us:

> (i) Amendments to S.3025 - "Impaired Loans", effective for
>   asset foreclosures on or after May 1, 2003.
>   (ii) Section 3475 - "Disposal of Long-Lived Assets and
>   Discontinued Operations", effective for disposal activities initiated by commitments
>   to plans on or after May 1, 2003.

In June 2001, the US Financial Accounting Standards Board (FASB) issued
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS
143 requires liability recognition for retirement obligations associated with the
Companys property, plant and equipment. These obligations are initially measured at
fair value, which is the discounted future value of the liability. This fair value is
capitalized as part of the cost of the related asset and amortized to expense over its
useful life. The liability accretes until we expect to settle the retirement obligation.
The Company is currently assessing the impact that adoption of this standard would have on
its consolidated financial position and results of operation.

In November 2002, the FASB issued Interpretation No. 45,
"Guarantors Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 elaborates on the
disclosures the Company must make about our obligations under certain guarantees that we
have issued. It also requires us to recognize, at the inception of a guarantee, a
liability for the fair value of the obligations the Company has undertaken in issuing the
guarantee. The initial recognition and initial measurement provisions are to be applied
only to guarantees issued or modified after December 31, 2002. Adoption of these
provisions will not have a material impact on the Companys financial position or
results of operations. The disclosure requirements are effective for annual or interim
periods ending after December 15, 2002.

In January 2003, the FASB issued Statement No. 148 "Accounting for
Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No.
123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary change to
the fair-value based method of accounting for stock-based employee compensation. In
addition, FAS 148 amends the disclosure requirements of FAS 123 to require prominent
disclosures in both annual and interim financial statements about the method of accounting
for stock-based employee compensation and the effect of the method used on reported
results. FAS 148 has no material impact on the Company as the Company does not plan to
adopt the fair-value method of accounting for stock options at the current time.

The following standards issued by the FASB do not impact the Company:

> (i) Statement No. 145  "Rescission of FASB Statements No. 4,
>       44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" effective
>       for financial statements issued on or after May 15, 2002;
>       (ii) Statement No. 146  "Accounting for Costs Associated
>       with Exit or Disposal Activities" effective for exit or disposal activities initiated
>       after December 31, 2002;
>       (iii) Statement No. 147  "Acquisitions of Certain Financial
>       Institutions - an Amendment of FASB Statements No. 72 and 144 and FASB Interpretation No.
>       9" effective for acquisitions on or after October 1, 2002; and
>       (iv) Interpretation No. 46  "Consolidation of Variable
>       Interest Entities" effective for financial statements issued after January 31, 2003.

Factors That May Affect Future Results

This report, including Managements Discussion and Analysis or
Plan of Operation, contains forward-looking statements and other prospective information
relating to future events. These forward-looking statements and other information are
subject to certain risks and uncertainties that could cause results to differ materially
from historical or anticipated results, including the following:



-  27-

Risks related to our industry and business

We have a working capital deficiency at December 31, 2002; our Credit facilities can be
called at any time.

At December 31, 2002, we had a working capital deficiency of
$37,983,234, which means our current liabilities exceeded our current assets by that
amount. Our bank debt is classified as a current liability as it is a facility based 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. A
decrease in the amount of our production or the price we receive for it could make it
difficult for us to service our loan or may cause the bank that issued our loan to
determine that our assets are insufficient security for our bank debt.

There is uncertainty about estimates used in this annual report and
they may prove to be inaccurate, resulting in a reduction of our working capital.

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

Our operations are subject to numerous risks of crude oil and natural
gas drilling and production activities.

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

> that no commercially productive crude oil or natural gas reservoirs
>   will be found;
>   that crude oil and natural gas drilling and production activities may
>   be shortened, delayed or canceled; and
>   that our ability to develop, produce and market our reserves may be
>   limited by:
>   title problems,
>       weather conditions,
>       compliance with governmental requirements, and
>       mechanical difficulties or shortages or delays in the delivery of
>       drilling rigs and other equipment.

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

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

We operate in a highly competitive industry that may adversely affect
our operations.

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



-  28-

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

Our ability to replace production with new reserves is highly dependent
on acquisitions or successful development and exploration activities.

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

Crude oil and natural gas price declines and volatility could adversely
affect our revenue, cash flows and profitability.

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

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

Lower crude oil and natural gas prices increase the risk of ceiling
limitation write-downs.

The Company changed its method of accounting for petroleum and natural
gas properties from the "successful efforts" method to the "full cost"
method in 2001. All costs related to the exploration for and the development of oil and
gas reserves are capitalized into a single cost centre representing the Companys
activity which is undertaken exclusively in Canada. Costs capitalized include land
acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped
properties and costs of drilling productive and non-productive wells. Proceeds from the
disposal of properties are applied as a reduction of cost without recognition of a gain or
loss except where such disposals would result in a major change in the depletion rate.
Capitalized costs are depleted and depreciated using the unit-of-production method based
on the estimated gross proven oil and natural gas reserves before royalties as determined
by independent engineers. Units of natural gas are converted into barrels of equivalents
on a relative energy content basis. Capitalized costs, net of accumulated depletion and
depreciation, are limited to estimated future net revenues from proven reserves, based on
year-end prices, undiscounted, less estimated future abandonment and site restoration
costs, general and administrative expenses, financing costs and income taxes. Estimated
future abandonment and site restoration costs are provided for over the life of proven
reserves on a unit-of-production basis. The annual charge is included in depletion and
depreciation expense and actual abandonment and site restoration costs are charged to the
provision as incurred. The amounts recorded for depletion and depreciation and the
provision for future abandonment and site restoration costs are based on estimates of
proven reserves and future costs. The recoverable value of capital assets is based on a
number of factors including the estimated proven reserves and future costs. By their
nature, these estimates are subject to measurement uncertainty and the impact on financial
statements of future periods could be material.



-  29-

The Company performs a cost recovery ceiling test which limits net
capitalized costs to the undiscounted estimated future net revenue from proven oil and gas
reserves plus the cost of unproven properties less impairment, using year-end prices or
average prices in that year, if appropriate. In addition, the value is further limited by
including financing costs, administration expenses, future abandonment and site
restoration costs and income taxes. Under U.S. GAAP, companies using the "full
cost" method of accounting for oil and gas producing activities perform a ceiling
test using discounted estimated future net revenue from proven oil and gas reserves using
a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this
reconciliation were those in effect at the applicable year-end. Financing and
administration costs are excluded from the calculation under U.S. GAAP. At December 31,
2001 the Company realized a U.S. GAAP ceiling test write-down of $17.5 million (after
tax). There were no such write-down required at December 31, 2002.

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

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

We may undertake acquisitions that could limit our ability to manage
and maintain our business, result in adverse accounting treatment and are difficult to
integrate 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 existing
operations. However we may be unable to complete any acquisitions, or any acquisitions we
may complete may not enhance our business. Any acquisitions could subject us to a number
of risks, including:

> diversion of management's attention;
>   amortization of substantial goodwill, adversely affecting our reported
>   results of operations;
>   inability to retain the management, key personnel and other employees
>   of the acquired business;
>   inability to establish uniform standards, controls, procedures and
>   policies;
>   inability to retain the acquired company's customers;
>   exposure to legal claims for activities of the acquired business prior
>   to acquisition; and inability to integrate the acquired company and its employees into our
>   organization effectively.

We may be subject to environmental liability claims that could result
in significant costs to us.

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

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

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



-  30-

> political conditions in the Middle East, the former Soviet Union and
>   other regions;
>   domestic and foreign supplies of oil and gas;
>   the level of consumer demand;
>   weather conditions;
>   domestic and foreign government regulations;
>   the availability and prices of alternative fuels; and
>   overall economic conditions.

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

As a Canadian oil and gas company, we may be adversely affected by
changes in the exchange rate between U.S. and Canadian dollars.

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

We depend on key personnel for critical management decisions and
industry contacts but have no employment contracts or key person insurance.

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

We have not paid dividends, do not intend to pay dividends in the
foreseeable future and are currently restricted from paying dividends pursuant to the
terms of our credit facility and Alberta corporate law.

We have not paid any cash dividends on our common stock and do not
expect to pay any cash or other dividends in the foreseeable future. The terms of our
current banking credit facility prohibit us from declaring and paying dividends except
from assets that are in excess of the required amount of security under our credit
facility, and Alberta corporate law prohibits the payment of dividends unless stated
solvency tests are met.

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 fluctuations
in response to quarterly variations in operating results, changes in financial estimates
by securities analysts, an imbalance of purchasers and sellers, or other factors.

Item 7. Financial Statements

The Consolidated Financial Statements of Enterra are attached as
follows:



Independent auditors reports to the shareholders F-1 and F-2

Enterra Energy Corp.s Consolidated Financial Statements as of and

for the years ended December 31, 2002 and 2001 F-3 through F-18



-  31-

Item 8. Changes In and Disagreements With Accountants on Accounting and Financial
Disclosure

Previous Independent Auditors:

Enterra Energy Corp. ("Enterra") has used the services of
KPMG

KPMG reports on our financial statements for the fiscal years ended
December 31, 2001 and December 31, 2002 contain no adverse opinion or disclaimer of
opinion and were not qualified or modified as to uncertainty, audit scope or accounting
principles.

Our Board of Directors approved the change in accountants.

For the two most recent fiscal years and the quarters ended March 31,
2002 and June 30, 2002, there has been no disagreement between us and KPMG on any matter
of accounting principles or practices, financial statement disclosure, or auditing scope
or procedure, which disagreement, if not resolved to the satisfaction of KPMG would have
caused it to make a reference to the subject matter of the disagreement in connection with
its reports.

During the two most recent fiscal years and the quarters ended March
31, 2002 and June 30, 2002, we have not been advised of any matters described in
Regulation S-B, Item 304(a)(I)(B).

New Independent Auditors:

We engaged Deloitte & Touche

PART III



> Item 9. Directors, Executive Officers, Promoters and
>     Control Persons; Compliance With Section 16(A) of the Exchange Act

The directors and executive officers of Enterra as of December 31, 2002
were:

|Name                  | Age | Position with Enterra                                        
|--------------------- | --- | -------------------------------------------------------------
|Walter Dawson         | 62  | Director                                                     
|Reg J. Greenslade     | 39  | Chairman, Director, President and Chief
    Executive Officer
|H.S. (Scobey) Hartley | 70  | Director                                                     
|Doug Paul             | 54  | Director                                                     
|Norman G Wallace      | 64  | Director                                                     
|Thomas J. Jacobsen    | 68  | Director, Chief Operating Officer                            
|Albert Johnston       | 59  | Vice President Operations                                    
|Luc Chartrand         | 46  | Chief Financial Officer                                      
|Rick McHardy          | 34  | Corporate Secretary                                          
|Tom Dirks             | 61  | Vice-President Exploration                                   
|Trevor Spagrud        | 34  | Vice-President Operations                                    

Walter A. Dawson. Mr. Dawson was formerly the Executive Chairman of
Enserco Energy Services Corp. He resigned in March 2001 after the merger with Tetonka was
completed to pursue the creation of Simmons Energy Services. In 1993, Mr. Dawson, through
his 100%-owned holding company, Perfco Investments Ltd., purchased control of Bonus
Petroleum Corp., a public company that became Enserco. Enserco is now a leader in the
Canadian workover and drilling market with 200 service rigs and 30 drilling rigs in Canada
and Australia and will achieve revenue of $250 million along with over $80 million cash
flow in 2001. Prior to Perfco Investments, Mr. Dawson founded and served 19 years as
President, Chief



-  32-

Executive Officer, and director of Computalog Ltd. In 1972, Mr. Dawson
purchased a cased-hole wireline unit from Gearhart Industries and incorporated Perfco
Services Ltd., which later formed Computalog Gearhart Ltd. in 1978. He was instrumental in
taking the company public on the Toronto Stock Exchange in 1980, negotiating an exclusive
technology/supply agreement with Gearhart Industries for Canada. Afterwards, he entered
the directional and fishing tool business, along with the incorporation of the
companys first research center where he hired 50 research and development experts to
design and build state-of-the-art well logging equipment. Mr. Dawson led and completed
several financings to achieve this goal. Mr. Dawson is currently a director of Integrated
Production Services, a Toronto Stock Exchange listed company, and is a director of Action
Energy Inc., a private company. He also held positions on several oil and gas boards over
his career for both service and producing companies. Mr. Dawson became a Director of
Enterra in August 2001.

Reg J. Greenslade. Mr. Greenslade became President of Big Horn in
April 1995 and President and CEO and a Director of Enterra in August 2001 and Chairman of
the Board in December 2002. Prior to joining Big Horn, Mr. Greenslade held senior
positions with several medium- and large-sized oil and gas companies. Most recently Mr.
Greenslade was with CS Resources Limited in the areas of exploitation engineering and
project management from 1993 to 1995. He was previously with Saskatchewan Oil and Gas
Corporation in the capacities of project management, production, and reservoir
engineering. He has extensive experience with secondary recovery schemes and is recognized
for his work in the specialized field of horizontal well technology.

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

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

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

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

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



-  33-

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

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

Albert Johnston. Mr. Johnston has been President of AJ Consulting since 1982 and
has worked with various drilling contractors in the design and supervision of drilling
programs. Mr. Johnston was Operation Manager with Custom Drilling from 1980 to 1982. Mr.
Johnston became Enterras Vice President of Operations in June 2002.

Tom Dirks. Mr. Dirks has been working as a Geologist in the U.S. and Canada since
1968. From 1968 to 1976 he worked with various companies on both sides of the border. He
co-founded Exalta Petroleums Ltd. in 1976. Exalta became a wholly-owned subsidiary of
Brinco Limited in 1979. Mr. Dirks was Executive Vice President of Brinco until 1982.
Between 1982 and 1992, Mr. Dirks was President of Equine Resources Ltd., Laredo Petroleums
Ltd. and Pedco Energy, all Vancouver publicly listed companies. Since 1992 Mr. Dirks has
been working as a Geological Consultant for various exploration companies. He became
Enterras Vice President of Exploration in June 2002.

Board of Directors

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

Currently directors receive an annual retainer of $7,500. In addition,
directors receive fees in the amount of $750 for each directors' meeting which they
personally attend and $250 for each conference call which they participate in which
exceeds 1 hour in duration. Directors are also entitled to be compensated for their
out-of-pocket costs, including travel and accommodation, relating to their attendance at
any directors' meeting. Finally, the directors are entitled to participate in the
Corporation's stock option plan. During the year ended December 31, 2001, options to
acquire a total of 240,000 common shares were granted to the current directors of the
Corporation (not including options granted to a director who is also a named executive
officer). Except as described herein, no compensation by way of annual retainer or meeting
fees was paid to directors for acting in such capacity in the year ended December 31,
2002.

Committees of the Board of Directors

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

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



-  34-

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

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

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





As a foreign private issuer, Enterra is exempt from the rules under the
exchange act prescribing the furnishing and content of proxy statements and our officers,
directors and principal shareholders are exempt from the reporting and short-swing profit
recovery provisions contained in section 16 of the exchange act.

Item 10. Executive Compensation

Executive Compensation

The following table provides a summary of compensation earned during
the last fiscal year ended December 31, 2001 by the Corporation's executive officers
during 2002. These officers were appointed to their positions in August 2001. The
compensation shown below is based on a calendar 2002 year.

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.
    GreensladePresident and Chief Executive Officer | 2002                                                    | 157,500                      | -                      | 11,025                        
|Tom JacobsenChief
    Operating Officer                         | 2002                                                    | 140,000                      | -                      | -                             
|Trevor R.
    SpagrudVice-President, Engineering                | 2002                                                    | 196,875                      | -                      | 9,187                         
|Luc ChartrandChief Financial Officer                            | 2002                                                    | 158,355                      | -                      | -                             





























-  35-

Management Contracts

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

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, in
accordance with resolutions of our board of directors and the policies of the Canadian
Venture Exchange, will not exceed a term of five years. The option price may be at a
discount to market price, which discount will not, in any event, exceed that permitted by
any stock exchange on which our shares are listed for trading.

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

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

Stock Options Granted During the Most Recently Completed Financial Year

The following table discloses the grants of options to purchase or
acquire shares of common stock to our executive officers during the fiscal year ended
December 31, 2002. All monetary amounts are in Canadian dollars.

Option Grants During Fiscal Year Ended December 31, 2002

|                | Number of
    Securities
    Under
    Options
    Granted
    (#) | % of TotalOptions
    Granted to
    Employees in
    FY Ended
    Dec. 31, 2002 | Exercise
    Price
    ($/share) | Unexercised
    options at
    December 31,
    2002
    (#) | Expiration
    Date
|--------------- | ------------------------------------------------------------------ | -------------------------------------------------------------------------------- | -------------------------------- | ------------------------------------------------------------ | -------------------
|               
|               
|               
|               
|Name           
|Albert Johnston | 20,000                                                             | 8.6%                                                                             | $ 4.41                           | 20,000                                                       | June 6, 2007       
|Albert Johnston | 5,000                                                              | 2.2%                                                                             | $ 6.00                           | 5,000                                                        | July 2, 2007       
|Tom Dirks       | 25,000                                                             | 10.8%                                                                            | $6.00                            | 25,000                                                       | July 2, 2007       

A total of 232,000 options were granted by Enterra during the fiscal
year ended December 31, 2002.



-  36-

Aggregated Option Exercises During the Most Recently Completed Financial Year and
Financial Year End Option Values

The following table sets forth the aggregate of options exercised by
our executive officers during the year ended December 31, 2002 and the December 31, 2001
year-end values for options granted to the executive officers. All monetary amounts are in
Canadian dollars. Add space below in far right column to improve readability

|                  | Securities
    Exercised (#) | Aggregate
    Value
    Realized ($) | Unexercised
    Options at FY-End
    Exercisable/
    Unexercisable (#) | Value ofUnexercised
    in-the-Money Options
    at FY-End
    Exercisable/
    Unexercisable ($)
    (1)
|----------------- | ---------------------------- | ------------------------------------ | ------------------------------------------------------------------------ | ---------------------------------------------------------------------------------------------------------
|                 
|                 
|                 
|                 
|                 
|Name             
|                  |                              |                                      |                                                                          |                                                                                                          
|Reg J. Greenslade | Nil                          | Nil                                  | 144,000                                                                  | $695,016/ $360,504                                                                                       
|Trevor Spagrud    | Nil                          | Nil                                  | 100,000                                                                  | $414,226/ $318,774                                                                                       
|Luc Chartrand     | Nil                          | Nil                                  | 72,500                                                                   | $267,948/ $263,477                                                                                       
|Tom Jacobsen      | Nil                          | Nil                                  | 60,000                                                                   | $109,950/ $329,850                                                                                       
|Albert Johnston   | Nil                          | Nil                                  | 25,000                                                                   | Nil/ $183,250                                                                                            
|Tom Dirks         | Nil                          | Nil                                  | 25,000                                                                   | Nil/ $183,250                                                                                            
|Rick McHardy      | Nil                          | Nil                                  | 15,000                                                                   | $79,868/ $30,082                                                                                         



> (1) The closing price of our shares of common stock on the TSX Venture
>   Exchange on the last trading day in December, 2002 was $11.33.

Item 11. Security Ownership of Certain Beneficial Owners and
Management

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information regarding beneficial
ownership of our common stock as of December 31, 2002, by:

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

 each of our executive officers and directors; and

 all executive officers and directors as a group.

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

|                                            | Number
    of |            
|------------------------------------------- | ------------- | -----------
|                                            | Shares        | Percentage 
|                                            | Beneficially  | of shares  
|                                            | owned         | outstanding
|Reg J. Greenslade                           | 322,703       | 3.21       
|Trevor Spagrud                              | 124,681       | 1.24       
|Luc Chartrand                               | 191,467       | 1.91       
|H.S. (Scobey) Hartley                       | 65,000        | 0.65       
|Walter Dawson                               | 464,896       | 4.63       
|Rick McHardy                                | 16,524        | 0.16       
|Thomas J. Jacobsen                          | 314,584       | 3.13       
|Albert Johnston                             | 53,200        | 0.53       
|Tom Dirks                                   | 25,000        | 0.25       
|Executive officers and directors as a group | 1,638,055     | 16.30      
|John P. McGrain (beneficial ownership > 5%) | 549,200       | 5.47       
|Total                                       | 2,187,255     | 21.77      

__________

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.
>   
>   -  37-
>   (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 246,980 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.
>     Mr. Johnston includes options to purchase 20,000 common shares at
>     an exercise price of $4.41 and options to purchase 5,000 common shares at an exercise
>     price of $6.00.
>     Mr. Dirks includes options to purchase 25,000 common shares at an
>     exercise price of $6.00

Equity Compensation Plan Information

The following table indicates the number of equity securities of Enterra authorized for
issuance as of December 31, 2002 with respect to compensation plans, including:

> All compensation plans previously approved by security holders; and
>     All compensation plans not previously approved by security holders.

|Plan category                                                  | Number of securities
    to be issued upon exercise of outstanding options, warrants and rights
    (a) | Weighted-average
    exercise price of outstanding options, warrants and rights
    (b) | Number of securities
    remaining available for future issuance under equity compensation plans (excluding
    securities reflected in column (a))
    (c)
|-------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------
|Equity compensation plans approved by security
    holders     | 1,071,703                                                                                               | $4.70                                                                                   | 200,000                                                                                                                                                    
|Equity compensation plans not approved by
    security holders | N/A                                                                                                     | N/A                                                                                     | N/A                                                                                                                                                        
|Total                                                          | 1,071,703                                                                                               | $4.70                                                                                   | 200,000                                                                                                                                                    

Exchange Controls

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

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



-  38-

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

Taxation

United States Taxation

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

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

> an individual citizen or resident of the United States;
>       a corporation created or organized under the laws of the United States
>       or any state thereof including the District of Columbia;
>       an estate the income of which is subject to United States federal
>       income taxation regardless of its source;
>       a trust if a court within the United States is able to exercise primary
>       jurisdiction over its administration and one or more U.S. persons have authority to
>       control all substantial decisions of the trust; or
>       a partnership to the extent the interests therein are owned by any of
>       the persons described in clauses (a), (b), (c) or (d) above.

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

The following discussion is based upon:

> the Internal Revenue Code;
>       U.S. judicial decisions;
>       administrative pronouncements;
>       existing and proposed Treasury regulations; and
>       the Canada/ U.S. Income Tax Treaty.

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

HOLDERS OF COMMON STOCK ARE URGED TO CONSULT THEIR TAX ADVISORS AS TO
THE PARTICULAR CONSEQUENCES TO THEM UNDER U.S. FEDERAL, STATE, LOCAL AND APPLICABLE
FOREIGN TAX LAWS OF THE ACQUISITION, OWNERSHIP AND DISPOSITION OF COMMON STOCK.

Dividends

Subject to the discussion of passive foreign investment companies
below, the gross amount of any distribution paid by us to a U.S. Holder will generally be
subject to U.S. federal income tax as foreign source dividend income to the extent paid
out of our current or accumulated earnings and profits, as determined under U.S. federal
income tax principles. The



-  39-

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

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

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

Sale or Exchange

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

> the holder's holding period for the common stock, with a preferential
>       rate available for common stock held for more than one year; and
>       the holder's marginal tax rate for ordinary income.

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

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

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

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

> such gain is effectively connected with the conduct by such Non-U.S.
>   Holder of a trade or business in the United States; or
>   in the case of any gain realized by an individual Non-U.S. Holder, such
>   Non-U.S. Holder is present in the United States for 183 days or more in the taxable year
>   of such sale and certain other conditions are met.
>   
>   -  40-

Personal Holding Company

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

> if at any time during the last half of our taxable year, five or fewer
>       individuals own or are deemed to own more than 50% of the total value of our shares; and
>       we receive 60% or more of our U.S. related gross income from specified
>       passive sources, such as royalty payments.

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

Foreign Personal Holding Company

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

> five or fewer individuals who are United States citizens or residents
>       own or are deemed to own more than 50% of the total voting power of all classes of our
>       shares entitled to vote or the total value of our shares; and
>       at least 60%, 50% in some cases, of our gross income, as adjusted,
>       consists of "foreign personal holding company income", which generally includes
>       passive income such as dividends, interests, gains from the sale or exchange of shares or
>       securities, rent and royalties.

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

Passive Foreign Investment Company

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

> at least 75% of our gross income for the taxable year is passive
>       income; or
>       at least 50% of the average value of our assets is attributable to
>       assets that produce or are held for the production of passive income.

For this purpose, passive income includes income such as:

> dividends;
>       interest;
>       rents or royalties, other than certain rents or royalties derived from
>       the active conduct of trade or business;
>       annuities; or
>       gains from assets that produce passive income.

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

-  41-

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

> any gain realized on the sale or other disposition of common stock; and
>       any "excess distribution" by us to the U.S. Holder.

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

Under the passive foreign investment company rules,

> the gain or excess distribution would be allocated ratably over the
>       U.S. Holder's holding period for the common stock;
>       the amount allocated to the taxable year in which the gain or excess
>       distribution was realized would be taxable as ordinary income;
>       the amount allocated to each prior year, with certain exceptions, would
>       be subject to tax at the highest tax rate in effect for that year; and
>       the interest charge generally applicable to underpayments of tax would
>       be imposed in respect of the tax attributable to each such year.

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

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

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

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

United States Backup Withholding and Information Reporting

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

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

-  42-

Canadian Federal Income Tax Considerations

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

> is resident in the United States and not resident in Canada;
>       holds the common stock as capital property;
>       does not have a "permanent establishment" or "fixed
>       base" in Canada, as defined in the Convention; and
>       deals at arm's length with us. Special rules, which are not discussed
>       below, may apply to "financial institutions", as defined in the ITA, and to
>       non-resident insurers carrying on an insurance business in Canada and elsewhere.

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

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

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

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

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

HOLDERS OF COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS TO
DETERMINE THE PARTICULAR TAX CONSEQUENCES TO THEM, INCLUDING THE APPLICATION AND EFFECT OF
ANY STATE, LOCAL OR FOREIGN INCOME AND OTHER TAX LAWS, OF THE ACQUISITION, OWNERSHIP AND
DISPOSITION OF COMMON STOCK.

-  43-

Item 12. Certain Relationships and Related Transactions

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None of Enterras directors or executive officers, nor any person
who beneficially owns directly or indirectly or exercises control or direction over
securities carrying more than 5% of the voting rights attaching to our shares of common
stock, nor any known associate or affiliate of these persons had any material interest,
direct or indirect in any transaction since January 1, 2001 which has materially affected
Enterra, or in any proposed transaction which will materially affect Enterra, except as
follows:

Consulting Agreement

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

Item 13. Exhibits And Reports On Form 10-KSB

Exhibits

> Financial Statements

|Audited Annual Financial Statements:                              | Page       
|----------------------------------------------------------------- | -----------
|Reports of Deloitte & ToucheLLPand KPMGLLPIndependent Accountants | F-1 and F-2
|Consolidated Balance Sheets                                       | F-3        
|Consolidated Statement of
    Income (Loss) and Retained Earnings | F-4        
|Consolidated
    Statement of Cash Flows                          | F-5        
|Notes to
    Consolidated Financial Statements                    | F-6 to F-18

(b) Exhibit List

Number Exhibit

|1.1  | Form of Underwriting
    Agreement.                                                                                                                                                                                       
|---- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1  | Amalgamation Agreement
    dated May 27, 1998 between Temba Resources Ltd. and PTR Resources Ltd. pursuant to which
    the Registrant was amalgamated under the Business Corporations Act (Alberta) on June 30,
    1998.
|2.2  | Letter Agreement dated
    August 12, 1999 pursuant to which the Registrant acquired all of the issued and
    outstanding shares of 759795 Alberta Ltd.                                                                  
|2.3  | Notice of Intention to File
    a Normal Course Issuer Bid.                                                                                                                                                               
|3.1  | Certificate of Amalgamation
    and attached Articles of Amalgamation of the Registrant dated and filed June 30, 1998.                                                                                                    
|3.2  | By-laws of the Registrant.                                                                                                                                                                                                
|4.1  | Form of Warrant Trust
    Indenture between the Registrant and Montreal Trust Company of Canada providing for the
    issuance of the Warrants.                                                                           
|4.2  | Form of Warrant Agreement
    between the Registrant and the Representatives providing for the issuance of the
    Underwriters' Warrants.                                                                                
|10.1 | Credit Facility Letter
    Agreement between the Alberta Treasury Branches and the Registrant as Borrower dated April
    19, 2000.                                                                                       
|10.2 | Promissory Notes dated June
    5, 2000 granted by Westlinks to each of Glenn Russell, Patrick Williams Advisors, William
    J. Gordica, F. Jack Wright, Lawrence W. Underwood and Sapphire Capital Inc.                 
|10.3 | Purchase and Sale Agreement
    dated April 6, 2000 between Sabre Exploration Ltd. and the Registrant.                                                                                                                    
|10.4 | Purchase and Sale Agreement
    dated October 1, 2000 between the Registrant and Compton Petroleum Corporation.                                                                                                           
|10.5 | Consulting Agreement dated
    October 13, 2000 between Westlinks Resources Ltd. and Wells Gray Resort & Resources
    Ltd.                                                                                               
|     | -   44-                                                                                                                                                                                                                   
|10.6 | Arrangement Agreement among
    Westlinks Resources Ltd. and 3779041Canada Ltd. and Big Horn Resources Ltd.                                                                                                               
|10.7 | Information Circular and
    Proxy Statement for the Plan of Arrangement between Big Horn Resources Ltd. and Westlinks
    Resources Ltd.                                                                                 
|21.1 | Subsidiaries of the Registrant                                                                                                                                                                                            
|99.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C.ss.1350, as adopted pursuant
      to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                        
|99.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C.ss.1350, as adopted pursuant
      to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                        

(b) Reports on Form 8-K

On October 18, 2002 a Form 8-K was filed concerning the filing of a
letter to shareholders.

ITEM 14. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Within the 90 days prior to the date of this report, Enterra Energy
Corp. carried out an evaluation, under the supervision and with the participation of the
Companys management, including the Companys Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of the Companys
disclosure controls and procedures. The Companys disclosure controls and procedures
are designed to ensure that information required to be disclosed by the Company in its
periodic Securities and Exchange Commission ("SEC") filings is recorded,
processed and reported within the time periods specified in the SECs rules and
forms. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that the Companys disclosure controls and procedures are effective in
timely alerting them to material information relating to the Company required to be
included in the Companys periodic SEC filings.

Changes in Internal Controls

There were no significant changes in the Companys internal
controls or in other factors that could significantly affect these controls subsequent to
the date of their evaluation.

-  45 -

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the
registrant caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.

Enterra Energy Corp.

|By: | Luc Chartrand
|--- | -------------

Name: Luc Chartrand

Title: Chief Financial Officer

March 28, 2003

In accordance with the Exchange Act, this report has been signed below
by the following persons on behalf of the Registrant and in the capacities and on the
dates indicated.

|Signature             | Title                                               | Date    
|--------------------- | --------------------------------------------------- | --------
|Walter Dawson         | Director                                            | 03/28/03
|Reg J. Greenslade     | Director, President and Chief
    Executive Officer | 03/28/03
|H.S. (Scobey) Hartley | Director                                            | 03/28/03
|Doug Paul             | Director                                            | 03/28/03
|Norman G. Wallace     | Director                                            | 03/28/03
|Thomas J. Jacobsen    | Director, Chief Operating
    Officer               | 03/28/03
|Luc Chartrand         | Chief Financial Officer                             | 03/28/03

-  46-

Consolidated Financial Statements of

ENTERRA ENERGY CORP.

AUDITORS REPORT TO THE SHAREHOLDERS

**Year ended December 31, 2002**

To the Shareholders of Enterra Energy Corp.:

We have audited the consolidated balance sheet of Enterra Energy Corp. as at December
31, 2002 and the consolidated statements of earnings and retained earnings and cash flows
for the year then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these financial
statements based on our audit.

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

In our opinion, these consolidated financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2002 and the results of
its operations and its cash flows for the year then ended in accordance with Canadian
generally accepted accounting principles.

The consolidated financial statements as at December 31, 2001 and for the year then
ended were audited by other auditors who expressed an opinion without reservation on those
consolidated financial statements in their report dated March 6, 2002.

(Signed) Deloitte & Touche

Chartered Accountants

Calgary, Canada

March 12, 2003

**F-1**



Consolidated Financial Statements of

ENTERRA ENERGY CORP.

AUDITORS REPORT TO THE SHAREHOLDERS

**Year ended December 31, 2001**

To the Shareholders of Enterra Energy Corp.:

We have audited the consolidated balance sheet of Enterra Energy Corp.
as at December 31, 2001 and the consolidated statements of earnings and retained earnings
and cash flows for the year then ended. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

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

Canadian generally accepted accounting principles vary in certain
significant respects from accounting principles generally accepted in the United States.
Application of accounting principles generally accepted in the United States would have
affected results of operations for the year ended December 31, 2001 and shareholders
equity as at December 31, 2001 to the extent summarized in note 16 to the consolidated
financial statements.

(Signed) KPMG

Chartered Accountants

Calgary, Canada

March 6, 2002

**F-2**



|Enterra Energy Corp.                                           
|---------------------------------------------------------------
|Consolidated Balance Sheets                                    
|As at December 31                                              
|(Expressed in Canadian dollars)                                
|                                                               
|                                                               
|Assets                                                         
|Current assets                                                 
|Cash                                                           
|Accounts receivable                                            
|Prepaid
    expenses and deposits                              
|                                                               
|                                                               
|Property and equipment (note 5)                                
|Deferred financing charges (note
    2)                        
|                                                               
|                                                               
|Liabilities                                                    
|Current liabilities                                            
|Accounts payable and accrued
    liabilities                   
|Income taxes payable                                           
|Bank indebtedness (note 6)                                     
|Current
    portion of long-term debt (note 7)                 
|                                                               
|                                                               
|Provision for future abandonment
    and site restoration costs
|Future income tax liability (note
    8)                       
|Long-term debt (note 7)                                        
|Deferred gain (note 13)                                        
|Series 1 preferred shares (note
    11)                        
|                                                               
|                                                               
|Shareholders Equity                                           
|Share capital (note 9)                                         
|Contributed surplus (note 9)                                   
|Retained earnings                                              
|                                                               
|Hedging contracts (note 13)                                    
|Commitments (note 14)                                          
|Subsequent events (note 15)                                    
|                                                               
|                                                               
|Approved on behalf of the Board :                              
|Reg Greenslade                                                 
|Director                                                       
|                                                               
|See accompanying notes to
    consolidated financial statements

|**F-3**                                                        
|---------------------------------------------------------------
|Enterra Energy Corp.                                           
|Consolidated Statements of Earnings and
    Retained Earnings  
|Years Ended December 31                                        
|(Expressed in Canadian dollars)                                
|                                                               
|                                                               
|Revenue                                                        
|Oil and gas                                                    
|                                                               
|Expenses                                                       
|Royalties, net of ARTC                                         
|Production                                                     
|General and administrative                                     
|Interest on long-term debt                                     
|Amortization of deferred financing charges
    (note 2)        
|Depletion, depreciation and future site
    restoration        
|                                                               
|Earnings before the following                                  
|Restructuring charges                                          
|Gain on redemption of preferred shares (note
    11)           
|Earnings
    before income taxes                               
|Income taxes (note 8)                                          
|Current                                                        
|Future                                                         
|                                                               
|Net earnings                                                   
|                                                               
|                                                               
|Retained earnings, beginning of year                           
|Retained earnings, end of year                                 
|                                                               
|Earnings per share :                                           
|Basic                                                          
|Diluted                                                        
|                                                               
|                                                               
|                                                               
|                                                               
|See accompanying notes to consolidated
    financial statements

**F-4**



|Enterra Energy Corp.                                                                                                                             
|-------------------------------------------------------------------------------------------------------------------------------------------------
|Consolidated Statements of Cash Flows                                                                                                            
|Years Ended December 31                                                                                                                          
|(Expressed in Canadian dollars)                                                                                                                  
|                                                                                                                                                 
|Cash provided by (used in) :                                                                                                                     
|Operations                                                                                                                                       
|Net earnings                                                                                                                                     
|Add non-cash items :                                                                                                                             
|Depletion, depreciation and future site
    restoration                                                                                          
|Future income taxes                                                                                                                              
|Deferred gain                                                                                                                                    
|Amortization of deferred gain                                                                                                                    
|Amortization of deferred financing charges                                                                                                       
|Gain on redemption of preferred shares                                                                                                           
|Funds from
    operations                                                                                                                        
|Net change in non-cash working capital items:                                                                                                    
|Accounts receivable                                                                                                                              
|Prepaid expenses                                                                                                                                 
|Accounts payable and accrued liabilities                                                                                                         
|Income taxes payable                                                                                                                             
|                                                                                                                                                 
|                                                                                                                                                 
|Financing                                                                                                                                        
|Bank indebtedness                                                                                                                                
|Long-term debt                                                                                                                                   
|Issue of common shares, net of issue costs                                                                                                       
|Repurchase of shares                                                                                                                             
|Deferred financing charges                                                                                                                       
|Redemption of preferred shares                                                                                                                   
|                                                                                                                                                 
|                                                                                                                                                 
|Investing                                                                                                                                        
|Property and equipment additions                                                                                                                 
|Acquisition of Big Horn Resources Ltd.                                                                                                           
|Proceeds on disposal of property and equipment                                                                                                   
|Investments                                                                                                                                      
|Future abandonment and site restoration costs                                                                                                    
|                                                                                                                                                 
|                                                                                                                                                 
|Increase in cash                                                                                                                                 
|Cash, beginning of year                                                                                                                          
|Cash, end of year                                                                                                                                
|                                                                                                                                                 
|Funds from operations per share:                                                                                                                 
|Basic                                                                                                                                            
|Future                                                                                                                                           
|                                                                                                                                                 
|During 2001, the Company paid
    $1,235,872 (2001 - $589,169) of interest on long-term debt and $132,000 (2001 - $120,000)
    of capital taxes.
|                                                                                                                                                 
|See accompanying notes to consolidated
    financial statements                                                                                  

**F-5**

Enterra Energy Corp.

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2002 and 2001

____________________________________________________________________________________________

1. Corporate history

> Enterra Energy Corp. (the "Company" or
>   "Enterra") was formed on June 30, 1998 by the amalgamation of Temba Resources
>   Ltd. and PTR Resources Ltd. in a share-for-share exchange. The combination was recorded
>   using the purchase method of accounting with Temba being identified as the acquirer.
>   Effective August 1, 2001 Enterra acquired 100% of the common shares of
>   Big Horn Resources Ltd. ("Big Horn"), a junior oil and gas company listed on the
>   Toronto Stock Exchange, by the way of a plan of arrangement. Consideration consisted of
>   cash of $2,205,447 (not including acquisition costs) and the issuance of 3,496,436 common
>   shares and 7,418,332 preferred shares. The terms of the Series 1 preferred shares are
>   described in note 11. In addition, 460,915 Enterra options were issued in exchange for Big
>   Horn options.



2. Significant accounting policies

> These consolidated financial statements are prepared in accordance
>   with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant
>   differences between Canadian and US GAAP on these consolidated financial statements is
>   disclosed in note 16. These consolidated financial statements include the accounts of
>   Enterra and its subsidiary companies and partnerships in which a controlling interest is
>   retained. All material intercompany accounts and transactions have been eliminated.
>   Substantially all exploration, development and production activities related to our oil
>   and gas business are conducted jointly with others and our accounts reflect only
>   Enterras proportionate interest.
>   (a) Petroleum and natural gas properties
>   The Company follows the "full cost" method of accounting for
>   petroleum and natural gas properties. All costs related to the exploration for and the
>   development of oil and gas reserves are capitalized into a single cost centre representing
>   the Companys activity which is undertaken exclusively in Canada. Costs capitalized
>   include land acquisition costs, geological and geophysical expenditures, lease rentals on
>   undeveloped properties and costs of drilling productive and non-productive wells. Proceeds
>   from the disposal of properties are applied as a reduction of cost without recognition of
>   a gain or loss except where such disposals would result in a major change in the depletion
>   rate.
>   Capitalized costs are depleted and depreciated using the
>   unit-of-production method based on the estimated gross proven oil and natural gas reserves
>   before royalties as determined by independent engineers. Units of natural gas are
>   converted into barrels of equivalents on a relative energy content basis.
>   Capitalized costs, net of accumulated depletion and depreciation, are
>   limited to estimated future net revenues from proven reserves, based on year-end prices,
>   undiscounted, less estimated future abandonment and site restoration costs, general and
>   administrative expenses, financing costs and income taxes.
>   Estimated future abandonment and site restoration costs are provided
>   for over the life of proven reserves on a unit-of-production basis. The annual charge is
>   included in depletion and depreciation expense and actual abandonment and site restoration
>   costs are charged to the provision as incurred. The amounts recorded for depletion and
>   depreciation and the provision for future abandonment and site restoration costs are based
>   on estimates of proven reserves and future costs. The recoverable value of capital assets
>   is based on a number of factors including the estimated proven reserves and future costs.
>   By their nature, these estimates are subject to measurement uncertainty and the impact on
>   financial statements of future periods could be material.

(b) Income taxes

The Company follows the liability method of accounting for future
  income taxes. Under the liability method, future income tax assets and liabilities are
  determined based on "temporary differences" (differences between the accounting
  basis and the tax basis of the assets and liabilities) and are measured using the
  currently enacted, or substantially enacted, tax rates and laws expected to apply when
  these differences reverse. A valuation allowance is recorded against any future income tax
  assets if it is more likely than not that the asset will not be realized. Income tax
  expense or benefit is the sum of the Companys provision for current income taxes and
  the difference between the opening and ending balances of the future income tax assets and
  liabilities.

(c) Financial instruments

The estimated fair value of all financial instruments is based on
  quoted market prices and if not available, on estimates from third-party brokers or
  dealers. The carrying value cash, accounts receivable, deposit, bank indebtedness,
  accounts payable, accrued liabilities, long-term and preferred shares approximates their
  fair value. Company uses financial instruments for non-trading purposes to manage
  fluctuations in commodity prices, as described in note 12. Hedge accounting is used when
  there is a high degree of correlation between price movements in the derivative instrument
  and the item designated as being hedged. The Company recognizes gains and losses in the
  same period as the hedged item. See note 13 for details about the Companys commodity
  hedging activities.

(d) Estimates and assumptions

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

(e) Per share amounts

The Company follows the treasury stock method to determine the dilutive
  effect of stock options and other dilutive instruments. Under the treasury stock method,
  only "in the money" dilutive instruments impact the diluted calculations.

The weighted average number of common shares outstanding during the
  years ended December 31, 2002 and 2001 were 9,154,491 and 6,992,393, respectively. In
  computing diluted earnings per share 258,116 shares (2001  5,114 shares) were added
  to the weighted average number of common shares outstanding during the year as a result of
  the dilutive effect of stock options. See note 10 for a reconciliation of basic and
  diluted earnings per share.

(f) Stock-based compensation

Effective January 1, 2002 the Company prospectively adopted the new
  recommendations of the CICA with respect to the accounting for stock-based compensation
  and other stock-based payments. In accordance with the new standard, the Company elected
  to continue its policy that no compensation is recorded on the granting of employee stock
  options and consideration paid on the exercise of such options is recorded as share
  capital. In addition, the new standard requires a fair value based method of accounting
  for other stock-based payments. See notes 9(d) and 9(e) for additional information with
  regard to the methods and assumptions used in calculating the fair value of stock-based
  compensation.



(g) Revenue recognition

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

> (h) Deferred financing charges
>   Deferred financing charges include costs related to the proposed
>   financing mentioned in note 9(f) and costs related to the capital leases described in note
>   7. These costs include professional and consulting fees, travel costs, legal and
>   accounting, and also include the $125,000 described in note 9(f). These costs are
>   amortized over the remaining life of their related financial instruments.
>   (i) Comparative figures
>   The presentation of certain figures of the previous year has been
>   changed to conform with the presentation adopted for the current year.

3. Business combination

> Effective August 1, 2001 Enterra acquired 100% of the issued and
>   outstanding shares of Big Horn Resources Ltd. Details of the acquisition are as follows:

|Assets acquired:                                                  |            
|----------------------------------------------------------------- | -----------
|Current assets, excluding
      cash                              | $2,841,106 
|Property and equipment                                            | 46,874,349 
|                                                                  | 49,715,455 
|Liabilities assumed:                                              |            
|Current liabilities                                               | 2,428,687  
|Bank indebtedness                                                 | 8,950,000  
|Provision for future
      abandonment and site restoration costs | 280,274    
|Future income tax liability                                       | 11,309,464 
|                                                                  | 22,968,425 
|                                                                  |            
|Net non-cash assets acquired                                      | 26,747,030 
|Cash acquired                                                     | 37,599     
|                                                                  | $26,784,629
|                                                                  |            
|Consideration:                                                    |            
|Cash                                                              | $2,227,647 
|Preferred
      shares (7,418,336 issued)                         | 6,305,586  
|Common shares
      (3,496,436 issued)                            | 18,251,396 
|                                                                  | $26,784,629

The consideration value attributed to the common shares
  contemplates an element related to the former stock options of Big Horn that were
  exchanged for stock options of the Company.  However, this element was not considered
  significant for separate reporting.

4. Investments

> Investments in Red Raven Resources Inc. and Raptor Capital
>   Corporation with an amount of $422,000 were disposed of during 2001 as part of the
>   severence amounts paid to former directors and officers of the Company.

5. Property and equipment

> **December
>       31, 2002****Cost**
>       **Accumulated**
>       **depletion and**
>       **Depreciation**
>       **Net**Petroleum and natural gas properties
>       $ 112,657,277
>       $ 18,897,024
>       $ 93,760,253Office furniture and equipment
>       1,077,988
>       483,928
>       594,060$ 113,735,265
>       $ 19,380,952
>       $ 94,354,313**December
>       31, 2001****Cost**
>       **Accumulated**
>       **depletion and**
>       **Depreciation**
>       **Net**Petroleum and natural gas properties
>       $ 82,574,219
>       $ 9,939,258
>       $ 72,634,961Office furniture and equipment
>       843,464
>       338,928
>       504,536$ 83,417,683
>       $ 10,278,186
>       $ 73,139,497
>   In conducting its 2001 ceiling test evaluation the Company followed
>   generally accepted accounting principles which provide for a two-year exemption from
>   write-down where the purchase price of reserves had been determined on a basis which
>   provided a higher amount than the ceiling test value, and where the excess was not
>   considered to represent a permanent impairment in the ultimate recoverable amount. If the
>   two-year exemption had not been used, the Company would have taken a write-down of $8.1
>   million based on prices at December 31, 2001 of $22.05 per bbl of oil and $3.42 per mcf of
>   gas. Enterra qualified for the exemption in connection of its acquisition of Big Horn in
>   August 2001.
>   In conducting its ceiling test evaluation for 2002 the Company followed
>   generally accepted accounting principles based on prices at December 31, 2002 of $45.89
>   per bbl of oil and $5.49 per mcf of gas. No write-down was required for 2002.
>   Included in the cost of the petroleum and natural gas properties are
>   amounts for capitalized general and administrative expenses. These amounts were $1,450,900
>   in 2002 (2001 - $729,400).
>   At December 31, 2002 costs of undeveloped land of $3,967,000 (2001 - $8,053,000) were
>   excluded from the calculation of depletion expense.
>   The Company estimates future abandonment and site restoration costs to be $4,114,000 at
>   December 31, 2002 (2001 - $3,083,000) of which $232,500 (2001 - $242,000) has been accrued
>   as a liability.

6. Bank indebtedness

> Bank indebtedness represents the outstanding balance under a line of
>   credit of $26,700,000 with the Alberta Treasury Branches. Drawings bear interest at 0.25%
>   above the banks prime lending rate. Security is provided by a first charge over all
>   of the Companys assets. The balance is repayable on demand. While the loan is due on
>   demand, the Company is not subject to scheduled repayments. This loan was classified as a
>   long-term liability in the December 31, 2001 financial statements and has been restated
>   into current liabilities in 2002. Effective for fiscal periods commencing January 1, 2002,
>   the Company adopted the new CICA recommendation regarding Balance Sheet Classification of
>   Callable Debt Obligations and Debt Obligations Expected to be Refinanced. All borrowings
>   where the lender has a right to demand repayment within twelve months are required to be
>   classified as current liabilities. The impact of this change has been to increase current
>   liabilities by the amount of any such borrowings then in place. At December 31, 2002 this
>   change has increased current liabilities by $24,436,640 (December 31, 2001 - $18,408,904).
>   **F-9**

7. Long-term debt

> Assets secured with long-term debt are tangible oil and gas equipment
>   with a cost of $5,217,500. These assets are subject to the depletion provisions described
>   in note 2(a).
>   **Balances
>       as at December 31, 2002**Description
>       **Principal****outstanding**
>       **Less**
>       **current portion**
>       **Net**
>       **Balance**Capital lease bearing interest at 8.605%,
>       repayable monthly at $88,802 plus applicable taxes. The lease term is for 60 months, due
>       October 1, 2007, with a purchase option of $1,000,000
>       $ 4,747,775
>       $ 678,636
>       $ 4,069,139Capital lease bearing interest at 12.15%,
>       repayable monthly at $4,448 plus applicable taxes. The lease term is 24 months due
>       December 19, 2004 with a purchase option of $100
>       91,042
>       47,500
>       43,542Note payable bearing interest at 8%, repayablemonthly
>       at $7,190. The lease term is 15 months due December 20, 2003.
>       82,781
>       82,781
>       -$ 4,921,598
>       $ 808,917
>       $ 4,112,681

8. Income taxes

> The income tax provision is calculated by applying Canadian federal
>   and provincial statutory tax rates to pre-tax income with adjustments as set out in the
>   following table:

|                                                      | **2002**    | **2001**   
|----------------------------------------------------- | ----------- | -----------
|Earnings before income
      taxes                    | $6,020,401  | $2,299,055 
|Combined federal and
      provincial income tax rate | 42.12%      | 42.60%     
|Computed income tax
      provision                   | 2,535,793   | 979,397    
|Increase (decrease)
      resulting from:             |             |            
|Resource allowance                                    | (1,627,200) | (1,211,828)
|Non-deductible Crown
      royalties, net of ARTC     | 1,313,089   | 781,332    
|Non-taxable portion of
      capital gain             | (1,310,552) | -          
|Capital taxes                                         | 132,000     | 120,000    
|Other                                                 | (130)       | 13,099     
|                                                      | $1,043,000  | $682,000   

The components of the net future income tax liability at
  December 31 were as follows:

|                                              | 2002         | 2001        
|--------------------------------------------- | ------------ | ------------
|Future income tax assets:                     |              |             
|Share issue costs                             | $ 647,597    | $ 916,709   
|Future abandonment and site
      restoration | 295,321      | 239,973     
|Deferred gain                                 | 75,015       | 243,236     
|                                              | 1,017,933    | 1,399,918   
|                                              |              |             
|Future income tax
      liabilities:          |              |             
|Property, plant and
      equipment           | 13,088,034   | 12,559,019  
|Net future income tax
      liability         | $ 12,070,101 | $ 11,159,101



At December 31, 2002 the Company had approximately $62,629,000 ( 2001 -
  $43,152,000 ) of tax pools available to reduce future taxable income.

9. Share capital

> (a) Authorized:
>   Unlimited number of voting common shares without nominal or par value.
>   Unlimited number of preferred shares issuable in one or more series
>   (b) Issued:

|                                                                    | **Number of**
      **common shares** | **Amount**  
|------------------------------------------------------------------- | ------------------------------------- | ------------
|                                                                    |                                       |             
|Balance, December 31, 2000                                          | 4,595,139                             | 5,031,846   
|Issued for cash on exercise of options                              | 43,500                                | 99,450      
|Issued for cash pursuant to public offerings                        | 1,035,000                             | 7,081,024   
|Issued on acquisition of property and
      equipment               | 213,047                               | 1,300,000   
|Issued on acquisition of Big Horn Resources
      Ltd.              | 3,496,436                             | 18,251,396  
|Shares repurchased                                                  | (232,500)                             | (753,300)   
|Issue costs incurred, net of income tax
      benefit of $1,118,251 | -                                     | (1,442,153) 
|Balance, December 31, 2001                                          | 9,150,622                             | $ 29,568,263
|Issued for cash on exercise of options                              | 44,511                                | 171,127     
|Shares repurchased                                                  | (18,808)                              | (74,315)    
|Balance, December 31, 2002                                          | 9,176,325                             | $29,665,075 



Contributed surplus is made up of the following amounts:

|                                                                |                      
|--------------------------------------------------------------- | ---------------------
|Balance at January 1, 2002                                      | $
                  -
|Value assigned to 100,000 warrants described
      in note 9(f) | 125,000              
|Loss related to shares repurchased during year                  | (59,971)             
|Balance at December 31, 2002                                    | $ 65,029             

(c) Options:

The Company granted options to purchase common shares to directors, officers, employees
  and consultants. Each option permits the holder to purchase one common share of Enterra at
  the stated exercise price. All options vest over 4 years and are exercisable on a
  cumulative basis over 5 years. At the time of grant, the exercise price is equal to the
  market price. The following options have been granted:



|                                         | **Number of**
      **Options** | **Weighted-average exercise price**
|---------------------------------------- | ------------------------------- | -----------------------------------
|Outstanding at December 31, 2000         | 430,500                         | $5.76                              
|Options granted                          | 990,000                         | $4.41                              
|Options exercised                        | (43,500)                        | $2.29                              
|Options cancelled                        | (577,000)                       | $6.15                              
|Outstanding at December 31, 2001         | 800,000                         | $4.00                              
|Options granted                          | 232,000                         | $5.30                              
|Options exercised                        | (44,511)                        | $3.84                              
|Options cancelled                        | (115,786)                       | $4.03                              
|Options outstanding at December 31, 2002 | 871,703                         | $4.35                              



Of the 232,000 options granted during 2002, 55,000 were
  granted to non-employees (2001  119,500). There were 871,703 options outstanding at
  December 31, 2002. Compensation expense related to these options amounted to $18,000 for
  2002. These options are exercisable at prices ranging from $4.00 to $8.85 and expire on
  dates ranging from November 1, 2006 to December 9, 2007, as follows:

|               | **Outstanding Options**                               |                                                                                        | **Exercisable Options**                                                             
|-------------- | ----------------------------------------------------- | -------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------
|               | **Number of**
      **Options**
      **(thousands)** | **Weighted**
      **Average**
      **Exercise**
      **Price**
      **($/option)** | **Weighted**
      **Average**
      **Years to**
      **Expiry**
      **(years)**
|               |                                                      
|               |                                                      
|               |                                                      
|               |                                                      
|$4.00 to $5.99 | 811                                                   | $ 4.11                                                                                 | 4.0                                                                                 
|$6.00 to $8.85 | 61                                                    | $ 7.31                                                                                 | 4.7                                                                                 
|               | 872                                                   |                                                                                        |                                                                                     

(d) Estimated fair value of stock options

We determine the estimated fair value of stock options issued in 2002
  and 2001 using the Generalized Black-Scholes model under the following assumptions:

|                                                             | **2002** | **2001**
|------------------------------------------------------------ | -------- | --------
|Weighted-average fair value ($/option)                       | $ 2.83   | $ 0.76  
|Risk-free interest rate (%)                                  | 5.0      | 5.0     
|Estimated hold period prior to exercise
      (years)        | 5        | 5       
|Volatility in the price of Enterras
      common shares (%) | 55       | 30      

(e) Pro forma net income  fair value based method of accounting
  for stock options

The following shows pro forma net income and earnings per common share
  had we applied the fair-value

based method of accounting to stock options issued in 2002 and 2001:

|                                              | **2002** | **2001**
|--------------------------------------------- | -------- | --------
|**Net earnings ( in 000s)**                  |          |         
|As reported                                   | $ 4,977  | $ 1,617 
|Less fair value of stock options to employees | (47)     | (27)    
|Pro Forma                                     | $ 4,930  | $ 1,590 
|                                              |          |         
|                                              |          |         
|**Earnings Per Common Share ($/share)**       |          |         
|Basic as Reported                             | $ 0.54   | $ 0.23  
|Pro Forma                                     | $ 0.54   | $ 0.23  
|                                              |          |         
|Diluted as Reported                           | $ 0.53   | $ 0.23  
|Pro Forma                                     | $ 0.52   | $ 0.23  



(f) Warrants:



|                                          | **Number of**
      **Warrants** | **Weighted**
      **average price**
|----------------------------------------- | -------------------------------- | ------------------------------------
|Balance, December 31, 2000                | -                                | -                                   
|Issued pursuant to public offering        | 1,000,000                        | US$ 3.50                            
|Issued pursuant to underwriters agreement | 100,000                          | US$ 5.40                            
|Balance, December 31, 2001                | 1,100,000                        | US$ 3.67                            
|Expired                                   | (1,000,000)                      | US$ 3.50                            
|Issued pursuant to debt financing         | 100,000                          | US$ 2.60                            
|Balance, December 31, 2002                | 200,000                          | US$ 4.00                            



On January 17, 2001, the Company completed a secondary public offering
  in the United States. The offering consisted of 1,000,000 units of one common share and
  one share purchase warrant for U.S. $4.55 per unit. The share purchase warrants were
  exercisable at US$ 3.50 per share. They expired on May 17, 2002. The 100,000 share
  purchase warrants related to the underwriters agreement are exercisable at U.S. $5.40 per
  share starting January 16, 2002 and may be exercised for a four year period thereafter. On
  March 28, 2002 the Company agreed to issue 300,000 share purchase warrants to an
  arms length U.S.-based consulting firm in connection with a potential debt financing
  in the United States. The warrants are to have a two-year term and are subject to
  different pricing (100,000 warrants at US$2.60, 100,000 at US$3.30 and 100,000 at
  US$4.00). The US$2.60 warrants have vested since the execution in May 2002 of a
  non-binding letter of intent relating to the proposed financing. The US$3.30 and US$4.00
  warrants are to vest only on the successful closing and funding of the proposed financing.
  A value of $125,000 was assigned to the 100,000 warrants at US$2.60. This value was
  determined using the Black Scholes Option Pricing model using an interest rate of 5% and a
  volatility factor of 50%. The $125,000 was credited to the Companys contributed
  surplus account.

10. Reconciliation of Earnings per Share Calculations:

> **For the year ended December 31, 2002****Net**
>       **Earnings**
>       **Weighted Average**
>       **Shares Outstanding**
>       **Per**
>       **Share**Basic
>       $4,977,401
>       9,154,491
>       $0.54Options and warrants assumed exercised
>       
>       803,999Shares assumed purchased
>       
>       (545,883)Diluted
>       $4,977,401
>       9,412,607
>       $0.53Excluded from the above calculation are 61,000 options
>   which were "out-of-the-money" in 2002.
>   **For the year ended December 31, 2001****Net**
>       **Earnings**
>       **Weighted Average**
>       **Shares Outstanding**
>       **Per**
>       **Share**Basic
>       $1,617,055
>       6,992,393
>       $0.23Options and warrants assumed exercised
>       
>       46,027Shares assumed purchased
>       
>       (40,913)Diluted
>       $1,617,055
>       6,997,507
>       $0.23

11. Series 1 preferred shares:

> At December 31, 2002 there were 749,047 Series 1 preferred shares
>   outstanding (December 31, 2001  7,418,336). These shares are non-voting. They aretransferable. Subsequent to August 16, 2002 holders of these shares are entitled to
>   receive a fixed cumulative dividend of $0.085 per share per annum, payable quarterly.
>   These shares are redeemable at any time by the Company for $0.85 per share. Holders of
>   these shares may require the Company to redeem all or any of these shares, at $0.85 per
>   share. There is no market for these shares and none is expected to develop. On March 26,
>   2002 the Company purchased 6,123,870 of its Series 1 preferred shares for $2.3 million,
>   resulting in a gain on redemption of $2,905,290. The purchase was paid for with cash of
>   $1,750,000 and a note payable of $550,000. This note was repaid for $325,000 on August 15,
>   2002 resulting in an additional gain, net of legal costs, of $206,181. A dividend of
>   $22,549 was paid on the preferred shares in 2002. This amount is included in interest
>   expense.
>   **F-13**

12. Financial instruments

> Due to the nature of its operation, the Company is exposed to
>   fluctuations in commodity prices, foreign-currency exchange rates, interest rates and
>   credit risk. The Company recognizes these risks and manages its operations to minimize the
>   exposure to the extent practical and, to a lesser extent, using derivative instruments.
>   The company uses non-exchange traded forwards, swaps and options, which may be settled in
>   cash or by delivery of the physical commodity. Management monitors the Companys
>   exposure to the above risks and regularly reviews its derivative activities and all
>   outstanding positions.
>   (i) Commodity prices risks
>   The Companys most significant market risk exposure relates to
>     crude oil prices fluctuation. Crude oil prices and quality differentials are influenced by
>     worldwide factors such as OPEC actions, political events and supply and demand
>     fundamentals.
>     To a lesser extent the Company is also exposed to natural gas price
>     movements. Natural gas prices are generally influenced by North American supply and
>     demand, and to a lesser extent local market conditions.
>   (ii) Foreign currency exchange risk:
>   The Company is exposed to foreign currency fluctuations as crude oil
>     and natural gas prices received are referenced to U.S. dollar denominated prices.
>   (iii) Credit risk:
>   A substantial portion of the Companys accounts receivable are
>     with customers and joint venture partners in the oil and gas industry and are subject to
>     normal industry credit risks. Purchasers of the Companys natural gas, crude oil and
>     natural gas liquids are subject to an internal credit review to minimize the risk of
>     non-payment.
>   (iv) Interest rate risk
>   Interest rate risk exists principally with respect to our indebtedness
>     that bears interest at floating rates. At December 31, 2002, we had $24,436,640 of
>     indebtedness bearing interest at floating rates and $4,921,598 of long-term debt bearing
>     interest at fixed rates.

13. Hedging contracts

> During 2002 and 2001, the Company entered into the following hedges
>   to minimize its exposure to fluctuations in commodity prices relating to its future sales
>   of crude oil and gas. The contracts are as follows:

> (a) The Company entered into a physical zero cost collar arrangement
>   during 2001 which provides a floor price of US$20 per barrel and a ceiling price of US$24
>   per barrel for 500 barrels of oil per day. The contract is effective from November 1, 2001
>   through April 30, 2002.
>   (b)In
>   July 2002, the Company entered into a physical zero cost collar arrangement with a floor
>   price of US$22 per barrel and a ceiling price of US$28 per barrel for 500 barrels of oil
>   per day. The contract is effective from October 1, 2002 through March 31, 2003. At
>   December 31, 2002 this contract had an estimated negative market value of $216,000.
>   **F-14**
>   (c) In July 2002, the Company entered into two contracts to deliver
>   natural gas. One is for 1,500 mcf per day, priced at CA$4.60 per mcf. The other is for
>   1,500 mcf per day, priced at CA$4.45 per mcf. Both contracts are effective from November
>   1, 2002 through March 31, 2003. At December 31, 2002 these contracts had an estimated
>   negative market value of $369,000.

> Effective January 31, 2001, the Company settled a fixed price contract
>   eliminating the requirement to deliver set physical quantities of oil at fixed prices.
>   Upon the cancellation of the contract the Company received approximately $1,680,000, which
>   will be recognized over the term of the contract. At December 31, 2002 the remaining
>   deferred gain related to this settlement was $237,463 (2001 - $761,302).

14. Commitments

> The Company has commitments for the following payments over the next
>   five years:
>   
>   **Thereafter****2003**
>       **2004**
>       **2005**
>       **2006**
>       **2007**Capital lease obligations
>       $1,118,994
>       $1,118,994
>       $1,070,068
>       $1,065,620
>       $1,799,215Note payable
>       86,284Rental payments re-office
>       space
>       447,357
>       429,854
>       165,121
>       114,894$1,652,635
>       $1,548,848
>       $1,235,189
>       $1,180,514
>       $1,799,215

15. Subsequent events



> (a) Subsequent to December 31, 2002 the Company sold some non-core
>   oil and gas properties for proceeds of $4.3 million.
>   (b) Subsequent to December 31, the Company entered into several
>   contracts to deliver 2,000 barrels of oil per day for the period April 1, 2003 and
>   December 31, 2003. The prices and volumes are as follows:
>   
>   **Volumes (in barrels per day)**
>       **Price (in US dollars)**1,000
>       US$29.60250
>       US$29.71250
>       US$29.50500
>       US$29.80**F-15**

16. United States accounting principles and reporting

> The Companys consolidated financial statements have been prepared
>   in Canadian Dollars and in accordance with generally accepted accounting principles in
>   Canada ("Canadian GAAP"), which differ in some respects from those in the United
>   States ("U.S. GAAP"). Any differences in accounting principles as they pertain
>   to the accompanying consolidated financial statements were insignificant except as
>   described below:
>   (a) Property and equipment:
>   The Company performs a cost recovery ceiling test which limits net
>     capitalized costs to the undiscounted estimated future net revenue from proven oil and gas
>     reserves plus the cost of unproven properties less impairment, using year-end prices or
>     average prices in that year, if appropriate. In addition, the value is further limited by
>     including financing costs, administration expenses, future abandonment and site
>     restoration costs and income taxes. Under U.S. GAAP, companies using the "full
>     cost" method of accounting for oil and gas producing activities perform a ceiling
>     test using discounted estimated future net revenue from proven oil and gas reserves using
>     a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this
>     reconciliation were those in effect at the applicable year-end. Financing and
>     administration costs are excluded from the calculation under U.S. GAAP. At December 31,
>     2001 the Company realized a U.S. GAAP ceiling test write-down of $17.5 million (after
>     tax). There was no such write-down at December 31, 2002. As a result of the 2001
>     write-down, the 2002 depletion expense under U.S. GAAP was lower by $2.1 million (after
>     tax).
>   (b) Provision for future abandonment and site restoration:
>   Under U.S. GAAP, the provision for future abandonment and site
>     restoration costs is recorded as a reduction of property and equipment.
>   (c) Financial instruments:
>   FAS 133 requires the company to recognize all derivative instruments on
>     the balance sheet as either an asset or a liability measured at fair value. Changes in the
>     fair value of derivatives are recognized in earnings unless specific hedge criteria are
>     met.
>     The Company routinely enters into physical commodity contracts to
>     minimize its exposure to fluctuations in commodity prices relating to its future sales of
>     crude oil. Such contracts often meet the criteria of FAS 133 as derivatives but are
>     generally eligible for the normal purchase and sale exception under FAS 138,
>     "Accounting for Certain Derivative Instruments and Certain Hedging Activities 
>     An Amendment of FAS 133". Contracts that meet the criteria of this exception are not
>     recognized on the balance sheet as either an asset or a liability measured at fair value.
>     At December 31, 2002 and 2001, under Canadian GAAP, the Company had a
>     deferred gain resulting from the settlement of a fixed price contract, which is being
>     amortized over the term of the contract. Under U.S. GAAP, this gain, net of related income
>     taxes, would be included in income as it did not qualify for hedge accounting under SFAS
>     133.
>   (d) Stock-based compensation:
>   Under U.S. GAAP, SFAS 123 establishes financial accounting and
>     reporting standards for stock-based employee compensation plans as well as transactions in
>     which an entity issues its equity instruments to acquire goods or services from
>     non-employees. During 2001, the Company granted 119,500 stock options to non-employees.
>     Had compensation cost for these stock options been determined based on their fair market
>     value at the grant dates of the awards, the Companys pre-tax income for the year
>     would have decreased by $90,294. The weighted average fair market value of options granted
>     to non-employees in 2002 was $0.76 per option. The fair value of each option granted was
>     estimated on the date of grant using the Black-Scholes option-pricing model with the
>     following assumptions: risk-free interest rate of 5%, volatility of 30% and expected life
>     of five years. After January 1, 2002, stock option issued to non-employee resulted in the
>     same accounting treatment under both Canadian and US GAAP.
>     **F-16**
>   (e) Cash flows
>   Under Canadian GAAP, companies are permitted to present a sub-total
>     prior to changes in non-cash working capital within operating activities. This information
>     is perceived to be useful information for various users of the financial statements and is
>     commonly presented by Canadian public companies. Under U.S. GAAP, this sub-total is not
>     permitted to be shown and would be removed in the statements of cash flows for all periods
>     presented. In addition, cash flow from operations per share figures would not be presented
>     under U.S. GAAP.
>   (f) Balance sheets:
>   The adjustments using U.S. GAAP would result in the following changes
>     to the consolidated balance sheets of the Company:
>   
>   **2002**
>       **2001****Canadian**
>       **GAAP**
>       **U.S.**
>       **GAAP**
>       **Canadian**
>       **GAAP**
>       **U.S.**
>       **GAAP****(restated)**AssetsCurrent assets
>       $ 8,078,752
>       $ 8,078,752
>       $ 6,923,061
>       $ 6,923,061Capital assets (a)(b)
>       94,354,313
>       68,307,526
>       73,139,497
>       43,692,704Deferred financing charges
>       284,040
>       284,040
>       -
>       -$ 102,717,105
>       $ 76,670,318
>       $ 80,062,558
>       $ 50,615,765LiabilitiesCurrent liabilities
>       46,061,986
>       46,061,986
>       $ 9,152,492
>       $ 27,651,690Long-term debt (c)
>       4,112,681
>       4,112,681
>       18,408,904
>       -Future income taxes (a)(d)
>       12,070,101
>       2,485,695
>       11,159,101
>       285,850Provision for future site restoration (b)
>       934,857
>       -
>       751,088
>       -Deferred gain (d)
>       237,463
>       -
>       761,302
>       -Series 1 preferred shares
>       636,690
>       636,690
>       6,305,586
>       6,305,58664,053,778
>       53,297,052
>       46,538,473
>       34,243,126Shareholders equityShare capital
>       29,665,075
>       29,665,075
>       29,568,263
>       29,568,263Contributed surplus
>       65,029
>       155,323
>       -
>       -Retained earnings (deficit)
>       8,933,223
>       (6,447,132)
>       3,955,822
>       (13,195,624)$ 38,663,327
>       23,373,266
>       33,524,085
>       16,372,639$ 102,717,105
>       $ 76,670,318
>       $ 80,062,558
>       $ 50,615,765**F-17**(g) Income statements:
>   The adjustments using U.S. GAAP would result in the following changes
>   to the consolidated financial statements of the Company:
>   
>   **2002**
>       **2001**Net earnings (loss) under Canadian
>       GAAP
>       $ 4,977,401
>       $ 1,617,055Less gain on redemption of
>       preferred shares, net of income tax
>       (3,111,471)
>       -Net earnings before extraordinary
>       items
>       1,865,930
>       1,617,055Adjustments:Full cost accounting (a)
>       -
>       (28,695,705)Related income taxes
>       -
>       11,159,101Hedging gain (c)
>       (523,839)
>       761,302Related income taxes
>       220,641
>       (324,315)Depletion expense (a)
>       3,583,775
>       -Related income taxes
>       (1,509,486)
>       -Stock-based compensation (d)
>       -
>       (90,294)Related income taxes
>       -
>       38,465Net earnings (loss) before
>       extraordinary items under U.S. GAAP
>       3,637,021
>       (15,534,391)Extraordinary items:Gain on redemption of preferred
>       shares, net of income tax
>       3,111,471
>       -Net earnings under U.S. GAAP
>       $ 6,748,492
>       ($ 15,534,391)Net earnings (loss) per share:Basic
>       $ 0.74
>       ($ 2.22)Diluted
>       $ 0.72
>       ($ 2.22)Net impact per share relating to
>       extraordinary items:Basic
>       $ 0.34
>       -Diluted
>       $ 0.33
>       -

**F-18**