UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-QSB

> 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2002

OR

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIESEXCHANGE ACT OF 1934

Commission file number 000-32115

ENTERRA ENERGY CORP. 

(Exact name of registrant as specified in its charter)

|  | **Alberta, Canada**n/a**(State or other jurisdiction of incorporation or organization)**(I.R.S. Employer    Identification No.)**Suite 2600, 500 – 4th Avenue S.W.

Calgary, Alberta, Canada**T2P 2V6**(Address of principal    executive offices)**(Zip Code)**403-263-0262

Registrant’s telephone number, including area code)

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

Yes _ X__ No____

There were 9,150,622 shares outstanding of the registrant’s Common Stock withoutpar value as of March 31, 2002.

 

ENTERRA ENERGY CORP. 
**INDEX**Page No.**PART I – FINANCIAL    INFORMATION**Item l. Financial Statements    (Unaudited):****Consolidated Balance Sheets at    March 31, 2002 and December 31, 2001****3**Statements of Earnings and    Retained Earnings - Three months ended March 31, 2002 and 2001****4**Statements of Cash Flows -    Three months ended March 31, 2002 and 2001****5**Notes to Consolidated Financial    Statements****6**Item 2. Management’s    Discussion and Analysis orPlan of Operations****10
 

 ** 

 

PART II – OTHER INFORMATION**Item 1. Legal Proceedings**
**19****Item 2. Changes in Securities    and Use of Proceeds****19****Item 3. Defaults Upon Senior    Securities****19****Item 4. Submission of Matters    to a Vote of Security Holders****19****Item 5. Other Information****19****Item 6. Exhibits and Reports on    Form 8-K****19****Signatures****20**
**- 2 -**

 

 
**PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS****ENTERRA ENERGY CORP.****Consolidated Balance Sheets***(Expressed in Canadian dollars)***March 31
**December 31****2002
**2001****(Unaudited)**Assets**Current assetsCash**$49,966
$43,364Accounts receivable**7,101,988
6,296,639Prepaid expenses and deposits**667,577
583,058**7,819,531
6,923,061Property and equipment **72,905,530
73,139,497Deferred financing charges**239,000
-**$80,964,061
$80,062,558**Liabilities**Current liabilitiesAccounts payable and accrued    liabilities**$8,821,932
$8,989,389Income taxes payable**121,393
163,103Note payable (note 2)**550,000
-Bank indebtedness (note 5)**21,143,550
18,408,904**30,636,875
27,561,396Provision for future abandonment    and site restoration costs**731,588
751,088Future income tax liability**11,208,101
11,159,101Deferred gain **613,378
761,302Series 1 preferred shares (note 2)**1,100,297
6,305,586**44,290,239
46,538,473**Shareholders’ Equity**Share capital**29,568,263
29,568,263Retained earnings**7,105,559
3,955,822**36,673,822
33,524,085**$80,964,061
$80,062,558Approved on behalf of the Board :Reg GreensladeWalter DawsonDirectorDirector*See accompanying notes to consolidated    financial statements*
**- 3 -**

 **ENTERRA ENERGY CORP.****Consolidated Statements of    Earnings and Retained Earnings****Three Months Ended March 31***(Expressed in Canadian dollars)**(Unaudited)***2002
**2001****Revenue**Oil and gas**$5,598,020
$4,288,379**Expenses**Royalties, net of ARTC**809,259
707,711Production**1,717,731
1,370,757General and administrative**246,460
256,728Interest on long-term debt**208,123
40,219Depletion, depreciation and future site    restoration**2,290,000
948,600**5,271,573
3,324,015**Earnings before the following****326,447
964,364Gain on redemption of preferred shares**2,905,290
-**Earnings before income taxes****3,231,737
964,364Income taxes :Current**33,000
114,000Future **49,000
240,000**82,000
354,000**Net earnings****3,149,737
610,364**Retained earnings, beginning of period****3,955,822
2,338,767**Retained earnings, end of period****$7,105,559
$2,949,131**Earnings per share :**Basic**$ 0.34
$ 0.11Diluted**$ 0.34
$ 0.11*See accompanying notes to consolidated    financial statements*
 

**- 4 -**

 
**ENTERRA ENERGY CORP.****Consolidated Statements of Cash    Flows****Three Months Ended March 31***(Unaudited)***2002
**2001****Cash provided by (used in) :****Operations**Net earnings**$3,149,737
$610,364Add non-cash items :Depletion and depreciation**2,290,000
948,600Future income taxes **49,000
240,000Deferred gain**-
1,680,031Amortization of deferred gain**(147,924)
(189,651)Gain on redemption of preferred    shares**(2,905,290)
-Funds from operations**2,435,523
3,289,344Net change in non-cash working    capital items :Accounts receivable**(805,349)
701,352Prepaid expenses**(323,519)
(31,350)Accounts payable and accrued    liabilities**(167,457)
(2,520,796)Income taxes payable**(41,710)
114,000**1,097,488
1,552,550**Financing**Bank indebtedness**2,734,646
(1,968,000)Deferred financing charges**(239,000)
-Issue of common shares, net of    issue costs**-
6,269,028**2,495,646
4,301,028**Investing**Capital assets additions**(2,798,688)
(5,851,065)Proceeds on disposal of property    and equipment**731,656
-Redemption of preferred shares**(1,750,000)
-Future abandonment and site    restoration costs**(8,500)
-**(3,825,532)
(5,851,065)Increase in cash**(232,398)
2,513Cash, beginning of period**43,364
1,443**Cash, end of period****($189,034)
$3,956**Funds from operations per share    :**Basic**$0.27
$0.60Future**$0.27
$0.60During the three months ended    March 31, 2002 the Company paid $208,123 (2001 - $40,219) of interest on bank debt*See accompanying notes to    consolidated financial statements*****- 5 -**

**Enterra energy corp.**

Notes to Consolidated Financial Statements

For the Three Months ended March 31, 2002 and 2001

(Unaudited)

The interim consolidated financial statements have been prepared bymanagement in accordance with Canadian generally accepted accounting principles. Theinterim consolidated financial statements have been prepared following the same accountingpolicies and methods used in preparing the consolidated financial statements for thefiscal year ended December 31, 2001, except as described below, and should be read inconjunction with those statements. The other disclosures below are incremental to thosereflected in the annual statements.
**1. Significant accounting policies**
(a) Capital assets 

As disclosed in the December 31, 2001 financial statements, the Company  has changed its method of accounting for petroleum and natural gas properties from the  "successful efforts" method to the "full cost" method. The full cost  method has been adopted retroactively and prior financial statements have been restated.  There was no impact of this change on the March 31, 2001 consolidated income statement.
** **
**2.****Series 1 preferred shares:**

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. The note  payable bears no interest and is due December 31, 2002. As at March 31, 2002 there were  1,294,466 Series 1 preferred shares outstanding. These shares are non-voting. They are****transferable. Holders of these shares are not entitled to receive any dividends  until the first anniversary of the date of issue. 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, at any time following the first  anniversary of the date of issue (August 16, 2001). There is no market for these shares  and none is expected to develop.

 
**3. Warrants**
On March 28, 2002 the Company agreed to issue 400,000 share  purchase warrants to an arm’s length U.S.-based consulting firm in connection with a  potential debt financing in the United States. The warrants are to have a two-year term  and are subject to different pricing (100,000 warrants at US$2.60, 100,000 at US$3.30 and  200,000 at US$4.00). The US$2.60 warrants are to vest upon the execution of a non-binding  letter of intent relating to the proposed financing. The US$3.30 and US$4.00 warrants are  to vest only on the successful closing and funding of the proposed financing.

 

 

**- 6 -**
**4. 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 grant of employee stock  options and consideration paid on the exercise of such options is recorded as share  capital. In addition, the new standard requires a fair value based method of accounting  for other stock-based payments. Had compensation expense for the Company’s  stock-based compensation plan been determined based on the fair value at the grant dates  for awards under the plan after January 1, 2002, the Company’s net income and  earnings per share would have been the same as those reported as there were no stock  options issued during the quarter.
**5. Bank indebtedness**
Bank indebtedness represents the outstanding balance under a line  of credit of $21,500,000 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. However, 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 12  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 March 31, 2002, this change has increased current liabilities by $21,143,550 and  reduced long-term debt by a corresponding amount.

The Company is currently not subject to principal repayments and no  payments are required in 2002.

 

 

**- 7 -**

 
**SUMMARY CONSOLIDATED FINANCIAL DATA**
The following table presents a summary of our  consolidated statement of operations derived from our financial statements for the three  months ended March 31, 2002 and 2001. The monetary amounts in the table are based on  Canadian GAAP. All data presented below should be read in conjunction with the  "Management’s Discussion and Analysis of Financial Condition and Results of  Operations" and our financial statements and accompanying notes included elsewhere in  this Form 10-QSB.
**Consolidated statements of operations data:*****(In thousand’s, except per share      data)*****Three Months      Ended June 30**Three Months      Ended June 30**2002**2001**C$**C$Net revenue
$ 5,598
$ 4,288Royalties, net of ARTC
809
708Production expenses
1,718
1,371General and administrative expenses
246
257Interest
208 
40Depreciation and depletion
2,290 
949
5,271
3,325Earnings from operations
$ 327 
$ 963Net earnings for the year
$ 3,150
$ 610Basic earnings per share
$ 0.34
$ 0.11
 

The following table indicates a summary of our  consolidated balance sheets as of March 31, 2002 and December 31, 2001. The monetary  amounts in the table are based on Canadian GAAP. 
**Consolidated balance sheet data:*****(In thousand’s)*****March 31**December 31**2002**2001**C$**C$Cash and short term investments
$ 50
$ 43Accounts receivable and prepaids
7,770
6,880Capital assets
72,906
73,139Total assets
80,964
80,063Total shareholders’ equity
36,674
33,524** 

**- 8 -**

 

 

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. **March 31**March 31**December 31**2002**2001**2001End of period
0.62708
0.63465
0.62869Average for the three months ended
0.62738
0.65514
N/AHigh during the three months ended
0.63550
0.67140
N/ALow during the three months ended
0.61750
0.63290
N/A
 
** 

 

 

 

 

 

 

**- 9 -**

** **

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL  CONDITION AND RESULTS OF OPERATIONS.**
The following discussion of our results of operations and financial  condition should be read in conjunction with the financial statements and other financial  information included in this annual report. The statements that relate to matters that are  not historical facts are "forward-looking statements". Words such as  "anticipate", "believe", "expect", "plan",  "intend", "estimate", "project", "will",  "should" "could", "may", "predict" and similar  expressions are intended to identify forward-looking statements. Future events and actual  results may differ materially from the results set forth in or implied in the  forward-looking statements. Factors that might cause such a difference such as those  discussed under "Risk factors" and elsewhere, include:
- fluctuations in worldwide prices of oil and natural gas and demand for oil and natural        gas; fluctuations in levels of oil and gas exploration and development activities;
the existence of competitors, technological changes and developments in the industry;
the existence of operating risks and hazards inherent in the industry, such as blowouts,        oil spills, fires, adverse weather, natural disasters, injury to third parties, oil spills        and other environmental damages;
the existence of regulatory uncertainties;
possible insufficient liquidity to meet the Company’s expansion plans; and
general economic conditions.

The following discussion is to inform you about our financial  conditions, liquidity and capital resources as of March 31, 2002 and December 31, 2001 and  the results of operations for the three months ended March 31, 2002 and 2001. The  information is expressed in Canadian dollars.**Three Months Ended March 31, 2002 Compared to Three Months  Ended June 30, 2001

Financial Condition, Liquidity and Capital Resources**
At March 31, 2002 Enterra’s working capital was a deficit of  $22.8 million (December 31, 2001 - $2.2 million). Included as part of current liabilities  at March 31, 2002 is bank debt of $21.1 million (December 31, 2001 - NIL). The  Company’s bank debt now appears on our balance sheet as a current liability. This  same bank debt was classified as a long-term liability at December 31, 2001. Nothing has  changed with the nature or the terms of our banking arrangement with our lender. The  reclassification of our bank debt from long-term liability to current liability is the  result of new Canadian accounting rules which came into effect January 1, 2002. These  rules specify that all borrowings where, among other things, the lender has a right to  demand repayment within 12 months (which is the case with our revolving production  facility) are to be classified as current liabilities. We are not subject to principal  repayments under our banking arrangement. Other than the in the event of a default or a  breach of covenants, our lender has advised us that no principal payments are required in  2002.

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

Cash flow from operations for the three months ended March 31, 2002 was  $2.4 million (2001 - $3.3 million) for a 26% decrease. The Company received approximately  $1.68 million in the first quarter of 2001 upon the settlement of a hedging contract.  Without that one-time cash inflow, the 2002 cash flow would have been 35% higher than in  2001.

 
****- 10 -**

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 March 31, 2002 was $21.1 million (December  31, 2001 - $18.4 million). Our bank debt is used to acquire capital assets and support  ongoing operations. At March 31, 2002 Enterra’s bank facility consisted of a line of  credit of $21.5 million (December 31, 2001 - $21.5 million) of which $21.1 million was  drawn (December 31, 2001 - $18.4 million). Interest on amounts drawn is based on the  bank’s prime rate plus 0.25%.

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

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

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

The Company has in excess of $45 million in tax pools available at  March 31, 2002.
**The bank debt to equity ratio at March 31, 2002 was 0.58 to 1 (    December 31, 2001 – 0.55 to 1 ).
**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 three months period ended March 31, 2002  were $2.8 million (2001 - $5.9 million). Drilling activity has been minimal in the first  quarter of 2002. Most of Enterra’s capital expenditures have been for land ,  equipment upgrades and workovers. 

Proceeds on disposal of oil and gas properties were $731,656 for the  three months ended March 31, 2002 (2001 – NIL). These properties sold were non-core  minor properties. 

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. The note payable bears no interest  and is due December 31, 2002. As at March 31, 2002 there were 1,294,466 Series 1 preferred  shares outstanding.

 
****- 11 -**

Results of Operations**
Gross revenue for the three months ended March 31, 2002 was $5.6  million (2001 - $4.3 million) for a 31% increase. The impact of the higher 2002 production  volumes was mitigated by the lower commodity prices in 2002. Production volumes for the  three months ended March 31, 2002 were 2,422 boe/day (2001 – 1,232 boe/day) for a 97%  increase. However, prices declined on average by 34% over the same period, reducing the  revenue increase to only 31%.

Average oil prices declined by 27% during the first quarter of 2002 and  average gas prices declined by 60% compared to the same period in 2001. The Company  received an average of $27.57 per barrel for its oil production during the three months  ended March 31, 2002, compared with $37.72 in 2001. The Company received an average of  $3.59 per mcf for its natural gas production during the three months ended March 31, 2002,  compared with $8.93 in 2001. As a result, Enterra’s revenue per boe declined by  $13.00 (or 34%) per boe in the first quarter of 2002 compared to 2001.

Royalties for the three months ended March 31, 2002 were $809,259 (2001  - $707,711). As a percentage of oil and gas revenues, royalties were 14% for the three  months ended March 31, 2002 (2001 – 17%). 

Operating expenses for the three months ended March 31, 2002 were $1.7  million (2001 - $1.4 million) This increase is the result of the increased production in  2002. On a barrel of oil equivalent basis operating costs for the three months ended March  31, 2002 were $7.88 (2001 - $12.37) This 36% decrease is mainly due to the Company’s  focus on cost reduction during the first quarter of 2002. By consolidating the operations  of Enterra and Big Horn, the Company was able to achieve significant reduction in  operating expenses. 

General and administrative expenses for the three months ended March  31, 2002 were $246,460 (2001 - $256,728). On a barrel of oil equivalent basis  administrative costs were $1.13 for the three months ended March 31, 2002 (2001 - $2.32).  The 51% decrease is a direct result of the synergies from the Big Horn merger.

Interest expense for the three months ended March 31, 2002 was $208,123  (2001 - $ 40,219). The increase in interest expense is due to higher debt levels in 2002.

Depletion and depreciation for the three months ended March 31, 2002  was $2.3 million (2001 - $948,600). The increase reflects the higher cost base in our  capital assets in 2002.

Current and future income tax expense for the three months ended March  31, 2002 were $33,000 and $49,000 respectively (2001 – $114,000 and $240,000). The  higher level of income taxes in 2001 is due to the gain on settlement of hedges (which  occurred in the first quarter of 2001, thereby increasing the income of Enterra for tax  purposes) and to the fact that there were fewer tax pools available to Enterra in 2001.  The future income tax expenses are calculated based on the timing of deductions for  accounting purposes and tax on petroleum and gas assets. 

The Company’s earnings were $3.1 million for the three months  ended March 31, 2002 (2001 - $610,364) for an increase of 416%. This large increase was  caused by a $2.9 million gain on redemption of preferred shares, which occurred in the  first quarter of 2002. Enterra redeemed 6,123,870 of its Series 1 preferred shares with a  face redemption price of $5,205,290 for $2.3 million, resulting in a gain of $2,905,290.  Without this gain, earnings for the three months ended March 31, 2002 would have been  $244,447, a decrease of 60% over 2001. The lower earnings in 2002 are due to lower prices  and higher depletion charges.

Earnings per share for the three months ended March 31, 2002 were $0.34  (2001 - $0.11). The weighted average number of shares outstanding for the three months  ended March 31, 2002 was 9,150,622 (2001 – 5,470,245). Without the $2.9 million gain  on redemption of preferred shares the earnings per share for the three months ended March  31, 2002 would have been $0.03.

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

 
****- 12 -**

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 grant of employee stock  options and consideration paid on the exercise of such options is recorded as share  capital. In addition, the new standard requires a fair value based method of accounting  for other stock-based payments. Had compensation expense for the Company’s  stock-based compensation plan been determined based on the fair value at the grant dates  for awards under the plan after January 1, 2002, the Company’s net income and  earnings per share would have been the same as those reported as there were no stock  options issued during the quarter.

 
**Factors That May Affect Future Results

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

We have a working capital deficiency at March 31, 2002; our Credit facilities can be  called at any time.**
At March 31, 2002, we had a working capital deficiency of $22.8  million, which means our current liabilities exceeded our current assets by that amount.  Our credit facilities are all on a demand basis and could be called for repayment at any  time.
**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. 

 
****- 13 -**

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 which 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.
**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.

****- 14 -******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 would have realized a U.S. GAAP ceiling test write-down  of C$17.5 million (after tax). Lower prices may also reduce the amount of crude oil and  natural gas that we can produce economically.
We may enter into hedge agreements and other financial arrangements at  various times to attempt to minimize the effect of crude oil and natural gas price  fluctuations. We cannot assure you that such transactions will reduce risk or minimize the  effect of any decline in crude oil or natural gas prices. Any substantial or extended  decline in crude oil or natural gas prices would have a material adverse effect on our  business and financial results. Hedging activities may limit the risk of declines in  prices, but such arrangements may also limit additional revenues from price increases. 

 

****- 15 -******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.

The Company performs a cost recovery ceiling test which limits net  capitalized costs to the undiscounted estimated future net revenue from proven oil and gas  reserves plus the cost of unproven properties less impairment, using year-end prices or  average prices in that year, if appropriate. In addition, the value is further limited by  including financing costs, administration expenses, future abandonment and site  restoration costs and income taxes. Under U.S. GAAP, companies using the "full  cost" method of accounting for oil and gas producing activities perform a ceiling  test using discounted estimated future net revenue from proven oil and gas reserves using  a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this  reconciliation were those in effect at the applicable year-end. Financing and  administration costs are excluded from the calculation under U.S. GAAP. At December 31,  2001 the Company would have realized a U.S. GAAP ceiling test write-down of $17.5 million  (after tax).

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

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

 

****- 16 -******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:
- 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.

 

****- 17 -****
**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.
** 

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.

 

****- 18 -****
** 

PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Not Applicable.
**ITEM 2. CHANGES IN SECURITIES.**
Not Applicable.
**ITEM 3. DEFAULTS UPON SENIOR SECURITIES.**
Not Applicable.
**ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.**
Not Applicable
**ITEM 5. OTHER INFORMATION.**
Not Applicable.
**ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.****Exhibits**
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.**Reports on Form 8-K – None**
 

****- 19 -****
** 

SIGNATURES**
Pursuant to the requirements of the  Securities Exchange Act of 1934, the registrant has duly caused this report to be signed  on its behalf by the undersigned thereunto duly authorized.
**Date: August 26, 2002 Enterra Energy Corp.**
**/s/ Luc Chartrand
__________________________________

Luc Chartrand
Chief Financial Officer

(Duly Authorized Officer and Principal

Financial and Accounting Officer)

 

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