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 SECURITIES EXCHANGE 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 reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 _ X__ No____

There were 9,150,622 shares outstanding of the registrant’s Common Stock without par 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 or Plan 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

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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 assets
Cash		$49,966	$43,364
Accounts receivable		7,101,988	6,296,639
Prepaid expenses and deposits		667,577	583,058
		7,819,531	6,923,061
Property and equipment		72,905,530	73,139,497
Deferred financing charges		239,000	-
		$80,964,061	$80,062,558
Liabilities
Current liabilities
Accounts payable and accrued liabilities		$8,821,932	$8,989,389
Income taxes payable		121,393	163,103
Note payable (note 2)		550,000	-
Bank indebtedness (note 5)		21,143,550	18,408,904
		30,636,875	27,561,396
Provision for future abandonment and site restoration costs		731,588	751,088
Future income tax liability		11,208,101	11,159,101
Deferred gain		613,378	761,302
Series 1 preferred shares (note 2)		1,100,297	6,305,586
		44,290,239	46,538,473
Shareholders’ Equity
Share capital		29,568,263	29,568,263
Retained earnings		7,105,559	3,955,822
		36,673,822	33,524,085
		$80,964,061	$80,062,558
Approved on behalf of the Board :
Reg Greenslade	Walter Dawson
Director	Director
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	707,711
Production	1,717,731	1,370,757
General and administrative	246,460	256,728
Interest on long-term debt	208,123	40,219
Depletion, depreciation and future site restoration	2,290,000	948,600
	5,271,573	3,324,015
Earnings before the following	326,447	964,364
Gain on redemption of preferred shares	2,905,290	-
Earnings before income taxes	3,231,737	964,364
Income taxes :
Current	33,000	114,000
Future	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	$ 0.11
Diluted	$ 0.34	$ 0.11
See accompanying notes to consolidated financial statements

 

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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	$610,364
Add non-cash items :
Depletion and depreciation	2,290,000	948,600
Future income taxes	49,000	240,000
Deferred gain	-	1,680,031
Amortization of deferred gain	(147,924)	(189,651)
Gain on redemption of preferred shares	(2,905,290)	-
Funds from operations	2,435,523	3,289,344
Net change in non-cash working capital items :
Accounts receivable	(805,349)	701,352
Prepaid 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)	2,513
Cash, beginning of period	43,364	1,443
Cash, end of period	($189,034)	$3,956
Funds from operations per share :
Basic	$0.27	$0.60
Future	$0.27	$0.60
During 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

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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 by management in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods used in preparing the consolidated financial statements for the fiscal year ended December 31, 2001, except as described below, and should be read in conjunction with those statements. The other disclosures below are incremental to those reflected in the annual statements.

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.

 

 

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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.

 

 

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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	$ 4,288
Royalties, net of ARTC	809	708
Production expenses	1,718	1,371
General and administrative expenses	246	257
Interest	208	40
Depreciation and depletion	2,290	949
	5,271	3,325
Earnings from operations	$ 327	$ 963
Net earnings for the year	$ 3,150	$ 610
Basic 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	$ 43
Accounts receivable and prepaids	7,770	6,880
Capital assets	72,906	73,139
Total assets	80,964	80,063
Total shareholders’ equity	36,674	33,524

 

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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	2001
End of period	0.62708	0.63465	0.62869
Average for the three months ended	0.62738	0.65514	N/A
High during the three months ended	0.63550	0.67140	N/A
Low during the three months ended	0.61750	0.63290	N/A

 

 

 

 

 

 

 

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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

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

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.

 

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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.

 

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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)

 

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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.

 

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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.

 

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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.

 

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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.

 

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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

 

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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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