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 September 30, 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 9,160,624 shares outstanding of the registrant’s Common Stock without par value as of September 30, 2002.

                                                          

		ENTERRA ENERGY CORP. INDEX	Page No.
		PART I – FINANCIAL INFORMATION
Item l. Financial Statements (Unaudited):
	Consolidated Balance Sheets at September 30, 2002 and December 31, 2001		3
	Consolidated Statements of Earnings and Retained Earnings - Three and nine months ended September 30, 2002 and 2001		4
	Consolidated Statements of Cash Flows - Three and nine months ended September 30, 2002 and 2001		5
	Notes to Consolidated Financial Statements		6
Item 2. Management’s Discussion and Analysis or Plan of Operations			12
Item 3. Controls and Procedures			23
		PART II – OTHER INFORMATION
Item 1. Legal Proceedings			24
Item 2. Changes in Securities and Use of Proceeds			24
Item 3. Defaults Upon Senior Securities			24
Item 4. Submission of Matters to a Vote of Security Holders			24
Item 5. Other Information			24
Item 6. Exhibits and Reports on Form 8-K			24
Signatures			25

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENTERRA ENERGY CORP.
Consolidated Balance Sheets
(Expressed in Canadian dollars)
		September 30	December 31
		2002	2001
		(Unaudited)
Assets
Current assets
Cash		$25,614	$43,364
Accounts receivable		5,437,429	6,296,639
Prepaid expenses and deposits		559,590	583,058
		6,022,633	6,923,061
Capital assets		77,378,035	73,139,497
Deferred financing charges (note 5)		774,858	-
		$84,175,526	$80,062,558
Liabilities
Current liabilities
Accounts payable and accrued liabilities		$9,105,183	$8,989,389
Income taxes payable		122,404	163,103
Bank indebtedness (note 3)		23,256,640	18,408,904
		32,484,227	27,561,396
Provision for future abandonment and site restoration costs		807,106	751,088
Future income tax liability		11,710,101	11,159,101
Deferred gain		320,604	761,302
Series 1 preferred shares (note 2)		907,294	6,305,586
		46,229,332	46,538,473
Shareholders’ Equity
Share capital (note 4)		29,603,063	29,568,263
Contributed surplus (note 4)		125,000	-
Retained earnings		8,218,131	3,955,822
		37,946,194	33,524,085
Hedging Contracts (note 7)
Subsequent Event (note 8)
		$84,175,526	$80,062,558
Approved on behalf of the Board :
Reg Greenslade	Walter Dawson
Director	Director
See accompanying notes to consolidated financial statements

 

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ENTERRA ENERGY CORP.
Consolidated Statements of Earnings and Retained Earnings
Three and Nine Months Ended September 30
(Expressed in Canadian dollars)
(Unaudited)
	Three Months September 30 2002	Three Months September 30 2001	Nine Months September 30 2002	Nine Months September 30 2001
Revenue
Oil and gas	$5,036,083	$6,325,625	$15,685,635	$15,284,203
Expenses
Royalties, net of ARTC	868,779	1,062,923	2,481,927	2,490,018
Production	916,572	1,830,535	3,682,799	4,230,935
General and administrative	380,189	158,999	1,176,818	668,393
Interest on long-term debt	268,597	262,221	705,253	405,285
Depletion, depreciation and site restoration	1,748,000	2,020,412	5,838,000	4,037,912
	4,182,137	5,335,090	13,884,797	11,832,543
Earnings before the following	853,946	990,535	1,800,838	3,451,660
Restructuring charges	-	(142,167)	-	(863,817)
Gain on redemption of preferred shares (note 2)	206,181	-	3,111,471	-
Earnings before income taxes	1,060,127	848,368	4,912,309	2,587,843
Income taxes :
Current (recovery)	33,000	(595,094)	99,000	279,046
Future	313,000	795,831	551,000	580,375
	346,000	200,737	650,000	859,421
Net earnings	714,127	647,631	4,262,309	1,728,422
Retained earnings, beginning of period	7,504,004	3,419,558	3,955,822	2,338,767
Retained earnings, end of period	$8,218,131	$4,067,189	$8,218,131	$4,067,189
Earnings per share :
Basic	$ 0.08	$ 0.09	$ 0.47	$0.28
Diluted	$ 0.08	$ 0.09	$ 0.46	$0.28
See accompanying notes to consolidated financial statements

 

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ENTERRA ENERGY CORP.
Consolidated Statements of Cash Flows
Three and Nine Months Ended September 30
(Expressed in Canadian dollars)
(Unaudited)	Three Months September 30 2002	Three Months September 30 2001	Nine Months September 30 2002	Nine Months September 30 2001
Cash provided by (used in) :
Operations
Net earnings	$714,127	$647,631	$4,262,309	$1,728,422
Add non-cash items :
Depletion, depreciation and site restoration	1,748,000	2,020,412	5,838,000	4,037,912
Future income taxes	313,000	795,831	551,000	580,375
Deferred gain	-	-	-	1,680,031
Amortization of deferred gain	(145,845)	(286,724)	(440,698)	(764,868)
Gain on redemption of preferred shares	(206,181)	-	(3,111,471)	-
Funds from operations	2,423,101	3,177,150	7,099,140	7,261,872
Net change in non-cash working capital items :
Accounts receivable	614,439	237,448	859,210	1,021,126
Prepaid expenses and deposits	39,018	(171,847)	23,468	(193,774)
Accounts payable and accrued liabilities	5,645,902	1,868,818	115,794	(917,502)
Income taxes payable	33,001	(625,094)	(40,699)	(1,067,125)
	8,755,461	4,486,475	8,056,913	6,104,597
Financing
Bank indebtedness	2,125,000	(2,378,360)	4,847,736	(181,360)
Deferred financing charges	(26,985)	-	(649,858)	-
Issue of common shares, net of issue costs	24,000	(155,942)	34,800	5,608,533
Redemption of preferred shares	(536,821)	-	(2,286,821)	-
	1,585,194	(2,534,302)	1,945,857	5,427,173
Investing
Capital assets	(10,636,246)	(1,884,146)	(16,210,086)	(9,728,213)
Acquisition of Big Horn Resources Ltd.	-	(477,665)	-	(2,190,048)
Investments	-	422,000	-	422,000
Proceeds on disposal of capital assets	262,548	-	6,219,548	-
Future abandonment and site restoration costs	(19,128)	14	(29,982)	(5,314)
	(10,392,826)	(1,939,797)	(10,020,520)	(11,501,575)
Increase (decrease) in cash	(52,171)	12,376	(17,750)	30,195
Cash, beginning of period	77,785	19,262	43,364	1,443
Cash, end of period	$25,614	$31,638	$25,614	$31,638
Funds from operations per share :
Basic	$0.27	$0.42	$0.78	$ 1.16
Diluted	$0.26	$0.42	$0.77	$ 1.16
During the three and nine months ended September 30, 2002 the Company paid respectively $257,496 and $694,152 (2001 -$262,221and $405,285) of interest on bank debt. There were no income taxes paid in the three and nine months ended September 30, 2002 and 2001.
See accompanying notes to consolidated financial statements

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Enterra energy corp.

Notes to Consolidated Financial Statements

For the Three and Nine Months ended September 30, 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. Changes in 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. The impact on the 2001 results was not significant. There was no impact of this change on the consolidated statements of earnings and retained earnings for the three and nine months ended September 30, 2002.

(b) 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. 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 earnings and earnings per share would not have been materially different than those reported.

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. This note was repaid for $325,000 on August 15, 2002 resulting in an additional gain, net of legal costs, of $206,181. An additional 227,061 preferred shares were repurchased during the third quarter for $193,002. As at September 30, 2002 there were 1,067,405 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. A dividend of $11,101 was paid on the preferred shares in the quarter ended September 30, 2002. This amount is included in interest expense.

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3. Bank indebtedness :

Bank indebtedness represents the outstanding balance under a line of credit of $24,000,000 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 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 September 30, 2002 this change has increased current liabilities by $23,256,640 and reduced long-term debt by a corresponding amount.

 

4. Share Capital :

(a) Issued :

 

(b) Options :

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(c) 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 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.

5. Deferred Financing Charges

Deferred financing charges include costs related to the proposed financing mentioned in note 4(c). These costs include professional and consulting fees, travel costs, legal and accounting, and also include the $125,000 described in note 4(c).

 

6. Reconciliation of Earnings per Share Calculations :

Excluded from the above calculation are 35,000 options which were "out-of-the-money" for the three months ended September 30, 2002

Excluded from the above calculation are 59,000 options which were "out-of-the-money" for the nine months ended September 30, 2002

 

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7. Hedging Contracts :

(a) 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.

(b) 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.

8. Subsequent event :

On October 1, 2002 the Company closed a sale-leaseback arrangement on some of its production and processing equipment for $5 million. The lease agreement calls for 60 monthly payments of $88,802, with an option to purchase of $1 million on the last day of the 60^th month. This arrangement will be accounted for as a capital lease.

 

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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 and nine months ended September 30, 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 September 30	Three Months Ended September 30	Nine Months Ended September 30	Nine Months Ended September 30
	2002	2001	2002	2001
	C$	C$	C$	C$
Revenue	$ 5,036	$ 6,326	$ 15,686	$ 15,284
Royalties, net of ARTC	869	1,063	2,482	2,490
Production expenses	917	1,831	3,683	4,231
General and administrative expenses	380	159	1,177	668
Interest on long-term debt	268	262	705	405
Depreciation, depletion and site restoration	1,748	2,020	5,838	4,038
	4,182	5,335	13,885	11,832
Earnings from operations	$ 854	$ 991	$ 1,801	$ 3,452
Net earnings for the period	$ 714	$ 648	$ 4,262	$ 1,728
Basic earnings per share	$ 0.08	$ 0.09	$ 0.47	$ 0.28

 

The following table indicates a summary of our consolidated balance sheets as of September 30, 2002 and December 31, 2001. The monetary amounts in the table are based on Canadian GAAP.

Consolidated balance sheet data:

(In thousand’s)
	September 30	December 31
	2002	2001
	C$	C$
Cash	$ 26	$ 43
Accounts receivable and prepaids	5,997	6,880
Capital assets	77,378	73,139
Total assets	84,176	80,063
Total shareholders’ equity	37,946	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.

	September 30	September 30	December 31
	2002	2001	2001
End of period	0.64589	0.69714	0.62869
Average for the three months ended	0.65139	0.72812	N/A
High during the three months ended	0.67490	0.78960	N/A
Low during the three months ended	0.63370	0.68590	N/A
Average for the nine months ended	0.68902	0.72672	N/A
High during the nine months ended	0.73430	0.78960	N/A
Low during the nine months ended	0.63370	0.68590	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 quarterly 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 September 30, 2002 and December 31, 2001 and the results of operations for the three and nine months ended September 30, 2002 and 2001. The information is expressed in Canadian dollars.

Three and Nine Months Ended September 30, 2002 Compared to Three and Nine Months Ended September 30, 2001

Financial Condition, Liquidity and Capital Resources

At September 30, 2002 Enterra’s working capital was a deficit of $26.5 million (December 31, 2001 - $2.2 million). Included as part of current liabilities at September 30, 2002 is bank debt of $23.3 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 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 for the three months ended September 30, 2002 was $2.4 million (2001 - $3.2 million) for a 23% decrease. The 2001 cash flow was higher because of higher production ( 2,110 boe/day in 2001 compared to 1,752 boe/day in 2002), higher prices and, mostly, because of an income tax recovery of approximately $600,000 (which was a one-time adjustment in Q3, 2001).

 

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Cash flow from operations for the nine months ended September 30, 2002 was $7.1 million (2001 - $7.3 million) for a 2% decrease. The 2001 cash flow included a $1.7 million cash settlement on a hedging contract. Without that settlement, the 2002 cash flow would have actually been 27% higher than 2001, which is reasonable in light of the higher production in the nine months ended September 30, 2002 (2,016 boe/day) compared to the same period in 2001 (1,606 boe/day).

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 September 30, 2002 was $23.3 million (December 31, 2001 - $18.4 million). Our bank debt is used to acquire capital assets and support ongoing operations. At September 30, 2002 Enterra’s bank facility consisted of a line of credit of $24 million (December 31, 2001 - $21.5 million) of which $23.3 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 9,160,624 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 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 $50 million in tax pools available at September 30, 2002.

The bank debt to equity ratio at September 30, 2002 was 0.61 to 1 (December 31, 2001 – 0.55 to 1).

On October 1, 2002 the Company closed a sale-leaseback arrangement on some of its production and processing equipment for $5 million. The funds will be used for the Company’s 2002 drilling program. The lease agreement calls for 60 monthly payments of $88,802, with an option to purchase of $1 million on the last day of the 60^th month. This arrangement will be accounted for as a capital lease.

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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 September 30, 2002 were $10.6 million (September 30, 2001 - $1.9 million). Capital expenditures for the nine months ended September 30, 2002 were $16.2 million (September 30, 2001 - $9.7 million). Drilling activity has been minimal in the first half of 2002 but has increased substantially in the third quarter. This trend will continue into the fourth quarter of 2002 and the first quarter of 2003, as these are typically the peak drilling months in terms of activity.

The Company has drilled 8 (5.2 net) wells in the nine months ended September 30, 2002, resulting in 4 (2.7 net) oil wells and 4 (2.5 net) gas wells. Approximately one third of all capital expenditures related to drilling and completion activities. More than half of our capital expenditures to date have been for land acquisition and equipment upgrades.

Proceeds on disposal of oil and gas properties were $6.2 million for the nine months ended September 30, 2002 (September 30, 2001 – NIL). 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 $6.2 million total proceeds.

 

Results of Operations

Gross revenue for the three months ended September 30, 2002 was $5 million (2001 - $6.3 million) for a 20% decrease. Revenue for the nine months ended September 30, 2002 was $15.7 million (2001 - $15.3 million) for a 3% increase. Production volumes for the three months ended September 30, 2002 were 1,752 boe/day (2001 – 2,110 boe/day) for a 17% decrease. The main reason for this decline was the sale of the Grand Forks property in 2002 which reduced Enterra’s production by 300-350 boe/day. Production volumes for the nine months ended September 30, 2002 were 2,016 boe/day (2001 – 1,606 boe/day) for a 26% increase. However, commodity prices during that period declined by 18%, resulting in a lower revenue increase of only 3% for the nine-month period.

Average oil prices declined by 7% during the first nine months of 2002 and average gas prices declined by 22% over the same period compared to their respective 2001 levels. The Company received an average of $33.23 per barrel for its oil production during the nine months ended September 30, 2002, compared with $35.70 in 2001. The Company received an average of $3.49 per mcf for its natural gas production during the nine months ended September 30, 2002, compared with $4.47 in 2001. As a result, Enterra’s revenue per boe declined by $6.37 (or 18%) per boe in the first nine months of 2002 compared to 2001.

Royalties for the three months ended September 30, 2002 were $0.9 million (2001 - $1.1 million) and $2.5 million for the nine months ended September 30, 2002 (2001 - $2.5 million). As a percentage of oil and gas revenues, royalties were 17% for the three months ended September 30, 2002 (2001 – 17%) and 16% for the nine months ended September 30, 2002 (2001 – 16%).

 

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Operating expenses for the three months ended September 30, 2002 were $0.9 million (2001 - $1.8 million) and $3.7 million for the nine months ended September 30, 2002 (2001 - $4.2 million). Operating costs actually decreased in the first nine months of 2002 despite the increase in production. This is consistent with 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 three months ended September 30, 2002 were $5.69 (2001 - $9.43) and $6.69 for the nine months ended September 30, 2002 (2001 - $9.65). The reduction in operating costs will 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 three months ended September 30, 2002 were $380,189 (2001 - $158,999) and $1.2 million for the nine months ended September 30, 2002 (2001 - $668,393). On a barrel of oil equivalent basis administrative costs were $2.36 for the three months ended September 30, 2002 (2001 - $0.82) and $2.14 for the nine months ended September 30, 2002 (2001 - $1.52). The 2002 increase is due to corporate expenditures (e.g. audit fees, reserve report, bank renewal fee financing costs) and to a small increase in payroll costs from 2001. As our production increases over time the general and administrative expenses will fall back to a level between $1.00 and $2.00 per boe.

Interest expense for the three months ended September 30, 2002 was $268,597 (2001 - $262,221) and $705,253 for the nine months ended September 30, 2002 (2001 - $405,285). The increase in interest expense is due to higher debt levels in 2002. Included in interest expense in 2002 is $11,101 of dividends paid to the preferred shareholders.

Depletion and depreciation for the three months ended September 30, 2002 was $1.7 million (2001 - $2 million) and $5.8 million for the nine months ended September 30, 2002 (2001 - $4 million). The increase reflects the higher cost base in our capital assets in 2002.

Enterra incurred $863,817 of one-time restructuring charges (mainly severance and termination payments) in the nine months ended September 30, 2001 as a result of the Big Horn acquisition. There were no such costs in 2002.

Current and future income tax expense for the three months ended September 30, 2002 were $33,000 and $313,000 respectively (2001 – ($595,094) and $795,831) and $99,000 and $551,000 respectively for the nine months ended September 30, 2002 (2001 – $279,046 and $580,375). 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 less 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 $714,127 for the three months ended September 30, 2002 (2001 - $647,631) for an increase of 11%. The earnings for the nine months ended September 30, 2002 were $4.3 million (2001 - $1.7 million) for a 147% increase. This large increase was caused 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 for the nine months ended September 30, 2002 would have been $1.2 million, a decrease of 33%. The lower earnings in 2002 are due to lower prices, higher depletion charges and higher general and administrative costs.

Earnings per share for the three months ended September 30, 2002 were $0.08 (2001 - $0.09) and $0.47 for the nine months ended September 30, 2002 (2001 - $0.28). The weighted average number of shares outstanding for the three months ended September 30, 2002 was 9,152,295 (2001 – 7,593,231) and 9,151,186 for the nine months ended September 30, 2002 (2001 – 6,255,043).

The Company had 9,160,624 common shares outstanding at September 30, 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 not have been materially different than those reported.

 

Share Capital

	Number of common shares	Amount
Balance, December 31, 2001	9,150,622	$ 29,568,263
Issued on exercise of options	29,008	109,115
Shares repurchased	(19,006)	(74,315)
Balance, September 30, 2002	9,160,624	$ 29,603,063

 

	Number of Options	Weighted-average exercise price
Outstanding at December 31, 2001	800,000	$4.00
Options granted	204,000	$4.81
Options exercised	(29,008)	($3.76)
Options cancelled	(108,786)	($4.00)
Outstanding at September 30, 2002	866,206	$4.58

 

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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Subsequent Event – Sale leaseback Arrangement

On October 1, 2002 the Company closed a sale-leaseback arrangement on some of its production and processing equipment for $5 million. The funds will be used for the Company’s 2002 drilling program. The lease agreement calls for 60 monthly payments of $88,802, with an option to purchase of $1 million on the last day of the 60^th month. This arrangement will be accounted for as a capital lease.

 

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 September 30, 2002; our Credit facilities can be called at any time.

At September 30, 2002, we had a working capital deficiency of $26.5 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.

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.

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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.

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.

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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.

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.

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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.

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.

 

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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.

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.

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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 (except to our preferred shareholders), 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. We have paid dividends of $11,101 to our preferred shareholders in the quarter ended September 30, 2002. Dividends will be paid to our preferred shareholders at a rate of $0.85 per share (on an annual basis). This dividend will decrease over time as the Company is gradually redeeming these preferred shares. At September 30, 2002 there were 1,067,405 preferred shares outstanding. 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. The Company’s banker is aware of the dividends being paid to the preferred shareholders and will allow such payments as long as all our bank covenants are being 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.

 

 

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ITEM 3. CONTROLS AND PROCEDURES

The Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures. They concluded that our disclosure controls and procedures were adequate and effective in ensuring that material information relating to the Company is properly recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to allow timely decisions regarding required disclosure.

We currently have in place systems relating to internal controls and procedures with respect to our financial information. Management reviews and evaluates these internal control systems on an on-going basis. Based on these evaluations, there were no significant deficiencies or material weaknesses in these internal controls requiring corrective actions. As a result, no corrective actions were taken. There have been no significant changes in these internal controls or in other factors that could significantly affect these internal controls subsequent to the review and evaluation.

 

 

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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: November 19, 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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Sarbanes-Oxley Section 302 Certification

I, Reg J. Greenslade, certify that:

1. I have reviewed this quarterly report on Form 10-QSB of Enterra Energy Corp.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 19, 2002

/s/ Reg J. Greenslade

Reg J. Greenslade.

Chief Executive Officer

 

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Sarbanes-Oxley Section 302 Certification

I, Luc Chartrand, certify that:

1. I have reviewed this quarterly report on Form 10-QSB of Enterra Energy Corp.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 19, 2002

/s/ Luc Chartrand

Luc Chartrand

Chief Financial Officer

 

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