EX-99 4 enterraq3report.htm THIRD QUARTER REPORT ENTERRA ENERGY TRUST




 
 
 
 
 
 
 
 

ENTERRA ENERGY TRUST

 

Q3 2005

 

Quarterly Report to the Unitholders

 

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005

 
 
 

Unaudited

 
 
 
 
 
 
 
 
 





ENTERRA ENERGY TRUST

  

MESSAGE TO UNITHOLDERS

For the nine month period ended September 30, 2005 ("Q3 2005")

 

 

 

 

       
       

2005 year-to-date has been the most productive period ever for Enterra.

       

The most notable event of the period was the completion of the previously announced acquisition of High Point Resources Inc., (“High Point”) on August 17, 2005.  The arrangement was approved by over 99.9% of the votes cast by shareholders of High Point at the special meeting held on August 16, 2005.  The full impact of the acquisition will be felt in the upcoming quarter since the results of the High Point operations included in Q3 2005 covers only a portion of the quarter from August 17 to September 30.

       

The High Point acquisition provides Enterra with sales volumes of over 3,000 boe/day, bringing our current sales volumes to approximately 10,000 boe/day.  In addition, the acquisition provides Enterra with more than 135,000 net acres of undeveloped land with over 120 drilling locations.   These programs will be developed by farm out arrangements with JED Oil Inc.  Enterra looks forward to an accelerated development of these new properties.  Drilling has already commenced, and to date, eight gas wells have been drilled, and all eight have been cased for production.

       

Efforts to balance the asset portfolio between oil and natural gas moved forward with the High Point acquisition, as well as the previously announced Rocky Mountain Gas acquisition.  Natural gas currently represents 40% of sales volumes, up from 17% compared to the same period in 2004.

       

A significant factor in the Trust’s strong financial performance has been strong commodity pricing.  The current pricing cannot be taken for granted and consequently represents an element of uncertainty for the future.  In an effort to minimize pricing disruption as we move forward, the Board of Directors authorized a limited program of commodity contracts which fix the floor price, while maintaining upside potential.

       

During Q3 2005, Enterra increased the monthly cash distribution to its unitholders to US$0.17 per Trust Unit.  This represents a 70% increase from the initial US$0.10 per Trust Unit that the Trust established as its initial distribution when it converted to a Trust in December 2003, and a 21% increase from the US$0.14 per Trust Unit that the Trust paid out at the start of 2005.  This also represents the 7th consecutive quarter where the cash distribution has been increased.  Cash distributions in Q3 2005 represented 71% of “funds from operations” (previously referred to as “cash flow from operations”).

       

Enterra continues to strengthen its management team to facilitate optimization of the recently acquired assets and to enable the Trust to move forward on its business plan including pursuing additional growth opportunities.  During the quarter, John Reader was appointed as Vice President, Operations and Engineering.

       

The Trust entered into an arrangement with Kingsbridge Capital Limited to raise up to US$100 million.  Enterra has now filed the prospectus, which enables the Trust to commence drawing on this equity facility.  This provides the Trust with a stronger balance sheet, and the ability to pursue additional acquisitions.

       

"There has been a considerable amount of time and effort deployed through the first part of 2005 to provide a solid foundation from which to execute our business plan during the remainder of 2005 and into the future,” stated Reg Greenslade, Chairman of Enterra.

       

Please visit our website at www.enterraenergy.com for up to date information.

       
       





ENTERRA ENERGY TRUST

      

MANAGEMENT’S DISCUSSION AND ANALYSIS

 

 

 

 
        

The following is Management’s Discussion and Analysis (“MD&A”) of Enterra Energy Trust (“the Trust”) for the nine months ended September 30, 2005.  This MD&A should be read in conjunction with the amended MD&A and the amended consolidated financial statements, together with the accompanying notes, for the year ended December 31, 2004, as well as the unaudited interim consolidated financial statements and accompanying notes for the nine months ended September 30, 2005.  All amounts are stated in Canadian dollars and are prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”) except where otherwise indicated.  This MD&A was written as of November 11, 2005.  

 
        

CERTAIN FINANCIAL REPORTING MEASURES

      
        

Management uses funds from operations to analyze operating performance and leverage.  Funds from operations as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles, (“GAAP”) and therefore it may not be comparable with the calculation of similar measures for other entities.  Funds from operations as presented is not intended to represent cash provided by operating activities nor should it be viewed as an alternative to net earnings or other measures of financial performance calculated in accordance with Canadian GAAP.  All references to funds from operations throughout this MD&A are based on cash provided by operating activities before changes in non-cash working capital.  This measure is the same as the measure previously referred to as non-GAAP "cash flow from operations".

 
        

It is management’s view, based on its communications with investors during events like conference calls, webcasts or road shows, that funds from operations is relevant to investors, especially since the Trust’s conversion to an oil and natural gas income trust.  Funds from operations is relevant to investors because it is the starting point for setting the monthly unitholder cash distribution amount.  Funds from operations is reconciled to the most comparable GAAP measure of cash provided by operating activities in a table included in this MD&A.  

 
        

Natural gas volumes recorded in thousand cubic feet (“mcf”) are converted to barrels of oil equivalent (“boe”) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (“bbl”).  Boe's may be misleading, particularly if used in isolation.  A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.

 
        

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

    
        

This interim report includes forward-looking statements.  All statements other than statements of historical facts contained in this interim report, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements.  The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements.  We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs.  These forward-looking statements are subject to a number of risks, uncertainties and assumptions as described in our Annual Information Report, our Annual Report and elsewhere in this interim report.

 
        

Other sections of this interim report may include additional factors that could adversely affect our business and financial performance.  Moreover, we operate in a very competitive and rapidly changing environment.  New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

 
        

We undertake no obligation to update publicly or revise any forward-looking statements.  You should not rely upon forward-looking statements as predictions of future events or performance.  We cannot assure you that the events and circumstances reflected in the forward-looking statements will be achieved or occur.  Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements.

 
        

OVERVIEW AND STRATEGY

       
        

Enterra Energy Trust operates as an oil and natural gas income trust.  We pay monthly cash distributions on the 15th day of each month to Unitholders of record on the immediately preceding distribution record date.  Our business strategy is to grow our oil and natural gas reserves and our cash distributions by acquiring properties that provide additional oil and gas production and potential for development upside.  We are focused on per Trust Unit growth.  We will finance acquisitions with cash flow, equity and with debt, the optimal mix being one that minimizes Unitholders’ dilution while maintaining a strong balance sheet.  Our ability to replace and grow our reserves over time is the key success factor in our business strategy.

 
        

The Trust completed three acquisitions in the first nine months of 2005.  On January 26, 2005 the Trust closed an acquisition of petroleum and natural gas properties for cash consideration of $12.1 million.   On June 1, 2005, the acquisition of Rocky Mountain Gas, Inc. was closed for consideration of approximately $23.8 million, including $0.3 million of transaction cost.  The consideration consisted of 736,842 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at $16.7 million, 275,474 trust units valued at $6.3 million and $0.6 million in cash.   On August 17, 2005, the acquisition of High Point Resources Inc. ("High Point") closed for consideration of approximately $201.0 million, including $1.3 million of transaction cost.  In addition the Trust assumed $75.0 million in debt and $4.2 million in working capital deficiency.  The consideration consisted of 7,490,898 trust units valued at $168.5 million and 1,407,177 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at $31.7 million.

 
        

OVERALL PERFORMANCE

       
        

Our financial results have been positively affected by increased natural gas sales volumes, arising from the three acquisitions completed in 2005, in particular the High Point acquisition, despite some temporary operational issues that resulted in lower production levels in Q2 2005.  With the completion of the High Point acquisition, the Trust exited Q3 with sales volumes of approximately 10,000 boe/day.

 
        

SUMMARIZED FINANCIAL AND OPERATIONAL DATA (in thousands except for volumes and per unit amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Oil and natural gas revenues

 $   47,638

 $  25,467

87%

 $107,495

 $  74,700

44%

 

Average sales (boe/day)

        8,284

       6,203

34%

        7,019

       6,534

7%

 

Exit sales rate (boe/day)

        9,887

       7,659

29%

        9,887

       7,659

29%

 

Funds from operations

 $   23,940

 $  13,110

83%

 $   51,026

 $  36,139

41%

 

Net earnings

 $     7,089

 $    3,921

81%

 $   13,907

 $  10,771

29%

 

Net earnings per Trust Unit

 $       0.23

 $      0.17

35%

 $       0.50

 $      0.50

1%

 

Weighted average number of Trust Units outstanding

      31,052

     21,371

45%

      27,591

     20,775

33%

 

Average price per barrel of oil

 $     69.60

 $    46.24

51%

 $     59.07

 $    40.60

45%

 

Average price per mcf of natural gas

 $       8.78

 $      6.09

44%

 $       8.02

 $      6.62

21%

 

Operating costs per boe

 $     10.10

 $    10.42

-3%

 $     11.28

 $      8.65

30%

 
        

OIL AND NATURAL GAS REVENUES

       
        

The increase in revenues for both Q3 2005 and for the nine month period ended September 30, 2005 were due to the increase in natural gas sales volumes together with the increases in the sales prices of oil and natural gas.  The increase in natural gas sales volumes was a direct result of the High Point acquisition, a company who's production was heavily natural gas weighted, for which the operating results have been included in the consolidated balances since August 17, 2005.  The increase in sales prices was a result of the current commodity price environment tempered by the stronger Canadian dollar.  

 
        

Sales (in thousands except for volumes and pricing)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Revenues

       

Oil and natural gas liquids ("NGL")

 $   33,140

 $  21,912

51%

 $   85,540

 $  62,415

37%

 

Natural gas

      14,498

       3,555

308%

      21,955

     12,285

79%

 

Total

 $   47,638

 $  25,467

87%

 $107,495

 $  74,700

44%

 
        

Daily Sales Volumes - Average

       

Oil & NGL (bbls/day)

        5,293

       5,146

3%

        5,348

       5,406

-1%

 

Natural gas (mcf/day)

      17,945

       6,343

183%

      10,022

       6,768

48%

 

Total (boe/day)

        8,284

       6,203

34%

        7,019

       6,534

7%

 
        

Daily Sales Volumes - Exit Rate

       

Oil & NGL (bbls/day)

        5,361

       6,175

-13%

        5,361

       6,175

-13%

 

Natural gas (mcf/day)

      27,156

       8,904

205%

      27,156

       8,904

205%

 

Total (boe/day)

        9,887

       7,659

29%

        9,887

       7,659

29%

 

 

 

 

 

 

 

 

 

Sales Volumes mix by product

       

Oil & NGL

64%

83%

-23%

76%

83%

-8%

 

Natural gas

36%

17%

112%

24%

17%

38%

 

 

100%

100%

 

100%

100%

 

 

 

 

 

 

 

 

 

 

Commodity Pricing

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Pricing Benchmarks

 

 

 

 

 

 

 

WTI (US$/bbl)

 $     63.19

 $    43.88

44%

 $     55.40

 $    39.12

42%

 

Average exchange rate: US$1.00 to $CDN =

 $       1.20

 $      1.31

-8%

 $       1.22

 $      1.33

-8%

 

WTI (CDN$/bbl)

 $     52.66

 $    33.50

57%

 $     45.41

 $    29.41

54%

 

AECO monthly index (CDN$/mcf)

 $       8.52

 $      6.95

23%

 $       7.73

 $      6.98

11%

 
        

Average Prices Received by the Trust

 

 

 

 

 

 

 

Oil (per bbl)

 $     69.60

 $    46.24

51%

 $     59.07

 $    40.60

45%

 

Natural gas (per mcf)

 $       8.78

 $      6.09

44%

 $       8.02

 $      6.62

21%

 

Total (per boe)

 $     62.50

 $    44.63

40%

 $     56.10

 $    41.72

34%

 
        

ROYALTIES

       
        

Royalties, which include Crown, freehold and overriding royalties, offset by Alberta Royalty Tax Credits (“ARTC”), have increased compared to the prior periods as the result of the increased revenues in 2005.  Royalties are based on the volume of production or sales, therefore royalties per boe fluctuate in relation to the fluctuation in the prices received by the Trust for the oil and natural gas sales.

 
        

Royalties (in thousands except for percentages and per boe amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Royalties

$   10,487

$    4,924

113%

 $   23,159

$16,568

40%

 

As a percentage of revenue

22%

19%

14%

22%

22%

-3%

 

Royalties per boe

$     13.76

$      8.63

59%

 $     12.09

 $      9.25

31%

 
        

OPERATING EXPENSES

       
        

The Trust's operating expenses per boe declined slightly in the current quarter.  The primary reason for the decrease in operating expenses in Q3 is due to the acquisition of the High Point properties which have averaged $4.40 per boe in the quarter.  

 
        

The year to date figures reflect the higher operating costs associated with the east central Alberta oil properties acquired in Q1 of both 2004 and 2005.  In addition, cost increases in power and fuel, and well servicing occurred due to higher commodity prices and labour costs.  Record rainfalls during Q2 2005 also resulted in additional costs.  The downtime experienced at the Clair field reduced the Trust's sales volumes, and therefore increased the operating expenses per boe.  With the completion of the High Point acquisition, and continued development of the related natural gas properties, overall operating costs per boe are expected to trend downward.

 
        

Operating Expenses (in thousands except for percentages and per boe amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Operating expenses

$     7,698

$    5,949

29%

$   21,613

$  15,486

40%

 

Operating expenses per boe

$     10.10

$    10.42

-3%

$     11.28

$      8.65

30%

 
        

GENERAL AND ADMINISTRATIVE EXPENSES

      
        

General and administrative ("G&A") expenses for Q3 2005 increased over the corresponding period in 2004 due to the expansion in operations of the Trust.  Additional personnel costs in the form of salaries and consulting fees along with higher legal costs have been incurred in connection with the integration and administration of the High Point assets, regulatory compliance requirements and the filing of the Base Shelf Prospectus.  

 
        

For the period ended September 30, 2005, the year over year increase was also impacted by the increased audit and consulting services required to respond to the resignation of senior officers of the Trust in Q1 2005 and the 2004 bonus that was approved by the unitholders, paid and recorded as an expense in Q2 2005.  Additionally, G&A expenses have increased due to computer software purchases and higher costs associated with regulatory compliance in Canada and the U.S.  Finally, the Trust discontinued capitalizing administrative costs, as indicated in the table below.  G&A expenses per boe are expected to decline in Q4 2005 as a result of the additional sales volumes acquired with the High Point acquisition that will be included for the entire quarter.

 
        

General and Administrative Expenses (in thousands except for percentages and per boe amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

G&A expenses - total

 $     2,428

 $    1,187

105%

 $     7,341

 $    3,140

134%

 

Bonus from 2004 paid in Q2 2005

               -   

             -   

 

       (1,584)

             -   

 

 

G&A capitalized

               -   

          247

-100%

              39

          849

-95%

 

G&A on a comparable basis with 2004

 $     2,428

 $    1,434

69%

 $     5,796

 $    3,989

45%

 

G&A as a percentage of revenue

5%

5%

9%

7%

4%

62%

 

G&A per boe - total

 $       3.19

 $      2.08

53%

 $       3.83

 $      1.75

118%

 

G&A per boe - on a comparable basis

 $       3.19

 $      2.51

27%

 $       3.00

 $      2.23

35%

 
        

INTEREST EXPENSE

       
        

Interest expense has increased due to the higher average outstanding loan balances during the period, interest on the bridge credit facility, and the increase in interest rates from the prior periods.  

 
        

Interest Expense (in thousands except for percentages and per boe amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Bank debt, capital lease, and notes payable at end of period

 $107,187

 $  43,034

149%

 $107,187

 $  43,034

149%

 

Interest expense

 $     1,365

 $       510

168%

 $     2,715

 $    1,731

57%

 

Interest expense per boe

 $       1.79

 $      0.89

100%

 $       1.42

 $      0.97

47%

 
        

DEPLETION, DEPRECIATION AND ACCRETION

      
        

Depletion, depreciation and accretion expense increased in 2005 compared to 2004, primarily due to the higher depletable base associated with the acquisition of the east central Alberta, Rocky Mountain Energy, and High Point properties.  

 
        

Depletion, Depreciation and Accretion  "DD&A" (in thousands except for percentages and per boe amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

DD&A

 $   18,130

 $    7,560

140%

 $   40,417

 $  24,181

67%

 

DD&A per boe

 $     23.79

 $    13.25

80%

 $     21.09

 $    13.51

56%

 
        

TAXES

       
        

Most of the current tax expense relates to the capital tax imposed on the taxable capital employed, and the balance relates to adjustments of prior year income tax expenses of an acquired corporate subsidiary.  The future income tax reduction in 2005 and 2004 reflects the timing differences between the expensing of property, plant and equipment for accounting purposes and for tax purposes.

 
        

Taxes (in thousands except for percentages)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Current tax expense

 $        933

 $         30

3010%

 $     1,102

 $         90

1124%

 

Future income tax (reduction) expense

          (888)

       1,228

-172%

       (3,364)

          116

-3000%

 

Total taxes

 $           45

 $    1,258

-96%

 $   (2,262)

 $       206

-1198%

 
        

NET EARNINGS

       
        

Net earnings have increased due to the increased volumes of natural gas sold by the Trust, together with the increases in the prices of oil and natural gas.  Earnings also benefited from future income tax recoveries in 2005.

 
        

Earnings (in thousands except for percentages and per boe amounts)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Earnings before taxes & NCI

 $     7,530

 $    5,313

42%

 $   12,234

 $  11,312

8%

 

Tax (recovery) expense

              45

       1,258

-96%

       (2,262)

          206

-1198%

 

Non-controlling interest

            396

          134

196%

            589

          335

76%

 

Net earnings

 $     7,089

 $    3,921

81%

 $   13,907

 $  10,771

29%

 

Net earnings per boe

 $       9.30

 $      6.87

35%

 $       6.38

 $      6.02

6%

 

Net earnings per Trust Unit

 $       0.23

 $      0.17

35%

 $       0.50

 $      0.50

1%

 

Weighted average number of Trust Units outstanding

      31,052

     21,371

45%

      27,591

     20,775

33%

 
        

FUNDS FROM OPERATIONS (formerly referred to as "cash flow from operations")

   
        

At the bequest of the various regulatory agencies, we no longer refer to cash flow from operations; the non-GAAP measure is now referred to as "funds from operations".  Funds from operations increased in 2005 compared to 2004, primarily due to the increased volumes of natural gas sold by the Trust, together with the increases in the prices of oil and natural gas.

 
        

Management uses funds from operations to analyze operating performance and leverage.  Funds from operations as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles, (“GAAP”) and therefore it may not be comparable with the calculation of similar measures for other entities.  Funds from operations as presented is not intended to represent cash provided by operating activities nor should it be viewed as an alternative to net earnings or other measures of financial performance calculated in accordance with Canadian GAAP.  All references to funds from operations throughout this MD&A are based on cash provided by operating activities before changes in non-cash working capital as reconciled in the table below:

 
        

Funds from Operations (in thousands except for percentages)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Cash provided by operating activities

 $   16,622

 $  13,083

27%

 $   47,545

 $  28,153

69%

 

Changes in non-cash working capital items

       (7,318)

          (27)

 

       (3,481)

     (7,986)

  

Funds from operations

 $   23,940

 $  13,110

83%

 $   51,026

 $  36,139

41%

 
        

CAPITAL EXPENDITURES

       
        

The Trust does not have material commitments for capital expenditures.  Our business strategy is to have other companies spend the capital to develop our properties in exchange for us receiving a 30% working interest in the developed properties at no additional cost to us.  We also retain a right of first refusal to purchase the remaining 70% working interest.  Any such purchases will be financed by the Trust's cash flow, by issuing new Trust Units and/or with debt.

 
        

The Trust closed three acquisitions in the first nine months of 2005. On January 26, 2005 the Trust closed an acquisition of petroleum and natural gas properties for cash consideration of $12.1 million.  On June 1, 2005, the acquisition of Rocky Mountain Gas, Inc. closed for consideration of approximately $23.8 million, including $0.3 million of transaction cost.  The consideration consisted of 736,842 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at $16.7 million, 275,474 trust units valued at $6.3 million and $0.6 million in cash.   The acquisition of High Point was closed on August 17, 2005, for consideration of approximately $201.0 million, including $1.3 million of transaction cost.  In addition the Trust assumed $75.0 million in debt and $4.2 million working capital deficiency.  The consideration consisted of 7,490,898 trust units valued at $168.5 million and 1,407,177 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at $31.7 million.

 
        

The following table represents the Trust's capital expenditures that were paid for with cash.  The source of this cash was through private placements of Trust Units and from working capital.  The table excludes capital expenditures, such as the portion of the RMG and High Point acquisitions, that were paid for with non-cash consideration such as Trust Units and exchangeable shares.

 
        

Capital Expenditures (in thousands except for percentages)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Net

$     4,586

$    5,886

-22%

$   24,436

$  29,794

-18%

 
        

CASH DISTRIBUTIONS PAID TO UNITHOLDERS

      
        

The Trust pays monthly cash distributions to its Unitholders.  Cash distributions are paid on the 15th of the following month (e.g. the September distribution was paid on October 15).  The monthly cash distributions per Trust Unit since the inception of the Trust are as follows:

 

US$

 

 

 

2003

2004

2005

 

January

    

$      0.10

$         0.14

 

February

    

$      0.10

$         0.14

 

March

 

 

 

 

$      0.11

$         0.15

 

April

    

$      0.11

$         0.15

 

May

    

$      0.11

$         0.15

 

June

 

 

 

 

$      0.12

$         0.16

 

July

    

$      0.12

$         0.16

 

August

    

$      0.12

$         0.16

 

September

 

 

 

 

$      0.13

$         0.17

 

October

    

$      0.13

  

November

    

$      0.13

  

December

 

 

 

$         0.10

$      0.14

  

 

 

 

 

    

Cash Distributions To Unitholders (in thousands except for percentages)

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

  

2005

2004 (restated)

Change

2005

2004 (restated)

Change

 

Cash distributions to unitholders

$   16,918

$  10,924

55%

$   45,128

$  28,338

59%

 

Funds from operations

$   23,940

$  13,110

83%

$   51,026

$  36,139

41%

 

Cash distributions as a percentage of funds from operations

71%

83%

-15%

88%

78%

13%

 
        

The acquisition of High Point on August 17, 2005 is providing the Trust with substantial additional funds from operations and will aid in the ongoing fullfilment of the Trust's cash distribution intentions.

 
        

To the extent that the Trust uses cash to finance acquisitions, development costs and other significant expenditures, the net cash that the Trust receives that is available for distribution to unitholders will be reduced.  Hence, the timing and amount of capital expenditures may affect the amount of net cash flow received by the Trust and, as a consequence, the amount of cash available to distribute to unitholders.  Therefore, distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made with the use of available cash.

 
        

The Board of Directors of Enterra has the discretion to determine the extent to which cash provided by operating activities will be allocated to the payment of debt service charges as well as the repayment of outstanding debt.  As a consequence, the amount of cash retained to pay debt service charges or reduce debt will reduce the amount of cash available for distribution to Unitholders during those periods in which funds are so retained.

 
        

LIQUIDITY AND CAPITAL RESOURCES

       
        

Our business strategy is to have other companies spend the capital to develop our properties in exchange for us receiving a 30% working interest in the developed properties at no additional cost to us.  We also retain a right of first refusal to purchase the remaining 70% working interest.  Any such purchases will be financed by the Trust's cash flow, by issuing new equity and/or with debt.  The Trust does not have material commitments for capital expenditures.  

 
        

In Q1 2005, properties in east central Alberta were acquired for $12.1 million.  This transaction closed on January 26, 2005 and production from these properties after that date is included in the 2005 results.  The acquisition was largely funded through a private placement of 500,000 Trust Units generating net proceeds of $11.7 million.

 
        

On June 1, 2005, the acquisition of Rocky Mountain Gas, Inc. was closed for consideration of approximately $23.8 million, including $0.3 million of transaction cost.  The consideration consisted of 736,842 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at $16.7 million, 275,474 trust units valued at $6.3 million and $0.6 million in cash.

 
        

On August 17, 2005, the acquisition of High Point was closed for consideration of approximately $201.0 million, including $1.3 million of transaction cost.  In addition the Trust assumed $75.0 million in debt and $4.2 million of working capital deficiency.  The consideration consisted of 7,490,898 trust units valued at $168.5 million and 1,407,177 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at $31.7 million.

 
        

Bank indebtedness represented the outstanding balance under two revolving lines of credit that had a total capacity of $41 million.  Drawings on the revolving facilities bore interest at 1.6% above the bank’s prime lending rate or bankers’ acceptance rates plus margins which were originally set at 165 basis points and were subject to adjustment up or down prospectively, on a three-month basis as determined by the Trust’s consolidated debt to cash flow ratio.  At December 31, 2004 the Trust also had available a demand subordinated debt facility of $4,000,000 which bore interest at the lender's prime rate plus 2%, and this facility was reduced to nil on April 30, 2005.  Security was provided by a first charge over all of the Trust’s assets excluding those acquired in the RMG and High Point acquisitions.

 
        

The Trust has entered into "Standstill Agreements" with the existing lenders whereby the repayment date of the above credit facilities has been  extended to November 30, 2005.  The terms of the credit facilities have not changed, except the amount available under the credit facilities was reduced to $35,000,000 on October 25, 2005 and will be reduced to $32,000,000 on November 25, 2005.  Any amounts drawn on the facilities must be repaid no later than November 30, 2005.  The Trust is not in compliance with certain non-financial covenants of the credit facility.  The Trust’s lenders have not declared the Trust to be in default, and the Trust is working to bring itself back into full compliance.

 
        

On November 10, 2005 , the Trust entered into an arrangement with a new group of lenders whereby new credit facilities will be available in the form of two revolving lines of credit that total $90,000,000.  The new credit facilities will replace the above credit facilities.  Drawings on the revolving facilities will bear interest at 0.25% above the bank’s prime lending rate or bankers’ acceptance rates plus margins which will be initially set at 135 basis points and will be subject to adjustment up or down prospectively, on a three-month basis as determined by the Trust’s consolidated debt to cash flow ratio.  Security will be provided by a first charge over all of the Trust’s assets.  The amounts available under these new credit facilities will be subject to a semi-annual borrowing base determination.

 
        

Drawings under this new credit facility are subject to the Trust having the ability to draw on the Kingsbridge equity line and funds drawn on this new credit facility being sufficient to repay the existing credit facilities and the bridge credit facility in full.  With the filing of the Canadian Base Shelf Prospectus and the corresponding U.S. Registration Statement on November 10, 2005, drawings under the new credit facility are expected to take place no later than November 25, 2005.

 
        

The bridge credit facility was put in place on August 17, 2005 to facilitate the acquisition of High Point.  The bridge credit facility is a reducing non-revolving secured loan with a principal amount of $75,000,000.  Security is provided by a first charge on all of the High Point assets that were acquired.  The loan bears interest at bank prime rate plus 1% and is repayable from the proceeds of any debt or equity financing or proceeds from the disposal of assets.  The loan is repayable in full on the earlier of November 30, 2005 or the date where the Trust draws on its new credit facilities with its lenders.

 
        
     

30-Sep-05

31-Dec-04

 

Working capital deficiency

 

 

 

 

$128,738

$     42,354

 
        

The working capital deficiency mainly relates to the requirement of GAAP that the Trust's bank indebtedness and bridge credit facility are classified as  current liability even though there is no expectation that the revolving lines of credit will be called by the bank. The Trust intends to improve its liquidity by raising additional cash by issuing Trust Units.

 
        

On April 27, 2005, the Trust announced an arrangement with Kingsbridge Capital Limited whereby Kingsbridge has committed to purchase US$100 million of Trust Units.  The Trust is not obligated to access any of the capital available under this commitment yet has an option to draw on this commitment through installments for a period of 24 months or until the US$100 million is fully drawn.  In conjunction with the agreement, Kingsbridge was granted 301,000 warrants to purchase Trust Units at initially US$25.77 per trust unit.

 
        

With the filing of the Canadian Base Shelf Prospectus and the corresponding Registration Statements in the U.S., the Trust now has the ability to draw on the Kingsbridge equity line.

 
        

Notes payable consists of an unsecured promissory note for US$3.5 million which bears interest at 12%, and is repayable on July 1, 2006.

 
        

OTHER

       
        

The Trust has indemnified all of the directors and officers of the Trust and all the officers, directors, shareholders, employees and agents of JED Oil Inc..  There is no pending litigation or proceeding involving any director or officer of the Trust for which a claim is being sought, nor is the Trust aware of any threatened litigation that may result in claims.

 
        

RELATIONSHIP WITH JED OIL INC.

       
        

Under a Technical Services Agreement between the Trust and JED, JED provides certain staff to the Trust while the Trust provides offices and other administrative services to JED.  As consultants to the Trust, JED’s employees will be eligible to participate in benefit plans of the Trust.  The Chairman of JED is also the Chairman of the Trust.

 
        

Under a Technical Services Agreement between the Trust and JED, costs of management, development, exploitation, operations and general and administrative activities are allocated based on relative production and capital expenditures, or as otherwise mutually agreed.  For the nine months ended September 30, 2005, total general and administrative expenses charged by JED to the Trust on a cost recovery basis were approximately $4.7 million and field-operating expenses charged by JED to the Trust on a cost recovery basis were approximately $1.9 million.

 
        

JED has loaned funds to the Trust secured by a promissory note.  Interest is charged on the note at a bank prime rate plus 0.4%.  There is no stated term of repayment.  For the nine months ended September 30, 2005, $0.3 million of interest was charged on the loaned funds.

 
        

The balance due to JED at September 30, 2005 is $14.9 million (December 31, 2004 - $4.5 million) consisting of $7.7 million of notes payable and $7.1 million of other transactions.

 
        

CRITICAL ACCOUNTING ESTIMATES

       
        

The Trust continues to evolve and document its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.  The Trust’s financial and operating results incorporate certain estimates including:
a) estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;
b) estimated capital expenditures on projects that are in progress;
c) estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves which the Trust expects to recover in the future;
d) estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; and
e) estimated future recoverable value of property, plant and equipment and goodwill.

 
        

CHANGE IN ACCOUNTING POLICY

       
        

On January 19, 2005, the CICA issued EIC-151 “Exchangeable Securities Issued by Subsidiaries of Income Trusts” that states that equity interests held by third parties in subsidiaries of an income trust should be reflected as either non-controlling interest or debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires that the shares be nontransferable to be classified as equity.  The Trust's exchangeable shares are transferable and, in accordance with EIC-151, have been reclassified to non-controlling interest on the consolidated balance sheets.

 
        

Since the Enterra exchangeable shares were not initially recorded at fair value, subsequent exchanges for Trust Units are measured at the fair value of the Trust Units issued.  The excess amounts are allocated to property, plant and equipment and to goodwill.  In addition, a portion of consolidated earnings before non-controlling interest is reflected as a reduction to such earnings in the Trust’s consolidated statements of earnings and accumulated earnings.  Prior periods have been retroactively restated as requested by the new accounting standard.

 
        

The following tables illustrate the impact of the new accounting policy on the balance sheet as at December 31, 2004 presented for comparative purposes:

 

 

 

 

 

 

 

 

 

December 31, 2004

 

 

 

As reported

Change upon adoption

 of EIC-151

As restated

 

Property, plant and equipment

   

 $   146,910

 $    1,548

 $   148,458

 

Goodwill

   

        29,991

     19,279

        49,270

 

Future income tax liability

   

        21,526

          602

        22,128

 

Non-controlling interest

   

               -   

       3,349

          3,349

 

Unitholders' capital

   

      111,653

     20,554

      132,207

 

Exchangeable shares

   

          3,273

     (3,273)

                -   

 

Accumulated earnings

 

 

 

        27,903

        (405)

        27,498

 
        

The following table illustrates the impact of the new accounting policy on 2004 net earnings and net earnings per Trust Unit:

 
  

2004

 

 

 

Q1

Q2

Q3

Q4

Year

 

Net earnings before change in accounting policy

$    2,562

$ 4,647

$       4,138

$    3,417

$     14,764

 

Increase in depletion, net of taxes

 

(63)

(94)

(83)

(88)

(328)

 

Non-controlling interest

 

(103)

(98)

(134)

(73)

(408)

 

Net earnings after change in accounting policy

$    2,396

$ 4,455

$       3,921

$    3,256

$     14,028

 
        

Net earnings per Trust Unit, as reported

       

Basic and diluted

 

$      0.12

$   0.21

$         0.17

$      0.13

$         0.63

 
        

Net earnings per Trust Unit, as restated

       

Basic and diluted

 

$      0.12

$   0.21

$         0.17

$      0.13

$         0.62

 
        
        

OUTSTANDING UNIT DATA (in thousands)

 

 

 

 

 

 
    

31-Oct-05

30-Sep-05

31-Dec-04

 

Trust Units

   

      35,017

   34,971

        25,427

 

Exchangeable shares

   

        1,929

      1,968

                -   

 

Trust Unit options

   

        1,328

      1,278

             950

 

Warrants

 

 

 

            301

         301

                -   

 
        

ADDITIONAL INFORMATION

       
        

Additional information relating to Enterra Energy Trust, including our Annual Information Forms and Annual Reports, can be found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, as well as on the Trust's website at www.enterraenergy.com.

 
        
        





ENTERRA ENERGY TRUST

       

MANAGEMENT’S DISCUSSION AND ANALYSIS

 

 

 

 

            
            
            

SUMMARY OF QUARTERLY RESULTS (in Thousands except for per unit amounts)

 

 

 

  

2005

 

2004

 

2003

  

Q3

Q2

Q1

 

Q4

Q3

Q2

Q1

 

Q4

  

 

 

(restated)

 

(restated)

 

 (restated)

Revenues

 $ 47,638

 $  29,807

 $  30,050

 

 $  33,593

 $  25,467

 $  27,585

 $  21,648

 

 $  15,599

Net earnings (loss)

 $    7,089

 $    2,567

 $    4,252

 

 $    3,256

 $    3,921

 $    4,454

 $    2,396

 

 $  (4,602)

 

Per unit, basic

 $      0.23

 $      0.10

 $      0.16

 

 $      0.13

 $      0.17

 $      0.21

 $      0.12

 

 $    (0.24)

 

Per unit, diluted

 $      0.23

 $      0.10

 $      0.16

 

 $      0.13

 $      0.17

 $      0.21

 $      0.12

 

 $    (0.24)

            

The quarterly information reflects a general trend to increasing revenue reflecting the overall growth of the Trust and the rising prices of the oil and natural gas sold by the Trust.  Earnings from operations and net earnings have fluctuated depending upon the timing of major expenses incurred by the Trust.  In Q4, 2003, $5.8 million of expenditures were incurred to affect the transition to a Trust.  In Q2 2005, a $1.6 million bonus payable for fiscal 2004 was approved by the unitholders and was paid and expensed in Q2 2005.  

            
            

ABBREVIATIONS

 

 

 

 

 

 

 

 

 

 

bbl

barrel of oil

        

bbls/day

barrels of oil per day

        

mcf

thousand cubic feet of natural gas

     

mcf/day

thousands of cubic feet of natural gas per day

    

mmcf/day

millions of cubic feet of natural gas per day

     

NGL

natural gas liquids

        

boe

barrels of oil equivalent

       
  

  (6 mcf equivalent to 1 bbl)

       

mboe

thousands of barrels of oil equivalent

     

boe/day

barrels of oil equivalent per day

       

GJ

Gigajoule

         

MMBTU

Millions of British Thermal Units

      

CICA

Canadian Institute of Chartered Accountants

    

GAAP

Canadian Generally Accepted Accounting Principles

    

CDN$

Canadian dollars

        

US$

United States dollars

        

WTI

West Texas Intermediate (Oil reference price)

    

AECO

Natural gas reference price in Alberta

     

Q1

First quarter of the year - January 1 to March 31

    

Q2

Second quarter of the year - April 1 to June 30

    

Q3

Third quarter of the year - July 1 to September 30

    

Q4

Fourth quarter of the year - October 1 to December 31

    

Unitholders

The holders of the Trust Units

       
            
            





ENTERRA ENERGY TRUST

      

CONSOLIDATED BALANCE SHEETS

      

(Thousands of Canadian dollars)

  

 

   

(unaudited)

 

 

 

 

 

 

      

September 30, 2005

December

 

 

 

 

 

 

31, 2004

Assets

     

 

(restated

Current assets

     

Note 2)

 

Cash

    

 $        3,056

 $       4,779

 

Accounts receivable

    

         36,608

        15,613

 

Prepaid expenses and deposits

 

 

 

 

               522

             518

 

     

         40,186

        20,910

Property, plant and equipment (Note 4)

    

       519,334

      148,458

Deposit on acquisition (Note 3)

    

                   -   

          2,400

Deferred financing charges

    

            1,475

               90

Goodwill

 

 

 

 

         82,437

        49,270

 

 

 

 

 

 

 $    643,432

 $   221,128

        

Liabilities

      

Current liabilities

      
 

Accounts payable and accrued liabilities

    

 $      36,740

 $       8,570

 

Due to JED Oil Inc. (Note 12)

    

         14,870

          4,493

 

Distribution payable to unitholders

    

            6,965

          4,398

 

Income taxes payable

    

            1,984

          1,068

 

Bank indebtedness (Note 5)

    

         25,000

        43,930

 

Bridge credit facility (Note 6)

    

         75,000

               -   

 

Notes payable (Note 7)

    

            4,399

               -   

 

Marketing contracts (Note 3)

    

            3,107

               -   

 

Current portion of capital lease

 

 

 

 

               859

             805

      

       168,924

        63,264

Asset retirement obligations (Note 8)

    

         24,061

        14,836

Future income tax liability

    

       118,353

        22,128

Capital lease

    

            1,929

          2,580

 

 

 

 

 

 

       313,267

      102,808

 

 

 

 

 

 

 

 

Non-controlling interest (Notes 2 and 9)

 

 

 

 

         37,403

          3,349

        

Unitholders’ Equity

      
 

Unitholders’ capital (Note 10)

    

       342,328

      132,207

 

Warrants (Note 10)

    

            1,215

               -   

 

Contributed surplus (Note 10)

    

               321

               78

 

Accumulated earnings

    

         41,405

        27,498

 

Accumulated distributions

 

 

 

 

        (92,507)

      (44,812)

 

 

 

 

 

 

       292,762

      114,971

Contingencies, commitments, and guarantees (Notes 13 and 14)

     

Subsequent event (Note 15)

      

 

 

 

 

 

 

 $    643,432

 $   221,128

 

 

 

     

Approved on behalf of the Board:

      
        

/s/ Reg Greenslade

 

/s/ Bill Sliney

    

Director

 

Director

 

 

 

 

See accompanying notes to consolidated financial statements

      





ENTERRA ENERGY TRUST

      

CONSOLIDATED STATEMENTS OF EARNINGS

    

AND ACCUMULATED EARNINGS

      

(Thousands of Canadian dollars, except per Trust Unit amounts)

    

(unaudited)

 

 

 

 

 

 

   

Three Months Ended

 

Nine Months Ended

   

September 30,

 

September 30,

 

 

 

2005

2004

 

2005

2004

    

(restated

  

(restated

    

Note 2)

  

Note 2)

Revenues

      
 

Oil and natural gas

 

 $     47,638

 $     25,467

 

 $    107,495

 $     74,700

 

Royalties

 

      (10,487)

        (4,924)

 

        (23,159)

      (16,568)

 

 

 

        37,151

        20,543

 

         84,336

        58,132

        

Expenses

      
 

Operating

 

          7,698

          5,949

 

         21,613

        15,486

 

General and administrative

 

          2,428

          1,187

 

            7,341

          3,140

 

Interest

 

          1,365

             510

 

            2,715

          1,731

 

Amortization of deferred financing charges

 

                 -   

               24

 

                 16

               52

 

Depletion, depreciation and accretion

 

        18,130

          7,560

 

         40,417

        24,181

 

Financial derivative loss

 

                 -   

               -   

 

                   -   

          2,230

 

 

 

        29,621

        15,230

 

         72,102

        46,820

        

Earnings before taxes and non-controlling interest

 

          7,530

          5,313

 

         12,234

        11,312

        
 

Current taxes

 

              933

               30

 

            1,102

               90

 

Future income tax (reduction) expense

 

            (888)

          1,228

 

          (3,364)

             116

        

Earnings before non-controlling interest

 

          7,485

          4,055

 

         14,496

        11,106

        

Non-controlling interest (Notes 2 and 9)

 

              396

             134

 

               589

             335

        

Net earnings

 

          7,089

          3,921

 

         13,907

        10,771

        

Accumulated earnings, beginning of period

 

        34,316

        20,474

 

         27,498

        13,624

        

Accumulated earnings, end of period

 

 $     41,405

 $     24,395

 

 $      41,405

 $     24,395

        

Net earnings per Trust Unit (Note 10)

      
 

Basic

 

 $         0.23

 $         0.17

 

 $           0.50

 $         0.50

 

Diluted

 

 $         0.23

 $         0.17

 

 $           0.50

 $         0.50

 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements

 

 

 

 

 

 





ENTERRA ENERGY TRUST

      

CONSOLIDATED STATEMENTS OF CASH FLOW

    

(Expressed in thousand Canadian dollars)

      

(unaudited)

 

 

 

 

 

 

   

Three Months Ended

 

Nine Months Ended

   

September 30,

 

September 30,

 

 

 

2005

2004

 

2005

2004

    

(restated

  

(restated

Cash provided by (used in):

  

Note 2)

  

Note 2)

Operating

      

   Net earnings

 

 $       7,089

 $       3,921

 

 $      13,907

 $     10,771

   Non-cash items:

      
 

Depletion, depreciation and accretion

 

        18,130

          7,560

 

         40,417

        24,181

 

Future income tax (reduction) expense

 

            (888)

          1,228

 

          (3,364)

             116

 

Amortization of deferred financing charges

 

                 -   

               24

 

                 16

               52

 

Amortization of marketing contract

 

         (1,007)

               -   

 

          (1,007)

               -   

 

Non-controlling interest

 

              396

             134

 

               589

             335

 

Unit-based compensation

 

              220

             243

 

               468

             684

 

Changes in non-cash working capital items

 

         (7,318)

             (27)

 

          (3,481)

        (7,986)

 

 

 

        16,622

        13,083

 

         47,545

        28,153

        

Financing

      
 

Cash distributions to unitholders

 

      (16,918)

      (10,924)

 

        (45,128)

      (28,338)

 

Bank indebtedness

 

         (9,839)

          2,920

 

        (23,159)

        (2,175)

 

Notes payable

 

          4,399

               -   

 

            4,399

               -   

 

Capital lease

 

            (203)

           (138)

 

             (597)

           (584)

 

Deferred financing charges

 

            (186)

               54

 

             (186)

           (134)

 

Due to JED Oil Inc.

 

          3,376

               -   

 

         10,377

               -   

 

Issue of Trust Units, net of issue costs

 

            (187)

               -   

 

         11,478

        36,838

 

Exercise of Trust Unit options

 

          2,001

               -   

 

            7,415

               -   

 

 

 

      (17,557)

        (8,088)

 

        (35,401)

          5,607

        

Investing

      
 

Property, plant and equipment additions

 

         (4,586)

        (5,886)

 

        (24,436)

      (29,794)

 

Deposit on acquisition

 

                 -   

               -   

 

            2,400

          2,015

 

Proceeds on disposal of property, plant and equipment

 

                 -   

             430

 

            2,104

          1,207

 

Acquisition of Rocky Mountain Energy, net of cash

 

                 -   

        (7,217)

 

                   -   

        (7,217)

 

Acquisition of Rocky Mountain Gas, net of cash

 

            (249)

               -   

 

                (83)

               -   

 

Acquisition of High Point, net of cash

 

          1,282

               -   

 

            1,282

               -   

 

Changes in non-cash working capital items

 

          4,771

               -   

 

            4,866

               -   

 

 

 

          1,218

      (12,673)

 

        (13,867)

      (33,789)

        

Change in cash

 

              283

        (7,678)

 

          (1,723)

             (29)

Cash, beginning of period

 

          2,773

          7,715

 

            4,779

               66

Cash, end of period

 

 $       3,056

 $            37

 

 $        3,056

 $            37

        

During the nine months ended September 30, 2005 the Trust paid interest of $2,715 (2004 - $1,731) and taxes of $1,102 (2004 – $90).

 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements

 

 

 

 

 

 

        





ENTERRA ENERGY TRUST

  

Notes to Interim Consolidated Financial Statements

  

As at September 30, 2005 and for the three and nine months ended September 30, 2005 and 2004

(Tabular amounts in thousands of Canadian dollars, except where otherwise noted)

 

(unaudited)

 

 

 

 

 

       
       

1.  Significant accounting policies

     
       

The interim consolidated financial statements of Enterra Energy Trust (the “Trust”) have been prepared by management in accordance with Canadian generally accepted accounting principles.  These interim consolidated financial statements have been prepared following the same accounting policies and methods used in preparing the amended consolidated financial statements for the fiscal year ended December 31, 2004, except as noted below, and should be read in conjunction with those amended consolidated financial statements.  The interim consolidated financial statements contain disclosures which are supplemental to the Trust’s annual amended consolidated financial statements.  Certain disclosures which are normally required to be included in the notes to the annual amended consolidated financial statements have been condensed or omitted.  These consolidated interim financial statements include the accounts of the Trust and its wholly owned subsidiaries.

       

On June 1, 2005, the Trust acquired Rocky Mountain Gas, Inc. ("RMG") (note 3) whose oil and natural gas properties are located in the United States. As a result these properties constitute a second cost center under the Trust's full cost accounting policy for the purpose of calculating depletion expense and the ceiling tests.  RMG is considered to be an "integrated foreign operation", therefore the Trust is using the temporal method of foreign currency translation.  Under the temporal method, monetary items are translated at the exchange rate in effect at the balance sheet date, while non-monetary items are translated at historical exchange rates.  Revenue and expense items are translated at the exchange rate in effect on the dates they occur, while depreciation and depletion of assets translated at historical exchange rates are translated at the same exchange rates as the assets to which they relate.

       

2.  Change in accounting policy

     
       

Non-controlling interest (“NCI”)

     

On January 19, 2005, the CICA issued EIC-151 “Exchangeable Securities Issued by Subsidiaries of Income Trusts” that states that equity interests held by third parties in subsidiaries of an income trust should be reflected as either non-controlling interest or debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires that the shares be nontransferable to be classified as equity.  The Trust's exchangeable shares are transferable and, in accordance with EIC-151, have been reclassified to non-controlling interest on the consolidated balance sheets.

       

Since the Enterra exchangeable shares (note 9) were not initially recorded at fair value, subsequent exchanges for Trust Units are measured at the fair value of the Trust Units issued.  The excess amounts are allocated to property, plant and equipment and to goodwill.  In addition, a portion of consolidated earnings before non-controlling interest is reflected as a reduction to such earnings in the Trust’s consolidated statements of earnings and accumulated earnings.  Prior periods have been retroactively restated as required by the transitional provisions of the accounting standard.

       

Prior to the adoption of EIC 151, trust units that would be issued upon conversion of exchangeable shares were included in the calculation of basic earnings per unit.  Under the new standard, exchangeable shares are excluded from the calculation of basic earnings per unit and included in the calculation of diluted earnings per unit.

       

The following tables illustrate the impact of the new accounting policy for periods which have been presented for comparative purposes:

       

Balance Sheet as at December 31, 2004

 

 

Balance as reported prior

 to NCI restatement

Adjustments for

 EIC-151

Balance

 as restated

Property, plant and equipment

  

 $     146,910

 $          1,548

 $     148,458

Goodwill

  

          29,991

           19,279

          49,270

Future income tax liability

  

          21,526

                602

          22,128

Non-controlling interest

  

                  -   

             3,349

            3,349

Unitholders' capital

  

        111,653

           20,554

        132,207

Exchangeable shares

  

            3,276

           (3,276)

                  -   

Accumulated earnings

 

 

          27,903

              (405)

          27,498

       

Basic weighted average number of units outstanding

 

23,327,728

       (809,355)

22,518,373

Diluted weighted average number of units outstanding

 

23,560,785

       (318,825)

23,241,960

       

 

 

 

 

 

Three months ended September 30, 2004

Nine months ended September 30, 2004

Net earnings before change in accounting policy

  

 $          4,138

 $       11,347

Increase in depletion, net of taxes

   

                (83)

              (241)

Non-controlling interest

   

              (134)

              (335)

Net earnings after change in accounting policy

 

 

 $          3,921

 $       10,771

       

Net earnings per Trust Unit, as previously reported

    

Basic

    

 $            0.17

 $           0.51

Diluted

   

 $            0.17

 $           0.50

       

Net earnings per Trust Unit, as restated

     

Basic

    

 $            0.17

 $           0.50

Diluted

 

 

 

 $            0.17

 $           0.50

       

3.  Acquisitions

     
       

Property acquisition

    

On January 26, 2005, the Trust acquired certain oil and natural gas properties in east central Alberta for net consideration of approximately $12,100,000.  Results from operations of these acquired assets are included in the Trust’s consolidated financial statements for the period subsequent to January 26, 2005.  At December 31, 2004, the Trust had made a refundable deposit on the properties in the amount of $2,400,000.

       

Rocky Mountain Gas, Inc. ("RMG")

    

On February 25, 2005, the Trust entered into a letter of intent with RMG for the Trust to acquire the outstanding shares of RMG which holds natural gas assets in Montana and Wyoming.  On June 1, 2005, the acquisition of RMG closed.  As RMG's properties are in the United States, they constitute a second cost center.

       

The acquisition was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration paid as follows:

       

Allocation of purchase price:

Current assets, including cash of $769

    

 $         1,606

Property, plant and equipment

    

          34,809

Goodwill (with no tax base)

    

            9,107

Marketing contract

    

              (480)

Current liabilities

    

           (1,562)

Debt

     

           (4,229)

Asset retirement obligations

    

           (3,807)

Future income tax liability

    

         (11,619)

      

 $       23,825

       

Cost of acquisition:

Cash

     

 $            602

Transaction costs

    

               250

736,842 RMG exchangeable shares

    

          16,722

275,474 Trust Units

    

            6,251

      

 $       23,825

       

The purchase price allocation is preliminary and subject to change.  The value assigned to each Enterra Trust Unit of $22.69 (US$18.35) was based on the weighted average trading price on the NASDAQ National Market System immediately prior to and after the measurement date.

       

High Point Resources Inc. ("High Point")

On August 17, 2005 the Trust completed the acquisition of 100% of the common shares of High Point through its subsidiary Rocky Mountain Acquisition Corp. ("RMAC") in exchange for 7,490,898 trust units and 1,407,177 RMAC exchangeable shares.

       

The acquisition was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration paid as follows:

       

Allocation of purchase price:

Current assets, including cash of $2,532

    

 $       12,306

Property, plant and equipment

    

        351,385

Goodwill (with no tax base)

    

          23,544

Current liabilities

    

         (16,522)

Marketing contracts

    

           (3,634)

Debt

     

         (75,000)

Asset retirement obligations

    

           (2,653)

Future income tax liability

    

         (87,970)

      

 $     201,456

       

Cost of acquisition:

7,490,898 Trust Units

    

 $     168,545

1,407,177 Exchangeable Shares

    

          31,661

Transaction costs

    

            1,250

      

 $     201,456

       

The purchase price allocation is preliminary and subject to change.  The value assigned to each Trust Unit and Exchangeable Share of $22.50 was based on the average trading price on the NASDAQ National Market System for the period prior to and after the measurement date.

       

4.  Property, plant and equipment

     
       

September 30,  2005

     

 Accumulated

 
     

 depletion &

 

 

 

 

 

 Cost

 depreciation

 Net

Petroleum and natural gas properties

  

 $     633,390

 $    (115,891)

 $     517,499

Office furniture and equipment

 

 

            2,919

           (1,084)

            1,835

 

 

 

 

 $     636,309

 $    (116,975)

 $     519,334

       

December 31, 2004 (restated)

     

 Accumulated

 
     

depletion &

 

 

 

 

 

Cost

depreciation

 Net

Petroleum and natural gas properties

  

 $     223,637

 $      (76,505)

 $     147,132

Office furniture and equipment

 

 

            2,158

              (832)

            1,326

 

 

 

 

 $     225,795

 $      (77,337)

 $     148,458

       

In the first nine months of 2005 there was $39,000 (2004 - $602,000) general and administrative expense capitalized and included in the cost of the petroleum and natural gas properties.  Included in petroleum and natural gas properties are assets acquired and pledged under capital lease agreements with a cost base of $5,218,000  (2004 - $5,218,000).  At September 30, 2005, costs associated with undeveloped properties of $127,519,000  (2004 - $9,044,000) were excluded from the calculation of depletion expense.

       

5.  Bank indebtedness

     
       

Bank indebtedness represented the outstanding balance under two revolving lines of credit that had a total capacity of $41 million.  Drawings on the revolving facilities bore interest at 1.6% above the bank’s prime lending rate or bankers’ acceptance rates plus margins which were originally set at 165 basis points and were subject to adjustment up or down prospectively, on a three-month basis as determined by the Trust’s consolidated debt to cash flow ratio.  At December 31, 2004 the Trust also had available a demand subordinated debt facility of $4,000,000 which bore interest at the lender's prime rate plus 2%, and this facility was reduced to nil on April 30, 2005.  Security was provided by a first charge over all of the Trust’s assets excluding those acquired in the RMG and High Point acquisitions.

       

The Trust has entered into "Standstill Agreements" with the existing lenders whereby the repayment date of the above credit facilities has been  extended to November 30, 2005.  The terms of the credit facilities have not changed, except the amount available under the credit facilities was reduced to $35,000,000 on October 25, 2005 and will be reduced to $32,000,000 on November 25, 2005.  Any amounts drawn on the facilities must be repaid no later than November 30, 2005.  The Trust is not in compliance with certain non-financial covenants of the credit facility.  The Trust’s lenders have not declared the Trust to be in default, and the Trust is working to bring itself back into full compliance.

       

On November 10, 2005 , the Trust entered into an arrangement with a new group of lenders whereby new credit facilities will be available in the form of two revolving lines of credit that total $90,000,000.  The new credit facilities will replace the above credit facilities.  Drawings on the revolving facilities will bear interest at 0.25% above the bank’s prime lending rate or bankers’ acceptance rates plus margins which will be initially set at 135 basis points and will be subject to adjustment up or down prospectively, on a three-month basis as determined by the Trust’s consolidated debt to cash flow ratio.  Security will be provided by a first charge over all of the Trust’s assets.  The amounts available under these new credit facilities will be subject to a semi-annual borrowing base determination.

       

Drawings under this new credit facility are subject to the Trust having the ability to draw on the Kingsbridge equity line and funds drawn on this new credit facility being sufficient to repay the existing credit facilities and the bridge credit facility in full.  With the filing of the Canadian Base Shelf Prospectus and the corresponding U.S. Registration Statement on November 10, 2005, drawings under the new credit facility are expected to take place no later than November 25, 2005.

       

6.  Bridge credit facility

     
       

The bridge credit facility was put in place on August 17, 2005 to facilitate the acquisition of High Point.  The bridge credit facility is a reducing non-revolving secured loan with a principal amount of $75,000,000.  Security is provided by a first charge on all of the High Point assets that were acquired.  The loan bears interest at bank prime rate plus 1% and is repayable from the proceeds of any debt or equity financing or proceeds from the disposal of assets.  The loan is repayable in full on the earlier of November 30, 2005 or the date where the Trust draws on its new credit facilities with its lenders.

       

7.  Notes payable

     
       

Notes payable consists of an unsecured promissory note for US$3.5 million which bears interest at 12%, and is repayable on July 1, 2006.

       

8.  Asset retirement obligations

     
       

The asset retirement obligations were estimated by management based on the Trust’s working interest in its wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities, and the estimated timing of the costs to be incurred.  At September 30, 2005, the Trust estimated the asset retirement obligations based on a total future liability of $40,134,000 (2004 - $25,354,000).  These obligations will be settled at the end of the useful lives of the underlying assets, which currently extend up to 20 years into the future.  This amount has been calculated using an inflation rate of 2% and discounted using a credit-adjusted risk-free interest rate of 8%.  The following table reconciles the asset retirement obligations:

 

 

 

 

 

 

 

Balance at December 31, 2004

    

$       14,836

Increase in liabilities during the period related to:

    

   Acquisitions

    

            8,074

   Additions

    

               164

   Accretion

    

               987

Balance at September 30, 2005

 

 

 

 

 $       24,061

       

9.  Non-controlling interest

     

 

      

Number of Exchangeable Shares issued

 

Enterra

RMAC series A

RMG

RMAC series B

 Total  

Balance at December 31, 2004

       410,770

       142,444

                  -   

                  -   

        553,214

Issued on acquisition of RMG (Note 3)

                -   

                -   

        736,842

                  -   

        736,842

Issued on acquisition of High Point (Note 3)

                -   

                -   

                  -   

      1,407,177

     1,407,177

Exchanged for Trust Units

       (27,624)

     (142,444)

                  -   

       (558,903)

       (728,971)

Balance at September 30, 2005

       383,146

                -   

        736,842

         848,274

     1,968,262

       

Non-controlling interest

 

 

 

 

 

Balance at December 31, 2004

    

 $         3,349

Issued on acquisition of RMG (Note 3)

    

          16,722

Issued on acquisition of High Point (Note 3)

    

          31,661

Exchanged for Trust Units

    

         (14,918)

Non-controlling interest in net earnings

 

 

 

 

               589

Balance at September 30, 2005

 

 

 

 

 $       37,403

       

The exchangeable shares are convertible at any time into Trust Units, at the option of the holder, based on the prevailing exchange ratio.  In the first nine months of 2005, 27,624 exchangeable shares of Enterra Energy Corp. were converted to 31,878 Trust Units, 142,444 exchangeable shares of RMAC Series A were converted to 147,637 Trust Units and 558,903 exchangeable shares of RMAC Series B were converted to 563,023 Trust Units.   The exchange ratio for Enterra Energy Corp. exchangeable shares was 1.17842 on September 30, 2005 (December 31, 2004 – 1.10534).  The exchange ratio for RMAC series B exchangeable shares was 1.00737 on September 30, 2005 (December 31, 2004 – n/a).  Each exchangeable share of RMG will be exchanged automatically for one Trust Unit on June 1, 2006.

       

10.  Unitholders’ equity

 

    
       

(a)  Unitholders' capital - issued Trust Units

    
       

 

 

 

 

 

 Number of

 

 

 

 

 

 

  Units

 Amount

Balance at December 31, 2004

   

    25,426,800

 $     132,207

Issued for exchangeable shares

   

         742,538

          15,436

Issued in private placement

   

         500,000

          11,709

Issued for services

   

           38,726

               771

Trust Unit options exercised

   

         496,667

            7,640

Issuance costs

   

                  -   

              (231)

Issued on acquisition of RMG (Note 3)

   

         275,474

            6,251

Issued on acquisition of High Point (Note 3)

    

      7,490,898

        168,545

Balance at September 30, 2005

 

 

 

 

    34,971,103

 $     342,328

       

(b) Available equity offering

     
       

On April 22, 2005, the Trust entered into an agreement with Kingsbridge Capital Limited (“Kingsbridge”) whereby they agreed to purchase up to US$100 million of Trust Units over a two-year period.  The Trust has no obligation to access any of the available capital, but may do so at its option.  The subscription price of the Trust Units on each drawdown will be 92% of the fifteen day volume weighted average trading price of the Trust Units on the NASDAQ provided that the price must be at least US$12.00 and not less than the minimum price permitted by the rules of the Toronto Stock Exchange.  The first draw may be up to US$25 million, and each subsequent draw can be up to the lesser of 4% of the Trust’s market capitalization or US$25 million.

       

The Trust granted warrants to Kingsbridge to purchase 301,000 Trust Units. The warrants have a three-year term.  The exercise price of the warrants was initially US$25.77 per Trust Unit and is reduced each month by the amount of the Trust’s distribution for such month on the Trust Units, provided that the price shall not decrease below US$21.55 per Trust Unit.

       

(c)  Contributed surplus

     

 

 

 

 

 

 

 

Balance at December 31, 2004

    

 $              78

Amortization of Trust Unit based compensation

   

               468

Trust Unit options exercised

 

 

 

 

 

              (225)

Balance at September 30, 2005

 

 

 

 

 

 $            321

       

(d)  Trust Unit options

     

 

 

 

 

 

 

 

      

 Weighted-average exercise price

 

 

 

 

 

 Number of Options

Balance at December 31, 2004

   

         950,000

 $         14.22

Granted

   

      1,262,500

 $         23.03

Exercised

   

       (496,667)

 $         14.93

Cancelled

   

       (438,333)

 $         17.06

Balance at September 30, 2005

 

 

 

 

      1,277,500

 $         21.68

       

(e)  Estimated fair value of Trust Unit options

    
       

The estimated fair value of Trust Unit options granted in 2005 was estimated using the Black-Scholes model under the following assumptions:

       

 

 

 

 

 

 

2005

Weighted-average fair value of options granted ($/option)

  

 $           2.17

Risk-free interest rate

    

3.64%

Estimated hold period prior to exercise

    

5 years

Weighted-average volatility

    

34%

Cash distribution yield

 

 

 

 

9.92%

       

(f)  Warrants

     

 

 

 

 

 

Number

 

Balance at December 31, 2004

   

                  -   

 $               -   

Granted

    

         301,000

            1,215

Balance at September 30, 2005

 

 

 

 

         301,000

 $         1,215

       

On April 2, 2005, the Trust granted warrants to purchase 301,000 Trust Units that have a three year term, which cannot be exercised for a six-month period ending October 2, 2005.  The exercise price of the warrants was initially US$25.77 per Trust Unit and is reduced each month by the amount of the Trust’s cash distribution for such month on the Trust Units, provided that the price shall not decrease below US$21.55 per Trust Unit. As at September 30, 2005 the exercise price of the warrants was US$24.99.  The fair value of the warrants has been reflected as deferred financing costs to be transferred to Trust Unit issue charges as the Trust issues new Trust Units.

       

The estimated fair value of the warrants was estimated using the Black-Scholes model under the following assumptions:

       

 

 

 

 

 

 

2005

Weighted-average fair value of warrants granted ($/warrant)

  

 $           4.04

Risk-free interest rate

    

3.64%

Estimated hold period prior to exercise

    

3 years

Weighted-average volatility

    

33%

Cash distribution yield

 

 

 

 

8.54%

       

(g)  Net earnings per Trust Unit

       

The calculation of the weighted average number of Trust Units outstanding for the three and nine month periods ended September 30, 2005 is shown in the table below.  The restated weighted average number of Trust Units outstanding for the three and nine month periods ended September 30, 2004 was 23,221,248 and 21,596,224, respectively (diluted - 23,329,994 and 21,635,439, respectively).

 

 

 

 

 

 

 

    

Net earnings

Weighted average Trust Units outstanding

 

Three Months Ended September 30, 2005

 

 

Per Unit

Basic

   

 $         7,089

    31,052,000

 $           0.23

Exchangeable shares / non-controlling interest

 

               396

      1,753,948

 

Trust Unit options assumed exercised

   

      1,277,500

 

Trust Units assumed purchased

 

 

 

       (985,411)

 

Diluted

 

 

 $         7,485

    33,098,037

 $           0.23

 

 

 

 

 

 

 

    

Net earnings

Weighted average Trust Units outstanding

 

Nine Months Ended September 30, 2005

 

 

Per Unit

Basic

   

 $       13,907

    27,590,771

 $           0.50

Exchangeable shares / non-controlling interest

 

               589

         967,597

 

Trust Unit options assumed exercised

   

      1,277,500

 

Trust Units assumed purchased

   

 

    (1,085,459)

 

Diluted

 

 

 $       14,496

    28,750,409

 $           0.50

       

11.  Commodity contracts

     
       

The Trust is exposed to market risks resulting from fluctuations in commodity prices and from time to time will enter into physical commodity contracts to manage its commodity price exposure.  At September 30, 2005, the following physical commodity contracts were outstanding:

       

Period

 

Volume

 

Units

 

Price / Unit

April 1, 2004 - October 31, 2005

6,000

 

GJ/day

 

$6.95/GJ

April 1, 2004 - October 31, 2005

3,000

 

GJ/day

 

$6.82/GJ

November 1, 2005 - March 31, 2006

3,000

 

GJ/day

 

$8.01/GJ

November 1, 2005 - March 31, 2006

3,000

 

GJ/day

 

$8.32/GJ

November 1, 2005 - March 31, 2006

2,000

 

GJ/day

 

$8.85/GJ

January 1, 2005 - December 31, 2005

1,000

 

mcf/day

 

US$4.14/ mcf

       

The Trust estimated the value of the commodity contracts at September 30, 2005 to be ($8,559,630).

       

12.  Relationship with JED Oil Inc.

     
       

Under a Technical Services Agreement between the Trust and JED Oil Inc. ("JED"), JED provides certain staff to the Trust while the Trust provides office and other administrative services to JED.  As consultants to the Trust, JED’s employees are eligible to participate in benefit plans of the Trust.  The Chairman of JED is also the Chairman of the Board of Directors of the Trust.

       

Under a Technical Services Agreement between the Trust and JED, costs of management, development, exploitation, operations and general and administrative activities are allocated based on relative production and capital expenditures, or as otherwise mutually agreed.  For the nine months ended September 30, 2005, total general and administrative expenses charged by JED to the Trust on a cost recovery basis were approximately $2,102,166 and field-operating expenses charged by JED to the Trust on a cost recovery basis were approximately $2,340,629.

       

JED has loaned funds to the Trust secured by a promissory note.  Interest is charged on the note at a 10%.  There is no stated term of repayment.  For the nine months ended September 30, 2005, $262,000 of interest was charged on the loaned funds.

       

The balance due to JED at September 30, 2005 is $14,870,000 (December 31, 2004 - $4,493,000) consisting of $7,654,000 of notes payable and $7,135,000 of other transactions.

       

13.  Contingencies

     
       

On October 24, 2003, a statement of claim was filed with the Court of Queen’s Bench of Alberta against the Trust in the amount of approximately $12.0 million or as proven by trial.  The claimant was requesting the Trust complete a property purchase that the Trust had terminated negotiations for in 2003.  On August 15, 2005 the outstanding statement of claim was resolved at no cost to the Trust.

       

14.  Guarantees

     
       

The Trust has indemnified all of the directors and officers of the Trust and all the officers, directors, shareholders, employees and agents of JED.  There is no pending litigation or proceeding involving any director or officer of the Trust for which a claim is being sought, nor is the Trust aware of any threatened litigation that may result in claims.

       

15.  Subsequent event

     
       

Subsequent to September 30, the Trust filed its US$500 million Base Shelf Prospectus and corresponding US Registration Statement.  This filing enables the Trust to access the Kingsbridge equity facility (note 10(b)).

       
       





ENTERRA ENERGY TRUST

 

COMPANY INFORMATION

 

  
  

HEAD OFFICE

STOCK EXCHANGE LISTINGS

2600, 500 – 4th Avenue SW

NASDAQ (symbol: EENC)

Calgary, AB  T2P 2V6

TSX (symbol: ENT.UN)

Tel (403) 263-0262

 

Fax (403) 294-1197

TRANSFER AGENT

www.enterraenergy.com

Olympia Trust Company

 

Calgary, AB

DIRECTORS

 

Reg J. Greenslade, Chairman (2) (3)

INDEPENDENT RESERVE ENGINEERS

H.S. (Scobey) Hartley (1) (2) (3) (4)

McDaniel & Associates Consultants Ltd.

William E. Sliney (1) (3) (4)

Calgary, AB

Norman W.G. Wallace (1) (2)

 

E. Keith Conrad (4)

LEGAL COUNSEL

 

Dorsey & Whitney LLP

(1)  Member, Audit Committee

Seattle, Wash.

(2)  Member, Compensation Committee

 

(3)  Member, Reserves Committee

Gowling Lafleur Henderson LLP

(4)  Member, Corporate Governance Committee

Calgary, AB

  

OFFICERS

McCarthy Tétrault LLP

Reg J. Greenslade

Calgary, AB

Chairman of the Board

 
 

INVESTOR INFORMATION

E. Keith Conrad

E. Keith Conrad

President and Chief Executive Officer

President and Chief Executive Officer

 

(403) 263-0262

John Kalman

kconrad@enterraenergy.com

Chief Financial Officer

 
 

Reg Greenslade

John Reader

Chairman

Vice President, Operations & Engineering

(403) 213-2507

 

rgreenslade@enterraenergy.com

AUDITORS

 

KPMG LLP

Linda Latman

Chartered Accountants

Investor Relations

Calgary, AB

(212) 836-9609

 

llatman@equityny.com

BANKERS

 

Alberta Treasury Branches

 

Calgary, AB