ZARGON ENERGY TRUST
TSX : ZAR.UN

ZARGON ENERGY TRUST
Zargon Oil & Gas Ltd.
TSX : ZAR

Zargon Oil & Gas Ltd.

November 14, 2005 00:05 ET

Zargon Energy Trust Announces an Increase in Distributions and Third Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 14, 2005) - Zargon Energy Trust (TSX:ZAR.UN)

FINANCIAL & OPERATING HIGHLIGHTS

Zargon Energy Trust is pleased to report record financial results in the third quarter of 2005. Driven by outstanding commodity prices for both oil and natural gas, the quarter was highlighted by cash flow of $1.15 per diluted trust unit, a 14 percent increase over the 2005 second quarter and a 32 percent increase over the comparable 2004 third quarter. Pursuant to Zargon's corporate strategy of distributing 50 percent of the Trust's projected long term cash flows attributed to the unitholders, the Trust announces that commencing with the November 2005 distribution payable on December 15, 2005, the Trust's monthly cash distribution rate will be increased by $0.02 to $0.18 per trust unit.

Highlights from the three and nine months ended September 30, 2005 are noted below:

- Very strong commodity prices in 2005, combined with relatively stable production volumes resulted in sharply higher revenues, cash flows and net earnings for the nine month period ended September 30, 2005. Revenues for the 2005 nine month period were $112.46 million, a 23 percent increase over the comparable 2004 nine month period. Similarly, cash flow from operations of $58.35 million, or $3.10 per diluted trust unit, for the 2005 nine month period showed 21 percent and 20 percent increases, respectively over the comparable 2004 nine month period. Finally, net earnings of $17.92 million or $1.12 per diluted trust unit for the nine month period provided 17 percent and 30 percent increases, respectively over the comparable 2004 period.

- Oil and liquids production volumes of 3,578 barrels per day in the 2005 third quarter were virtually unchanged from the first and second quarters of 2005 and were five percent higher than the 2004 third quarter. The 2005 third quarter natural gas production volumes of 26.75 million cubic feet per day were four percent lower than the previous quarter and 11 percent below the third quarter 2004 average due primarily to the complete loss of the Trust's previously most prolific gas well (see Production discussion below). On an equivalent basis, third quarter 2005 production averaged 8,036 barrels of equivalent per day, four percent below the 2004 third quarter and two percent below the preceding quarter. For the nine months ended September 30, 2005, production volumes averaged 8,239 barrels of equivalent per day, an increase of one percent from the first nine months of 2004. Production on a per million trust unit outstanding basis averaged 438 barrels of equivalent per day for the first nine months of 2005 and represents a two percent decline from last year's nine month production rate of 445 barrels of equivalent per day.

- In the first nine months of 2005, the Trust paid seven monthly cash distributions of $0.14 per trust unit and two monthly cash distributions of $0.16 per trust unit for a nine month total of $1.30 per trust unit. These distributions were equivalent to a payout ratio of 42 percent of the Trust's 2005 nine month cash flow of $3.10 per diluted trust unit. During the nine month period of 2005, Zargon distributed $20.78 million to unitholders, which after the effect of the exchangeable shares that do not receive cash distributions, represented 36 percent of the Trust's $58.35 million of cash flow from operations for the period. Commencing with the November distribution, Zargon is raising its monthly cash distribution to $0.18 per trust unit. This distribution is based on Zargon's long term sustainable trust strategy that calls for the distribution of approximately 50 percent of the Trust's cash flows attributed to the unitholders. At this time, the Trust's distribution levels have been set assuming long term commodity prices of $50 US per barrel (WTI oil), and $8 US per mmbtu (NYMEX natural gas).

- Capital expenditures for the first nine months of 2005 were $35.56 million and were highlighted by the drilling of 38.1 net wells. The Trust's balance sheet remains very strong with net debt of $19.83 million (excluding unrealized risk management liability) at September 30, 2005, which is slightly less than the third quarter 2005 cash flow from operations. During the first nine months of 2005, the Trust financed 100 percent of distributions and capital expenditures from cash flow from operations, and still had a surplus of $2.01 million of funds available to retire debt and working capital deficiencies.



Three Months Ended Nine Months Ended
September 30, September 30,
-----------------------------------------------
Percent Percent
(unaudited) 2005 2004 Change 2005 2004 Change
------------------------------------------------------------------------

FINANCIAL

Income and Investments
($ million)
Petroleum and natural
gas revenue 42.47 32.41 31 112.46 91.07 23
Cash flow from
operations 21.85 16.13 35 58.35 48.39 21
Cash distributions 7.45 4.27 74 20.78 4.27 387
Net earnings 6.30 4.22 49 17.92 15.31 17
Net capital
expenditures 13.91 23.64 (41) 35.56 41.02 (13)

Per Trust Unit,
Diluted
Cash flow from
operations ($/unit) 1.15 0.87 32 3.10 2.58 20
Net earnings ($/unit) 0.39 0.28 39 1.12 0.86 30

Cash Distributions
($/trust unit) 0.46 0.28 64 1.30 0.28 364

Balance Sheet at
Period End ($ million)
Property and equipment,
net 242.68 200.26 21
Bank indebtedness 11.43 9.77 17
Unitholders' equity 140.90 119.72 18

Total Units Outstanding
at Period End (million) 18.87 18.55 2


OPERATING

Average Daily Production
Oil and liquids (bbl/d) 3,578 3,422 5 3,585 3,348 7
Natural gas (mmcf/d) 26.75 29.90 (11) 27.92 28.81 (3)
Equivalent (boe/d) 8,036 8,405 (4) 8,239 8,149 1
Equivalent per million
total units (boe/d) 427 457 (7) 438 445 (2)

Average Selling Price
(before risk management
losses)
Oil and liquids ($/bbl) 65.91 49.74 33 56.99 44.73 27
Natural gas ($/mcf) 8.44 6.09 39 7.44 6.34 17

Wells Drilled, Net 16.2 15.2 7 38.1 33.5 14

Undeveloped Land at
Period End
(thousand net acres) 365 399 (9)
------------------------------------------------------------------------
------------------------------------------------------------------------

Notes: The calculation of barrels of equivalent is based on the
conversion ratio that six thousand cubic feet of natural gas is
equivalent to one barrel of oil (boe).

Average daily production per million total units is calculated using the
weighted average number of units outstanding during the period, plus the
weighted average number of exchangeable shares outstanding for the
period converted at the exchange ratio at the end of the period.

Total units outstanding include trust units plus exchangeable shares
outstanding at period end. The exchangeable shares are converted at the
exchange ratio at the end of the period.

Cash distributions and cash distributions per trust unit for comparative
purposes commenced August 2004.


PRODUCTION

Natural gas production volumes averaged 26.75 million cubic feet per day in the third quarter 2005 compared to 27.94 million cubic feet per day in the second quarter 2005 and 29.90 million cubic feet per day in the third quarter 2004, declines of four percent and 11 percent respectively. These declines are due to a production loss of almost two million cubic feet per day that occurred in April due to water influx at what had been our most prolific well. The well, located at Progress in the Peace River Arch region of the West Central Alberta core area, partially regained productive capabilities for two months and then watered out completely in August. Successful exploration and development programs, primarily in Zargon's principal gas property located at Jarrow in the Alberta Plains and at Highvale in West Central Alberta are gradually replacing the majority of the lost production.

Oil and liquids production of 3,578 barrels per day in the 2005 third quarter increased five percent over the 2004 third quarter and was level with second quarter 2005. Since the resumption of field activities following a very wet spring, Zargon has continued to expand its oil exploitation programs in the Williston Basin. Specifically, during the third quarter 2005 Zargon successfully drilled and completed five horizontal wells and one vertical well in this core area. These wells are still in various stages of completion and tie-in, however early indications are that the horizontal well at Pinto, Saskatchewan and another at Truro, North Dakota will be substantial producers.

EXPLORATION AND EXPLOITATION(a)

With some delays, the Trust was able to increase its drilling program to a quarterly record of 18 gross wells (16.2 net) in the third quarter 2005, 16 of them operated, that yielded 11 gross (10.0 net) gas wells, six (5.2 net) oil wells and one dry hole for a 94 percent success ratio. Of the natural gas wells, eight were drilled in our Alberta Plains core area and three in the West Central Alberta core area including one in the Peace River Arch. All six oil wells were drilled in the Williston Basin core area.

The Trust plans to continue its recent high level of field activity through the fourth quarter, drilling a minimum of 13 gross wells divided between the Alberta Plains, West Central Alberta and Williston Basin core areas. Consistent with past programs, the Alberta Plains drilling program will focus on natural gas exploration and development at the Jarrow natural gas property. West Central Alberta activities will include additional Pembina natural gas locations, augmented by Highvale and Peace River Arch natural gas exploration. The fourth quarter plan for the Williston Basin properties includes three new horizontals at Elswick in Southeast Saskatchewan and two more horizontals at Haas and Truro in North Dakota, all following up on 2005 successes.

CAPITAL EXPENDITURES(a)

Despite weather and equipment related delays, Zargon's summer-fall field capital program has been both active and successful. Third quarter 2005 field expenditures of $15.13 million raised the nine month level for exploration and development to $35.44 million and the production volumes coming from this work are building strongly. An active field program is continuing in the fourth quarter and total 2005 capital expenditures are anticipated to reach $48 million, a 20 percent increase from the original 2005 capital budget level of $40 million. This increase in the exploration and development budgets can be equally attributed to an increase in the 2005 drilling program to 50 net wells, and to an increase in field costs as a result of very high industry activity levels.

Zargon continues to post land and bid at Alberta and Saskatchewan Crown sales, but in an increasingly competitive environment. In the nine months ended September 30, 2005, Zargon spent $2.31 million on undeveloped land, a decrease of 25 percent from the prior year's comparable period. During the nine month period undeveloped land expiries were mostly offset by 27 thousand net acres of land purchases, leaving a net reduction of 11 thousand net acres when compared to December 31, 2004. Notwithstanding this modest reduction, Zargon still retains a substantial undeveloped land inventory of 365 thousand net acres.

Zargon's activities in the property acquisition market have been limited throughout the first nine months of 2005 due to the high cost of acceptable opportunities and on a net basis, property acquisition expenditures were close to zero. In particular, the Trust took advantage of strong property prices in the third quarter and sold minor non-operated interests in the Alberta Plains and Williston Basin core areas for $2.28 million.

GUIDANCE(a)

In the August 11, 2005 press release announcing the results for the first half of 2005, production guidance for the Trust in the second half of 2005 was revised to take into account the first phase of production difficulties encountered with the Progress gas well. Third quarter 2005 rates were anticipated to roughly match second quarter levels, and growth in production volumes was expected to be delayed until the fourth quarter when gains from Alberta Plains natural gas exploration and Williston Basin oil exploitation drilling programs materialized. With the Progress well completely watering out in August, third quarter 2005 natural gas production volumes of 26.75 million cubic feet per day missed guidance levels by 1.19 million cubic feet per day and although oil production volumes met guidance, Zargon's third quarter production of 8,036 barrels of equivalent per day was two percent below guidance levels.

However, based on the successful summer-fall drilling program, the Trust is forecasting fourth quarter 2005 production volumes to increase significantly from third quarter levels to 8,500 barrels per day. This fourth quarter level meets the previous fourth quarter guidance of 8,500 barrels of oil equivalent per day, but is now comprised of a more oil-weighted 3,900 barrels per day of oil and liquids and 27.60 million cubic feet per day of natural gas. On a preliminary basis, Zargon is providing calendar 2006 production guidance at 8,600 barrels of equivalent per day which is premised on a 2006 exploration and development capital program of $45 million.

The aforementioned production guidance volumes do not include an allowance for opportunistic property or corporate acquisitions that would be funded by bank debt or possibly equity issues. Although recently stymied by high property prices, Zargon's acquisition initiatives will continue to be focused on acquiring underdeveloped oil properties (particularly in the Williston Basin) or undeveloped natural gas prospective lands that provide Zargon exploration and development opportunities to sustain production and reserves on a per unit basis, while distributing approximately 50 percent of the Trust's projected long term cash flows attributed to the unitholders.

(a) Please see comments on "Forward-Looking Statements" on the last page of this report.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis (MD&A) should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2005 and the audited consolidated financial statements and MD&A for the year ended December 31, 2004. All amounts are in Canadian dollars unless otherwise noted. All references to "Zargon" or the "Trust" refer to Zargon Energy Trust and all references to the "Company" refer to Zargon Oil & Gas Ltd.

In the MD&A, reserves and production are commonly stated in barrels of equivalent (boe) on the basis that six thousand cubic feet of natural gas is equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalent conversion method primarily applicable to the burner tip and does not represent a value equivalent at the wellhead.

Non-GAAP Measurements: The MD&A contains the term "cash flow from operations"("cash flow") which should not be considered an alternative to, or more meaningful than, "cash flow from operating activities" as determined in accordance with Canadian GAAP as an indicator of the Trust's financial performance. This term does not have any standardized meaning as prescribed by GAAP and therefore, the Trust's determination of cash flow from operations may not be comparable to that reported by other trusts. The reconciliation between net earnings and cash flow from operations can be found in the consolidated statements of cash flows in the consolidated financial statements. The Trust evaluates its performance based on net earnings and cash flow from operations. The Trust considers cash flow from operations to be a key measure as it demonstrates the Trust's ability to generate the cash necessary to pay distributions, repay debt and to fund future capital investment. It is also used by research analysts to value and compare oil and gas trusts, and it is frequently included in published research when providing investment recommendations. Cash flow from operations per unit is calculated using the diluted weighted average number of units for the period.

This MD&A has been prepared as of November 10, 2005.

PLAN OF ARRANGEMENT

On July 15, 2004, approval was given by the shareholders to a resolution in favour of a Plan of Arrangement (the "Arrangement") reorganizing Zargon Oil & Gas Ltd. (the "Company") into Zargon Energy Trust (the "Trust" or "Zargon"). The Arrangement received court approval and also became effective on July 15, 2004. The Arrangement resulted in shareholders of the Company receiving either one trust unit or one exchangeable share for each common share held. The unitholders of the Trust are entitled to receive cash distributions paid by the Trust. Holders of exchangeable shares are not eligible to receive distributions but rather on each payment of a distribution, the number of trust units into which each exchangeable share is exchangeable is increased on a cumulative basis in respect of the distribution. The exchangeable shares are traded on the Toronto Stock Exchange and can be converted, at the option of the holder, into trust units at any time. On July 15, 2014, all the remaining outstanding exchangeable shares will be redeemed into trust units unless the Board of Directors of the Company elect to extend the redemption period. In certain circumstances, the Company has the right to require redemption of the exchangeable shares prior to July 15, 2014. Upon completion of the Arrangement, 14.87 million trust units and 3.66 million exchangeable shares were issued. The Trust is an unincorporated open-ended investment trust governed by the laws of the Province of Alberta. It is the intent of the Trust to distribute, over the long term, an average of 50 percent of the cash flow from operations attributable to outstanding unitholders. On September 15, 2004 Zargon commenced cash distributions, relating to August 2004, of $0.14 per trust unit.

The reorganization of the Company into a Trust has been accounted for using the continuity of interest method. Accordingly, the consolidated financial statements for the three and nine months ended September 30, 2005 reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by the Company. The comparative figures referred to in the consolidated financial statements and this MD&A include the previous consolidated results of the Company.

SUMMARY OF SIGNIFICANT EVENTS IN THE THIRD QUARTER

- As a result of continued high commodity prices, the Trust realized another quarterly record cash flow from operations of $21.85 million in the third quarter of 2005 and paid or declared total distributions of $7.45 million ($0.46 per trust unit) to unitholders, resulting in a quarterly payout ratio of 34 percent of cash flow or 40 percent on a per diluted trust unit basis. For Canadian income tax purposes, the distributions are currently estimated to be 100 percent taxable income to unitholders.

- Average field prices for the third quarter received (before risk management losses) for oil and liquids increased to $65.91 per barrel and for natural gas increased to $8.44 per thousand cubic feet, a 22 percent and 18 percent increase, respectively, from the second quarter of 2005. Production of 8,036 barrels of oil equivalent was down two percent from the previous quarter.

- During the third quarter of 2005, the Trust drilled 18 gross wells (16.2 net) with a 94 percent success rate. Total net capital expenditures were $13.91 million for the quarter.

- The Trust continues to maintain its balance sheet strength with a combined debt and working capital deficiency of $19.83 million (excluding the unrealized risk management liability), which represents just over three months of the first nine months 2005 annualized cash flow.

FINANCIAL ANALYSIS

Crude oil and natural gas prices continued to reach new highs during the third quarter of 2005. Canadian benchmark prices received by Zargon for its production increased as a result of the overall impact that the Gulf Coast hurricanes caused on commodity inventory levels and reduced production. These commodity price increases more than offset a decrease in production volumes of two percent from the previous quarter, resulting in another record quarter for revenue of $42.47 million, an 18 percent increase compared to the second quarter of 2005. Oil and liquids prices received averaged $65.91 per barrel before risk management losses in third quarter 2005 compared to $49.74 in the 2004 third quarter and $54.13 in the preceding quarter, gains of 33 percent and 22 percent respectively. Reflecting industry trends, Zargon's crude oil field price differential from the Edmonton par price, increased to $10.60 per barrel in the third quarter of 2005 compared to $6.51 per barrel in the third quarter of 2004. Natural gas prices averaged $8.44 per thousand cubic feet before risk management losses in the third quarter of 2005, an increase of 39 percent and 18 percent, respectively, over the 2004 third quarter and the preceding quarter levels. The difference between the realized price received for natural gas and the benchmark AECO average daily price during the third quarter of 2005 widened primarily due to fixed price physical contracts (see note 10 to the consolidated financial statements) and Zargon also receiving the AECO monthly index, which is set prior to the actual month of delivery, versus the AECO average daily index for approximately 30 percent of its gas production.



Pricing

Three Months Ended Nine Months Ended
September 30, September 30,
-----------------------------------------------
Percent Percent
Average For The Period 2005 2004 Change 2005 2004 Change
------------------------------------------------------------------------

Natural Gas:
NYMEX monthly index
price ($US/mmbtu) 8.25 5.84 41 7.15 5.83 23
AECO average daily spot
price ($Cdn/mmbtu) 9.37 6.21 51 7.88 6.54 20
Realized price
($Cdn/mcf) (note 1) 8.44 6.09 39 7.44 6.34 17

Crude Oil:
WTI ($US/bbl) 63.19 43.88 44 55.40 39.11 42
Edmonton par price
($Cdn/bbl) 76.51 56.25 36 67.91 50.82 34
Realized price
($Cdn/bbl) (note 1) 65.91 49.74 33 56.99 44.73 27

------------------------------------------------------------------------
------------------------------------------------------------------------

Note 1: Amounts are before risk management losses.


Natural gas production volumes of 26.75 million cubic feet per day in the 2005 third quarter decreased four percent over the preceding quarter and 11 percent from 2004 third quarter levels due to production losses at a significant well in the West Central Alberta core area, and delays in the tie-in of new wells due to wet field conditions and third quarter processing facility maintenance related shut-ins in the Alberta Plains core area. Oil and liquids production volumes in the third quarter of 2005 of 3,578 barrels per day were relatively unchanged from the previous quarter's production of 3,582 barrels per day. On a year-over-year basis, oil and liquids volumes increased five percent when compared to the third quarter of 2004 volumes, primarily due to the July 26, 2004 acquisition of Southeast Saskatchewan properties and new exploitation drilling in the Williston Basin core area.



Production by Core Area

2005 2004
-------------------------------------------------------------
Three
Months
Ended Oil Oil
September and Natural and Natural
30, Liquids Gas Equivalents Liquids Gas Equivalents
------------------------------------------------------------------------
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)

Alberta
Plains 531 18.47 3,608 595 19.63 3,867
West Central
Alberta 211 8.06 1,556 211 10.01 1,879
Williston
Basin 2,836 0.22 2,872 2,616 0.26 2,659
-------------------------------------------------------------

3,578 26.75 8,036 3,422 29.90 8,405
------------------------------------------------------------------------
------------------------------------------------------------------------


2005 2004
-------------------------------------------------------------
Nine
Months
Ended Oil Oil
September and Natural and Natural
30, Liquids Gas Equivalents Liquids Gas Equivalents
------------------------------------------------------------------------
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)

Alberta
Plains 556 19.19 3,754 606 18.87 3,750
West Central
Alberta 206 8.48 1,620 222 9.69 1,837
Williston
Basin 2,823 0.25 2,865 2,520 0.25 2,562
-------------------------------------------------------------

3,585 27.92 8,239 3,348 28.81 8,149
------------------------------------------------------------------------
------------------------------------------------------------------------


Zargon's commodity price risk management policy uses forward sales, options, puts and costless collars for, on average, 20 to 35 percent of working interest production in order to partially offset the effects of large price fluctuations. Because our risk management strategy is protective in nature and is designed to guard the Trust against extreme effects on cash flow from sudden falls in prices and revenues, upward price trends tend to produce overall losses. Financial risk management contracts in place as at December 31, 2004 were designated as hedges for accounting purposes and the Trust continues to monitor these contracts in determining the continuation of hedge effectiveness. For these contracts, realized gains and losses are recorded in the statement of earnings as the contracts settle and no unrealized gain or loss is recognized. For financial risk management contracts entered into after December 31, 2004, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes. Accordingly, for outstanding contracts not designated as hedges as at September 30, 2005, an unrealized gain or loss is recorded on the fair value (mark-to-market) of the contracts at that time. Thus, the 2005 third quarter's continued high oil and natural gas prices brought about a realized risk management loss of $2.62 million compared to a $1.43 million loss in the third quarter of 2004 and $1.23 million in the preceding quarter. The unrealized risk management loss for the third quarter of 2005 was $5.30 million compared to $1.10 million in the preceding quarter. The primary driver for these losses was the high natural gas prices recorded in the current quarter. Contracts settled by physical delivery which may contain fixed, floor or collar pricing are recognized as part of the normal revenue stream. Zargon's financial and physical commodity risk management positions are fully described in note 10 to the unaudited consolidated interim financial statements.

Royalties, inclusive of Alberta Royalty Tax Credit and Saskatchewan Resource Surcharge, totalled $9.78 million for the third quarter of 2005, an increase of 24 percent from the preceding quarter and an increase of 32 percent from $7.39 million in the 2004 third quarter. As a percentage of gross revenue, royalty rates have moved in a narrow range from 22.8 percent in the third quarter of 2004 to 22.1 percent in the second quarter of 2005 and 23.0 percent in the third quarter of 2005.

On a unit of production basis, production costs for the quarter have increased to $8.52 per barrel of equivalent from $7.67 per barrel of equivalent in the second quarter 2005 and $7.45 in the third quarter 2004. The increase in the per unit costs is primarily due to seasonal natural gas facility, battery and well maintenance costs and increased industry-wide cost pressures. Zargon is continuing its efforts to contain increases in per unit operating costs during this very active period in the oil and gas industry and is striving to maintain per barrel of equivalent costs at current levels.



Operating Netbacks
2005 2004
---------------------------------------
Three Months Ended Oil and Natural Oil and Natural
September 30, Liquids Gas Liquids Gas
------------------------------------------------------------------------
($/bbl) ($/mcf) ($/bbl) ($/mcf)

Production revenue 65.91 8.44 49.74 6.09
Realized risk management loss (5.58) (0.32) (3.81) (0.08)
Royalties (14.47) (2.04) (10.86) (1.50)
Production costs (11.74) (0.99) (11.74) (0.75)
---------------------------------------

Operating netbacks 34.12 5.09 23.33 3.76
------------------------------------------------------------------------
------------------------------------------------------------------------


2005 2004
---------------------------------------
Nine Months Ended Oil and Natural Oil and Natural
September 30, Liquids Gas Liquids Gas
------------------------------------------------------------------------
($/bbl) ($/mcf) ($/bbl) ($/mcf)

Production revenue 56.99 7.44 44.73 6.34
Realized risk management loss (3.76) (0.13) (2.85) (0.05)
Royalties (12.72) (1.74) (9.45) (1.46)
Production costs (10.64) (0.99) (10.29) (0.76)
---------------------------------------

Operating netbacks 29.87 4.58 22.14 4.07
------------------------------------------------------------------------
------------------------------------------------------------------------


Measured on a unit of production basis (net of recoveries), general and administrative expenses were $1.80 per barrel of equivalent in the first nine months of 2005 compared to $1.36 per barrel of equivalent in the first nine months of 2004 and $1.45 for the 2004 year. The increase in costs on a per unit of production basis are primarily due to increased staff costs, increased outside advisory costs related to operating as a trust and securities regulatory compliance costs primarily as a result of new regulations in Canada related to documentation of internal financial controls.

Expensing of unit-based compensation in the first nine months of 2005 was $0.66 million, a 78 percent decrease compared to the first nine months of 2004. This decrease is primarily due to the one time charge incurred in the third quarter of 2004 for the accelerated vesting of stock options related to the July 15, 2004 Arrangement. The unit-based compensation expense, arising from unit rights granted upon and subsequent to the July 15, 2004 Plan of Arrangement, was originally calculated using the intrinsic value method up until December 31, 2004. In response to an emphasis by securities regulators that fair value methodologies be used, new measurement techniques were adopted for 2005 utilizing a fair value option-pricing model for such unit rights grants. Zargon has assessed the impact on amounts previously recorded as 2004 unit-based compensation expense, and there is no significant impact.

Interest expense in the first nine months of 2005 was $0.56 million, $0.32 million higher compared to the first nine months of 2004. The primary reason for the increase on a year-over-year basis is the increase in average bank indebtedness due to the acquisition of Southeastern Saskatchewan properties and reorganization costs related to the trust conversion incurred in the third quarter of 2004.

Capital and current income taxes were $1.20 million in the first nine months of 2005 compared to $0.80 million in the first nine months of 2004. On a year-to-date basis, United States current income taxes are $0.69 million and Canadian capital taxes are $0.51 million compared to $0.39 million and $0.41 million for the first nine months of 2004. The primary reason for this increase in United States current income taxes is due to the increasing profitability of those operations as a result of higher commodity prices.



Trust Netbacks

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
($/boe) 2005 2004 2005 2004
------------------------------------------------------------------------

Petroleum and natural
gas revenue 57.45 41.91 50.00 40.79
Realized risk management loss (3.54) (1.84) (2.06) (1.35)
Royalties (13.23) (9.56) (11.45) (9.05)
Production costs (8.52) (7.45) (7.97) (6.90)
----------------------------------------

Operating netbacks 32.16 23.06 28.52 23.49

General and administrative (2.04) (1.38) (1.80) (1.36)
Interest (0.23) (0.13) (0.25) (0.10)
Capital and current
income taxes (0.33) (0.69) (0.53) (0.36)
----------------------------------------

Cash flow netbacks 29.56 20.86 25.94 21.67

Depletion and depreciation (12.61) (9.06) (12.06) (8.80)
Unrealized risk management loss (7.17) - (3.85) -
Accretion of asset
retirement obligations (0.41) (0.35) (0.40) (0.36)
Unit/stock-based compensation (0.25) (3.45) (0.29) (1.33)
Unrealized foreign
exchange gain 0.50 0.37 0.10 0.12
Future income taxes 0.31 (1.79) (0.06) (4.06)
----------------------------------------

Earnings before
non-controlling interest 9.93 6.58 9.38 7.24
------------------------------------------------------------------------
------------------------------------------------------------------------


The third quarter 2005 depletion and depreciation unit expense of $12.61 per barrel of equivalent is a five percent increase over the previous quarter expense of $12.05 per barrel of oil equivalent and a 39 percent increase from the third quarter 2004 expense of $9.06 per barrel of oil equivalent. Approximately $0.30 of the per barrel of equivalent increase from the second quarter to the third quarter of 2005 was due to the write off of proved reserves of 2.4 billion cubic feet related to the production loss at a significant well in the West Central Alberta core area. The remainder of the increase from the prior quarter and on a year-over-year basis is primarily due to the increase in the property and equipment balance from the conversion of exchangeable shares due to the application of EIC-151.

The provision for accretion of asset retirement obligations for the first nine months of 2005 was $0.89 million, a 12 percent increase compared to the first nine months of 2004. The year-over-year change is due to changes in the estimated future liability for asset retirement obligations as a result of wells added through the drilling program and the 2004 acquisition of Southeast Saskatchewan properties in the Williston Basin core area.

The provision for future taxes was $0.15 million for the first nine months of 2005 compared to $9.07 million in the first nine months of 2004. The year-over-year reduction is due to the trust conversion since Zargon's future tax obligations are reduced as distributions are made from the Trust. In September 2005, the Department of Finance of the Government of Canada released a consultation paper "Tax and Other Issues Related to Publicly Listed Flow-Through Entities (Income Trusts and Limited Partnerships)". The purpose of this paper is for the Government of Canada to seek input by December 31, 2005 on tax and other economic issues related to business income trusts and their impact on federal tax revenues and the Canadian economy. Zargon is closely monitoring these developments but is unable to determine the impact on its tax position or that of its unitholders, if any, at this time.

On January 19, 2005 the CICA issued EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that states that exchangeable securities issued by a subsidiary of an Income Trust should be reflected as either a non-controlling interest or debt on the consolidated balance sheet unless they meet certain criteria. The exchangeable shares issued by Zargon Oil & Gas Ltd., a corporate subsidiary of the Trust, are publicly traded and have an expiry term, which could be extended at the option of the Board of Directors. Therefore, these securities are considered, by EIC-151, to be transferable to third parties and to have an indefinite life. EIC-151 states that if these criteria are met, the exchangeable shares should be reflected as a non-controlling interest. Previously, the exchangeable shares were reflected as a component of unitholders' equity. In accordance with the transitional provisions of EIC-151, the Trust adopted this standard as at December 31, 2004 and has retroactively restated prior periods dating back to the Plan of Arrangement dated July 15, 2004. As a result of this change in accounting policy, the Trust has reflected a non-controlling interest of $10.00 million on the Trust's consolidated balance sheet as at September 30, 2005. Consolidated net earnings have been reduced for net earnings attributable to the non-controlling interest of $3.18 million in the first nine months of 2005. In accordance with EIC-151 and given the circumstances in Zargon's case, each redemption is accounted for as a step-purchase, which to date in 2005 has resulted in an increase in property and equipment of $23.86 million, an increase in unitholders' equity by $20.84 million, and an increase in future income tax liability of $6.20 million. Cash flow was not impacted by this change. The cumulative impact to date of the application of EIC-151 has been to increase property and equipment by $35.14 million, accumulated depletion and depreciation by $3.72 million, unitholders' equity and non-controlling interest by $30.99 million, future income tax liability by $9.20 million and an allocation of net earnings to exchangeable shareholders' of $5.05 million.

Cash flow from operations in the third quarter 2005 of $21.85 million was $2.84 million or 15 percent higher than the preceding quarter and $5.72 million or 35 percent higher than the 2004 third quarter. The 2005 first nine months cash flow from operations of $58.35 million was 21 percent higher than the prior year's comparative period primarily as a result of a 20 percent increase in the cash flow netback to $25.94 per barrel of oil equivalent and a one percent increase in production volumes to 8,239 barrels of oil equivalent. Cash flow per diluted unit showed similar gains with the 2005 third quarter cash flow of $1.15 per diluted trust unit increasing 14 percent over the second quarter levels and the 2005 first nine months cash flow of $3.10 per diluted unit improving 20 percent over the 2004 comparable period.

Net earnings of $6.30 million for the third quarter of 2005 decreased three percent from the preceding quarter and increased 49 percent from the third quarter of 2004. The net earnings track the cash flow from operations for the respective periods modified by non-cash charges which in the 2005 period include increased depletion and depreciation, unrealized risk management losses and non-controlling interest.



Capital Expenditures

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
($ million) 2005 2004 2005 2004
------------------------------------------------------------------------

Undeveloped land 0.58 1.21 2.31 3.06
Geological and geophysical
(seismic) 1.06 1.09 2.53 3.45
Drilling and completion
of wells 10.10 8.45 23.25 18.18
Well equipment and facilities 3.39 1.80 7.35 4.72
----------------------------------------

Exploration and development 15.13 12.55 35.44 29.41
----------------------------------------

Property acquisitions 1.06 11.09 2.40 11.88
Property dispositions (2.28) - (2.28) (0.27)
----------------------------------------

Net property acquisitions
(dispositions) (1.22) 11.09 0.12 11.61
----------------------------------------

Total capital expenditures (net) 13.91 23.64 35.56 41.02
------------------------------------------------------------------------
------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Net capital expenditures of $35.56 million in the first nine months of 2005 were 13 percent lower than in the first nine months of 2004. Capital expenditures for the first nine months of 2005 were allocated to Alberta Plains $12.49 million, West Central Alberta $10.15 million and Williston Basin $12.92 million. Drilling and completion expenditures increased 28 percent from the previous year to $23.25 million and well equipping correspondingly increased 56 percent to $7.35 million during the same period reflecting an active field program of 43 gross (38.1 net) wells compared to 40 gross (33.5 net) wells in the first nine months of 2004. Undeveloped land purchases fell 25 percent as Zargon continues a more selective land acquisition program as Crown sales continue to be extremely competitive. Net property acquisitions are $11.49 million lower in the nine month period ended September 30, 2005 compared to the same period in 2004 as a result of the acquisition of producing oil property interests in Southeast Saskatchewan which occurred in July 2004. Cash flow from operations in the first nine months of 2005 of $58.35 million and proceeds from the exercise of trust unit rights of $2.13 million funded the capital program, payment of distributions and a reduction of the working capital deficiency and bank indebtedness. As at September 30, 2005, the Trust continues to maintain a strong balance sheet with a combined debt and working capital deficiency (excluding the unrealized risk management liability) of $19.83 million, which is just over three months of the first nine months annualized cash flow.

On September 30, 2005, Zargon obtained syndicated committed credit facilities with a borrowing base of $80 million which replaces its former demand facility of $50 million. These facilities consist of a Canadian $60 million tranche and a US $15 million tranche. These facilities are fully revolving for a 364 day period with the provision for an annual extension at the option of the lenders and upon notice from the Company. Zargon's oil and gas properties have been provided as security for these facilities.

At November 10, 2005, Zargon Energy Trust has 16.263 million trust units and 2.419 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective exchange ratio of 1.08981, there would be 18.884 million trust units outstanding. Pursuant to the trust unit rights incentive plan there are currently an additional 0.778 million trust unit incentive rights issued and outstanding.



Capital Sources

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
($ million) 2005 2004 2005 2004
------------------------------------------------------------------------

Cash flow from operations 21.85 16.13 58.35 48.39
Changes in working capital
and other 2.48 9.91 (1.34) 0.68
Change in bank indebtedness (4.09) 9.77 (2.80) 2.79
Reorganization costs - (9.44) - (9.44)
Cash distributions (7.45) (4.27) (20.78) (4.27)
Issuance of trust units/shares
related to exercise of trust
unit rights/stock options 1.12 1.54 2.13 2.87
----------------------------------------

Total capital sources 13.91 23.64 35.56 41.02
------------------------------------------------------------------------
------------------------------------------------------------------------


OUTLOOK

Zargon continues to be well positioned with a very strong balance sheet, 365 thousand net acres of undeveloped land and a promising project inventory. The loss of production from a significant well in West Central Alberta, facility maintenance shut-ins and the delayed tie-in of production due to wet weather conditions resulted in reduced production volumes for the third quarter of 2005. However, with the recent tie-in of wells and drilling activity in the Williston Basin and Alberta Plains core areas, Zargon is forecasting an average production rate of 8,500 barrels of oil equivalent per day for the fourth quarter of 2005 and 8,600 barrels of oil equivalent per day for the 2006 year. Zargon intends to continue its disciplined approach with a strategy of focusing on exploration and exploitation of its existing asset base while executing value-added property acquisitions when they become available.



SUMMARY OF QUARTERLY RESULTS
2005
--------------------
Q1 Q2 Q3
------------------------------------------------------------------------
Petroleum and natural gas revenue ($ million) 34.12 35.87 42.47
Net earnings ($ million) 5.14 6.48 6.30
Net earnings per diluted unit ($) 0.32 0.41 0.39
Cash flow ($ million) 17.48 19.01 21.85
Cash flow per diluted unit ($) 0.93 1.01 1.15
Cash distributions ($ million) 6.60 6.73 7.45
Cash distributions paid or declared per unit ($) 0.42 0.42 0.46
Net capital expenditures ($ million) 10.69 10.96 13.91
Total assets ($ million) 245.20 253.75 264.44
Bank debt ($ million) 18.23 15.52 11.43
Daily production (boe) 8,446 8,238 8,036
Average realized commodity price before risk
management losses ($/boe) 44.90 47.85 57.45
Cash flow netback ($/boe) 23.01 25.36 29.56
------------------------------------------------------------------------
------------------------------------------------------------------------

2004
---------------------------
Q1 Q2 Q3 Q4
------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 27.70 30.96 32.41 32.90
Net earnings ($ million) (note 1) 5.54 5.54 4.22 5.33
Net earnings per diluted unit ($)
(note 1) 0.30 0.29 0.28 0.34
Cash flow ($ million) 15.73 16.53 16.13 15.36
Cash flow per diluted unit ($) 0.84 0.88 0.87 0.82
Cash distributions ($ million) - - 4.27 6.43
Cash distributions paid or declared
per unit ($) - - 0.28 0.42
Net capital expenditures ($ million) 9.77 7.61 23.64 15.25
Total assets ($ million) (note 1) 186.18 189.80 215.23 226.96
Bank debt ($ million) 3.67 - 9.77 14.23
Daily production (boe) 7,889 8,150 8,405 8,440
Average realized commodity price before
risk management losses ($/boe) 38.59 41.75 41.91 42.36
Cash flow netback ($/boe) 21.91 22.28 20.86 19.78
------------------------------------------------------------------------
------------------------------------------------------------------------

2003
---------------------------
Q1 Q2 Q3 Q4
------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 29.19 24.20 23.76 24.51
Net earnings ($ million) (note 1) 6.65 9.17 4.44 4.10
Net earnings per diluted unit ($)
(note 1) 0.36 0.50 0.24 0.22
Cash flow ($ million) 15.23 13.53 12.34 13.24
Cash flow per diluted unit ($) 0.84 0.74 0.67 0.72
Net capital expenditures ($ million) 6.86 8.10 12.11 12.84
Total assets ($ million) (note 1) 165.12 165.98 172.81 181.05
Bank debt ($ million) 20.78 11.47 8.92 6.98
Daily production (boe) 7,060 7,222 7,470 8,020
Average realized commodity price before
risk management losses ($/boe) 45.94 36.82 34.57 33.22
Cash flow netback ($/boe) 23.96 20.58 17.96 17.95
------------------------------------------------------------------------
------------------------------------------------------------------------

Note 1: Certain comparative period numbers reflect retroactive
restatements due to changes in accounting policies.


ADDITIONAL INFORMATION

Additional information regarding the Trust and its business operations, including the Trust's Renewal Annual Information Form for December 31, 2004, is available on the Trust's SEDAR profile at www.sedar.com.



"Signed" C.H. Hansen
President and Chief Executive Officer


Calgary, Alberta
November 10, 2005


ZARGON ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

(unaudited) September 30, December 31,
($ thousand) 2005 2004
------------------------------------------------------------------------

ASSETS

Current
Accounts receivable 19,591 14,275
Prepaid expenses and deposits 2,168 2,953
---------------------------
21,759 17,228

Property and equipment,
net (notes 3 and 4) 242,676 209,736
---------------------------

264,435 226,964
---------------------------
---------------------------
LIABILITIES

Current
Bank indebtedness (note 4) - 14,230
Accounts payable and accrued liabilities 27,560 24,153
Cash distributions payable 2,600 2,210
Unrealized risk management liability (note 10) 8,650 -
---------------------------
38,810 40,593

Long term debt (note 4) 11,429 -

Asset retirement obligations (note 5) 15,403 14,390

Future income taxes 47,884 41,830
---------------------------

113,526 96,813
---------------------------
NON-CONTROLLING INTEREST

Exchangeable shares (note 2) 10,006 9,529
---------------------------

UNITHOLDERS' EQUITY

Unitholders' capital (note 6) 68,831 45,755
Contributed surplus (note 6) 1,242 1,170
Accumulated earnings 102,316 84,399
Accumulated cash distributions (note 11) (31,486) (10,702)
---------------------------

140,903 120,622
---------------------------

264,435 226,964
---------------------------
---------------------------
See accompanying notes.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF EARNINGS AND ACCUMULATED EARNINGS

Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
($ thousand, except
per unit amounts) 2005 2004 2005 2004
------------------------------------------------------------------------
(restated - (restated -
note 2) note 2)

Revenue
Petroleum and natural
gas revenue 42,468 32,409 112,460 91,072
Unrealized risk management
loss (note 10) (5,299) - (8,650) -
Realized risk management
loss (note 10) (2,618) (1,427) (4,637) (3,010)
Royalties (net of Alberta
Royalty Tax Credit) (9,781) (7,394) (25,727) (20,203)
---------------------------------------
24,770 23,588 73,446 67,859
---------------------------------------
Expenses
Production 6,298 5,762 17,931 15,413
General and administrative 1,505 1,069 4,059 3,027
Unit/stock-based
compensation (note 6) 185 2,663 658 2,972
Interest 171 99 555 233
Unrealized foreign exchange gain (369) (287) (218) (263)
Accretion of asset retirement
obligations (note 5) 301 274 893 799
Depletion and depreciation 9,324 7,009 27,125 19,648
---------------------------------------
17,415 16,589 51,003 41,829
---------------------------------------

Earnings before income taxes 7,355 6,999 22,443 26,030
---------------------------------------

Income taxes
Future (recovery) (232) 1,385 145 9,065
Current 241 527 1,200 797
---------------------------------------
9 1,912 1,345 9,862
---------------------------------------

Earnings for the period before
non-controlling interest 7,346 5,087 21,098 16,168
Non-controlling interest -
exchangeable shares (note 2) (1,051) (863) (3,181) (863)
---------------------------------------

Net earnings for the period 6,295 4,224 17,917 15,305
---------------------------------------

Accumulated earnings,
beginning of period
As previously reported 96,021 81,086 84,399 70,125
Retroactive application of
change in accounting policy -
asset retirement obligations - - - (120)
---------------------------------------
As restated 96,021 81,086 84,399 70,005
---------------------------------------
Reorganization costs upon
trust conversion - (6,238) - (6,238)
---------------------------------------
Accumulated earnings,
end of period 102,316 79,072 102,316 79,072
---------------------------------------
---------------------------------------

Net earnings per unit/per
common share (note 7)
Basic 0.39 0.24 1.13 0.88
Diluted 0.39 0.28 1.12 0.86
---------------------------------------
---------------------------------------
See accompanying notes.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
($ thousand) 2005 2004 2005 2004
------------------------------------------------------------------------
(restated - (restated -
note 2) note 2)

Operating activities
Net earnings for the period 6,295 4,224 17,917 15,305
Add (deduct) non-cash items:
Non-controlling interest -
exchangeable shares 1,051 863 3,181 863
Unrealized risk management loss 5,299 - 8,650 -
Depletion and depreciation 9,324 7,009 27,125 19,648
Accretion of asset
retirement obligations 301 274 893 799
Unit/stock-based compensation 185 2,663 658 2,972
Unrealized foreign exchange gain (369) (287) (218) (263)
Future income taxes (recovery) (232) 1,385 145 9,065
---------------------------------------
21,854 16,131 58,351 48,389

Asset retirement expenditures (151) (91) (372) (147)
Changes in non-cash working capital (655) 5,262 (886) 2,052
---------------------------------------
21,048 21,302 57,093 50,294
---------------------------------------

Financing activities
Advances (repayment) of
bank indebtedness (4,093) 9,771 (2,801) 2,793
Cash distributions to unitholders (7,448) (4,271) (20,784) (4,271)
Exercise of unit
rights/stock options 1,122 1,537 2,130 2,867
Changes in non-cash
working capital 342 2,140 453 2,140
---------------------------------------
(10,077) 9,177 (21,002) 3,529
---------------------------------------

Investing activities
Additions to property
and equipment (16,192) (23,640) (37,842) (41,291)
Proceeds on disposal of
property and equipment 2,284 - 2,284 275
Reorganization costs - (9,443) - (9,443)
Changes in non-cash
working capital 2,937 1,399 (533) (3,364)
---------------------------------------
(10,971) (31,684) (36,091) (53,823)
---------------------------------------

Change in cash - (1,205) - -

Cash, beginning of period - 1,205 - -
---------------------------------------
Cash, end of period - - - -
---------------------------------------
---------------------------------------


See accompanying notes.


ZARGON ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the three and nine months ended September 30, 2005 and 2004 (unaudited)

1. NATURE OF THE ORGANIZATION AND BASIS OF PRESENTATION

Organization

On July 15, 2004, Zargon Oil & Gas Ltd. (the "Company") was reorganized into Zargon Energy Trust (the "Trust" or "Zargon") as part of a Plan of Arrangement (the "Arrangement"). Shareholders of the Company received one trust unit or one exchangeable share for each common share held. All outstanding common share options were settled for cash prior to the completion of the reorganization. The unitholders of the Trust are entitled to receive cash distributions paid by the Trust. Holders of exchangeable shares are not eligible to receive cash distributions paid, but rather, on each payment of a distribution, the number of trust units into which each exchangeable share is exchangeable is increased on a cumulative basis in respect of the distribution. The Trust is an unincorporated open-ended investment trust established under the laws of the Province of Alberta and was created pursuant to a trust indenture ("Trust Indenture").

The Trust's principal business activity is the exploration for and development and production of petroleum and natural gas.

Basis of Presentation

The interim unaudited consolidated financial statements of Zargon have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim unaudited consolidated financial statements have been prepared following the same accounting policies and methods in computation as the consolidated financial statements for the fiscal year ended December 31, 2004. The interim unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the Zargon Energy Trust annual report for the year ended December 31, 2004.

While the Trust commenced operations on July 15, 2004, these unaudited interim consolidated financial statements follow the continuity of interest basis of accounting as if the Trust had always carried on the business formerly carried on by Zargon Oil & Gas Ltd. This basis is intended to provide unitholders with meaningful and comparative financial information.

2. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

Zargon Oil & Gas Ltd. is authorized to issue a maximum of 3.66 million exchangeable shares. The exchangeable shares are convertible into trust units at the option of the shareholder based on the exchange ratio, which is adjusted monthly to reflect the distribution paid on the trust units. Cash distributions are not paid on the exchangeable shares. During the nine months ended September 30, 2005, a total of 757,000 exchangeable shares were converted into 791,000 trust units based on the exchange ratio at the time of conversion. At September 30, 2005, the exchange ratio was 1.07861 trust units per exchangeable share.



Non-Controlling Interest - Exchangeable Shares Nine Months Ended
September 30, 2005
-----------------------
Number of
(thousand, except exchange ratio) Shares Amount ($)
-----------------------
Non-controlling interest exchangeable shares issued
Balance, beginning of period 3,186 9,529
Earnings attributable to non-controlling interest - 3,181
Exchanged for trust units at book value and
including earnings attributed since
beginning of period (757) (2,704)
-----------------------

Balance, end of period 2,429 10,006
-----------------------
-----------------------

Exchange ratio, end of period 1.07861
Trust units issuable upon conversion of
exchangeable shares, end of period 2,620
-----------------------
-----------------------


For the year ended December 31, 2004 the Trust retroactively applied EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts". Per EIC-151, if certain conditions are met, the exchangeable shares issued by a subsidiary must be reflected as non-controlling interest on the consolidated balance sheet and in turn, net earnings must be reduced by the amount of net earnings attributed to the non-controlling interest. Consolidated net earnings for the period from the July 15, 2004 Plan of Arrangement through to September 30, 2004 have been reduced for net earnings attributable to the non-controlling interest of $0.86 million.

The non-controlling interest on the consolidated balance sheet consists of the book value of exchangeable shares at the time of the Plan of Arrangement, plus net earnings attributable to the exchangeable shareholders, less exchangeable shares (and related cumulative earnings) redeemed. The net earnings attributable to the non-controlling interest on the consolidated statement of earnings represents the cumulative share of net earnings attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable each period end.

Immediately prior to the July 15, 2004 Plan of Arrangement, the Company had $45.14 million in share capital. Upon conversion to the Trust structure these amounts were allocated $36.22 million to trust units and $8.92 million to exchangeable shares, based on the terms of the Arrangement.



The effect of EIC-151 on Zargon's unitholders' capital and exchangeable
shares is as follows:

Zargon
Oil & Zargon Zargon Oil &
Gas Ltd. Energy Gas Ltd.
Common Trust Exchangeable
($ thousand) Shares Units Shares Total
---------------------------------------

Immediately prior to July 15, 2004
Plan of Arrangement 45,136
Plan of Arrangement July 15, 2004 (45,136) 36,219 8,917
---------------------------------------
- 36,219 8,917 45,136
Issued on redemption of
exchangeable shares at book value - 1,155 (1,155) -
Effect of EIC-151 - 8,381 1,767 10,148
---------------------------------------
Balance at December 31, 2004 - 45,755 9,529 55,284

Issued on redemption of
exchangeable shares at book value - 1,843 (1,843) -
Effect of EIC-151 - 18,517 2,320 20,837
Unit-based compensation recognized - 586 - 586
Unit rights exercised for cash - 2,130 - 2,130
---------------------------------------
Balance at September 30, 2005 - 68,831 10,006 78,837
---------------------------------------
---------------------------------------

3. PROPERTY AND EQUIPMENT

($ thousand) September 30, 2005
---------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
---------------------------------
Petroleum, natural gas properties and
other equipment(a) 367,778 125,102 242,676
---------------------------------
---------------------------------

($ thousand) December 31, 2004
---------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
---------------------------------
Petroleum, natural gas properties and
other equipment(a) 308,116 98,380 209,736
---------------------------------
---------------------------------

(a) As a result of shareholders redeeming exchangeable shares, property
and equipment increased $23.86 million in the first nine months of
2005 and $11.28 million in 2004. The effect of these increases has
resulted in additional depletion and depreciation expense recorded
in the first nine months of 2005 of approximately $3.72 million.


4. LONG TERM DEBT

On September 30, 2005, a Canadian subsidiary and a US subsidiary of the Trust entered into syndicated committed credit facilities with a borrowing base of $80 million which replaces its former demand facility of $50 million. These facilities consist of a $60 million tranche available to the Canadian borrower and a US $15 million tranche available to the US borrower. A $150 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities. The facilities are fully revolving for a 364 day period with the provision for an annual extension at the option of the lenders and upon notice from the Company. Should the facilities not be renewed they convert to one year non-revolving term facilities at the end of the revolving 364 day period. Repayment would not be required until the end of the non-revolving term, and as such, the revolving credit facility has been classified as long term debt.



5. ASSET RETIREMENT OBLIGATIONS

The following table reconciles Zargon's asset retirement obligation:

Nine Months Ended
September 30,
-----------------------
($ thousand) 2005 2004
-----------------------

Balance, beginning of period 14,390 12,194
Liabilities incurred 526 1,357
Liabilities settled (372) (147)
Accretion expense 893 799
Foreign exchange (34) (116)
-----------------------

Balance, end of period 15,403 14,087
-----------------------
-----------------------


Commencing July 1, 2005 incremental asset retirement obligations are calculated using a revised discount rate of 7.5 percent. Asset retirement obligations prior to this period were calculated using a discount rate of 8.5 percent.

6. UNITHOLDERS' EQUITY

Pursuant to the Plan of Arrangement on July 15, 2004, 14.87 million units of the Trust and 3.66 million exchangeable shares (see note 2) of the Company were issued in exchange for all of the outstanding shares of the Company on a one-for-one basis.

The Trust is authorized to issue an unlimited number of voting trust units.



Nine Months Ended
Trust Units September 30, 2005
-----------------------
Number
(thousand) of Units Amount ($)
-----------------------
Units issued
Balance, beginning of period 15,341 45,755
Unit rights exercised for cash 120 2,130
Unit-based compensation recognized - 586
Issued on conversion of exchangeable shares 791 20,360
-----------------------

Balance, end of period 16,252 68,831
-----------------------
-----------------------


The proforma total units outstanding at period end, including trust units outstanding, and trust units issuable upon conversion of exchangeable shares and after giving effect to the exchange ratio at the end of the period (see note 2) is 18.872 million units.



A summary of the Company's share capital account for the first nine
months of 2004 is as follows:

Nine Months Ended
Common Shares of Zargon Oil & Gas Ltd. September 30, 2004
-----------------------
Number
(no par value) (thousand) of Shares Amount ($)
-----------------------
Shares issued
Balance, beginning of period 17,992 42,200
Stock options exercised for cash 534 2,867
Stock-based compensation recognized - 69
Trust units issued (14,866) (36,219)
Exchangeable shares issued (3,660) (8,917)
-----------------------

Balance, end of period - -
-----------------------
-----------------------

A summary of the Trust's unit account for the first nine months of 2004
is as follows:

Nine Months Ended
Trust Units September 30, 2004
-----------------------
Number
(thousand) of Units Amount ($)
-----------------------
Units issued
Issued pursuant to Plan of Arrangement
July 15, 2004 14,866 36,219
Issued on conversion of exchangeable shares 421 1,026
-----------------------

Balance, end of period 15,287 37,245
-----------------------
-----------------------

Contributed Surplus

The following table summarizes information about the Trust's contributed
surplus account:

Nine Months Ended
Contributed Surplus September 30, 2005
-----------------------
($ thousand)

Balance, beginning of period 1,170
Unit-based compensation expense 658
Unit-based compensation recognized on exercise
of unit rights (586)
-----------------------

Balance, end of period 1,242
-----------------------
-----------------------


Compensation Plans

Trust Unit Rights Incentive Plan and Unit-based Compensation

The Trust has a unit rights incentive plan (the "Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and service providers. The Trust is authorized to issue up to 1.82 million unit rights, however, the number of trust units reserved for issuance upon exercise of the rights shall not at any time exceed 10 percent of the aggregate number of issued and outstanding trust units of the Trust. At the time of grant, unit right exercise prices approximate the market price for the trust units. At the time of exercise, the rights holder has the option of exercising at the original grant price or the exercise price as calculated per the Arrangement. Rights granted under the Plan generally vest over a three-year period and expire approximately five years from the grant date.

The Plan allows for the exercise price of rights to be reduced in future periods by an amount that distributions exceed a stated return on assets. The unit-based compensation expense arising from unit rights granted upon and subsequent to, the July 15, 2004 Plan of Arrangement, were originally calculated using the intrinsic value method. In response to an emphasis by securities regulators that fair value methodologies be used, new measurement techniques have recently been developed utilizing a fair value option-pricing model for such unit rights grants. Zargon has reassessed the previous unit rights grants under this fair value model and there is no significant impact on amounts previously recorded as 2004 unit-based compensation expense. Zargon will continue to use fair value methodologies, where possible, for future unit rights grants.

The assumptions made for unit rights granted for 2005 include a volatility factor of expected market price of 25.6 percent, a weighted average risk-free interest rate of 3.38 percent, a dividend yield of 7.32 percent and a weighted average expected life of the unit rights of four years, resulting in unit-based compensation expense of $0.19 million and $0.66 million for the three and nine months ended September 30, 2005 respectively.

Compensation expense associated with rights granted under the Plan is recognized in earnings over the vesting period of the Plan with a corresponding increase or decrease in contributed surplus. The exercise of trust unit rights is recorded as an increase in trust units with a corresponding reduction in contributed surplus. Forfeiture of rights are recorded as a reduction in expense in the period in which they occur.



The following table summarizes information about the Trust's unit
rights:

Nine Months Ended
September 30, 2005
-----------------------
Number Weighted
of Unit Average
Rights Exercise
(thousand) Price($)
-----------------------

Outstanding at beginning of period 579 17.79
Unit rights granted 334 24.74
Unit rights exercised (120) 17.79
Unit rights cancelled (15) 17.70
-----------

Outstanding at end of period 778 20.77
-----------
-----------

Unit rights exercisable at period end 81 17.70
-----------
-----------


Stock Option Plan and Stock-based Compensation

Prior to the Plan of Arrangement, the Company calculated the value of stock-based compensation for its predecessor stock option plan using a Black-Scholes option-pricing model to estimate the fair value of stock options at the date of grant. This stock option plan ceased to exist at the July 15, 2004 Plan of Arrangement.



A summary of the Company's predecessor stock option plan prior to the
Plan of Arrangement is as follows:

Nine Months Ended
September 30, 2004
-----------------------
Weighted
Number Average
of Shares Exercise
(thousand) Price($)
-----------------------

Outstanding at beginning of period 1,297 7.05
Granted 430 16.00
Exercised (534) 5.39
Cancelled (9) 9.61
Cancelled immediately prior to trust conversion (1,184) 11.03
-----------

Outstanding at end of period - -
-----------
-----------

The following table summarizes information about the Trust's unit rights
in 2004 subsequent to the Plan of Arrangement:

Nine Months Ended
September 30, 2004
-----------------------
Number Weighted
of Unit Average
Rights Exercise
(thousand) Price($)
-----------------------

Outstanding at beginning of period - -
Unit rights granted 579 17.79
-----------

Outstanding at end of period 579 17.79
-----------
-----------

Options exercisable at period end - -
-----------
-----------


7. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS

Basic per unit amounts are calculated using the weighted average number of trust units outstanding during the period. Diluted per unit amounts are calculated using the treasury stock method to determine the dilutive effect of unit-based compensation. Diluted per unit amounts also include exchangeable shares using the "if-converted" method.



Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
(thousand) 2005 2004 2005 2004
----------------------------------------
(units) (units) (units) (units)

Basic 16,141 17,375 15,906 17,327

Diluted 19,024 18,493 18,852 18,746
----------------------------------------
----------------------------------------


8. SEGMENTED INFORMATION

Zargon's entire operating activities are related to exploration, development and production of oil and natural gas in the geographic segments of Canada and the US.



Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
($thousand) 2005 2004 2005 2004
----------------------------------------

Petroleum and Natural Gas Revenue
Canada 36,348 28,270 96,978 80,018
United States 6,120 4,139 15,482 11,054
----------------------------------------

Total 42,468 32,409 112,460 91,072
----------------------------------------
----------------------------------------
Net Capital Expenditures
Canada 12,997 22,406 33,639 37,840
United States 911 1,234 1,919 3,176
----------------------------------------

Total 13,908 23,640 35,558 41,016
----------------------------------------
----------------------------------------
September December
30, 31,
Total Assets 2005 2004
--------------------
Canada 234,303 200,171
United States 30,132 26,793
--------------------
Total 264,435 226,964
--------------------
--------------------

9. SUPPLEMENTAL CASH FLOW INFORMATION

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
($thousand) 2005 2004 2005 2004
----------------------------------------

Cash interest paid 320 144 711 252
Cash taxes paid 656 506 1,520 694
----------------------------------------
----------------------------------------


10. FINANCIAL INSTRUMENTS

The Trust is a party to certain financial instruments that have fixed the price of a portion of its oil and natural gas production. The Trust enters into these contracts for risk management purposes only, in order to protect a portion of its future cash flow from the volatility of oil and natural gas commodity prices. The Trust has outstanding contracts at September 30, 2005 as follows:



Fair
Market
Value
Range of Loss
Volume Rate Price Terms(thousand)
------------------------------------------------------------------------

Financial Contracts
Designated as Hedges

Oil swaps 36,800 bbl 400 bbl/d $44.05 US/bbl Oct. 1/05- $ 956
Dec. 31/05

Oil 18,400 bbl 200 bbl/d $37.00 US/bbl Put Oct. 1/05- $ 469
collars $44.40 US/bbl Call Dec. 31/05

36,200 bbl 200 bbl/d $36.00 US/bbl Put Jan. 1/06- $ 785
$48.40 US/bbl Call Jun. 30/06

Natural
gas 124,000 gj 4,000 gj/d $6.49/gj Oct. 1/05- $ 551
swaps Oct. 31/05

Natural
gas 62,000 gj 2,000 gj/d $6.00/gj Put Oct. 1/05- $ 182
collars $8.01/gj Call Oct. 31/05

453,000 gj 3,000 gj/d $5.90/gj Put Nov. 1/05- $ 1,604
$10.00/gj Call Mar. 31/06

Natural 62,000 gj 2,000 gj/d $5.10/gj Oct. 1/05- -
gas put Oct. 31/05

------------------------------------------------------------------------
Total Fair Market Value Loss, Financial Contracts
Designated as Hedges $ 4,547
------------------------------------------------------------------------
------------------------------------------------------------------------
Financial Contracts Not
Designated as Hedges

Oil 27,600 bbl 300 bbl/d $45.70 US/bbl Oct. 1/05- $ 662
swaps Dec. 31/05

36,200 bbl 200 bbl/d $48.50 US/bbl Jan. 1/06- $ 781
Jun. 30/06

109,500 bbl 300 bbl/d $51.83 US/bbl Jan. 1/06- $ 1,907
Dec. 31/06

36,800 bbl 200 bbl/d $51.12 US/bbl Jul. 1/06- $ 671
Dec. 31/06

Oil 36,200 bbl 200 bbl/d $40.00 US/bbl Put Jan. 1/06- $ 758
collars $49.05 US/bbl Call Jun. 30/06

73,000 bbl 200 bbl/d $52.00 US/bbl Put Jan. 1/06- -
$78.95 US/bbl Call Dec. 31/06

36,800 bbl 200 bbl/d $55.00 US/bbl Put Jul. 1/06- -
$78.05 US/bbl Call Dec. 31/06

Natural
gas 62,000 gj 2,000 gj/d $6.52/gj Oct. 1/05- $ 274
swaps Oct. 31/05

428,000 gj 2,000 gj/d $8.18/gj Apr. 1/06- $ 901
Oct. 31/06

Natural
gas 302,000 gj 2,000 gj/d $6.50/gj Put Nov. 1/05- $ 1,431
collars $8.80/gj Call Mar. 31/06

302,000 gj 2,000 gj/d $7.00/gj Put Nov. 1/05- $ 1,265
$9.35/gj Call Mar. 31/06
------------------------------------------------------------------------
Total Fair Market Value Loss, Financial Contracts Not
Designated as Hedges $ 8,650
------------------------------------------------------------------------
------------------------------------------------------------------------
Physical Contracts

Natural
gas 856,000 gj 4,000 gj/d $7.92/gj Apr. 1/06- $ 2,026
swaps Oct. 31/06

Natural
gas 151,000 gj 1,000 gj/d $8.47/gj Put Nov. 1/05- $ 610
collars $9.50/gj Call Mar. 31/06

151,000 gj 1,000 gj/d $8.50/gj Put Nov. 1/06- -
$12.85/gj Call Mar. 31/07

151,000 gj 1,000 gj/d $9.50/gj Put Nov. 1/06- -
$13.50/gj Call Mar. 31/07

Natural 62,000 gj 2,000 gj/d $6.05/gj Oct. 1/05- -
gas put Oct. 31/05

------------------------------------------------------------------------
Total Fair Market Value Loss, Physical Contracts $ 2,636
------------------------------------------------------------------------
------------------------------------------------------------------------


Oil swaps and collars are settled against the NYMEX pricing index, whereas natural gas swaps, collars, and puts are settled against the AECO pricing index.

Financial risk management contracts in place as at December 31, 2004 were designated as hedges for accounting purposes and the Trust continues to monitor these contracts in determining the continuation of hedge effectiveness. For these contracts, realized gains and losses are recorded in the statement of earnings as the contracts settle and no unrealized gain or loss is recognized. The realized losses for the first nine months of 2005 were $4.64 million (2004 - $3.01 million). At September 30, 2005, an additional $4.55 million would have been required to settle the above designated hedge contracts. Contracts settled by way of physical delivery are recognized as part of the normal revenue stream. These instruments have no book values recorded in the interim consolidated financial statements.

For financial risk management contracts entered into after December 31, 2004, the Trust does consider these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and accordingly, for outstanding contracts not designated as hedges, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end. The unrealized losses as at September 30, 2005 were $8.65 million (2004 - nil). These instruments have been recorded as a liability in the interim consolidated balance sheet.

11. ACCUMULATED CASH DISTRIBUTIONS

During the nine month period, the Trust paid or declared distributions to the unitholders in the aggregate amount of $20.78 million (2004 - $4.27 million) in accordance with the following schedule:



------------------------------------------------------------------------
Per Trust
Month Record Date Distribution Date Unit
------------------------------------------------------------------------

January 2005 January 31, 2005 February 15, 2005 $0.14
February 2005 February 28, 2005 March 15, 2005 $0.14
March 2005 March 31, 2005 April 15, 2005 $0.14
April 2005 April 30, 2005 May 16, 2005 $0.14
May 2005 May 31, 2005 June 15, 2005 $0.14
June 2005 June 30, 2005 July 15, 2005 $0.14
July 2005 July 31, 2005 August 15, 2005 $0.14
August 2005 August 31, 2005 September 15, 2005 $0.16
September 2005 September 30, 2005 October 17, 2005 $0.16
------------------------------------------------------------------------
------------------------------------------------------------------------


For Canadian income tax purposes, the distributions are currently estimated to be 100 percent taxable income to unitholders.



CORPORATE INFORMATION

------------------------------------------------------------------------


Board of Directors Officers Stock Exchange Listing


Craig H. Hansen John O. McCutcheon Toronto Stock Exchange
Calgary, Alberta Chairman Trading Symbols:
ZAR.UN - trust units
K. James Harrison Craig H. Hansen ZOG.B - exchangeable shares
Oakville, Ontario President and
Chief Executive Transfer Agent
H. Earl Joudrie Officer
Toronto, Ontario Valiant Trust Company
Brent C. Heagy 310, 606 - 4th Street S.W.
Kyle D. Kitagawa Vice President, Calgary, Alberta T2P 1T1
Calgary, Alberta Finance and Chief
Financial Officer Head Office
John O. McCutcheon
Vancouver, British Mark I. Lake 700, 333 - 5th Avenue S.W.
Columbia Vice President, Calgary, Alberta T2P 3B6
Exploration Phone: (403) 264-9992
Jim D. Peplinski Fax: (403) 265-3026
Calgary, Alberta Daniel A. Roulston Email: zargon@zargon.ca
Executive Vice
J. Graham Weir President, Operations Website
Calgary, Alberta
Sheila A. Wares www.zargon.ca
William J. Whelan Vice President,
Calgary, Alberta Accounting

Grant A. Zawalsky Kenneth W. Young
Calgary, Alberta Vice President, Land


Forward-Looking Statements - This document contains statements that are forward-looking, such as those relating to results of operations and financial condition, capital spending, financing sources, commodity prices, costs of production and the magnitude of oil and natural gas reserves. By their nature, forward-looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly actual results may differ materially from those predicted. The forward-looking statements contained in this quarterly report are as of November 10, 2005 and are subject to change after this date. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Zargon disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Zargon Energy Trust
Telephone: (403) 264-9992
E-mail: zargon@zargon.ca
Website: www.zargon.ca

Contact Information

  • Zargon Energy Trust
    C.H. Hansen
    President and Chief Executive Officer
    or
    B.C. Heagy
    Vice President, Finance and Chief Financial Officer