ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

November 14, 2006 17:08 ET

Zargon Energy Trust Announces 2006 Third Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 14, 2006) -

FINANCIAL & OPERATING HIGHLIGHTS

Zargon Energy Trust (TSX:ZAR.UN)(TSX:ZOG.B) is pleased to report its financial results from operations for the third quarter and the nine months ended September 30, 2006. Cash flow from operations was $20.04 million ($1.03 per diluted trust unit) in the 2006 third quarter compared with $22.13 million ($1.14 per diluted trust unit) in the 2006 second quarter and $21.85 million ($1.15 per diluted trust unit) in the 2005 third quarter.

Highlights from the three and nine months ended September 30, 2006 are noted below:

- Third quarter 2006 production averaged 8,194 barrels of oil equivalent per day, two percent below the preceding quarter and an increase of two percent from the corresponding quarter of 2005. Third quarter production volumes declined due to a combination of scheduled and unscheduled third party gas plant maintenance, unpredicted natural gas production declines and second quarter non-core property sales. For the first nine months of 2006, production averaged 8,441 barrels of oil equivalent per day equal to 439 barrels of oil equivalent per day per million trust units outstanding. Compared to the corresponding 2005 period, production volumes increased two percent in 2006 and remained virtually unchanged on a per million trust units basis.

- Revenue and cash flow from operations in the 2006 third quarter declined two percent and nine percent, respectively, from the prior quarter. Relatively stable realized oil prices were offset by a four percent decline in realized natural gas prices from the prior quarter. Cash flow was also impacted by increased operating costs during the quarter as a result of increased seasonal field maintenance activities and some prior period adjustments.

- The Trust declared three monthly cash distributions of $0.18 per trust unit in the third quarter of 2006 for a total of $9.00 million. These cash distributions were equivalent to a payout ratio of 52 percent of the Trust's third quarter cash flow on a diluted trust unit basis and after considering the effect of the exchangeable shares not receiving distributions, the distributions amounted to 45 percent of cash flow from operations. The Trust's third quarter exploration and development capital expenditures increased 50 percent from the prior quarter to $18.64 million as a larger 19.9 net well exploration and exploitation drilling program was conducted. Reflecting this expanded capital program, debt net of working capital (excluding unrealized risk management assets and liabilities) increased to $29.63 million at September 30, 2006 and the Trust's balance sheet remains very strong with debt net of working capital slightly more than four months of the 2006 year-to-date annualized cash flow.




Three Months Ended Nine Months Ended
September 30, September 30,
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Percent Percent
(unaudited) 2006 2005 Change 2006 2005 Change
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FINANCIAL

Income and
Investments
($ million)
Petroleum and
natural gas
revenue 37.93 42.47 (11) 117.54 112.46 5
Cash flow from
operations 20.04 21.85 (8) 64.52 58.35 11
Cash
distributions 9.00 7.45 21 26.85 20.78 29
Net earnings 12.31 6.30 95 37.45 17.92 109
Net capital
expenditures 18.99 13.91 37 42.96 35.56 21

Per Unit, Diluted
Cash flow from
operations
($/unit) 1.03 1.15 (10) 3.35 3.10 8
Net earnings
($/unit) 0.73 0.39 87 2.25 1.12 101

Cash Distributions
($/trust unit) 0.54 0.46 17 1.62 1.30 25

Balance Sheet at
Period End
($ million)
Property and
equipment, net 271.14 242.68 12
Bank debt 20.71 11.43 81
Unitholders' equity 164.55 140.90 17

Total Units
Outstanding at
Period End (million) 19.35 18.87 3


OPERATING

Average Daily
Production
Oil and liquids
(bbl/d) 3,704 3,578 4 3,810 3,585 6
Natural gas
(mmcf/d) 26.94 26.75 1 27.78 27.92 (1)
Equivalent
(boe/d) 8,194 8,036 2 8,441 8,239 2
Equivalent per
million trust
units (boe/d) 424 427 (1) 439 438 -

Average Selling
Price (before
the impact of
financial risk
management
contracts)
Oil and liquids
($/bbl) 67.75 65.91 3 63.44 56.99 11
Natural gas
($/mcf) 5.99 8.44 (29) 6.80 7.44 (9)

Wells Drilled, Net 19.9 16.2 23 42.8 38.1 12

Undeveloped Land
at Period End
(thousand net acres) 374 365 2
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Notes: Throughout this report, the calculation of barrels of oil equivalent (boe) is based on the conversion ratio that six thousand cubic feet of natural gas is equivalent to one barrel of oil. For a further discussion about this term, refer to the Management's Discussion and Analysis section in this report.

Cash flow from operations is a non-GAAP term that represents net earnings except for non-cash items. For a further discussion about this term, refer to the Management's Discussion and Analysis section in this report.

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.

Average daily production per million trust 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 average exchange ratio for the period.

PRODUCTION (1)

Natural gas production volumes in the third quarter of 2006 averaged 26.94 million cubic feet per day, a two percent reduction from the 2006 second quarter and a one percent increase from the 2005 third quarter. During the quarter, West Central Alberta tie-ins were offset by a combination of natural declines, scheduled and unscheduled third party gas plant maintenance and unpredicted production declines from three specific wells in the Greater Highvale area. Consequently, the anticipated natural gas production gains for the quarter did not materialize. During the third quarter, a multi-well development program commenced at the Alberta Plains Jarrow and Hamilton Lake properties and production volumes from these wells plus new volumes from the ongoing West Central Alberta tie-in program should provide modest natural gas production gains for the 2006 fourth quarter.

Oil and liquids production of 3,704 barrels per day in the 2006 third quarter slightly changed from the preceding quarter but showed a four percent increase over the corresponding 2005 quarter. Production volumes held steady as new volumes from four second quarter horizontal wells offset naturally occurring production declines. Over the next few months, oil production volumes are also anticipated to grow modestly as Williston Basin and Alberta Plains horizontal wells are placed on production.

CAPITAL EXPENDITURES (1)

Over the last few quarters, Zargon has focused on expanding and strengthening its technical staff in order to efficiently capture the substantial opportunities associated with its existing asset base. With improved access to more competitively priced field services, Zargon embarked on a very active field capital program in the third quarter drilling 23 gross wells (19.9 net wells), a significant increase from the 9.7 net wells and 13.2 net wells drilled in the second and first quarters, respectively. The program resulted in 10.2 net natural gas wells, 6.7 net oil wells, 1.0 net water injection well and 2.0 net dry holes which equated to a 90 percent success ratio.

Highlights of the third quarter drilling program included a natural gas exploration success at Saddle Hills in the West Central Alberta core area, and two successful horizontal oil development wells at the Jarrow and Taber properties in the Alberta Plains core area. Each of these successes is anticipated to lead to multiple follow-up locations in 2007. In the Williston Basin, two horizontal development oil wells and three vertical development wells were drilled to advance the development of the Pinto, Steelman and Weyburn properties. Also, during the quarter three higher risk Williston Basin exploration wells were drilled on a Bakken (Torquay) concept at Frys East. These exploratory wells plus recent fourth quarter exploration successes at Pinto, Saskatchewan will lead to further exploration and development locations this winter.

During the quarter, Zargon commenced its 22.0 net well Viking down-spacing and step-out development program at the Jarrow and Hamilton Lake properties of the Alberta Plains. Initial results are encouraging and the ensuing production gains plus follow-on shallow gas drilling programs are forecast for the first quarter of 2007. In aggregate, for the first nine months of 2006, Zargon drilled 42.8 net wells which consisted of 17.5 net wells in the Alberta Plains, 14.8 net wells in the Williston Basin and 10.5 net wells in the West Central Alberta core areas.

For the 2006 fourth quarter, Zargon will proceed with an active natural gas drilling program comprised of the ongoing multi-well Alberta Plains development program and West Central Alberta exploration at the Highvale, Progress and Hamelin Creek properties. Oil directed drilling will be concentrated in the Williston Basin and will include two horizontal wells at Steelman and Elswick, Saskatchewan; two horizontal re-entries at Haas, North Dakota plus exploration drilling at Pinto and Frys East, Saskatchewan. With this active fourth quarter program, Zargon is forecasting a $63 million capital expenditure program in 2006 that includes the drilling of 75 net wells.

In recent months, the cost of acquiring land at Crown land sales has dropped substantially and accordingly, Zargon has been able to maintain its strong undeveloped land inventory with moderately priced purchases fully offsetting expiries. Zargon's undeveloped land inventory at September 30, 2006 was 374 thousand net acres which is essentially unchanged from the 375 thousand net acres reported at the end of the second quarter.

GUIDANCE (1)

In November 2005, Zargon set its 2006 full year production guidance at 8,600 barrels of oil equivalent per day and maintained this guidance level over the subsequent quarters. For the first nine months of 2006, Zargon's production has averaged 8,441 barrels of oil equivalent per day, two percent below guidance levels. The 2006 first quarter was two percent above guidance while the second and third quarters were three and five percent, respectively, below guidance because of identifiable field problems. Field activities in the third quarter and fourth quarter have been expanded and are expected to increase production levels from third quarter lows to fourth quarter average rates of 8,500 barrels of oil equivalent per day which are forecast to be comprised of 3,800 barrels per day of oil and liquids and 28.20 million cubic feet per day of natural gas. With these projected fourth quarter levels, Zargon's 2006 average production volumes would average just over 8,450 barrels of oil equivalent per day, a one percent increase from the 2005 levels of 8,342 barrels of oil equivalent per day, but a two percent decline on a per diluted trust unit basis.

With anticipated positive production growth momentum entering into next year, Zargon is providing preliminary 2007 guidance at 8,750 barrels of oil equivalent per day which is premised on a 2007 exploration and development capital program of $55 million that includes the drilling of 65 net wells. Initially, the allocation of this capital program is forecast to be $23 million to the Alberta Plains, $20 million to the Williston Basin and $12 million to the West Central Alberta core areas. The capital program will focus on Williston Basin oil exploitation, multi-well Alberta Plains natural gas development, selected West Central Alberta gas well development programs and will continue to include a 25 percent exploration component. The 2007 exploration programs will include seismically defined Alberta Plains Mannville targets, selected larger scope Williston Basin exploration concepts and West Central Alberta seismically defined structural and stratigraphic targets. In light of this year's disappointing unexpected declines at certain new West Central Alberta wells, the 2007 budget will emphasize natural gas targets that may deliver lower initial rates but provide a longer life and more predictable production profile.

During the first nine months of 2006, Zargon has maintained a base (sustainable) monthly distribution of $0.18 per trust unit, premised on the underlying assumptions of previous production guidance levels and long term commodity prices of US $55 per barrel (WTI oil), US $8 per mmbtu (NYMEX natural gas) and an $0.87 Cdn./US dollar currency exchange rate. Consistent with 2005, if and when commodity prices exceed these assumptions, Zargon will consider supplemental semi-annual distributions to reach our stated goal of distributing approximately 50 percent of the cash flows attributable to unitholders. In the first nine months of 2006, Zargon distributed 48 percent of the cash flow attributed to the unitholders and has chosen to not make any supplemental distributions. Going forward into 2007, Zargon plans to continue with its base (sustainable) monthly distribution of $0.18 per trust unit which is premised on the current 2007 production guidance levels, positive contributions from current hedging contracts and the long term commodity price assumptions of US $55 per barrel (WTI oil), an $0.87 Cdn./US dollar currency exchange rate and a now reduced US $7.50 per mmbtu (NYMEX natural gas) price.

As in the past, production guidance levels do not include an allowance for property or corporate acquisitions that would be funded on an opportunistic basis by bank debt or possibly equity issues. In recent weeks, the combined effects of lower natural gas and oil commodity prices and the recently announced proposed changes to the Canadian income trust tax rules after 2010 may have negatively impacted the Canadian oil and gas trust industry's access to new capital from debt and equity markets. If this condition persists, reduced price and competition levels might be observed for Crown land purchases, property acquisitions and small corporate acquisitions. With its very low debt levels, Zargon is well positioned to participate in these acquisition markets if value opportunities can be sourced.

(1) Please see comments on "Forward-Looking Statements" in the Management's Discussion and Analysis section in 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, 2006 and the audited consolidated financial statements and MD&A for the year ended December 31, 2005. All amounts are in Canadian dollars unless otherwise noted. All references to "Zargon" or the "Trust" refer to Zargon Energy Trust.

In the MD&A, reserves and production are commonly stated in barrels of oil 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.

The following are descriptions of non-GAAP measures used in this MD&A:

- 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 unaudited interim consolidated statements of cash flows in the unaudited interim 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.

- Payout ratio equals cash distributions as a percentage of cash flow for the period. Payout ratio is a useful measure used by management to analyze the Trust's efficiency and sustainability.

- The Trust also uses the term "debt net of working capital". Debt net of working capital as presented does not have any standardized meaning prescribed by Canadian GAAP and may not be comparable with the calculation of similar measures for other entities. Debt net of working capital as used by the Trust is calculated as bank debt and any working capital deficit excluding the current portion of unrealized risk management assets and liabilities.

- Operating netbacks equal total petroleum and natural gas revenue per boe plus realized risk management gains per boe, less realized risk management losses per boe, royalties per boe and production costs per boe. Operating netbacks are a useful measure to compare the Trust's operations with those of its peers.

- Cash flow netbacks per boe are calculated as operating netbacks less general and administrative expenses per boe, interest and financing charges per boe and capital and current income taxes per boe. Cash flow netbacks are a useful measure to compare the Trust's operations with those of its peers.

References to "production volumes" or "production" in this MD&A refer to sales volumes.

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 report are as of November 13, 2006 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, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

This MD&A has been prepared as of November 13, 2006.

SUMMARY OF SIGNIFICANT EVENTS IN THE THIRD QUARTER

- During the third quarter of 2006, the Trust realized cash flow from operations of $20.04 million and declared total distributions of $9.00 million ($0.54 per trust unit) to unitholders, resulting in a quarterly payout ratio of 45 percent of cash flow or 52 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 received (before the impact of financial risk management contracts) for oil and liquids remained relatively unchanged at $67.75 per barrel compared to the second quarter of 2006 and prices received for natural gas declined to $5.99 per thousand cubic feet, a four percent decline from the second quarter of 2006. Third quarter production volumes were 8,194 barrels of oil equivalent per day, a two percent decline from the second quarter production levels.

- During the third quarter of 2006, the Trust drilled 23 gross wells (19.9 net) with a 90 percent success rate. Total net capital expenditures were $18.99 million for the quarter compared to $8.78 million for the prior quarter which included $4.20 million of property dispositions.

- The Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities) of $29.63 million, which represents slightly more than four months of the 2006 year-to-date annualized cash flow.

FINANCIAL ANALYSIS

Third quarter 2006 revenue of $37.93 million was two percent below the $38.66 million in the second quarter of 2006 and 11 percent below the $42.47 million in the third quarter of 2005. A four percent decrease in natural gas prices and a two percent decline in production volumes from the previous quarter were the primary reasons for the lower revenues. Third quarter 2006 realized oil and liquids prices averaged $67.75 per barrel before the impact of financial risk management contracts and were relatively unchanged from the preceding quarter's $67.47 per barrel and were three percent higher than the $65.91 per barrel recorded in the 2005 third quarter. Zargon's crude oil field price differential from the Edmonton par price increased to $11.33 per barrel in the third quarter of 2006 compared to $11.08 per barrel in the second quarter of 2006. Natural gas prices received averaged $5.99 per thousand cubic feet before the impact of financial risk management contracts in the third quarter of 2006, a decrease of 29 percent from the 2005 third quarter prices received and a four percent decline from the preceding quarter levels. In 2006, Zargon has realized a small non-recurring premium to the benchmark AECO average daily price due to a combination of fixed price physical contracts (see note 11 to the interim unaudited consolidated financial statements) and from the impact of Zargon receiving AECO monthly index pricing for approximately 21 percent of its natural gas production.



Pricing


Average For Three Months Ended Nine Months Ended
The Period September 30, September 30,
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Percent Percent
2006 2005 Change 2006 2005 Change
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Natural Gas:
NYMEX average
daily spot price
($US/mmbtu) 6.06 9.94 (39) 6.77 7.77 (13)
AECO average daily
spot price
($Cdn/mmbtu) 5.65 9.37 (40) 6.40 7.88 (19)
Realized price
($Cdn/mcf) (1) 5.99 8.44 (29) 6.80 7.44 (9)

Crude Oil:
WTI ($US/bbl) 70.48 63.19 12 68.22 55.40 23
Edmonton par price
($Cdn/bbl) 79.08 76.51 3 75.53 67.91 11
Realized price
($Cdn/bbl) (1) 67.75 65.91 3 63.44 56.99 11
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(1) Amounts are before the impact of financial risk management contracts.


Natural gas production volumes decreased by two percent in the third quarter of 2006 to 26.94 million cubic feet per day from 27.44 million cubic feet per day in the second quarter of 2006 and were one percent higher than the 2005 third quarter. Oil and liquids production during the third quarter of 2006 was 3,704 barrels per day which is one percent below the 2006 second quarter rate of 3,748 barrels per day and four percent above the third quarter of 2005 level. The year-over-year increase in oil and liquids production is primarily due to the effect of successful ongoing Williston Basin core area exploitation drilling programs. On a barrel of oil equivalent basis, Zargon produced 8,194 barrels of oil equivalent per day in the third quarter of 2006, which represents a two percent decrease from the 8,322 barrels of oil equivalent per day in the second quarter of 2006 and a two percent increase when compared to the third quarter of 2005. The third quarter production declines were due to a combination of scheduled and unscheduled third party gas plant maintenance, unpredicted natural gas production declines and second quarter non-core property sales.



Production by Core Area

Three Months Ended September 30,
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2006 2005
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Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
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Alberta
Plains 484 18.92 3,637 531 18.47 3,608
West Central
Alberta 162 7.81 1,464 211 8.06 1,556
Williston
Basin 3,058 0.21 3,093 2,836 0.22 2,872
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3,704 26.94 8,194 3,578 26.75 8,036
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Nine Months Ended September 30,
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2006 2005
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Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
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Alberta
Plains 511 19.19 3,710 556 19.19 3,754
West Central
Alberta 176 8.37 1,571 206 8.48 1,620
Williston
Basin 3,123 0.22 3,160 2,823 0.25 2,865
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3,810 27.78 8,441 3,585 27.92 8,239
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Zargon's commodity price risk management policy, which is approved by the Board of Directors, allows the use of forward sales and costless collars for a targeted range of 20 to 35 percent of oil and natural gas working interest production in order to partially offset the effects of large commodity price fluctuations. Financial risk management contracts in place as at December 31, 2004 were designated as hedges for accounting purposes and the Trust monitored these contracts in determining the continuation of hedge effectiveness. As at June 30, 2006, all designated hedge contracts had expired. For the designated hedge contracts, realized gains and losses were recorded in the statement of earnings as the contracts settled and no unrealized gain or loss was 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 and accordingly, for these contracts, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end.

Specifically, in the 2006 third quarter, relatively high and stable oil prices were more than offset by declining natural gas prices and as a result the net realized financial risk management gain totalled $0.34 million (consisting of a $1.32 million realized gain on natural gas contracts less a $0.98 million loss on oil contracts) that compares to a $0.71 million realized net loss in the second quarter of 2006 and a $2.62 million realized net loss in the third quarter of 2005. The 2006 third quarter unrealized risk management gains resulted from oil contract gains ($5.30 million) and by unrealized risk management natural gas contract gains ($0.97 million) providing a total gain of $6.27 million for the quarter which compares to a net nominal charge for the 2006 second quarter and a net $5.30 million loss in the third quarter of 2005. These unrealized risk management gains or losses are generated by the change over the reporting period in the mark-to-market valuation of Zargon's future contracts. Zargon's commodity risk management positions are fully described in note 11 to the unaudited consolidated interim financial statements.

Royalties, inclusive of the Alberta Royalty Credit and the Saskatchewan Resource Surcharge, totalled $8.48 million for the third quarter of 2006, an increase of five percent from the $8.09 million preceding quarter expense and a decrease of 13 percent from $9.78 million in the third quarter of 2005. The variations generally track changes in production, prices and volumes. As a percentage of gross revenue, royalty rates moved in a relatively narrow range from 23.0 percent in the third quarter of 2005 to 20.9 percent in the second quarter of 2006 and 22.3 percent in the third quarter of 2006. The lower effective royalty rates in the 2006 second quarter were a result of adjustments to prior periods. Recent lower than expected royalty rates are also due to the effect of revenue gains Zargon has achieved due to fixed price and monthly index physical contracts. Going forward, Zargon expects that its royalty rate will approximate 23 percent for the next few quarters. During the third quarter of 2006, the Alberta provincial government announced the elimination of the Alberta Royalty Credit effective January 1, 2007. The estimated impact of this announcement is an increase of royalty expense of approximately $0.50 million per year for fiscal years commencing in 2007.

On a unit of production basis, production costs of $9.26 per barrel of oil equivalent in the third quarter of 2006 compares with $7.67 per barrel of oil equivalent in the preceding quarter and $8.52 per barrel of oil equivalent in the third quarter of 2005. The large increase in the 2006 third quarter costs relate to adjustments to prior periods ($0.41 per barrel of oil equivalent), a seasonally active summer maintenance and workover field program, increased water handling costs for selected West Central Alberta natural gas wells, and the industry-wide trend of increased unit operating costs. For the first nine months of 2006, Zargon's operating costs have averaged $8.15 per barrel of oil equivalent, a two percent increase over the prior year's average cost of $7.97 per barrel of oil equivalent. Despite continued efforts to contain the industry-wide trend of increasing operating costs, Zargon anticipates that production costs will average around $8.50 per barrel of oil equivalent for the next few quarters.



Operating Netbacks

Three Months Ended September 30,
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2006 2005
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
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Production revenue 67.75 5.99 65.91 8.44
Realized risk management
gain/(loss) (2.88) 0.53 (5.58) (0.32)
Royalties (15.77) (1.26) (14.47) (2.04)
Production costs (12.71) (1.07) (11.74) (0.99)
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Operating netbacks 36.39 4.19 34.12 5.09
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Nine Months Ended September 30,
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2006 2005
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
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Production revenue 63.44 6.80 56.99 7.44
Realized risk management
gain/(loss) (4.04) 0.32 (3.76) (0.13)
Royalties (14.26) (1.42) (12.72) (1.74)
Production costs (11.00) (0.97) (10.64) (0.99)
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Operating netbacks 34.14 4.73 29.87 4.58
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Measured on a unit of production basis (net of recoveries), general and administrative expenses were $2.14 per barrel of oil equivalent in the first nine months of 2006 compared to $1.80 in the first nine months of 2005 and $1.99 for the twelve month period of 2005. The increase in general and administrative expenses on a per unit of production basis are primarily due to increased technical staff and related costs.

Expensing of unit-based compensation in the first nine months of 2006 was $1.23 million, an 88 percent increase from the first nine months of 2005. The increase is a result of unit-right grants which generally occur on a quarterly basis.

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges on these facilities in the third quarter were $0.37 million, $0.01 million lower than the previous quarter amount of $0.38 million and an increase of $0.20 million from $0.17 million in the third quarter of 2005. This year-over-year increase is primarily due to a combination of higher 2006 average bank debt levels and higher effective interest rates. As noted in the prior quarter, on June 30, 2006, Zargon amended and renewed its syndicated committed credit facilities, which resulted in an increase in the available facilities and borrowing base to $100 million from the previous amount of $80 million. The next renewal date is July 31, 2007.

Capital and current taxes for the 2006 third quarter were $0.45 million, primarily relating to United States operations, where increased taxable income is resulting in higher United States taxes. When compared to prior periods, capital and current income taxes increased $0.34 million over the 2006 second quarter and increased $0.21 million relative to the third quarter of 2005. In the second quarter of 2006, Zargon's consolidated capital and current income taxes had declined as a result of declining rates and a prior year's $0.28 million recovery of Canadian capital taxes. Additionally, in the 2006 second quarter the Canadian federal government substantively enacted legislation to eliminate the federal capital tax effective January 1, 2006. As a result of these changes, the federal capital taxes recorded in the 2006 first quarter were eliminated in the 2006 second quarter. Tax pools as at September 30, 2006 are estimated to be approximately $100 million which represents an increase from the comparable $90 million of tax pools available to Zargon at December 31, 2005.

On October 31, 2006, the Federal Government announced tax proposals pertaining to taxation of distributions paid by trusts and the personal tax treatment of trust distributions. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. If enacted, the proposals would result in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. As the proposals are not yet enacted, there was no impact on the results of the Trust for the period ended September 30, 2006. The Trust is currently assessing the proposals and the potential implications to the Trust.



Trust Netbacks

Three Months Ended Nine Months Ended
September 30, September 30,
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($/boe) 2006 2005 2006 2005
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Petroleum and natural gas revenue 50.32 57.45 51.01 50.00
Realized risk management gain/(loss) 0.45 (3.54) (0.75) (2.06)
Royalties (11.25) (13.23) (11.10) (11.45)
Production costs (9.26) (8.52) (8.15) (7.97)
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Operating netbacks 30.26 32.16 31.01 28.52

General and administrative (2.60) (2.04) (2.14) (1.80)
Interest and financing charges (0.49) (0.23) (0.46) (0.25)
Capital and current income taxes (0.59) (0.33) (0.41) (0.53)
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Cash flow netbacks 26.58 29.56 28.00 25.94

Depletion and depreciation (13.48) (12.61) (13.14) (12.06)
Unrealized risk management
gain/(loss) 8.31 (7.17) 3.80 (3.85)
Accretion of asset retirement
obligations (0.40) (0.41) (0.40) (0.40)
Unit-based compensation (0.73) (0.25) (0.54) (0.29)
Unrealized foreign exchange gain - 0.50 0.18 0.10
Future income taxes
recovery/(expense) (1.56) 0.31 0.88 (0.06)
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Earnings before non-controlling
interest 18.72 9.93 18.78 9.38
---------------------------------------------------------------------------
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Depletion and depreciation expense for the third quarter of 2006 increased two percent to $10.16 million, compared to $9.92 million in the prior quarter and increased nine percent when compared to the third quarter 2005 expense of $9.32 million. On a per barrel of oil equivalent basis, the depletion and depreciation rates were $13.48, $13.10 and $12.61 for the third and second quarters of 2006 and the third quarter of 2005, respectively. The primary reasons for the year-over-year expense increase are due to the increase in the property and equipment balance from normal operations, from the conversion of exchangeable shares due to the application of EIC-151 and also as a result of prior quarter production losses and the related reserve adjustments for wells in the West Central Alberta core area.

The provision for accretion of asset retirement obligations for the first nine months of 2006 was $0.93 million, a four percent increase compared to the first nine months of 2005. 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 Zargon's drilling program.

The provision for future taxes for the third quarter of 2006 was $1.17 million when compared to a recovery of $3.42 million in the prior quarter and a recovery of $0.23 million in the third quarter of 2005. Effectively, Zargon's future tax obligations are reduced as distributions are made from the Trust and consequently it is anticipated that Zargon's effective tax rate will continue to be low. The first nine months of 2006 includes a second quarter recovery of $6.01 million relating to a reduction in future federal and provincial income tax rates substantively enacted during the 2006 second quarter and includes the impact of certain tax balance adjustments. In addition to the effect of prior quarter tax rate adjustments, the 2006 third quarter increase in future taxes is also a result of the increase in unrealized risk management gains.

According to the January 19, 2005 CICA pronouncement, EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", Zargon Energy Trust must reflect the exchangeable securities issued by its subsidiary (Zargon Oil & Gas Ltd.) as a non-controlling interest. Prior to 2005, these exchangeable shares were reflected as a component of unitholders' equity. Accordingly, the Trust has reflected a non-controlling interest of $17.60 million on the Trust's consolidated balance sheet as at September 30, 2006. Consolidated net earnings have been reduced for net earnings attributable to the non-controlling interest of $1.80 million in the third quarter of 2006. In accordance with EIC-151 and given the circumstances in Zargon's case, each exchangeable share redemption is accounted for as a step-purchase, which in the third quarter of 2006 resulted in an increase in property and equipment of $0.59 million, an increase in unitholders' equity by $0.57 million and an increase in future income tax liability of $0.15 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 $41.06 million, unitholders' equity and non-controlling interest by $44.02 million, future income tax liability by $10.74 million and an allocation of net earnings to exchangeable shareholders' of $13.70 million.

Cash flow from operations in the 2006 third quarter of $20.04 million was $2.09 million, or nine percent lower than the preceding quarter and $1.82 million or eight percent lower than the prior year third quarter. The decline in cash flow from the preceding quarter was primarily due to increased production costs and general and administrative costs, but was also as a result of declining natural gas prices received. Compared to the prior year third quarter, a 12 percent decline in commodity prices was only partially offset by a two percent increase in production volumes. Cash flow on a per diluted trust unit basis was $1.03 for the third quarter of 2006, a 10 percent decrease from both the prior quarter and the 2005 third quarter.

Net earnings of $12.31 million for the 2006 third quarter were seven percent below $13.22 million in the preceding quarter and 96 percent above $6.30 million in the third quarter of 2005. The net earnings track the cash flow from operations for the respective periods modified by non-cash charges, which in the 2006 period include depletion and depreciation, unrealized risk management gains/losses, future income taxes/recoveries and non-controlling interest.



Capital Expenditures

Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------------------------------------------
($ million) 2006 2005 2006 2005
---------------------------------------------------------------------------

Undeveloped land 0.78 0.58 3.68 2.31
Geological and geophysical (seismic) 1.02 1.06 2.87 2.53
Drilling and completion of wells 13.14 10.10 28.60 23.25
Well equipment and facilities 3.70 3.39 11.07 7.35
---------------------------------------------------------------------------

Exploration and development 18.64 15.13 46.22 35.44
---------------------------------------------------------------------------

Property acquisitions 0.36 1.06 1.25 2.40
Property dispositions (0.01) (2.28) (4.51) (2.28)
---------------------------------------------------------------------------

Net property
acquisitions/(dispositions) 0.35 (1.22) (3.26) 0.12
---------------------------------------------------------------------------

Total net capital expenditures 18.99 13.91 42.96 35.56
---------------------------------------------------------------------------
---------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Net capital expenditures of $42.96 million in the first nine months of 2006 were 21 percent higher than the first nine months of 2005, reflecting an active field program of 50 gross (42.8 net) wells compared to 43 gross (38.1 net) wells in the first nine months of 2005. Net capital expenditures for the first nine months of 2006 were allocated to Alberta Plains - $15.21 million, West Central Alberta - $13.75 million and Williston Basin - $14.00 million. Drilling and completion expenses of $28.60 million were 23 percent higher than the prior year's nine month amount of $23.25 million. During the third quarter of 2006, 19.9 net wells were drilled compared to 9.7 net wells in the second quarter of 2006 and 16.2 net wells in the third quarter of 2005. Cash flow from operations in the 2006 first nine months of $64.52 million, proceeds from the exercise of trust unit rights of $3.61 million and the increase in bank debt of $10.37 million funded the capital program, the changes in working capital and the cash distributions to the unitholders. At September 30, 2006, the Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities) of $29.63 million, as compared to $21.83 million at the end of the 2006 second quarter, which represents slightly more than four months of the 2006 year-to-date annualized cash flow.

The recently announced changes to the Canadian income trust tax rules after 2010 may have negatively impacted the Canadian oil and gas trust industry's access to new capital from debt and equity markets in the near future. Zargon's strategy of reinvesting approximately 50 percent of its cash flows as well as the ability to access its recently increased revolving credit facilities can mitigate the potential negative impact on capital markets of the recent tax announcement on Zargon's sustainability strategies.

At November 13, 2006, Zargon Energy Trust had 16.718 million trust units and 2.267 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective November 13, 2006 exchange ratio of 1.17942, there would be 19.392 million trust units outstanding. Pursuant to the trust unit rights incentive plan there are currently an additional 1.097 million trust unit incentive rights issued and outstanding.



Capital Sources

Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------------------------------------------
($ million) 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash flow from operations 20.04 21.85 64.52 58.35
Changes in working capital and other 5.06 2.48 (8.69) (1.34)
Change in bank debt 2.58 (4.09) 10.37 (2.80)
Cash distributions to unitholders (9.00) (7.45) (26.85) (20.78)
Issuance of trust units 0.31 1.12 3.61 2.13
---------------------------------------------------------------------------

Total capital sources 18.99 13.91 42.96 35.56
---------------------------------------------------------------------------
---------------------------------------------------------------------------


OUTLOOK

With a very strong balance sheet, 374 thousand net acres of undeveloped land and a promising internally generated project inventory, Zargon continues to be well positioned to meet its objectives as a sustainable trust. For 2007, Zargon is forecasting an average production rate of 8,750 barrels of oil equivalent per day which is premised on a 2007 exploration and development capital program of $55 million. Consistent with its history, the Trust will adhere to a focused strategy of exploring and exploiting its existing asset base while executing value-added property acquisitions, which if available, would be funded by bank debt or equity issues.



SUMMARY OF QUARTERLY RESULTS

2006
---------------------------------------------------------------------------
Q1 Q2 Q3
---------------------------------------------------------------------------
Petroleum and natural gas revenue ($ million) 40.94 38.66 37.93
Net earnings ($ million) 11.92 13.22 12.31
Net earnings per diluted unit ($) 0.72 0.79 0.73
Cash flow ($ million) 22.35 22.13 20.04
Cash flow per diluted unit ($) 1.17 1.14 1.03
Cash distributions ($ million) 8.89 8.96 9.00
Cash distributions declared per unit ($) 0.54 0.54 0.54
Net capital expenditures ($ million) 15.19 8.78 18.99
Total assets ($ million) 282.35 283.86 294.14
Bank debt ($ million) 26.64 18.14 20.71
Average daily production (boe) 8,812 8,322 8,194
Average realized commodity price before
the impact of financial risk management
contracts ($/boe) 51.63 51.06 50.32
Cash flow netback ($/boe) 28.18 29.22 26.58
---------------------------------------------------------------------------
---------------------------------------------------------------------------

2005
---------------------------------------------------------------------------
Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 34.12 35.87 42.47 50.26
Net earnings ($ million) 5.14 6.48 6.30 17.45
Net earnings per diluted unit ($) 0.32 0.41 0.39 1.06
Cash flow ($ million) 17.48 19.01 21.85 26.62
Cash flow per diluted unit ($) 0.93 1.01 1.15 1.40
Cash distributions ($ million) 6.60 6.73 7.45 16.66
Cash distributions declared
per unit ($) 0.42 0.42 0.46 1.02
Net capital expenditures
($ million) (1) 10.69 10.96 13.91 19.12
Total assets ($ million) 245.20 253.75 264.44 277.86
Bank debt ($ million) 18.23 15.52 11.43 10.34
Average daily production (boe) 8,446 8,238 8,036 8,651
Average realized commodity price before
the impact of financial risk management
contracts ($/boe) 44.90 47.85 57.45 63.15
Cash flow netback ($/boe) 23.01 25.36 29.56 33.45
---------------------------------------------------------------------------
---------------------------------------------------------------------------


2004
---------------------------------------------------------------------------
Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 27.70 30.96 32.41 32.90
Net earnings ($ million) (2) 5.54 5.54 4.22 5.33
Net earnings per diluted unit ($) (2) 0.30 0.29 0.28 0.34
Cash flow ($ 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 declared per unit ($) - - 0.28 0.42
Net capital expenditures ($ million) 9.77 7.61 23.64 15.25
Total assets ($ million) (2) 186.18 189.80 215.23 226.96
Bank debt ($ million) 3.67 - 9.77 14.23
Average daily production (boe) 7,889 8,150 8,405 8,440
Average realized commodity price before
the impact of financial risk management
contracts ($/boe) 38.59 41.75 41.91 42.36
Cash flow netback ($/boe) 21.91 22.28 20.86 19.78
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) Amounts include capital expenditures acquired for cash and equity
issuances.
(2) 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 Annual Information Form for December 31, 2005, is
available on the Trust's SEDAR profile at www.sedar.com.

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

Calgary, Alberta
November 13, 2006



ZARGON ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

(unaudited) September 30, December 31,
($ thousand) 2006 2005
---------------------------------------------------------------------------

ASSETS (note 4)

Current
Accounts receivable 14,326 21,835
Prepaid expenses and deposits 2,915 2,710
Unrealized risk management asset (note 11) 5,760 -
---------------------------------------------------------------------------

23,001 24,545

Property and equipment, net (note 3) 271,142 253,315
---------------------------------------------------------------------------

294,143 277,860
---------------------------------------------------------------------------
---------------------------------------------------------------------------

LIABILITIES

Current
Accounts payable and accrued liabilities 23,157 30,570
Cash distributions payable 3,004 11,122
Unrealized risk management liability (note 11) 767 3,756
---------------------------------------------------------------------------

26,928 45,448

Long term debt (note 4) 20,712 10,339

Asset retirement obligations (note 5) 16,585 15,859

Future income taxes (note 7) 47,763 48,928
---------------------------------------------------------------------------

111,988 120,574
---------------------------------------------------------------------------

NON-CONTROLLING INTEREST

Exchangeable shares (note 2) 17,604 12,673
---------------------------------------------------------------------------

UNITHOLDERS' EQUITY

Unitholders' capital (note 6) 80,382 71,644
Contributed surplus (note 6) 1,949 1,347
Accumulated earnings 157,214 119,768
Accumulated cash distributions (note 13) (74,994) (48,146)
---------------------------------------------------------------------------

164,551 144,613
---------------------------------------------------------------------------

294,143 277,860
---------------------------------------------------------------------------
---------------------------------------------------------------------------
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) 2006 2005 2006 2005
---------------------------------------------------------------------------

REVENUE
Petroleum and natural gas revenue 37,934 42,468 117,541 112,460
Unrealized risk management
gain/(loss) (note 11) 6,267 (5,299) 8,749 (8,650)
Realized risk management
gain/(loss) (note 11) 338 (2,618) (1,731) (4,637)
Royalties (8,478) (9,781) (25,588) (25,727)
---------------------------------------------------------------------------

36,061 24,770 98,971 73,446
---------------------------------------------------------------------------

EXPENSES
Production 6,980 6,298 18,779 17,931
General and administrative 1,957 1,505 4,924 4,059
Unit-based compensation (note 6) 549 185 1,234 658
Interest and financing charges 374 171 1,060 555
Unrealized foreign exchange gain - (369) (422) (218)
Accretion of asset retirement
obligations (note 5) 308 301 930 893
Depletion and depreciation 10,161 9,324 30,275 27,125
---------------------------------------------------------------------------

20,329 17,415 56,780 51,003
---------------------------------------------------------------------------

EARNINGS BEFORE INCOME TAXES 15,732 7,355 42,191 22,443
---------------------------------------------------------------------------

INCOME TAXES (note 7)
Current 446 241 944 1,200
Future (recovery) 1,172 (232) (2,037) 145
---------------------------------------------------------------------------

1,618 9 (1,093) 1,345
---------------------------------------------------------------------------

EARNINGS FOR THE PERIOD BEFORE
NON-CONTROLLING INTEREST 14,114 7,346 43,284 21,098

Non-controlling interest
- exchangeable shares (note 2) (1,804) (1,051) (5,838) (3,181)
---------------------------------------------------------------------------

NET EARNINGS FOR THE PERIOD 12,310 6,295 37,446 17,917

ACCUMULATED EARNINGS, BEGINNING OF
PERIOD 144,904 96,021 119,768 84,399
---------------------------------------------------------------------------

ACCUMULATED EARNINGS, END OF PERIOD 157,214 102,316 157,214 102,316
---------------------------------------------------------------------------
---------------------------------------------------------------------------

NET EARNINGS PER UNIT (note 8)
Basic 0.74 0.39 2.26 1.13
Diluted 0.73 0.39 2.25 1.12
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
($ thousand) 2006 2005 2006 2005
---------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings for the period 12,310 6,295 37,446 17,917
Add (deduct) non-cash items:
Non-controlling interest
- exchangeable shares 1,804 1,051 5,838 3,181
Unrealized risk management
(gain)/loss (6,267) 5,299 (8,749) 8,650
Depletion and depreciation 10,161 9,324 30,275 27,125
Accretion of asset retirement
obligations 308 301 930 893
Unit-based compensation 549 185 1,234 658
Unrealized foreign exchange gain - (369) (422) (218)
Future income taxes (recovery) 1,172 (232) (2,037) 145
---------------------------------------------------------------------------

20,037 21,854 64,515 58,351

Asset retirement expenditures (164) (151) (458) (372)
Changes in non-cash working capital 4,795 (655) 1,399 (886)
---------------------------------------------------------------------------

24,668 21,048 65,456 57,093
---------------------------------------------------------------------------

FINANCING ACTIVITIES
Advances (repayment) of bank debt 2,576 (4,093) 10,373 (2,801)
Cash distributions to unitholders (9,003) (7,448) (26,848) (20,784)
Exercise of unit rights 313 1,122 3,607 2,130
Changes in non-cash working capital 5 342 (8,118) 453
---------------------------------------------------------------------------

(6,109) (10,077) (20,986) (21,002)
---------------------------------------------------------------------------

INVESTING ACTIVITIES
Additions to property and equipment (18,995) (16,192) (47,466) (37,842)
Proceeds on disposal of property
and equipment 10 2,284 4,510 2,284
Changes in non-cash working capital 426 2,937 (1,514) (533)
---------------------------------------------------------------------------

(18,559) (10,971) (44,470) (36,091)
---------------------------------------------------------------------------

CHANGE IN CASH, AND CASH END OF PERIOD - - - -
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes.



ZARGON ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the three and nine months ended September 30, 2006 and 2005 (unaudited)


1. BASIS OF PRESENTATION

The interim unaudited consolidated financial statements of Zargon Energy Trust (the "Trust" or "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, 2005. These interim unaudited consolidated financial statements do not include all disclosures required in the annual consolidated financial statements. 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, 2005.

The Trust's principal business activity is the exploration for and development and production of petroleum and natural gas in Canada and the United States ("US").

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, 2006, a total of 0.13 million exchangeable shares were converted into 0.15 million trust units based on the exchange ratio at the time of conversion. At September 30, 2006, the exchange ratio was 1.17264 trust units per exchangeable share.



Non-Controlling Interest - Exchangeable Shares

Nine Months Ended
September 30, 2006
---------------------------------------------------------------------------
Number Amount
(thousand, except exchange ratio) of Shares ($)
---------------------------------------------------------------------------
Non-controlling interest exchangeable
shares issued
Balance, beginning of period 2,402 12,673
Earnings attributable to non-controlling
interest - 5,838
Exchanged for trust units at book value
and including earnings attributed since
beginning of period (130) (907)
---------------------------------------------------------------------------
Balance, end of period 2,272 17,604
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Exchange ratio, end of period 1.17264
Trust units issuable upon conversion of
exchangeable shares, end of period 2,664
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Per EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", 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.

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.



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

Zargon Zargon Oil
Energy & Gas Ltd.
Trust Exchangeable
($ thousand) Units Shares Total
---------------------------------------------------------------------------
Balance, beginning of period 71,644 12,673 84,317
Issued on redemption of exchangeable
shares at book value 319 (319) -
Effect of EIC-151 4,180 5,250 9,430
Unit-based compensation recognized
on exercise of unit rights 632 - 632
Unit rights exercised for cash 3,607 - 3,607
---------------------------------------------------------------------------
Balance at September 30, 2006 80,382 17,604 97,986
---------------------------------------------------------------------------
---------------------------------------------------------------------------

3. PROPERTY AND EQUIPMENT

September 30, 2006
---------------------------------------------------------------------------
Accumulated
Depletion
and Net Book
($ thousand) Cost Depreciation Value
---------------------------------------------------------------------------
Petroleum, natural gas properties
and other equipment(1) 436,879 165,737 271,142
---------------------------------------------------------------------------
---------------------------------------------------------------------------

December 31, 2005
---------------------------------------------------------------------------
Accumulated
Depletion
and Net Book
($ thousand) Cost Depreciation Value
---------------------------------------------------------------------------
Petroleum, natural gas properties
and other equipment(1) 388,777 135,462 253,315
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(1) As a result of shareholders redeeming exchangeable shares, property and equipment has cumulatively increased $41.06 million, $4.85 million relating to the first nine months of 2006, $24.93 million relating to 2005 and $11.28 million relating to 2004. The effect of these increases has resulted in additional depletion and depreciation expense recorded in the first nine months of 2006 of $4.11 million and $3.72 million for the same period in 2005.

4. LONG TERM DEBT

On June 30, 2006, Zargon amended and renewed its syndicated committed credit facilities, the result of which is an increase in the available facilities and borrowing base to $100 million from the previous amount of $80 million. These facilities consist of an $80 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 Zargon's management. The next renewal date is July 31, 2007. 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, these facilities have 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) 2006 2005
---------------------------------------------------------------------------

Balance, beginning of period 15,859 14,390
Net liabilities incurred 294 526
Liabilities settled (458) (372)
Accretion expense 930 893
Foreign exchange (40) (34)
---------------------------------------------------------------------------
Balance, end of period 16,585 15,403
---------------------------------------------------------------------------
---------------------------------------------------------------------------

6. UNITHOLDERS' EQUITY

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

Trust Units Nine Months Ended
September 30, 2006
---------------------------------------------------------------------------
Number Amount
(thousand) of Units ($)
---------------------------------------------------------------------------

Units issued
Balance, beginning of period 16,355 71,644
Unit rights exercised for cash 185 3,607
Unit-based compensation recognized on exercise
of unit rights - 632
Issued on conversion of exchangeable shares 149 4,499
---------------------------------------------------------------------------
Balance, end of period 16,689 80,382
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The proforma total units outstanding at September 30, 2006, 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 19.353 million units.

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



Contributed Surplus

Nine Months Ended
($ thousand) September 30, 2006
---------------------------------------------------------------------------

Balance, beginning of period 1,347
Unit-based compensation expense 1,234
Unit-based compensation recognized on exercise of unit rights (632)
---------------------------------------------------------------------------
Balance, end of period 1,949
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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. Zargon uses a fair value methodology to value the unit rights grants.

The weighted average assumptions made for unit rights granted for 2006 include a volatility factor of expected market price of 26.64 percent, a risk-free interest rate of 4.11 percent, a dividend yield of 6.89 percent and an expected life of the unit rights of four years, resulting in unit-based compensation expense of $1.23 million for the nine months ended September 30, 2006.

Compensation expense associated with rights granted under the Plan is recognized in earnings over the vesting period of the Plan with a corresponding increase 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, 2006
---------------------------------------------------------------------------
Number of Weighted Average
Unit Rights Exercise Price
(thousand) ($/unit right)
---------------------------------------------------------------------------

Outstanding at beginning of period 915 22.80
Unit rights granted 382 31.41
Unit rights exercised (185) 19.50
Unit rights cancelled (15) 25.05
------------------------------------------------------
Outstanding at end of period 1,097 26.33
------------------------------------------------------
------------------------------------------------------
Unit rights exercisable at period end 235 23.49
---------------------------------------------------------------------------
---------------------------------------------------------------------------


7. INCOME TAXES

In the second quarter, the new Federal Government budget eliminated the large corporation tax effective for 2006 and accordingly, amounts previously recorded for 2006 have been reversed.

The future income tax provision for the nine months ended September 30, 2006 includes a recovery of $6.01 million relating to a reduction in future federal and provincial income tax rates substantively enacted and recorded during the second quarter and includes the impact of certain tax balance adjustments.

On October 31, 2006, the Federal Government announced tax proposals pertaining to taxation of distributions paid by trusts and the personal tax treatment of trust distributions. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. If enacted, the proposals would result in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. As the proposals are not yet enacted, there was no impact on the results of the Trust for the period ended September 30, 2006. The Trust is currently assessing the proposals and the potential implications to the Trust.

8. 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 units) 2006 2005 2006 2005
---------------------------------------------------------------------------

Basic 16,666 16,141 16,551 15,906

Diluted 19,424 19,024 19,236 18,852
---------------------------------------------------------------------------
---------------------------------------------------------------------------


9. 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) 2006 2005 2006 2005
---------------------------------------------------------------------------

Petroleum and Natural Gas Revenue
Canada 31,093 36,348 98,264 96,978
United States 6,841 6,120 19,277 15,482
---------------------------------------------------------------------------
Total 37,934 42,468 117,541 112,460
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Net Capital Expenditures
Canada 17,875 12,997 38,862 33,639
United States 1,110 911 4,094 1,919
---------------------------------------------------------------------------
Total 18,985 13,908 42,956 35,558
---------------------------------------------------------------------------
---------------------------------------------------------------------------


September 30, December 31,
($ thousand) 2006 2005
---------------------------------------------------------------------------
Property and Equipment, net
Canada 237,174 221,664
United States 33,968 31,651
---------------------------------------------------------------------------
Total 271,142 253,315
---------------------------------------------------------------------------
---------------------------------------------------------------------------


10. SUPPLEMENTAL CASH FLOW INFORMATION

Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------------------------------------------
($ thousand) 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash interest paid 360 320 1,063 711

Cash taxes (refunded)/paid (175) 656 551 1,520
---------------------------------------------------------------------------
---------------------------------------------------------------------------


11. RISK MANAGEMENT CONTRACTS

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, 2006 as follows:



Financial Contracts at September 30, 2006:
Fair Market
Value
Weighted Gain/(Loss)
Rate Average Price Range of Terms ($ thousand)
---------------------------------------------------------------------------
Oil swaps 600 bbl/d $54.55 US/bbl Oct. 1/06-Dec. 31/06 (604)
100 bbl/d $71.50 US/bbl Oct. 1/06-Dec. 31/07 214
500 bbl/d $67.33 US/bbl Jan. 1/07-Jun. 30/07 8
400 bbl/d $73.01 US/bbl Jan. 1/07-Dec. 31/07 810
500 bbl/d $72.10 US/bbl Jul. 1/07-Dec. 31/07 335

Oil collars 200 bbl/d $52.00 US/bbl Put Oct. 1/06-Dec. 31/06 -
$78.95 US/bbl Call
200 bbl/d $55.00 US/bbl Put Oct. 1/06-Dec. 31/06 -
$78.05 US/bbl Call

Natural gas
swaps 4,000 gj/d $9.31/gj Oct. 1/06-Oct. 31/06 638
3,000 gj/d $9.13/gj Nov. 1/06-Mar. 31/07 1,106
4,000 gj/d $8.47/gj Apr. 1/07-Oct. 31/07 1,487

Natural gas
collars 1,000 gj/d $9.50/gj Put Nov. 1/06-Mar. 31/07 424
$12.50/gj Call
1,000 gj/d $10.50/gj Put Nov. 1/06-Mar. 31/07 575
$13.18/gj Call
---------------------------------------------------------------------------
Net Fair Market Value, Financial Contracts 4,993
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Physical Contracts at September 30, 2006:

Fair Market
Value
Weighted Gain/(Loss)
Rate Average Price Range of Terms ($ thousand)
---------------------------------------------------------------------------
Natural
gas fixed
price 4,000 gj/d $7.91/gj Oct. 1/06-Oct. 31/06 466
2,000 gj/d $9.23/gj Nov. 1/06-Mar. 31/07 766
1,000 gj/d $7.88/gj Apr. 1/07-Oct. 31/07 246

Natural gas
collars 1,000 gj/d $8.50/gj Put Nov. 1/06-Mar. 31/07 273
$12.85/gj Call
1,000 gj/d $9.50/gj Put Nov. 1/06-Mar. 31/07 424
$13.50/gj Call
---------------------------------------------------------------------------
Total Fair Market Value, Physical Contracts 2,175
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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

For financial risk management contracts, 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 and accordingly any unrealized gains or losses are recorded based on the fair value (mark-to-market) of the contracts at the period end. The unrealized gain for the first nine months of 2006 was $8.75 million and the unrealized loss for the first nine months of 2005 was $8.65 million.

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.

12. COMMITMENTS

In the second quarter of 2006, Zargon renewed and expanded its office lease for six years until July 31, 2012. Payments required under this new office lease are as follows: remainder of 2006 - $0.16 million; 2007 - $0.73 million; 2008 - $0.85 million; 2009 - $0.85 million; 2010 - $0.85 million; thereafter - $1.34 million. There have been no other significant changes in Zargon's commitments from those previously disclosed in the 2005 annual report.



13. ACCUMULATED CASH DISTRIBUTIONS

During the nine month period, the Trust declared cash distributions to the
unitholders in the aggregate amount of $26.85 million (2005 -
$20.78 million) in accordance with the following schedule:

2006 Distributions Record Date Distribution Date Per Trust Unit
---------------------------------------------------------------------------

January January 31, 2006 February 15, 2006 $0.18
February February 28, 2006 March 15, 2006 $0.18
March March 31, 2006 April 17, 2006 $0.18
April April 30, 2006 May 15, 2006 $0.18
May May 31, 2006 June 15, 2006 $0.18
June June 30, 2006 July 17, 2006 $0.18
July July 31, 2006 August 15, 2006 $0.18
August August 31, 2006 September 15, 2006 $0.18
September September 30, 2006 October 16, 2006 $0.18
---------------------------------------------------------------------------
---------------------------------------------------------------------------

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 Craig H. Hansen
Calgary, Alberta President and The Toronto Stock
Chief Executive Officer Exchange
K. James Harrison(3)(4)
Oakville, Ontario Henry J. Baird Zargon Energy
Vice President, Trust
Kyle D. Kitagawa(1)(2) Exploitation Trust Units
Calgary, Alberta Trading Symbol:
Brent C. Heagy ZAR.UN
James J. Lawson(1)(3) Vice President, Finance
Oakville, Ontario and Chief Financial Zargon Oil & Gas
Officer Ltd.
John O. McCutcheon Exchangeable
Chairman of the Board Mark I. Lake Shares
Vancouver, British Columbia Vice President, Trading Symbol:
Exploration ZOG.B
Jim Peplinski(2)(4)
Calgary, Alberta Daniel A. Roulston
Executive Vice Transfer Agent
J. Graham Weir(1)(2) President, Operations
Calgary, Alberta Valiant Trust
Sheila A. Wares Company
Grant A. Zawalsky(3)(4) Vice President, 310, 606 - 4th
Calgary, Alberta Accounting Street S.W.
Calgary, Alberta
1 Audit Committee Kenneth W. Young T2P 1T1
2 Reserves Committee Vice President, Land
3 Governance and
Nominating Committee Head Office
4 Compensation Committee
700, 333 - 5th
Avenue S.W.
Calgary, Alberta
T2P 3B6
Telephone:
(403) 264-9992
Fax:
(403) 265-3026
Email:
zargon@zargon.ca

Website

www.zargon.ca



Phone: (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