ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

November 13, 2007 17:01 ET

Zargon Energy Trust Announces 2007 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 13, 2007) - Zargon Energy Trust (TSX:ZAR.UN) and Zargon Oil & Gas Ltd. (TSX:ZOG.B):

For The Three And Nine Months Ended September 30, 2007

FINANCIAL & OPERATING HIGHLIGHTS

Zargon Energy Trust is pleased to report its financial results for the third quarter of 2007. Funds flow from operations was $17.38 million ($0.88 per diluted trust unit) in the 2007 third quarter compared with $20.56 million ($1.05 per diluted trust unit) in the 2007 second quarter and $19.87 million ($1.02 per diluted trust unit) in the 2006 third quarter.

Highlights from the three and nine months ended September 30, 2007 are noted below:

- Third quarter 2007 production averaged 8,501 barrels of oil equivalent per day, up slightly from the preceding quarter and an increase of four percent from the corresponding quarter of 2006. Third quarter production volumes remained stable compared to the prior quarter as new natural gas production in the West Central Alberta and Alberta Plains core areas were offset by natural oil production declines in the Williston Basin core area. For the third quarter of 2007, Zargon's production averaged 432 barrels of oil equivalent per day per million trust units outstanding compared to the 424 barrels of oil equivalent per day per million trust units outstanding in the third quarter of 2006 and 432 barrels of oil equivalent per day per million trust units outstanding in the second quarter of 2007.

- Revenue in the 2007 third quarter decreased seven percent and funds flow from operations decreased 15 percent from the prior quarter. Compared to the prior quarter, increased realized oil prices of nine percent were offset by a 26 percent reduction in realized natural gas prices and higher production costs primarily related to seasonal repairs and maintenance in the Williston Basin core area.

- The Trust continued to maintain its cash distributions on a per unit basis with three monthly cash distributions of $0.18 per trust unit in the third quarter of 2007 for a total of $9.19 million. These cash distributions were equivalent to a payout ratio of 61 percent of the Trust's third quarter funds flow on a diluted trust unit basis, and after considering the effect of the exchangeable shares not receiving distributions, the distributions amounted to 53 percent of funds flow from operations.

- The Trust's third quarter exploration and development capital expenditures increased 92 percent from the prior quarter to $16.41 million primarily as a result of increased drilling activity, tie-ins and equipping of wells relating to a 19.3 net well Alberta Plains summer-fall shallow gas development drilling program. Debt net of working capital (excluding unrealized risk management assets and liabilities) increased 18 percent from the balance at the end of the prior quarter to $54.61 million at September 30, 2007. The Trust's balance sheet remains strong with a debt net of working capital to annualized funds flow ratio of slightly less than 0.7 times.



Three Months Ended Nine Months Ended
September 30, September 30,
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Percent Percent
(unaudited) 2007 2006 Change 2007 2006 Change
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Financial

Income and Investments
($ million)
Petroleum and natural gas
revenue 36.64 37.93 (3) 114.38 117.54 (3)
Funds flow from operations 17.38 19.87 (13) 59.74 64.06 (7)
Cash distributions 9.19 9.00 2 27.49 26.85 2
Net earnings 5.50 12.31 (55) 22.35 37.45 (40)
Net capital expenditures 16.43 18.99 (13) 48.32 42.96 12
Per Unit, Diluted
Funds flow from operations
($/unit) 0.88 1.02 (14) 3.06 3.33 (8)
Net earnings ($/unit) 0.32 0.73 (56) 1.32 2.25 (41)
Cash Distributions ($/trust
unit) 0.54 0.54 - 1.62 1.62 -
Balance Sheet at Period End ($
million)
Property and equipment, net 304.76 271.14 12
Bank debt 44.10 20.71 113
Unitholders' equity 167.11 164.55 2
Total Units Outstanding at
Period End (million) 19.70 19.35 2

Operating

Average Daily Production
Oil and liquids (bbl/d) 3,588 3,704 (3) 3,679 3,810 (3)
Natural gas (mmcf/d) 29.48 26.94 9 28.83 27.78 4
Equivalent (boe/d) 8,501 8,194 4 8,483 8,441 -
Equivalent per million trust
units (boe/d) 432 424 2 433 439 (1)
Average Selling Price (before
the impact of financial
risk management contracts)
Oil and liquids ($/bbl) 68.19 67.75 1 62.49 63.44 (1)
Natural gas ($/mcf) 5.21 5.99 (13) 6.56 6.80 (4)
Wells Drilled, Net 20.9 19.9 5 37.9 42.8 (11)
Undeveloped Land at Period End
(thousand net acres) 387 374 3
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Notes:
Throughout this report, funds flow from operations, funds flow from
operations per diluted unit and funds flow netbacks are now calculated
inclusive of asset retirement expenditures. All prior period calculations
have been restated to reflect this change.

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.

Funds flow from operations is a non-GAAP term that represents net earnings
and asset retirement expenditures 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 2007 averaged 29.48 million cubic feet per day, an increase of three percent from the previous quarter and a nine percent increase from the corresponding period of 2006. New natural gas volumes added from well tie-ins in the West Central Alberta and Alberta Plains core areas were partially offset by natural declines and compressor outages in the Jarrow area of the Alberta Plains. Further natural gas production gains are anticipated in the fourth quarter as wells from the summer-fall shallow gas development drilling program in the Jarrow and Hamilton Lake areas of the Alberta Plains are placed on production.

Oil and liquids production volumes were 3,588 barrels per day in the 2007 third quarter, a three percent reduction from the preceding quarter and the corresponding 2006 quarter primarily due to natural declines in the Williston Basin core area. Oil and liquids production should remain relatively stable in the fourth quarter, but significant production gains coming from fourth quarter Taber and Williston Basin oil exploitation drilling programs should be realized in the 2008 first quarter.

CAPITAL EXPENDITURES (1)

During the third quarter of 2007, Zargon conducted an active field capital program with the drilling of 24 gross wells (20.9 net) that resulted in 19.3 net natural gas wells and 1.6 net oil wells for a 100 percent success rate. The largest increase in activity occurred in the Alberta Plains core area, where 6.3 net natural gas wells were drilled at Jarrow and 13.0 net natural gas wells were drilled at Hamilton Lake. The remaining third quarter 1.6 net oil wells were located in the Williston Basin core area at Antler and Midale, Saskatchewan.

In Alberta Plains, Zargon executed a 19.3 net well shallow natural gas development field program. In this core area, the focus for the fourth quarter will be on the tie-in of these Jarrow and Hamilton Lake shallow natural gas wells and on the drilling of two horizontal development oil wells at Taber. As a result of current low natural gas prices, the previously scheduled additional seven well Jarrow exploration program for the fourth quarter has been deferred until January 2008.

Recent tie-ins of natural gas wells at Pembina and Highvale in West Central Alberta have added an additional 1.5 million cubic feet per day of natural gas production since the end of the second quarter of 2007. For a variety of partner and surface access related reasons, the West Central Alberta fourth quarter drilling program has been reduced to three exploratory wells at the Peace River Arch Gordondale, Highvale and Pembina properties. The remaining 2007 fourth quarter scheduled West Central Alberta exploration wells have been deferred until the 2008 first quarter and include two net wells at Highvale and four (2.9 net) wells at Peace River Arch locations exploring targets at the Rycroft, Kakut, Webster and Hamelin Creek properties.

In the Williston Basin, Zargon is proceeding with an expanded field program in the fourth quarter that includes one vertical well at Pinto and horizontal wells at Steelman and Elswick, Saskatchewan and at Mackobee Coulee and Truro in North Dakota.

The cost of acquiring land at Crown land sales continues to moderate, and accordingly, Zargon has been able to maintain its undeveloped land inventory with reasonably priced purchases. Zargon's undeveloped land inventory at September 30, 2007 was 387 thousand net acres, an increase of two thousand net acres from the balance reported at the end of the prior quarter.

OUTLOOK (1)

Following a highly prosperous and enthusiastic period, the past year has presented multiple challenges to our industry including changes in tax rules for trusts, lower natural gas prices, a much higher Canadian dollar and recently, proposed changes to the royalty structure by the Government of Alberta. Although the long term outlook for our industry continues to be very positive, these events have combined to negatively impact current cash flows and, perhaps more importantly, the industry's access to capital from debt and equity markets. As a consequence of these reduced capital inflows into our industry, there has been a clear trend to significantly lower costs for the key inputs for our exploration, development and exploitation businesses. Specifically, Zargon's access to more reasonably priced Crown land purchases, access to lower cost higher-quality field services relating to the drilling and completion of wells and access to higher quality professional staff has improved significantly. We have also observed a clear trend to more realistic vendor price expectations for Canadian property and corporate acquisitions.

Over its history, Zargon has followed a counter-cyclical and value-seeking business strategy that has tended to restrict our growth during our industry's enthusiastic periods. As a result of this disciplined strategy, Zargon enters this period of improved access and cost for our key business inputs in an opportune position, as evidenced by a debt net of working capital to annualized funds flow ratio of slightly less than 0.7 times and a payout ratio of 53 percent of the Trust's third quarter funds flow after considering the effect of the exchangeable shares not receiving distributions. With a strong balance sheet and with our continued investor support, Zargon is very well positioned to deliver long term focused per unit production and reserve gains during this period of opportunity and at this point, provided that our capital programs meet efficiency targets, we do not anticipate a need to materially reduce our capital spending programs because of the lower cash flows resulting from a strong Canadian dollar and low natural gas prices.

In order to prepare for this new short and medium term industry environment of lower natural gas prices, strong oil prices and significantly improved access to opportunities, we have modified our capital programs for the remainder of 2007 and 2008 to accelerate cash flow generating oil projects and to bring forward long term natural gas exploration initiatives while deferring development drilling programs that would provide short term natural gas production gains. The resulting 2008 budget of $55 million is allocated $22 million to the Alberta Plains, $18 million to the Williston Basin and $15 million to the West Central Alberta core areas. Compared to 2007, the budget has an increased oil exploitation focus and an increased long term natural gas exploration focus evidenced by a 19 percent allocation to land, seismic and geological expenditures up from the respective 14 and 17 percentages in 2006 and 2007.

In the Alberta Plains core area, there will be an increased focus on Taber oil exploitation, a continued focus on Jarrow exploration, but unless there is a sustained natural gas price recovery, a reduction in the Jarrow and Hamilton Lake natural gas development programs. For the Williston Basin core area, Zargon will continue with optimization of ultimate oil recovery factors in its large oil-in-place pools through exploitation drilling and water injection pressure maintenance projects. In the West Central Alberta core area, the focus will primarily be on Peace River Arch exploration prospects that can provide longer-life, stable production profiles.

GUIDANCE (1)

In the August 13, 2007 press release announcing the 2007 second quarter results, Zargon updated its 2007 full year production guidance to an estimated range of 8,500 to 8,600 barrels of oil equivalent per day based on a $60 million exploration and development capital program. With positive momentum for production levels headed into the fourth quarter of this year, Zargon is anticipating a fourth quarter 2007 production rate of 8,625 barrels of oil equivalent per day and an average 2007 rate in excess of 8,500 barrels of oil equivalent per day. The reallocated 2007 capital budget remains at $60 million and will include the drilling of 53 gross (46.9 net) wells.

For 2008, Zargon is providing preliminary guidance at 8,800 barrels of oil equivalent per day, which is based on a 2008 exploration and development capital program of $55 million that includes the drilling of 50 net wells.

Since November 2005, Zargon has maintained a monthly distribution of $0.18 per trust unit, and plans to maintain this level of distribution for the remainder of this year and into 2008.

RETIREMENT OF CHAIRMAN AND APPOINTMENT OF NEW CHAIRMAN

On November 6, 2007, Zargon announced that John O. McCutcheon is retiring as Chairman of the Board of Zargon. John is an original founder of Zargon and has provided valuable leadership to the organization over its 14 year public history. We, as an organization, are deeply grateful to John for his many years of service as Chairman and would like to thank him for his contribution and look forward to his continued participation as a member of the Board of Directors. On the same date, we also announced the appointment of K. James (Jim) Harrison as Chairman of the Board. Jim is a senior member of the Board of Directors of Zargon and has a long history of service to the organization as a Board member since 1995. He has recently served as Chairman of the Governance & Nominating Committee and is President of K.J. Harrison & Partners Inc., an investment management firm based in Toronto, Canada. Zargon's Board, management and staff are all looking forward to working with Jim as we continue to build long term value for the unitholders of Zargon.

(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, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006. 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 "funds flow from operations" ("funds flow"), which should not be considered an alternative to or more meaningful than, "cash flows 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 funds flow from operations may not be comparable to that reported by other trusts. The reconciliation between cash flows from operating activities and funds flow from operations can be found in the table below and 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 funds flow from operations. The Trust considers funds 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. Funds flow from operations per unit is calculated using the diluted weighted average number of units for the period.



Funds Flow from Operations
Reconciliation
Three Months Nine Months
Ended Ended
September 30, September 30,
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($ million) 2007 2006 2007 2006
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Cash flows from operating
activities 24.64 24.67 62.08 65.46
Changes in non-cash working
capital (7.26) (4.80) (2.34) (1.40)
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Funds flow from operations 17.38 19.87 59.74 64.06
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- 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 adjusted for realized risk management gains and/or 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.

- Funds flow netbacks per boe are calculated as operating netbacks less general and administrative expenses per boe, interest and financing charges per boe, asset retirement expenditures per boe and current income taxes per boe. Funds 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 12, 2007 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 12, 2007.

SUMMARY OF SIGNIFICANT EVENTS IN THE THIRD QUARTER

- During the third quarter of 2007, the Trust realized funds flow from operations of $17.38 million and declared total distributions of $9.19 million ($0.54 per trust unit) to unitholders. 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 and for natural gas prices increased nine percent to $68.19 per barrel and decreased 26 percent to $5.21 per thousand cubic feet, respectively, compared to the second quarter of 2007. Third quarter production volumes were 8,501 barrels of oil equivalent per day, relatively even with the second quarter 2007 production levels.

- During the third quarter of 2007, the Trust drilled 24 gross wells (20.9 net) with a 100 percent success rate. Total net capital expenditures for this quarter were $16.43 million, a substantial increase compared to the activity restricted $10.97 million prior quarter due to spring break-up, and $18.99 million for the 2006 third quarter.

- On July 30, 2007, Zargon amended and renewed its syndicated credit facilities, which resulted in an increase in the available facilities and the borrowing base by $20 million to $120 million. These expanded facilities continue to be available for general corporate purposes and the potential acquisition of oil and gas properties.

- 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 $54.61 million. Unutilized credit facilities of $75.90 million were available at September 30, 2007.

FINANCIAL ANALYSIS

Third quarter 2007 revenue of $36.64 million was seven percent below the $39.21 million in the second quarter of 2007 and three percent below the $37.93 million in the third quarter of 2006. A nine percent increase in oil and liquids prices received was offset by a 26 percent decrease in natural gas prices received when compared to the prior quarter amounts. Average daily production volumes held relatively even over the prior quarter rate. Third quarter 2007 realized oil and liquids field prices averaged $68.19 per barrel before the impact of financial risk management contracts and were nine percent higher from the preceding quarter's $62.37 per barrel and were one percent higher than the $67.75 per barrel recorded in the 2006 third quarter. Zargon's crude oil field price differential from the Edmonton par price increased to $11.76 per barrel in the third quarter of 2007 compared to $9.56 per barrel in the second quarter of 2007. Further increases in the crude oil field price differentials are expected this upcoming winter season. Natural gas field prices received averaged $5.21 per thousand cubic feet before the impact of financial risk management contracts in the third quarter of 2007, a decrease of 13 percent from the 2006 third quarter prices received and a 26 percent decrease from the preceding quarter levels. Zargon's realized field prices differ from the benchmark AECO average daily price due to a combination of fixed price physical contracts (see note 12 to the interim unaudited consolidated financial statements) and from the impact of Zargon receiving AECO monthly index pricing for a portion of its natural gas production.



Pricing
Three Months Ended Nine Months Ended
September 30, September 30,
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Percent Percent
Average For The Period 2007 2006 Change 2007 2006 Change
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Natural Gas:
NYMEX average daily spot price
($US/mmbtu) 6.16 6.06 2 6.97 6.77 3
AECO average daily spot price
($Cdn/mmbtu) 5.16 5.65 (9) 6.55 6.40 2
Zargon realized field price
before the impact of financial
risk management contracts
($Cdn/mcf) 5.21 5.99 (13) 6.56 6.80 (4)
Zargon realized field price
before the impact of physical
and financial risk management
contracts ($Cdn/mcf) 5.03 5.55 (9) 6.37 6.35 -
Zargon realized field price
after the impact of physical
and financial risk management
contracts ($Cdn/mcf) 5.72 6.52 (12) 6.95 7.12 (2)
Crude Oil:
WTI ($US/bbl) 75.38 70.48 7 66.19 68.22 (3)
Edmonton par price ($Cdn/bbl) 79.95 79.08 1 72.99 75.53 (3)
Zargon realized field price
before the impact of financial
risk management contracts
($Cdn/bbl) 68.19 67.75 1 62.49 63.44 (1)
Zargon realized field price
after the impact of financial
risk management contracts
($Cdn/bbl) 67.31 64.87 4 63.94 59.40 8
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Natural gas production volumes increased in the third quarter of 2007 to 29.48 million cubic feet per day compared to 28.55 million cubic feet per day in the second quarter of 2007 and were nine percent higher than the 2006 third quarter. The year-over-year increase in natural gas production volumes is primarily due to the continued tie-in of wells in the Alberta Plains and West Central Alberta core areas. Oil and liquids production during the third quarter of 2007 was 3,588 barrels per day, which is three percent below the 2007 second quarter rate of 3,707 barrels per day and three percent below the 2006 third quarter level. The year-over-year decrease in oil and liquids production is primarily due to the effect of naturally occurring production declines. On a barrel of oil equivalent basis, Zargon produced 8,501 barrels of oil equivalent per day in the third quarter of 2007, which represents less than a one percent increase from the 8,465 barrels of oil equivalent per day in the second quarter of 2007 and a four percent increase when compared to the third quarter of 2006.



Production by Core Area

Three Months Ended September 30,

2007 2006
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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)
----------------------------------------------------------------------------
Alberta Plains 583 19.87 3,895 484 18.92 3,637
West Central
Alberta 144 9.34 1,700 162 7.81 1,464
Williston Basin 2,861 0.27 2,906 3,058 0.21 3,093
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3,588 29.48 8,501 3,704 26.94 8,194
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Nine Months Ended September 30,

2007 2006
----------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta Plains 543 19.90 3,859 511 19.19 3,710
West Central
Alberta 159 8.66 1,602 176 8.37 1,571
Williston Basin 2,977 0.27 3,022 3,123 0.22 3,160
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3,679 28.83 8,483 3,810 27.78 8,441
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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. 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 2007 third quarter, relatively lower natural gas prices brought about a net realized financial risk management gain totalling $1.11 million (consisting of a $1.40 million gain on natural gas contracts net of a $0.29 million loss on oil contracts), which compares to a $1.12 million realized net gain in the second quarter of 2007 and a $0.34 million realized net gain in the third quarter of 2006.

The 2007 third quarter unrealized risk management loss resulted from unrealized risk management oil contract losses ($2.59 million) slightly offset by natural gas contract gains ($0.23 million), providing a net loss of $2.36 million for the quarter, which compares to a net $1.22 million gain for the 2007 second quarter and a net $6.27 million gain in the third quarter of 2006. 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 financial contracts. Zargon's commodity risk management positions are fully described in note 12 to the unaudited consolidated interim financial statements.

Royalties, inclusive of the Saskatchewan Resource Surcharge, totalled $7.63 million for the third quarter of 2007, a decrease of 11 percent from the $8.53 million preceding quarter expense and a decrease of 10 percent from $8.48 million in the third quarter of 2006. 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 22.3 percent in the third quarter of 2006 to 21.8 percent in the second quarter of 2007 and 20.8 percent in the third quarter of 2007. Through to the end of 2008, Zargon expects that its royalty rate will remain stable at recent levels in the 21 to 22 percent range. Commencing in 2009, the oil and natural gas royalty structure will change on Alberta related production volumes. A discussion around this issue follows later in this report. 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 $10.95 per barrel of oil equivalent in the third quarter of 2007 compares with $9.97 per barrel of oil equivalent in the preceding quarter and $9.26 per barrel of oil equivalent in the third quarter of 2006. Compared to the prior quarter, increased production costs are primarily related to increased workovers and seasonal repairs and maintenance in the Williston Basin core area. Over the last two years, Zargon has experienced severe industry-wide production cost inflation pressures, which may now be somewhat abating due to lower industry activity levels in response to recent natural gas price declines and Alberta royalty rate uncertainties. For 2008, Zargon anticipates that production costs can be maintained in the $10.50 to $11.50 per barrel of oil equivalent range as general cost inflation pressures are reduced and benefits from Zargon's specific cost containment initiatives including the buyout of natural gas compressor lease contracts are realized.



Operating Netbacks

Three Months Ended September 30, 2007 2006
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 68.19 5.21 67.75 5.99
Realized risk management
gain/(loss) (0.88) 0.51 (2.88) 0.53
Royalties (14.47) (1.05) (15.77) (1.26)
Production costs (14.83) (1.35) (12.71) (1.07)
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Operating netbacks 38.01 3.32 36.39 4.19
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Nine Months Ended September 30, 2007 2006
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 62.49 6.56 63.44 6.80
Realized risk management
gain/(loss) 1.45 0.39 (4.04) 0.32
Royalties (13.56) (1.38) (14.26) (1.42)
Production costs (13.77) (1.31) (11.00) (0.97)
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Operating netbacks 36.61 4.26 34.14 4.73
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Measured on a unit of production basis (net of recoveries), general and administrative expenses were $2.41 per barrel of oil equivalent in the first nine months of 2007 compared to $2.14 in the first nine months of 2006 and $2.27 for the twelve month period of 2006. The year-over-year increase in general and administrative expenses on a per unit of production basis are primarily due to additional office lease costs and the costs related to the expansion of Zargon's technical staff.

Expensing of unit-based compensation in the first nine months of 2007 was $1.14 million, a seven percent decrease from the corresponding nine months of 2006. The slight decrease in expense for this period is a result of increased cancellations of unit rights and a general decline in the valuation of new quarterly grants.

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges on these facilities in the 2007 third quarter were $0.85 million, $0.12 million higher than the previous quarter amount of $0.73 million and an increase of $0.47 million from $0.37 million in the third quarter of 2006. This year-over-year increase is primarily due to a combination of higher than average bank debt levels and higher effective interest rates. On July 30, 2007, Zargon amended and renewed its syndicated committed credit facilities, which resulted in an increase in the available facilities and borrowing base to $120 million from the previous amount of $100 million. The next renewal date is July 29, 2008. These expanded facilities continue to be available for general corporate purposes and the potential acquisition of oil and gas properties.

Current taxes for the 2007 third quarter were $0.83 million, primarily relating to the United States operations, where increased taxable income is resulting in higher United States taxes. When compared to prior periods, current income taxes increased $0.38 million over the 2006 third quarter and increased $0.13 million relative to the second quarter of 2007. Tax pools as at September 30, 2007 are approximately $143 million, which represents an increase from the comparable $113 million of tax pools available to Zargon at December 31, 2006.



Trust Netbacks

Three Months Ended Nine Months Ended
September 30, September 30,
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($/boe) 2007 2006 2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas revenue 46.84 50.32 49.39 51.01
Realized risk management gain/(loss) 1.41 0.45 1.97 (0.75)
Royalties (9.76) (11.25) (10.57) (11.10)
Production costs (10.95) (9.26) (10.42) (8.15)
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Operating netbacks 27.54 30.26 30.37 31.01
General and administrative (2.70) (2.60) (2.41) (2.14)
Interest and financing charges (1.08) (0.49) (0.93) (0.46)
Asset retirement expenditures (1) (0.48) (0.22) (0.37) (0.20)
Current income taxes (1.06) (0.59) (0.87) (0.41)
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Funds flow netbacks (1) 22.22 26.36 25.79 27.80
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(1) Throughout this report, funds flow netbacks are now calculated inclusive
of asset retirement expenditures. All prior period calculations have
been restated to reflect this change.


Depletion and depreciation expense for the third quarter of 2007 increased four percent to $12.18 million compared to $11.76 million in the prior quarter and increased 20 percent when compared to the 2006 third quarter expense of $10.16 million. On a per barrel of oil equivalent basis, the depletion and depreciation rates were $15.58, $15.27 and $13.48 for the third and second quarters of 2007 and the third quarter of 2006, respectively. The primary reasons for the year-over-year expense increase are due to the impact of last year's increased finding, development and acquisition costs and from the financial impact of the conversion of exchangeable shares pursuant to the application of EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts".

The provision for accretion of asset retirement obligations for the first nine months of 2007 was $0.98 million, a six percent increase compared to the first nine months of 2006. 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 recovery of future taxes for the third quarter of 2007 was $3.77 million when compared to a recovery of $3.35 million in the prior quarter and a provision of future tax expense of $1.17 million in the third quarter of 2006. The increase in future tax recovery, when compared to the 2007 second quarter recovery and the 2006 third quarter provision, is primarily related to the decrease in net earnings for the quarter as a result of previously mentioned items such as lower natural gas revenues as a result of declining natural gas prices received, unrealized risk management losses and increased production costs.

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. On June 12, 2007, the Federal Government enacted these tax proposals, which will result in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes to have a nil effective tax rate. Under the legislation, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be 31.5 percent. Until 2011, 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 until that time.

Based on its assets and liabilities as at June 30, 2007, the quarter in which the tax proposals were substantively enacted, the Trust had estimated the amount of its temporary differences, which were previously not subject to tax, and had estimated the periods in which these differences will reverse. The Trust estimated that $7.05 million net tax deductible temporary differences will reverse after January 1, 2011, which resulted in a reduction of the future tax liability of $2.22 million in the 2007 second quarter. The taxable temporary differences relate principally to the remaining tax pools attributed to the oil and gas properties being greater than their net book value. The year-over-year increase in the future tax recovery reflects these legislated adjustments.

The future income tax provision for the nine months ended September 30, 2007 also includes a recovery of $2.17 million relating to a reduction in future federal income tax rates substantively enacted during the second quarter of 2007 and includes the impact of certain tax balance adjustments.

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 $20.71 million on the Trust's consolidated balance sheet as at September 30, 2007. Consolidated net earnings have been reduced for net earnings attributable to the non-controlling interest of $0.86 million in the third quarter of 2007. 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 2007 resulted in an increase in property and equipment of $0.61 million, an increase in unitholders' equity of $0.61 million and an increase in future income tax liability of $0.20 million. Funds 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 $51.01 million, unitholders' equity and non-controlling interest by $52.51 million, future income tax liability by $16.96 million and an allocation of net earnings to exchangeable shareholders' of $18.46 million.

Funds flow from operations in the 2007 third quarter of $17.38 million was $3.18 million, or 15 percent lower than the preceding quarter and $2.49 million or 13 percent lower than the prior year third quarter. The decrease in funds flow from the preceding quarter was primarily due to decreased natural gas revenues (net of related royalties) as a result of sharply lower natural gas prices in the 2007 third quarter. Increased production costs and general and administrative costs were also contributing factors in lower funds flow when compared to the second quarter of 2007. Funds flow on a per diluted trust unit basis was $0.88 for the third quarter of 2007, a 16 percent decrease from the prior quarter and a 14 percent decrease from the 2006 third quarter.

Net earnings of $5.50 million for the 2007 third quarter were 53 percent below the $11.63 million of net earnings in the preceding quarter and 55 percent below the $12.31 million in the third quarter of 2006. The net earnings track the funds flow from operations for the respective periods modified by asset retirement expenditures and non-cash charges, which include depletion and depreciation, unrealized risk management gains/losses, future income taxes/recoveries and non-controlling interest. The primary reasons for the $6.81 million decrease in net earnings when comparing the third quarter of 2007 to the corresponding 2006 third quarter is due to previously mentioned items such as increased production costs ($1.58 million), increased depletion and depreciation expenses ($2.02 million) and unrealized risk management losses ($8.63 million) offset by future tax recoveries ($4.94 million) relating to these items.



Capital Expenditures

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ million) 2007 2006 2007 2006
----------------------------------------------------------------------------
Undeveloped land 1.59 0.78 4.93 3.68
Geological and geophysical (seismic) 1.01 1.02 3.46 2.87
Drilling and completion of wells 8.91 13.14 23.04 28.60
Well equipment and facilities 4.27 3.66 13.44 10.93
Administrative assets 0.63 0.04 0.93 0.14
----------------------------------------------------------------------------
Exploration and development 16.41 18.64 45.80 46.22
----------------------------------------------------------------------------
Property acquisitions 0.02 0.36 2.52 1.25
Property dispositions - (0.01) - (4.51)
----------------------------------------------------------------------------
Net property acquisitions/
(dispositions) 0.02 0.35 2.52 (3.26)
----------------------------------------------------------------------------
Total net capital expenditures 16.43 18.99 48.32 42.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Net capital expenditures of $48.32 million in the first nine months of 2007 were 12 percent higher than the first nine months of 2006, reflecting an active field program of 44 gross (37.9 net) wells, increased well equipping and facility costs and three property acquisition transactions. Net capital expenditures for the first nine months of 2007 were allocated to Alberta Plains - $22.44 million, West Central Alberta - $15.41 million and Williston Basin - $10.47 million. Drilling and completion expenses of $23.04 million were 19 percent lower than the prior year's first nine months amount of $28.60 million. During the third quarter of 2007, 20.9 net wells were drilled compared to 2.6 net wells in the second quarter of 2007 and 19.9 net wells in the third quarter of 2006. Funds flow from operations in the first nine months of 2007 was $59.74 million, proceeds from the exercise of trust unit rights of $2.13 million and the increase in bank debt of $14.06 million funded the capital program and the cash distributions to the unitholders. At September 30, 2007, 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 $54.61 million, as compared to $46.19 million at the end of the 2007 second quarter. Unutilized credit facilities of $75.90 million were available at September 30, 2007.

Recently, the combination of declining natural gas prices, the Alberta government's royalty announcement and last year's announced changes to the Canadian income trust tax rules after 2010 has partially restricted the oil and gas industry's ability to attract new capital from debt and equity markets. Zargon's historically conservative strategy of maintaining a relatively low cash distribution to funds flow ratio and conservative debt levels should enable Zargon to maintain its capital and distribution programs during this period of partially restricted access to debt and equity capital.



Cash Distributions Analysis

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ million) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flows from operating activities 24.64 24.67 62.08 65.46
Net earnings 5.50 12.31 22.35 37.45
Actual cash distributions paid or
payable relating to the period (9.19) (9.00) (27.49) (26.85)
----------------------------------------------------------------------------
Excess of cash flows from operating
activities over cash distributions
paid 15.45 15.67 34.59 38.61
Excess (shortfall) of net earnings over
cash distributions paid (3.69) 3.31 (5.14) 10.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Management monitors the Trust's distribution policy with respect to forecasted net cash flows, debt levels and capital expenditures. Zargon's cash distributions are discretionary to the extent that these distributions do not cause a breach of the financial covenants under Zargon's credit facilities and to the extent the Trust (non-consolidated) is not taxable. As a crude oil and natural gas Trust, Zargon's reserve base is depleted with production and Zargon therefore relies on ongoing exploration, development and acquisition activities to replace reserves and to offset production declines. The success of these exploration, development and acquisition capital programs, along with commodity price fluctuations are the main factors influencing the sustainability of the Trust's distributions. Since Zargon's July 2004 Trust conversion, it has been successful in maintaining production per Trust unit and reserves per Trust unit at relatively stable rates, through its ongoing exploration, development and acquisition capital programs.

For the three and nine months ended September 30, 2007, cash flows from operating activities (after changes in non-cash working capital) of $24.64 million and $62.08 million, respectively, exceeded cash distributions of $9.19 million and $27.49 million, respectively. This was consistent with the three and nine months ended September 30, 2006 in which cash flows from operating activities (after changes in non-cash working capital) of $24.67 million and $65.46 million, respectively, exceeded cash distributions of $9.00 million and $26.85 million, respectively.

For the three and nine months ended September 30, 2007, cash distributions of $9.19 million and $27.49 million, exceeded net earnings of $5.50 million and $22.35 million, respectively. For the three and nine months ended September 30, 2006, net earnings of $12.31 million and $37.45 million exceeded cash distributions of $9.00 million and $26.85 million, respectively. Net earnings include significant non-cash charges, which were $12.26 million for the 2007 third quarter and $38.23 million for the nine months ended September 30, 2007, that do not impact cash flow. Net earnings also include fluctuations in future income taxes due to changes in tax rates and tax rules. In addition, other non-cash charges such as depletion and depreciation are not a good proxy for the cost of maintaining Zargon's productive capacity given the natural declines associated with crude oil and natural gas assets. In these instances, where distributions exceed net earnings, a portion of the cash distribution paid to unitholders may represent an economic return of the unitholders' capital.

For the 2007 third quarter, cash distributions and net capital expenditures totalled $25.62 million, which was slightly higher than the cash flows from operating activities (after changes in non-cash working capital) of $24.64 million. For the nine months ended September 30, 2007, cash distributions and net capital expenditures totalled $75.81 million, which was $13.73 million higher than the cash flows from operating activities (after changes in non-cash working capital) of $62.08 million. For the three and nine months ended September 30, 2006, cash distributions and net capital expenditures exceeded the cash flows from operating activities (after changes in non-cash working capital) by $3.32 million and $4.35 million, respectively. Zargon relies on access to debt and capital markets to the extent cash distributions and net capital expenditures exceed cash flows from operating activities (after changes in non-cash working capital). Over the long term, Zargon expects to fund cash distributions and capital expenditures with its cash flows from operating activities, however, it will continue to fund acquisitions and growth through additional debt and equity issuances. In the crude oil and natural gas industry, because of the nature of reserve reporting, the natural reservoir declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Therefore, maintenance capital is not disclosed separately from development capital spending.

During the first nine months of 2007, Zargon has maintained a monthly distribution of $0.18 per trust unit, and plans to maintain this level of distribution for the remainder of this year and into 2008.

At November 12, 2007, Zargon Energy Trust had 17.040 million trust units and 2.099 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective November 12, 2007 exchange ratio of 1.27739, there would be 19.721 million trust units outstanding. Pursuant to the trust unit rights incentive plan there are currently an additional 1.341 million trust unit incentive rights issued and outstanding.



Capital Sources and Uses

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ million) 2007 2006 2007 2006
----------------------------------------------------------------------------
Funds flow from operations (1) 17.38 19.87 59.74 64.06
Changes in non-cash working capital 10.63 5.23 (0.12) (8.23)
Change in bank debt (2.64) 2.58 14.06 10.37
Cash distributions to unitholders (9.19) (9.00) (27.49) (26.85)
Issuance of trust units 0.25 0.31 2.13 3.61
----------------------------------------------------------------------------
Total capital sources 16.43 18.99 48.32 42.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughout this report, funds flow from operations is now calculated
inclusive of asset retirement expenditures. All prior period
calculations have been restated to reflect this change.


CHANGE IN ACCOUNTING POLICIES

As of January 1, 2007, the Trust adopted CICA Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation" and Section 3865 "Hedges". Under the new standards, a new statement, the Consolidated Statement of Comprehensive Income, has been introduced that provides for certain gains and losses arising from changes in fair value, to be temporarily recorded outside the income statements. In addition, all financial instruments, including derivatives, are to be included in the Trust's Consolidated Balance Sheets and measured, in most cases, at fair values, and requirements for hedge accounting have been further clarified. There is no material impact to the Trust's consolidated financial statements as a result of implementing the new standards. As required by the new standards, prior periods have not been restated.

As of January 1, 2007, the Trust adopted revised CICA Section 1506 "Accounting Changes", which provides expanded disclosures for changes in accounting policies, accounting estimates and correction of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impractical to determine. Also, voluntary changes in accounting policy are made only when required by a primary source of GAAP or when the change results in more relevant and reliable information. There is no material impact to the Trust's consolidated financial statements as a result of implementing this new standard.

For a detailed discussion about the accounting policies adopted, please refer to note 2 of the consolidated interim financial statements for the three and nine month periods ended September 30, 2007.

The Trust has assessed new and revised accounting pronouncements that have been issued that are not yet effective and have determined that the following may have a significant impact on the Trust:

On December 1, 2006, the CICA issued three new accounting standards: CICA Section 1535 "Capital Disclosures", CICA Section 3862 "Financial Instruments - Disclosures" and CICA Section 3863 "Financial Instruments - Presentation". These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace CICA Section 3861 "Financial Instruments - Disclosure and Presentation", revising and enhancing its disclosure requirements, and carrying forward its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. The Trust is currently assessing the impact of these new standards on its consolidated financial statements.

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards ("IFRS") by the end of 2011. The Trust continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.

MANAGEMENT AND FINANCIAL REPORTING SYSTEMS

Zargon is required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to as Canadian SOX ("C-Sox"). The 2007 certificate requires that the Trust disclose in the interim MD&A any changes in the Trust's internal controls over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting. The Trust confirms that no such changes were made to the internal controls over financial reporting during the third quarter of 2007.
Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control systems are met.

BUSINESS RISKS

ENVIRONMENTAL REGULATION AND RISK

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. In 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases.

Recently the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as "ecoACTION", which includes the Regulatory Framework for Air Emissions and the Alberta Government has also introduced legislation regarding greenhouse gas emissions.

On March 8, 2007, the Alberta government introduced legislation to reduce greenhouse gas emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases per year must reduce their emissions intensity by 12 per cent over the average emissions levels of 2003, 2004 and 2005; if they are not able to do so, these facilities will be required to pay $15 per tonne for every tonne above the 12 per cent target, beginning on July 1, 2007. At this time, the Trust has determined that there is currently no impact of this legislation on Zargon's existing facilities ownership.

Although Zargon is not a large emitter of greenhouse gases, the Trust continues to monitor developments in this area. Although environmental legislation is evolving in a manner that could result in stricter standards and enforcement, larger fines and liability, and potentially increased capital expenditures and operating costs, at this time it is not possible to predict the impact of these requirements on the Trust and its operations and financial condition.

ALBERTA ROYALTY AND TAX REGIME

On February 16, 2007, the Alberta Government announced that a review of the Province's royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil and gas resources, including oil sands, conventional oil and gas and coalbed methane, will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. On September 18, 2007 the Royalty Review Panel delivered its final report and recommendations to the Government of Alberta. The report titled "Our Fair Share" recommended significant increases to royalties levied on natural gas, conventional oil and oil sands produced in Alberta. On October 25, 2007, the Alberta Government released details of its planned implementation of the final Royalty Review Panel report, titled "The New Royalty Framework" ("NRF"). Zargon has reviewed the modifications proposed by the Government of Alberta to its royalty program, which is scheduled to take effect on January 1, 2009. While more detailed analysis is ongoing, the following observations have been noted:

- Currently 34 percent of Zargon's production is from properties located outside Alberta and therefore is not affected by the NRF.

- Royalties determined under the NRF will be determined based on commodity prices, well productivity and depth of wells. A significant portion of Zargon's wells are lower productivity wells, that on a relative basis, are less impacted by the NRF than higher productivity wells.

- Zargon has recalculated its January 1, 2007 reserves using Zargon's independent engineering firm McDaniel & Associates Consultants Ltd. using the January 1, 2007 escalated price forecast (present value before tax at 10 percent) under both the existing and NRF proposed royalty rates. The impact of the proposed change in royalty rates on the net present value of Zargon's proved and probable reserves, was slightly negative but this negative adjustment amounted to less than one percent of Zargon's net asset value.

- The NRF will have a more significant impact on the economics of Zargon's ongoing natural gas exploration programs which target moderate rate natural gas wells in our West Central Alberta and Alberta Plains core areas. Consequently, commencing in 2009, the project economics for Zargon's exploration programs will be directly impacted at most natural gas prices by the increased royalties outlined in the Alberta Government's NRF report.

OUTLOOK

With a strong balance sheet, 387 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 2008, Zargon is forecasting an average production rate of 8,800 barrels of oil equivalent per day which is premised on a 2008 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 issuances.



SUMMARY OF QUARTERLY RESULTS

2007
----------------------------------------------------------------------------
Q1 Q2 Q3
----------------------------------------------------------------------------
Petroleum and natural gas revenue ($ million) 38.53 39.21 36.64
Net earnings ($ million) 5.22 11.63 5.50
Net earnings per diluted unit ($) 0.31 0.68 0.32
Funds flow from operations ($ million) (1) 21.80 20.56 17.38
Funds flow from operations per diluted unit
($) (1) 1.12 1.05 0.88
Cash distributions ($ million) 9.12 9.17 9.19
Cash distributions declared per trust unit ($) 0.54 0.54 0.54
Net capital expenditures ($ million) 20.93 10.97 16.43
Total assets ($ million) 324.31 324.96 327.54
Bank debt ($ million) 37.68 46.74 44.10
Average daily production (boe) 8,483 8,465 8,501
Average realized commodity field price before
the impact of financial risk management
contracts ($/boe) 50.47 50.91 46.84
Funds flow netback ($/boe) (1) 28.55 26.69 22.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughout this report, funds flow from operations, funds flow from
operations per diluted unit and funds flow netbacks are now calculated
inclusive of asset retirement expenditures. All prior period
calculations have been restated to reflect this change.


2006
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 40.94 38.66 37.93 36.50
Net earnings ($ million) 11.92 13.22 12.31 7.05
Net earnings per diluted unit ($) 0.72 0.79 0.73 0.43
Funds flow from operations
($ million) (1) 22.12 22.06 19.87 18.84
Funds flow from operations per diluted
unit ($) (1) 1.15 1.14 1.02 0.97
Cash distributions ($ million) 8.89 8.96 9.00 9.05
Cash distributions declared per trust
unit ($) 0.54 0.54 0.54 0.54
Net capital expenditures ($ million) 15.19 8.78 18.99 20.41
Total assets ($ million) 282.35 283.86 294.14 310.57
Bank debt ($ million) 26.64 18.14 20.71 30.04
Average daily production (boe) 8,812 8,322 8,194 8,366
Average realized commodity field price
before the impact of financial risk
management contracts ($/boe) 51.63 51.06 50.32 47.42
Funds flow netback ($/boe) (1) 27.89 29.13 26.36 24.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughout this report, funds flow from operations, funds flow from
operations per diluted unit and funds flow netbacks are now calculated
inclusive of asset retirement expenditures. All prior period
calculations have been restated to reflect this change.


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 ($) 0.32 0.41 0.39 1.06
Funds flow from operations
($ million) (1) 17.42 18.85 21.70 26.39
Funds flow from operations per diluted
unit ($) (1) 0.93 1.00 1.14 1.38
Cash distributions ($ million) 6.60 6.73 7.45 16.66
Cash distributions declared per trust
unit ($) 0.42 0.42 0.46 1.02
Net capital expenditures
($ million) (2) 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 field price
before the impact of financial risk
management contracts ($/boe) 44.90 47.85 57.45 63.15
Funds flow netback ($/boe) (1) 22.92 25.15 29.36 33.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughout this report, funds flow from operations, funds flow from
operations per diluted unit and funds flow netbacks are now calculated
inclusive of asset retirement expenditures. All prior period
calculations have been restated to reflect this change.
(2) Amounts include capital expenditures acquired for cash and equity
issuances.


ADDITIONAL INFORMATION

Additional information regarding the Trust and its business operations, including the Trust's Annual Information Form for December 31, 2006, is available on the Trust's SEDAR profile at www.sedar.com.



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

Calgary, Alberta
November 12, 2007


CONSOLIDATED BALANCE SHEETS
(unaudited) September 30, December 31,
($ thousand) 2007 2006
----------------------------------------------------------------------------
ASSETS (note 5)
Current
Accounts receivable 17,182 18,362
Prepaid expenses and deposits (note 2) 2,838 3,281
Unrealized risk management asset (note 12) 2,759 5,817
----------------------------------------------------------------------------
22,779 27,460
Property and equipment, net (note 4) 304,757 283,108
----------------------------------------------------------------------------
327,536 310,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities 27,469 28,410
Cash distributions payable (note 13) 3,067 3,022
Unrealized risk management liability (note 12) 3,940 20
----------------------------------------------------------------------------
34,476 31,452
Long term debt (note 5) 44,097 30,037
Asset retirement obligations (note 6) 18,054 17,307
Future income taxes (note 8) 43,098 47,891
----------------------------------------------------------------------------
139,725 126,687
----------------------------------------------------------------------------
NON-CONTROLLING INTEREST
Exchangeable shares (note 3) 20,706 18,319
----------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (note 7) 88,870 82,868
Contributed surplus (note 7) 3,151 2,475
Accumulated earnings 186,618 164,267
Accumulated cash distributions (note 13) (111,534) (84,048)
----------------------------------------------------------------------------
167,105 165,562
----------------------------------------------------------------------------
327,536 310,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.


CONSOLIDATED STATEMENTS OF EARNINGS
AND COMPREHENSIVE INCOME AND
ACCUMULATED EARNINGS


Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
----------------------------------------------------------------------------
($ thousand, except per
unit amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
REVENUE
Petroleum and natural gas revenue 36,637 37,934 114,382 117,541
Unrealized risk management
gain/(loss) (note 12) (2,358) 6,267 (6,978) 8,749
Realized risk management gain/(loss) 1,105 338 4,551 (1,731)
Royalties (7,630) (8,478) (24,490) (25,588)
----------------------------------------------------------------------------
27,754 36,061 87,465 98,971
----------------------------------------------------------------------------
EXPENSES
Production 8,561 6,980 24,122 18,779
General and administrative 2,117 1,957 5,583 4,924
Unit-based compensation (note 7) 416 549 1,142 1,234
Interest and financing charges 848 374 2,147 1,060
Unrealized foreign exchange gain (115) - (693) (422)
Accretion of asset retirement
obligations (note 6) 330 308 982 930
Depletion and depreciation 12,184 10,161 35,489 30,275
----------------------------------------------------------------------------
24,341 20,329 68,772 56,780
----------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES 3,413 15,732 18,693 42,191
----------------------------------------------------------------------------
INCOME TAXES (note 8)

Current 828 446 2,006 944
Future (recovery) (3,770) 1,172 (9,124) (2,037)
----------------------------------------------------------------------------
(2,942) 1,618 (7,118) (1,093)
----------------------------------------------------------------------------
EARNINGS FOR THE PERIOD BEFORE
NON-CONTROLLING INTEREST 6,355 14,114 25,811 43,284
Non-controlling interest -
exchangeable shares (note 3) (859) (1,804) (3,460) (5,838)
----------------------------------------------------------------------------
NET EARNINGS AND COMPREHENSIVE
INCOME FOR THE PERIOD 5,496 12,310 22,351 37,446
ACCUMULATED EARNINGS, BEGINNING
OF PERIOD 181,122 144,904 164,267 119,768
----------------------------------------------------------------------------
ACCUMULATED EARNINGS, END OF
PERIOD 186,618 157,214 186,618 157,214
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET EARNINGS PER UNIT (note 9)

Basic 0.32 0.74 1.32 2.26
Diluted 0.32 0.73 1.32 2.25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings and comprehensive
income for the period 5,496 12,310 22,351 37,446
Add (deduct) non-cash items:
Non-controlling interest -
exchangeable shares 859 1,804 3,460 5,838
Unrealized risk management
(gain)/loss 2,358 (6,267) 6,978 (8,749)
Depletion and depreciation 12,184 10,161 35,489 30,275
Accretion of asset retirement
obligations 330 308 982 930
Unit-based compensation 416 549 1,142 1,234
Unrealized foreign exchange gain (115) - (693) (422)
Future income taxes (recovery) (3,770) 1,172 (9,124) (2,037)
Asset retirement expenditures (379) (164) (848) (458)
----------------------------------------------------------------------------
17,379 19,873 59,737 64,057
Changes in non-cash working capital 7,256 4,795 2,340 1,399
----------------------------------------------------------------------------
24,635 24,668 62,077 65,456
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Advances (repayment) of bank debt (2,642) 2,576 14,060 10,373
Cash distributions to unitholders (9,192) (9,003) (27,486) (26,848)
Exercise of unit rights 251 313 2,127 3,607
Changes in non-cash financing
working capital 6 5 45 (8,118)
----------------------------------------------------------------------------
(11,577) (6,109) (11,254) (20,986)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property and
equipment (16,429) (18,995) (48,319) (47,466)
Proceeds on disposal of property
and equipment - 10 - 4,510
Changes in non-cash investing
working capital 3,371 426 (2,504) (1,514)
----------------------------------------------------------------------------
(13,058) (18,559) (50,823) (44,470)
----------------------------------------------------------------------------
CHANGE IN CASH, AND CASH END
OF PERIOD - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the three and nine months ended September 30, 2007 and 2006 (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, 2006, except as noted below. The disclosures provided below are incremental to those included with the annual audited consolidated financial statements. These interim unaudited consolidated financial statements do not include all disclosures required in the annual consolidated financial statements and 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, 2006.

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. CHANGES IN ACCOUNTING POLICIES

On January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation" and Section 3865 "Hedges". As required by the new standards, prior periods have not been restated.

The adoption of these standards has had no material impact on the Trust's net earnings or cash flows. The other effects of the implementation of the new standards are discussed below.

Comprehensive Income

The new standards introduce comprehensive income, which consists of net earnings and other comprehensive income ("OCI"). Upon adoption of Section 1530, the Trust revised its "Consolidated Statements of Earnings and Accumulated Earnings" to include the newly required statement of comprehensive income by creating a combined statement.

CICA Section 1530 introduces a new requirement to temporarily present certain gains and losses from changes in fair value outside net earnings. It includes unrealized gains and losses such as: changes in the currency translation adjustment relating to self-sustaining foreign operations; unrealized gains or losses on available-for-sale investments; and the effective portion of gains or losses on derivatives designated as cash flow hedges.

The adoption of comprehensive income has been made in accordance with the applicable transitional provisions and no amounts have been reclassified to accumulated other comprehensive income. Currently, Zargon has no OCI.

Financial Instruments

The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives. All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as "held-for-trading", "available-for-sale", "held-to-maturity", "loans and receivables", or "other financial liabilities" as defined by the standard.

Financial assets and financial liabilities "held-for-trading" are measured at fair value with changes in those fair values recognized in net earnings. Financial assets "available-for-sale" are measured at fair value, with changes in those fair values recognized in OCI until the asset is removed from the balance sheet. Financial assets "held-to-maturity", "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest method of amortization. The methods used by the Trust in determining fair value of financial instruments are unchanged as a result of implementing the new standard.

Accounts receivable are designated as "loans and receivables". Accounts payable and accrued liabilities, cash distributions payable and long term debt are designated as "other liabilities".

The adoption of the financial instruments standard has been made in accordance with its transitional provisions. Accordingly, at January 1, 2007, $0.17 million of prepaid expenses and deposits were expensed to reflect the adopted policy of expensing long term debt transaction costs, premiums and discounts related to long term debt. Previously, the Trust deferred these costs within prepaid expenses and deposits and amortized them straight-line over the life of the related long term debt. The adoption of the expensing method had no effect on opening accumulated earnings.

Risk management assets and liabilities are derivative financial instruments classified as "held-for-trading". Additional information on the Trust's accounting treatment of derivative financial instruments is contained in note 2 of the Trust's annual audited consolidated financial statements for the year ended December 31, 2006.

CICA Section 3865 provides alternative treatments to Section 3855 for entities that choose to designate qualifying transactions as hedges for accounting purposes. It replaces and expands on Accounting Guideline 13 "Hedging Relationships" and the hedging guidance in Section 1650 "Foreign Currency Translation" by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. As Zargon currently uses mark-to-market accounting for its derivative financial instruments there is no material impact to the Trust's consolidated financial statements as a result of implementing this new standard.

As of January 1, 2007, the Trust adopted revised CICA Section 1506 "Accounting Changes", which provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impractical to determine. As well, voluntary changes in accounting policy are made only when required by a primary source of GAAP or when the change results in more relevant and reliable information. There is no material impact to the Trust's consolidated financial statements as a result of implementing this new standard.

The Trust has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact on the Trust:

As of January 1, 2008, Zargon will be required to adopt two new CICA standards, Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation", which will replace Section 3861 "Financial Instruments - Disclosure and Presentation". The new disclosure standard increases the emphasis on the risks associated with both recognized and unrecognized financial instruments and how those risks are managed. The new presentation standard carries forward the former presentation requirements. The new financial instruments presentation and disclosure requirements were issued in December 2006 and the Trust is assessing the impact on its consolidated financial statements.

As of January 1, 2008, Zargon will be required to adopt the new CICA Section 1535 "Capital Disclosures", which will require companies to disclose their objectives, policies and processes for managing capital. In addition, disclosures are to include whether companies have complied with externally imposed capital requirements. The new capital disclosure requirements were issued in December 2006 and the Trust is assessing the impact on its consolidated financial statements.

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards ("IFRS") by the end of 2011. The Trust continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.

3. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

Zargon Oil & Gas Ltd. is authorized to issue an unlimited number of 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, 2007, a total of 0.11 million exchangeable shares were converted into 0.13 million trust units based on the exchange ratio at the time of conversion. At September 30, 2007, the exchange ratio was 1.26897 trust units per exchangeable share.



Non-Controlling Interest - Exchangeable Shares

Nine Months Ended September 30, 2007
----------------------------------------------------------------------------
(thousand, except exchange ratio) Number of Shares Amount ($)
----------------------------------------------------------------------------
Balance, beginning of period 2,207 18,319
Earnings attributable to
non-controlling interest - 3,460
Exchanged for trust units at book
value and including earnings
attributed since beginning of period (108) (1,073)
----------------------------------------------------------------------------
Balance, end of period 2,099 20,706
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, end of period 1.26897
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 sheets 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 sheets 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 statements 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 82,868 18,319 101,187
Issued on redemption of exchangeable
shares at book value 262 (262) -
Effect of EIC-151 3,147 2,649 5,796
Unit-based compensation recognized on
exercise of unit rights 466 - 466
Unit rights exercised for cash 2,127 - 2,127
----------------------------------------------------------------------------
Balance at September 30, 2007 88,870 20,706 109,576
----------------------------------------------------------------------------
----------------------------------------------------------------------------

4. PROPERTY AND EQUIPMENT

September 30, 2007
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousand) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties and
other equipment (1) 516,844 212,087 304,757
----------------------------------------------------------------------------
----------------------------------------------------------------------------

December 31, 2006
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousand) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties and
other equipment (1) 459,706 176,598 283,108
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As a result of shareholders redeeming exchangeable shares, property and
equipment has cumulatively increased $51.01 million, $8.07 million
relating to the first nine months of 2007, $6.73 million relating to
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 of $15.16 million, $4.60 million relating to
the first nine months of 2007, $5.48 million relating to 2006 and $5.08
million relating to 2005.


5. LONG TERM DEBT

On July 30, 2007, Zargon amended and renewed its syndicated committed credit facilities, the result of which is an increase in the available facilities and borrowing base to $120 million from the previous amount of $100 million. 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 29, 2008. 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.



6. ASSET RETIREMENT OBLIGATIONS

The following table reconciles Zargon's asset retirement obligations:

Nine Months Ended September 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period 17,307 15,859
Net liabilities incurred 751 294
Liabilities settled (848) (458)
Accretion expense 982 930
Foreign exchange (138) (40)
----------------------------------------------------------------------------
Balance, end of period 18,054 16,585
----------------------------------------------------------------------------
----------------------------------------------------------------------------

7. UNITHOLDERS' EQUITY

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

Trust Units

Nine Months Ended September 30, 2007
----------------------------------------------------------------------------
Number of Amount
(thousand) Units ($)
----------------------------------------------------------------------------
Balance, beginning of period 16,789 82,868
Unit rights exercised for cash 120 2,127
Unit-based compensation recognized on
exercise of unit rights - 466
Issued on conversion of exchangeable shares 131 3,409
----------------------------------------------------------------------------
Balance, end of period 17,040 88,870
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The proforma total units outstanding at September 30, 2007, 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 3) is 19.704 million units.



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

Contributed Surplus

($ thousand) Nine Months Ended September 30, 2007
----------------------------------------------------------------------------
Balance, beginning of period 2,475
Unit-based compensation expense 1,142
Unit-based compensation recognized on
exercise of unit rights (466)
----------------------------------------------------------------------------
Balance, end of period 3,151
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 other service providers. The Trust is authorized to issue up to 2.36 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 the total outstanding units including units issuable upon exchange of exchangeable shares of Zargon and other fully paid securities of Zargon entities exchangeable into units, which are the economic equivalent of units including full voting rights. 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 Plan. 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 2007 include a volatility factor of expected market price of 26.3 percent, a risk-free interest rate of 4.2 percent, a dividend yield of 8.2 percent and an expected life of the unit rights of four years. These unit rights, together with the continued vesting of unit rights granted in prior years resulted in unit-based compensation expense for the nine months ended September 30, 2007 of $1.14 million (2006 - $1.23 million).

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, 2007
----------------------------------------------------------------------------
Number of Weighted Average
Unit Rights Exercise Price
(thousand) ($/unit right)
----------------------------------------------------------------------------
Outstanding at beginning of period 1,208 26.32
Unit rights granted 375 26.39
Unit rights exercised (120) 17.75
Unit rights cancelled (122) 28.64
--------------------------------------------------------
Outstanding at end of period 1,341 26.80
--------------------------------------------------------
--------------------------------------------------------
Unit rights exercisable at period end 559 25.50
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. INCOME TAXES

The future income tax provision for the nine months ended September 30, 2007 includes a recovery of $2.17 million relating to a reduction in future federal income tax rates substantively enacted during the second quarter of 2007 and includes the impact of certain tax balance adjustments.

In June 2007, the Government of Canada enacted new legislation imposing additional income taxes upon certain publicly traded income trusts, including Zargon Energy Trust, effective January 1, 2011. Prior to September 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes to have a nil effective tax rate. Under the legislation, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be 31.5 percent. Temporary differences reversing before 2011 will still give rise to nil future income taxes.

Based on its assets and liabilities as at June 30, 2007, the quarter in which the tax proposals were substantively enacted, the Trust had estimated the amount of its temporary differences, which were previously not subject to tax and had estimated the periods in which these differences will reverse. The Trust estimated that $7.05 million net tax deductible temporary differences will reverse after January 1, 2011, which resulted in a reduction of the future tax liability of $2.22 million in the 2007 second quarter. The taxable temporary differences relate principally to the remaining tax pools attributed to the oil and gas properties being greater than their net book value. The year-over-year increase in the future tax recovery reflects these legislated adjustments.

While the Trust believes it will be subject to additional tax under the new legislation, the estimated effective rate on temporary difference reversals after 2011 may change in future periods. As the legislation is new, future technical interpretations could occur and could materially affect management's estimate of the future tax liability.

The amount and timing of reversals of temporary differences will also depend on the Trust's future operating results, acquisitions and dispositions of assets and liabilities, and distribution policy. A significant change in any of the preceding assumptions could materially affect the Trust's estimate of the future tax liability.

9. 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) 2007 2006 2007 2006
----------------------------------------------------------------------------
Basic 17,014 16,666 16,952 16,551
Diluted 19,731 19,424 19,545 19,236
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. 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) 2007 2006 2007 2006
----------------------------------------------------------------------------
Petroleum and Natural Gas Revenue
Canada 31,015 31,093 98,202 98,264
United States 5,622 6,841 16,180 19,277
----------------------------------------------------------------------------
Total 36,637 37,934 114,382 117,541
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Capital Expenditures
Canada 16,326 17,875 48,082 38,862
United States 103 1,110 237 4,094
----------------------------------------------------------------------------
Total 16,429 18,985 48,319 42,956
----------------------------------------------------------------------------
----------------------------------------------------------------------------


September 30, December 31,
($ thousand) 2007 2006
----------------------------------------------------------------------------
Property and Equipment, net
Canada 271,298 248,440
United States 33,459 34,668
----------------------------------------------------------------------------
Total 304,757 283,108
----------------------------------------------------------------------------
----------------------------------------------------------------------------

11. SUPPLEMENTAL CASH FLOW INFORMATION

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash interest paid 730 360 2,134 1,063
Cash taxes (refunded)/paid 684 (175) 2,146 551
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. 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 the following outstanding financial contracts:



Financial Contracts at September 30, 2007:

Fair Market
Weighted Value
Average Gain/(Loss)
Rate Price Range of Terms ($ thousand)
----------------------------------------------------------------------------
Oil swaps 1,000 bbl/d $72.40 US/bbl Oct. 1/07-Dec. 31/07 (718)
300 bbl/d $66.70 US/bbl Jan. 1/08-Mar. 31/08 (312)
300 bbl/d $61.72 US/bbl Jan. 1/08-Jun. 30/08 (858)
600 bbl/d $71.54 US/bbl Jan. 1/08-Dec. 31/08 (1,070)
300 bbl/d $68.29 US/bbl Apr. 1/08-Jun. 30/08 (233)
600 bbl/d $68.94 US/bbl Jul. 1/08-Dec. 31/08 (703)
500 bbl/d $72.74 US/bbl Jan. 1/09-Mar. 31/09 (36)
Natural gas
swaps 5,000 gj/d $8.36/gj Oct. 1/07-Oct. 31/07 523
6,000 gj/d $8.41/gj Nov. 1/07-Mar. 31/08 1,926
1,000 gj/d $7.84/gj Apr. 1/08-Oct. 31/08 300
----------------------------------------------------------------------------
Net Fair Market Value, Financial Contracts (1,181)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Oil swaps are settled against the NYMEX pricing index, whereas natural gas swaps 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 loss for the first nine months of 2007 was $6.98 million and the unrealized gain for the first nine months of 2006 was $8.75 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. The Trust has the following outstanding physical contracts:



Physical Contracts at September 30, 2007:

Fair Market
Weighted Value
Average Gain
Rate Price Range of Terms ($ thousand)
----------------------------------------------------------------------------
Natural gas
fixed price 1,000 gj/d $7.88/gj Oct. 1/07-Oct. 31/07 90
1,000 gj/d $7.95/gj Apr. 1/08-Oct. 31/08 323
----------------------------------------------------------------------------
Total Fair Market Value, Physical Contracts 413
----------------------------------------------------------------------------
----------------------------------------------------------------------------


13. CASH DISTRIBUTIONS

During the nine month period, the Trust declared cash distributions to the unitholders in the aggregate amount of $27.49 million (2006 - $26.85 million) in accordance with the following schedule:



2007 Distributions Record Date Distribution Date Per Trust Unit
----------------------------------------------------------------------------
January January 31, 2007 February 15, 2007 $0.18
February February 28, 2007 March 15, 2007 $0.18
March March 31, 2007 April 16, 2007 $0.18
April April 30, 2007 May 15, 2007 $0.18
May May 31, 2007 June 15, 2007 $0.18
June June 30, 2007 July 16, 2007 $0.18
July July 31, 2007 August 15, 2007 $0.18
August August 31, 2007 September 17, 2007 $0.18
September September 30, 2007 October 15, 2007 $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 STOCK EXCHANGE LISTING

Craig H. Hansen Toronto Stock Exchange
Calgary, Alberta
Zargon Energy Trust
K. James Harrison Trust Units
Chairman of the Board Trading Symbol: ZAR.UN
Oakville, Ontario
Zargon Oil & Gas Ltd.
Kyle D. Kitagawa (1) (2) Exchangeable Shares
Calgary, Alberta Trading Symbol: ZOG.B

James J. Lawson (3) (4) TRANSFER AGENT
Oakville, Ontario
Valiant Trust Company
John O. McCutcheon (3) 310, 606 - 4(th) Street S.W.
Vancouver, British Columbia Calgary, Alberta T2P 1T1

Margaret A. McKenzie (1) (3) HEAD OFFICE
Calgary, Alberta
700, 333 - 5(th) Avenue S.W.
Jim Peplinski (2) (4) Calgary, Alberta T2P 3B6
Calgary, Alberta Telephone: (403) 264-9992
Fax: (403) 265-3026
J. Graham Weir (1) (2) Email: zargon@zargon.ca
Calgary, Alberta
WEBSITE
Grant A. Zawalsky (3) (4)
Calgary, Alberta www.zargon.ca

1 Audit Committee
2 Reserves Committee
3 Governance and Nominating Committee
4 Compensation Committee

OFFICERS

Craig H. Hansen
President and Chief Executive Officer

Brent C. Heagy
Executive Vice President and
Chief Financial Officer

Daniel A. Roulston
Executive Vice President, Operations

Henry J. Baird
Vice President, Exploitation

Jason B. Dranchuk
Controller and Treasurer

Tracy L. Howard
Corporate Secretary

Brian G. Kergan
Vice President, Corporate Development and Reserves

Mark I. Lake
Vice President, Exploration

Lorne D. Schwetz
Vice President, Land


Contact Information

  • Zargon Energy Trust
    C.H. Hansen
    President and Chief Executive Officer
    (403) 264-9992
    or
    B.C. Heagy
    Executive Vice President and Chief Financial Officer
    (403) 264-9992
    Email: zargon@zargon.ca
    Website: www.zargon.ca