ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

March 11, 2008 17:02 ET

Zargon Energy Trust Announces 2007 Fourth Quarter and Full Year Financial Results

CALGARY, ALBERTA--(Marketwire - March 11, 2008) - Zargon Energy Trust ("Zargon" or the "Trust") (TSX:ZAR.UN) (TSX:ZOG.B) today announced its financial results for the fourth quarter and year ended December 31, 2007. This announcement augments Zargon's February 28, 2008 press release that provided an operational update and released the 2007 year end reserve information.

Highlights from the fourth quarter and year ended December 31, 2007:

- Fourth quarter 2007 revenue of $41.13 million and funds flow from operations of $20.10 million were 12 percent and 16 percent, respectively, higher than the preceding 2007 third quarter levels. Net earnings for the fourth quarter were $2.20 million, a 60 percent decrease from the third quarter of 2007. Revenue for the full year increased by one percent to $155.51 million, funds flow from operations decreased four percent to $79.84 million and net earnings decreased 45 percent to $24.55 million.

- Production volumes in 2007 remained relatively stable with a year-over-year increase of two percent to 8,560 barrels of oil equivalent per day compared to 2006. Fourth quarter production of 30.74 million cubic feet per day of natural gas and 3,666 barrels per day of oil and liquids provided Zargon quarterly production volumes of 8,790 barrels of oil equivalent per day, three percent higher than third quarter volumes.

- Net capital expenditures in 2007 were $66.67 million comprised of $1.86 million of net property acquisitions, $63.54 million for exploration and development programs and $1.27 million for administrative assets. For the year, Zargon drilled 46.9 net wells with a 94 percent success ratio, yielding 32.7 net natural gas wells, 11.6 net oil wells and 2.6 net dry holes.

- Cash distributions in 2007 of $2.16 per trust unit were declared and represented 53 percent of the year's $4.08 per diluted trust unit of funds flow from operations. Including the effect of the exchangeable shares, which do not receive distributions, the 2007 cash distributions totalled $36.70 million or 46 percent of the year's $79.84 million of funds flow from operations. Fourth quarter cash distributions totalled $0.54 per trust unit.

- Year end debt net of working capital (excluding unrealized risk management assets and liabilities) of $62.30 million is slightly less than 0.8 times the annualized fourth quarter funds flow from operations.



Three Months Ended December 31, Year Ended December 31,
Percent Percent
2007 2006 Change 2007 2006 Change
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FINANCIAL (unaudited) (unaudited)
HIGHLIGHTS
Income and
Investments
($ million)
Petroleum and
natural gas
revenue 41.13 36.50 13 155.51 154.04 1
Funds flow from
operations 20.10 18.84 7 79.84 82.89 (4)
Cash distributions 9.21 9.05 2 36.70 35.90 2
Net earnings 2.20 7.05 (69) 24.55 44.50 (45)
Net capital
expenditures 18.35 20.41 (10) 66.67 63.37 5

Per Unit, Diluted
Funds flow from
operations
($/unit) 1.02 0.97 5 4.08 4.31 (5)
Net earnings
($/unit) 0.13 0.43 (70) 1.45 2.68 (46)

Cash Distributions
($/trust unit) 0.54 0.54 - 2.16 2.16 -

Balance Sheet at
Year End
($ million)
Property and
equipment, net 313.95 283.11 11
Bank debt 56.87 30.04 89
Unitholders'
equity 161.48 165.56 (2)

Total Units
Outstanding at
Year End
(million) 19.76 19.42 2

OPERATING
HIGHLIGHTS
Average Daily
Production
Oil and liquids
(bbl/d) 3,666 3,789 (3) 3,675 3,805 (3)
Natural gas
(mmcf/d) 30.74 27.46 12 29.31 27.70 6
Equivalent
(boe/d) 8,790 8,366 5 8,560 8,422 2
Equivalent per
million trust
units (boe/d) 445 431 3 436 437 -

Average Selling
Price (before the
impact of financial
risk management
contracts)
Oil and liquids
($/bbl) 71.29 54.69 30 64.71 61.25 6
Natural gas
($/mcf) 5.95 6.90 (14) 6.40 6.82 (6)

Wells Drilled, Net 9.0 33.4 (73) 46.9 76.2 (38)

Undeveloped Land
at Year End
(thousand net
acres) 362 381 (5)
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Notes:
Throughout this press release, 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 press release, 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.
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.
Funds flow from operations is a non-GAAP term that represents net earnings
and asset retirement expenditures except for non-cash items.
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.


2007 HIGHLIGHTS

The combination of high crude oil prices and stable production volumes enabled Zargon to achieve relatively stable revenues and funds flow from operations in 2007. During 2007, Zargon's one percent gain in revenues to $155.51 million came primarily from a two percent increase in production volumes and a six percent gain in oil and liquid prices that was partially offset by a six percent decrease in natural gas prices. Zargon's 2007 funds flow from operations showed a four percent decline to $79.84 million, as Zargon experienced higher production, general and administrative and interest and financing costs in the year. Net earnings for the year were $24.55 million, a 45 percent decrease from 2006. The majority of the changes in the net earnings came from large changes in the non-cash items pertaining to unrealized risk management gains/losses and future income taxes.

Net capital expenditures for 2007 totalled $66.67 million with $63.54 million allocated to field-related activities, $1.86 million to net property acquisitions and $1.27 million to administrative assets. Compared to the prior year, the 2007 capital program showed a five percent increase in overall net expenditures and a four percent decrease in field-related expenditures. For the year ended December 31, 2007, Zargon spent $7.49 million to maintain an undeveloped land base of 362 thousand net acres (2006 - 381 thousand net acres); shot or acquired seismic at a cost of $4.41 million; drilled, equipped and tied-in wells for $51.64 million and concluded $1.86 million of net property acquisitions. Cash distributions to unitholders totalled $36.70 million during the 2007 year (2006 - $35.90 million). All of these activities were funded by the year's funds flow plus an increase in debt net of working capital (excluding the unrealized risk management assets and liabilities) of $22.48 million.



Financial Highlights

($ million, except per unit amounts) 2007 2006 2005
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Petroleum and natural gas revenue 155.51 154.04 162.72

Funds flow from operations (1) 79.84 82.89 84.37
Per unit - diluted 4.08 4.31 4.48

Net earnings 24.55 44.50 35.37
Per unit - diluted 1.45 2.68 2.19

Total assets 340.19 310.57 277.86
Net capital expenditures (2) 66.67 63.37 54.68
Bank debt 56.87 30.04 10.34
Cash distributions 36.70 35.90 37.44
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(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.
(2) Amounts include capital expenditures acquired for cash and equity
issuances.


Cash Distributions

Cash distributions to unitholders are at the discretion of the Board of Directors and can fluctuate depending on funds flow from operations. The Trust's capital program is financed from available funds flow and additional draw downs on the bank facilities, if required. The key drivers of Zargon's funds flow are commodity prices and production volumes. Since the Trust's production is relatively evenly weighted between natural gas (2007 - 57 percent) and oil and liquids (2007 - 43 percent), both commodity prices have a significant effect on its funds flow. In the event that oil and natural gas prices and/or production volumes are higher than anticipated and a cash surplus develops, the surplus may be used to increase distributions, reduce debt, and/or increase the capital program. In the event that oil and natural gas prices and/or production volumes are lower than expected, the Trust may decrease distributions, increase debt and/or decrease the capital program. Zargon regularly reviews its monthly distribution policy in the context of the current commodity price environment, production levels and capital program requirements. Distributions remained constant throughout 2007 at $0.18 per trust unit and have been maintained at this level since November 2005. Cash distributions to unitholders declared for 2007 totalled $36.70 million. For a further discussion, see the "Liquidity and Capital Resources" section of this report.

For Canadian income tax purposes, the 2007 cash distributions are 100 percent taxable income to unitholders.

DETAILED FINANCIAL ANALYSIS

Petroleum and Natural Gas Revenue

Zargon derives its revenue from the production and sale of petroleum (oil, natural gas liquids) and natural gas. Petroleum and natural gas revenue, exclusive of the impact of financial risk management contracts, increased one percent to $155.51 million in 2007 from $154.04 million in 2006 primarily due to a slight increase in overall production. Compared to the prior year, the relative weighting of production revenue between petroleum and natural gas in 2007 was reallocated due to commodity pricing with 56 percent of the revenues coming from the sale of oil and liquids (55 percent in 2006) and 44 percent coming from the sale of natural gas (45 percent in 2006). Production volumes on a barrel of oil equivalent basis in 2007 increased two percent to 8,560 barrels of oil equivalent per day from the prior year amount of 8,422 barrels of oil equivalent per day. Specifically, in 2007, natural gas production increased six percent and oil and liquids production decreased three percent over 2006 levels. Production decreases in oil and liquids resulted primarily from Williston Basin natural declines. Natural gas production increases resulted from the ongoing development program in Zargon's Jarrow and Hamilton Lake areas and from the tie-in of the West Central Alberta core area wells drilled as part of the 2006 drilling program. The average price of oil and liquids received by Zargon rose to $64.71 per barrel in 2007, up six percent from 2006. The average field price of natural gas was $6.40 per thousand cubic feet in 2007, a six percent decrease from $6.82 per thousand cubic feet in 2006.



Pricing

Average for the year 2007 2006 2005
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Natural Gas:
NYMEX average daily spot price ($US/mmbtu) 6.98 6.75 8.89
AECO average daily spot price ($Cdn/mmbtu) 6.45 6.54 8.77
Zargon realized field price before the
impact of financial risk management
contracts ($Cdn/mcf) 6.40 6.82 8.41
Zargon realized field price before the
impact of physical and financial risk
management contracts ($Cdn/mcf) 6.26 6.43 8.49
Zargon realized field price after the
impact of physical and financial risk
management contracts ($Cdn/mcf) 6.82 7.21 8.16

Crude Oil:
WTI ($US/bbl) 72.31 66.22 56.56
Edmonton par price ($Cdn/bbl) 76.35 72.77 68.72
Zargon realized field price before the
impact of financial risk management
contracts ($Cdn/bbl) 64.71 61.25 57.15
Zargon realized field price after the
impact of financial risk management
contracts ($Cdn/bbl) 64.54 58.05 53.32
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Petroleum (Oil and Natural Gas Liquids) Pricing

Zargon's field oil and natural gas liquids prices are adjusted at the point of sale for transportation charges and oil quality differentials from an Edmonton light sweet crude price that varies with world commodity prices. In 2007, Zargon's average oil and liquids field price, exclusive of the impact of financial risk management contracts, increased six percent to $64.71 per barrel from $61.25 per barrel in 2006 and $57.15 per barrel in 2005. The field price differential for Zargon's average blended 30 degree API crude stream was $11.64 per barrel less than the 2007 Edmonton reference crude price, which compares to the 2006 differential of $11.52 per barrel and the 2005 differential of $11.57 per barrel. As the quality and weight of Zargon's crude stream has remained relatively consistent for several years, the movements in Zargon's price differential are derived from the North American refinery supply and demand factors for light and medium crudes.

Natural Gas Pricing

The average field natural gas price, exclusive of the impact of financial risk management contracts, for 2007 decreased to $6.40 per thousand cubic feet, which is six percent lower than the 2006 average of $6.82 per thousand cubic feet and 24 percent lower than the 2005 average of $8.41 per thousand cubic feet. Historically, Zargon's field prices have shown a small discount to the benchmark AECO average daily price due to a lower heating content for Zargon's natural gas and due to legacy aggregator and other contracts, which are based partially on monthly index prices that tend to lag the AECO average daily index price in upward or downward trending markets. The 2007 field price differential for Zargon's natural gas before the impact of physical and financial risk management contracts was a discount of $0.19 per thousand cubic feet. In 2007, the various fixed price physical contracts, which are treated as part of natural gas production revenue and natural gas pricing, created a gain of $1.14 million (2006 - $2.51 million), equivalent to an increase of $0.11 per thousand cubic feet (2006 - $0.25 per thousand cubic feet).

Similar to the prior year, approximately 21 percent of Zargon's 2007 natural gas production was sold under aggregator contracts pursuant to long term contracts. The remainder of Zargon's natural gas production was sold by spot sale contracts and Alberta index prices were received.

Risk Management Activities

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 volumes, in order to partially offset the effects of large commodity price fluctuations. Because our risk management strategy is protective in nature and is designed to guard the Trust against extreme effects on funds flow from sudden falls in prices and revenues, upward price spikes tend to produce overall losses. Financial risk management contracts in place as at December 31, 2004, were designated as hedges for accounting purposes and the Trust monitored these contracts in determining the continuation of hedge effectiveness. As at June 30, 2006, all designated hedge contracts had expired. For the designated hedge contracts, realized gains and losses were recorded in the statements of earnings as the contracts settled and no unrealized gain or loss was recognized.

For 2007, the total realized risk management gain was $4.26 million; compared to a loss of $0.57 million in 2006 and a loss of $7.75 million in 2005. Of the 2007 gain, $4.49 million (equivalent to an increase of $0.42 per thousand cubic feet) is related to a gain from natural gas financial risk management transactions slightly offset by $0.23 million (equivalent to a decrease of $0.17 per barrel) related to losses from oil financial risk management transactions. Oil swaps and collars are settled against the NYMEX pricing index, whereas natural gas swaps, collars and puts are settled against the AECO monthly pricing index. In 2007, NYMEX WTI crude oil prices generally increased throughout the year, peaking in the month of November. AECO natural gas prices trended downwards during the first nine months of 2007 with a slight recovery in the 2007 fourth quarter. 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 year end. The 2007 net unrealized risk management loss totalled $16.80 million which, compares to a $9.55 million net unrealized risk management gain in 2006 (2005 - $3.76 million loss). Specifically, the 2007 net unrealized risk management losses resulted from financial oil contract losses ($15.09 million) and financial natural gas contract losses ($1.71 million). These unrealized risk management gains or losses are generated by the change over the reporting period in the mark-to-market valuation of Zargon's future financial contracts. Gains or losses on fixed price physical contracts are included in petroleum and natural gas revenue when settled in the statements of earnings and comprehensive income and no mark-to-market valuation is recorded on these contracts.

Royalties

Royalties include payments made to the Crown, freehold owners and third parties. Reported royalties also include the cost of the Saskatchewan Resource Surcharge ("SRC") and the cost of North Dakota state taxes. During 2007, total royalties were $32.75 million, a decrease of two percent from $33.43 million in 2006. Royalties as a percentage of gross revenue were 21.1 percent in 2007 compared to 21.7 percent in 2006 and 22.9 percent in 2005. On a commodity basis, natural gas royalties averaged 20.9 percent in 2007, a slight increase from the previous year's average of 20.8 percent. Oil royalties averaged 21.2 percent, down slightly from the prior year 2006 rate of 22.4 percent. The decrease in oil royalties is primarily related to initial low royalty rate incentives on certain new oil production wells in Saskatchewan.

During 2007, 59 percent (2006 - 60 percent) of the total royalties were paid to provincial and state governments, with the remainder paid to freehold owners and other third parties. The SRC charges were $1.10 million in 2007, up slightly from $1.01 million in the prior year and from $1.03 million in 2005, reflecting the trend in Saskatchewan oil revenues. North Dakota state taxes decreased to $2.01 million in 2007 from $2.27 million in the prior year primarily due to decreased oil production and sales. 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. 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.

Production Expenses

Zargon's production expenses increased 23 percent to $32.62 million in 2007 from $26.42 million in 2006. On a per unit of production basis, production expenses increased 22 percent to $10.44 per barrel of oil equivalent from $8.59 in 2006 ($7.89 in 2005).

Natural gas production expenses in 2007 rose 25 percent to $1.31 per thousand cubic feet from $1.05 per thousand cubic feet in 2006. The primary reasons for the increase are due to increased third-party gas gathering charges, increased third-party gas processing fees and increased water disposal and water hauling costs. These increased costs reflect, in part, the impact of additional natural gas volumes being processed through non-operated third party natural gas gathering and processing facilities.

Oil production expenses also rose in 2007 to $13.89 per barrel, an increase of 22 percent from $11.40 per barrel in 2006. The primary reasons for the increase are due to increased workovers and seasonal repairs and maintenance in the Williston Basin core area and are reflective of a continuing industry-wide trend to higher oil property operating costs, particularly in the Williston Basin.

In 2007, 2006 and 2005, Zargon's costs increased substantially due, in general, to the effect of 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. This trend culminated with a $10.51 per barrel of oil equivalent operating cost in the fourth quarter of 2007 following a record $10.95 per barrel of oil equivalent operating cost in the 2007 third quarter. 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

The average oil and liquids price received, after realized risk management losses, in 2007 of $64.54 per barrel was 11 percent higher than the $58.05 per barrel received in 2006, while the average natural gas price received, after realized risk management gains/losses, in 2007 of $6.82 per thousand cubic feet was five percent below the $7.21 per thousand cubic feet received in 2006. Operating netbacks increased/decreased commensurately. Oil and liquids netbacks rose 12 percent to $36.93 per barrel from $32.93 per barrel in 2006. Natural gas netbacks decreased 12 percent to $4.17 per thousand cubic feet from $4.73 per thousand cubic feet in 2006. On a barrel of oil equivalent basis, 2007 operating netbacks declined less than one percent to $30.21 from $30.46 in 2006.



Operating Netbacks

2007 2006
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Oil and Oil and
Liquids Natural Gas Liquids Natural Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
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Production revenue 64.71 6.40 61.25 6.82
Realized risk management
gain/(loss) (0.17) 0.42 (3.20) 0.38
Royalties (13.72) (1.34) (13.72) (1.42)
Production costs (13.89) (1.31) (11.40) (1.05)
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Operating netbacks 36.93 4.17 32.93 4.73
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General and Administrative Expenses

Gross general and administrative costs increased 14 percent in 2007 to $11.69 million from $10.25 million in 2006. On a per unit of production basis, net general and administrative costs increased 16 percent to $2.63 per barrel of oil equivalent compared to $2.27 per barrel of oil equivalent in 2006 and $1.99 in 2005. Trending upwards from 2005 and 2006, the 2007 increased general and administrative costs on a per unit of production basis were due to additional office lease costs and the costs related to the expansion of Zargon's technical staff and consultants.



General and Administrative Expenses

($ million, except as noted) 2007 2006 2005
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Gross general and administrative expenses 11.69 10.25 8.96
Overhead recoveries (3.48) (3.28) (2.91)
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Net general and administrative expenses 8.21 6.97 6.05
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Net expense after recoveries ($/boe) 2.63 2.27 1.99

Number of office employees at year end 45 43 39
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Interest and Financing Charges

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges were $3.07 million compared to $1.53 million in 2006 and $0.79 million in 2005. An increase in the average debt level is the primary reason for the increase in interest and financing charges. Zargon's effective interest and financing charge rate was 6.2 percent on an average bank debt of $49.86 million in 2007, compared to 6.4 percent on an average bank debt of $23.84 million in 2006 and 4.3 percent on an average bank debt of $18.17 million in 2005. At year end 2007, Zargon's bank debt, net of working capital (excluding unrealized risk management assets and liabilities), totalled $62.30 million, up 56 percent from $39.83 million at December 31, 2006.

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. Subsequent to year end, Zargon again amended and renewed its syndicated committed credit facilities, which resulted in a further increase in the available facilities and borrowing base to $150 million from the July 30, 2007 amount of $120 million. This most recent increase in committed credit facilities was completed on January 31, 2008 and was performed in conjunction with Zargon's corporate acquisition of Rival Energy Ltd. The next renewal date is July 29, 2008. These expanded facilities continue to be available for general corporate purposes and the potential acquisition of additional oil and gas properties such as those most recently acquired through the acquisition of Rival Energy Ltd.

Current Income Taxes

Current income taxes for 2007 were $2.14 million compared to $1.60 million in 2006. Of the total, $2.04 million is due to current taxes incurred in the United States compared to $1.34 million in 2006. The increased 2007 taxable income in the United States is due to a reduced 2007 capital program for this geographic region, resulting in reduced tax pool claims and, therefore, resulting in higher United States taxes. Provided that oil prices remain high, a similar or slightly higher level of United States current income taxes is predicted in 2008. The remaining current tax amounts relate to Canadian provincial capital taxes, which were $0.10 million in 2007 compared to $0.26 million in 2006. Tax pools as at December 31, 2007 were approximately $148 million, which represents an increase from the comparable $113 million of tax pools available to Zargon at the end of 2006. The Trust is a taxable entity under the Income Tax Act (Canada) and is currently only taxable (until 2011) on the income that is not distributed or declared distributable to unitholders. For Canadian income tax purposes, 2007 cash distributions are 100 percent taxable income to unitholders.

Trust Netbacks

Historically high oil prices and increased production volumes in 2007 resulted in relatively strong revenue netbacks and operating netbacks. On a barrel of oil equivalent basis, revenue of $49.77 in 2007 was one percent lower than the prior year and operating netbacks, as well as funds flow netbacks, decreased one percent and five percent over the prior year to $30.21 and $25.55 per barrel of oil equivalent, respectively.



Trust Netbacks

($/boe) 2007 2006 2005
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Petroleum and natural gas revenue 49.77 50.11 53.44
Realized risk management gain/(loss) 1.36 (0.18) (2.55)
Royalties (10.48) (10.88) (12.25)
Production costs (10.44) (8.59) (7.89)
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Operating netbacks 30.21 30.46 30.75

General and administrative (2.63) (2.27) (1.99)
Interest and financing charges (0.98) (0.50) (0.26)
Asset retirement expenditures (0.36) (0.20) (0.20)
Current income taxes (0.69) (0.52) (0.59)
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Funds flow netbacks (1) 25.55 26.97 27.71
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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.


Funds Flow from Operations

In 2007, despite production volume increases of two percent on a barrel of oil equivalent basis and increased realized risk management gains, the overall increase in operating costs and slightly lower realized average commodity prices produced a four percent decline in funds flow from operations to $79.84 million, compared to $82.89 million in 2006 and $84.37 million in 2005. The corresponding funds flow per diluted unit was $4.08 in 2007, a five percent decline from $4.31 in 2006, and a nine percent decline from $4.48 in 2005. The diluted per unit statistics reflect a two percent increase in the weighted average outstanding units to 19.55 million in 2007 from 19.24 million in 2006. The 2006 weighted average outstanding units were also two percent higher than the 2005 amount of 18.85 million.

The following table summarizes the variances in funds flow from operations between 2006 and 2007. It demonstrates that the variance (decline in funds flow from operations) is caused mainly by a slight decrease in overall realized commodity prices and increased operating expenses, both of which were partially offset by increased production volumes, decreased royalties and increased realized risk management gains.



$ Per Per Unit
Diluted Percent
$ Million Trust Unit Variance
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Funds flow from operations - 2006 (1) 82.89 4.31 -
Price variance (1.04) (0.05) (1)
Volume variance 2.52 0.12 3
Realized risk management gains 4.82 0.25 6
Royalties 0.69 0.04 1
Expenses:
Production (6.20) (0.32) (7)
General and administrative (1.24) (0.06) (1)
Interest and financing charges (1.54) (0.08) (2)
Asset retirement expenditures (0.51) (0.03) (1)
Current taxes (0.55) (0.03) (1)
Weighted average trust units - diluted - (0.07) (2)
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Funds flow from operations - 2007 79.84 4.08 (5)
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(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.


Depletion and Depreciation

In 2007, Zargon's depletion and depreciation provision increased 18 percent to $48.41 million, compared to $41.14 million in 2006 and $37.48 million in 2005. The higher charges reflect an increase of two percent in production volumes and a 16 percent increase in the charge on a per barrel of oil equivalent basis. The primary reasons for the year-over-year expense increase on a per barrel of oil equivalent basis are due to increased finding, development and acquisition costs and the impact of the conversion of exchangeable shares relating to the application of EIC-151.

Depletion and depreciation charges calculated on a unit of production method are based on total proved reserves with a conversion of six thousand cubic feet of natural gas being equivalent to one barrel of oil. The 2007 depletion calculation includes $10.84 million of future capital expenditures to develop the Trust's reserves, but excludes $22.78 million of unproven properties relating to undeveloped land.

Zargon's depletion and depreciation, on a barrel of oil equivalent basis, increased 16 percent in 2007 to $15.49 from $13.38 in 2006 and $12.31 in 2005. Depletion and depreciation rates will be subject to continuing upward pressure as Zargon continues to experience increased finding and development costs as compared to the historical costs that were generated in prior years when commodity prices were substantially lower.

Accretion of Asset Retirement Obligations

For the year ended December 31, 2007, the non-cash accretion expense for asset retirement obligations is $1.41 million compared to $1.24 million in 2006 and $1.20 million in 2005. The year-over-year increases are due to changes in the estimated future liability for asset retirement obligations as a result of wells added through Zargon's drilling program inclusive of wells acquired/disposed of in the year and changes resulting from revisions to the timing and the amounts of the original estimates of undiscounted cash flows. The significant assumptions used in this calculation are a credit adjusted risk-free rate of 7.5 percent, an inflation rate of two percent and the payments to settle the retirement obligations occurring over the next 40 years with the majority of the costs being incurred after 2016. The estimated net present value of the total asset retirement obligation is $21.18 million as at December 31, 2007, based on a total future liability of $101.88 million.

Unit-Based Compensation

Unit-based compensation was $1.71 million in 2007, $0.15 million lower than the $1.86 million expense in 2006. The Trust generally grants unit rights on a quarterly basis. The slight decrease in the current year expense is as a result of increased cancellations of unit rights and a general decline in the valuation of new quarterly grants. Zargon will continue to use fair value methodologies for future unit rights grants. These non-cash expenses will be recurring charges in future years if Zargon continues to grant employees and directors trust unit rights.

The trust unit rights incentive plan 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 exceed 10 percent of the aggregate number of issued and outstanding trust units of the Trust. The Plan allows for the holder of rights to either exercise the right based on the original grant price or on a modified price as calculated per the Plan of Arrangement. Unit right grant prices are set at the market closing price for the trust units on the date prior to the unit rights being issued. Trust unit rights granted under the plan generally vest over a three-year period and expire approximately five years from the grant date.

Future Income Taxes

The provision for the future tax recovery for 2007 was $15.47 million when compared to a future tax recovery of $2.82 million in 2006 and an expense of $0.47 million in 2005. Effectively, Zargon's future tax obligations are reduced as distributions are made from the Trust and, consequently, it is anticipated that Zargon's effective tax rate will continue to be low through to 2011. The 2007 year includes a second quarter recovery and a fourth quarter recovery relating to reductions in future federal and provincial income tax rates substantively enacted during the respective 2007 quarters. Additionally, the increase in future tax recovery, when compared to the 2006 prior year, is significantly impacted by the decrease in earnings before income taxes for the period as a result of previously mentioned items such as increased 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. Subsequent 2007 fourth quarter legislation has lowered this tax rate to 29.5 percent in 2011 and 28.0 percent beyond 2011 to assimilate recent corporate tax rate changes. 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 approximately 28.0 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. At June 30, 2007, 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 by $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.

Non-Controlling Interest - Exchangeable Shares

EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", states exchangeable securities issued by a subsidiary of an Income Trust should be reflected as either a non-controlling interest or debt on the consolidated balance sheet unless they meet certain criteria. The exchangeable shares issued by Zargon Oil & Gas Ltd., a corporate subsidiary of the Trust, are publicly traded and have an expiry term, which could be extended at the option of the Board of Directors. Therefore, these securities are considered, by EIC-151, to be transferable to third parties and to have an indefinite life. EIC-151 states that if these criteria are met, the exchangeable shares should be reflected as a non-controlling interest.

Accordingly, the Trust has increased its unitholders' equity and non-controlling interest for 2007 by $6.64 million (2006 - $12.12 million) on the Trust's consolidated balance sheets. Consolidated net earnings for 2007 have been reduced for net earnings attributable to the non-controlling interest by $3.81 million (2006 - $7.14 million). In accordance with EIC-151, and given the circumstances in Zargon's case, each redemption is accounted for as a step-purchase, which for 2007; resulted in an additional increase in property and equipment of $8.82 million (2006 - $6.73 million) and an increase in the future income tax liability of $5.99 million (2006 - $1.75 million). Funds flow from operations were not impacted by this change.

The cumulative impact to date of the application of EIC-151 has been to increase gross property and equipment by $51.76 million, (for depletion impact see note 4 in the audited consolidated financial statements), unitholders' equity and non-controlling interest by $53.35 million, future income tax liability by $17.22 million and an allocation of net earnings to exchangeable shareholders of $18.81 million.

Net Earnings

Zargon's 2007 net earnings were $24.55 million, a $19.95 million decrease from $44.50 million in 2006. The 2005 net earnings were $35.37 million. The net earnings track the funds flow from operations for the respective periods modified by asset retirement expenditures and non-cash charges, which in 2007; include depletion and depreciation, unrealized risk management losses, future income tax recoveries, unit-based compensation and non-controlling interest. The primary reasons for the $19.95 million decrease in net earnings when comparing the year ended 2007 to the 2006 prior year, are the previously mentioned items such as increased unrealized risk management losses ($26.35 million), increased depletion and depreciation expenses ($7.27 million) and production costs ($6.20 million) offset by realized risk management gains ($4.82 million), the related items of future tax recoveries ($12.65 million) and decreased non-controlling interest ($3.33 million). On a per diluted unit basis, 2007 net earnings were $1.45 compared to $2.68 in 2006 and $2.19 in 2005.

The 2007 net earnings were 31 percent of funds flow from operations, primarily reflecting the increase in unrealized risk management losses and the increase in future income tax recoveries. The 2006 net earnings represented 54 percent of funds flow from operations compared to 42 percent of funds flow from operations in 2005.

Capital Expenditures

Net capital expenditures in 2007 of $66.67 million increased five percent from $63.37 million in 2006. In 2007, Zargon completed a drilling program of 53 gross (46.9 net) wells compared to 89 gross (76.2 net) wells in 2006, and as a result drilling and completion expenditures decreased commensurately by 21 percent to $33.15 million. Of the total 2007 net capital expenditures, $18.01 million were expended on West Central Alberta, $30.33 million on Alberta Plains, $17.06 million on Williston Basin properties and $1.27 million was incurred corporately on leasehold improvements and administrative assets.



Capital Expenditures

($ million) 2007 2006 2005
----------------------------------------------------------------------------
Undeveloped land 7.49 5.25 3.65
Geological and geophysical (seismic) 4.41 3.34 3.47
Drilling and completion of wells 33.15 41.80 33.36
Well equipment and facilities 18.49 15.94 11.43
----------------------------------------------------------------------------

Exploration and development 63.54 66.33 51.91
----------------------------------------------------------------------------

Property acquisitions 3.04 1.40 3.68
Property dispositions (1.18) (4.54) (2.45)
----------------------------------------------------------------------------

Net property acquisitions/(dispositions) 1.86 (3.14) 1.23
----------------------------------------------------------------------------

Corporate acquisitions assigned to property and
equipment (1) - - 1.19
----------------------------------------------------------------------------

Total net capital expenditures excluding
administrative assets (1) 65.40 63.19 54.33
Administrative assets 1.27 0.18 0.35
----------------------------------------------------------------------------
Total net capital expenditures (1) 66.67 63.37 54.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts include capital expenditures acquired for cash and equity
issuances.


SUBSEQUENT EVENTS

On January 23, 2008, Zargon completed the acquisition of Rival Energy Ltd. ("Rival") for consideration comprising of 0.57 million Zargon trust units and $16.40 million in cash for all the issued and outstanding Rival common shares. Pursuant to the Rival Plan of Arrangement, Rival shareholders had the option of electing to receive 0.0562 Zargon trust units or $1.35 for each Rival common share, up to an aggregate maximum of $16.40 million in cash. The first post-Arrangement distribution by Zargon was paid on February 15, 2008 to Zargon unitholders (including former Rival shareholders who had elected to receive and continue to hold Zargon trust units) of record on January 31, 2008. In conjunction with this acquisition, Zargon also amended its credit facilities (see Bank Debt section later in this report).

LIQUIDITY AND CAPITAL RESOURCES

In 2007, the summation of the funds outflows pertaining to the net capital expenditure program ($66.67 million) and the cash distributions to unitholders ($36.70 million) exceeded the summation of the funds inflows coming from the funds flow from operations ($79.84 million) plus the proceeds from the issuance of trust units ($2.13 million) by $21.40 million.

Zargon's financing philosophy and the three sources of funding are as follows:

- Internally generated funds flow from operations provides the basic level of funding for the Trust's annual capital expenditures program and for distributions to unitholders.

- Debt may be utilized for acquisitions or to expand capital programs when it is deemed appropriate. As at December 31, 2007 the Trust had $120 million in syndicated committed credit facilities of which $63.13 million or 53 percent of these facilities are unutilized. The Trust increased these facilities by $30 million to $150 million on January 31, 2008.

- New equity, if available and if on favourable terms, can be utilized for acquisitions or to expand capital programs.

Recently, the combination of declining natural gas prices, the Alberta government's royalty announcement and the announced changes to the Canadian income trust tax rules after 2010 have 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

($ million) 2007 2006 2005
----------------------------------------------------------------------------

Cash flows from operating activities 76.30 83.74 82.97
Net earnings 24.55 44.50 35.37
Actual cash distributions paid or payable relating
to the period (36.70) (35.90) (37.44)
----------------------------------------------------------------------------

Excess of cash flows from operating activities
over cash distributions paid 39.60 47.84 45.53
Excess (shortfall) of net earnings over cash
distributions paid (12.15) 8.60 (2.07)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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.

For the year ended December 31, 2007, cash flows from operating activities (after changes in non-cash working capital) of $76.30 million exceeded cash distributions of $36.70 million. This was consistent with the year ended December 31, 2006 in which cash flows from operating activities (after changes in non-cash working capital) of $83.74 million exceeded cash distributions of $35.90 million.

For the year ended December 31, 2007, cash distributions of $36.70 million exceeded net earnings of $24.55 million. Net earnings include significant non-cash charges ($56.43 million in 2007) which do not impact cash flow. For the year ended December 31, 2006, cash distributions of $35.90 million were significantly less than the net earnings of $44.50 million. In the 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 year ended December 31, 2007, cash distributions and net capital expenditures totalled $103.37 million, which was $27.06 million higher than the cash flows from operating activities (after changes in non-cash working capital) of $76.30 million. For the year ended December 31, 2006, cash distributions and net capital expenditures totalled $99.27 million, which was $15.53 million higher than the cash flows from operating activities (after changes in non-cash working capital) of $83.74 million. 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 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 year ended December 31, 2007, Zargon has maintained a monthly distribution of $0.18 per trust unit, and plans to maintain this level of distribution into 2008.



Capital Sources and Uses

($ million) 2007 2006 2005
----------------------------------------------------------------------------

Funds flow from operations (1) 79.84 82.89 84.37
Change in bank debt 26.83 19.70 (3.89)
Issuance of trust units 2.13 4.02 3.87
Cash distributions to unitholders (36.70) (35.90) (37.44)
Changes in working capital and other (5.43) (7.34) 7.77
----------------------------------------------------------------------------

Total capital sources 66.67 63.37 54.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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.


Funds Flow from Operations

It is anticipated that Zargon's 2008 exploration and development capital budget and cash distributions to unitholders will be financed through the Trust's funds flow from operations and its credit facilities. Funds flow is partially influenced by factors that the Trust cannot control, such as commodity prices, the US/Canadian dollar exchange rates and interest rates. Zargon's 2008 estimated sensitivity to moderate fluctuations in these key business parameters is shown in the accompanying table.



Funds Flow Sensitivity Summary
Change in 2008 Funds Flow
($ million) ($/unit)
----------------------------------------------------------------------------

Change of $1.00 US/bbl in the price of WTI oil 0.61 0.03
Change in oil production of 100 bbl/d 1.96 0.10
Change of $0.10 US/mcf in the price of NYMEX
natural gas 0.84 0.04
Change in natural gas production of one mmcf/d 1.79 0.09
Change in $0.01 in the $US/$Cdn exchange rate 1.63 0.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Bank Debt

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. Subsequent to year end, Zargon again amended its syndicated committed credit facilities which further resulted in an increase in the available facilities and borrowing base to $150 million from the July 30, 2007 amount of $120 million. These facilities consist of a $130 million tranche available to the Canadian borrower and a US $18 million tranche available to the US borrower. This most recent increase in committed credit facilities was completed on January 31, 2008 and was performed in conjunction with Zargon's corporate acquisition of Rival Energy Ltd. These expanded facilities continue to be available for general corporate purposes and the potential acquisition of additional oil and gas properties. Pursuant to the January 2008 amendment, the $150 million demand debenture on the assets of the subsidiaries of the Trust, which have been provided as security for these facilities, was increased to $300 million. 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. At December 31, 2007, bank debt was $56.87 million, an increase of $26.83 million from the prior year end bank debt amount of $30.04 million. The increase in bank debt was primarily attributed to net capital expenditures and cash distributions exceeding funds flow from operations during the year. Zargon reviews its compliance with its bank debt covenants on a quarterly basis and has no violations as at December 31, 2007.

Zargon's debt net of working capital (excluding unrealized risk management assets and liabilities) of $62.30 million at December 31, 2007 was equivalent to 78 percent of the 2007 funds flow from operations of $79.84 million. At December 31, 2006, the debt net of working capital (excluding unrealized risk management assets and liabilities) was $39.83 million, equivalent to 48 percent of the 2006 funds flow from operations of $82.89 million.

Equity

At March 10, 2008, Zargon had 17.676 million trust units and 2.060 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the current effective exchange ratio of 1.31785, there would be 20.391 million trust units outstanding at this date. Pursuant to the trust unit rights incentive plan, there are currently an additional 1.476 million trust unit incentive rights issued and outstanding.

During 2007, 6.940 million Zargon trust units traded on The Toronto Stock Exchange with a high trading price of $31.24 per unit, a low of $21.35 per unit and a closing price of $23.06 per unit. The 2007 trading statistics show a 36 percent year-over-year decrease in trading volume and a seven percent decrease in the closing unit price. Zargon's market capitalization (including the market value of exchangeable shares) at year end 2007, was approximately $456 million, compared to approximately $482 million at the end of 2006.

Segmented Geographic Information

During 2007, approximately 86 percent (2006 - 84 percent) of Zargon's combined petroleum and natural gas revenue came from Western Canadian (Alberta, Saskatchewan and Manitoba) properties, with the remaining 14 percent (2006 - 16 percent) of revenues generated in the United States (North Dakota).



SELECTED QUARTERLY INFORMATION

($ million, except
per unit amounts) 2007 2006
----------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
----------------------------------------------------------------------------

Petroleum and
natural gas
revenue 41.13 36.64 39.21 38.53 36.50 37.93 38.66 40.94

Funds flow from
operations (1) 20.10 17.38 20.56 21.80 18.84 19.87 22.06 22.12
Per unit -
diluted 1.02 0.88 1.05 1.12 0.97 1.02 1.14 1.15

Net earnings 2.20 5.50 11.63 5.22 7.05 12.31 13.22 11.92
Per unit -
diluted 0.13 0.32 0.68 0.31 0.43 0.73 0.79 0.72

Cash distributions 9.21 9.19 9.17 9.12 9.05 9.00 8.96 8.89
Per trust unit 0.54 0.54 0.54 0.54 0.54 0.54 0.54 0.54

Net capital
expenditures 18.35 16.43 10.97 20.93 20.41 18.99 8.78 15.19
Total assets 340.19 327.54 324.96 324.31 310.57 294.14 283.86 282.35
Bank debt 56.87 44.10 46.74 37.68 30.04 20.71 18.14 26.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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.


FOURTH QUARTER 2007 RESULTS

During the fourth quarter of 2007, Zargon's petroleum and natural gas revenues of $41.13 million were 12 percent higher than the previous quarter's revenues. Production for the 2007 fourth quarter of 8,790 barrels of oil equivalent per day exceeded the fourth quarter guidance of 8,625 barrels of oil equivalent per day by two percent and was three percent higher than the 2007 third quarter's production of 8,501 barrels of oil equivalent per day. Compared to the previous quarter, oil production increased two percent to 3,666 barrels per day as Williston Basin and Alberta Plains (Taber area) wells were placed on production. Fourth quarter natural gas production increased four percent over the previous quarter to 30.74 million cubic feet per day as recently drilled West Central Alberta and Alberta Plains natural gas wells were tied-in. Average field prices received during the fourth quarter, before the impact of financial risk management contracts, were $71.29 per barrel for oil and liquids and $5.95 per thousand cubic feet for natural gas, a five percent increase and a 14 percent increase, respectively, compared to the 2007 third quarter prices. Reflecting market and seasonal trends, Zargon's field price differential for its blended 30 degree API crude oil stream increased to a $15.13 per barrel discount to the Edmonton reference crude oil price, a 44 percent increase from Zargon's average differential of $10.50 per barrel for the first nine months of 2007.

Funds flow from operations was $20.10 million in the fourth quarter, an increase of 16 percent or $2.72 million over the prior quarter. A comparative analysis of the primary factors that caused this quarter-over-quarter increase is as follows:

- Fourth quarter 2007 petroleum and natural gas revenues of $41.13 million were $4.49 million or 12 percent higher than the 2007 third quarter revenues of $36.64 million. This revenue increase was a result of the three percent increase in production volumes and the nine percent increase in average realized commodity prices.

- Realized risk management losses were $0.30 million in the fourth quarter of 2007, a $1.41 million change over the prior quarter's $1.11 million of risk management gains. The primary reason for the fourth quarter net loss related to gains ($1.39 million) being realized on financial natural gas risk management contracts being more than offset by losses ($1.69 million) realized on financial oil risk management contracts. Natural gas prices continued to be weak during the 2007 fourth quarter, while oil prices continued to be relatively strong.

- Royalties for the fourth quarter were $8.26 million, an increase of $0.63 million from the prior quarter. The average royalty rate for the quarter of 20.1 percent was similar to the 20.8 percent from the 2007 third quarter. This small decline in the average royalty rate is attributed to the effect of fourth quarter gains recognized on fixed price physical natural gas contracts, which increase natural gas pricing and revenue but are not subject to royalties.

- Production expenses were $8.50 million for the quarter, a $0.06 million or one percent decrease from the third quarter of 2007. On a per barrel of oil equivalent basis, production expenses decreased four percent to $10.51 in the fourth quarter of 2007 compared to $10.95 in the prior quarter. This quarterly decline in per unit costs was due in part to reduced levels of Williston Basin workovers, seasonal repairs and maintenance costs.

- General and administrative expenses increased in the fourth quarter by $0.51 million over the third quarter of 2007. This is a 24 percent increase compared to the prior quarter and is primarily due to amounts recorded for year end performance-based compensation for employees.

- Interest and financing charges in the fourth quarter were $0.92 million, an increase of nine percent or $0.08 million from the prior quarter. The average debt level for the fourth quarter increased 18 percent to $61.04 million compared to $51.88 million in the third quarter of 2007, resulting in increased debt servicing charges.

- Current income taxes of $0.14 million were $0.69 million lower than the 2007 third quarter taxes. The decrease was primarily due to a reduction in estimated United States taxable income related to an active fourth quarter capital expenditure program in this geographic region.

- Asset retirement expenditures reflect the actual amounts incurred to abandon and reclaim unutilized non-producing wells. These asset retirement expenditures totalled $0.29 million in the 2007 fourth quarter and were reduced from the prior quarter amount of $0.38 million. The difference between accretion expenses (as reflected on the income statements) and asset retirement expenditures are a result of the timing differences between the estimating of future expenses and the actual incurrence of actual expenses during the period.

Net earnings for the quarter decreased $3.30 million to $2.20 million, a 60 percent decrease compared to the third quarter 2007 net earnings of $5.50 million. Net earnings track the funds flow from operations for the respective periods modified by asset retirement expenditures and non-cash charges, which included the following for the fourth quarter of 2007:

- Unit-based compensation expense increased by $0.15 million during the fourth quarter of 2007 to $0.56 million, a 35 percent increase over the third quarter. The increase is a result of additional unit rights granted in the fourth quarter of 2007.

- Depletion and depreciation expense increased by $0.74 million to $12.92 million in the fourth quarter. The additional expense resulted from the increased production in the fourth quarter and the use of an updated depletion and depreciation rate of $15.98 per barrel of oil equivalent, compared to the prior quarter's $15.58 per barrel of oil equivalent charge. The increased per unit charges are calculated on the basis of the recently completed 2007 year end reserve appraisal prepared by independent engineers that reflects Zargon's, and the industry's, trend to higher finding and development costs. Furthermore, 2007 depletion and depreciation rates continue to increase quarterly as a result of ongoing increases in the property and equipment balance from the conversion of exchangeable shares due to the application of EIC-151.

- Unrealized risk management losses in the 2007 fourth quarter of $9.82 million were 316 percent or $7.46 million higher than the third quarter loss of $2.36 million. These unrealized losses result from "marking-to-market" financial risk management contracts at each period end. During the fourth quarter, unrealized risk management losses resulted from stronger commodity pricing at the December 31, 2007 mark-to-market date when compared to the third quarter September 30, 2007 mark-to-market date. In particular, higher year end futures oil pricing resulted in unrealized contract losses of $8.50 million. Additionally, the natural gas losses of $1.32 million were also the result of higher year end futures natural gas pricing. The realization and the expiry of certain financial natural gas and oil contracts also affect the mark-to-market amounts.

- The provision for accretion of asset retirement obligations for the 2007 fourth quarter was $0.42 million, an increase of $0.09 million or 28 percent when compared to the prior quarter expense. The quarter-over-quarter increase is due to changes in the estimated future liability for asset retirement obligations as a result of wells added through Zargon's drilling program inclusive of wells acquired/disposed of in the quarter and changes resulting from revisions to the timing and the amounts of the original estimates of undiscounted cash flows.

- The future income tax recovery was $6.35 million during the quarter compared to a future income tax recovery of $3.77 million from the third quarter of 2007. The future income tax recovery in the 2007 fourth quarter was due to a substantive enactment of reduced future federal income tax rates and the significant decrease of earnings to a loss position before taxes of $3.66 million compared to the third quarter earnings before taxes of $3.41 million. In summary, the fourth quarter decrease in net earnings was primarily derived by the increase of non-cash unrealized risk management contract losses in the quarter.

- Reduction in earnings due to non-controlling interests pertaining to exchangeable shares decreased to $0.35 million in the 2007 fourth quarter from $0.86 million in the third quarter. This was due to a decrease in net earnings before non-controlling interest in the fourth quarter.

Net capital expenditures were $18.35 million during the fourth quarter of 2007, a 12 percent increase from the prior quarter amount of $16.43 million. During the fourth quarter, Zargon completed an extensive field capital program focused on Alberta Plains core area Taber horizontal oil wells, West Central Alberta natural gas exploration locations and Williston Basin core area horizontal oil exploitation wells. During the fourth quarter of 2007, 9.0 net wells were drilled compared to 20.9 net wells in the third quarter of 2007.

Cash distributions to unitholders declared for the quarter totalled $9.21 million.



ZARGON ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

As at December 31
($ thousands) 2007 2006
----------------------------------------------------------------------------

ASSETS (note 5 and 19)

Current
Accounts receivable (note 11) 21,668 18,362
Prepaid expenses and deposits 3,145 3,281
Unrealized risk management asset (note 11) 1,432 5,817
----------------------------------------------------------------------------
26,245 27,460

Property and equipment, net (note 4) 313,949 283,108
----------------------------------------------------------------------------

340,194 310,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES

Current
Accounts payable and accrued liabilities 27,172 28,410
Cash distributions payable (note 17) 3,074 3,022
Unrealized risk management liability (note 11) 12,430 20
----------------------------------------------------------------------------
42,676 31,452

Long term debt (note 5) 56,868 30,037

Asset retirement obligations (note 6) 21,184 17,307

Future income taxes (note 9) 37,258 47,891
----------------------------------------------------------------------------
157,986 126,687
----------------------------------------------------------------------------
Commitments and contingencies (notes 5, 7, 11, 12 and 13)

NON-CONTROLLING INTEREST

Exchangeable shares (note 8) 20,730 18,319
----------------------------------------------------------------------------

UNITHOLDERS' EQUITY

Unitholders' capital (note 7) 89,688 82,868
Contributed surplus (note 7) 3,714 2,475
Accumulated earnings 188,819 164,267
Accumulated cash distributions (note 17) (120,743) (84,048)
----------------------------------------------------------------------------
161,478 165,562
----------------------------------------------------------------------------

340,194 310,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME AND
ACCUMULATED EARNINGS

For the years ended December 31
($ thousands, except per unit amounts) 2007 2006
----------------------------------------------------------------------------

Revenue
Petroleum and natural gas revenue 155,512 154,039
Unrealized risk management gain/(loss) (note 11) (16,796) 9,553
Realized risk management gain/(loss) 4,255 (569)
Royalties (32,746) (33,431)
----------------------------------------------------------------------------
110,225 129,592
----------------------------------------------------------------------------

Expenses
Production 32,620 26,416
General and administrative 8,209 6,973
Unit-based compensation (note 7) 1,705 1,856
Interest and financing charges (note 5) 3,071 1,532
Unrealized foreign exchange (gain)/loss (226) 24
Accretion of asset retirement obligations (note 6) 1,406 1,244
Depletion and depreciation 48,410 41,136
----------------------------------------------------------------------------
95,195 79,181
----------------------------------------------------------------------------

Earnings before income taxes 15,030 50,411
----------------------------------------------------------------------------

Income taxes (note 9)
Current 2,143 1,598
Future (recovery) (15,470) (2,824)
----------------------------------------------------------------------------
(13,327) (1,226)
----------------------------------------------------------------------------

Earnings before non-controlling interest 28,357 51,637

Non-controlling interest - exchangeable shares (note 8) (3,805) (7,138)
----------------------------------------------------------------------------

Net earnings and comprehensive income 24,552 44,499

Accumulated earnings, beginning of year 164,267 119,768
----------------------------------------------------------------------------

Accumulated earnings, end of year 188,819 164,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net earnings per unit (note 10)
Basic 1.45 2.68
Diluted 1.45 2.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31
($ thousands) 2007 2006
----------------------------------------------------------------------------

Operating activities
Net earnings for the year 24,552 44,499
Add (deduct) non-cash items:
Non-controlling interest - exchangeable shares 3,805 7,138
Unrealized risk management (gain)/loss 16,796 (9,553)
Depletion and depreciation 48,410 41,136
Accretion of asset retirement obligations 1,406 1,244
Unit-based compensation 1,705 1,856
Unrealized foreign exchange (gain)/loss (226) 24
Future income taxes (recovery) (15,470) (2,824)
Asset retirement expenditures (1,140) (627)
----------------------------------------------------------------------------
79,838 82,893

Changes in non-cash working capital (note 14) (3,535) 842
----------------------------------------------------------------------------
76,303 83,735
----------------------------------------------------------------------------

Financing activities
Advances of bank debt 26,831 19,698
Cash distributions to unitholders (36,695) (35,902)
Exercise of unit rights 2,127 4,018
Changes in non-cash financing working capital (note 14) 52 (8,099)
----------------------------------------------------------------------------
(7,685) (20,285)
----------------------------------------------------------------------------

Investing activities
Additions to property and equipment (67,850) (67,909)
Proceeds on disposal of property and equipment 1,181 4,543
Changes in non-cash investing working capital (note 14) (1,949) (84)
----------------------------------------------------------------------------
(68,618) (63,450)
----------------------------------------------------------------------------

Net change in cash during the year and cash, end of year - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See supplemental cash flow information contained in note 15.

See accompanying notes to the consolidated financial statements.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007 and 2006
All amounts are stated in Canadian dollars unless otherwise noted.


1. STRUCTURE OF THE TRUST

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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Consolidation

These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Because a precise determination of many assets and liabilities is dependent upon future events, the preparation of periodic financial statements necessarily involves the use of estimates and approximations. Accordingly, actual results could differ materially from those estimates. The consolidated financial statements have, in management's opinion, been properly prepared within reasonable limits of materiality and within the framework of the Trust's accounting policies summarized below.

The consolidated financial statements include the accounts of Zargon Energy Trust, all of its subsidiaries and a partnership. All subsidiaries and the partnership are directly or indirectly owned and their operations are fully reflected in the consolidated financial statements.

Revenue Recognition

Petroleum and natural gas revenue is recognized in earnings when reserves are produced and delivered to the purchaser.

Joint Operations

The majority of the petroleum and natural gas operations of the Trust are conducted jointly with others, and accordingly, these consolidated financial statements reflect only the proportionate interests of the Trust in such activities.

Property and Equipment

The Trust follows the full cost method of accounting for its oil and natural gas operations whereby all costs relating to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in separate cost centres for Canada and the United States. Such costs include land acquisition costs, annual carrying charges of non-producing properties, geological and geophysical costs and costs of drilling and equipping wells.

Depletion and depreciation of petroleum, natural gas properties and equipment is computed using the unit of production method based on the estimated proved reserves of petroleum and natural gas before royalties determined by independent consultants. For purposes of this calculation, reserves are converted to common units on the basis that six thousand cubic feet of natural gas is equivalent to one barrel of oil. A portion of the cost of petroleum and natural gas rights relating to undeveloped properties is excluded from the depletion calculation. Twenty percent of the year end balance of these costs is added to the depletion base each year. Proceeds on the disposal of petroleum and natural gas properties are applied against capitalized costs, with gains or losses not ordinarily recognized, unless such a disposal would result in a change in the depletion rate of 20 percent or more.

Depreciation of office equipment is provided using the declining balance method at an annual rate of 20 percent. Leasehold improvements are depreciated over the term of the lease.

Impairment Test

The Trust applies an impairment test to petroleum, natural gas properties and equipment costs on a quarterly basis or more frequently as events or circumstances dictate. This impairment test is performed on both the Canadian and US cost centres. An impairment loss exists when the carrying amount of the Trust's petroleum, natural gas properties and equipment exceeds the estimated undiscounted future net cash flows associated with the Trust's proved reserves (before royalties). If an impairment loss is determined to exist, the costs carried on the consolidated balance sheets in excess of the fair value of the Trust's proved and probable reserves are charged to earnings. Reserves are determined pursuant to evaluation by independent engineers as dictated by National Instrument 51-101.

Asset Retirement Obligations

Zargon recognizes the fair value of an Asset Retirement Obligation ("ARO") in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit of production method based on proved reserves (before royalties). The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed in the period. Actual costs incurred upon the settlement of the ARO are charged against the liability.

Financial Instruments

Derivative financial instruments are utilized to reduce commodity price risk associated with the Trust's production of oil and natural gas. The base prices for the commodities are sometimes denominated in US dollars and the Trust may also use such financial instruments to reduce the related foreign currency risk. Financial instruments may also be used from time to time to reduce interest rate risk on outstanding debt. The Trust does not enter into financial instruments for trading or speculative purposes.

The Trust follows a policy of using risk management instruments such as fixed price swaps, forward sales, puts and costless collars. The objective is to partially offset or mitigate the wide price swings commonly encountered in oil and natural gas commodities and in so doing protect a minimum level of cash flow in periods of low commodity prices.

For financial risk management contracts entered into prior to December 31, 2004, the Trust's policy was to designate each derivative financial instrument employed as a hedge of a specific portion of projected production over the term of the instrument. The Trust formally documented its risk management objectives and strategies for undertaking the hedged transactions, the hedging item, the nature of the specific risk exposures being hedged, the intended term of the hedge relationship, the method for assessing effectiveness and the method of accounting for the hedging relationship. The effectiveness of the derivative was assessed on an ongoing basis to ensure that the derivatives entered into were highly effective in offsetting changes in fair values of the hedged items. The instruments employed could have been denominated in US or Canadian dollars. Gains or losses from all hedging contracts, other than forward sales settled by physical delivery, were recognized as hedging gains or losses when the sale of hedged production occurred. The Trust believed these derivative financial instruments used were effective as hedges over their term. In the event that a designated hedged item ceased to exist, any realized or unrealized gain or loss on such derivative commodity instruments were to be recognized in earnings immediately. If the hedge relationship was terminated, either via ineffectiveness or via termination of the designation, gains or losses previously deferred continued to be deferred and recognized when they were realized. As at June 30, 2006, all designated hedge contracts had expired.

For financial risk management contracts entered into after December 31, 2004, the Trust does consider these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, for outstanding contracts not designated as hedges, an unrealized gain or loss is recorded based on the change in fair value (mark-to-market) of the contracts at each reporting period end. These instruments have been recorded as unrealized risk management assets/liabilities in the consolidated balance sheets.

In the case of forward sales, the instrument can sometimes be satisfied by physical delivery. In the case of physical delivery, the payment/receipt is recorded as part of the normal revenue stream.

Foreign currency swap agreements may be used from time to time to manage the risk inherent in producing commodities whose price is based directly or indirectly on US dollars, using a notional principal amount equal to the projected monthly revenue from their sale. Payments or charges are calculated and paid according to the terms of the agreement, usually with monthly settlement. At December 31, 2007 and 2006, the Trust had no such financial instruments.

The Trust had no interest rate financial instruments at December 31, 2007 and 2006.

Income Taxes

The Trust follows the liability method of tax allocation in accounting for income taxes. Under this method, the Trust records future income taxes for the effect of any differences between the accounting and income tax basis of an asset or liability using income tax rates expected to apply in the periods in which these temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in tax rates is recognized in earnings in the period in which the change is substantively enacted.

Foreign Currency Translation

The Trust uses the temporal method of foreign currency translation whereby the monetary assets and liabilities recorded in a foreign currency are translated into Canadian dollars at year end exchange rates, and non-monetary assets and liabilities at the exchange rates prevailing when the assets were acquired or liability incurred. Revenues and expenses are translated at the average rate of exchange prevailing during the year. Gains and losses on translation are included in the consolidated statements of earnings and comprehensive income.

Trust Unit Rights and Unit-Based Compensation

Under the Trust's unit rights incentive plan (the "Plan"), rights to purchase trust units are allowed to be granted to directors, officers, employees and other service providers at current market prices. The Plan allows for the exercise price of rights to be reduced in future periods by an amount that distributions exceed a stated return on assets. Under the fair value method of accounting for unit-based compensation the cost of the option is charged to earnings with an offsetting amount recorded in contributed surplus, based on an estimate from the fair value model. Forfeiture of rights are recorded as a reduction in expense in the period in which they occur.

Per Unit Amounts

Per unit amounts are calculated using the weighted average number of trust units outstanding during the year. Diluted per unit amounts are calculated using the treasury stock method to determine the dilutive effect of unit-based compensation. The Trust follows the treasury stock method, which assumes that the proceeds received from "in-the-money" trust unit rights and unrecognized future unit-based compensation expense are used to repurchase units at the average market rate during the year. Diluted per unit amounts also include exchangeable shares using the "if-converted" method, whereby it is assumed the conversion of the exchangeable shares occurs at the beginning of the reporting period (or at the time of issuance if later).

Measurement Uncertainty

The amounts recorded for depletion and depreciation of property and equipment and the assessment of these assets for impairment are based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the consolidated financial statements of changes in such estimates in future periods could be material.

Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal and regulatory environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment is made to the property and equipment balance.

Cash Distributions

The Trust declares monthly distributions of cash to unitholders of record on the last day of each calendar month. Pursuant to the Trust's policy, it will pay distributions to its unitholders subject to satisfying its financing covenants. Such distributions are recorded as distributions of equity upon declaration of the distribution.

3. 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.

Equity

Section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period. This section specifies that changes in equity for the period arising from net earnings, OCI, other changes in earnings, changes in contributed surplus, and changes in unitholders' capital must be presented separately.

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 classified as "held-for-trading" are measured at fair value with changes in fair value recognized in earnings. Financial assets classified as "available-for-sale" are measured at fair value, with changes in fair value recognized in OCI until the asset is removed from the consolidated balance sheets. Financial assets classified as "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 on a straight-line basis over the term of the related long term debt. The adoption of the expensing method had no impact 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.

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.

Future Accounting Pronouncements

The Trust has identified new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact to 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 disclosure of 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 February 2008, the CICA issued Section 3064 "Goodwill and Intangible Assets", replacing Section 3062 "Goodwill and Other Intangible Assets". The new Section will be effective on January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Trust is currently evaluating the impact of the adoption of this new Section, however does not expect a material impact on its consolidated financial statements.

The CICA Accounting Standards Board ("AcSB") has 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 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.



4. PROPERTY AND EQUIPMENT

December 31, 2007
----------------------------------------------------------------------------
Accumulated Depletion
($ thousands) Cost and Depreciation Net Book Value
----------------------------------------------------------------------------

Petroleum, natural gas
properties and
equipment(i) 535,850 223,780 312,070
Leasehold improvements
and office equipment 3,107 1,228 1,879
----------------------------------------------------------------------------
538,957 225,008 313,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2006
----------------------------------------------------------------------------
Accumulated Depletion
($ thousands) Cost and Depreciation Net Book Value
----------------------------------------------------------------------------

Petroleum, natural gas
properties and
equipment(i) 457,865 175,585 282,280
Leasehold improvements
and office equipment 1,841 1,013 828
----------------------------------------------------------------------------
459,706 176,598 283,108
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(i)As a result of shareholders redeeming exchangeable shares, property and
equipment has cumulatively increased $51.76 million; $8.82 million
relating to 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 approximately $16.72 million; $6.16 million relating to 2007, $5.48
million relating to 2006 and $5.08 million relating to 2005.


At December 31, 2007, petroleum, natural gas properties and equipment include $22.78 million (2006 - $20.99 million) relating to undeveloped properties that have been excluded from the depletion calculation.

An impairment test calculation was performed on the Trust's petroleum, natural gas properties and equipment at December 31, 2007 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amount of the Trust's petroleum, natural gas properties and equipment; consequently an impairment provision was not recorded. This impairment calculation was performed separately on both the Canadian and US cost centres.



The following table outlines benchmark prices used in the impairment test at
December 31, 2007:

WTI Crude Oil Exchange Rate WTI Crude Oil AECO Gas
Year ($US/bbl) ($US/$Cdn) ($Cdn/bbl) ($Cdn/gj)
----------------------------------------------------------------------------

2008 92.45 1.00 92.45 6.59
2009 87.80 1.00 87.80 7.35
2010 86.32 1.00 86.32 7.63
2011 86.89 1.00 86.89 7.73
2012 86.04 1.00 86.04 7.75
----------------------------------------------------------------------------
Thereafter
(inflation %) 2.0% 1.00 2.0% 2.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Actual prices used in the impairment test were adjusted for commodity price differentials specific to Zargon.

5. LONG TERM DEBT

On June 30, 2006, Zargon amended and renewed its 2005 syndicated committed credit facilities, resulting in an increase in the available facilities and borrowing base to $100 million from the previous amount of $80 million. These facilities consisted of an $80 million tranche available to the Canadian borrower and a US $15 million tranche available to the US borrower. On July 30, 2007, Zargon amended and renewed these facilities, the result of which is an increase in the available facilities and borrowing base to $120 million. These facilities consist of a $100 million tranche available to the Canadian borrower and a US $18 million tranche available to the US borrower. A $150 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities. The facilities are fully revolving for a 364-day period with the provision for an annual extension at the option of the lenders and upon notice from Zargon's management. The next renewal date is July 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.

Interest rates fluctuate under the syndicated facilities with Canadian prime, US prime, and US base rates plus an applicable margin between zero basis points and 25 basis points, as well as with Canadian banker's acceptance and LIBOR rates plus an applicable margin between 90 basis points and 150 basis points. At December 31, 2007, $56.87 million (2006 - $30.04 million) had been drawn on the syndicated committed credit facilities bearing interest at Canadian prime (December 31, 2007 - 6.0 percent; December 31, 2006 - 6.0 percent) with any unused amounts subject to standby fees. In the normal course of operations Zargon enters into various letters of credit. At December 31, 2007, the approximate value of outstanding letters of credit totalled $0.44 million (2006 - $0.47 million). Refer to note 19 for a subsequent amendment to Zargon's syndicated committed credit facilities.

6. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation was estimated by management based on Zargon's net working interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. Zargon has estimated the net present value of its total asset retirement obligations to be $21.18 million as at December 31, 2007 (2006 - $17.31 million), based on a total future liability of $101.88 million (2006 - $65.08 million). These payments are expected to be made over the next 40 years with the majority of the costs being incurred after 2016. Commencing July 1, 2005, incremental asset retirement obligations are calculated using a revised credit adjusted risk-free rate of 7.5 percent. Asset retirement obligations prior to this period were calculated using a credit adjusted risk-free rate of 8.5 percent. An inflation rate of two percent used in the calculation of the present value of the asset retirement obligation remains unchanged.



The following table reconciles Zargon's asset retirement obligations:

Year Ended December 31,
----------------------------------------------------------------------------
($ thousands) 2007 2006
----------------------------------------------------------------------------

Balance, beginning of year 17,307 15,859
Adjustment to asset retirement obligations 2,911 -
Net liabilities incurred 851 826
Liabilities settled (1,140) (627)
Accretion expense 1,406 1,244
Foreign exchange (151) 5
----------------------------------------------------------------------------
Balance, end of year 21,184 17,307
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. UNITHOLDERS' EQUITY

Pursuant to the Plan of Arrangement on July 15, 2004, 14.87 million units of the Trust and 3.66 million exchangeable shares (see note 8) of the Company were issued in exchange for all of the outstanding shares of the Company on a one-for-one basis.

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



Trust Units

December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Number of Amount Number of Amount
(thousands) Units ($) Units ($)
----------------------------------------------------------------------------

Balance, beginning of year 16,789 82,868 16,355 71,644
Unit rights exercised for cash 120 2,127 208 4,018
Unit-based compensation
recognized on exercise
of unit rights - 466 - 728
Issued on conversion of
exchangeable shares 167 4,227 226 6,478
----------------------------------------------------------------------------
Balance, end of year 17,076 89,688 16,789 82,868
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Trust Unit Rights Incentive Plan

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 under the Plan (the "modified price"). The modified price is calculated by deducting from the grant price the amount by which monthly distributions, on a per unit basis, made by the Trust after the grant date exceed a monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties. 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 following table summarizes information about the Trust's unit rights:

December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Weighted Weighted
Average Average
Exercise Price Exercise Price
Number of Initial and Number of Initial and
Unit Rights Modified Unit Rights Modified
(thousands) ($/unit right) (thousands) ($/unit right)
----------------------------------------------------------------------------

Outstanding
beginning
of year 1,208 26.32 / 24.73 915 22.80 / 21.51
Unit rights
granted 522 25.36 518 29.70
Unit rights
exercised (120) 17.73 (208) 19.30
Unit rights
cancelled (122) 28.75 (17) 25.59
----------------------------------------------------------------------------
Outstanding
end of year 1,488 26.41 / 24.60 1,208 26.32 / 24.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unit rights
exercisable
at year end 559 25.51 / 22.66 212 24.11 / 21.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following tables summarize information about unit rights outstanding and
excercisable at December 31, 2007:

At the initial grant price:

Unit Rights Outstanding Unit Rights Exercisable
----------------------------------------------------------------------------
Range of Weighted Weighted Weighted
Exercise Average Average Average
Prices Number Remaining Exercise Number Exercise
($/unit Outstanding Contractual Price Exercisable Price
right) (thousands) Life ($/unit right) (thousands) ($/unit right)
----------------------------------------------------------------------------
17.70 -
22.00 261 1.6 years 19.77 218 19.33
22.75 -
25.06 378 3.8 years 23.98 43 24.91
26.65 -
29.93 485 3.3 years 27.89 126 28.16
31.09 -
33.05 364 2.7 years 31.72 172 31.55
---------------------- -----------------------------------------
1,488 26.41 559 25.51
----------------------------------------------------------------------------
----------------------------------------------------------------------------

At the modified price:


Unit Rights Outstanding Unit Rights Exercisable
----------------------------------------------------------------------------
Range of Weighted Weighted Weighted
Exercise Average Average Average
Prices Number Remaining Exercise Number Exercise
($/unit Outstanding Contractual Price Exercisable Price
right) (thousands) Life ($/unit right) (thousands) ($/unit right)
----------------------------------------------------------------------------
13.72 -
18.71 261 1.6 years 16.12 218 15.61
21.88 -
23.79 378 3.8 years 23.30 43 23.67
24.33 -
27.84 485 3.3 years 26.34 126 25.38
28.37 -
31.65 364 2.7 years 29.73 172 29.36
---------------------- -----------------------------------------
1,488 24.60 559 22.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Unit-Based Compensation

The weighted average assumptions used for unit rights granted in 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 8.6 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 in 2007 of $1.71 million (2006 - $1.86 million).

Compensation expense associated with unit 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 expenses in the period in which they occur.

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



Contributed Surplus

($ thousands)
----------------------------------------------------------------------------

Balance, December 31, 2005 1,347
Unit-based compensation expense 1,856
Unit-based compensation recognized on exercise of unit rights (728)
----------------------------------------------------------------------------
Balance, December 31, 2006 2,475
Unit-based compensation expense 1,705
Unit-based compensation recognized on exercise of unit rights (466)
----------------------------------------------------------------------------
Balance, December 31, 2007 3,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Trust Unit Redemption

Under the terms of the Trust Indenture, unitholders may require the Trust to redeem all or any part of the trust units at a price and under certain terms and conditions as specified in the Trust Indenture. The redemption price per trust unit will be equal to the lesser of: (i) 90 percent of the "market price" of the trust units on the principal market on which the trust units are quoted for trading during the 10 trading day period commencing immediately after the date on which the trust units are tendered to Zargon for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are so tendered for redemption. Trust units tendered for redemption in any calendar month shall be paid on the last day of the third following month by, at the Trust's option: (i) a cash payment; or (ii) a distribution of notes and/or redemption notes. It is anticipated that this redemption right will not be the primary mechanism for holders of trust units to dispose of their trust units. Notes or redemption notes which may be distributed in specie to unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop for such notes or redemption notes. Notes or redemption notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans and registered education savings plans. To date, no trust units have been tendered for redemption.

8. 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 year, a total of 0.14 million (2006 - 0.20 million) exchangeable shares were converted into 0.17 million (2006 - 0.23 million) trust units based on the exchange ratio at the time of conversion. At December 31, 2007, the exchange ratio was 1.29611 (December 31, 2006 - 1.19403) trust units per exchangeable share. As set out in the Arrangement, the exchangeable shares are entitled to vote equally to the number of trust units for which each exchangeable share is convertible into a trust unit on the record date. The Board of Directors of Zargon Oil & Gas Ltd. hold the option to redeem all outstanding exchangeable shares for trust units on or before July 15, 2014. At such time, should the Board of Directors not extend the term of the exchangeable shares, there would be no remaining non-controlling interest.

Pursuant to EIC-151 "Exchangeable Securities Issued by a Subsidiary of an Income Trust", 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 and comprehensive income 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 year end.



Non-Controlling Interest - Exchangeable Shares

December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
(thousands, except Number of Amount Number of Amount
exchange ratio) Shares ($) Shares ($)
----------------------------------------------------------------------------

Balance, beginning of year 2,207 18,319 2,402 12,673
Exchanged for trust units
at book value and including
net earnings attributed
during the year (136) (1,394) (195) (1,492)
Earnings attributable to
non-controlling interest - 3,805 - 7,138
----------------------------------------------------------------------------
Balance, end of year 2,071 20,730 2,207 18,319
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exchange ratio, end of year 1.29611 1.19403

Trust units issuable upon
conversion of exchangeable
shares, end of year 2,684 2,635
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The proforma total units outstanding at December 31, 2007, including trust units outstanding, and trust units issuable upon conversion of exchangeable shares and after giving rise to the exchange ratio at the end of the year, is 19.76 million units (2006 - 19.42 million units).

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



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

Balance at December 31, 2005 71,644 12,673 84,317
Issued on redemption of
exchangeable shares at book value 477 (477) -
Effect of EIC-151 6,001 6,123 12,124
Unit-based compensation recognized
on exercise of unit rights 728 - 728
Unit rights exercised for cash 4,018 - 4,018
----------------------------------------------------------------------------
Balance at December 31, 2006 82,868 18,319 101,187
Issued on redemption of
exchangeable shares at book value 330 (330) -
Effect of EIC-151 3,897 2,741 6,638
Unit-based compensation recognized
on exercise of unit rights 466 - 466
Unit rights exercised for cash 2,127 - 2,127
----------------------------------------------------------------------------
Balance at December 31, 2007 89,688 20,730 110,418
----------------------------------------------------------------------------
----------------------------------------------------------------------------


EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" states that exchangeable securities issued by a subsidiary of an Income Trust should be reflected as either a non-controlling interest or debt on the consolidated balance sheets unless they meet certain criteria. The exchangeable shares issued by Zargon Oil & Gas Ltd., a corporate subsidiary of the Trust, are publicly traded and have an expiry term, which could be extended at the option of the Board of Directors. Therefore, these securities are considered, by EIC-151, to be transferable to third parties and to have an indefinite life. EIC-151 states that if these criteria are met, the exchangeable shares should be reflected as a non-controlling interest.

As a result of EIC-151, the Trust has increased its unitholders' equity and non-controlling interest for 2007 by $6.64 million (2006 - $12.12 million) on the Trust's consolidated balance sheets. Consolidated net earnings for 2007 have been reduced for net earnings attributable to the non-controlling interest by $3.81 million (2006 - $7.14 million). In accordance with EIC-151 and given the circumstances in Zargon's case, each redemption is accounted for as a step-purchase, which for 2007 additionally resulted in an increase in property and equipment of $8.82 million (2006 - $6.73 million), and an increase in future income tax liability of $5.99 million (2006 - $1.75 million). Funds flow from operations were not impacted by this change.

The cumulative impact to date of the application of EIC-151 has been to increase gross property and equipment by $51.76 million (for depletion impact see note 4), unitholders' equity and non-controlling interest by $53.35 million, future income tax liability by $17.22 million and an allocation of net earnings to exchangeable shareholders of $18.81 million.

9. INCOME TAXES

The Trust is a taxable entity under the Income Tax Act (Canada) and, until 2011, is taxable only on income that is not distributed or distributable to the unitholders. As the Trust allocates all of its Canadian taxable income to the unitholders in accordance with the Trust Indenture, and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no current tax provision for Canadian income tax expense has been incurred by the Trust. Provincial capital taxes and US income taxes are provided for under current income tax expense.

In the Trust's structure, payments are made between the Company and the Trust that result in the transferring of taxable income from the Company to individual unitholders. These payments may reduce future income tax liabilities previously recorded by the Company that would be recognized as a recovery of income tax in the period incurred.

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. Subsequent 2007 fourth quarter legislation has lowered this tax rate to 29.5 percent in 2011 and 28.0 percent beyond 2011 to assimilate recent corporate tax rate changes. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its consolidated balance sheets 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 approximately 28.0 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 of 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 distributions. A significant change in any of the preceding assumptions could materially affect management's estimate of the future tax liability.

Income taxes differ from the amounts which would be obtained by applying the statutory income tax rates to earnings before income taxes as follows:



($ thousands) 2007 2006
----------------------------------------------------------------------------

Statutory income tax rates 33.03% 36.30%

Expected income taxes 4,964 18,300
Add (deduct) income tax effect of:
Non-deductible Crown charges - 2,145
Resource allowance - (2,397)
Rate adjustments (5,775) (8,865)
Impact of changes in tax rates relating
to income trusts after 2010 (2,220) -
Cash distributions (12,120) (13,032)
Capital taxes and US income taxes 2,143 1,598
Other (319) 1,025
----------------------------------------------------------------------------
(13,327) (1,226)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The 2007 and 2006 years include recoveries relating to reductions in future federal and provincial income tax rates substantively enacted during the respective years.

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The components of Zargon's net future income tax liability are as follows:



($ thousands) 2007 2006
----------------------------------------------------------------------------

Net book value of property and equipment
in excess of tax pools 43,469 46,336
Deferred partnership earnings 4,762 6,024
Asset retirement obligations (7,051) (6,333)
Unrealized risk management asset/(liability) (3,633) 2,104
Share issue costs (57) (8)
Other (232) (232)
----------------------------------------------------------------------------
37,258 47,891
----------------------------------------------------------------------------
----------------------------------------------------------------------------

As at December 31, 2007, Zargon's estimated tax pools are as follows:

($ thousands) December 31, 2007
----------------------------------------------------------------------------

Canadian oil and gas property expenses in the Trust 37,772
Canadian oil and gas property expenses in other entities 7,821
Canadian development expenses 27,224
Canadian exploration expenses 45,125
Capital cost allowance 40,441
US tax pools 4,440
Partnership deferral (15,815)
Other 1,248
----------------------------------------------------------------------------
148,256
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS

(thousands of units) 2007 2006
----------------------------------------------------------------------------

Basic 16,975 16,600
Diluted 19,551 19,244
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Dilution amounts of 2.58 million units (2006 - 2.64 million) were added to the weighted average number of units outstanding during the year in the calculation of diluted per unit amounts. These unit additions represent the dilutive effect of unit rights according to the treasury stock method and also include exchangeable shares using the "if-converted" method. Due to the fact that at the time of exercise, the rights holder has the option of exercising at the original grant price or a modified price as calculated under the Plan, the prices used in the treasury stock calculation are the lower prices calculated under the Plan. An adjustment to the numerator amount was required in the diluted calculation to provide for the earnings of $3.81 million (2006 - $7.14 million) attributable to the non-controlling interest pertaining to the exchangeable shareholders.

11. FINANCIAL INSTRUMENTS

Fair Value of Financial Assets and Liabilities

Financial instruments of the Trust consist of accounts receivable, deposits, accounts payable, cash distributions payable, unrealized risk management assets and liabilities and long term debt. As at December 31, 2007 and 2006, there are no significant differences between the carrying values of these instruments and their estimated market values.

Credit Risk Management

Accounts receivable include amounts receivable for petroleum and natural gas sales that are generally made to large credit worthy purchasers, and amounts receivable from joint venture partners that are recoverable from production. Accordingly, management views credit risks on these amounts as low. Of Zargon's significant individual accounts receivable at December 31, 2007, approximately 22 percent was owing from one company (2006 - 26 percent).

The Trust is exposed to losses in the event of non-performance by counterparties to financial risk management contracts. The Trust minimizes credit risk associated with possible non-performance of these counterparties by entering into contracts with only investment grade counterparties, limiting exposure to any one counterparty and monitoring procedures. Management believes these risks are minimal.

Interest Rate Risk Management

Borrowings under bank credit facilities are market rate based (variable interest rates); thus, carrying values approximate fair values.

Foreign Currency Risk Management

The Trust is exposed to fluctuations in the exchange rate between the Canadian dollar and the US dollar. Crude oil, and to a large extent natural gas prices, are based upon reference prices denominated in US dollars, while the majority of the Trust's expenses are denominated in Canadian dollars. When considered appropriate, the Trust enters into agreements to fix the exchange rate of the Canadian dollar to the US dollar in order to manage this risk.

Commodity Price Risk Management

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 flows from the volatility of oil and natural gas commodity prices.



Financial Contracts at December 31, 2007:

Fair Market
Value
Weighted Gain/(Loss)
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------

Oil swaps 300 bbl/d $66.70 US/bbl Jan. 1/08-Mar. 31/08 (777)
300 bbl/d $61.72 US/bbl Jan. 1/08-Jun. 30/08 (1,779)
600 bbl/d $71.54 US/bbl Jan. 1/08-Dec. 31/08 (4,687)
500 bbl/d $87.58 US/bbl Jan. 1/08-Jun. 30/09 (1,086)
300 bbl/d $68.29 US/bbl Apr. 1/08-Jun. 30/08 (690)
600 bbl/d $68.94 US/bbl Jul. 1/08-Dec. 31/08 (2,468)
500 bbl/d $72.74 US/bbl Jan. 1/09-Mar. 31/09 (747)
500 bbl/d $85.30 US/bbl Jul. 1/09-Dec. 31/09 (196)
Natural gas
swaps 6,000 gj/d $8.41/gj Jan. 1/08-Mar. 31/08 1,147
1,000 gj/d $7.84/gj Apr. 1/08-Oct. 31/08 285
----------------------------------------------------------------------------
Net Fair Market Value, Financial Contracts (10,998)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 year end. The unrealized loss for 2007 was $16.80 million and the unrealized gain for 2006 was $9.55 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 consolidated financial statements.



Physical Contract at December 31, 2007:
Fair Market
Value
Weighted Gain/(Loss)
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Natural gas
fixed price 1,000 gj/d $7.95/gj Apr. 1/08-Oct. 31/08 308
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. COMMITMENTS

The Trust is committed to future minimum payments for natural gas transportation contracts in addition to operating leases for office space, office equipment, vehicles and field equipment. Payments required under these commitments for each of the next five years are: 2008 - $2.02 million; 2009 - $1.48 million; 2010 - $1.23 million; 2011 - $1.23 million; 2012 - $0.71 million; thereafter - nil.

13. CONTINGENCIES AND GUARANTEES

In the normal course of operations, Zargon executes agreements that provide for indemnification and guarantees to counterparties in transactions such as the sale of assets and operating leases.

These indemnifications and guarantees may require compensation to counterparties for costs and losses incurred as a result of various events, including breaches of representations and warranties, loss of or damages to property, environmental liabilities or as a result of litigation that may be suffered by counterparties.

Certain indemnifications can extend for an unlimited period and generally do not provide for any limit on the maximum potential amount. The nature of substantially all of the indemnifications prevents the Trust from making a reasonable estimate of the maximum potential amount that might be required to pay counterparties as the agreements do not specify a maximum amount, and the amounts depend on the outcome of future contingent events, the nature and likelihood of which cannot be determined at this time.

The Trust indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their services to the Trust to the extent permitted by law. The Trust has acquired and maintains liability insurance for its directors and officers. The Trust is party to various legal claims associated with the ordinary conduct of business. The Trust does not anticipate that these claims will have a material impact on its financial position.



14. CHANGES IN NON-CASH WORKING CAPITAL

Year Ended December 31,
----------------------------------------------------------------------------
($ thousands) 2007 2006
----------------------------------------------------------------------------

Changes in non-cash working capital items:
Accounts receivable (3,306) 3,473
Prepaid expenses and deposits 136 (571)
Accounts payable and accrued liabilities (1,238) (2,160)
Cash distributions payable 52 (8,100)
Foreign exchange and other (1,076) 17
----------------------------------------------------------------------------
(5,432) (7,341)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Changes relating to operating activities (3,535) 842
Changes relating to financing activities 52 (8,099)
Changes relating to investing activities (1,949) (84)
----------------------------------------------------------------------------
(5,432) (7,341)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

15. SUPPLEMENTAL CASH FLOW INFORMATION

($ thousands) 2007 2006
----------------------------------------------------------------------------

Cash interest paid 3,259 1,593
Cash taxes paid 2,972 2,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------

16. SEGMENTED INFORMATION

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

2007
----------------------------------------------------------------------------
($ thousands) Canada United States Combined
----------------------------------------------------------------------------

Petroleum and natural gas revenue 133,473 22,039 155,512
Earnings before income taxes 5,703 9,327 15,030
Property and equipment, net 278,444 35,505 313,949
Total assets 301,643 38,551 340,194
Net capital expenditures 63,591 3,078 66,669
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2006
----------------------------------------------------------------------------
($ thousands) Canada United States Combined
----------------------------------------------------------------------------

Petroleum and natural gas revenue 129,967 24,072 154,039
Earnings before income taxes 39,797 10,614 50,411
Property and equipment, net 248,440 34,668 283,108
Total assets 273,748 36,820 310,568
Net capital expenditures 58,040 5,326 63,366
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----------------------------------------------------------------------------

17. CASH DISTRIBUTIONS

During the year, the Trust declared distributions to the unitholders in the
aggregate amount of $36.70 million (2006 -- $35.90 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
October October 31, 2007 November 15, 2007 $0.18
November November 30, 2007 December 17, 2007 $0.18
December December 31, 2007 January 15, 2008 $0.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

January January 31, 2006 February 15, 2006 $0.18
February February 28, 2006 March 15, 2006 $0.18
March March 31, 2006 April 17, 2006 $0.18
April April 30, 2006 May 15, 2006 $0.18
May May 31, 2006 June 15, 2006 $0.18
June June 30, 2006 July 17, 2006 $0.18
July July 31, 2006 August 15, 2006 $0.18
August August 31, 2006 September 15, 2006 $0.18
September September 30, 2006 October 16, 2006 $0.18
October October 31, 2006 November 15, 2006 $0.18
November November 30, 2006 December 15, 2006 $0.18
December December 31, 2006 January 15, 2007 $0.18
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----------------------------------------------------------------------------


18. RELATED PARTY TRANSACTIONS

Zargon paid $0.05 million (2006 - $0.05 million) for vehicle leases to a company owned by a Board member; $0.07 million (2006 - $0.09 million) for legal services to a law firm of which a Board member is a partner; nil (2006 - $0.02 million) for field services to a company of which a senior Zargon officer is a Board member and nominal shareholder; and nil (2006 - $0.06 million) in consulting fees to a company owned by a Board member. These payments were in the normal course of operations, were made on commercial terms, and therefore were recorded at their exchange amounts.

19. SUBSEQUENT EVENTS

On January 23, 2008, Zargon completed the acquisition of Rival Energy Ltd. ("Rival") for consideration comprising of 0.57 million Zargon trust units and $16.40 million in cash for all the issued and outstanding Rival common shares. Pursuant to the Rival Plan of Arrangement, Rival shareholders had the option of electing to receive 0.0562 Zargon trust units or $1.35 for each Rival common share, up to an aggregate maximum of $16.40 million in cash. The first post-Arrangement distribution by Zargon was paid on February 15, 2008 to Zargon unitholders (including former Rival shareholders who had elected to receive and continue to hold Zargon trust units) of record on January 31, 2008.

On January 31, 2008, Zargon amended its syndicated committed credit facilities, the result of which is an increase in the available facilities and borrowing base to $150 million. These facilities consist of a $130 million tranche available to the Canadian borrower and a US $18 million tranche available to the US borrower. A $300 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities.

Forward-Looking Statements - This document contains statements that are forward-looking, such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. 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 document are as of March 10, 2008 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.

Barrels of Oil Equivalent - Barrels of oil equivalent ("boe") 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 equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Based in Calgary, Alberta, Zargon is a sustainable energy trust with oil and natural gas operations in Alberta, Saskatchewan, Manitoba and North Dakota. Zargon's securities trade on the Toronto Stock Exchange.

In order to learn more about Zargon, we encourage you to visit Zargon's website at www.zargon.ca where you will find a current unitholder presentation, financial reports and historical news releases.

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