ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

March 10, 2010 17:01 ET

Zargon Energy Trust Announces 2009 Fourth Quarter And Full Year Results

CALGARY, ALBERTA--(Marketwire - March 10, 2010) - Zargon Energy Trust (TSX:ZAR.UN) (TSX:ZOG.B) ("Zargon" or the "Trust") today announced its operating and financial results for the fourth quarter and year ended December 31, 2009.

Highlights from the fourth quarter and year ended December 31, 2009:

- Fourth quarter 2009 revenue of $47.21 million and funds flow from operating activities of $24.75 million were 15 percent and eight percent, respectively, higher than the preceding 2009 third quarter levels. Net earnings for the fourth quarter were $0.44 million, a 90 percent decrease from the third quarter of 2009. Revenue for the full year decreased by 32 percent to $155.99 million, funds flow from operating activities decreased 19 percent to $86.35 million and net earnings decreased 96 percent to $2.72 million.

- Production volumes in 2009 increased seven percent to 9,856 barrels of oil equivalent per day compared to 2008. Fourth quarter production of 30.60 million cubic feet per day of natural gas and 5,485 barrels per day of oil and liquids provided Zargon quarterly production volumes of 10,586 barrels of oil equivalent per day, five percent higher than third quarter volumes.

- Net capital expenditures in 2009 were $104.59 million with $57.38 million of corporate and net property acquisitions, $46.45 million for exploration and development programs and $0.76 million for administrative assets. For the year, Zargon drilled 25.7 net wells with a 100 percent success ratio, yielding 15.9 net oil wells and 9.8 net natural gas wells.

- Cash distributions in 2009 of $2.16 per trust unit were declared and represented 59 percent of the year's $3.64 per diluted trust unit of funds flow from operating activities. Including the effect of the exchangeable shares, which do not receive distributions, the 2009 cash distributions totalled $45.96 million or 53 percent of the year's $86.35 million of funds flow from operating activities. Fourth quarter cash distributions totalled $0.54 per trust unit.

- Year end debt net of working capital (excluding unrealized risk management assets/liabilities and future income taxes) of $88.01 million is 0.89 times the annualized fourth quarter funds flow from operating activities. Currently, Zargon has $180 million in credit facilities held by three major Canadian based banking institutions.



Three Months Ended Year Ended
TRUST HIGHLIGHTS December 31, December 31,
Percent Percent
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
(unaudited)(unaudited)

FINANCIAL
Income and Investments
($ millions)
Petroleum and natural
gas revenue 47.21 41.25 14 155.99 229.49 (32)
Funds flow from
operating activities 24.75 20.40 21 86.35 106.91 (19)
Cash flows from
operating activities 27.86 24.84 12 88.83 110.12 (19)
Cash distributions 12.45 9.96 25 45.96 39.09 18
Net earnings 0.44 28.19 (98) 2.72 68.29 (96)
Net capital expenditures 12.87 16.37 (21) 104.59 119.73 (13)

Per Unit, Diluted
Funds flow from
operating activities
($/unit) 0.95 0.97 (2) 3.64 5.18 (30)
Cash flows from
operating activities
($/unit) 1.07 1.18 (9) 3.74 5.34 (30)
Net earnings ($/unit) 0.02 1.53 (99) 0.13 3.80 (97)

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

Balance Sheet at Year End
($ millions)
Property and equipment, net 425.96 386.75 10
Bank debt 76.58 77.58 (1)
Unitholders' equity 248.34 222.54 12

Total Units Outstanding
at Year End (millions) 26.02 21.15 23

OPERATING
Average Daily Production
Oil and liquids (bbl/d) 5,485 4,434 24 5,055 4,306 17
Natural gas (mmcf/d) 30.60 29.86 2 28.80 29.68 (3)
Equivalent (boe/d) 10,586 9,410 12 9,856 9,252 7
Equivalent per million
trust units (boe/d) 408 446 (9) 412 446 (8)

Average Selling Price
(before the impact of
financial risk
management contracts)
Oil and liquids ($/bbl) 68.88 53.87 28 59.89 89.65 (33)
Natural gas ($/mcf) 4.42 6.99 (37) 4.32 8.12 (47)

Wells Drilled, Net 5.0 13.9 (64) 25.7 35.9 (28)

Undeveloped Land at
Year End
(thousand net acres) 540 419 29

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

Notes:
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.
For net capital expenditures, amounts include capital expenditures acquired
for cash, equity issuances, acquisition costs and net debt assumed on
corporate acquisitions.
Funds flow from operating activities is a non-GAAP term that represents net
earnings and asset retirement expenditures except for non-cash items.
Total trust units outstanding include trust units plus exchangeable shares
outstanding at period end. The exchangeable shares are converted at the
exchange ratio at the end of the period.
Average daily production per million trust units is calculated using the
weighted average number of units outstanding during the period, plus the
weighted average number of exchangeable shares outstanding for the period
converted at the average exchange ratio for the period.


2009 HIGHLIGHTS

Despite increased production volumes, significantly lower crude oil and natural gas prices resulted in Zargon achieving lower 2009 revenues and funds flow from operating activities when compared to 2008. During 2009, Zargon's revenue decreased by 32 percent to $155.99 million, which was primarily due to a 33 percent decrease in oil prices and a 47 percent decrease in natural gas prices that was slightly offset by a seven percent increase in production volumes. Zargon's 2009 funds flow from operating activities showed a 19 percent decrease to $86.35 million. Net earnings for the year were $2.72 million, a 96 percent decrease from 2008. The majority of the decrease in net earnings resulted from the above mentioned changes and from the large increase in non-cash unrealized risk management losses.

Net capital expenditures for 2009 totalled $104.59 million with $46.45 million from field-related activities, $1.04 million to net property acquisitions, $56.34 million to corporate acquisitions and $0.76 million to administrative assets. Compared to the prior year, the 2009 capital program showed a 13 percent decrease in overall net expenditures and a 13 percent decrease in field-related expenditures. For the year ended December 31, 2009, Zargon spent $5.60 million on undeveloped land; shot or acquired seismic at a cost of $3.71 million; drilled, equipped and tied-in wells for $37.14 million and concluded $57.38 million of corporate and net property acquisitions. Cash distributions to unitholders totalled $45.96 million during the 2009 year (2008 - $39.09 million). All of these activities were funded by the year's funds flow of $86.35 million plus the issuance of trust units valued at $65.14 million.



Financial Highlights

($ millions, except for per unit amounts) 2009 2008 2007
----------------------------------------------------------------------------
Petroleum and natural gas revenue 155.99 229.49 155.51
Funds flow from operating activities 86.35 106.91 79.84
Per unit - diluted 3.64 5.18 4.08
Cash flows from operating activities 88.83 110.12 76.30
Per unit - diluted 3.74 5.34 3.90
Net earnings 2.72 68.29 24.55
Per unit - diluted 0.13 3.80 1.45
Total assets 464.38 447.60 343.11
Net capital expenditures (1) 104.59 119.73 66.67
Bank debt 76.58 77.58 56.87
Cash distributions 45.96 39.09 36.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts include capital expenditures for corporate and property
acquisitions acquired for cash consideration, equity issuances, net debt
assumed and are also inclusive of transaction costs.


Cash Distributions

Cash distributions to unitholders are at the discretion of the Board of Directors and can fluctuate depending on funds flow from operating activities. The Trust's capital program is financed from available funds flow, equity issuances 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 oil and liquids (2009 - 51 percent) and natural gas (2009 - 49 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. Monthly distributions remained constant throughout 2009 at $0.18 per trust unit and have been maintained at this level since November 2005. In particular, realized price risk management gains of $27.69 million provided support in enabling Zargon to maintain distributions during the overall commodity price declines in 2009. Cash distributions to unitholders declared for 2009 totalled $45.96 million. For a further discussion, see the "Liquidity and Capital Resources" section of this report.

For Canadian income tax purposes, the 2009 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 and natural gas liquids) and natural gas. Petroleum and natural gas revenue, exclusive of the impact of financial risk management contracts, decreased 32 percent to $155.99 million in 2009 from $229.49 million in 2008 primarily due to decreased commodity prices throughout 2009 despite an increase in overall production. Compared to the prior year, the relative weighting of production revenue between petroleum and natural gas in 2009 was reallocated due to commodity pricing with 71 percent of the revenues coming from the sale of oil and liquids (62 percent in 2008) and 29 percent coming from the sale of natural gas (38 percent in 2008). Average production volumes on a barrel of oil equivalent basis in 2009 increased seven percent to 9,856 barrels of oil equivalent per day from the prior year amount of 9,252 barrels of oil equivalent per day. Specifically, in 2009, natural gas production decreased three percent and oil and liquids production increased 17 percent over 2008 levels. Production volume increases in oil and liquids resulted primarily from the 2009 second quarter corporate acquisition of Masters Energy Inc. ("Masters"), the third quarter corporate acquisition of Churchill Energy Inc. ("Churchill") and a successful Williston Basin oil exploitation program. Overall natural gas production decreases resulted from natural production declines that were not offset by drilling activity due to Zargon's relatively quiet natural gas field capital program, but were supported by additional natural gas volumes acquired in the Masters and Churchill corporate acquisitions. The average field price of oil and liquids received by Zargon decreased to $59.89 per barrel in 2009, down 33 percent from $89.65 per barrel in 2008. The average Zargon realized field price of natural gas was $4.32 per thousand cubic feet in 2009, a 47 percent decrease from $8.12 per thousand cubic feet in 2008.



Pricing

Average for the year 2009 2008 2007
----------------------------------------------------------------------------
Natural Gas:
NYMEX average daily spot price ($US/mmbtu) 3.90 8.88 6.98
AECO average daily spot price ($Cdn/mmbtu) 3.96 8.16 6.45
Zargon realized field price before the impact of
financial risk management contracts ($Cdn/mcf) 4.32 8.12 6.40
Zargon realized field price before the impact of
physical and financial risk management contracts
($Cdn/mcf) 3.80 8.06 6.26
Zargon realized field price after the impact of
physical and financial risk management contracts
($Cdn/mcf) 4.74 8.10 6.82
Zargon realized natural gas field price
differential/(premium) (1) (0.36) 0.04 0.05
Zargon realized natural gas field price differential
before the impact of physical and financial risk
management contracts 0.16 0.10 0.19
Crude Oil:
WTI ($US/bbl) 61.80 99.65 72.31
Edmonton par price ($Cdn/bbl) 65.87 102.16 76.35
Zargon realized field price before the impact of
financial risk management contracts ($Cdn/bbl) 59.89 89.65 64.71
Zargon realized field price after the impact of
financial risk management contracts ($Cdn/bbl) 72.55 79.82 64.54
Zargon realized oil field price differential (2) 5.98 12.51 11.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Calculated as Zargon's realized field price before the impact of
financial risk management contracts ($Cdn/mcf) as compared to AECO
average daily spot price ($Cdn/mmbtu). Note: premiums may occur as a
result of the realization of fixed price physical contracts and the
impact of Zargon receiving AECO monthly index pricing for a portion of
its natural gas production.

(2) Calculated as Zargon's realized field price before the impact of
financial risk management contracts ($Cdn/bbl) as compared to Edmonton
par price ($Cdn/bbl).


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 2009, Zargon's average oil and liquids field price, exclusive of the impact of financial risk management contracts, decreased 33 percent to $59.89 per barrel from $89.65 per barrel in 2008 and was seven percent lower than the $64.71 per barrel received in 2007. The field price differential for Zargon's average blended 30 degree API crude stream was $5.98 per barrel less than the 2009 Edmonton reference crude price, which compares to the 2008 differential of $12.51 per barrel and the 2007 differential of $11.64 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. Oil and natural gas liquids transportation expenses are included in production expenses and are defined by the point of legal transfer of the product.

Natural Gas Pricing

The average field natural gas price, exclusive of the impact of financial risk management contracts, for 2009 decreased to $4.32 per thousand cubic feet, which is 47 percent lower than the 2008 average of $8.12 per thousand cubic feet and 33 percent lower than the 2007 average of $6.40 per thousand cubic feet. Historically, Zargon's field prices have shown a small discount to the benchmark AECO average daily price due to the cost of the transmission of natural gas within Alberta. The 2009 field price differential for Zargon's natural gas before the impact of physical and financial risk management contracts was a discount of $0.16 per thousand cubic feet, compared to discounts of $0.10 and $0.19 per thousand cubic feet in 2008 and 2007, respectively. In 2009, the various fixed price physical contracts, which are treated as part of natural gas production revenue and natural gas pricing, created a gain of $5.03 million (2008 - $0.48 million), equivalent to an increase of $0.48 per thousand cubic feet (2008 - $0.04 per thousand cubic feet).

Approximately six percent of Zargon's 2009 natural gas production (2008 - 18 percent) 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, costless collars and other instruments for up to a 24 month term and for up to 30 percent of the combined oil and natural gas working interest production volumes. 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.

For 2009, the total realized risk management gain was $27.69 million; compared to a loss of $15.72 million in 2008 and a gain of $4.26 million in 2007. Of the 2009 gain, $4.34 million (equivalent to an increase of $0.41 per thousand cubic feet) is related to a gain from natural gas financial risk management transactions, $23.36 million (equivalent to an increase of $12.66 per barrel) related to gains from oil financial risk management transactions (foreign exchange contracts are considered in conjunction with the oil contracts) and $0.01 million is related to a loss from electricity risk management transactions. Oil swaps and collars are settled against the NYMEX WTI pricing index, whereas natural gas swaps, collars and puts are settled against the AECO monthly pricing index. Electricity swaps are settled against the AESO pricing index. In 2009, NYMEX WTI crude oil prices rose throughout the first half of the year before holding relatively steady for the remainder of the year. AECO natural gas prices continued to trend lower throughout the first eight months, finding its low for the August month before beginning to trend upwards. These lower prices, relative to the respective risk management contracts, resulted in overall year-to-date realized risk management gains for 2009.

Zargon's management considers financial risk management 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 2009 net unrealized risk management loss totalled $36.39 million, which compares to a $44.38 million net unrealized risk management gain in 2008 (2007 - $16.80 million loss). Specifically, the 2009 net unrealized risk management losses resulted from financial oil contract losses ($34.70 million), financial natural gas contract losses ($2.87 million) and financial electricity contract losses ($0.13 million) and were offset by financial foreign exchange contract gains ($1.31 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 accumulated earnings 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 2009, total royalties were $27.42 million, a decrease of 41 percent from $46.64 million in 2008. The variations in royalty rates generally track changes in production volumes and prices. Commencing in 2009, the oil and natural gas royalty structure changed for Alberta production volumes. Further discussion regarding this issue is provided later in this report under the heading "Capital Expenditures". Reflecting the relatively lower commodity prices and modified royalty structure, on a consolidated basis, royalties, as a percentage of gross revenue, were 17.6 percent in 2009 (18.2 percent excluding revenue that does not attract royalty expenses) compared to 20.3 percent in 2008 and 21.1 percent in 2007. On a commodity basis, natural gas royalties averaged 10.4 percent in 2009, a decrease from the previous year's average of 19.7 percent, resulting primarily from lower royalties associated with lower natural gas pricing under the modified Alberta royalty structure. Oil royalties averaged 20.5 percent, down slightly from the prior year rate of 20.7 percent. The decrease in oil royalties is primarily related to initial low royalty rate incentives on certain new oil production wells in Saskatchewan and Alberta.

During 2009, 49 percent (2008 - 58 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 $1.08 million in 2009, down from $1.63 million in the prior year and from $1.10 million in 2007, reflecting the trend in Saskatchewan oil revenues. North Dakota state taxes decreased to $0.97 million in 2009 from $2.47 million in the prior year primarily due to decreased sales revenue (lower oil prices received) and decreased oil production and sales for the US operations.

Production Expenses

Zargon's production expenses increased 19 percent to $47.56 million in 2009 from $39.91 million in 2008, reflecting, in part, the addition of higher cost properties acquired in recent corporate acquisitions. On a per unit of production basis, production expenses increased 12 percent to $13.22 per barrel of oil equivalent from $11.79 in 2008 ($10.44 in 2007).

Natural gas production expenses in 2009 rose 38 percent to $2.14 per thousand cubic feet from $1.55 per thousand cubic feet in 2008. The primary reasons for the increase are decreased natural gas production volumes, increased third party natural gas gathering and processing fees and increased water disposal and water hauling costs. These increased costs reflect the impact of additional natural gas volumes being processed through non-operated third party natural gas gathering and processing facilities.

Oil production expenses decreased in 2009 to $13.56 per barrel, a decrease of seven percent from $14.63 per barrel in 2008. The primary reason for the decrease is due to increased production volumes, which more than offset charges due to increased workovers and increased repairs and annual maintenance programs.

In 2009, 2008 and 2007, 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 oil and natural gas price declines. In particular, operating costs averaged $13.09 per barrel of oil equivalent in the fourth quarter of 2009 down from $13.18 per barrel of oil equivalent in the 2009 third quarter. For 2010, Zargon anticipates a continued moderation in upward cost pressures and anticipates maintaining operating costs in the $13.00 to $14.00 per barrel of oil equivalent range.

Operating Netbacks

The average oil and liquids price received, after realized risk management gains/losses, in 2009 of $72.55 per barrel was nine percent lower than the $79.82 per barrel received in 2008. The average natural gas price received, after realized risk management gains/losses, in 2009 of $4.74 per thousand cubic feet was 41 percent below the $8.10 per thousand cubic feet received in 2008. Operating netbacks decreased commensurately. Supported by realized risk management gains, oil and liquids netbacks were relatively even at $46.72 per barrel up slightly from $46.60 per barrel in 2008. Natural gas netbacks decreased 57 percent to $2.15 per thousand cubic feet from $4.95 per thousand cubic feet in 2008. On a barrel of oil equivalent basis, 2009 operating netbacks decreased 20 percent to $30.22 from $37.56 in 2008.



Operating Netbacks

2009 2008
----------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 59.89 4.32 89.65 8.12
Realized risk management gain/(loss) 12.66 0.42 (9.83) (0.02)
Royalties (12.27) (0.45) (18.59) (1.60)
Production costs (13.56) (2.14) (14.63) (1.55)
----------------------------------------------------------------------------
Operating netbacks 46.72 2.15 46.60 4.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------


General and Administrative Expenses

Gross general and administrative costs increased 26 percent in 2009 to $17.38 million from $13.80 million in 2008. On a per unit of production basis, net general and administrative costs increased 24 percent to $3.83 per barrel of oil equivalent compared to $3.08 per barrel of oil equivalent in 2008 and $2.63 in 2007. Trending upwards from 2007 and 2008, the 2009 increased general and administrative costs on a per unit of production basis is primarily due to additional office lease costs associated with corporate acquisitions, amounts recorded for year end performance-based compensation and costs related to the expansion of Zargon's technical staff and consultants as Zargon repositions itself for its expanded exploitation and acquisition initiatives. The 2009 expenses included approximately $0.19 per barrel of equivalent of one-time employment related charges.



General and Administrative Expenses

($ millions, except as noted) 2009 2008 2007
----------------------------------------------------------------------------
Gross general and administrative expenses 17.38 13.80 11.69
Overhead recoveries (3.61) (3.35) (3.48)
----------------------------------------------------------------------------
Net general and administrative expenses 13.77 10.45 8.21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net expense after recoveries ($/boe) 3.83 3.08 2.63
Number of office employees at year end 57 53 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest and Financing Charges

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges were $3.02 million compared to $4.91 million in 2008 and $3.07 million in 2007. A decrease in the average debt level and lower borrowing costs for the first half of 2009 (prior to renewal of Zargon's credit facilities) are the primary reasons for the decrease in interest and financing charges. In particular, bank debt levels were decreased in June 2009, when the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of equity issuance expenses). Zargon's effective interest and financing charge rate was 3.5 percent on an average outstanding bank debt of $85.38 million in 2009, compared to 5.2 percent on an average bank debt of $95.07 million in 2008 and 6.2 percent on an average bank debt of $49.86 million in 2007. At year end 2009, Zargon's bank debt, net of working capital (excluding unrealized risk management assets/liabilities and future income taxes), totalled $88.01 million, up slightly from $87.71 million at December 31, 2008. This increase reflected the net debt acquired and cash consideration paid in the corporate acquisitions of Masters Energy Inc. and Churchill Energy Inc., which was mostly offset by the application of proceeds from the trust unit offering. For more information on Zargon's credit facilities, see the "Bank Debt" section of this report.

Current Income Taxes

Current income taxes for 2009 were $2.49 million compared to $4.05 million in 2008. Of the total, $2.21 million is due to current taxes incurred in the United States compared to $3.08 million in 2008. On a year-over-year comparison, current income taxes have decreased due to a reduction in 2009 taxable income in the United States related to lower revenue attributed to relatively lower oil prices in 2009. The remaining current tax amounts relate to withholding taxes on US dividends declared from Zargon's US subsidiary to its parent corporation and Canadian provincial capital taxes, which, in aggregate, totalled $0.28 million in 2009 compared to $0.97 million in 2008.

Tax pools as at December 31, 2009 were approximately $293 million, which represents an increase from the comparable $188 million of tax pools available to Zargon at the end of 2008, primarily due to the tax pools acquired in the Masters and Churchill acquisitions. 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 a further discussion on the Trust's conversion plans, see the "Future Income Taxes" section later in this report.

For Canadian income tax purposes, 2009 cash distributions are 100 percent taxable income to unitholders.

Trust Netbacks

Lower oil and natural gas prices in 2009 were supported by realized risk management gains resulting in relatively strong revenue netbacks and operating netbacks. On a barrel of oil equivalent basis, revenue of $43.36 in 2009 was 36 percent lower than the prior year and operating netbacks, as well as funds flow netbacks, decreased 20 percent and 24 percent, respectively, from the prior year to $30.22 and $24.01 per barrel of oil equivalent, respectively.



Trust Netbacks

($/boe) 2009 2008 2007
----------------------------------------------------------------------------
Petroleum and natural gas revenue 43.36 67.77 49.77
Realized risk management gain/(loss) 7.70 (4.65) 1.36
Royalties (7.62) (13.77) (10.48)
Production costs (13.22) (11.79) (10.44)
----------------------------------------------------------------------------
Operating netbacks 30.22 37.56 30.21
General and administrative (3.83) (3.08) (2.63)
Interest and financing charges (0.84) (1.45) (0.98)
Asset retirement expenditures (0.85) (0.26) (0.36)
Current income taxes (0.69) (1.20) (0.69)
----------------------------------------------------------------------------
Funds flow netbacks 24.01 31.57 25.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Funds Flow from Operating Activities

In 2009, production volume increases of seven percent on a barrel of oil equivalent basis were more than offset by decreased revenue of 36 percent per barrel of oil equivalent and the increase in cash operating costs during the year to produce a 19 percent decrease in funds flow from operating activities to $86.35 million, compared to $106.91 million in 2008 and $79.84 million in 2007. The corresponding funds flow per diluted unit was $3.64 in 2009, a 30 percent decrease from $5.18 in 2008 and an 11 percent decrease from $4.08 in 2007. The diluted per unit statistics reflect a 15 percent increase in the weighted average outstanding units to 23.75 million in 2009 from 20.63 million in 2008. The 2008 weighted average outstanding units were also six percent higher than the 2007 amount of 19.55 million.

The following table summarizes the variances in funds flow from operating activities between 2008 and 2009. It demonstrates that the variance (decrease in funds flow from operating activities) is caused primarily by a decrease in realized commodity prices and increased operating expenses despite increased production volumes, increased realized risk management gains and decreased royalties.



$ Per Per Unit
Diluted Percent
$ Million Trust Unit Variance
----------------------------------------------------------------------------
Funds flow from operating activities - 2008 106.91 5.18 -
Price variance (83.08) (3.50) (68)
Volume variance 9.56 0.40 8
Realized risk management gains 43.41 1.83 35
Royalties 19.22 0.81 16
Expenses:
Production (7.65) (0.32) (6)
General and administrative (3.32) (0.14) (3)
Interest and financing charges 1.90 0.08 2
Asset retirement expenditures (2.16) (0.09) (2)
Current taxes 1.56 0.07 1
Weighted average trust units - diluted - (0.68) (13)
----------------------------------------------------------------------------
Funds flow from operating activities - 2009 86.35 3.64 (30)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion and Depreciation

In 2009, Zargon's depletion and depreciation provision increased nine percent to $64.72 million, compared to $59.64 million in 2008 and $48.41 million in 2007. The higher charges reflect an increase of seven percent in production volumes and a two percent increase in the charge on a per barrel of oil equivalent basis. 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 2009 depletion calculation includes $7.80 million of future capital expenditures to develop the Trust's reserves, but excludes $24.37 million of unproven properties relating to undeveloped land.

Zargon's depletion and depreciation, on a barrel of oil equivalent basis, increased two percent in 2009 to $17.99 from $17.61 in 2008 and also increased 16 percent from the 2007 rate of $15.49.

Accretion of Asset Retirement Obligations

For the year ended December 31, 2009, the non-cash accretion expense for asset retirement obligations was $2.74 million compared to $2.18 million in 2008 and $1.41 million in 2007. 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 wells acquired with the recent Masters and Churchill corporate acquisitions. 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 2019. The estimated net present value of the total asset retirement obligation is $35.47 million as at December 31, 2009, based on a total future liability of $164.58 million.

Unit-Based Compensation

Unit-based compensation was $1.26 million in 2009, $0.07 million higher than the $1.19 million expense in 2008. The increase in the current year expense is a result of the timing of 2009 grants and a general increase in the valuation of these new 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 has a unit rights incentive plan (the "Old Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and other service providers. On April 22, 2009, a new unit rights incentive plan (the "New Plan") was approved. The Trust is authorized to issue up to an aggregate of 2.13 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 Old Plan or the New Plan (the "modified price"). Under the Old Plan, the modified price was based on the increment of the amount the monthly distribution exceeded a monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the Old Plan). Under the New Plan, if the monthly distribution exceeds the monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the New Plan), the entire amount (not the increment) of the distribution is deducted from the original grant price. Rights granted under either 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.

Unrealized Foreign Exchange

Unrealized foreign exchange losses of $0.18 million in 2009 compare to gains of $1.96 million for 2008. Gains and losses result from translations of Zargon's US subsidiaries into Canadian dollars at rates as determined under the temporal method of converting foreign subsidiaries as required by Canadian GAAP. The volatility in the US/Cdn dollar has created non-cash translation gains/losses as recorded in Zargon's income statement.

Future Income Taxes

The provision for the future tax recovery for 2009 was $18.95 million when compared to a future tax expense of $12.75 million in 2008 and a recovery of $15.47 million in 2007. 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 2009 future tax recovery, when compared to the 2008 prior year expense, is significantly impacted by the decrease in earnings before income taxes for the period as a result of previously mentioned items such as decreased commodity prices and increased unrealized risk management losses.

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 would have resulted in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. Subsequent 2007 fourth quarter legislation lowered this tax rate to 29.5 percent in 2011 and 28.0 percent beyond 2011. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes to have a nil effective tax rate. On February 26, 2008, the Federal Government, in its Federal Budget, announced further changes to the specified investment flow through ("SIFT") tax rules. The provincial component of the SIFT tax will be based on the provincial rates where the SIFT has a permanent establishment rather than using a 13.0 percent flat provincial rate. During the 2009 first quarter this tax rate change had been substantively enacted, and the future income tax impact has been recorded in the financial statements. Under the legislation, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be approximately 26.5 percent for 2011 and 25.0 percent thereafter. 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.

On December 15, 2006, the Canadian Federal Department of Finance stated its intention to allow conversions of SIFT income trusts to a corporation without any adverse tax consequences to investors. On July 14, 2008, the Department of Finance released the draft legislative proposals to allow the conversion of these SIFT trusts into corporations. Zargon is currently reviewing and assessing this recent legislation and is considering its potential impact on the organization while Zargon's management develops its strategic plan beyond December 2010, which is the effective date of the new SIFT tax rules. Zargon's current plans are to convert from its trust structure to a corporation at the end of 2010 or early in 2011. Zargon's management continues to believe that a partial cash flow distributing model is an effective model to produce conventional oil and gas assets in our relatively mature sedimentary basins, and as such plans to distribute regular dividends under the corporate structure.

Non-Controlling Interest - Exchangeable Shares

According to the January 19, 2005 CICA pronouncement, EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", Zargon Energy Trust must reflect the exchangeable securities issued by its subsidiary, Zargon Oil & Gas Ltd. as 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. Prior to 2005, these exchangeable shares were reflected as a component of unitholders' equity.

Accordingly, the Trust has increased its unitholders' equity and non-controlling interest for 2009 by $1.04 million (2008 - $12.52 million) on the Trust's consolidated balance sheets. Consolidated net earnings for 2009 have been reduced for net earnings attributable to the non-controlling interest by $0.34 million (2008 - $10.10 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 2009, resulted in an additional increase in property and equipment of $0.97 million (2008 - $3.39 million) and an increase in the future income tax liability of $0.27 million (2008 - $0.97 million). Funds flow from operating activities 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 $56.13 million (for depletion impact see note 5 in the audited consolidated financial statements), unitholders' equity and non-controlling interest by $66.91 million, future income tax liability by $18.46 million and an allocation of net earnings to exchangeable shareholders of $29.24 million.

Net Earnings

Zargon's 2009 net earnings were $2.72 million, a 96 percent decrease from $68.29 million in 2008. The 2007 net earnings were $24.55 million. The net earnings track the funds flow from operating activities for the respective periods modified by asset retirement expenditures and non-cash charges, which, in 2009; includes depletion and depreciation, unrealized risk management gains/losses, future income tax expenses/recoveries, unit-based compensation and non-controlling interest. On a per diluted unit basis, 2009 net earnings were $0.13 compared to net earnings of $3.80 in 2008 and $1.45 in 2007.

The 2009 net earnings were three percent of funds flow from operating activities, primarily reflecting the increase in non-cash charges (net of tax) such as unrealized risk management losses and depletion. The 2008 net earnings represented 64 percent of funds flow from operating activities compared to 31 percent of funds flow from operating activities in 2007.

Capital Expenditures

Total net capital expenditures (including net property acquisitions, cash and equity consideration and net debt assumed for corporate acquisitions) in 2009 of $104.59 million decreased 13 percent from $119.73 million in 2008, and was highlighted by $56.34 million attributed to the corporate acquisitions of Masters and Churchill. Zargon's field capital expenditure program also declined 13 percent in 2009 to $46.45 million from the $53.35 million 2008 field capital expenditure program. In 2009, Zargon drilled 29 gross (25.7 net) wells compared to 39 gross (35.9 net) wells in 2008 and, as a result, drilling and completion expenditures decreased commensurately by 21 percent to $21.94 million. Of the total 2009 field capital expenditures (excluding corporate and net property acquisitions), $8.67 million were expended on West Central Alberta, $18.29 million on Alberta Plains and $19.49 million on Williston Basin properties. Additionally, $0.76 million was incurred corporately on leasehold improvements and administrative assets and $57.38 million was attributed to the corporate and net property acquisitions. Field capital expenditures for the 2009 year are net of $2.40 million and $0.40 million in Alberta drilling credits in the respective Alberta Plains and West Central Alberta core areas. Alberta drilling credits are designed to encourage the execution of new drilling projects in Alberta and were announced in response to the slow-down in drilling throughout the province. The drilling credit is based on a $200 per metre credit on total metres drilled with a cap based on production levels and Alberta Crown royalties paid.



Capital Expenditures

($ millions) 2009 2008 2007
----------------------------------------------------------------------------
Undeveloped land 5.60 8.14 7.49
Geological and geophysical (seismic) 3.71 4.44 4.41
Drilling and completion of wells 21.94 27.66 33.15
Well equipment and facilities 15.20 13.11 18.49
----------------------------------------------------------------------------
Exploration and development 46.45 53.35 63.54
----------------------------------------------------------------------------
Property acquisitions (1) 1.17 6.41 3.04
Property dispositions (0.13) (0.22) (1.18)
----------------------------------------------------------------------------
Net property acquisitions/(dispositions) (1) 1.04 6.19 1.86
----------------------------------------------------------------------------
Corporate acquisitions assigned to property and
equipment (2) 56.34 59.85 -
----------------------------------------------------------------------------
Total net capital expenditures excluding
administrative assets (1) (2) 103.83 119.39 65.40
Administrative assets 0.76 0.34 1.27
----------------------------------------------------------------------------
Total net capital expenditures (1) (2) 104.59 119.73 66.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

(2) Amounts include capital expenditures acquired for cash, equity
issuances, acquisition costs and net debt assumed on corporate
acquisitions.


CORPORATE ACQUISITIONS

On April 29, 2009, a subsidiary of the Trust acquired all of the issued and outstanding common shares of Masters Energy Inc. ("Masters"), a public oil and gas company, for a total consideration of 1,475,468 Zargon trust units, $5.70 million in cash and the assumption of approximately $13.29 million of net debt (including adjustments and transaction costs) for a total transaction value of $40.03 million.

The results of operations for Masters have been included in the consolidated financial statements since April 29, 2009. In relation to the 2009 year, the Masters acquisition has contributed approximately 697 barrels of oil equivalent per day of production volumes to Zargon's total average production volumes of 9,856 barrels of oil equivalent per day and has provided a significant Alkaline Surfactant Polymer (ASP) tertiary oil recovery opportunity at the Little Bow oil property in Southern Alberta.

On September 23, 2009, a subsidiary of the Trust acquired all of the issued and outstanding shares of Churchill Energy Inc. ("Churchill"), a public oil and gas company, for a total consideration of 554,669 Zargon trust units, $0.11 million in cash and the assumption of approximately $6.85 million of net debt (including adjustments and transaction costs) for a total transaction value of approximately $16.31 million. This acquisition brought oil exploitation opportunities at Grand Forks and Brazeau, Alberta along with significant tax pools.

The results of operations for Churchill have been included in the consolidated financial statements since September 23, 2009. In relation to the 2009 year, the Churchill acquisition has contributed approximately 87 barrels of oil equivalent per day of production volumes to Zargon's total average production volumes of 9,856 barrels of oil equivalent per day.

LIQUIDITY AND CAPITAL RESOURCES

In 2009, the summation of the funds inflows coming from the funds flow from operating activities ($86.35 million) plus the issuance of trust units ($65.14 million - arising from the acquisitions of Masters and Churchill, the equity issuance and unit right exercises) exceeded the summation of the funds outflows pertaining to the net capital expenditure program ($104.59 million) and the cash distributions to unitholders ($45.96 million) by $0.94 million.

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

- Internally generated funds flow from operating activities 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, 2009, the Trust had $180 million in syndicated committed credit facilities of which $102.81 million or 57 percent of these facilities were unutilized.

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

The volatility of oil and natural gas prices, the changes relating to Alberta royalties and Canadian income trust tax rules and global economic concerns have partially restricted the oil and natural 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 enabled Zargon to fund its capital and distribution programs during 2009.

On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of equity issuance costs). The net proceeds of the offering were used to reduce outstanding borrowings under existing credit facilities, and, in turn, were also used to partially fund the 2009 capital expenditure program and for general corporate purposes.



Cash Distributions Analysis

($ millions) 2009 2008 2007
----------------------------------------------------------------------------
Cash flows from operating activities 88.83 110.12 76.30
Net earnings 2.72 68.29 24.55
Actual cash distributions paid or payable relating
to the period (45.96) (39.09) (36.70)
----------------------------------------------------------------------------
Excess of cash flows from operating activities over
cash distributions paid 42.87 71.03 39.60
Excess (shortfall) of net earnings over cash
distributions paid (43.24) 29.20 (12.15)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the twelve months of 2009, Zargon has maintained a base monthly distribution of $0.18 per trust unit. 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 and the Trust's ability to manage costs, are the main factors influencing the sustainability of the Trust's distributions.

For the year ended December 31, 2009, cash flows from operating activities (after changes in non-cash working capital) of $88.83 million exceeded cash distributions of $45.96 million. This was consistent with the year ended December 31, 2008, in which cash flows from operating activities (after changes in non-cash working capital) of $110.12 million exceeded cash distributions of $39.09 million.

For the year ended December 31, 2009, cash distributions of $45.96 million exceeded net earnings of $2.72 million. Net earnings include significant non-cash charges ($86.69 million in 2009), particularly unrealized risk management losses and depletion and depreciation that do not impact cash flows. For the year ended December 31, 2008, cash distributions of $39.09 million were exceeded by net earnings of $68.29 million. Net earnings also include fluctuations in future income taxes due to changes in tax rates and tax rules. In addition, other non-cash charges such as depletion and depreciation are not a good proxy for the cost of maintaining Zargon's productive capacity given the natural declines associated with crude oil and natural gas assets. In 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, 2009, cash distributions and net capital expenditures totalled $150.55 million ($120.15 million excluding the $30.40 million of equity issuances attributed to corporate acquisitions), which was $61.72 million higher than cash flows from operating activities (after changes in non-cash working capital) of $88.83 million. For the year ended December 31, 2008, cash distributions and net capital expenditures totalled $158.82 million, which was $48.70 million higher than cash flows from operating activities (after changes in non-cash working capital) of $110.12 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 fund cash distributions or dividends and capital expenditures with its cash flows from operating activities; however, it will continue to fund acquisitions and growth through additional debt and equity issuances. In the crude oil and natural gas industry, because of the nature of reserve reporting, the natural reservoir declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities, therefore, maintenance capital is not disclosed separately from development capital spending.



Capital Sources and Uses

($ millions) 2009 2008 2007
----------------------------------------------------------------------------
Funds flow from operating activities 86.35 106.91 79.84
Change in bank debt (1.00) 20.71 26.83
Issuance of trust units 65.14 25.08 2.13
Cash distributions to unitholders (45.96) (39.09) (36.70)
Changes in working capital and other 0.06 6.12 (5.43)
----------------------------------------------------------------------------
Total capital sources 104.59 119.73 66.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Funds Flow from Operating Activities

It is anticipated that Zargon's 2010 exploration and development capital budget and cash distributions to unitholders will be financed through the Trust's funds flow from operating activities 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 2010 estimated sensitivity to moderate fluctuations in these key business parameters is shown in the accompanying table.



Funds Flow Sensitivity Summary

Change in 2010 Funds Flow
($ millions) ($/unit)
----------------------------------------------------------------------------
Change of $1.00 US/bbl in the price of WTI oil 1.75 0.07
Change in oil production of 100 bbl/d 2.07 0.08
Change of $0.10 US/mcf in the price of NYMEX natural gas 0.71 0.03
Change in natural gas production of one mmcf/d 1.56 0.06
Change of $0.01 in the $US/$Cdn exchange rate 1.81 0.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Bank Debt

On July 27, 2009, Zargon amended and renewed its syndicated committed credit facilities, the result of which was the maintaining of the available facilities and borrowing base of $180 million. These facilities consist of a $170 million tranche available to the Canadian borrower and a US $8 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. The facilities are fully revolving for a 336 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 June 29, 2010. Should the facilities not be renewed, they convert to one year non-revolving term facilities at the end of the revolving 336 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. These facilities continue to be available for general corporate purposes and the potential acquisition of additional oil and natural gas properties such as those most recently acquired through the corporate acquisitions of Masters Energy Inc. and Churchill Energy Inc. which were funded by bank debt and equity issuances. Zargon reviews its compliance with its bank debt covenants on a quarterly basis and has no violations as at December 31, 2009. Zargon's management is planning to convert to a corporation from its current trust structure towards the end of 2010. In order for this conversion to occur Zargon would have to ensure that all legal and regulatory requirements are satisfied and would be required to obtain the consent of the lenders under Zargon's current syndicated credit facility.

Through to the 2010 renewal, it is anticipated that Zargon's borrowing costs will be higher as general debt pricing, standby fees and extension fees have risen considerably in the current economic environment. Interest rates fluctuate under the syndicated facilities with Canadian prime, US prime and US base rates plus an applicable margin between 125 basis points and 275 basis points (2008 - zero and 32.5 basis points, respectively), as well as with Canadian banker's acceptance and LIBOR rates plus an applicable margin between 275 basis points and 425 basis points (2008 - 97.5 and 157.5 basis points, respectively).

At December 31, 2009, $76.58 million (December 31, 2008 - $77.58 million) had been drawn on the syndicated committed credit facilities with any unused amounts subject to standby fees. The net change in bank debt was nominal, as any requirements to borrow for Zargon's general corporate purposes and corporate and property acquisitions were offset by Zargon's June 2009 equity issuance of trust units.

In the normal course of operations, Zargon enters into various letters of credit. At December 31, 2009, the approximate value of outstanding letters of credit totalled $0.61 million (December 31, 2008 - $0.52 million).

Zargon's debt net of working capital (excluding unrealized risk management assets/liabilities and future income taxes) of $88.01 million at December 31, 2009 was equivalent to 102 percent of the 2009 funds flow from operating activities of $86.35 million. At December 31, 2008, the debt net of working capital (excluding unrealized risk management assets/liabilities and future income taxes) was $87.71 million, equivalent to 82 percent of the 2008 funds flow from operating activities of $106.91 million.

Equity

At March 9, 2010, Zargon Energy Trust had 23.219 million trust units and 1.768 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective March 9, 2010 exchange ratio of 1.66788, there would be 26.168 million trust units outstanding. Pursuant to the trust unit rights incentive plans, there are currently an additional 1.440 million trust unit incentive rights issued and outstanding.

During 2009, 12.047 million Zargon trust units traded on the Toronto Stock Exchange with a high trading price of $19.33 per unit, a low of $13.05 per unit and a closing price of $19.25 per unit. The 2009 trading statistics show a 20 percent year-over-year decrease in trading volume and a 10 percent increase in the closing unit price. Zargon's market capitalization (including the market value of exchangeable shares) at year end 2009, was approximately $501 million, compared to approximately $369 million at the end of 2008.

Segmented Geographic Information

During 2009, approximately 90 percent (2008 - 88 percent) of Zargon's combined petroleum and natural gas revenue came from Western Canadian (Alberta, Saskatchewan and Manitoba) properties, with the remaining 10 percent (2008 - 12 percent) of revenues generated in the United States (North Dakota). This shift in weighting is due to additional revenues generated from the Masters and Churchill corporate acquisitions which both were comprised of only Canadian oil and natural gas properties.



SELECTED QUARTERLY INFORMATION

($ millions,
except per unit
amounts) 2009 2008
----------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Petroleum and
natural gas
revenue 47.21 40.96 35.84 31.98 41.25 66.35 69.66 52.24
Funds flow from
operating
activities 24.75 22.84 20.92 17.85 20.40 29.75 32.02 24.75
Per unit -
diluted 0.95 0.90 0.91 0.84 0.97 1.42 1.55 1.23
Cash flows from
operating
activities 27.86 23.30 21.94 15.73 24.84 33.58 36.44 15.27
Per unit -
diluted 1.07 0.92 0.95 0.74 1.18 1.60 1.76 0.76
Net earnings 0.44 4.47 (2.55) 0.37 28.19 40.05 (4.51) 4.56
Per unit -
diluted 0.02 0.20 (0.13) 0.02 1.53 2.20 (0.25) 0.26
Cash
distributions 12.45 12.22 11.26 10.03 9.96 9.87 9.71 9.55
Per unit -
diluted 0.54 0.54 0.54 0.54 0.54 0.54 0.54 0.54
Net capital
expenditures 12.87 29.32 48.96 13.44 16.37 17.47 26.28 59.61
Total assets 464.38 473.47 466.60 440.76 447.60 426.63 418.88 396.90
Bank debt 76.58 77.05 70.43 85.78 77.58 74.95 85.45 92.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


FOURTH QUARTER 2009 RESULTS

During the fourth quarter of 2009, Zargon's petroleum and natural gas revenues of $47.21 million were 15 percent higher than the previous quarter's revenues. Production for the 2009 fourth quarter of 10,586 barrels of oil equivalent per day was five percent higher than the 2009 third quarter's production of 10,088 barrels of oil equivalent per day. Compared to the previous quarter, oil production increased two percent to 5,485 barrels per day as flush production was recognized from the tie-in of Williston Basin oil wells and from volumes gained from the acquisition of Churchill Energy Inc. being included for the full quarter. Fourth quarter natural gas production increased eight percent from the previous quarter to 30.60 million cubic feet per day as various shut-in wells were reactivated and due to the initial production rates from new natural gas in the Kakut area of West Central Alberta along with additional volumes recognized from the late 2009 third quarter acquisition of Churchill. Average field prices received during the fourth quarter, before the impact of financial risk management contracts, were $68.88 per barrel for oil and liquids and $4.42 per thousand cubic feet for natural gas, a six percent and a 29 percent increase, respectively, compared to the 2009 third quarter prices. Zargon's field price differential for its blended 30 degree API crude oil stream increased to a $7.68 per barrel discount to the Edmonton reference crude oil price, a 32 percent increase from Zargon's average differential of $5.80 per barrel for the first nine months of 2009.

Funds flow from operating activities was $24.75 million in the fourth quarter, an increase of eight percent or $1.91 million from the prior quarter. A comparative analysis of the primary factors that caused this quarter-over-quarter increase is as follows:

- Fourth quarter 2009 petroleum and natural gas revenues of $47.21 million were 15 percent higher than the 2009 third quarter revenues of $40.96 million. This revenue increase was a result of the 10 percent increase in average realized commodity prices and a five percent increase in average daily production volumes.

- Realized risk management gains were $5.78 million in the fourth quarter of 2009, a $1.05 million decrease from the prior quarter's $6.83 million of realized risk management gains. The quarter over quarter decrease, resulted from risk management contract expiries and increasing commodity prices. The fourth quarter net gains resulted from gains ($0.42 million) being realized on financial natural gas risk management contracts, gains ($5.38 million) realized on financial oil risk management contracts (foreign exchange contracts are considered in conjunction with the oil contracts) and losses ($0.02 million) realized on financial electricity management contracts. Oil and natural gas prices continued to strengthen during the 2009 fourth quarter.

- Royalties for the fourth quarter were $8.27 million, an increase of $0.71 million from the prior quarter. The average royalty rate for the quarter of 17.5 percent was below the 18.5 percent rate from the 2009 third quarter, as a result of additional low rate incentive wells, which were brought on production and some prior period adjustments.

- Production expenses were $12.75 million for the quarter, four percent higher than the third quarter of 2009. On a per barrel of oil equivalent basis, production expenses decreased one percent to $13.09 in the fourth quarter of 2009 compared to $13.18 in the prior quarter. This quarterly decline in per unit costs was due, in part, to increased production from new wells being tied-in, the reactivation of gas wells and initial production rates from new gas wells.

- General and administrative expenses increased in the fourth quarter by $0.75 million over the third quarter of 2009. This is a 25 percent increase compared to the prior quarter and is primarily due to amounts recorded for the year end performance-based compensation for employees.

- Interest and financing charges in the fourth quarter were $1.10 million, an increase of 38 percent or $0.30 million from the prior quarter. The average debt level for the fourth quarter increased 12 percent to $87.06 million compared to $77.56 million in the third quarter of 2009, resulting in increased debt servicing charges. Zargon's interest borrowing rates also increased during the quarter in-line with the borrowing pricing grid established under the terms of Zargon's credit facilities.

- Current income taxes of $0.91 million were $0.23 million higher than the 2009 third quarter taxes. The increase was primarily due to increased withholding taxes on dividends declared from Zargon's US subsidiary to its parent corporation.

- Asset retirement expenditures reflect the actual amounts incurred to abandon and reclaim unutilized non-producing wells. These asset retirement expenditures totalled $1.49 million in the 2009 fourth quarter and increased from the prior quarter amount of $0.69 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 incurrence of actual expenses during the period.

Net earnings for the quarter decreased $4.03 million to $0.44 million, a 90 percent decrease compared to the third quarter of 2009 net earnings of $4.47 million. Net earnings track the funds flow from operating activities for the respective periods modified by asset retirement expenditures and non-cash charges, which included the following for the fourth quarter of 2009:

- Unit-based compensation expense increased by $0.05 million during the fourth quarter of 2009 to $0.44 million, a 13 percent increase from the third quarter. The increase is a result of additional unit rights granted in the fourth quarter of 2009.

- Depletion and depreciation expense increased by $0.69 million to $17.50 million in the 2009 fourth quarter. The additional expense resulted from the increased production in the fourth quarter despite the use of an updated depletion and depreciation rate of $17.97 per barrel of oil equivalent, compared to the prior quarter's $18.12 per barrel of oil equivalent charge.

- Unrealized risk management losses in the 2009 fourth quarter of $12.97 million were 261 percent higher than the third quarter losses of $3.60 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 higher commodity pricing at the December 31, 2009 mark-to-market date when compared to the third quarter September 30, 2009 mark-to-market date. In particular, higher year end futures resulted in unrealized risk management contract oil losses of $11.31 million, natural gas contract losses of $0.42 million, electricity contract losses of $0.13 million and foreign exchange contract losses of $1.11 million. 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 2009 fourth quarter was $0.75 million, relatively even with the prior quarter expense. The small 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.

- Unrealized foreign exchange losses of $0.05 million in the 2009 fourth quarter compare to losses of $0.08 million for the prior quarter. Gains and losses result from translations of Zargon's US subsidiaries into Canadian dollars at rates as determined under the temporal method of converting foreign subsidiaries as required by Canadian GAAP. Relative to the closing foreign exchange rates at September 30, 2009, the increase in the value of the Canadian dollar relative to the US dollar has created nominal non-cash translation losses as recorded in Zargon's income statement for the fourth quarter.

- The future income tax recovery was $5.98 million during the quarter compared to a future income tax recovery of $3.13 million from the third quarter of 2009. The increased future income tax recovery in the 2009 fourth quarter was due to a significant increase of losses before taxes of $4.58 million compared to the third quarter earnings before taxes of $2.59 million. In summary, the fourth quarter losses before taxes were primarily a result of higher non-cash unrealized risk management contract losses in the quarter.

- Reduction in earnings due to non-controlling interests pertaining to exchangeable shares decreased to $0.06 million in the 2009 fourth quarter from $0.57 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 $12.87 million during the fourth quarter of 2009, a 56 percent decrease from the prior quarter amount of $29.32 million (which included $16.31 million for the Churchill acquisition). During the fourth quarter, Zargon completed a field capital program focused on the Alberta Plains core area Taber oil exploitation wells, a West Central Alberta natural gas exploration location and the Williston Basin core area horizontal oil exploitation wells. During the fourth quarter of 2009, 5.0 net wells (Williston Basin - 1.8 net wells, Alberta Plains - 3.0 net wells, West Central Alberta - 0.2 net wells) were drilled compared to 10.3 net wells in the third quarter of 2009.

Cash distributions to unitholders declared for the 2009 fourth quarter totalled $12.45 million ($0.18 per trust unit per month).



CONSOLIDATED BALANCE SHEETS
As at December 31 ($ thousands) 2009 2008
----------------------------------------------------------------------------
ASSETS (note 6)
Current
Accounts receivable 25,223 20,725
Prepaid expenses and deposits 2,013 1,162
Unrealized risk management asset (note 12) 4,289 29,641
Future income taxes (note 13) 1,714 -
----------------------------------------------------------------------------
33,239 51,528
Long term deposit 1,845 1,612
Unrealized risk management asset (note 12) - 4,745
Goodwill 2,969 2,969
Property and equipment, net (notes 4 and 5) 425,964 386,746
Future income taxes (note 13) 361 -
----------------------------------------------------------------------------
464,378 447,600
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities 34,507 28,687
Cash distributions payable (note 19) 4,157 3,326
Unrealized risk management liability (note 12) 6,032 724
Future income taxes (note 13) 1,219 8,553
----------------------------------------------------------------------------
45,915 41,290
Long term debt (note 6) 76,580 77,581
Unrealized risk management liability (note 12) 1,270 281
Asset retirement obligations (note 7) 35,468 28,592
Future income taxes (note 13) 30,327 49,704
----------------------------------------------------------------------------
189,560 197,448
----------------------------------------------------------------------------
Commitments and contingencies (notes 6, 8, 12, 14
and 15)
NON-CONTROLLING INTEREST
Exchangeable shares (note 9) 26,477 27,610
----------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (note 8) 188,840 120,650
Contributed surplus (note 8) 5,471 4,617
Accumulated earnings 259,823 257,104
Accumulated cash distributions (note 19) (205,793) (159,829)
----------------------------------------------------------------------------
248,341 222,542
----------------------------------------------------------------------------
464,378 447,600
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME AND ACCUMULATED
EARNINGS

For the years ended December 31
($ thousands, except per unit amounts) 2009 2008
----------------------------------------------------------------------------
REVENUE
Petroleum and natural gas revenue 155,985 229,494
Unrealized risk management gain/(loss) (note 12) (36,393) 44,378
Realized risk management gain/(loss) (note 12) 27,685 (15,722)
Royalties (27,422) (46,644)
----------------------------------------------------------------------------
119,855 211,506
----------------------------------------------------------------------------
EXPENSES
Production 47,564 39,913
General and administrative 13,769 10,447
Unit-based compensation (note 8) 1,263 1,185
Interest and financing charges (note 6) 3,015 4,911
Unrealized foreign exchange (gain)/loss 184 (1,958)
Accretion of asset retirement obligations (note 7) 2,744 2,183
Depletion and depreciation 64,715 59,638
----------------------------------------------------------------------------
133,254 116,319
----------------------------------------------------------------------------
EARNINGS/(LOSSES) BEFORE INCOME TAXES (13,399) 95,187
----------------------------------------------------------------------------
INCOME TAXES (note 13)
Current 2,492 4,051
Future tax expense/(recovery) (18,947) 12,751
----------------------------------------------------------------------------
(16,455) 16,802
----------------------------------------------------------------------------
EARNINGS BEFORE NON-CONTROLLING INTEREST 3,056 78,385
Non-controlling interest - exchangeable shares
(note 9) (337) (10,100)
----------------------------------------------------------------------------
NET EARNINGS AND COMPREHENSIVE INCOME 2,719 68,285

ACCUMULATED EARNINGS, BEGINNING OF YEAR 257,104 188,819
----------------------------------------------------------------------------
ACCUMULATED EARNINGS, END OF YEAR 259,823 257,104
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET EARNINGS PER UNIT (note 10)
Basic 0.13 3.79
Diluted 0.13 3.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31 ($ thousands) 2009 2008
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings for the year 2,719 68,285
Add (deduct) non-cash items:
Non-controlling interest - exchangeable shares 337 10,100
Unrealized risk management (gain)/loss 36,393 (44,378)
Depletion and depreciation 64,715 59,638
Accretion of asset retirement obligations 2,744 2,183
Unit-based compensation 1,263 1,185
Unrealized foreign exchange (gain)/loss 184 (1,958)
Future income tax expense/(recovery) (18,947) 12,751
Asset retirement expenditures (3,056) (897)
----------------------------------------------------------------------------
86,352 106,909
Changes in non-cash operating working capital
(note 16) 2,476 3,215
----------------------------------------------------------------------------
88,828 110,124
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Advances/(repayment) of bank debt (1,001) 3,799
Cash distributions declared to unitholders (45,964) (39,086)
Exercise of unit rights 1,295 1,166
Issuance of unitholders' capital, net of issue costs 33,444 -
Changes in non-cash financing working capital
(note 16) 831 252
----------------------------------------------------------------------------
(11,395) (33,869)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property and equipment (48,382) (58,944)
Proceeds on disposal of property and equipment 127 220
Corporate acquisitions (cash portion) (19,260) (16,835)
Long term deposit (233) (157)
Changes in non-cash investing working capital
(note 16) (9,685) (539)
----------------------------------------------------------------------------
(77,433) (76,255)
----------------------------------------------------------------------------
NET CHANGE IN CASH DURING THE YEAR AND CASH, END OF
YEAR - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See supplemental cash flow information contained in note 17.
See accompanying notes to the consolidated financial statements.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2009 and 2008

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

Revenue associated with the sale of crude oil, natural gas, and natural gas liquids is recognized when title and risks pass to the purchaser, normally at the plant gate which is the pipeline delivery point for natural gas and at the contracted delivery point for crude oil.

Joint Operations

A portion 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 plus the cost of unproved properties are charged to earnings. Reserves are determined pursuant to evaluation by independent engineers as dictated by National Instrument 51-101.

Goodwill

The Trust must record goodwill relating to a corporate acquisition when the total purchase price exceeds the fair value for accounting purposes of the net identifiable assets and liabilities of the acquired company. The goodwill balance is assessed for impairment annually at year end or as events occur that could result in an indication of impairment. Impairment is recognized based on the fair value of the reporting entity (consolidated Trust) compared to the book value of the reporting entity. If the fair value of the consolidated Trust is less than the book value, impairment is measured by allocating the fair value of the consolidated Trust to the identifiable assets and liabilities as if the Trust had been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value of the consolidated Trust over the amounts assigned to the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value of goodwill is the impairment amount. Impairment is charged to earnings in the period in which it occurs.

Goodwill is stated at cost less impairment and is not amortized.

At December 31, 2009 an impairment test was performed and it was determined that there was no impairment to the goodwill balance (December 31, 2008 - nil).

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

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 Canadian Institute of Chartered Accountants ("CICA") Handbook Section 3855.

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 other comprehensive income ("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.

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.

The Trust considers these financial risk management 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 collar and swap agreements are utilized to manage the risk inherent in producing commodities whose price is based directly or indirectly on US dollars, using notional principal amounts 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.

The Trust had no interest rate financial instruments at December 31, 2009 and 2008.

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 and accumulated earnings.

Trust Unit Rights and Unit-Based Compensation

Under the Trust's unit rights incentive plans (the "Plans"), rights to purchase trust units are allowed to be granted to directors, officers, employees and other service providers at current market prices. The Plans allow 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 if the rights have not yet vested.

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

Goodwill and Intangible Assets

On January 1, 2009, the Trust adopted the CICA Handbook Section 3064 "Goodwill and Intangible Assets", replacing Section 3062 "Goodwill and Other Intangible Assets". Under this new guidance, fewer items meet the criteria for capitalization. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Requirements concerning goodwill are unchanged from the requirements included in the previous Section 3062, as the new Section was only amended for intangible assets. The adoption of this Section did not significantly impact the Trust's consolidated financial statements.

Credit Risk and the Fair Value of Financial Instruments

Effective January 1, 2009, the Trust retrospectively adopted the recommendations of Emerging Issues Committee abstract 173 "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", which was issued in January 2009, without restatement of prior periods. The abstract requires that an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial assets and liabilities, including derivative instruments, for presentation and disclosure purposes. The adoption of the abstract did not significantly impact the Trust's consolidated financial statements.

Financial Instruments - Recognition and Measurement

Effective December 31, 2009, the Trust prospectively adopted the CICA amendments to Handbook Section 3855, "Financial Instruments - Recognition and Measurement." Amendments to this Section have prohibited the reclassification of a financial asset out of the held-for-trading category when the fair value of the embedded derivative in a combined contract cannot be reasonably measured.

Section 3855 was also amended with regards to the impairment of financial assets. The definition of "loans and receivables" has been revised and, provided that certain conditions have been met, the amendments permit reclassification of financial assets from the held-for-trading and available-for-sale categories into the loans and receivables category. The amendments also provide one method of assessing impairment for all financial assets regardless of classification. The adoption of the amendments to this standard did not have an impact on the Trust's consolidated financial statements.

Financial Instruments - Disclosure and Presentation

Effective December 31, 2009, the Trust adopted CICA issued amendments to Handbook Section 3862, "Financial Instruments - Disclosures." The amendments include enhanced disclosures relating to the fair value of financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 12 for enhanced fair value disclosures. The amendments are consistent with recent amendments to financial instrument disclosure standards in International Financial Reporting Standards.

Future Accounting Pronouncements

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

In December 2008, the CICA issued Section 1582 "Business Combinations", which will replace CICA Section 1581 of the same name. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price on the date of the exchange. Currently, the purchase price used is based on the market price of the shares for a reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. Currently, only contingent liabilities that are resolved and payable are included in the cost to acquire the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from the non-current assets in the purchase price allocation. Section 1582 will be effective for the Trust on January 1, 2011, with prospective application. The Trust is currently evaluating the impact of the adoption of the new Section on its consolidated financial statements.

In December 2008, the CICA issued Sections 1601 "Consolidated Financial Statements" and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards will be effective for the Trust on January 1, 2011. Section 1602 will result in the reclassification of non-controlling interest to unitholders' equity. The Trust is currently evaluating the impact of the adoption of Section 1601 on its consolidated financial statements.

International Financial Reporting Standards

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, the AcSB confirmed in February 2008 that International Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by Zargon for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.

Zargon's IFRS project consists of three key phases:

-Scoping and diagnostic phase - this phase involves performing a high level impact analysis to identify areas that may be affected by the transition to IFRS.

- Impact analysis and evaluation phase - this phase involves analysis of policy choices allowed under IFRS and their impact on the financial statements.

- Implementation phase - involves implementation of all changes approved in the impact analysis phase and will include changes to information systems, business processes, modification of agreements (if applicable) and training of all staff who are impacted by the conversion.

Zargon has completed the scoping and diagnostic phase and has prepared draft analysis for the impact analysis and evaluation phase. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the consolidated financial statements. In addition, due to anticipated changes to IFRS prior to Zargon's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this Annual Financial Report.

IFRS 1 "First-Time Adoption of International Financial Reporting Standards" ("IFRS 1"), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate for Zargon. Zargon currently anticipates utilizing the following IFRS 1 exemptions:

- Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option to value the PP&E assets at their deemed cost being the Canadian GAAP net book value assigned to these assets as at the date of transition, January 1, 2010. This amendment is permissible for entities that currently follow the full cost accounting guideline under Canadian GAAP. Under this current policy, Zargon accumulates all oil and gas assets into separate cost centres for Canada and the United States. Under IFRS, Zargon's PP&E assets must be divided into smaller cost centres. The net book value of the assets on the date of transition will be allocated to the new cost centres on the basis of Zargon's reserve volumes or values at that point in time.

- Business Combinations - IFRS 1 allows Zargon to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations. The IFRS business combination rules converge with the new CICA Handbook Section 1582 that is also effective for Zargon on January 1, 2011; however, early adoption is permitted.

The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of operations. At this time, Zargon has identified key differences that will impact the financial statements as follows:

-Re-classification of Exploration and Evaluation ("E&E") expenditures from PP&E - Upon transition to IFRS, Zargon will re-classify all E&E expenditures that are currently included in the PP&E balance on the consolidated balance sheets. This will consist of the book value for Zargon's undeveloped land that relates to exploration areas. It is not anticipated that E&E assets will be depleted and the assets must be assessed for impairment when indicators of impairment exist.

- Calculation of depletion expense for PP&E assets - Upon transition to IFRS, Zargon has the option to calculate depletion using a reserve base of proved reserves, which is comparable to the Canadian GAAP method of calculation depletion, or both proved and probable reserves. Zargon has not concluded at this time which method for calculating depletion will be used. Also, depletion must be calculated at a more granular level than what is currently required under Canadian GAAP.

- Impairment of PP&E assets - Under IFRS, impairment of PP&E must be calculated at a more granular level than what is currently required under Canadian GAAP. Impairment calculations will be performed at the cash generating unit ("CGU") level using either total proved or proved plus probable reserves. The most significant difference is that the Canadian GAAP "ceiling test" incorporates a 2-step approach for testing impairment, while IFRS uses a 1-step approach. Under Canadian GAAP, a discounted cash flow analysis is not required if the undiscounted cash flows from proved reserves exceed its carrying amount (step1). If the carrying amount exceeds the undiscounted future cash flows, then a prescribed discounted cash flow test is performed (step 2). Under IFRS, impairment testing based on discounted cash flows or fair value determinations is required and is performed at the CGU level.

- Due to the recent withdrawal of the exposure draft on International Accounting Standards ("IAS") 12 "Income Taxes" in November 2009 and the issuance of the exposure draft on IAS 37 "Provisions, Contingent Liabilities and Contingent Assets" in January 2010, management is still determining the impact of these revised standards on its IFRS transition.

In addition to accounting policy differences, Zargon's transition to IFRS will impact the internal controls over financial reporting ("ICFR") and information technology systems as follows:

- ICFR - As the review of Zargon's accounting policies is completed, an assessment will be made to determine changes required for ICFR. This will be an ongoing process through 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.

- Information technology systems - Zargon will be upgrading systems during the first quarter of 2010 in preparation for IFRS reporting. These modifications are deemed critical in order to allow for reporting of both Canadian GAAP and IFRS financial statements in 2010. Additional system modifications may be required based on final policy choices.

4. ACQUISITIONS

Churchill Energy Inc.

On September 23, 2009, a subsidiary of the Trust acquired all of the outstanding shares of Churchill Energy Inc. ("Churchill"), a public oil and gas company, for consideration of $9.74 million. Consideration consisted of $0.11 million cash, the issuance of 554,669 Zargon trust units valued at $16.87 per unit and acquisition costs of $0.27 million.

The results of operations for Churchill have been included in the consolidated financial statements since September 23, 2009.

The acquisition was accounted for by the purchase method and the preliminary purchase price allocation is as follows:



Net Assets Acquired

($ thousands)
----------------------------------------------------------------------------
Property and equipment 9,794
Working capital deficiency (6,576)
Future income tax asset 8,920
Asset retirement obligations (2,403)
----------------------------------------------------------------------------
Total net assets acquired 9,735
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consideration

($ thousands)
----------------------------------------------------------------------------
Cash 108
Trust units issued 9,357
Acquisition costs 270
----------------------------------------------------------------------------
Total purchase price 9,735
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Masters Energy Inc.

On April 29, 2009, a subsidiary of the Trust acquired all of the outstanding shares of Masters Energy Inc. ("Masters"), a public oil and gas company, for consideration of $27.10 million. Consideration consisted of $5.70 million cash, the issuance of 1,475,468 Zargon trust units valued at $14.26 per unit and acquisition costs of $0.36 million. Zargon assumed Masters' long term debt, which was repaid on the closing date of the acquisition.

The results of operations for Masters have been included in the consolidated financial statements since April 29, 2009.

The acquisition was accounted for by the purchase method and the purchase price allocation is as follows:



Net Assets Acquired

($ thousands)
----------------------------------------------------------------------------
Property and equipment 44,030
Working capital deficiency (105)
Long term debt (12,825)
Future income tax asset 69
Asset retirement obligations (4,072)
----------------------------------------------------------------------------
Total net assets acquired 27,097
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consideration

($ thousands)
----------------------------------------------------------------------------
Cash 5,700
Trust units issued 21,040
Acquisition costs 357
----------------------------------------------------------------------------
Total purchase price 27,097
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Newpact Energy Corp.

On May 16, 2008, a subsidiary of the Trust acquired all of the outstanding shares of Newpact Energy Corp. ("Newpact"), a private oil and gas company, for consideration of $9.54 million. Consideration consisted of the issuance of 425,940 Zargon trust units valued at $22.04 per unit and acquisition costs of $0.15 million.

The results of operations for Newpact have been included in the consolidated financial statements since May 16, 2008.

The acquisition was accounted for by the purchase method and the purchase price allocation is as follows:



Net Assets Acquired

($ thousands)
----------------------------------------------------------------------------
Property and equipment 13,925
Working capital deficiency (2,491)
Future income tax liability (922)
Asset retirement obligations (976)
----------------------------------------------------------------------------
Total net assets acquired 9,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consideration

($ thousands)
----------------------------------------------------------------------------
Trust units issued 9,388
Acquisition costs 148
----------------------------------------------------------------------------
Total purchase price 9,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Rival Energy Ltd.

On January 23, 2008, a subsidiary of the Trust acquired all of the outstanding shares of Rival Energy Ltd. ("Rival"), a public oil and gas company, for consideration of $30.06 million. Consideration consisted of $16.40 million cash, the issuance of 573,300 Zargon trust units valued at $23.32 per unit and acquisition costs of $0.29 million.

The results of operations for Rival have been included in the consolidated financial statements since January 23, 2008.

The acquisition was accounted for by the purchase method and the purchase price allocation is as follows:



Net Assets Acquired

($ thousands)
----------------------------------------------------------------------------
Property and equipment 54,065
Goodwill 2,969
Working capital deficiency (854)
Long term debt (16,914)
Future income tax liability (5,443)
Asset retirement obligations (3,767)
----------------------------------------------------------------------------
Total net assets acquired 30,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consideration

($ thousands)
----------------------------------------------------------------------------
Cash 16,400
Trust units issued 13,369
Acquisition costs 287
----------------------------------------------------------------------------
Total purchase price 30,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. PROPERTY AND EQUIPMENT

December 31, 2009
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousands) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties and
other equipment (1) 771,121 347,260 423,861
Leasehold improvements and office
equipment 4,136 2,033 2,103
----------------------------------------------------------------------------
775,257 349,293 425,964
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2008
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousands) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties and
other equipment (1) 667,944 282,949 384,995
Leasehold improvements and office
equipment 3,380 1,629 1,751
----------------------------------------------------------------------------
671,324 284,578 386,746
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As a result of shareholders redeeming exchangeable shares, property and
equipment has cumulatively increased $56.13 million, $0.97 million
relating to 2009, $3.39 million relating to 2008 and $51.76 million
relating to prior years. The effect of these increases has resulted in
additional depletion and depreciation expense of approximately $27.22
million, $4.91 million relating to 2009, $5.59 million relating to 2008
and $16.72 million relating to prior years.


At December 31, 2009, petroleum, natural gas properties and equipment include $24.37 million (2008 - $24.73 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, 2009 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, 2009:



WTI Crude Oil Exchange Rate WTI Crude Oil AECO Gas
Year ($US/bbl) ($US/$Cdn) ($Cdn/bbl) ($Cdn/gj)
----------------------------------------------------------------------------
2010 81.92 0.95 86.23 5.38
2011 85.85 0.95 90.37 5.87
2012 87.84 0.95 92.46 6.04
2013 89.21 0.95 93.91 6.18
2014 90.74 0.95 95.52 6.33
----------------------------------------------------------------------------
Thereafter (inflation %) 2.0% 0.95 2.0% 2.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

6. LONG TERM DEBT

On July 27, 2009, Zargon amended and renewed its syndicated committed credit facilities, the result of which was the maintaining of the available facilities and borrowing base of $180 million. These facilities consist of a $170 million tranche available to the Canadian borrower and a US $8 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. The facilities are fully revolving for a 336 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 June 29, 2010. Should the facilities not be renewed, they convert to one year non-revolving term facilities at the end of the revolving 336 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 125 basis points and 275 basis points (2008 - zero and 32.5 basis points, respectively), as well as with Canadian banker's acceptance and LIBOR rates plus an applicable margin between 275 basis points and 425 basis points (2008 - 97.5 and 157.5 basis points, respectively). At December 31, 2009, $76.58 million (December 31, 2008 - $77.58 million) had been drawn on the syndicated committed credit facilities with any unused amounts subject to standby fees. In the normal course of operations Zargon enters into various letters of credit. At December 31, 2009, the approximate value of outstanding letters of credit totalled $0.61 million (December 31, 2008 -$0.52 million). The letters of credit reduce the amount of Zargon's available credit facilities to $102.81 million at December 31, 2009 (2008 - $101.90 million).

Zargon reviews its compliance with its bank debt covenants on a quarterly basis and has no violations as at December 31, 2009. Zargon's management is planning to convert to a corporation from its current trust structure towards the end of 2010. In order for this conversion to occur Zargon would have to ensure that all legal and regulatory requirements are satisfied and would be required to obtain the consent of the lenders under Zargon's current syndicated credit facility.

7. 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 $35.47 million as at December 31, 2009 (2008 - $28.59 million), based on a total future liability of $164.58 million (2008 - $142.52 million). These payments are expected to be made over the next 40 years with the majority of the costs being incurred after 2019. 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) 2009 2008
----------------------------------------------------------------------------
Balance, beginning of year 28,592 21,184
Net liabilities incurred/acquired 7,353 5,920
Liabilities settled (3,056) (897)
Accretion expense 2,744 2,183
Foreign exchange (165) 202
----------------------------------------------------------------------------
Balance, end of year 35,468 28,592
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. 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 9) 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, 2009 December 31, 2008
----------------------------------------------------------------------------
Number of Amount Number of Amount
(thousands) Units ($) Units ($)
----------------------------------------------------------------------------
Balance, beginning of year 18,479 120,650 17,076 89,688
Unit rights exercised for cash 98 1,295 69 1,166
Unit-based compensation recognized
on exercise of unit rights - 391 - 246
Issued on corporate and property
acquisitions (note 4) 2,030 30,397 1,045 23,910
Equity issuance 2,365 35,475 - -
Issue costs, net of future tax
effect of $487 - (1,544) - -
Issued on conversion of
exchangeable shares 125 2,176 289 5,640
----------------------------------------------------------------------------
Balance, end of year 23,097 188,840 18,479 120,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of issue costs).

Trust Unit Rights Incentive Plan

The Trust has a unit rights incentive plan (the "Old Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and other service providers. On April 22, 2009, a new unit rights incentive plan (the "New Plan") was approved by the unitholders. The Trust is authorized to issue up to an aggregate of 2.13 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 Old Plan or the New Plan (the "modified price"). Under the Old Plan, the modified price was based on the increment of the amount the monthly distribution exceeded a monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the Old Plan). Under the New Plan, if the monthly distribution exceeds the monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the New Plan), the entire amount (not the increment) of the distribution is deducted from the original grant price. Rights granted under either 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
under the Old Plan:


December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Weighted Average Weighted 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 at
beginning of year 1,654 25.57 / 23.63 1,488 26.41 / 24.60
Unit rights granted - - 445 22.65
Unit rights exercised (98) 13.21 (69) 16.92
Unit rights cancelled (234) 26.60 (210) 27.22
----------------------------------------------------------------------------
Outstanding at end
of year 1,322 25.97 / 23.52 1,654 25.57 / 23.63
----------------------------------------------------------------------------
Unit rights exercisable
at year end 961 26.87 / 23.99 839 26.51 / 23.57
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Weighted Average Weighted 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 at
beginning of year - - / - - - / -
Unit rights granted 434 15.81 - -
Unit rights exercised - - - -
Unit rights cancelled (13) 15.76 - -
----------------------------------------------------------------------------
Outstanding at end
of year 421 15.81 / 14.58 - - / -
----------------------------------------------------------------------------
Unit rights exercisable
at year end - - / - - - / -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following tables summarize information about unit rights outstanding
and exercisable at December 31, 2009:

For the Old Plan at the initial grant price:

Unit Rights Outstanding Unit Rights Exercisable
----------------------------------------------------------------------------
Weighted Weighted
Weighted Average Average
Range of Average Exercise Exercise
Exercise Number Remaining Price Number Price
Prices Outstanding Contractual ($/unit Exercisable ($/unit
($/unit right) (thousands) Life right) (thousands) right)
----------------------------------------------------------------------------
13.00 - 25.06 613 2.1 years 22.58 383 22.99
26.00 - 27.40 310 1.8 years 26.65 204 26.88
27.91 - 29.93 146 1.6 years 28.81 121 28.99
31.09 - 33.05 253 0.7 years 31.72 253 31.72
----------------------------------------------------------------------------
1,322 25.97 961 26.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the Old Plan at the modified price:

Unit Rights Outstanding Unit Rights Exercisable
----------------------------------------------------------------------------
Weighted Weighted
Weighted Average Average
Range of Average Exercise Exercise
Exercise Number Remaining Price Number Price
Prices Outstanding Contractual ($/unit Exercisable ($/unit
($/unit right) (thousands) Life right) (thousands) right)
----------------------------------------------------------------------------
12.20 - 22.37 613 2.1 years 20.53 383 20.48
22.91 - 25.04 310 1.8 years 24.26 204 23.94
25.89 - 26.42 146 1.6 years 26.13 121 26.17
26.95 - 30.23 253 0.7 years 28.31 253 28.31
----------------------------------------------------------------------------
1,322 23.52 961 23.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the New Plan at the initial grant price:

Unit Rights Outstanding Unit Rights Exercisable
----------------------------------------------------------------------------
Weighted Weighted
Weighted Average Average
Range of Average Exercise Exercise
Exercise Number Remaining Price Number Price
Prices Outstanding Contractual ($/unit Exercisable ($/unit
($/unit right) (thousands) Life right) (thousands) right)
----------------------------------------------------------------------------
15.56 368 4.1 years 15.56 - -
15.80 - 17.31 21 4.1 years 16.73 - -
18.00 - 18.05 29 4.1 years 18.03 - -
18.67 3 4.1 years 18.67 - -
----------------------------------------------------------------------------
421 15.81 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the New Plan at the modified price:

Unit Rights Outstanding Unit Rights Exercisable
----------------------------------------------------------------------------
Weighted Weighted
Weighted Average Average
Range of Average Exercise Exercise
Exercise Number Remaining Price Number Price
Prices Outstanding Contractual ($/unit Exercisable ($/unit
($/unit right) (thousands) Life right) (thousands) right)
----------------------------------------------------------------------------
14.24 368 4.1 years 14.24 - -
14.75 - 16.63 21 4.1 years 15.91 - -
17.51 - 17.73 29 4.1 years 17.59 - -
18.49 3 4.1 years 18.49 - -
----------------------------------------------------------------------------
421 14.58 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Unit-Based Compensation

The weighted average assumptions used for unit rights granted in 2009 include a volatility factor of expected market price of 34.5 percent, a risk-free interest rate of 1.7 percent and an expected life of the unit rights of four years. The fair value of the unit rights granted under the New Plan in the year was calculated at $4.50 per unit right. These unit rights, together with the continued vesting of unit rights granted in prior years, resulted in unit-based compensation expense in 2009 of $1.26 million (2008 - $1.19 million).

Compensation expense associated with unit rights granted under either 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 if the rights have not yet vested.

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



Contributed Surplus
($ thousands)
----------------------------------------------------------------------------
Balance, December 31, 2007 3,714
Unit-based compensation expense (1) 1,149
Unit-based compensation recognized on exercise of unit rights (246)
----------------------------------------------------------------------------
Balance, December 31, 2008 4,617
Unit-based compensation expense (1) 1,245
Unit-based compensation recognized on exercise of unit rights (391)
----------------------------------------------------------------------------
Balance, December 31, 2009 5,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) During the fourth quarter of 2008, the Trust issued 10,000 unit
appreciation rights ("UARs") with an intrinsic value of $0.02 million
at December 31, 2009 ($0.04 million at December 31, 2008). These UARs
are awards entitling the recipients to receive cash in an amount
equivalent to any excess of the market value of a stated number of
units over a stated price. UARs are included in unit-based
compensation expense; however rewards settled in cash are liabilities
and therefore are not included in contributed surplus.


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.

9. 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 0.08 million (2008 - 0.21 million) exchangeable shares were converted into 0.12 million (2008 - 0.29 million) trust units based on the exchange ratio at the time of conversion. At December 31, 2009, the exchange ratio was 1.63709 (2008 - 1.43643) 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 Subsidiaries of Income Trusts", if certain conditions are met, the exchangeable shares issued by a subsidiary must be reflected as non-controlling interest on the consolidated balance sheets and, in turn, net earnings must be reduced by the amount of net earnings attributed to the non-controlling interest.

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



Non-Controlling Interest - Exchangeable Shares

December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Number of Number of
(thousands, except exchange ratio) Shares Amount ($) Shares Amount ($)
----------------------------------------------------------------------------
Balance, beginning of year 1,862 27,610 2,071 20,730
Exchanged for trust units at book
value and including earnings
attributed during the period (78) (1,470) (209) (3,220)
Earnings attributable to
non-controlling interest - 337 - 10,100
----------------------------------------------------------------------------
Balance, end of year 1,784 26,477 1,862 27,610
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, end of period 1.63709 1.43643
Trust units issuable upon
conversion of exchangeable
shares, end of year 2,920 2,675
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The proforma total units outstanding at December 31, 2009, 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 26.02 million units (2008 - 21.15 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, 2007 89,688 20,730 110,418
Issued on redemption of exchangeable
shares at book value 508 (508) -
Effect of EIC-151 5,132 7,388 12,520
Unit-based compensation recognized on
exercise of unit rights 246 - 246
Issued on corporate and property
acquisitions 23,910 - 23,910
Unit rights exercised for cash 1,166 - 1,166
----------------------------------------------------------------------------
Balance at December 31, 2008 120,650 27,610 148,260
Issued on redemption of exchangeable
shares at book value 192 (192) -
Effect of EIC-151 1,984 (941) 1,043
Unit-based compensation recognized on
exercise of unit rights 391 - 391
Issued on corporate and property
acquisitions 30,397 - 30,397
Unit rights exercised for cash 1,295 - 1,295
Equity issuance (net of share issue costs
and future taxes) 33,931 - 33,931
----------------------------------------------------------------------------
Balance at December 31, 2009 188,840 26,477 215,317
----------------------------------------------------------------------------
----------------------------------------------------------------------------


EIC-151 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 2009 by $1.04 million (2008 - $12.52 million) on the Trust's consolidated balance sheets. Consolidated net earnings for 2009 have been reduced for net earnings attributable to the non-controlling interest by $0.34 million (2008 - $10.10 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 2009 additionally resulted in an increase in property and equipment of $0.97 million (2008 - $3.39 million), and an increase in future income tax liability of $0.27 million (2008 - $0.97 million). Funds flow from operating activities 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 $56.13 million (for depletion impact see note 5), unitholders' equity and non-controlling interest by $66.91 million, future income tax liability by $18.46 million and an allocation of net earnings to exchangeable shareholders of $29.24 million.

10. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS



(thousands of units) 2009 2008
----------------------------------------------------------------------------
Basic 21,099 18,021
Diluted 23,745 20,632
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Dilution amounts of 2.65 million units (2008 - 2.61 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 "ifconverted" 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 Old Plan and the New Plan, the prices used in the treasury stock calculation are the lower prices calculated under the Old Plan and the New Plan. An adjustment to the numerator amount was required in the diluted calculation to provide for the earnings of $0.34 million (2008 - $10.10 million) attributable to the non-controlling interest pertaining to the exchangeable shareholders.

11. CAPITAL DISCLOSURES

The Trust's capital structure is comprised of unitholders' equity plus long term debt. The Trust's objectives when managing its capital structure are to:

i) maintain financial flexibility so as to preserve Zargon's access to capital markets and its ability to meet its financial obligations; and

ii) finance internally generated growth as well as acquisitions.

The Trust monitors its capital structure and short term financing requirements using the non-GAAP financial metric of debt net of working capital ("net debt") to funds flow from operating activities. Net debt, as used by the Trust, is calculated as bank debt and any working capital deficit excluding the current portion of unrealized risk management assets and liabilities and future income taxes. Funds flow from operating activities represent net earnings/losses and asset retirement expenditures except for non-cash items. The metric is used to steward the Trust's overall debt position as a measure of the Trust's overall financial strength and is calculated as follows:


($ thousands, except ratio) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Net debt 88,008 87,707
Funds flow from operating activities 86,352 106,909
----------------------------------------------------------------------------
Net debt to funds flow from operating
activities ratio 1.02 0.82
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2009, Zargon's net debt to funds flow from operating activities ratio was 1.02, an increase from 0.82 at December 31, 2008, primarily due to weak commodity prices negatively affecting funds flow from operating activities. Bank debt levels increased throughout the year when the Trust acquired Masters on April 29, 2009 and Churchill on September 23, 2009. On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis of $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of issue costs). On July 27, 2009, Zargon amended and renewed its syndicated committed credit facilities of $180 million. The next renewal date is June 29, 2010. These facilities continue to be available for general corporate purposes and the potential acquisition of oil and natural gas properties.

To manage its capital structure, the Trust may adjust capital spending, adjust distributions paid to unitholders, issue new units, issue new debt or repay existing debt.

The Trust's capital management objectives, evaluation measures, definitions and targets have remained unchanged over the periods presented. Zargon is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants.

Zargon reviews its compliance with its bank debt covenants on a quarterly basis and has no violations as at December 31, 2009. Zargon's management is planning to convert to a corporation from its current trust structure towards the end of 2010. In order for this conversion to occur Zargon would have to ensure that all legal and regulatory requirements are satisfied and would be required to obtain the consent of the lenders under Zargon's current syndicated credit facility.

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT CONTRACTS

Fair Value of Financial Assets and Liabilities

Zargon's financial assets and liabilities are comprised of accounts receivable, deposits, accounts payable, cash distributions payable, unrealized risk management assets and liabilities and long term debt. Fair values of financial assets and liabilities, summarized information related to risk management positions and discussion of risks associated with financial assets and liabilities are presented as follows:

A) Fair Value of Financial Assets and Liabilities

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 fair values of these accounts approximate their carrying amounts.

Risk management assets and liabilities are derivative financial instruments classified as "held-for-trading". These accounts are recorded at their estimated fair value using quoted market prices.

Financial instruments of the Trust carried on the consolidated balance sheets are carried at amortized cost with the exception of risk management contracts, which are carried at fair value.

All of the Trust's risk management contracts are transacted in active markets. The Trust classifies the fair value of these transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.

-Level I

Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

-Level II

Pricing inputs are other than quoted prices in active markets included in Level I. Prices in Level II are either directly or indirectly observable as of the reporting date. Level II valuations are based on inputs, included quoted forward prices for commodities, time value and volatility factors, which are can be substantially observed or corroborated in the marketplace.

-Level III

Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The Trust's risk management contracts have been assessed on the fair value hierarchy described above. The Trust's risk management contracts are classified as Level II. Assessment of the significance of a particular input into the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level.

B) Risk Management Assets and Liabilities

The Trust is a party to certain financial instruments that have fixed the price of a portion of its oil and natural gas production and foreign exchange conversion rates. The Trust enters into these contracts for risk management purposes only, in order to protect a portion of its future cash flow from the volatility of oil and natural gas commodity prices and foreign exchange rates. 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 in earnings based on the fair value (mark-to-market) of the contracts at each reporting period. The unrealized loss on the statement of earnings and comprehensive income and accumulated earnings for 2009 was $36.39 million and the unrealized gain for 2008 was $44.38 million.

As at December 31, 2009, the Trust had the following outstanding commodity and foreign currency risk management contracts:



Commodity Financial Risk Management Contracts:

Fair Market Value
Weighted Asset/(Liability)
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Oil swaps
300 bbl/d $132.98 US/bbl Jan. 1/10 - Jun. 30/10 2,956
1,400 bbl/d $73.11 US/bbl Jan. 1/10 - Dec. 31/10 (4,551)
400 bbl/d $77.40 US/bbl Jan. 1/10 - Jun. 30/11 (1,382)
300 bbl/d $83.30 US/bbl Jul. 1/10 - Dec. 31/10 (19)
300 bbl/d $77.25 US/bbl Jan. 1/11 - Sep. 30/11 (749)
----------------------------------------------------------------------------
Total Fair Market Value, Commodity Price Financial Contracts (3,745)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Oil swaps are settled against the NYMEX WTI pricing index.



Foreign Exchange Financial Risk Management Contracts:

Average Foreign
Monthly US Exchange Fair Market
Dollar Volume Rate Value Asset
($ thousands) ($Cdn/$US) Range of Terms ($ thousands)
----------------------------------------------------------------------------
Foreign exchange swaps
1,203 1.1715 Jan. 1/10 - Jun. 30/10 865
----------------------------------------------------------------------------
Total Fair Market Value, Foreign Exchange Financial Contracts 865
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The contracts are settled based on the average daily noon close rate for US
dollars converted to Canadian dollars as published by the Bank of Canada.

Electricity Financial Risk Management Contracts:

Fair Market
Weighted Value Liability
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Electricity swaps
6 MWs/d $80.42/MWh Jan. 1/10 - Dec. 31/10 (70)
6 MWs/d $79.33/MWh Jan. 1/11 - Dec. 31/11 (63)
----------------------------------------------------------------------------
Total Fair Market Value, Electricity Financial Contracts (133)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Electricity swaps are settled against the AESO pricing index.

Physical Risk Management Contracts:

Fair Market
Weighted Value Loss
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Electricity swaps
32 MWs/d $55.50/MWh Jan. 1/10 - Mar. 31/11 (82)
----------------------------------------------------------------------------
Total Fair Market Value, Physical Contracts (82)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Commodity price contracts are settled by way of physical delivery and are recognized as part of the normal revenue stream. Electricity contracts are settled by way of physical delivery and are recognized as part of the normal operating cost stream. These instruments have no book values recorded in the consolidated financial statements.

Commodity Price Sensitivities

The following table summarizes the sensitivity of the fair value of the Trust's risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, the Trust believes 10 percent volatility is a reasonable long term measure.

Fluctuations of 10 percent in commodity prices could have resulted in unrealized gains or losses on risk management contracts impacting net earnings as follows:



($ thousands) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Natural gas price - 474
Crude oil price 8,617 3,584
----------------------------------------------------------------------------
----------------------------------------------------------------------------


C) Risks Associated with Financial Assets and Liabilities

The Trust is exposed to financial risks arising from its financial assets and liabilities. The financial risks include market risk (commodity prices, interest rates and foreign exchange rates), credit risk and liquidity risk.

- Market Risk

Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market prices and is comprised of the following:

- Commodity Price Risk

As a means of mitigating exposure to commodity price risk volatility, the Trust has entered into various derivative agreements. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Trust's policy is to not use derivative financial instruments for speculative purposes.

Natural Gas - To partially mitigate the natural gas commodity price risk, the Trust enters into swaps, which fix the Canadian dollar AECO prices.

Crude Oil - The Trust has partially mitigated its exposure to the WTI NYMEX price with fixed price swaps.

-Interest Rate Risk

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

At the December 31, 2009 debt pricing levels, the increase or decrease in net earnings for each one percent change in interest rates would amount to $0.82 million (2008 - $0.83 million).

- Foreign Exchange Risk

As Zargon operates in North America, fluctuations in the exchange rate between the US/Canadian dollar can have a significant effect on the Trust's reported results. A $0.01 change in the US to Canadian dollar exchange rate would have resulted in a $0.61 million (2008 - $1.16 million) increase or decrease in net earnings for the year ended December 31, 2009. In order to mitigate the Trust's exposure to foreign exchange fluctuations, the Trust enters into foreign exchange derivative agreements.

- Credit Risk

Credit risk is the risk that the counterparty to a financial asset will default, resulting in the Trust incurring a financial loss. This credit exposure is mitigated with credit practices that limit transactions according to counterparties' credit quality. A substantial portion of the Trust's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks.

The maximum credit risk exposure associated with accounts receivable, accrued revenues and risk management assets is the total carrying value. The Trust monitors these balances monthly to limit the risk associated with collection. Of Zargon's accounts receivable at December 31, 2009, approximately 40 percent (December 31, 2008 - 37 percent) was owing from two companies and Zargon anticipates full collection.

The Trust's allowance for doubtful accounts was $0.10 million as at December 31, 2009 and $0.10 million as at December 31, 2008. During 2009, the Trust did not record any additional provisions for non-collectible accounts receivable.

When determining whether amounts that are past due are collectible, management assesses the credit worthiness and past payment history of the counterparty, as well as the nature of the past due amount. Zargon considers all material amounts greater than 90 days to be past due. As at December 31, 2009, $0.78 million of accounts receivable are past due, excluding amounts described above, all of which are considered to be collectable.

- Liquidity Risk

Liquidity risk is the risk the Trust will encounter difficulties in meeting its financial liability obligations. The Trust manages its liquidity risk through cash and debt management. See note 11 for a more detailed discussion.

As at December 31, 2009, Zargon had available unused committed bank credit facilities of approximately $102.81 million compared to $101.90 million at December 31, 2008. The Trust believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.

The timing of cash outflows relating to financial liabilities are outlined in the table below:



($ thousands) 1 year 2-3 years Total
----------------------------------------------------------------------------
Accounts payable and accrued liabilities 34,507 - 34,507
Cash distributions payable 4,157 - 4,157
Risk management liabilities (1) 6,032 1,270 7,302
Long term debt (2) - 76,580 76,580
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) See the section titled "Commodity Price Sensitivities" in this note for
a better understanding of the volatility around these amounts.
(2) See note 6 for the details on the credit facilities.


13. 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. Withholding taxes, 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 would have resulted in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. Subsequent 2007 fourth quarter legislation lowered this tax rate to 29.5 percent in 2011 and 28.0 percent beyond 2011.

On February 26, 2008, the Federal Government, in its Federal Budget, announced further changes to the specified investment flow through ("SIFT") tax rules. The provincial component of the SIFT tax will be based on the provincial rates where the SIFT has a permanent establishment rather than using a 13.0 percent flat rate. During the 2009 first quarter this tax rate change had been substantively enacted, and the future income tax impact has been recorded in the consolidated financial statements. Under the legislation, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be approximately 26.5 percent for 2011 and 25.0 percent thereafter. 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.

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.

On December 15, 2006, the Canadian Federal Department of Finance stated its intention to allow conversions of SIFT income trusts to a corporation without any adverse tax consequences to investors. On July 14, 2008, the Department of Finance released the draft legislative proposals to allow the conversion of these SIFT trusts into corporations. Zargon is currently reviewing and assessing this recent legislation and is considering its potential impact on the organization while Zargon's management develops its strategic plan beyond December 2010, which is the effective date of the new SIFT tax rules.

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) 2009 2008
----------------------------------------------------------------------------
Statutory income tax rates 29.42% 30.08%
Expected income taxes expense (recovery) (3,942) 28,632
Add (deduct) income tax effect of:
Rate adjustments 458 (1,225)
Cash distributions (13,523) (11,757)
Capital taxes and withholding taxes 285 969
Other 267 183
----------------------------------------------------------------------------
(16,455) 16,802
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The 2009 and 2008 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) 2009 2008
----------------------------------------------------------------------------
Net book value of property and equipment in excess of
tax pools 46,983 49,829
Deferred partnership earnings 7,560 7,494
Asset retirement obligations (9,199) (7,525)
Current unrealized risk management (asset)/liability (495) 8,553
Long-term unrealized risk management (asset)/liability (361) 1,321
Non-capital losses (14,296) (1,046)
Share issue costs (491) (31)
Other (230) (338)
----------------------------------------------------------------------------
29,471 58,257
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2009, Zargon's estimated tax pools are as follows:

December 31, December 31,
($ thousands) 2009 2008
----------------------------------------------------------------------------
Canadian oil and gas property expenses in the Trust 30,610 33,992
Canadian oil and gas property expenses in other
entities 43,629 29,846
Canadian development expenses 47,713 36,224
Canadian exploration expenses 49,411 39,332
Capital cost allowance 61,290 51,218
Non-capital losses 60,600 752
US tax pools 2,425 3,185
Partnership deferral (6,290) (8,312)
Other 3,750 1,722
----------------------------------------------------------------------------
293,138 187,959
----------------------------------------------------------------------------
----------------------------------------------------------------------------


14. COMMITMENTS

The Trust is committed to future minimum payments for natural gas transportation sales commitments in addition to operating leases for office space, office equipment and vehicles. Payments required under these commitments for each of the next five years are: 2010 - $2.95 million; 2011 - $1.36 million; 2012 - $0.76 million; 2013 - $nil; 2014 - $nil; thereafter - $nil.

15. 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.



16. CHANGES IN NON-CASH WORKING CAPITAL

Year Ended December 31,
----------------------------------------------------------------------------
($ thousands) 2009 2008
----------------------------------------------------------------------------
Changes in non-cash working capital items:
Accounts receivable (4,498) 943
Prepaid expenses and deposits (851) 528
Accounts payable and accrued liabilities 5,820 1,515
Cash distributions payable 831 252
Working capital acquired from corporate acquisitions (6,681) (3,345)
Foreign exchange and other (999) 3,035
----------------------------------------------------------------------------
(6,378) 2,928
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Changes relating to operating activities 2,476 3,215
Changes relating to financing activities 831 252
Changes relating to investing activities (9,685) (539)
----------------------------------------------------------------------------
(6,378) 2,928
----------------------------------------------------------------------------
----------------------------------------------------------------------------


17. SUPPLEMENTAL CASH FLOW INFORMATION

($ thousands) 2009 2008
----------------------------------------------------------------------------
Cash interest paid 3,558 4,121
Cash taxes paid 1,204 4,973
----------------------------------------------------------------------------
----------------------------------------------------------------------------


18. 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.



2009
----------------------------------------------------------------------------
($ thousands) Canada United States Combined
----------------------------------------------------------------------------
Petroleum and natural gas revenue 141,012 14,973 155,985
Earnings/(losses) before income taxes (19,313) 5,914 (13,399)
Property and equipment, net 394,448 31,516 425,964
Total assets 430,653 33,725 464,378
Goodwill 2,969 - 2,969
Net capital expenditures 47,682 573 48,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------


2008
----------------------------------------------------------------------------
($ thousands) Canada United States Combined
----------------------------------------------------------------------------
Petroleum and natural gas revenue 202,146 27,348 229,494
Earnings before income taxes 82,647 12,540 95,187
Property and equipment, net 353,174 33,572 386,746
Total assets 411,218 36,382 447,600
Goodwill 2,969 - 2,969
Net capital expenditures 57,744 980 58,724
----------------------------------------------------------------------------
----------------------------------------------------------------------------


19. CASH DISTRIBUTIONS

During the year, the Trust declared distributions to the unitholders in the aggregate amount of $45.96 million (2008 - $39.09 million) in accordance with the following schedule:



2009 Distributions Record Date Distribution Date Per Trust Unit
----------------------------------------------------------------------------
January January 31, 2009 February 16, 2009 $0.18
February February 28, 2009 March 16, 2009 $0.18
March March 31, 2009 April 15, 2009 $0.18
April April 30, 2009 May 15, 2009 $0.18
May May 31, 2009 June 15, 2009 $0.18
June June 30, 2009 July 15, 2009 $0.18
July July 31, 2009 August 17, 2009 $0.18
August August 31, 2009 September 15, 2009 $0.18
September September 30, 2009 October 15, 2009 $0.18
October October 31, 2009 November 16, 2009 $0.18
November November 30, 2009 December 15, 2009 $0.18
December December 31, 2009 January 15, 2010 $0.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


2008 Distributions Record Date Distribution Date Per Trust Unit
----------------------------------------------------------------------------
January January 31, 2008 February 15, 2008 $0.18
February February 29, 2008 March 17, 2008 $0.18
March March 31, 2008 April 15, 2008 $0.18
April April 30, 2008 May 15, 2008 $0.18
May May 31, 2008 June 16, 2008 $0.18
June June 30, 2008 July 15, 2008 $0.18
July July 31, 2008 August 15, 2008 $0.18
August August 31, 2008 September 15, 2008 $0.18
September September 30, 2008 October 15, 2008 $0.18
October October 31, 2008 November 17, 2008 $0.18
November November 30, 2008 December 15, 2008 $0.18
December December 31, 2008 January 15, 2009 $0.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


20. RELATED PARTY TRANSACTIONS

Zargon paid $0.05 million (2008 - $0.05 million) for vehicle leases to a company owned by a Board member and $0.41 million (2008 - $0.23 million) for legal services to a law firm of which a Board member is a partner. These payments were in the normal course of operations, were made on commercial terms, and therefore were recorded at their exchange amounts.

21. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to conform with the current year's financial statement presentation.



Forward-Looking Statements - This press release offers our assessment of Zargon's future plans and operations as at March 9, 2010, and contains forward-looking statements including:

- our expectations for production costs referred to under the heading "Production Expenses";

- our expectations for taxes referred to under the headings "Current Income Taxes" and "Future Income Taxes";

- our expectations for interest expenses referred to under the heading "Bank Debt" and note 6 "Long Term Debt";

- our distribution policy referred to under the headings "2009 Highlights" and "Liquidity and Capital Resources";

- our expected sources of funds for distributions and capital expenditures referred to under the heading "Liquidity and Capital Resources"; and

- our expectations for designing and implementing International Financial Reporting Standards referred to under the note 3 "Changes in Accounting Policies".

Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe" and similar expressions (including the negatives thereof). By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including 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. Risks are described in more detail in our Annual Information Form, which is available on our website and at www.sedar.com. Forward-looking statements are provided to allow investors to have a greater understanding of our business.

You are cautioned that the assumptions, including among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition, our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities 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. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that 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
    zargon@zargon.ca
    www.zargon.ca