ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

August 13, 2007 17:01 ET

Zargon Energy Trust Announces 2007 Second Quarter Results and Management Changes

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

For The Three And Six Months Ended June 30, 2007

FINANCIAL & OPERATING HIGHLIGHTS

Zargon Energy Trust is pleased to report its financial results for the second quarter of 2007. Funds flow from operations was $20.56 million ($1.05 per diluted trust unit) in the 2007 second quarter compared with $21.80 million ($1.12 per diluted trust unit) in the 2007 first quarter and $22.06 million ($1.14 per diluted trust unit) in the 2006 second quarter.

Highlights from the three and six months ended June 30, 2007 are noted below:

- Second quarter 2007 production averaged 8,465 barrels of oil equivalent per day, essentially unchanged from the preceding quarter and an increase of two percent from the corresponding quarter of 2006. Second quarter production volumes remained stable as the new production coming from the West Central Alberta core area exploration programs were offset by natural declines and compression outages in the Jarrow area of the Alberta Plains core area. For the second quarter of 2007, Zargon's production averaged 432 barrels of oil equivalent per day per million trust units outstanding compared to the 433 barrels of oil equivalent per day per million trust units outstanding produced in the second quarter of 2006.

- Revenue in the 2007 second quarter increased two percent and funds flow from operations decreased six percent from the prior quarter. Compared to the prior quarter, increased realized oil prices of nine percent were offset by a seven percent reduction in realized natural gas prices and by decreased realized risk management gains.

- The Trust declared three monthly cash distributions of $0.18 per trust unit in the second quarter of 2007 for a total of $9.17 million. These cash distributions were equivalent to a payout ratio of 51 percent of the Trust's second quarter funds flow on a diluted trust unit basis and after considering the effect of the exchangeable shares not receiving distributions, the distributions amounted to 45 percent of funds flow from operations.

- The Trust's second quarter exploration and development capital expenditures decreased 59 percent from the prior quarter to $8.56 million primarily as a result of decreased drilling activity during the spring break-up season. Debt net of working capital (excluding unrealized risk management assets and liabilities) decreased slightly from the balance at the end of the prior quarter to $46.19 million at June 30, 2007. The Trust's balance sheet remains strong with a debt net of working capital to annualized funds flow ratio of slightly more than 0.5 times.

- On July 30, 2007, the Trust amended and renewed its syndicated committed credit facilities, the result of which was an increase in the borrowing base and available facilities to $120 million from the previous amount of $100 million. These facilities are available for general corporate purposes and the acquisition of oil and gas properties.



Three Months Ended Six Months Ended
June 30, June 30,
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Percent Percent
(unaudited) 2007 2006 Change 2007 2006 Change
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Financial
Income and Investments ($ million)
Petroleum and natural gas revenue 39.21 38.66 1 77.75 79.61 (2)
Funds flow from operations 20.56 22.06 (7) 42.36 44.18 (4)
Cash distributions 9.17 8.96 2 18.29 17.85 3
Net earnings 11.63 13.22 (12) 16.86 25.14 (33)
Net capital expenditures 10.97 8.78 25 31.89 23.97 33
Per Unit, Diluted
Funds flow from operations
($/unit) 1.05 1.14 (8) 2.17 2.30 (6)
Net earnings($/unit) 0.68 0.79 (14) 1.00 1.52 (34)
Cash Distributions($/trust unit) 0.54 0.54 - 1.08 1.08 -
Balance Sheet at Period End
($ million)
Property and equipment, net 299.59 261.40 15
Bank debt 46.74 18.14 158
Unitholders' equity 169.53 159.81 6
Total Units Outstanding at
Period End (million) 19.64 19.29 2

Operating
Average Daily Production
Oil and liquids(bbl/d) 3,707 3,748 (1) 3,725 3,864 (4)
Natural gas(mmcf/d) 28.55 27.44 4 28.50 28.21 1
Equivalent(boe/d) 8,465 8,322 2 8,474 8,566 (1)
Equivalent per million trust
units (boe/d) 432 433 - 434 447 (3)
Average Selling Price
(before the impact of financial
risk management contracts)
Oil and liquids ($/bbl) 62.37 67.47 (8) 59.71 61.34 (3)
Natural gas ($/mcf) 7.00 6.27 12 7.27 7.19 1
Wells Drilled, Net 2.6 9.7 (73) 17.0 22.9 (26)
Undeveloped Land at Period End
(thousand net acres) 385 375 3
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Notes:

Throughout this report, funds flow from operations, funds flow from
operations per diluted unit and funds flow netbacks are now calculated
inclusive of asset retirement expenditures. All prior period calculations
have been restated to reflect this change.

Throughout this report, the calculation of barrels of oil equivalent ("boe")
is based on the conversion ratio that six thousand cubic feet of natural gas
is equivalent to one barrel of oil. For a further discussion about this
term, refer to the Management's Discussion and Analysis section in this
report.

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

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

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


PRODUCTION (1)

Natural gas production volumes in the second quarter of 2007 averaged 28.55 million cubic feet per day, essentially unchanged from the previous quarter and a four percent increase from the corresponding period of 2006. New volumes from the ongoing West Central Alberta exploration programs were offset by natural declines and compression outages in the Jarrow area of Alberta Plains. In the upcoming quarter, ongoing West Central Alberta natural gas production tie-ins when augmented with the ongoing Alberta Plains core area drilling, completion and tie-in programs in the Jarrow and Hamilton Lake areas should provide relatively stable to slightly increasing natural gas production rates for the remainder of the year.

Oil and liquids production volumes were 3,707 barrels per day in the 2007 second quarter, a one percent reduction from the preceding quarter and from the corresponding 2006 quarter. Production volumes held relatively steady compared to the prior quarter as new Williston Basin volumes from a strong horizontal well at Manor were offset by naturally occurring production declines. Over the next few months, oil production volumes are anticipated to remain relatively stable as natural declines continue to be offset by our ongoing Williston Basin and Alberta Plains Taber horizontal exploitation programs.

CAPITAL EXPENDITURES (1)

During the second quarter of 2007, Zargon drilled three gross wells (2.6 net) that resulted in 0.6 net natural gas wells and 2.0 net oil wells for a 100 percent success ratio. As anticipated, field activities were restricted due to extended spring break-up conditions. In the Alberta Plains core area, a 0.6 net natural gas well was drilled at Jarrow and 1.0 net horizontal oil well was drilled at Taber. In the Williston Basin core area, 1.0 net well was drilled at Pinto, Saskatchewan. There was no drilling activity in the West Central Alberta core area in the second quarter.

With the conclusion of spring break-up, Zargon has now returned to an active summer-fall field program. In the Alberta Plains core area, the focus for the third quarter will be on tie-ins and facility optimization at Jarrow, a seven well seismically driven Jarrow natural gas exploration program and a 13 well Viking development drilling program at Hamilton Lake. An additional seven well Jarrow exploration program will be scheduled for the fourth quarter along with a two well Taber horizontal oil development program.

In West Central Alberta, winter and spring well tie-ins were responsible for increasing the core area's second quarter production to 1,692 barrels of oil equivalent per day, an increase of 278 barrels of oil equivalent per day over the first quarter volumes. An additional 1.0 million cubic feet per day coming from last winter's exploration program will be tied-in this summer. Building on this success, Zargon is planning to drill nine West Central Alberta exploration wells prior to the end of the year. This fall-winter program is scheduled to include five wells at the Peace River Arch, one well at Pembina and three wells at Highvale. The five (3.0 net) Peace River Arch locations will explore seismically defined targets at the Rycroft, Gordondale, Kakut, Webster and Hamelin Creek properties.

In the Williston Basin, Zargon will resume its ongoing development drilling program with one vertical well at Frys and five horizontal wells at the Elswick and Steelman, Saskatchewan and Mackobee Coulee, North Dakota properties scheduled to be drilled in the third and fourth quarters. Ongoing waterflood modifications and solution gas conservation at Pinto, Saskatchewan will also augment production volumes by the end of the year.

The cost of acquiring land at Crown land sales continues to moderate and accordingly, Zargon has been able to maintain its undeveloped land inventory with reasonably priced purchases. Zargon's undeveloped land inventory at June 30, 2007 was 385 thousand net acres, down one thousand net acres from the balance reported at the end of the prior quarter.

As discussed in the first quarter 2007 report, in recent months improved values appear to be available in the property and acquisition market and during the second quarter, Zargon concluded three minor acquisition transactions aggregating $2.41 million for assets relating to existing properties in each of Zargon's core areas. It is anticipated that the combination of Zargon's strong balance sheet and the industry's improved acquisition metrics should permit Zargon to be an active participant in the property and corporate acquisition market over the next few quarters. To help accomplish this acquisition initiative, Zargon has increased its bank borrowing base to $120 million and has filled a newly created executive position of Vice President, Corporate Development and Reserves. Property or corporate acquisition programs can be funded by debt or equity and will be focused on either explorable and developable Alberta natural gas properties or exploitable Williston Basin oil properties.

GUIDANCE (1)

In the May 14, 2007 press release announcing the 2007 first quarter results, Zargon updated its 2007 full year production guidance to an estimated range of 8,600 to 8,750 barrels of oil equivalent per day based on a $55 million capital program and the drilling of 65 net wells. However, second and third quarter production volumes have been slightly lower than anticipated due to the impact of an extended spring break-up, and the previously announced regulatory delays and challenges pertaining to the availability of third party processing services.

Furthermore, due to the recent natural gas price weakness, Zargon has elected to defer some of the originally planned shallow natural gas Alberta Plains development drilling programs, and redirect this capital to longer term opportunities. For the Alberta Plains core area additional capital is allocated to the buyout of Alberta Plains natural gas compressor lease contracts, to Taber horizontal oil development projects and to longer lead time natural gas exploration programs. Also, recognizing Zargon's improved exploration results and production gains in the West Central Alberta core area, additional capital has been allocated to exploration initiatives during this period of improved costs for field services and improved access to Crown lands and farm-in opportunities. The net effect of these factors is that Zargon's full year guidance has been decreased to a range between 8,500 and 8,600 barrels of oil equivalent per day and the 2007 exploration and development capital program (not including acquisitions and dispositions) has been increased by $5 million to $60 million although the projected well count decreases slightly to 58 net wells. The allocation of this capital program is now forecast to be $25 million to the Alberta Plains, $17 million to the Williston Basin and $18 million to the West Central Alberta core areas.

During the first six months of 2007, Zargon has maintained a base (sustainable) monthly distribution of $0.18 per trust unit, which is based on Zargon's sustainable trust strategy that targets for the distribution of approximately 50 percent of the Trust's funds flow from operations attributed to the unitholders. For the remainder of this year, Zargon plans to continue with its base (sustainable) monthly distribution of $0.18 per trust unit, which is premised on the current 2007 production guidance levels, positive contributions from current risk management contracts and Zargon's recently revised long term commodity price assumptions of US $60 per barrel (WTI oil), a US $7.25 per mmbtu (NYMEX natural gas) price and a $0.92 Cdn/US dollar currency exchange rate.

MANAGEMENT CHANGES

Zargon is pleased to announce the appointment of two new Vice Presidents. Mr. Lorne Schwetz has recently been promoted to Vice President, Land. He will be responsible for all aspects of land negotiation and land administration. Mr. Schwetz was previously Manager, Land Negotiations and he has over 13 years experience in increasingly responsible land positions in the industry.

Effective August 15, 2007, Mr. Brian Kergan will be joining Zargon as Vice President, Corporate Development and Reserves. Mr. Kergan will be responsible for business development activities, which includes corporate and property acquisition initiatives and he will also manage Zargon's reserves evaluation process. He has over 25 years experience in exploitation engineering, reserves and business development and has held increasingly responsible positions with larger and junior oil and gas organizations as well as with consulting organizations.

Finally, Sheila Wares has notified Zargon that she will be retiring from her position as Vice President, Accounting, although she will continue to contribute on a part time basis. Sheila has been with Zargon since its inception and has provided 17 years of valuable service to the organization. We would like to take this opportunity to thank Sheila for her substantial contributions over these years and in particular for the role that she played in building Zargon from a small private oil and gas company to its current size and structure.

(1) Please see comments on "Forward-Looking Statements" in the Management's Discussion and Analysis section in this report.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") should be read in conjunction with the unaudited interim consolidated financial statements for the three and six months ended June 30, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006. All amounts are in Canadian dollars unless otherwise noted. All references to "Zargon" or the "Trust" refer to Zargon Energy Trust.

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

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

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

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

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

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

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

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

Forward-Looking Statements - This document contains statements that are forward-looking, such as those relating to results of operations and financial condition, capital spending, financing sources, commodity prices, costs of production and the magnitude of oil and natural gas reserves. By their nature, forward-looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly actual results may differ materially from those predicted. The forward-looking statements contained in this report are as of August 10, 2007 and are subject to change after this date. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

This MD&A has been prepared as of August 10, 2007.

SUMMARY OF SIGNIFICANT EVENTS IN THE SECOND QUARTER

- During the second quarter of 2007, the Trust realized funds flow from operations of $20.56 million and declared total distributions of $9.17 million ($0.54 per trust unit) to unitholders, resulting in a quarterly payout ratio of 45 percent of funds flow or 51 percent on a per diluted trust unit basis. For Canadian income tax purposes, the distributions are currently estimated to be 100 percent taxable income to unitholders.

- Average field prices received (before the impact of financial risk management contracts) for oil and liquids and for natural gas prices increased nine percent to $62.37 per barrel and decreased seven percent to $7.00 per thousand cubic feet, respectively, compared to the first quarter of 2007. Second quarter production volumes were 8,465 barrels of oil equivalent per day, relatively even with the first quarter 2007 production levels.

- During the second quarter of 2007 spring break-up season, the Trust drilled three gross wells (2.6 net) with a 100 percent success rate. Total net capital expenditures for this activity restricted quarter were $10.97 million compared to $20.93 million for the prior quarter and $8.78 million for the 2006 second quarter.

- The Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities) of $46.19 million, which represents slightly more than six months of the 2007 year-to-date annualized funds flow.

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

- During the 2007 second quarter, Zargon's future tax provision included recoveries of $2.22 million and $0.78 million as a result of new tax legislation imposed on certain income trusts and reductions in future federal income tax rates.

FINANCIAL ANALYSIS

Second quarter 2007 revenue of $39.21 million was two percent above the $38.53 million in the first quarter of 2007 and one percent above the $38.66 million in the second quarter of 2006. A nine percent increase in oil and liquids prices received and a near offsetting seven percent decrease in natural gas prices received, were the primary reasons for the slight increase in revenues when compared to the prior quarter amounts. Average daily production volumes held relatively even over the prior quarter rate. Second quarter 2007 realized oil and liquids field prices averaged $62.37 per barrel before the impact of financial risk management contracts and were nine percent higher from the preceding quarter's $57.04 per barrel and were eight percent lower than the $67.47 per barrel recorded in the 2006 second quarter. Zargon's crude oil field price differential from the Edmonton par price decreased to $9.56 per barrel in the second quarter of 2007 compared to $10.05 per barrel in the first quarter of 2007. Natural gas field prices received averaged $7.00 per thousand cubic feet before the impact of financial risk management contracts in the second quarter of 2007, an increase of 12 percent from the 2006 second quarter prices received and a seven percent decrease from the preceding quarter levels. Zargon's realized field prices differ from the benchmark AECO average daily price due to a combination of fixed price physical contracts (see note 12 to the interim unaudited consolidated financial statements) and from the impact of Zargon receiving AECO monthly index pricing for a portion of its natural gas production.



Pricing

Three Months Ended Six Months Ended
June 30, June 30,
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Percent Percent
Average For The Period 2007 2006 Change 2007 2006 Change
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Natural Gas:
NYMEX average daily spot
price ($US/mmbtu) 7.53 6.54 15 7.37 7.13 3
AECO average daily spot
price ($Cdn/mmbtu) 7.07 6.04 17 7.24 6.77 7
Zargon realized field
price before the impact
of financial risk
management contracts
($Cdn/mcf) 7.00 6.27 12 7.27 7.19 1
Zargon realized field
price before the impact
of physical and financial
risk management contracts
($Cdn/mcf) 6.90 5.91 17 7.07 6.74 5
Crude Oil:
WTI ($US/bbl) 65.04 70.70 (8) 61.60 67.09 (8)
Edmonton par price ($Cdn/bbl) 71.93 78.55 (8) 69.51 73.76 (6)
Zargon realized field price
before the impact of financial
risk management contracts
($Cdn/bbl) 62.37 67.47 (8) 59.71 61.34 (3)
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Natural gas production volumes were relatively even in the second quarter of 2007 at 28.55 million cubic feet per day compared to 28.44 million cubic feet per day in the first quarter of 2007 and were four percent higher than the 2006 second quarter. Oil and liquids production during the second quarter of 2007 was 3,707 barrels per day which is one percent below the 2007 first quarter rate of 3,742 barrels per day and one percent below the second quarter of 2006 level. The year-over-year decrease in oil and liquids production is primarily due to the effect of naturally occurring production declines and 2006 non-core property sales. On a barrel of oil equivalent basis, Zargon produced 8,465 barrels of oil equivalent per day in the second quarter of 2007, which represents less than a one percent decrease from the 8,483 barrels of oil equivalent per day in the first quarter of 2007 and a two percent increase when compared to the second quarter of 2006. Second quarter production volumes remained stable as the continued tie-in of wells from the West Central Alberta core area winter drilling program were offset by natural declines and compression outages in the Jarrow area of the Alberta Plains core area.



Production by Core Area

Three Months Ended June 30,

2007 2006
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Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
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Alberta
Plains 511 19.17 3,706 508 18.54 3,598
West Central
Alberta 177 9.09 1,692 179 8.68 1,626
Williston
Basin 3,019 0.29 3,067 3,061 0.22 3,098
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3,707 28.55 8,465 3,748 27.44 8,322
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Six Months Ended June 30,

2007 2006
----------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta
Plains 523 19.92 3,843 524 19.33 3,746
West Central
Alberta 167 8.32 1,553 183 8.66 1,626
Williston
Basin 3,035 0.26 3,078 3,157 0.22 3,194
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3,725 28.50 8,474 3,864 28.21 8,566
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Zargon's commodity price risk management policy, which is approved by the Board of Directors, allows the use of forward sales and costless collars for a targeted range of 20 to 35 percent of oil and natural gas working interest production in order to partially offset the effects of large commodity price fluctuations. Financial risk management contracts in place as at December 31, 2004 were designated as hedges for accounting purposes and the Trust monitored these contracts in determining the continuation of hedge effectiveness. As at June 30, 2006, all designated hedge contracts had expired. For the designated hedge contracts, realized gains and losses were recorded in the statements of earnings as the contracts settled and no unrealized gain or loss was recognized. For financial risk management contracts entered into after December 31, 2004, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and accordingly, for these contracts, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end.

Specifically, in the 2007 second quarter, relatively lower oil and natural gas prices brought about a net realized financial risk management gain totalling $1.12 million (consisting of a $0.62 million gain on natural gas contracts and a $0.50 million gain on oil contracts) that compares to a $2.33 million realized net gain in the first quarter of 2007 and a $0.71 million realized net loss in the second quarter of 2006. The 2007 second quarter unrealized risk management gain resulted from natural gas contract gains ($2.41 million) net of unrealized risk management oil contract losses ($1.19 million) providing a net gain of $1.22 million for the quarter which compares to a net $5.84 million loss for the 2007 first quarter and a net nominal loss in the second quarter of 2006. These unrealized risk management gains or losses are generated by the change over the reporting period in the mark-to-market valuation of Zargon's future contracts. Zargon's commodity risk management positions are fully described in note 12 to the unaudited consolidated interim financial statements.

Royalties, inclusive of the Saskatchewan Resource Surcharge, totalled $8.53 million for the second quarter of 2007, an increase of two percent from the $8.33 million preceding quarter expense and an increase of six percent from $8.09 million in the second quarter of 2006. The variations generally track changes in production, prices and volumes. As a percentage of gross revenue, royalty rates moved in a relatively narrow range from 20.9 percent in the second quarter of 2006 to 21.6 percent in the first quarter of 2007 and 21.8 percent in the second quarter of 2007. Going forward, Zargon expects that its royalty rate will remain stable at recent levels. During the third quarter of 2006, the Alberta Provincial Government announced the elimination of the Alberta Royalty Credit effective January 1, 2007. The estimated impact of this announcement is an increase of royalty expense of approximately $0.50 million per year for fiscal years commencing in 2007.

On a unit of production basis, production costs of $9.97 per barrel of oil equivalent in the second quarter of 2007 compares with $10.32 per barrel of oil equivalent in the preceding quarter and $7.67 per barrel of oil equivalent in the second quarter of 2006. The high 2007 first quarter costs included adjustments from prior periods on non-operated properties (approximately $0.30 per barrel of oil equivalent). Over the last two years, Zargon has experienced severe industry-wide production cost inflation pressures, which may now be abating due to lower industry activity levels in response to recent natural gas price declines. For 2007, Zargon anticipates that production costs will average between $9.50 to $10.00 per barrel of oil equivalent as general cost inflation pressures are reduced and Zargon's specific cost containment initiatives including the buyout of natural gas compressor lease contracts are implemented.



Operating Netbacks

Three Months Ended June 30, 2007 2006
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
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Production revenue 62.37 7.00 67.47 6.27
Realized risk management gain/(loss) 1.48 0.24 (5.66) 0.49
Royalties (14.00) (1.47) (14.75) (1.22)
Production costs (13.36) (1.22) (10.10) (0.95)
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Operating netbacks 36.49 4.55 36.96 4.59
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Six Months Ended June 30, 2007 2006
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 59.71 7.27 61.34 7.19
Realized risk management gain/(loss) 2.58 0.33 (4.61) 0.23
Royalties (13.11) (1.56) (13.53) (1.50)
Production costs (13.25) (1.29) (10.16) (0.92)
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Operating netbacks 35.93 4.75 33.04 5.00
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Measured on a unit of production basis (net of recoveries), general and administrative expenses were $2.26 per barrel of oil equivalent in the first half of 2007 compared to $1.91 in the first half of 2006 and $2.27 for the twelve month period of 2006. The year-over-year increase in general and administrative expenses on a per unit of production basis are primarily due to additional office lease costs and the costs related to the expansion of Zargon's technical staff.

Expensing of unit-based compensation in the first half of 2007 was $0.73 million, a six percent increase from the corresponding 2006 first half. The increase is a result of unit right grants that generally occur on a quarterly basis.

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges on these facilities in the 2007 second quarter were $0.73 million, $0.15 million higher than the previous quarter amount of $0.57 million and an increase of $0.35 million from $0.38 million in the second quarter of 2006. This year-over-year increase is primarily due to a combination of higher average bank debt levels and higher effective interest rates. On July 30, 2007, Zargon amended and renewed its syndicated committed credit facilities, which resulted in an increase in the available facilities and borrowing base to $120 million from the previous amount of $100 million. The next renewal date is July 29, 2008. These expanded facilities continue to be available for general corporate purposes and the potential acquisition of oil and gas properties.

Capital and current taxes for the 2007 second quarter were $0.70 million, primarily relating to the United States operations, where increased taxable income is resulting in higher United States taxes. When compared to prior periods, capital and current income taxes increased $0.59 million over the 2006 second quarter and increased $0.22 million relative to the first quarter of 2007. Tax pools as at June 30, 2007 are approximately $131 million, which represents an increase from the comparable $113 million of tax pools available to Zargon at December 31, 2006.



Trust Netbacks

Three Months Ended Six Months Ended
June 30, June 30,
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($/boe) 2007 2006 2007 2006
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Petroleum and natural gas revenue 50.91 51.06 50.69 51.35
Realized risk management gain/(loss) 1.45 (0.94) 2.25 (1.34)
Royalties (11.08) (10.68) (10.99) (11.04)
Production costs (9.97) (7.67) (10.15) (7.61)
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Operating netbacks 31.31 31.77 31.80 31.36
General and administrative (2.45) (1.91) (2.26) (1.91)
Interest and financing charges (0.95) (0.50) (0.85) (0.44)
Asset retirement expenditures (1) (0.31) (0.09) (0.30) (0.19)
Capital and current income taxes (0.91) (0.14) (0.77) (0.32)
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Funds flow netbacks (1) 26.69 29.13 27.62 28.50
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(1) Throughout this report, funds flow netbacks are now calculated inclusive
of asset retirement expenditures. All prior period calculations have
been restated to reflect this change.


Depletion and depreciation expense for the second quarter of 2007 increased two percent to $11.76 million, compared to $11.54 million in the prior quarter and increased 19 percent when compared to the 2006 second quarter expense of $9.92 million. On a per barrel of oil equivalent basis, the depletion and depreciation rates were $15.27, $15.12 and $13.10 for the second and first quarters of 2007 and the second quarter of 2006, respectively. The primary reasons for the year-over-year expense increase are due to the impact of last year's increased finding, development and acquisition costs and from the financial impact of the conversion of exchangeable shares pursuant to the application of EIC-151.

The provision for accretion of asset retirement obligations for the first half of 2007 was $0.65 million, a five percent increase compared to the first half of 2006. The year-over-year change is due to changes in the estimated future liability for asset retirement obligations as a result of wells added through Zargon's drilling program.

The recovery of future taxes for the second quarter of 2007 was $3.35 million when compared to a recovery of $2.00 million in the prior quarter and a recovery of future taxes of $3.42 million in the second quarter of 2006. The future income tax provision for the three and six months ended June 30, 2007 includes a recovery of $0.78 million relating to a reduction in future federal income tax rates substantively enacted during the second quarter of 2007 and includes the impact of certain tax balance adjustments.

On October 31, 2006, the Federal Government announced tax proposals pertaining to taxation of distributions paid by trusts and the personal tax treatment of trust distributions. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. On June 12, 2007, the Federal Government enacted these tax proposals, which will result in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes to have a nil effective tax rate. Under the legislation, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be 31.5 percent. Until 2011, Zargon's future tax obligations are reduced as distributions are made from the Trust and consequently, it is anticipated that Zargon's effective tax rate will continue to be low until that time.

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

According to the January 19, 2005 CICA pronouncement, EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", Zargon Energy Trust must reflect the exchangeable securities issued by its subsidiary (Zargon Oil & Gas Ltd.) as a non-controlling interest. Prior to 2005, these exchangeable shares were reflected as a component of unitholders' equity. Accordingly, the Trust has reflected a non-controlling interest of $20.05 million on the Trust's consolidated balance sheet as at June 30, 2007. Consolidated net earnings have been reduced for net earnings attributable to the non-controlling interest of $1.79 million in the second quarter of 2007. In accordance with EIC-151 and given the circumstances in Zargon's case, each exchangeable share redemption is accounted for as a step-purchase, which in the second quarter of 2007 resulted in an increase in property and equipment of $0.38 million, an increase in unitholders' equity of $0.37 million and an increase in future income tax liability of $0.12 million. Funds flow was not impacted by this change. The cumulative impact to date of the application of EIC-151 has been to increase property and equipment by $50.40 million, unitholders' equity and non-controlling interest by $51.24 million, future income tax liability by $16.76 million and an allocation of net earnings to exchangeable shareholders' of $17.60 million.

Funds flow from operations in the 2007 second quarter of $20.56 million was $1.23 million, or six percent lower than the preceding quarter and $1.50 million or seven percent lower than the prior year second quarter. The decrease in funds flow from the preceding quarter was primarily due to decreased realized risk management contract gains. Funds flow on a per diluted trust unit basis was $1.05 for the second quarter of 2007, a six percent decrease from the prior quarter and an eight percent decrease from the 2006 second quarter.

Net earnings of $11.63 million for the 2007 second quarter were 123 percent above the $5.22 million of net earnings in the preceding quarter and 12 percent below the $13.22 million in the second quarter of 2006. The net earnings track the funds flow from operations for the respective periods modified by asset retirement expenditures and non-cash charges, which include depletion and depreciation, unrealized risk management gains/losses, future income taxes/recoveries and non-controlling interest. The primary reasons for the $1.58 million decrease in net earnings when comparing second quarter 2007 to the corresponding 2006 second quarter is due to previously mentioned items such as increased production costs ($1.87 million), increased depletion and depreciation expenses ($1.84 million), offset by realized risk management gains ($1.83 million) and the corresponding net future tax recoveries pertaining to these items.



Capital Expenditures

Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ million) 2007 2006 2007 2006
----------------------------------------------------------------------------
Undeveloped land 1.99 1.70 3.34 2.90
Geological and geophysical (seismic) 0.69 0.85 2.45 1.85
Drilling and completion of wells 2.37 6.92 14.13 15.46
Well equipment and facilities 3.51 2.93 9.47 7.37
----------------------------------------------------------------------------
Exploration and development 8.56 12.40 29.39 27.58
----------------------------------------------------------------------------
Property acquisitions 2.41 0.58 2.50 0.89
Property dispositions - (4.20) - (4.50)
----------------------------------------------------------------------------
Net property acquisitions/(dispositions) 2.41 (3.62) 2.50 (3.61)
----------------------------------------------------------------------------
Total net capital expenditures 10.97 8.78 31.89 23.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Net capital expenditures of $31.89 million in the first half of 2007 were 33 percent higher than the first half of 2006, reflecting an active field program of 20 gross (17.0 net) wells, increased well equipping and facility costs and three property acquisition transactions. Net capital expenditures for the first half of 2007 were allocated to Alberta Plains - $13.73 million, West Central Alberta - $11.46 million and Williston Basin - $6.70 million. Drilling and completion expenses of $14.13 million were nine percent lower than the prior year's first half amount of $15.46 million. During the second quarter of 2007, 2.6 net wells were drilled compared to 14.4 net wells in the first quarter of 2007 and 9.7 net wells in the second quarter of 2006. Funds flow from operations in the 2007 first half of $42.36 million, proceeds from the exercise of trust unit rights of $1.88 million and the increase in bank debt of $16.70 million funded the capital program, the changes in working capital and the cash distributions to the unitholders. At June 30, 2007, the Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities) of $46.19 million, as compared to $47.18 million at the end of the 2007 first quarter, which represents slightly more than six months of the 2007 year-to-date annualized funds flow.

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

At August 10, 2007, Zargon Energy Trust had 17.013 million trust units and 2.117 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective August 10, 2007 exchange ratio of 1.25230, there would be 19.664 million trust units outstanding. Pursuant to the trust unit rights incentive plan there are currently an additional 1.226 million trust unit incentive rights issued and outstanding.



Capital Sources and Uses

Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ million) 2007 2006 2007 2006
----------------------------------------------------------------------------
Funds flow from operations (1) 20.56 22.06 42.36 44.18
Changes in working capital (10.41) 1.90 (10.76) (13.45)
Change in bank debt 9.06 (8.50) 16.70 7.80
Cash distributions to unitholders (9.17) (8.96) (18.29) (17.85)
Issuance of trust units 0.93 2.28 1.88 3.29
----------------------------------------------------------------------------
Total capital sources 10.97 8.78 31.89 23.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughout this report, funds flow from operations is now calculated
inclusive of asset retirement expenditures. All prior period
calculations have been restated to reflect this change.


CHANGE IN ACCOUNTING POLICIES

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

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

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

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

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

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

MANAGEMENT AND FINANCIAL REPORTING SYSTEMS

Zargon is required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to as Canadian SOX ("C-Sox"). The 2007 certificate requires that the Trust disclose in the interim MD&A any changes in the Trust's internal controls over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting. The Trust confirms that no such changes were made to the internal controls over financial reporting during the second quarter of 2007.

Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control systems are met.

BUSINESS RISKS

ENVIRONMENTAL REGULATION AND RISK

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

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

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

REVIEW OF ALBERTA ROYALTY AND TAX REGIME

On February 16, 2007, the Alberta Government announced that a review of the Province's royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil and gas resources, including oil sands, conventional oil and gas and coalbed methane, will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The review panel is to produce a final report that will be presented to the Minister of Finance by August 31, 2007.

OUTLOOK

With a strong balance sheet, 385 thousand net acres of undeveloped land and a promising internally generated project inventory, Zargon continues to be well positioned to meet its objectives as a sustainable trust. For 2007, Zargon is forecasting an average production rate of 8,500 to 8,600 barrels of oil equivalent per day which is premised on a 2007 exploration and development capital program of $60 million. Consistent with its history, the Trust will adhere to a focused strategy of exploring and exploiting its existing asset base while executing value-added property acquisitions which, if available, would be funded by bank debt or equity issuances.



SUMMARY OF QUARTERLY RESULTS

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


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


2005
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 34.12 35.87 42.47 50.26
Net earnings ($ million) 5.14 6.48 6.30 17.45
Net earnings per diluted unit ($) 0.32 0.41 0.39 1.06
Funds flow from operations
($ million) (1) 17.42 18.85 21.70 26.39
Funds flow from operations per diluted
unit ($) (1) 0.93 1.00 1.14 1.38
Cash distributions ($ million) 6.60 6.73 7.45 16.66
Cash distributions declared per trust
unit ($) 0.42 0.42 0.46 1.02
Net capital expenditures ($ million) (2) 10.69 10.96 13.91 19.12
Total assets ($ million) 245.20 253.75 264.44 277.86
Bank debt ($ million) 18.23 15.52 11.43 10.34
Average daily production (boe) 8,446 8,238 8,036 8,651
Average realized commodity field price
before the impact of financial risk
management contracts ($/boe) 44.90 47.85 57.45 63.15
Funds flow netback ($/boe) (1) 22.92 25.15 29.36 33.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughout this report, funds flow from operations, funds flow from
operations per diluted unit and funds flow netbacks are now calculated
inclusive of asset retirement expenditures. All prior period
calculations have been restated to reflect this change.
(2) Amounts include capital expenditures acquired for cash and equity
issuances.


ADDITIONAL INFORMATION

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

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

Calgary, Alberta
August 10, 2007


CONSOLIDATED BALANCE SHEETS

(unaudited) June 30, December 31,
($ thousand) 2007 2006
----------------------------------------------------------------------------
ASSETS (note 5)
Current
Accounts receivable 19,191 18,362
Prepaid expenses and deposits (note 2) 3,298 3,281
Unrealized risk management asset (note 12) 2,876 5,817
----------------------------------------------------------------------------
25,365 27,460
Property and equipment, net (note 4) 299,590 283,108
----------------------------------------------------------------------------
324,955 310,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities 18,874 28,410
Cash distributions payable (note 13) 3,061 3,022
Unrealized risk management liability (note 12) 1,699 20
----------------------------------------------------------------------------
23,634 31,452
Long term debt (note 5) 46,739 30,037
Asset retirement obligations (note 6) 17,836 17,307
Future income taxes (note 8) 47,175 47,891
----------------------------------------------------------------------------
135,384 126,687
----------------------------------------------------------------------------
NON-CONTROLLING INTEREST
Exchangeable shares (note 3) 20,045 18,319
----------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (note 7) 87,967 82,868
Contributed surplus (note 7) 2,779 2,475
Accumulated earnings 181,122 164,267
Accumulated cash distributions (note 13) (102,342) (84,048)
----------------------------------------------------------------------------
169,526 165,562
----------------------------------------------------------------------------
324,955 310,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.


CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME AND
ACCUMULATED EARNINGS

Three Months Ended Six Months Ended
(unaudited) June 30, June 30,
----------------------------------------------------------------------------
($ thousand, except per unit amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
REVENUE
Petroleum and natural gas revenue 39,213 38,664 77,745 79,607
Unrealized risk management gain/(loss)
(note 12) 1,215 (3) (4,620) 2,482
Realized risk management gain/(loss) 1,120 (708) 3,446 (2,069)
Royalties (8,534) (8,087) (16,860) (17,110)
----------------------------------------------------------------------------
33,014 29,866 59,711 62,910
----------------------------------------------------------------------------
EXPENSES
Production 7,683 5,812 15,561 11,799
General and administrative 1,889 1,444 3,466 2,967
Unit-based compensation (note 7) 367 366 726 685
Interest and financing charges 726 376 1,299 686
Unrealized foreign exchange gain (517) (397) (578) (422)
Accretion of asset retirement
obligations (note 6) 328 312 652 622
Depletion and depreciation 11,761 9,922 23,305 20,114
----------------------------------------------------------------------------
22,237 17,835 44,431 36,451
----------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES 10,777 12,031 15,280 26,459
----------------------------------------------------------------------------
INCOME TAXES (note 8)
Current 699 110 1,178 498
Future (recovery) (3,350) (3,421) (5,354) (3,209)
----------------------------------------------------------------------------
(2,651) (3,311) (4,176) (2,711)
----------------------------------------------------------------------------
EARNINGS FOR THE PERIOD BEFORE
NON-CONTROLLING INTEREST 13,428 15,342 19,456 29,170
Non-controlling interest - exchangeable
shares (note 3) (1,794) (2,127) (2,601) (4,034)
----------------------------------------------------------------------------
NET EARNINGS AND COMPREHENSIVE INCOME
FOR THE PERIOD 11,634 13,215 16,855 25,136

ACCUMULATED EARNINGS, BEGINNING OF
PERIOD 169,488 131,689 164,267 119,768
----------------------------------------------------------------------------
ACCUMULATED EARNINGS, END OF PERIOD 181,122 144,904 181,122 144,904
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET EARNINGS PER UNIT (note 9)
Basic 0.69 0.80 1.00 1.52
Diluted 0.68 0.79 1.00 1.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.


CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Six Months Ended
(unaudited) June 30, June 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings and comprehensive income
for the period 11,634 13,215 16,855 25,136
Add (deduct) non-cash items:
Non-controlling interest - exchangeable
shares 1,794 2,127 2,601 4,034
Unrealized risk management (gain)/loss (1,215) 3 4,620 (2,482)
Depletion and depreciation 11,761 9,922 23,305 20,114
Accretion of asset retirement
obligations 328 312 652 622
Unit-based compensation 367 366 726 685
Unrealized foreign exchange gain (517) (397) (578) (422)
Future income taxes (recovery) (3,350) (3,421) (5,354) (3,209)
Asset retirement expenditures (240) (64) (469) (294)
----------------------------------------------------------------------------
20,562 22,063 42,358 44,184
Changes in non-cash working capital (1,470) 1,279 (4,916) (3,396)
----------------------------------------------------------------------------
19,092 23,342 37,442 40,788
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Advances (repayment) of bank debt 9,059 (8,502) 16,702 7,797
Cash distributions to unitholders (9,173) (8,957) (18,294) (17,845)
Exercise of unit rights 925 2,280 1,876 3,294
Changes in non-cash working capital 12 32 39 (8,123)
----------------------------------------------------------------------------
823 (15,147) 323 (14,877)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property and equipment (10,965) (12,978) (31,890) (28,471)
Proceeds on disposal of property and
equipment - 4,200 - 4,500
Changes in non-cash working capital (8,950) 583 (5,875) (1,940)
----------------------------------------------------------------------------
(19,915) (8,195) (37,765) (25,911)
----------------------------------------------------------------------------
CHANGE IN CASH, AND CASH END OF PERIOD - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the three and six months ended June 30, 2007 and 2006 (unaudited)

1. BASIS OF PRESENTATION

The interim unaudited consolidated financial statements of Zargon Energy Trust (the "Trust" or "Zargon") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim unaudited consolidated financial statements have been prepared following the same accounting policies and methods in computation as the consolidated financial statements for the fiscal year ended December 31, 2006, except as noted below. The disclosures provided below are incremental to those included with the annual audited consolidated financial statements. These interim unaudited consolidated financial statements do not include all disclosures required in the annual consolidated financial statements and should be read in conjunction with the consolidated financial statements and notes thereto in the Zargon Energy Trust annual report for the year ended December 31, 2006.

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

2. CHANGES IN ACCOUNTING POLICIES

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

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

Comprehensive Income

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

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

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

Financial Instruments

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

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

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

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

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

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

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

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

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

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

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

3. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

Zargon Oil & Gas Ltd. is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares are convertible into trust units at the option of the shareholder, based on the exchange ratio, which is adjusted monthly to reflect the distribution paid on the trust units. Cash distributions are not paid on the exchangeable shares. During the six months ended June 30, 2007, a total of 0.09 million exchangeable shares were converted into 0.11 million trust units based on the exchange ratio at the time of conversion. At June 30, 2007, the exchange ratio was 1.24430 trust units per exchangeable share.



Non-Controlling Interest - Exchangeable Shares

Six Months Ended June 30, 2007
----------------------------------------------------------------------------
(thousand, except exchange ratio) Number of Shares Amount ($)
----------------------------------------------------------------------------
Balance, beginning of period 2,207 18,319
Earnings attributable to non-controlling
interest - 2,601
Exchanged for trust units at book value and
including earnings attributed since
beginning of period (90) (875)
----------------------------------------------------------------------------
Balance, end of period 2,117 20,045
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, end of period 1.24430
Trust units issuable upon conversion of
exchangeable shares, end of period 2,634
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Per EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", if certain conditions are met, the exchangeable shares issued by a subsidiary must be reflected as non-controlling interest on the consolidated balance sheets and in turn, net earnings must be reduced by the amount of net earnings attributed to the non-controlling interest.

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



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

Zargon Zargon Oil
Energy & Gas Ltd.
Trust Exchangeable
($ thousand) Units Shares Total
----------------------------------------------------------------------------
Balance, beginning of period 82,868 18,319 101,187
Issued on redemption of
exchangeable shares at book
value 219 (219) -
Effect of EIC-151 2,582 1,945 4,527
Unit-based compensation
recognized on exercise of unit
rights 422 - 422
Unit rights exercised for cash 1,876 - 1,876
----------------------------------------------------------------------------
Balance at June 30, 2007 87,967 20,045 108,012
----------------------------------------------------------------------------
----------------------------------------------------------------------------

4. PROPERTY AND EQUIPMENT

June 30, 2007
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousand) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas
properties and other
equipment (1) 499,493 199,903 299,590
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

(1) As a result of shareholders redeeming exchangeable shares, property and
equipment has cumulatively increased $50.40 million, $7.46 million
relating to the first six months of 2007, $6.73 million relating to
2006, $24.93 million relating to 2005 and $11.28 million relating to
2004. The effect of these increases has resulted in additional depletion
and depreciation expense of $13.64 million, $3.08 million relating to
the first six months of 2007, $5.48 million relating to 2006 and $5.08
million relating to 2005.


5. LONG TERM DEBT

On July 30, 2007, Zargon amended and renewed its syndicated committed credit facilities, the result of which is an increase in the available facilities and borrowing base to $120 million from the previous amount of $100 million. These facilities consist of a $100 million tranche available to the Canadian borrower and a US $18 million tranche available to the US borrower. A $150 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities. The facilities are fully revolving for a 364 day period with the provision for an annual extension at the option of the lenders and upon notice from Zargon's management. The next renewal date is July 29, 2008. Should the facilities not be renewed, they convert to one year non-revolving term facilities at the end of the revolving 364 day period. Repayment would not be required until the end of the non-revolving term, and as such, these facilities have been classified as long term debt.



6. ASSET RETIREMENT OBLIGATIONS

The following table reconciles Zargon's asset retirement obligations:

Six Months Ended June 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period 17,307 15,859
Net liabilities incurred/(disposed) 435 (28)
Liabilities settled (469) (294)
Accretion expense 652 622
Foreign exchange (89) (40)
----------------------------------------------------------------------------
Balance, end of period 17,836 16,119
----------------------------------------------------------------------------
----------------------------------------------------------------------------

7. UNITHOLDERS' EQUITY

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

Trust Units

Six Months Ended June 30, 2007
----------------------------------------------------------------------------
Number of Amount
(thousand) Units ($)
----------------------------------------------------------------------------
Balance, beginning of period 16,789 82,868
Unit rights exercised for cash 107 1,876
Unit-based compensation recognized on exercise of
unit rights - 422
Issued on conversion of exchangeable shares 109 2,801
----------------------------------------------------------------------------
Balance, end of period 17,005 87,967
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The proforma total units outstanding at June 30, 2007, including trust units
outstanding, and trust units issuable upon conversion of exchangeable shares
and after giving effect to the exchange ratio at the end of the period (see
note 3) is 19.639 million units.

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

Contributed Surplus

($ thousand) Six Months Ended June 30, 2007
----------------------------------------------------------------------------
Balance, beginning of period 2,475
Unit-based compensation expense 726
Unit-based compensation recognized on
exercise of unit rights (422)
----------------------------------------------------------------------------
Balance, end of period 2,779
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Trust Unit Rights Incentive Plan and Unit-Based Compensation

The Trust has a unit rights incentive plan (the "Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and service providers. The Trust is authorized to issue up to 2.36 million unit rights; however, the number of trust units reserved for issuance upon exercise of the rights shall not at any time exceed 10 percent of the aggregate number of the total outstanding units including units issuable upon exchange of exchangeable shares of Zargon and other fully paid securities of Zargon entities exchangeable into units, which are the economic equivalent of units including full voting rights. At the time of grant, unit right exercise prices approximate the market price for the trust units. At the time of exercise, the rights holder has the option of exercising at the original grant price or the exercise price as calculated per the Plan. Rights granted under the Plan generally vest over a three-year period and expire approximately five years from the grant date. Zargon uses a fair value methodology to value the unit rights grants.

The weighted average assumptions made for unit rights granted for 2007 include a volatility factor of expected market price of 26.4 percent, a risk-free interest rate of 4.0 percent, a dividend yield of 8.3 percent and an expected life of the unit rights of four years. These unit rights, together with the continued vesting of unit rights granted in prior years resulted in unit-based compensation expense for the six months ended June 30, 2007 of $0.73 million (2006 - $0.69 million).

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



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

Six Months Ended June 30, 2007
----------------------------------------------------------------------------
Weighted
Average
Exercise
Number of Price
Unit Rights ($/unit
(thousand) right)
----------------------------------------------------------------------------
Outstanding at beginning of period 1,208 26.32
Unit rights granted 243 26.24
Unit rights exercised (107) 17.53
Unit rights cancelled (78) 28.64
--------------------------------------------------------------
Outstanding at end of period 1,266 26.83
--------------------------------------------------------------
--------------------------------------------------------------
Unit rights exercisable at period end 586 25.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. INCOME TAXES

The future income tax provision for the three and six months ended June 30, 2007 includes a recovery of $0.78 million relating to a reduction in future federal income tax rates substantively enacted during the quarter and includes the impact of certain tax balance adjustments.

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

Based on its assets and liabilities as at June 30, 2007, the Trust has estimated the amount of its temporary differences, which were previously not subject to tax and has estimated the periods in which these differences will reverse. The Trust estimates that $7.05 million net tax deductible temporary differences will reverse after January 1, 2011, resulting in a reduction of the future tax liability of $2.22 million. The tax deductible temporary differences relate principally to the remaining tax pools attributed to the oil and gas properties being greater than their net book value.

As the legislation gives rise to a change in the Trust's estimated future income tax liability in the period, the recognition of the reduced liability is accounted for prospectively in the period and a recovery of $2.22 million of future tax expense has been recorded in the future income tax provision for the three and six months ended June 30, 2007.

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

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

9. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS

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



Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
(thousand units) 2007 2006 2007 2006
----------------------------------------------------------------------------
Basic 16,971 16,549 16,920 16,492
Diluted 19,610 19,335 19,505 19,206
----------------------------------------------------------------------------
----------------------------------------------------------------------------

10. SEGMENTED INFORMATION

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

Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
Petroleum and Natural Gas Revenue
Canada 33,733 31,859 67,187 67,171
United States 5,480 6,805 10,558 12,436
----------------------------------------------------------------------------
Total 39,213 38,664 77,745 79,607
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Capital Expenditures
Canada 10,975 6,295 31,756 20,987
United States (10) 2,483 134 2,984
----------------------------------------------------------------------------
Total 10,965 8,778 31,890 23,971
----------------------------------------------------------------------------
----------------------------------------------------------------------------


($ thousand) June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Property and Equipment, net
Canada 265,512 248,440
United States 34,078 34,668
----------------------------------------------------------------------------
Total 299,590 283,108
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. SUPPLEMENTAL CASH FLOW INFORMATION

Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ thousand) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash interest paid 824 335 1,404 703
Cash taxes paid 699 335 1,462 726
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. RISK MANAGEMENT CONTRACTS

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



Financial Contracts at June 30, 2007:

Fair Market
Weighted Value
Rate Average Price Range of Terms Gain/(Loss)
----------------------------------------------------------------------------
($ thousand)
----------------------------------------------------------------------------
Oil swaps 1,000 bbl/d $72.40 US/bbl Jul. 1/07-Dec. 31/07 228
300 bbl/d $66.70 US/bbl Jan. 1/08-Mar. 31/08 (154)
300 bbl/d $61.72 US/bbl Jan. 1/08-Jun. 30/08 (607)
100 bbl/d $65.55 US/bbl Jan. 1/08-Dec. 31/08 (265)
300 bbl/d $68.29 US/bbl Apr. 1/08-Jun. 30/08 (118)
600 bbl/d $68.94 US/bbl Jul. 1/08-Dec. 31/08 (421)
Natural gas
swaps 5,000 gj/d $ 8.36/gj Jul. 1/07-Oct. 31/07 1,523
6,000 gj/d $ 8.41/gj Nov. 1/07-Mar. 31/08 850
1,000 gj/d $ 7.84/gj Apr. 1/08-Oct. 31/08 141
----------------------------------------------------------------------------
Net Fair Market Value, Financial Contracts 1,177
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

For financial risk management contracts, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and accordingly any unrealized gains or losses are recorded based on the fair value (mark-to-market) of the contracts at the period end. The unrealized loss for the first six months of 2007 was $4.62 million and the unrealized gain for the first six months of 2006 was $2.48 million.

Contracts settled by way of physical delivery are recognized as part of the normal revenue stream. These instruments have no book values recorded in the interim consolidated financial statements. The Trust has the following outstanding physical contracts:



Physical Contracts at June 30, 2007:

Fair Market
Weighted Value Gain
Rate Average Price Range of Terms ($ thousand)
----------------------------------------------------------------------------
Natural gas
fixed price 1,000 gj/d $ 7.88/gj Jul. 1/07-Oct. 31/07 246
1,000 gj/d $ 7.95/gj Apr. 1/08-Oct. 31/08 165
----------------------------------------------------------------------------
Total Fair Market Value, Physical Contracts 411
----------------------------------------------------------------------------
----------------------------------------------------------------------------

13. CASH DISTRIBUTIONS

During the six month period, the Trust declared cash distributions to the
unitholders in the aggregate amount of $18.29 million (2006 - $17.85
million) in accordance with the following schedule:


2007 Distributions Record Date Distribution Date Per Trust Unit
----------------------------------------------------------------------------
January January 31, 2007 February 15, 2007 $ 0.18
February February 28, 2007 March 15, 2007 $ 0.18
March March 31, 2007 April 16, 2007 $ 0.18
April April 30, 2007 May 15, 2007 $ 0.18
May May 31, 2007 June 15, 2007 $ 0.18
June June 30, 2007 July 16, 2007 $ 0.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


CORPORATE INFORMATION


BOARD OF DIRECTORS STOCK EXCHANGE LISTING

Craig H. Hansen The Toronto Stock Exchange
Calgary, Alberta
Zargon Energy Trust
K. James Harrison (3) (4) Trust Units
Oakville, Ontario Trading Symbol: ZAR.UN

Kyle D. Kitagawa (1) (2) Zargon Oil & Gas Ltd.
Calgary, Alberta Exchangeable Shares
Trading Symbol: ZOG.B
James J. Lawson (1) (3)
Oakville, Ontario TRANSFER AGENT

John O. McCutcheon Valiant Trust Company
Chairman of the Board 310, 606 - 4th Street S.W.
Vancouver, British Columbia Calgary, Alberta T2P 1T1

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




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



OFFICERS

Craig H. Hansen
President and Chief Executive Officer

Brent C. Heagy
Executive Vice President and Chief Financial Officer

Daniel A. Roulston
Executive Vice President, Operations

Henry J. Baird
Vice President, Exploitation

Mark I. Lake
Vice President, Exploration

Jason B. Dranchuk
Controller and Treasurer

Grant A. Zawalsky
Corporate Secretary

Lorne D. Schwetz
Vice President, Land

Contact Information

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