ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

August 14, 2006 02:01 ET

Zargon Energy Trust Announces 2006 Second Quarter Results

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

FINANCIAL & OPERATING HIGHLIGHTS

Zargon Energy Trust (TSX:ZAR.UN) (TSX:ZOG.B) is pleased to report continued strong financial results from operations in the second quarter of 2006. Cash flow from operations was $22.13 million ($1.14 per diluted trust unit) in the 2006 second quarter, compared with $22.35 million ($1.17 per diluted trust unit) in the 2006 first quarter and $19.01 million ($1.01 per diluted trust unit) in the 2005 second quarter.

Highlights from the three and six months ended June 30, 2006 are noted below:

- Second quarter 2006 production averaged 8,322 barrels of oil equivalent per day, an increase of one percent from the second quarter of 2005 and a decline of six percent from the preceding quarter. As anticipated, second quarter production volumes were held back due to a combination of scheduled and unscheduled plant maintenance, a seasonally restricted capital program, naturally occurring production declines and non-core property sales. For the first half of 2006, production of 8,566 barrels of oil equivalent per day equated to 447 barrels of oil equivalent per day per million trust units outstanding which is essentially unchanged from the 2005 first half's rate of 445.

- Revenue and cash flow from operations in the 2006 second quarter were impacted by a 22 percent increase in the realized crude oil prices over the previous quarter's prices. The gains from the record crude prices were offset by a 22 percent decrease in the 2006 second quarter natural gas prices from the first quarter levels. For the 2006 second quarter, the net effect of these offsetting price changes and the lower production volumes was a six percent decrease in revenues but only a one percent decrease in the cash flow from operations when compared to the 2006 first quarter.

- The Trust declared three monthly cash distributions of $0.18 per trust unit in the second quarter of 2006 for a total of $8.96 million. These cash distributions were equivalent to a payout ratio of 47 percent of the Trust's second quarter cash flow on a diluted trust unit basis and after considering the effect of the exchangeable shares not receiving distributions, the distributions amounted to 40 percent of cash flow from operations. The Trust's second quarter exploration and development capital expenditures included the drilling of 9.7 net wells and totalled $12.40 million. These expenditures were offset by $3.62 million of net property dispositions and Zargon's net capital program totalled $8.78 million, a 42 percent decline from the first quarter's $15.19 million net capital program. With the second quarter's cash flow substantially exceeding the sum of the Trust's distributions and capital expenditures, the Trust's balance sheet remains very strong with June 30, 2006 debt net of working capital totalling $21.83 million which equates to less than three months of the Trust's annualized cash flow.

- On June 30, 2006, 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 $100 million from the previous amount of $80 million.



Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
Percent Percent
(unaudited) 2006 2005 Change 2006 2005 Change
------------------------------------------------------------------------

FINANCIAL

Income and Investments ($
million)
Petroleum and natural gas
revenue 38.66 35.87 8 79.61 69.99 14
Cash flow from operations 22.13 19.01 16 44.48 36.50 22
Cash distributions 8.96 6.73 33 17.85 13.34 34
Net earnings 13.22 6.48 104 25.14 11.62 116
Net capital expenditures 8.78 10.96 (20) 23.97 21.65 11

Per Unit, Diluted
Cash flow from operations
($/unit) 1.14 1.01 13 2.32 1.94 20
Net earnings ($/unit) 0.79 0.41 93 1.52 0.73 108

Cash Distributions ($/trust
unit) 0.54 0.42 29 1.08 0.84 29

Balance Sheet at Period End ($
million)
Property and equipment, net 261.40 235.61 11
Bank debt 18.14 15.52 17
Unitholders' equity 159.81 138.88 15

Total Units Outstanding at
Period End (million) 19.29 18.77 3


OPERATING

Average Daily Production
Oil and liquids (bbl/d) 3,748 3,582 5 3,864 3,589 8
Natural gas (mmcf/d) 27.44 27.94 (2) 28.21 28.52 (1)
Equivalent (boe/d) 8,322 8,238 1 8,566 8,341 3
Equivalent per million total
units (boe/d) 433 439 (1) 447 445 -

Average Selling Price (before risk
management gain/loss)
Oil and liquids ($/bbl) 67.47 54.13 25 61.34 52.47 17
Natural gas ($/mcf) 6.27 7.17 (13) 7.19 6.96 3

Wells Drilled, Net 9.7 10.2 (5) 22.9 21.9 5

Undeveloped Land at Period End
(thousand net acres) 375 368 2
------------------------------------------------------------------------
------------------------------------------------------------------------

Notes: Throughout this report, the calculation of barrels of oil
equivalent (boe) is based on the conversion ratio that six
thousand cubic feet of natural gas is equivalent to one barrel
of oil.

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

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

Average daily production per million total 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 averaged 27.44 million cubic feet per day in the second quarter of 2006, two percent less than the corresponding period of 2005 and five percent less than the 2006 first quarter. In addition to natural declines, second quarter natural gas production volumes were also impacted by scheduled and unscheduled plant maintenance and weather related delays in the West Central Alberta core area, particularly in the Peace River Arch property. During the third quarter, the tie-in of six West Central Alberta wells drilled last winter at the Peace River Arch, Pembina and Highvale properties will add new production volumes. Also, multi-well Viking development programs are now getting underway in the Hamilton Lake and Jarrow properties in the Alberta Plains core area and will provide additional support for natural gas production volumes by the fourth quarter.

Oil and liquids production of 3,748 barrels per day in the 2006 second quarter showed a five percent increase over the 2005 second quarter and a six percent decline from the first quarter of 2006 which contained a significant amount of flush production from late 2005 horizontal well completions at Pinto, Saskatchewan and at the Haas and Truro, North Dakota properties.

CAPITAL EXPENDITURES(1)

During the 2006 second quarter, Zargon drilled 13 gross wells (9.7 net) that resulted in 3.2 net natural gas wells, 4.5 net oil wells and 2.0 net water injection wells. Although activity levels were restricted due to spring break-up conditions, the drilling program was highlighted by an exploration success at Progress in West Central Alberta and the drilling of four Williston Basin horizontal oil wells in the Truro and Haas properties of North Dakota and at Elswick in Southeast Saskatchewan. For the first half of the year, Zargon has drilled 22.9 net wells which are relatively equally divided between the West Central Alberta (6.9 net wells), Alberta Plains (8.0 net wells) and Williston Basin (8.0 net wells) core areas.

Over the last six months, Zargon has successfully focused on expanding and strengthening its technical capabilities in order to efficiently capture the substantial opportunities associated with its existing asset base. With our expanded technical staff coupled with recently improved access to field service equipment, Zargon is embarking on a very active field capital program in the second half of 2006. Highlights of the expanded second half drilling program include a 22 net well Viking down-spacing and step-out development program in the Jarrow and Hamilton Lake properties of the Alberta Plains. If successful, further large scale shallow gas development programs would be planned for 2007. Also in the Alberta Plains, two horizontal oil development wells at Jarrow and Taber could provide a substantial number of follow-up locations. In West Central Alberta, exploration and development natural gas wells are planned at Pembina (six wells), Highvale (three wells) and at the Peace River Arch (three wells). In the Williston Basin, Zargon will continue with horizontal and vertical well development programs to exploit existing waterfloods (eight wells planned), and will also drill four higher risk exploration wells on Bakken (Torquay) and Frobisher prospects in the Frys East and Pinto areas of Saskatchewan.

Although Crown land sale prices continue to be very high, Zargon has made sufficient, selective Crown acquisitions to offset expiries during the first half of 2006. Zargon's undeveloped land inventory at June 30, 2006 was 375 thousand net acres, which is two percent higher than 367 thousand net acres at year end 2005.

Transaction prices in the property market continued to set unprecedented highs and Zargon made no material acquisitions in the first half of 2006. In order to capture some of this enthusiasm, in the second quarter of 2006, Zargon marketed and sold two small higher operating cost, non-core oil properties having a combined 60 barrels per day of oil production for $3.70 million.

GUIDANCE(1)

In the November 14, 2005, and subsequent press releases, Zargon set its 2006 full year production guidance at 8,600 barrels of oil equivalent per day. For the first six months of 2006, Zargon's production has averaged 8,566 barrels of oil equivalent per day, less than one percent below guidance levels. The 2006 first quarter benefited from flush production rates from new Williston Basin horizontal oil wells and the tie-in of West Central Alberta natural gas wells drilled in the fourth quarter of 2005 and production averaged 8,812 barrels of oil equivalent per day, slightly higher than the annual guidance levels. As anticipated, in the second quarter, production declined to 8,322 barrels of oil equivalent per day due to the decline from initial flush oil and natural gas production rates, scheduled and unscheduled plant outages, a seasonally restricted capital program and the sale of non-core properties. At this time, Zargon reconfirms its 2006 guidance levels at 8,600 barrels of oil equivalent per day. With a planned very active summer/fall drilling program in each of the core areas plus the tie-in of West Central Alberta behind pipe gas reserves, it is anticipated that Zargon's production rates will steadily increase throughout the third and fourth quarters of 2006 providing positive production growth momentum into the first quarter of 2007. Zargon is increasing its 2006 capital budget by $10 million to $60 million to take advantage of Zargon's extensive inventory of internally generated opportunities in a recently improved cost and service availability environment. This increase will be allocated to both natural gas and oil drilling opportunities and will increase the expected 2006 well count to 75 net wells from last fall's original budget level of 50 net wells. The 2006 budget will be roughly divided equally between each of Zargon's three core areas and will continue to include a 25 percent exploration component. The impact of this expanded budget will not make a material difference to Zargon's production volumes in 2006, but should provide the foundation for continued steady production gains in 2007.

During the first half of 2006, Zargon maintained a base (sustainable) monthly distribution of $0.18 per unit, based on the underlying assumptions of production guidance of 8,600 barrels of oil equivalent per day, long term commodity prices of US $55 per barrel (WTI oil), US $8 per mmbtu (NYMEX natural gas) and a $0.87 Cdn./US dollar currency exchange rate. Consistent with last year's practice, if and when commodity prices exceed these assumptions, Zargon will consider supplemental semi-annual distributions to reach our stated goal of distributing approximately 50 percent of the cash flows attributable to unitholders. Although during the first half of 2006, Zargon distributed only 47 percent of the cash flow attributed to the unitholders, Zargon chose not to make a mid-year supplemental distribution due to the large decline, extreme volatility and poor predictability of this summer's natural gas prices. Our next supplemental distribution review date is scheduled for the December 2006 distribution that would be payable in mid- January 2007. The decision will be based on the commodity price environment, tax position and funding requirements for the exploration and development program at that time.

As in the past, production guidance levels do not include an allowance for property or corporate acquisitions that would be funded on an opportunistic basis by bank debt or possibly equity issues. Although the current acquisition market continues to remain highly competitive, the Trust will continue to seek opportunities to acquire underdeveloped oil properties (particularly in the Williston Basin) and undeveloped natural gas prospective lands that provide the foundation for future exploration and development programs designed to deliver sustainable results.

(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, 2006 and the audited consolidated financial statements and MD&A for the year ended December 31, 2005. All amounts are in Canadian dollars unless otherwise noted. All references to "Zargon" or the "Trust" refer to Zargon Energy Trust.

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

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

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

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

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

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

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

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

Forward-Looking Statements - This document contains statements that are forward-looking, such as those relating to results of operations and financial condition, capital spending, financing sources, commodity prices, costs of production and the magnitude of oil and natural gas reserves. By their nature, forward-looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly actual results may differ materially from those predicted. The forward-looking statements contained in this report are as of August 10, 2006 and are subject to change after this date. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

This MD&A has been prepared as of August 10, 2006.

SUMMARY OF SIGNIFICANT EVENTS IN THE SECOND QUARTER

- During the second quarter of 2006, the Trust realized cash flow from operations of $22.13 million and declared total distributions of $8.96 million ($0.54 per trust unit) to unitholders, resulting in a quarterly payout ratio of 40 percent of cash flow or 47 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 risk management gains/losses) for oil and liquids increased to $67.47 per barrel and prices received for natural gas declined to $6.27 per thousand cubic feet, a 22 percent increase and a 22 percent decline, respectively, from the first quarter of 2006. As anticipated, second quarter production volumes of 8,322 barrels of oil equivalent per day showed a six percent decline from the first quarter record production levels due to a combination of scheduled and unscheduled plant maintenance, a seasonally low field capital program, naturally occurring production declines and non-core property sales.

- During the second quarter of 2006, the Trust drilled 13 gross wells (9.7 net) with a 100 percent success rate. Total net capital expenditures were $8.78 million for the quarter, which includes $4.20 million of property dispositions.

- The Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities) of $21.83 million, which represents slightly less than three months of the first half 2006 annualized cash flow.

- 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 $100 million. This expanded facility continues to be available for general corporate purposes and the potential acquisition of oil and gas properties.

- During the 2006 second quarter, Zargon recognized a future tax recovery of $6.01 million as a result of reductions in future federal and provincial income tax rates.

FINANCIAL ANALYSIS

During the second quarter of 2006, Zargon reported relatively strong levels of petroleum and natural gas revenue and cash flow from operations. Second quarter 2006 revenue of $38.66 million was six percent below the $40.94 million in the first quarter of 2006 and eight percent above $35.87 million in the second quarter of 2005. A decrease in production volumes of six percent from the previous quarter was the primary reason for the lower revenues. Oil and liquids prices received averaged $67.47 per barrel before risk management gains/losses in the second quarter of 2006 compared to $54.13 in the 2005 second quarter and $55.51 in the preceding quarter, an increase of 25 percent and 22 percent, respectively. Zargon's crude oil field price differential from the Edmonton par price decreased to $11.08 per barrel in the second quarter of 2006 compared to $13.45 per barrel in the first quarter of 2006. Natural gas prices received averaged $6.27 per thousand cubic feet before risk management gains/losses in the second quarter of 2006, a decrease of 13 percent from the 2005 second quarter prices and a 22 percent decline from the preceding quarter levels. In 2006, Zargon has realized a small non-recurring premium to the benchmark AECO average daily price due to a combination of fixed price physical contracts (see note 11 to the interim unaudited consolidated financial statements) and from the impact of Zargon's use of AECO monthly index contracts for approximately 21 percent of its first half natural gas production.



Pricing

Three Months Ended Six Months Ended
Average For The Period June 30, June 30,
-----------------------------------------------------------------------
Percent Percent
2006 2005 Change 2006 2005 Change
-----------------------------------------------------------------------

Natural Gas:
NYMEX average daily spot
price ($US/mmbtu) 6.54 6.94 (6) 7.13 6.68 7
AECO average daily spot price
($Cdn/mmbtu) 6.04 7.37 (18) 6.77 7.13 (5)
Realized price ($Cdn/mcf)(1) 6.27 7.17 (13) 7.19 6.96 3

Crude Oil:
WTI ($US/bbl) 70.70 53.19 33 67.09 51.52 30
Edmonton par price
($Cdn/bbl) 78.55 65.76 19 73.76 63.61 16
Realized price ($Cdn/bbl)(1) 67.47 54.13 25 61.34 52.47 17
-----------------------------------------------------------------------
-----------------------------------------------------------------------

(1) Amounts are before risk management gain/loss.


Natural gas production volumes decreased by five percent in the second quarter of 2006 to 27.44 million cubic feet per day from 28.99 million cubic feet per day in the first quarter of 2006 and were two percent lower than the 2005 second quarter. Oil and liquids production during the second quarter of 2006 was 3,748 barrels per day which is six percent below the 2006 first quarter rate of 3,981 barrels per day and five percent above the second quarter of 2005 level. The year-over-year increase in oil and liquids production is primarily due to the effect of a successful late 2005 Williston Basin core area exploitation drilling program. On a barrel of oil equivalent basis, Zargon produced 8,322 barrels of oil equivalent per day, which represents a six percent decrease from the 8,812 barrels of oil equivalent per day in the first quarter of 2006 and a one percent increase when compared to the second quarter of 2005. The second quarter production declines were due to a combination of scheduled and unscheduled plant maintenance, a seasonally low field capital program, naturally occurring production declines (specifically related to flush production rates from recently drilled Williston Basin oil wells) and non-core property sales.



Production by Core Area

Three Months Ended June 30,
------------------------------------------------------------------------
2006 2005
------------------------------------------------------------------------
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 508 18.54 3,598 597 19.53 3,852
West Central
Alberta 179 8.68 1,626 209 8.13 1,563
Williston
Basin 3,061 0.22 3,098 2,776 0.28 2,823
------------------------------------------------------------------------

3,748 27.44 8,322 3,582 27.94 8,238
------------------------------------------------------------------------
------------------------------------------------------------------------

Six Months Ended June 30,
------------------------------------------------------------------------
2006 2005
------------------------------------------------------------------------
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 524 19.33 3,746 569 19.55 3,827
West Central
Alberta 183 8.66 1,626 203 8.70 1,652
Williston
Basin 3,157 0.22 3,194 2,817 0.27 2,862
------------------------------------------------------------------------

3,864 28.21 8,566 3,589 28.52 8,341
------------------------------------------------------------------------
------------------------------------------------------------------------


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 price fluctuations. Because our risk management strategy is protective in nature and is designed to guard the Trust against extreme effects on cash flow from sudden falls in prices and revenues, upward price trends tend to produce overall losses. Financial risk management contracts in place as at December 31, 2004 were designated as hedges for accounting purposes and the Trust monitored these contracts in determining the continuation of hedge effectiveness. As at June 30, 2006, all designated hedge contracts had expired. For these contracts, realized gains and losses were recorded in the statement of earnings as the contracts settled and no unrealized gain or loss was recognized. For financial risk management contracts entered into after December 31, 2004, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and accordingly, for these contracts, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end. In relation to the terms of specific financial risk management contracts, the 2006 second quarter's relatively high oil prices were somewhat offset by relatively low natural gas prices resulting in a net realized risk management loss on these contracts of $0.71 million that compares to a $1.36 million realized net loss in the first quarter of 2006 and a $1.23 million realized net loss in the second quarter of 2005. The 2006 second quarter unrealized risk management oil contract losses were nearly offset by unrealized risk management natural gas contract gains for the same period resulting in a net nominal charge when compared to a $2.49 million gain in the preceding quarter and a $1.10 million loss in the second quarter of 2005. These unrealized risk management gains or losses reflect the change over the reporting period in the mark-to-market valuation of Zargon's future contracts as compared to the very volatile futures commodity market. Zargon's commodity risk management positions are fully described in note 11 to the unaudited consolidated interim financial statements.

Royalties, inclusive of Alberta Royalty Credit and Saskatchewan Resource Surcharge, totalled $8.09 million for the second quarter of 2006, a decrease of 10 percent from the $9.02 million preceding quarter expense and an increase of two percent from $7.91 million in the second quarter of 2005. The variations generally track changes in production, prices and volumes. As a percentage of gross revenue, royalty rates moved in a narrow range from 22.1 percent in the second quarter of 2005 to 22.0 percent in the first quarter of 2006 and 20.9 percent in the second quarter of 2006. The lower royalty rates in the second quarter of 2006 compared to the second quarter of 2005 and to the first quarter of 2006 are a result of adjustments related to prior periods and are also due to the effect of revenue gains Zargon has achieved in the quarter from fixing a portion of its natural gas revenue on the AECO monthly pricing index versus the AECO average daily index. Zargon expects that its royalty rate will approximate 23 percent for the remainder of 2006 based on current prices and production rates.

On a unit of production basis, production costs of $7.67 per barrel of oil equivalent in the second quarter of 2006 compares with $7.55 in the preceding quarter and $7.67 in the second quarter of 2005. The containment of the industry-wide trend to increased unit operating costs continues to be a key initiative for Zargon. In the first half of 2006, the containment of production costs has been assisted by the positive impact of relatively higher flush production rates from new wells and from the second quarter sale of non-core higher cost properties. Although industry cost pressures continue, for the reminder of the year Zargon anticipates that it will be able to hold the per unit production costs to a level under the $8.00 per barrel of oil equivalent threshold.



Operating Netbacks

Three Months Ended June 30,
------------------------------------------------------------------------
2006 2005
------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
------------------------------------------------------------------------

Production revenue 67.47 6.27 54.13 7.17
Realized risk management
gain/(loss) (5.66) 0.49 (2.84) (0.12)
Royalties (14.75) (1.22) (12.00) (1.57)
Production costs (10.10) (0.95) (9.84) (1.00)
------------------------------------------------------------------------

Operating netbacks 36.96 4.59 29.45 4.48
------------------------------------------------------------------------
------------------------------------------------------------------------

Six Months Ended June 30,
------------------------------------------------------------------------
2006 2005
------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
------------------------------------------------------------------------

Production revenue 61.34 7.19 52.47 6.96
Realized risk management
gain/(loss) (4.61) 0.23 (2.84) (0.04)
Royalties (13.53) (1.50) (11.83) (1.60)
Production costs (10.16) (0.92) (10.09) (0.98)
------------------------------------------------------------------------

Operating netbacks 33.04 5.00 27.71 4.34
------------------------------------------------------------------------
------------------------------------------------------------------------


Measured on a unit of production basis (net of recoveries), general and administrative expenses were $1.91 per barrel of oil equivalent in the first half of 2006 compared to $1.69 in the first half of 2005 and $1.99 for the twelve month period of 2005. The upward and continuing cost pressures on general and administrative expenses on a per unit of production basis are primarily due to increased staff and related costs.

Expensing of unit-based compensation in the first half of 2006 was $0.69 million, a 45 percent increase from the first half of 2005. Increases are a result of unit-right grants which generally occur on a quarterly basis.

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges on these facilities in the second quarter were $0.38 million, $0.07 million higher than the previous quarter amount of $0.31 million and an increase of $0.18 million from $0.20 million in the second quarter of 2005. This increase is primarily due to a combination of higher 2006 average bank debt levels and higher effective interest rates. On June 30, 2006, Zargon amended and renewed its syndicated committed credit facilities, which resulted in an increase in the available facilities and borrowing base to $100 million from the previous amount of $80 million. The next renewal date is July 31, 2007.

Capital and current income taxes decreased $0.28 million to $0.11 million from the first quarter of 2006 and decreased $0.41 million when compared to the second quarter of 2005. Despite upward pressures on taxability on Zargon's United States operations which totalled $0.24 million in the 2006 second quarter, Zargon's consolidated capital and current income taxes declined as a result of declining rates and a prior year recovery of Canadian capital taxes in the amount of $0.28 million. Furthermore, in a recent budget announcement the Canadian federal government substantively enacted legislation to eliminate the federal capital tax effective January 1, 2006. As a result of these changes, the federal capital taxes recorded in the 2006 first quarter have been eliminated in the 2006 second quarter.



Trust Netbacks

Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
($/boe) 2006 2005 2006 2005
------------------------------------------------------------------------

Petroleum and natural gas
revenue 51.06 47.85 51.35 46.35
Realized risk management loss (0.94) (1.65) (1.34) (1.34)
Royalties (10.68) (10.55) (11.04) (10.57)
Production costs (7.67) (7.67) (7.61) (7.70)
------------------------------------------------------------------------

Operating netbacks 31.77 27.98 31.36 26.74

General and administrative (1.91) (1.66) (1.91) (1.69)
Interest and financing charges (0.50) (0.27) (0.44) (0.25)
Capital and current income taxes (0.14) (0.69) (0.32) (0.63)
------------------------------------------------------------------------

Cash flow netbacks 29.22 25.36 28.69 24.17

Depletion and depreciation (13.10) (12.05) (12.97) (11.79)
Unrealized risk management
gain/(loss) - (1.46) 1.60 (2.22)
Accretion of asset retirement
obligations (0.41) (0.40) (0.40) (0.39)
Unit-based compensation (0.48) (0.20) (0.44) (0.31)
Unrealized foreign exchange
gain/(loss) 0.52 (0.13) 0.27 (0.10)
Future income taxes
recovery/(expense) 4.52 (0.93) 2.07 (0.25)
------------------------------------------------------------------------

Earnings before non-controlling
interest 20.27 10.19 18.82 9.11
------------------------------------------------------------------------
------------------------------------------------------------------------


Depletion and depreciation expense for the second quarter of 2006 decreased slightly by three percent to $9.92 million, compared to $10.19 million in the prior quarter and increased 10 percent when compared to the second quarter 2005 expense of $9.04 million. On a per barrel of oil equivalent basis, the depletion and depreciation rates were $13.10, $12.85 and $12.05 for the second and first quarters of 2006 and the second quarter of 2005, respectively. The primary reasons for the year-over-year expense increase are due to the increase in the property and equipment balance from the conversion of exchangeable shares due to the application of EIC-151, and also as a result of production losses and the related reserve adjustments for wells in the West Central Alberta core area.

The provision for accretion of asset retirement obligations for the first half of 2006 was $0.62 million, a five percent increase compared to the first half of 2005. The year-over-year change is due to changes in the estimated future liability for asset retirement obligations as a result of wells added through Zargon's drilling program.

The provision for future taxes for the second quarter of 2006 was a recovery of $3.42 million compared to a provision for future tax expense of $0.21 million in the prior quarter and an expense of $0.70 million in the second quarter of 2005. Effectively, Zargon's future tax obligations are reduced as distributions are made from the Trust and consequently it is anticipated that Zargon's effective tax rate will continue to be low. The 2006 second quarter and the first half of 2006 include a recovery of $6.01 million relating to a reduction in future federal and provincial income tax rates substantively enacted during the quarter and includes the impact of certain tax balance adjustments.

According to the January 19, 2005 CICA pronouncement, EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", Zargon Energy Trust must reflect the exchangeable securities issued by its subsidiary (Zargon Oil & Gas Ltd.) as a non-controlling interest. Prior to 2005, these exchangeable shares were reflected as a component of unitholders' equity. Accordingly, the Trust has reflected a non-controlling interest of $15.93 million on the Trust's consolidated balance sheet as at June 30, 2006. Consolidated net earnings have been reduced for net earnings attributable to the non-controlling interest of $2.13 million in the second quarter of 2006. In accordance with EIC-151 and given the circumstances in Zargon's case, each exchangeable share redemption is accounted for as a step-purchase, which in the second quarter of 2006 resulted in an increase in property and equipment of $1.98 million, an increase in unitholders' equity by $1.87 million and an increase in future income tax liability of $0.52 million. Cash flow was not impacted by this change. The cumulative impact to date of the application of EIC-151 has been to increase property and equipment by $40.47 million, unitholders' equity and non-controlling interest by $41.78 million, future income tax liability by $10.59 million and an allocation of net earnings to exchangeable shareholders' of $11.90 million.

Cash flow from operations in the 2006 second quarter of $22.13 million was $0.22 million, or one percent lower than the preceding quarter and $3.11 million or 16 percent higher than the prior year second quarter. The decline in cash flow from the preceding quarter was primarily due to the decline in production volumes and the resulting decrease in revenue. With the prior year quarterly comparison, commodity prices received on a barrel of oil equivalent basis were seven percent higher and production volumes were one percent higher. Cash flow on a per diluted trust unit basis was $1.14 for the second quarter of 2006, a three percent decrease from the prior quarter and a 13 percent increase from the second quarter of 2005 which tracks the changes in cash flow for the respective periods.

Net earnings of $13.22 million for the second quarter of 2006 were 11 percent above $11.92 million in the preceding quarter and 104 percent above $6.48 million in the second quarter of 2005. The net earnings track the cash flow from operations for the respective periods modified by non-cash charges, which in the 2006 period include depletion and depreciation, unrealized risk management gains/losses, future income taxes/recoveries and non-controlling interest.




Capital Expenditures

Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
($ million) 2006 2005 2006 2005
------------------------------------------------------------------------

Undeveloped land 1.70 0.87 2.90 1.73
Geological and geophysical
(seismic) 0.85 0.64 1.85 1.47
Drilling and completion of
wells 6.92 6.88 15.46 13.15
Well equipment and facilities 2.93 1.85 7.37 3.96
------------------------------------------------------------------------

Exploration and development 12.40 10.24 27.58 20.31
------------------------------------------------------------------------

Property acquisitions 0.58 0.72 0.89 1.34
Property dispositions (4.20) - (4.50) -
------------------------------------------------------------------------

Net property
acquisitions/(dispositions) (3.62) 0.72 (3.61) 1.34
------------------------------------------------------------------------

Total net capital expenditures 8.78 10.96 23.97 21.65
------------------------------------------------------------------------
------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Net capital expenditures of $23.97 million in the first half of 2006 were 11 percent higher than the first half of 2005, reflecting an active field program of 27 gross (22.9 net) wells compared to 25 gross (21.9 net) wells in the first half of 2005. Net capital expenditures for the first half of 2006 were allocated to Alberta Plains $8.39 million, West Central Alberta $9.51 million and Williston Basin $6.07 million. Field related drilling and completion expenses of $15.46 million were 18 percent higher than the prior year's first half field related capital program. During the second quarter of 2006, 9.7 net wells were drilled compared to 13.2 net wells in the first quarter of 2006 and 10.2 net wells in the second quarter of 2005. Also, during the quarter, Zargon divested two higher operating cost properties which were non-core to Zargon's operations for proceeds of $3.70 million. Cash flow from operations in the 2006 first half of $44.48 million, proceeds from the exercise of trust unit rights of $3.29 million and the increase in bank debt of $7.80 million funded the capital program, the changes in working capital and the cash distributions to the unitholders. At June 30, 2006, the Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities) of $21.83 million, as compared to $28.39 million at the end of the 2006 first quarter, which represents slightly less than three months of the first half 2006 annualized cash flow.

At August 10, 2006, Zargon Energy Trust had 16.657 million trust units and 2.286 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective August 10, 2006 exchange ratio of 1.15941, there would be 19.307 million trust units outstanding. Pursuant to the trust unit rights incentive plan there are currently an additional 0.976 million trust unit incentive rights issued and outstanding.



Capital Sources

Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
($ million) 2006 2005 2006 2005
------------------------------------------------------------------------

Cash flow from operations 22.13 19.01 44.48 36.50
Changes in working capital and
other 1.83 1.19 (13.75) (3.81)
Change in bank debt (8.50) (2.70) 7.80 1.29
Cash distributions to
unitholders (8.96) (6.73) (17.85) (13.34)
Issuance of trust units 2.28 0.19 3.29 1.01
------------------------------------------------------------------------

Total capital sources 8.78 10.96 23.97 21.65
------------------------------------------------------------------------
------------------------------------------------------------------------


CONTRACTUAL OBLIGATIONS

During the second quarter of 2006, Zargon renewed and expanded its office lease for six years until July 31, 2012. Payments required under this new office lease are as follows: remainder of 2006 - $0.33 million; 2007 - $0.73 million; 2008 - $0.85 million; 2009 - $0.85 million; 2010 - $0.85 million; thereafter - $1.34 million. There have been no other significant changes in Zargon's commitments from those previously disclosed in the 2005 annual report.

OUTLOOK

With a very strong balance sheet, 375 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 2006, Zargon is forecasting an average production rate of 8,600 barrels of oil equivalent per day. Although Zargon continues to enjoy a period of high cash flows, the Trust intends to continue with the disciplined approach that has served Zargon well to date. The Trust will adhere to a focused strategy of exploring and exploiting its existing asset base while executing value-added property acquisitions, which if available, would be funded by bank debt or equity issues.



SUMMARY OF QUARTERLY RESULTS

2006
------------------------------------------------------------------------
Q1 Q2
------------------------------------------------------------------------
Petroleum and natural gas revenue ($ million) 40.94 38.66
Net earnings ($ million) 11.92 13.22
Net earnings per diluted unit ($) 0.72 0.79
Cash flow ($ million) 22.35 22.13
Cash flow per diluted unit ($) 1.17 1.14
Cash distributions ($ million) 8.89 8.96
Cash distributions declared per unit ($) 0.54 0.54
Net capital expenditures ($ million) 15.19 8.78
Total assets ($ million) 282.35 283.86
Bank debt ($ million) 26.64 18.14
Average daily production (boe) 8,812 8,322
Average realized commodity price before risk
management gain/loss ($/boe) 51.63 51.06
Cash flow netback ($/boe) 28.18 29.22
------------------------------------------------------------------------
------------------------------------------------------------------------

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

2004
------------------------------------------------------------------------
Q1 Q2 Q3 Q4
------------------------------------------------------------------------
Petroleum and natural gas revenue
($ million) 27.70 30.96 32.41 32.90
Net earnings ($ million) (2) 5.54 5.54 4.22 5.33
Net earnings per diluted
unit ($) (2) 0.30 0.29 0.28 0.34
Cash flow ($ million) 15.73 16.53 16.13 15.36
Cash flow per diluted unit ($) 0.84 0.88 0.87 0.82
Cash distributions ($ million) - - 4.27 6.43
Cash distributions declared per
unit ($) - - 0.28 0.42
Net capital expenditures
($ million) 9.77 7.61 23.64 15.25
Total assets ($ million) (2) 186.18 189.80 215.23 226.96
Bank debt ($ million) 3.67 - 9.77 14.23
Average daily production (boe) 7,889 8,150 8,405 8,440
Average realized commodity
price before risk
management gain/loss ($/boe) 38.59 41.75 41.91 42.36
Cash flow netback ($/boe) 21.91 22.28 20.86 19.78
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Amounts include capital expenditures acquired for cash and equity
issuances.
(2) Certain comparative period numbers reflect retroactive restatements
due to changes in accounting policies.


ADDITIONAL INFORMATION

Additional information regarding the Trust and its business operations, including the Trust's Annual Information Form for December 31, 2005, is available on the Trust's SEDAR profile at www.sedar.com.



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


Calgary, Alberta
August 10, 2006


ZARGON ENERGY TRUST
CONSOLIDATED BALANCE SHEETS

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

ASSETS (note 4)

Current
Accounts receivable 16,237 21,835
Prepaid expenses and deposits 2,960 2,710
Unrealized risk management asset (note 11) 3,260 -
------------------------------------------------------------------------

22,457 24,545

Property and equipment, net (note 3) 261,401 253,315
------------------------------------------------------------------------

283,858 277,860
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES

Current
Accounts payable and accrued
liabilities 19,891 30,570
Cash distributions payable 2,998 11,122
Unrealized risk management liability (note 11) 4,533 3,756
------------------------------------------------------------------------

27,422 45,448

Long term debt (note 4) 18,136 10,339

Asset retirement obligations (note 5) 16,119 15,859

Future income taxes (note 7) 46,440 48,928
------------------------------------------------------------------------

108,117 120,574
------------------------------------------------------------------------

NON-CONTROLLING INTEREST

Exchangeable shares (note 2) 15,928 12,673
------------------------------------------------------------------------

UNITHOLDERS' EQUITY

Unitholders' capital (note 6) 79,534 71,644
Contributed surplus (note 6) 1,366 1,347
Accumulated earnings 144,904 119,768
Accumulated cash distributions (note 13) (65,991) (48,146)
------------------------------------------------------------------------

159,813 144,613
------------------------------------------------------------------------

283,858 277,860
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF EARNINGS AND ACCUMULATED EARNINGS

Three Months Ended Six Months Ended
(unaudited) June 30, June 30,
($ thousand, except per unit amounts) 2006 2005 2006 2005
------------------------------------------------------------------------

REVENUE
Petroleum and natural gas revenue 38,664 35,868 79,607 69,992
Unrealized risk management
gain/(loss) (note 11) (3) (1,095) 2,482 (3,351)
Realized risk management loss
(note 11) (708) (1,234) (2,069) (2,019)
Royalties (8,087) (7,911) (17,110) (15,946)
------------------------------------------------------------------------

29,866 25,628 62,910 48,676
------------------------------------------------------------------------

EXPENSES
Production 5,812 5,749 11,799 11,633
General and administrative 1,444 1,246 2,967 2,554
Unit-based compensation (note 6) 366 147 685 473
Interest and financing charges 376 200 686 384
Unrealized foreign exchange
(gain)/loss (397) 97 (422) 151
Accretion of asset retirement
obligations (note 5) 312 298 622 592
Depletion and depreciation 9,922 9,037 20,114 17,801
------------------------------------------------------------------------

17,835 16,774 36,451 33,588
------------------------------------------------------------------------

EARNINGS BEFORE INCOME TAXES 12,031 8,854 26,459 15,088
------------------------------------------------------------------------

INCOME TAXES (note 7)
Current 110 515 498 959
Future (recovery) (3,421) 696 (3,209) 377
------------------------------------------------------------------------

(3,311) 1,211 (2,711) 1,336
------------------------------------------------------------------------

EARNINGS FOR THE PERIOD BEFORE
NON-CONTROLLING INTEREST 15,342 7,643 29,170 13,752

Non-controlling interest -
exchangeable shares (note 2) (2,127) (1,161) (4,034) (2,130)
------------------------------------------------------------------------

NET EARNINGS FOR THE PERIOD 13,215 6,482 25,136 11,622

ACCUMULATED EARNINGS, BEGINNING OF
PERIOD 131,689 89,539 119,768 84,399
------------------------------------------------------------------------

ACCUMULATED EARNINGS, END OF PERIOD 144,904 96,021 144,904 96,021
------------------------------------------------------------------------
------------------------------------------------------------------------

NET EARNINGS PER UNIT (note 8)
Basic 0.80 0.41 1.52 0.74
Diluted 0.79 0.41 1.52 0.73
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes.


ZARGON ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Six Months Ended
(unaudited) June 30, June 30,
($ thousand) 2006 2005 2006 2005
------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings for the period 13,215 6,482 25,136 11,622
Add (deduct) non-cash items:
Non-controlling interest -
exchangeable shares 2,127 1,161 4,034 2,130
Unrealized risk management
(gain)/loss 3 1,095 (2,482) 3,351
Depletion and depreciation 9,922 9,037 20,114 17,801
Accretion of asset retirement
obligations 312 298 622 592
Unit-based compensation 366 147 685 473
Unrealized foreign exchange
(gain)/loss (397) 97 (422) 151
Future income taxes (recovery) (3,421) 696 (3,209) 377
------------------------------------------------------------------------

22,127 19,013 44,478 36,497

Asset retirement expenditures (64) (159) (294) (221)
Changes in non-cash working capital 1,279 1,325 (3,396) (231)
------------------------------------------------------------------------

23,342 20,179 40,788 36,045
------------------------------------------------------------------------

FINANCING ACTIVITIES
Advances (repayment) of bank debt (8,502) (2,703) 7,797 1,292
Cash distributions to unitholders (8,957) (6,732) (17,845) (13,336)
Exercise of unit rights 2,280 195 3,294 1,008
Changes in non-cash working capital 32 34 (8,123) 111
------------------------------------------------------------------------

(15,147) (9,206) (14,877) (10,925)
------------------------------------------------------------------------

INVESTING ACTIVITIES
Additions to property and equipment (12,978) (10,965) (28,471) (21,650)
Proceeds on disposal of property and
equipment 4,200 - 4,500 -
Changes in non-cash working capital 583 (8) (1,940) (3,470)
------------------------------------------------------------------------

(8,195) (10,973) (25,911) (25,120)
------------------------------------------------------------------------

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


ZARGON ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the three and six months ended June 30, 2006 and 2005 (unaudited)

1. BASIS OF PRESENTATION

The interim unaudited consolidated financial statements of Zargon Energy Trust (the "Trust" or "Zargon") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim unaudited consolidated financial statements have been prepared following the same accounting policies and methods in computation as the consolidated financial statements for the fiscal year ended December 31, 2005. These interim unaudited consolidated financial statements do not include all disclosures required in the annual consolidated financial statements. The interim unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the Zargon Energy Trust annual report for the year ended December 31, 2005.

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

2. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

Zargon Oil & Gas Ltd. is authorized to issue a maximum of 3.66 million exchangeable shares. The exchangeable shares are convertible into trust units at the option of the shareholder based on the exchange ratio, which is adjusted monthly to reflect the distribution paid on the trust units. Cash distributions are not paid on the exchangeable shares. During the six months ended June 30, 2006, a total of 0.12 million exchangeable shares were converted into 0.13 million trust units based on the exchange ratio at the time of conversion. At June 30, 2006, the exchange ratio was 1.15269 trust units per exchangeable share.

Non-Controlling Interest - Exchangeable Shares



Six Months Ended
June 30, 2006
------------------------------------------------------------------------
Number
of Amount
(thousand, except exchange ratio) Shares ($)
------------------------------------------------------------------------

Non-controlling interest exchangeable shares
issued
Balance, beginning of period 2,402 12,673
Earnings attributable to non-controlling interest - 4,034
Exchanged for trust units at book value and
including earnings attributed since beginning of
period (115) (779)
------------------------------------------------------------------------

Balance, end of period 2,287 15,928
------------------------------------------------------------------------
------------------------------------------------------------------------

Exchange ratio, end of period 1.15269
Trust units issuable upon conversion of
exchangeable shares, end of period 2,636
------------------------------------------------------------------------
------------------------------------------------------------------------


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

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

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



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

Balance, beginning of period 71,644 12,673 84,317
Issued on redemption of exchangeable
shares at book value 281 (281) -
Effect of EIC-151 3,649 3,536 7,185
Unit-based compensation recognized on
exercise of unit rights 666 - 666
Unit rights exercised for cash 3,294 - 3,294
------------------------------------------------------------------------

Balance at June 30, 2006 79,534 15,928 95,462
------------------------------------------------------------------------
------------------------------------------------------------------------


3. PROPERTY AND EQUIPMENT
June 30, 2006
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousand) Cost Depreciation Value
------------------------------------------------------------------------

Petroleum, natural gas properties
and other equipment(1) 416,977 155,576 261,401
------------------------------------------------------------------------
------------------------------------------------------------------------

December 31, 2005
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousand) Cost Depreciation Value
------------------------------------------------------------------------

Petroleum, natural gas properties
and other equipment(1) 388,777 135,462 253,315
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) As a result of shareholders redeeming exchangeable shares, property
and equipment has cumulatively increased $40.47 million, $4.26
million relating to the first six months of 2006, $24.93 million
relating to 2005 and $11.28 million relating to 2004. The effect of
these increases has resulted in additional depletion and
depreciation expense recorded in the first six months of 2006 of
$2.79 million and $2.40 million for the same period in 2005.


4. LONG TERM DEBT

On June 30, 2006, Zargon amended and renewed its syndicated committed credit facilities, the result of which is an increase in the available facilities and borrowing base to $100 million from the previous amount of $80 million. These facilities consist of an $80 million tranche available to the Canadian borrower and a US $15 million tranche available to the US borrower. A $150 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities. The facilities are fully revolving for a 364 day period with the provision for an annual extension at the option of the lenders and upon notice from Zargon's management. The next renewal date is July 31, 2007. Should the facilities not be renewed, they convert to one year non-revolving term facilities at the end of the revolving 364 day period. Repayment would not be required until the end of the non-revolving term, and as such, these facilities have been classified as long term debt.

5. ASSET RETIREMENT OBLIGATIONS

The following table reconciles Zargon's asset retirement obligation:



Six Months
Ended June 30,
------------------------------------------------------------------------
($ thousand) 2006 2005
------------------------------------------------------------------------

Balance, beginning of period 15,859 14,390
Net liabilities incurred/(disposed) (28) 359
Liabilities settled (294) (221)
Accretion expense 622 592
Foreign exchange (40) 13
------------------------------------------------------------------------

Balance, end of period 16,119 15,133
------------------------------------------------------------------------
------------------------------------------------------------------------

6. UNITHOLDERS' EQUITY

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

Trust Units
Six Months Ended
June 30, 2006
------------------------------------------------------------------------
Number
of Amount
(thousand) Units ($)
------------------------------------------------------------------------

Units issued
Balance, beginning of period 16,355 71,644
Unit rights exercised for cash 170 3,294
Unit-based compensation recognized on exercise of unit
rights - 666
Issued on conversion of exchangeable shares 131 3,930
------------------------------------------------------------------------

Balance, end of period 16,656 79,534
------------------------------------------------------------------------
------------------------------------------------------------------------


The proforma total units outstanding at June 30, 2006, including trust units outstanding, and trust units issuable upon conversion of exchangeable shares and after giving effect to the exchange ratio at the end of the period (see note 2) is 19.292 million units.

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



Contributed Surplus
Six Months Ended
June 30, 2006
------------------------------------------------------------------------

Balance, beginning of period 1,347
Unit-based compensation expense 685
Unit-based compensation recognized on exercise of unit
rights (666)
------------------------------------------------------------------------

Balance, end of period 1,366
------------------------------------------------------------------------
------------------------------------------------------------------------


Trust Unit Rights Incentive Plan and Unit-Based Compensation

The Trust has a unit rights incentive plan (the "Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and service providers. The Trust is authorized to issue up to 1.82 million unit rights, however, the number of trust units reserved for issuance upon exercise of the rights shall not at any time exceed 10 percent of the aggregate number of issued and outstanding trust units of the Trust. At the time of grant, unit right exercise prices approximate the market price for the trust units. At the time of exercise, the rights holder has the option of exercising at the original grant price or the exercise price as calculated per the Arrangement. Rights granted under the Plan generally vest over a three-year period and expire approximately five years from the grant date. Zargon uses a fair value methodology to value the unit rights grants.

The weighted average assumptions made for unit rights granted for 2006 include a volatility factor of expected market price of 27.6 percent, a risk-free interest rate of 4.03 percent, a dividend yield of 7.09 percent and an expected life of the unit rights of four years, resulting in unit-based compensation expense of $0.69 million for the six months ended June 30, 2006.

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



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


Six Months Ended
June 30, 2006
------------------------------------------------------------------------
Weighted
Average
Number of Exercise
Unit Rights Price
(thousand) ($/unit right)
------------------------------------------------------------------------

Outstanding at beginning of period 915 22.80
Unit rights granted 246 30.50
Unit rights exercised (170) 19.43
Unit rights cancelled (15) 25.05
---------------------------------------------------------

Outstanding at end of period 976 25.29
---------------------------------------------------------
---------------------------------------------------------

Unit rights exercisable at period end 251 23.29
------------------------------------------------------------------------
------------------------------------------------------------------------


7. INCOME TAXES

Included in the provision for current taxes for the three months ended June 30, 2006 is a recovery of $0.17 million due to the new federal government budget eliminating the large corporation tax effective for 2006.

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



8. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS

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

Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------------------------------------
(thousand units) 2006 2005 2006 2005
------------------------------------------------------------------------

Basic 16,549 15,930 16,492 15,776

Diluted 19,335 18,840 19,206 18,803
------------------------------------------------------------------------
------------------------------------------------------------------------


9. SEGMENTED INFORMATION

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

Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------------------------------------
($ thousand) 2006 2005 2006 2005
------------------------------------------------------------------------

Petroleum and Natural Gas Revenue
Canada 31,859 31,173 67,171 60,630
United States 6,805 4,695 12,436 9,362
------------------------------------------------------------------------

Total 38,664 35,868 79,607 69,992
------------------------------------------------------------------------
------------------------------------------------------------------------

Net Capital Expenditures
Canada 6,295 9,999 20,987 20,642
United States 2,483 966 2,984 1,008
------------------------------------------------------------------------

Total 8,778 10,965 23,971 21,650
------------------------------------------------------------------------
------------------------------------------------------------------------


June 30, December 31,
($ thousand) 2006 2005
------------------------------------------------------------------------

Property and Equipment, net
Canada 227,794 221,664
United States 33,607 31,651
------------------------------------------------------------------------

Total 261,401 253,315
------------------------------------------------------------------------
------------------------------------------------------------------------

10. SUPPLEMENTAL CASH FLOW INFORMATION

Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------------------------------------
($ thousand) 2006 2005 2006 2005
------------------------------------------------------------------------

Cash interest paid 335 173 703 391

Cash taxes paid 335 420 726 864
------------------------------------------------------------------------
------------------------------------------------------------------------


11. RISK MANAGEMENT CONTRACTS

The Trust is a party to certain financial instruments that have fixed the price of a portion of its oil and natural gas production. The Trust enters into these contracts for risk management purposes only, in order to protect a portion of its future cash flow from the volatility of oil and natural gas commodity prices. The Trust has outstanding contracts at June 30, 2006 as follows:




Financial Contracts at June 30, 2006:
Fair Market
Value
Gain/(Loss)
Rate Price Range of Terms ($thousand)
------------------------------------------------------------------------
Oil 600 bbl/d $54.55 US/bbl Jul. 1/06-Dec. 31/06 (2,584)
swaps 100 bbl/d $71.50 US/bbl Jul. 1/06-Dec. 31/07 (261)
500 bbl/d $67.33 US/bbl Jan. 1/07-Jun. 30/07 (913)
300 bbl/d $72.61 US/bbl Jan. 1/07-Dec. 31/07 (414)
400 bbl/d $71.48 US/bbl Jul. 1/07-Dec. 31/07 (360)

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

Natural 4,000 gj/d $9.31/gj Jul. 1/06-Oct. 31/06 1,901
gas 3,000 gj/d $9.13/gj Nov. 1/06-Mar. 31/07 186
swaps 4,000 gj/d $8.47/gj Apr. 1/07-Oct. 31/07 785

Natural 1,000 gj/d $9.50/gj Put Nov. 1/06-Mar. 31/07 118
gas $12.50/gj Call
collars 1,000 gj/d $10.50/gj Put Nov. 1/06-Mar. 31/07 269
$13.18/gj Call
------------------------------------------------------------------------
Net Fair Market Value, Financial Contracts (1,273)
------------------------------------------------------------------------
------------------------------------------------------------------------

Physical Contracts at June 30, 2006:
Fair Market
Value
Gain/(Loss)
Rate Price Range of Terms ($thousand)
------------------------------------------------------------------------
Natural 4,000 gj/d $7.91/gj Jul. 1/06-Oct. 31/06 1,217
gas 2,000 gj/d $9.23/gj Nov. 1/06-Mar. 31/07 152
fixed
price

Natural 1,000 gj/d $8.50/gj Put Nov. 1/06-Mar. 31/07 -
gas $12.85/gj Call
collars 1,000 gj/d $9.50/gj Put Nov. 1/06-Mar. 31/07 118
$13.50/gj Call
------------------------------------------------------------------------
Total Fair Market Value, Physical Contracts 1,487
------------------------------------------------------------------------
------------------------------------------------------------------------


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

For financial risk management contracts, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and accordingly any unrealized gains or losses are recorded based on the fair value (mark-to-market) of the contracts at the period end. The unrealized gain for the first six months of 2006 was $2.48 million and the unrealized loss for the first six months of 2005 was $3.35 million.

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

12. COMMITMENTS

During the second quarter of 2006, Zargon renewed and expanded its office lease for six years until July 31, 2012. Payments required under this new office lease are as follows: remainder of 2006 - $0.33 million; 2007 - $0.73 million; 2008 - $0.85 million; 2009 - $0.85 million; 2010 - $0.85 million; thereafter - $1.34 million. There have been no other significant changes in Zargon's commitments from those previously disclosed in the 2005 annual report.

13. ACCUMULATED CASH DISTRIBUTIONS

During the six month period, the Trust declared cash distributions to the unitholders in the aggregate amount of $17.85 million (2005 - $13.34 million) in accordance with the following schedule:



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

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


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




CORPORATE INFORMATION

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

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

Website

www.zargon.ca



Contact Information

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