ZARGON ENERGY TRUST
TSX : ZAR.UN

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

Zargon Oil & Gas Ltd.

November 10, 2010 17:01 ET

Zargon Energy Trust Announces 2010 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 10, 2010) - Zargon Energy Trust (TSX:ZAR.UN) (TSX:ZOG.B)



FINANCIAL & OPERATING HIGHLIGHTS

Three Months Ended Nine Months Ended
September 30, September 30,
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Percent Percent
(unaudited) 2010 2009 Change 2010 2009 Change
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Financial

Income and Investments
($ millions)
Petroleum and natural
gas revenue 44.50 40.96 9 136.84 108.77 26
Funds flow from
operating activities 18.49 22.84 (19) 59.11 61.61 (4)
Cash flows from
operating activities 20.05 23.30 (14) 53.92 60.97 (12)
Cash distributions
(net of Distribution
Reinvestment Plan) 11.92 12.22 (2) 36.35 33.51 8
Net earnings 0.41 4.47 (91) 14.22 2.28 524
Net capital
expenditures (1.26) 29.32 (104) 51.74 91.72 (44)
Per Unit, Diluted
Funds flow from
operating activities
($/unit) 0.70 0.90 (22) 2.25 2.67 (16)
Cash flows from
operating activities
($/unit) 0.76 0.92 (17) 2.06 2.64 (22)
Net earnings ($/unit) 0.02 0.20 (90) 0.61 0.11 455
Cash Distributions
($/trust unit) 0.54 0.54 - 1.62 1.62 -
Balance Sheet at Period
End ($ millions)
Property and
equipment, net 435.91 431.72 1
Bank debt 97.61 77.05 27
Unitholders' equity 264.70 285.68 (7)
Total Units Outstanding
at Period End (millions) 26.81 25.93 3

Operating

Average Daily Production
Oil and liquids (bbl/d) 5,850 5,382 9 5,716 4,911 16
Natural gas (mmcf/d) 25.46 28.23 (10) 26.12 28.20 (7)
Equivalent (boe/d) 10,094 10,088 - 10,069 9,610 5
Equivalent per million
trust units (boe/d) 381 398 (4) 382 413 (8)
Average Selling Price
(before the impact of
financial risk
management contracts)
Oil and liquids ($/bbl) 67.64 64.72 5 69.43 56.51 23
Natural gas ($/mcf) 3.45 3.43 1 4.00 4.29 (7)
Wells Drilled, Net 4.8 10.3 (53) 23.8 20.7 15
Undeveloped Land at
Period End (thousand
net acres) 505 594 (15)
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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. For a further discussion
about this term, refer to the Management's Discussion and Analysis section
in this report.

For net capital expenditures, amounts include capital expenditures acquired
for cash, equity issuances, acquisitions costs and net debt assumed on
corporate acquisitions.

Funds flow from operating activities is a non-GAAP term that represents
net earnings/losses 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.


FINANCIAL & OPERATING HIGHLIGHTS

Zargon Energy Trust is pleased to report its financial results for the third quarter of 2010.

Highlights from the three and nine months ended September 30, 2010 are noted below:



-- Third quarter 2010 production averaged 10,094 barrels of oil equivalent
per day and was essentially unchanged from the preceding quarter and the
corresponding 2009 quarter. Reflecting Zargon's continuing focus on oil
exploitation initiatives, oil and liquids production averaged 5,850
barrels of oil per day in the third quarter, a two percent gain over the
prior quarter and a nine percent increase over the corresponding 2009
quarter.
-- Revenue and funds flow from operating activities each increased one
percent when compared to the prior quarter. Funds flow from operating
activities was $18.49 million ($0.70 per diluted trust unit) in the 2010
third quarter compared with $18.38 million ($0.70 per diluted trust
unit) in the 2010 second quarter and $22.84 million ($0.90 per diluted
trust unit) in the 2009 third quarter.
-- The Trust declared three monthly cash distributions of $0.18 per trust
unit in the third quarter of 2010 for a total of $12.71 million ($11.92
million after accounting for the trust units issued for the Distribution
Reinvestment Plan ("DRIP")). These cash distributions (net of the DRIP)
were equivalent to a payout ratio of 64 percent of funds flow from
operating activities.
-- The Trust's third quarter exploration and development capital
expenditures (excluding property acquisitions and dispositions)
decreased 36 percent from the prior quarter to $10.55 million primarily
as a result of delayed field programs due in part to an unusually wet
summer in the Alberta Plains South and Williston Basin core areas.
-- During the third quarter of 2010, Zargon completed a series of minor
property sales totalling $21.89 million, or $28.94 million inclusive of
the property sales concluded in the prior quarter. These property sales
related to a fully marketed spring property disposition package that
entailed 17 non-core minor oil properties that were producing
approximately 375 barrels of oil equivalent per day.
-- On September 9, 2010, Zargon closed the acquisition of Oakmont Energy
Ltd. ("Oakmont") for a total consideration of approximately 0.336
million Zargon trust units and the assumption of approximately $3.41
million of net debt for a total transaction value of approximately $9.36
million.
-- Debt net of working capital (excluding unrealized risk management
assets/liabilities and future income taxes) decreased 11 percent from
the prior quarter to $107.90 million at September 30, 2010, which
represents approximately 60 percent of the Trust's available credit
facilities at September 30, 2010. The Trust's balance sheet remains
strong with a debt net of working capital to annualized funds flow from
operating activities ratio of 1.4 times.
-- Subsequent to quarter end, Zargon Energy Trust announced that the Board
of Directors of Zargon Oil & Gas Ltd. have unanimously approved the
conversion of Zargon Energy Trust to a corporation. The conversion is
expected to be completed on December 31, 2010 and is proposed to be
implemented through a Plan of Arrangement that will require the approval
of two-thirds of the unitholders and exchangeable shareholders at a
special meeting to be held on December 15, 2010.


Production (1)

Oil and liquids production averaged 5,850 barrels per day in the 2010 third quarter, and was supported by Williston Basin horizontal drilling and the second quarter Little Bow oil exploitation property acquisition that offset our natural declines and property disposition volumes. Over the last year, the Williston Basin and Alberta Plains South oil exploitation horizontal programs have provided Zargon's best returns and, after a weather related hiatus, these programs are resuming in late fall. Reflecting continued success with Zargon's reservoir engineering focused strategy to increase oil recovery factors in smaller but under exploited reservoirs, the third quarter oil and liquids production was 58 percent of total production based on a 6:1 equivalent basis, which compares to 53 percent in the 2009 third quarter, 47 percent in the 2008 third quarter and 42 percent in the 2007 third quarter. Over this three year period since we initiated our return to our oil exploitation focus, Zargon has maintained a stable $0.18 per unit monthly distribution while increasing oil production volumes by 63 percent. Further oil production increases are anticipated in 2011 as we continue to execute our oil exploitation strategy.

Natural gas production volumes in the third quarter of 2010 averaged 25.46 million cubic feet per day, a two percent decrease from the previous quarter and a 10 percent decrease from the corresponding period of 2009. The third quarter 2010 natural gas production decreases were due to naturally occurring production declines, property disposition volumes, significant Peace River Arch third party processing shut-ins and weather related outages. In light of the comparatively strong returns available from our oil exploitation field capital programs, we have redirected essentially all of our discretionary natural gas capital programs to our oil exploitation business. Consequently, for the remainder of this year and next, we anticipate that our corporate natural gas production volumes will continue to decline.

With oil production increasing by nine percent and natural gas production decreasing by 10 percent in the last four quarters, production on a 6:1 equivalency basis has remained essentially unchanged over the last year at just over 10,000 barrels of oil equivalent per day. Due to some minor equity issuances during this period, total production per trust unit on a 6:1 equivalency basis declined four percent from 398 to 381 barrels of oil equivalent per day per million trust units. We do note, however, that this decline is at least partially mitigated by the relative value of the commodities, as evidenced by the 20:1 ratio of the oil and liquids price versus the natural gas price that Zargon received in the 2010 third quarter.

Capital Expenditures and Budgets (1)

Due to weather related surface access delays for our horizontal oil exploitation drilling program, Zargon's third quarter field capital program totalled $10.55 million, a 36 and 17 percent decrease from the respective 2010 second quarter and 2009 third quarter field capital expenditures. During the quarter, Zargon drilled eight gross wells (4.8 net) that resulted in 3.2 net oil wells and 1.6 net natural gas wells for a 100 percent success ratio. The drilling program included three oil exploitation horizontal wells (Steelman and Elswick) in the Williston Basin core area, one Taber horizontal well and two Jarrow natural gas wells in the Alberta Plains core area and one oil well and one natural gas well in the West Central Alberta core area.

For the remainder of 2010 and 2011, Zargon will proceed with a steady oil exploitation focused drilling program which is expected to deliver continuous drilling operations through until the 2011 spring break-up. In the Williston Basin, horizontal oil exploitation wells will be drilled at Cromer, Manitoba, Truro, North Dakota and Elswick, Steelman, Fertile, and Manor, Saskatchewan. Following spring break-up, we plan to reinitiate this continuous program with wells at Daly and Virden, Manitoba, Mackobee Coulee, North Dakota and Elswick, Steelman, Fertile, Weyburn North, Midale, and Manor, Saskatchewan. In aggregate, we have an inventory of more than 70 oil exploitation wells to drill on our Williston Basin properties, of which we anticipate that we will drill 24 wells in the next five quarters.

In the Alberta Plains, we are proceeding with similar continuous drilling operations through to the 2011 spring break-up, with oil exploitation locations at Taber, Killam South, Killam, Wayne and Hamilton Lake. Following spring break-up we plan to reinitiate this steady oil exploitation program with additional horizontal wells in the Taber, Killam and Hamilton Lake properties, plus additional exploitation wells (vertical and horizontal) at Provost, Bellshill Lake and Grand Forks. In aggregate, we have an inventory of more than 50 oil exploitation wells to drill on our Alberta Plains properties, of which we anticipate that we will drill 21 wells in the next five quarters.

In the West Central Alberta core area, we will proceed with two oil exploitation vertical locations in the fall-winter season at Spirit River and St. Anne. Zargon is not planning on drilling any natural gas wells in any of its core areas during this upcoming fall or winter drilling season.

With these upcoming field programs, we expect to drill a total of 10 net wells in the fourth quarter which will result in 34 net wells for the year and will take our total 2010 field capital expenditures to $60 million. The 2011 field capital program budgets 37 net wells, which corresponds to a 2011 field capital expenditure program of $65 million. These budgeted capital programs are rigorously focused on our core organizational strengths, where we use our reservoir engineering knowledge to increase reservoir oil recoveries from smaller and technically complex oil reservoirs that tend to be overlooked by our larger competitors.

In addition to our field related activities, Zargon has demonstrated a capability to make smaller accretive corporate and/or property acquisitions that have been funded by bank debt and/or equity issuances and have brought exploitable oil-in-place assets. To this end, on September 9, 2010, Zargon closed the acquisition of Oakmont Energy Ltd. for a total consideration of $9.36 million. This Alberta Plains South acquisition brings us three smaller oil-in-place exploitation projects and approximately 110 barrels of oil per day of oil production along with approximately 1.0 million cubic feet of natural gas per day.

In conjunction with our ongoing smaller corporate acquisition program, Zargon is proceeding with a continuous property disposition program that is designed to monetize the properties that we are not prepared to exploit or do not fit within a property footprint that we seek to expand. We see this program as an important source of funding for further acquisitions, as well as a fundamental element in our effort to deliver a disciplined focus on our core oil exploitation initiatives. In the third quarter, Zargon completed a spring 2010 disposition program with the sale of 17 non-core minor high-cost oil properties that were producing approximately 375 barrels of oil equivalent per day for approximately $22 million in the quarter and approximately $29 million for the entire program. In the fourth quarter, we are marketing an additional 17 non-core high-cost natural gas properties producing approximately 200 barrels of oil equivalent per day.

Guidance (1)

In the August 11, 2010 press release announcing the second quarter 2010 results, Zargon provided updated production guidance of 10,400 barrels of oil equivalent per day for the second half of 2010. During the third quarter, Zargon's production averaged 10,094 barrels of oil equivalent per day, which was approximately three percent below guidance. This shortfall reflects a quiet field capital quarter of deferred drilling programs due in part to surface access and weather considerations. More importantly, the shortfall is due to the suspension of our natural gas drilling initiatives coming from a corporate decision that we have better uses for our capital than the pursuit of the low return activities required to maintain or grow natural gas volumes.

Consequently, for the remainder of 2010 and for all of 2011, we anticipate that production will average approximately 10,000 barrels of oil equivalent per day on a 6:1 equivalency basis. Consistent with recent results, we anticipate that oil production volumes will grow in a lumpy but ultimately an annualized rate of 10 percent per year. Conversely, with only minor capital allocations, we anticipate that our natural gas production will decline at a similar 10 percent per year rate, with the end result that our total production will remain relatively steady on a 6:1 equivalency basis. Finally, we note that these guidance levels are based on a 2011 capital budget of $65 million that does not include any allowance for additional corporate/property acquisitions or dispositions and does not include any recognition of our Little Bow Alkaline Surfactant Polymer ("ASP") tertiary recovery project that, if approved next spring, would require some preliminary capital expenditures in late 2011.

Following a year of transition from both an organizational and structural perspective, Zargon looks forward to 2011 with a renewed focus and confidence. We remain well positioned with a strong balance sheet and a promising inventory of oil exploitation projects focused on increasing oil recovery factors in existing reservoirs through primary, secondary and now tertiary methods. We are also pleased that our historical conservative hedging, debt and distribution policies have enabled our organization to maintain the current monthly $0.18 per unit distribution for 60 consecutive months. Going forward as a corporation, we will continue to acknowledge that our primary objective is to deliver a stable stream of reliable dividends while sustaining our reserve and production parameters on a per share basis. We will also acknowledge that in the long run, our shareholders look for us to provide a well-managed low-risk long-dated call option on the price of oil as well as for us to ultimately provide a modest level of per share reserve and production growth in addition to a stable dividend yield.

As announced last August, we anticipate that, commencing in January 2011, our initial corporate dividend rate will be $0.14 per share per month, which, from a Canadian taxable shareholder perspective, is roughly equivalent, on an after tax basis, to our current distribution of $0.18 per unit per month. Based on current modelling, it is anticipated that this dividend rate will be initially funded from approximately 45-50 percent of our funds flow from operating activities (based on current forward prices). Over time, due to the upward trending forward price curve and due to expectations of continued oil volume growth, we anticipate that our corporate cash flow will grow and will permit the $0.14 per share per month dividend payout ratio to decline to our long term 35 percent payout target. Ultimately, it is our expectation that the combination of future accretive acquisitions and the incremental field capital programs funded by increased cash flows (after dividends) will provide the modest per share reserve and production growth that we desire. However, we would add a cautionary note that the proposed $0.14 per share monthly dividend is predicated on both the current forward commodity price strip and our current expectations regarding capital program efficiencies and production declines. Material changes to any of these assumptions may necessitate a change to our monthly dividend rate.

In order to implement our year end conversion to a corporation, Zargon is planning on using an exchange method whereby unitholders transfer their trust units in exchange for a single class of common shares of the corporation on a one-for-one basis. Exchangeable shareholders will receive common shares based on the number of exchangeable shares held multiplied by the exchange ratio as of December 31, 2010 after giving effect to the final distribution as a Trust. This exchange method will result in a tax-deferred rollover to unitholders and exchangeable shareholders. The conversion will be implemented through a Plan of Arrangement requiring court approval and two-thirds unitholder and exchangeable shareholder approval at a special meeting to be held on December 15, 2010.

(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") is a review of Zargon Energy Trust's 2010 third quarter financial results and should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2010 and the audited consolidated financial statements and related notes for the year ended December 31, 2009. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). All amounts are in Canadian dollars unless otherwise noted. All references to "Zargon" or the "Trust" refer to Zargon Energy Trust and all references to the "Company" refer to Zargon Oil & Gas Ltd.

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 operating activities"
("funds flow"), which should not be considered an alternative to, or
more meaningful than, "cash flows from operating activities" as
determined in accordance with Canadian GAAP as an indicator of the
Trust's financial performance. This term does not have any standardized
meaning as prescribed by GAAP and, therefore, the Trust's determination
of funds flow from operating activities may not be comparable to that
reported by other trusts. The reconciliation between cash flows from
operating activities and funds flow from operating activities can be
found in the table below and in the consolidated statements of cash
flows in the consolidated financial statements. The Trust evaluates its
performance based on net earnings and funds flow from operating
activities. The Trust considers funds flow from operating activities 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
operating activities per unit is calculated using the diluted weighted
average number of units for the period.

Funds Flow from Operating Activities Reconciliation

Three Months Ended Nine Months Ended
September 30, September 30,
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($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash flows from operating
activities 20.05 23.30 53.92 60.97
Changes in non-cash operating
working capital (1.56) (0.46) 5.19 0.64
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Funds flow from operating
activities 18.49 22.84 59.11 61.61
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----------------------------------------------------------------------------

-- The Trust also uses the term "debt net of working capital" or "net
debt". 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 unrealized risk
management assets/liabilities and future income taxes.
-- Operating netbacks per boe equal total petroleum and natural gas revenue
per boe adjusted for realized risk management gains and/or losses per
boe, royalties per boe and production costs per boe. Operating netbacks
are a useful measure to compare the Trust's operations with those of its
peers.
-- Funds flow netbacks per boe are calculated as operating netbacks less
general and administrative expenses per boe, interest and financing
charges per boe, asset retirement expenditures per boe and current
income taxes per boe. Funds flow netbacks are a useful measure to
compare the Trust's operations with those of its peers.


References to "production volumes" or "production" in this document refer to sales volumes.

Forward-Looking Statements - This document offers our assessment of Zargon's future plans and operations as at November 10, 2010, and contains forward-looking statements including:



-- our expectations for royalties referred to under the heading "Financial
Analysis";
-- our expectations for production and reserves referred to under the
heading "Financial and Operating Highlights";
-- our expectations for capital expenditures referred to under the heading
"Financial and Operating Highlights";
-- our expectations for current taxes referred to under the heading
"Financial Analysis";
-- our distribution/dividend policy referred to under the headings
"Financial and Operating Highlights", "Financial Analysis" and
"Liquidity and Capital Resources";
-- our expected sources of funds for distributions/dividends and capital
expenditures referred to under the headings "Financial and Operating
Highlights" and "Liquidity and Capital Resources";
-- our expectations for converting to a corporation from our current trust
structure as referred to under the headings "Financial and Operating
Highlights" and "Financial Analysis";
-- our expectations for operating results referred to under the headings
"Financial and Operating Highlights" and "Outlook";
-- our expectations for designing and implementing International Financial
Reporting Standards referred to under the heading "International
Financial Reporting Standards"; and
-- our expectations for the properties to be acquired and/or disposed
referred to under the heading "Financial and Operating Highlights".


Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe" and similar expressions (including the negatives thereof). By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. Risks are described in more detail in our Annual Information Form, which is available on our website and at www.sedar.com. Forward-looking statements are provided to allow investors to have a greater understanding of our business.

You are cautioned that the assumptions, including among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition, our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

This MD&A has been prepared as of November 10, 2010.

SUMMARY OF SIGNIFICANT EVENTS IN THE THIRD QUARTER



-- During the third quarter of 2010, the Trust realized funds flow from
operating activities of $18.49 million and declared distributions of
$12.71 million ($11.92 million in cash after considering the trust units
issued for the Distribution Reinvestment Plan, ("DRIP")) or $0.54 per
trust unit to unitholders. For Canadian income tax purposes, the
distributions are currently estimated to be 100 percent taxable income
to unitholders.
-- Average field prices received (before the impact of financial risk
management contracts) for oil and liquids and for natural gas increased
one percent to $67.64 per barrel and decreased seven percent to $3.45
per thousand cubic feet, respectively, compared to the second quarter of
2010.
-- Third quarter production volumes of 10,094 barrels of oil equivalent per
day were essentially unchanged from both the second quarter 2010 and the
third quarter 2009 production levels. Oil and liquids production during
the third quarter of 2010 were 5,850 barrels per day, which is two
percent above the 2010 second quarter rate of 5,740 barrels per day and
nine percent above the third quarter of 2009 level.
-- During the third quarter of 2010, the Trust drilled eight gross wells
(4.8 net) with a 100 percent success rate. Total field exploration and
development capital expenditures (excluding corporate and net property
dispositions) were $10.55 million for the quarter compared to $16.36
million for the prior quarter.
-- The Trust continues to maintain a relatively strong balance sheet with a
combined debt net of working capital (excluding unrealized risk
management assets/liabilities and future income taxes) of $107.90
million, an 11 percent reduction from $121.67 million at the end of the
second quarter, and represents approximately 60 percent of the Trust's
available credit facilities at September 30, 2010.
-- During the third quarter of 2010, Zargon completed property dispositions
totalling $21.89 million, or $28.94 million inclusive of the disposition
amounts realized in the prior quarter. In aggregate, this disposition
program included 17 non-core minor oil properties that were producing
approximately 375 barrels of oil equivalent per day.
-- On September 9, 2010, Zargon concluded the acquisition of Oakmont Energy
Ltd. ("Oakmont") for a total consideration of approximately 0.336
million Zargon trust units and the assumption of approximately $3.41
million of net debt for a total transaction value of approximately $9.36
million.
-- Subsequent to quarter end, Zargon Energy Trust announced that the Board
of Directors of Zargon Oil & Gas Ltd. have unanimously approved the
conversion of Zargon Energy Trust to a corporation. The conversion is
expected to be completed on December 31, 2010 and is proposed to be
implemented through a Plan of Arrangement that will require the approval
of two-thirds of the unitholders and exchangeable shareholders at a
special meeting to be held on December 15, 2010.


FINANCIAL ANALYSIS

Third quarter 2010 revenue of $44.50 million was one percent above the $43.89 million in the second quarter of 2010 and nine percent above the $40.96 million in the third quarter of 2009. Third quarter 2010 realized oil and liquids field prices averaged $67.64 per barrel before the impact of financial risk management contracts and were one percent higher than the preceding quarter's $67.27 per barrel and five percent higher than the $64.72 per barrel recorded in the 2009 third quarter. Zargon's crude oil field price differential from the Edmonton par price decreased to $6.79 per barrel in the third quarter of 2010 compared to $7.91 per barrel in the second quarter of 2010. Natural gas field prices received averaged $3.45 per thousand cubic feet in the third quarter of 2010, a seven percent decrease from the preceding quarter and a one percent increase from the 2009 third quarter prices.



Pricing

Three Months Ended Nine Months Ended
September 30, September 30,
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Percent Percent
Average for the period 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Natural Gas:
NYMEX average daily spot
price ($US/mmbtu) 4.30 3.16 36 4.59 3.81 20
AECO average daily spot
price ($Cdn/mmbtu) 3.54 2.94 20 4.13 3.78 9
Zargon realized field
price before the impact
of financial risk
management contracts
($Cdn/mcf) (1) 3.45 3.43 1 4.00 4.29 (7)
Zargon realized field
price before the
impact of physical and
financial risk management
contracts
($Cdn/mcf) (1) 3.35 2.83 18 3.97 3.62 10
Zargon realized field
price after the impact
of physical and
financial risk
management contracts
($Cdn/mcf) (1) 3.45 3.91 (12) 4.00 4.80 (17)
Zargon realized natural
gas field price
differential/
(premium) (1) (2) 0.09 (0.49) 0.13 (0.51)
Zargon realized natural
gas field price
differential before the
impact of physical
and financial risk
management contracts 0.19 0.11 0.16 0.16
Crude Oil:
WTI ($US/bbl) 76.23 68.30 12 77.66 57.00 36
Edmonton par price
($Cdn/bbl) 74.43 71.50 4 76.56 62.31 23
Zargon realized field
price before the impact
of financial risk
management contracts
($Cdn/bbl) 67.64 64.72 5 69.43 56.51 23
Zargon realized field
price after the impact
of financial risk
management contracts
($Cdn/bbl) 67.33 76.00 (11) 71.01 69.92 2
Zargon realized oil
field price
differential (3) 6.79 6.78 7.13 5.80
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----------------------------------------------------------------------------
(1) Zargon was not subject to any financial natural gas contracts for the
first nine months of 2010.
(2) Calculated as Zargon's realized field price before the impact of
financial risk management contracts ($Cdn/mcf) as compared to AECO
average daily spot price ($Cdn/mmbtu). Note: premiums occurred in 2009
as a result of the realization of fixed price physical contracts and
the impact of Zargon receiving AECO monthly index pricing for a portion
of its natural gas production.
(3) Calculated as Zargon's realized field price before the impact of
financial risk management contracts ($Cdn/bbl) as compared to Edmonton
par price ($Cdn/bbl).


Natural gas production volumes decreased by two percent in the third quarter of 2010 to 25.46 million cubic feet per day from 25.86 million cubic feet per day in the second quarter of 2010 and were 10 percent lower than the 2009 third quarter. When compared to the prior quarter, the 2010 third quarter decrease in natural gas production volumes was primarily a result of natural declines. Oil and liquids production volumes during the third quarter of 2010 were 5,850 barrels per day, which was two percent above the 2010 second quarter rate of 5,740 barrels per day and nine percent above the third quarter of 2009 level. The year-over-year increase in oil and liquids was primarily due to property and corporate acquisitions and oil exploitation focused horizontal drilling programs. On a barrel of oil equivalent basis, Zargon produced 10,094 barrels of oil equivalent per day in the third quarter of 2010, essentially unchanged from both the second quarter 2010 and the third quarter 2009 production levels.



Production by Core Area

Three Months Ended
September 30, 2010 2009
----------------------------------------------------------------------------
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 2,572 15.78 5,202 2,115 16.42 4,853
West Central
Alberta 352 9.12 1,873 424 11.37 2,319
Williston
Basin 2,926 0.56 3,019 2,843 0.44 2,916
----------------------------------------------------------------------------
5,850 25.46 10,094 5,382 28.23 10,088
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Nine Months Ended
September 30, 2010 2009
---------------------------------------------------------------------------
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 2,376 15.41 4,944 1,759 16.89 4,573
West Central
Alberta 379 10.02 2,050 390 10.82 2,194
Williston
Basin 2,961 0.69 3,075 2,762 0.49 2,843
----------------------------------------------------------------------------
5,716 26.12 10,069 4,911 28.20 9,610
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Zargon's commodity price risk management policy, which is approved by the Board of Directors, allows the use of forward sales, costless collars and other instruments up to a 24 month term for a 30 percent maximum of the combined oil and natural gas working interest production (subject to a 50 percent maximum limitation on any single commodity) in order to partially offset the effects of large commodity price fluctuations. Zargon's management considers financial risk management contracts to be effective on an economic basis, but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, for these contracts, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end.

Specifically, in the 2010 third quarter, relatively higher oil prices (when compared to contract prices) resulted in a small net realized financial risk management loss of $0.19 million on oil contracts that compares to a $1.42 million realized net gain in the second quarter of 2010 and a $6.83 million realized net gain in the third quarter of 2009 (foreign exchange contracts are considered in conjunction with the 2009 oil contracts).

The 2010 third quarter unrealized risk management loss of $4.76 million resulted from oil contract losses of $4.75 million and electricity contract losses of $0.01 million, which compares to a net $6.99 million gain for the 2010 second quarter and a net $3.60 million loss in the third quarter of 2009. These non-cash unrealized risk management gains or losses are generated by the change over the reporting period in the mark-to-market valuation of Zargon's risk management contracts. Recent volatility in commodity prices has resulted in significant fluctuations in the mark-to-market amount of unrealized risk management assets and liabilities. The period-over-period changes in these valuations directly impacts net earnings. Zargon's commodity risk management positions are fully described in note 11 to the unaudited consolidated interim financial statements.

Royalties, inclusive of the Saskatchewan Resource Surcharge, totalled $7.65 million for the third quarter of 2010, a decrease of four percent from the $8.00 million preceding quarter expense and an increase of one percent from $7.57 million in the third quarter of 2009. The variations in royalty rates generally track changes in production volumes and prices. Commencing in 2009, the oil and natural gas royalty structure changed for Alberta production volumes (as disclosed in our 2009 Annual Financial Report). Reflecting the 2010 commodity prices and the modified royalty structure, on a consolidated basis, the third quarter of 2010 royalties resulted in a rate of 17.2 percent compared to 18.2 percent in the second quarter of 2010. For the remainder of the year, Zargon expects that its royalty rate should remain in the 17 to 20 percent range, but will ultimately depend on the actual price received for our production.

On a unit of production basis, production costs of $12.91 per barrel of oil equivalent in the third quarter of 2010 were unchanged from the preceding quarter and were slightly lower than the $13.18 per barrel of oil equivalent in the third quarter of 2009. Despite the impact of acquiring higher cost oil-weighted properties in 2009 and 2010, Zargon has been able to maintain stable production costs on a barrel of oil equivalent basis.



Operating Netbacks

Three Months Ended
September 30, 2010 2009
----------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 67.64 3.45 64.72 3.43
Realized risk management
gain/(loss) (0.31) - 11.29 0.48
Royalties (12.98) (0.29) (13.54) (0.33)
Production costs (13.68) (1.98) (13.65) (2.11)
----------------------------------------------------------------------------
Operating netbacks 40.67 1.18 48.82 1.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Nine Months Ended
September 30, 2010 2009
----------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 69.43 4.00 56.51 4.29
Realized risk management
gain 1.58 - 13.41 0.51
Royalties (13.62) (0.47) (11.41) (0.50)
Production costs (13.27) (2.10) (14.28) (2.04)
----------------------------------------------------------------------------
Operating netbacks 44.12 1.43 44.23 2.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Measured on a unit of production basis (net of recoveries), general and administrative expenses were $4.26 per barrel of oil equivalent in the third quarter of 2010 compared to $3.19 in the third quarter of 2009 and $3.83 for the twelve month period of 2009. The increase in the third quarter is primarily due to the inclusion of transaction costs in the amount of $0.38 million ($0.41 per barrel of oil equivalent) associated with the property disposition package and the Oakmont corporate acquisition. As a result of adopting CICA Handbook Section 1582 "Business Combinations", Zargon is now required to expense all transaction costs incurred relating to property and corporate acquisitions/dispositions. For further details, please refer to notes 2 and 3 of the unaudited consolidated interim financial statements. For the 2010 nine month period, general and administrative expenses were $4.32 per barrel of oil equivalent and included one-time employee related costs of $0.42 per barrel of oil equivalent.

Expensing of unit-based compensation in the third quarter of 2010 totalled $0.35 million, a $0.05 million decrease from the third quarter of 2009 and a five percent decrease from the prior quarter.

Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges on these facilities in the 2010 third quarter were $1.23 million, $0.06 million higher than the previous quarter amount of $1.17 million and $0.43 million higher than the $0.80 million in the third quarter of 2009. This year-over-year increase is primarily due to an increase in average borrowing levels and higher average borrowing costs.

Current income taxes for the 2010 third quarter were $0.32 million, and related primarily to the United States operations. When compared to prior periods, current income taxes decreased $0.36 million from the 2009 third quarter and decreased $0.50 million relative to the second quarter of 2010. Assuming relatively stable oil prices, similar United States current income tax levels are predicted for the remainder of 2010. Total corporate tax pools as at September 30, 2010, are approximately $328 million, which represents an increase of 12 percent from the comparable $293 million of tax pools available to Zargon at December 31, 2009, primarily as a result of the 2010 field capital programs and the Oakmont corporate acquisition.



Trust Netbacks
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($/boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Petroleum and natural gas
revenue 47.91 44.13 49.78 41.46
Realized risk management
gain/(loss) (0.21) 7.35 0.88 8.35
Royalties (8.24) (8.15) (8.95) (7.30)
Production costs (12.91) (13.18) (12.97) (13.27)
----------------------------------------------------------------------------
Operating netbacks 26.55 30.15 28.74 29.24
General and administrative (4.26) (3.19) (4.32) (3.83)
Interest and financing
charges (1.33) (0.86) (1.26) (0.73)
Asset retirement
expenditures (0.71) (0.75) (0.96) (0.60)
Current income taxes (0.35) (0.74) (0.69) (0.60)
----------------------------------------------------------------------------
Funds flow netbacks 19.90 24.61 21.51 23.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion and depreciation expense for the third quarter of 2010 increased one percent to $16.99 million compared to $16.76 million in the prior quarter and increased one percent when compared to the third quarter of 2009 expense of $16.82 million. On a per barrel of oil equivalent basis, the depletion and depreciation rates were $18.30, $18.33 and $18.12 for the third and second quarters of 2010 and the third quarter of 2009, respectively. The 2009 calendar year depletion and depreciation rate was $17.99 per barrel of oil equivalent.

The provision for accretion of asset retirement obligations for the first nine months of 2010 was $2.57 million, a 29 percent increase compared to the first nine months of 2009. The year-over-year increase is due to changes in the estimated future liability for asset retirement obligations as a result of wells added through Zargon's drilling program inclusive of wells acquired/disposed of in the current year and with the recent corporate/property acquisitions/dispositions.

The recovery of future taxes for the third quarter of 2010 was $4.35 million compared to a recovery of $1.58 million in the prior quarter and a recovery of $3.13 million in the third quarter of 2009. The 2010 third quarter increase in the future tax recovery is related to the quarter's decrease in net earnings primarily a result of increased unrealized risk management losses.

On October 31, 2006, the Federal Government announced tax proposals pertaining to the taxation of distributions paid by trusts and the personal tax treatment of trust distributions. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. On June 12, 2007, the Federal Government enacted these tax proposals, which would have resulted in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. Subsequent 2007 fourth quarter legislation lowered this tax rate to 29.5 percent in 2011 and 28.0 percent beyond 2011. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes to have a nil effective tax rate. On February 26, 2008, the Federal Government, in its Federal Budget, announced further changes to the specified investment flow through ("SIFT") tax rules. The provincial component of the SIFT tax will be based on the provincial rates where the SIFT has a permanent establishment rather than using a 13.0 percent flat rate. During the 2009 first quarter, this tax rate change had been substantively enacted, and the future income tax impact has been recorded in the financial statements. Under the legislation and current Canadian GAAP, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be approximately 26.5 percent for 2011 and 25.0 percent thereafter. Until 2011, Zargon's future tax obligations are reduced as distributions are made from the Trust and, consequently, it is anticipated that Zargon's effective tax rate will continue to be low until that time.

On December 15, 2006, the Canadian Federal Department of Finance stated its intention to allow conversions of SIFT income trusts to corporations without any adverse tax consequences to investors. On July 14, 2008, the Department of Finance released the draft legislative proposals to allow the conversion of these SIFT trusts into corporations. Subsequent to quarter end, Zargon Energy Trust announced that the Board of Directors of Zargon Oil & Gas Ltd. have unanimously approved the conversion of Zargon Energy Trust to a corporation. The conversion is expected to be completed on December 31, 2010 and is proposed to be implemented through a Plan of Arrangement that will require the approval of two-thirds of the unitholders and exchangeable shareholders at a special meeting to be held on December 15, 2010. Zargon's management continues to believe that a partial cash flow distributing model is effective for our relatively mature sedimentary basins, and as such, plans to distribute regular dividends under the corporate structure.

On January 1, 2010, the Trust adopted new CICA Handbook Section 1602 "Non Controlling Interests." The related EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" was updated to reflect the changes in the new Handbook Section. According to EIC-151, the Trust must reflect the exchangeable securities issued by its subsidiary (Zargon Oil & Gas Ltd.) as a non-controlling interest. The January 1, 2010 updates to EIC-151 have only impacted the Trust's balance sheet classification, and as such, non-controlling interests are now reflected as a component of unitholders' equity. Accordingly, the Trust has reflected a non-controlling interest of $26.43 million on the Trust's consolidated balance sheet as at September 30, 2010. Consolidated net earnings have been reduced for net earnings attributable to the non-controlling interest of $0.05 million in the third quarter of 2010. In accordance with EIC-151 and given the circumstances in Zargon's case, each exchangeable share redemption is accounted for as a step-purchase, which in the third quarter of 2010 resulted in an increase in property and equipment of $0.07 million, an increase in unitholders' equity and non-controlling interest of $0.10 million and an increase in future income tax liability of $0.02 million. Funds flow was not impacted by this change. The cumulative impact to date of the application of EIC-151 has been an increase to property and equipment of $57.72 million, unitholders' equity and non-controlling interest of $69.86 million and future income tax liability of $18.88 million and an allocation of net earnings to exchangeable shareholders of $31.02 million.

Funds flow from operating activities in the 2010 third quarter of $18.49 million was $0.12 million, or one percent higher than the preceding quarter and $4.35 million or 19 percent lower than the prior year third quarter. The decrease in funds flow compared to the prior year third quarter was primarily a result of significant 2009 realized risk management gains. Funds flow on a per diluted trust unit basis of $0.70 for the third quarter of 2010 is unchanged from the prior quarter and is 22 percent lower than the 2009 third quarter.

Net earnings of $0.41 million for the 2010 third quarter were significantly lower than the $8.65 million of net earnings in the preceding quarter and the $4.47 million of net earnings in the third quarter of 2009, primarily due to a large third quarter 2010 unrealized risk management loss. The net earnings track the funds flow from operating activities 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.



Capital Expenditures

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Undeveloped land 1.94 1.47 5.38 4.00
Geological and geophysical
(seismic) 0.68 0.63 3.40 2.22
Drilling and completion of
wells 6.82 6.08 22.11 16.07
Well equipment and
facilities 1.11 4.57 11.09 11.80
----------------------------------------------------------------------------
Exploration and development 10.55 12.75 41.98 34.09
----------------------------------------------------------------------------
Property acquisitions 0.37 0.11 29.79 0.81
Property dispositions (21.89) (0.11) (29.94) (0.11)
----------------------------------------------------------------------------
Net property
acquisitions/(dispositions) (21.52) - (0.15) 0.70
----------------------------------------------------------------------------
Corporate acquisitions
assigned to property and
equipment (1) 9.36 16.31 9.36 56.34
----------------------------------------------------------------------------
Total net capital
expenditures excluding
administrative
assets (1) (1.61) 29.06 51.19 91.13
Administrative assets 0.35 0.26 0.55 0.59
----------------------------------------------------------------------------
Total net capital
expenditures (1) (1.26) 29.32 51.74 91.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts include capital expenditures acquired for cash, equity
issuances, acquisition costs (2009 only) and net debt assumed on
corporate acquisitions.


PROPERTY DISPOSITIONS

During the third quarter of 2010, Zargon completed property dispositions totalling $21.89 million, or $28.94 million inclusive of the disposition amounts realized in the prior quarter. In aggregate, this disposition program included 17 non-core minor oil properties that were producing approximately 375 barrels of oil equivalent per day.

CORPORATE ACQUISITION

On September 9, 2010, Zargon acquired all of the issued and outstanding common shares of Oakmont Energy Ltd. ("Oakmont"), a private oil and gas company, for consideration of $5.95 million. Consideration consisted of the issuance of 335,574 Zargon trust units valued at $17.72 per unit. Net debt of approximately $3.41 million was assumed as part of this acquisition. This acquisition brought oil exploitation opportunities at Little Bow and Grand Forks.

Oakmont's operating results have been included in the consolidated financial statements since September 9, 2010. In relation to the third quarter 2010 results, the Oakmont acquisition has contributed approximately 61 barrels of oil equivalent per day of production volumes to Zargon's total quarterly production volumes of 10,094 barrels of oil equivalent per day.

LIQUIDITY AND CAPITAL RESOURCES

Total net capital expenditures (including net property acquisitions and consideration and net debt assumed for the Oakmont acquisition) of $51.74 million in the first nine months of 2010 were 44 percent lower than the same period in 2009 which included the Masters Energy Inc. and Churchill Energy Inc. acquisitions. Field expenditures of $41.98 million for the first nine months of 2010 reflected an increased development field program when compared to $34.09 million for the same period in 2009. Drilling and completion expenses of $22.11 million were 38 percent higher than the prior year's first nine months amount of $16.07 million. During the first nine months of 2010, 23.8 net wells were drilled compared to 20.7 net wells in the same period in 2009. Field capital expenditures (excluding corporate and net property acquisitions) for the first nine months of 2010 were allocated to Alberta Plains - $15.96 million, West Central Alberta - $7.20 million and Williston Basin - $18.82 million. During the first nine months, Zargon incurred $29.79 million of property acquisitions which were offset by dispositions of $29.94 million. In particular, during the 2010 third quarter, Zargon acquired Oakmont for a transaction value of $9.36 million and completed property dispositions of $21.89 million.

Funds flow from operating activities in the first nine months of 2010 of $59.11 million, proceeds from the issuance of trust units of $7.98 million (due to the acquisition of Oakmont and unit right exercises) and the increase in bank debt of $21.03 million funded the capital program including corporate and net property acquisitions, the changes in working capital and the cash distributions to the unitholders.

At September 30, 2010, the Trust continues to maintain a relatively strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities and future income taxes) of $107.90 million, compared to $121.67 million at the end of the 2010 second quarter, which represents approximately 60 percent of the Trust's available credit facilities at September 30, 2010.

The volatility of oil and natural gas prices, uncertainty or modifications regarding Alberta royalties and Canadian income trust tax rules and global economic concerns have, on occasion, restricted the oil and natural gas industry's ability to attract new capital from debt and equity markets. Zargon's historically conservative strategy of maintaining a relatively low cash distribution to funds flow ratio and conservative debt levels should enable Zargon to continue its capital and distribution programs during periods of limited access to debt and equity capital.



Cash Distributions Analysis

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash flows from operating
activities 20.05 23.30 53.92 60.97
Net earnings 0.41 4.47 14.22 2.28
Actual cash distributions
paid or payable relating
to the period (1) (11.92) (12.22) (36.35) (33.51)
----------------------------------------------------------------------------
Excess of cash flows from
operating activities over
cash distributions
paid 8.13 11.08 17.57 27.46
Excess (shortfall) of net
earnings over cash
distributions paid (11.51) (7.75) (22.13) (31.23)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Cash distributions represent the cash portion only and do not include
trust units issued through Zargon's Distribution Reinvestment Plan which
commenced in April 2010.


During the first nine months of 2010, Zargon has maintained a base monthly distribution of $0.18 per trust unit, a level which has been maintained since November 2005. Management monitors the Trust's distribution policy with respect to forecasted net cash flows, debt levels and capital expenditures. Zargon's cash distributions are discretionary to the extent that these distributions do not cause a breach of the financial covenants under Zargon's credit facilities and to the extent the Trust (non-consolidated) is not taxable. As a crude oil and natural gas Trust, Zargon's reserve base is depleted with production and Zargon, therefore, relies on ongoing exploration, development and acquisition activities to replace reserves and to offset production declines. The success of these exploration, development and acquisition capital programs, along with commodity price fluctuations and the Trust's ability to manage costs, are the main factors influencing the sustainability of the Trust's distributions.

For the three and nine months ended September 30, 2010, cash flows from operating activities (after changes in non-cash working capital) of $20.05 million and $53.92 million, respectively, exceeded cash distributions of $11.92 million and $36.35 million, respectively. Similarly, for the three and nine months ended September 30, 2009, cash flows from operating activities (after changes in non-cash working capital) of $23.30 million and $60.97 million, respectively, exceeded cash distributions of $12.22 million and $33.51 million, respectively.

For the three and nine months ended September 30, 2010, cash distributions of $11.92 million and $36.35 million, respectively, exceeded net earnings of $0.41 million and $14.22 million, respectively. Net earnings include significant non-cash charges, which were $18.74 million for the 2010 third quarter and $47.53 million for the nine months ended September 30, 2010, that do not impact cash flow. For the three and nine months ended September 30, 2009, cash distributions of $12.22 million and $33.51 million, respectively, exceeded net earnings of $4.47 million and $2.28 million, respectively. Net earnings also include fluctuations in future income taxes due to changes in tax rates and tax rules. In the instances where distributions exceed net earnings, a portion of the cash distribution paid to unitholders may represent an economic return of the unitholders' capital.

For the quarter ended September 30, 2010, cash distributions and net capital expenditures totalled $10.66 million (including the $9.36 million attributed to the Oakmont corporate acquisition), which was $9.39 million lower than the cash flows from operating activities (after changes in non-cash working capital) of $20.05 million. For the quarter ended September 30, 2009, cash distributions and net capital expenditures totalled $41.54 million (including the $16.31 million attributed to the Churchill Energy Inc. corporate acquisition), which was $18.24 million higher than the cash flows from operating activities (after changes in non-cash working capital) of $23.30 million. Zargon relies on access to debt and capital markets to the extent that cash distributions and net capital expenditures exceed cash flows from operating activities (after changes in non-cash working capital). Over the long term, Zargon expects to fund cash distributions/dividends and capital expenditures with its cash flows from operating activities; however, it will continue to fund acquisitions and growth through additional debt and equity issuances. In the crude oil and natural gas industry, because of the nature of reserve reporting, the natural reservoir declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Therefore, maintenance capital is not disclosed separately from development capital spending.

At November 10, 2010, Zargon Energy Trust had 23.813 million trust units and 1.691 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective November 10, 2010 exchange ratio of 1.79887, there would be 26.855 million trust units outstanding. Pursuant to the trust unit rights incentive plans, there are currently an additional 1.522 million trust unit incentive rights issued and outstanding.



Capital Sources and Uses

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Funds flow from operating
activities 18.49 22.84 59.11 61.61
Change in bank debt (16.51) 6.62 21.03 (0.53)
Issuance of trust units 6.10 9.36 7.98 65.11
Cash distributions to
unitholders (1) (11.92) (12.22) (36.35) (33.51)
Changes in working capital
and other 2.58 2.72 (0.03) (0.96)
----------------------------------------------------------------------------
Total capital sources (1.26) 29.32 51.74 91.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Cash distributions represent the cash portion only and do not include
trust units issued through Zargon's Distribution Reinvestment Plan which
commenced in April 2010.


CHANGES IN CANADIAN ACCOUNTING POLICIES

On January 1, 2010, Zargon adopted the following three Canadian Institute of Chartered Accountants ("CICA") Handbook sections:

CICA Handbook Section 1582 "Business Combinations", which replaces Section 1581 of the same name. Under this new guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the date of exchange and contingent liabilities are to be recognized at fair value at the acquisition date and re-measured at fair value with changes recorded through earnings each period until settled. In addition, this new guidance generally requires all transaction costs to be expensed and negative goodwill is required to be recognized immediately in earnings. The provisions of this new Section were applied to the acquisition of Oakmont Energy Ltd. (see note 3 to the consolidated financial statements).

CICA issued Section 1601 "Consolidated Financial Statements", which replaces Section 1600 of the same name. This guidance requires uniform accounting policies to be consistent throughout all consolidated entities and the difference between reporting dates of a parent and a subsidiary to be no longer than three months. The adoption of this Section did not have an impact on the Trust's consolidated financial statements.

CICA issued Section 1602 "Non-Controlling Interests", which replaces Section 1600, "Consolidated Financial Statements". Non-controlling interest ("NCI") is now presented within equity. Under this new guidance, when there is a loss or gain of control, the Trust's previously held interest is re-valued at fair value. In addition, NCI may be reported at fair value or at the proportionate share of the fair value of the acquired net assets and allocation of the net income to the NCI will be on this basis. The adoption of this Section has reclassified the NCI from liabilities to equity on the Trust's consolidated balance sheet on a retrospective basis.

The above CICA Handbook Sections are converged with International Financial Reporting Standards.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

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

In 2008, Zargon commenced the process to transition its financial statements from current Canadian GAAP to IFRS and has been progressing towards completion throughout 2009 and into 2010. Zargon's project consists of three key phases: the scoping and diagnostic phase, the impact analysis and evaluation phase and the implementation phase. A wholesome description of Zargon's IFRS project phases and Zargon's progress to the end of 2009 is contained within Zargon's MD&A for the year ended December 31, 2009.

Throughout 2009 and 2010, Zargon has trained key accounting and finance personnel as well as the senior management team on the application of IFRS accounting policies and the potential impact on the consolidated financial statements. Individuals within the corporate accounting department have participated in various seminars and industry discussion groups regarding the application of current IFRS and potential changes to the standards. The corporate accounting department continues to lead the conversion project along with sponsorship from the management team. The project has been progressing according to the project plan and Zargon expects to be completed in time to meet its 2011 financial reporting requirements.

With respect to the key areas identified in previous reports, the following is a summary of additional progress:

During the third quarter of 2010, Zargon prepared a draft opening balance sheet at January 1, 2010 which was reviewed by the external auditors, and is subject to further audit work before it is considered final. Zargon is currently drafting its financial results under IFRS for the first quarter of 2010. The draft first quarter 2010 comparative financial statements and related disclosures are scheduled to be reviewed by the external auditors during the fourth quarter of 2010. All amounts are unaudited, as Zargon has not yet prepared a full set of annual financial statements under IFRS.

IFRS 1 "First-Time Adoption of International Financial Reporting Standards" ("IFRS 1"), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Zargon's January 1, 2010 draft opening balance sheet utilized the following IFRS 1 exemptions:

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

- Business Combinations - IFRS 1 allows Zargon to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations. The IFRS business combination rules converge with the new CICA Handbook Section 1582 that is also effective for Zargon on January 1, 2011, which Zargon early adopted on January 1, 2010 as discussed earlier in this report.

The following is a listing of key areas where accounting policies differ and where accounting policy decisions are necessary that will impact our reported financial position and results of operations:

- Re-classification of Exploration and Evaluation ("E&E") expenditures from PP&E - Upon transition to IFRS, Zargon will re-classify all E&E expenditures that are currently included in the PP&E balance on the consolidated balance sheets. Zargon has determined that it has approximately $25 million of oil and natural gas assets that meet the definition of E&E. The E&E assets will not be depleted and Zargon will be evaluating the projects on a quarterly basis for proper classification. E&E assets must be assessed for impairment when indicators of impairment exist.

- Calculation of depletion expense for PP&E assets - Upon transition to IFRS, Zargon has the option to calculate depletion using a reserve base of proved reserves, which is comparable to the Canadian GAAP method of calculating depletion, or using a reserve base of proved and probable reserves. Also, depletion must be calculated at a more granular level than what is currently required under Canadian GAAP. Zargon plans to calculate its depletion expense using proved and probable reserves as its depletion base. Accordingly, due to the larger depletion base associated with proved and probable reserves, Zargon expects its depletion expense to be reduced and net earnings to increase under IFRS as compared to its current calculation under Canadian GAAP. The magnitude of the decrease is still being quantified by management.

- Impairment of PP&E assets - Under IFRS, impairment of PP&E must be calculated at a more granular level than what is currently required under Canadian GAAP. Impairment calculations will be performed at the cash generating unit ("CGU") level using either total proved or proved and probable reserves. The most significant difference is that the Canadian GAAP "ceiling test" incorporates a 2-step approach for testing impairment, while IFRS uses a 1-step approach. Under Canadian GAAP, a discounted cash flow analysis is not required if the undiscounted cash flows from proved reserves exceed its carrying amount (step 1). If the carrying amount exceeds the undiscounted future cash flows, then a prescribed discounted cash flow test is performed (step 2). Under IFRS, impairment testing based on discounted cash flows or fair value determinations is required and is performed at the CGU level. Impairment tests are required to be performed on initial transition to IFRS. At January 1, 2010, no impairment was identified.

- Provisions for asset retirement obligations - Under IFRS, Zargon is required to revalue its entire liability for asset retirement obligations at each balance sheet date using a current liability-specific discount rate. Under Canadian GAAP, once recorded, asset retirement obligations are not adjusted for future changes in discount rates. Under current IFRS standards, it is unclear if the discount rate used would be based on a credit adjusted rate, as it currently is under Canadian GAAP, or based on a risk free rate. As such, discount rates are currently under review by management, as there is diversity in practice when selecting a rate. Zargon's asset retirement obligation is expected to increase as a result of applying a risk free rate, with an offsetting charge to retained earnings.

- Income tax - In November 2009 the IASB withdrew an exposure draft on Income Taxes. Current IFRS income tax requirements are fundamentally consistent with Canadian GAAP. Any changes to Income Tax reporting are expected to be predominantly caused by changes in the book value of assets and changes in tax rates applied, not due to the change in Income Tax accounting methodology. Upon transition, Zargon expects its future tax liability to decrease under IFRS as compared to its current calculation under Canadian GAAP, primarily due to expected changes to Zargon's provision for asset retirement obligations.

- Share-based payments - Under IFRS, share-based payments for equity awards are expensed based on a graded vesting schedule compared to the straight-line method which was permitted under Canadian GAAP. A forfeiture rate is also required to be applied to the calculation under IFRS at the initial determination of the fair value of the share-based expense, whereas under Canadian GAAP forfeitures could be recorded as they were incurred. Under IFRS our trust units are classified as equity, however, under IFRS the 2010 unit-based payments are required to be classified as a liability. For the 2010 comparative period, Zargon's unit-based compensation plan is deemed to be cash settled under IFRS, even though the trust units are not settled in cash. Following transition, Zargon expects share-based payments expenses to be accelerated under IFRS as compared to its current calculation under Canadian GAAP.

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

- ICFR - As the review of Zargon's accounting policies is completed, an assessment will be made to determine changes required for ICFR. As an example, additional controls will be implemented for the IFRS 1 changes such as the allocation of Zargon's PP&E as well as the process for reclassifying Zargon's E&E expenditures from PP&E. This will be an ongoing process throughout 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements. As at the date of this MD&A, Zargon has drafted the IFRS January 1, 2010 opening balance sheet and is currently determining adjustments to the comparative information for the 2010 quarters. Once this comparative information is drafted, additional and/or modified ICFR will be implemented and will be operational in 2011.

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

- Business activities - Management has been cognizant of the upcoming transition to IFRS and as such has worked with its counterparties and lenders to ensure that any agreements that contain references to Canadian GAAP financial statements are modified to allow IFRS statements. Zargon's management has amended its banking agreements to provide for changes which may contemplate for accounting changes which may arise in the calculation of Zargon's pricing and debt covenants.

The preliminary decisions about IFRS 1 exemptions and accounting policy choices, and the assessments of differences between IFRS and Canadian GAAP have not been finalized. Users are cautioned that the analysis will not be finalized until 2011 and that the preliminary decisions and estimated impacts of adopting IFRS may change. In addition, other differences may exist between amounts reported by Zargon under Canadian GAAP and IFRS. New or revised standards are being developed by IASB ("International Accounting Standards Board") that may impact the adoption of IFRS by Zargon in 2011 or thereafter. Zargon continues to monitor these and other accounting standard developments within IFRS which might impact its IFRS conversion.

MANAGEMENT AND FINANCIAL REPORTING SYSTEMS

Zargon is required to comply with National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to as Canadian SOX ("C-Sox"). The 2010 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 have materially affected, or are 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 first nine months of 2010.

Because of their inherent limitations, 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.

OUTLOOK

With a relatively strong balance sheet, 505 thousand net acres of undeveloped land, a promising internally generated oil exploitation project inventory and its ability to execute accretive asset and/or corporate acquisitions, Zargon continues to be well positioned to meet its value-creating and distribution/dividend generating objectives in the remainder of 2010 and beyond.



SUMMARY OF QUARTERLY RESULTS
2010
----------------------------------------------------------------------------
Q1 Q2 Q3
----------------------------------------------------------------------------
Petroleum and natural gas revenue ($ millions) 48.46 43.89 44.50
Net earnings ($ millions) 5.16 8.65 0.41
Net earnings per diluted unit ($) 0.22 0.37 0.02
Funds flow from operating activities
($ millions) 22.24 18.38 18.49
Funds flow from operating activities per
diluted unit ($) 0.85 0.70 0.70
Cash flows from operating activities
($ millions) 21.00 12.87 20.05
Cash flows from operating activities per
diluted unit ($) 0.80 0.49 0.76
Cash distributions ($ millions) (1) 12.55 11.88 11.92
Cash distributions declared per trust unit ($) 0.54 0.54 0.54
Net capital expenditures ($ millions) (2) 18.74 34.26 (1.26)
Total assets ($ millions) 466.22 484.45 462.92
Bank debt ($ millions) 84.23 114.12 97.61
Average daily production (boe) 10,062 10,050 10,094
Average realized commodity field price before
the impact of financial risk management
contracts ($/boe) 53.51 47.99 47.91
Funds flow netback ($/boe) 24.56 20.11 19.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Cash distributions represent the cash portion only and do not include
trust units issued through Zargon's Distribution Reinvestment Plan which
commenced in April 2010.
(2) Third quarter 2010 expenditures include corporate acquisition amounts as
follows; net debt assumed of $3.41 million and the equity issuance of
trust units valued at $5.95 million.


2009
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Petroleum and natural gas
revenue ($ millions) 31.98 35.84 40.96 47.21
Net earnings/(losses)
($ millions) 0.37 (2.55) 4.47 0.44
Net earnings/(losses) per
diluted unit ($) 0.02 (0.13) 0.20 0.02
Funds flow from operating
activities ($ millions) 17.85 20.92 22.84 24.75
Funds flow from operating
activities per diluted
unit ($) 0.84 0.91 0.90 0.95
Cash flows from operating
activities ($ millions) 15.73 21.94 23.30 27.86
Cash flows from operating
activities per diluted
unit ($) 0.74 0.95 0.92 1.07
Cash distributions
($ millions) 10.03 11.26 12.22 12.45
Cash distributions
declared per trust unit ($) 0.54 0.54 0.54 0.54
Net capital expenditures
($ millions) (1) (2) 13.44 48.96 29.32 12.87
Total assets ($ millions) 440.76 466.60 473.47 464.38
Bank debt ($ millions) 85.78 70.43 77.05 76.58
Average daily production
(boe) 9,213 9,520 10,088 10,586
Average realized commodity
field price before the
impact of financial risk
management contracts($/boe) 38.57 41.37 44.13 48.48
Funds flow netback ($/boe) 21.53 24.14 24.61 25.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Second quarter 2009 expenditures include corporate acquisition amounts
as follows; cash consideration of $5.70 million, transaction costs of
$0.36 million, net debt assumed of $12.93 million and the equity
issuance of trust units valued at $21.04 million.
(2) Third quarter 2009 expenditures include corporate acquisition amounts as
follows; cash consideration of $0.11 million, transaction costs of $0.27
million, net debt assumed of $6.58 million and the equity issuance of
trust units valued at $9.36 million.


2008
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Petroleum and natural gas
revenue ($ millions) 52.24 69.66 66.35 41.25
Net earnings/(losses)
($ millions) 4.56 (4.51) 40.05 28.19
Net earnings/(losses) per
diluted unit ($) 0.26 (0.25) 2.20 1.53
Funds flow from operating
activities ($ millions) 24.75 32.02 29.75 20.40
Funds flow from operating
activities per diluted
unit ($) 1.23 1.55 1.42 0.97
Cash flows from operating
activities ($ millions) 15.27 36.44 33.58 24.84
Cash flows from operating
activities per diluted
unit ($) 0.76 1.76 1.60 1.18
Cash distributions
($ millions) 9.55 9.71 9.87 9.96
Cash distributions
declared per trust unit ($) 0.54 0.54 0.54 0.54
Net capital expenditures
($ millions) (1) (2) (3) 59.61 26.28 17.47 16.37
Total assets ($ millions) 396.90 418.88 426.63 447.60
Bank debt ($ millions) 92.18 85.45 74.95 77.58
Average daily production
(boe) 9,015 9,239 9,340 9,410
Average realized commodity
field price before the
impact of financial risk
management contracts($/boe) 63.68 82.85 77.22 47.65
Funds flow netback ($/boe) 30.17 38.08 34.62 23.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) First quarter 2008 expenditures include corporate acquisition amounts as
follows; cash consideration of $16.40 million, transaction costs of
$0.29 million, net debt assumed of $17.77 million and the equity
issuance of trust units valued at $13.37 million.
(2) Second quarter 2008 net capital expenditures include corporate
acquisition amounts as follows; transaction costs of $0.15 million, net
debt assumed of $2.49 million and the equity issuance of trust units
valued at $9.39 million.
(3) Third quarter 2008 net capital expenditures include property acquisition
amounts as follows; the equity issuance of trust units valued at $1.14
million.


ADDITIONAL INFORMATION

Additional information regarding the Trust and its business operations, including the Trust's Annual Information Form for December 31, 2009, is available on the Trust's SEDAR profile at www.sedar.com.

"Signed" C.H. Hansen

President and Chief Executive Officer

Calgary, Alberta

November 10, 2010



CONSOLIDATED BALANCE SHEETS

(unaudited)
----------------------------------------------------------------------------
September 30, December 31,
($ thousands) 2010 2009
----------------------------------------------------------------------------
ASSETS (note 5)
Current
Accounts receivable 19,365 25,223
Prepaid expenses and deposits 2,554 2,013
Unrealized risk management asset (note 11) 241 4,289
Future income taxes 946 1,714
----------------------------------------------------------------------------
23,106 33,239
Long term deposit 653 1,845
Unrealized risk management asset (note 11) 45 -
Goodwill 2,969 2,969
Property and equipment, net (notes 3 and 4) 435,908 425,964
Future income taxes 235 361
----------------------------------------------------------------------------
462,916 464,378
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities 28,194 34,507
Cash distributions payable (note 15) 4,014 4,157
Unrealized risk management liability (note 11) 3,517 6,032
Future income taxes 65 1,219
----------------------------------------------------------------------------
35,790 45,915
Long term debt (note 5) 97,606 76,580
Unrealized risk management liability (note 11) 876 1,270
Asset retirement obligations (note 6) 42,093 35,468
Future income taxes 21,851 30,327
----------------------------------------------------------------------------
198,216 189,560
----------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (note 7) 201,707 188,840
Non-controlling interest - exchangeable
shares (note 8) 26,434 26,477
Contributed surplus (note 7) 6,184 5,471
Accumulated earnings 274,045 259,823
Accumulated cash distributions (note 15) (243,670) (205,793)
----------------------------------------------------------------------------
264,700 274,818
----------------------------------------------------------------------------
462,916 464,378
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME AND ACCUMULATED
EARNINGS
Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
REVENUE
Petroleum and natural gas
revenue 44,495 40,955 136,837 108,773
Unrealized risk
management loss (note 11) (4,758) (3,597) (1,095) (23,422)
Realized risk management
gain/(loss) (note 11) (191) 6,826 2,406 21,904
Royalties (7,652) (7,568) (24,611) (19,148)
----------------------------------------------------------------------------
31,894 36,616 113,537 88,107
----------------------------------------------------------------------------
EXPENSES
Production 11,987 12,234 35,643 34,812
General and
administrative 3,960 2,964 11,874 10,054
Unit-based compensation
(note 7) 346 394 1,082 819
Interest and financing
charges (note 5) 1,231 801 3,474 1,912
Unrealized foreign
exchange loss 21 82 9 131
Accretion of asset
retirement obligations
(note 6) 917 730 2,572 1,992
Depletion and
depreciation 16,990 16,818 50,152 47,211
----------------------------------------------------------------------------
35,452 34,023 104,806 96,931
----------------------------------------------------------------------------
EARNINGS/(LOSSES) BEFORE
INCOME TAXES (3,558) 2,593 8,731 (8,824)
----------------------------------------------------------------------------
INCOME TAXES
Current 321 684 1,886 1,583
Future tax recovery (4,345) (3,132) (9,156) (12,969)
----------------------------------------------------------------------------
(4,024) (2,448) (7,270) (11,386)
----------------------------------------------------------------------------
CONSOLIDATED EARNINGS 466 5,041 16,001 2,562
LESS NET EARNINGS
ATTRIBUTED TO
NON-CONTROLLING INTEREST
(note 8) 52 574 1,779 281
----------------------------------------------------------------------------
NET EARNINGS AND
COMPREHENSIVE INCOME
ATTRIBUTED TO ZARGON 414 4,467 14,222 2,281

ACCUMULATED EARNINGS,
BEGINNING OF PERIOD 273,631 254,918 259,823 257,104
----------------------------------------------------------------------------
ACCUMULATED EARNINGS, END
OF PERIOD 274,045 259,385 274,045 259,385
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET EARNINGS PER UNIT (note 9)
Basic 0.02 0.20 0.61 0.11
Diluted 0.02 0.20 0.61 0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Nine Months Ended
(unaudited) September 30, September 30,
----------------------------------------------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings for the period 414 4,467 14,222 2,281
Add (deduct) non-cash items:
Non-controlling interest
- exchangeable shares 52 574 1,779 281
Unrealized risk
management loss 4,758 3,597 1,095 23,422
Depletion and
depreciation 16,990 16,818 50,152 47,211
Accretion of asset
retirement obligations 917 730 2,572 1,992
Unit-based compensation 346 394 1,082 819
Unrealized foreign
exchange loss 21 82 9 131
Future income tax
recovery (4,345) (3,132) (9,156) (12,969)
Asset retirement
expenditures (662) (692) (2,648) (1,563)
----------------------------------------------------------------------------
18,491 22,838 59,107 61,605
Changes in non-cash
operating working capital
(note 12) 1,558 462 (5,187) (638)
----------------------------------------------------------------------------
20,049 23,300 53,920 60,967
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Advances/(repayment) of
bank debt (16,512) 6,619 21,026 (531)
Cash distributions
declared to unitholders (11,921) (12,215) (36,354) (33,511)
Exercise of unit rights 151 - 2,032 1,269
Issuance of unitholders
capital, net of issue
costs - - - 33,444
Changes in non-cash
financing working capital
(note 12) 60 100 (143) 812
----------------------------------------------------------------------------
(28,222) (5,496) (13,439) 1,483
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property and
equipment (11,268) (13,107) (72,321) (35,486)
Proceeds on disposal of
property and equipment 21,892 101 29,943 107
Corporate acquisitions
(cash portion) - (378) - (19,260)
Long term deposit (11) 172 1,192 (98)
Changes in non-cash
investing working capital
(note 12) (2,440) (4,592) 705 (7,713)
----------------------------------------------------------------------------
8,173 (17,804) (40,481) (62,450)
----------------------------------------------------------------------------
NET CHANGE IN CASH DURING
THE PERIOD AND CASH, END
OF PERIOD - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the three and nine months ended September 30, 2010 and 2009 (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, 2009, 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 financial report for the year ended December 31, 2009.

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, 2010, Zargon adopted the following three Canadian Institute of Chartered Accountants ("CICA") Handbook sections:

CICA Handbook Section 1582 "Business Combinations", which replaces Section 1581 of the same name. Under this new guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the date of exchange and contingent liabilities are to be recognized at fair value at the acquisition date and re-measured at fair value with changes recorded through earnings each period until settled. In addition, this new guidance generally requires all transaction costs to be expensed and negative goodwill is required to be recognized immediately in earnings. The provisions of this new Section were applied to the acquisition of Oakmont Energy Ltd. (see note 3 to the consolidated financial statements).

CICA issued Section 1601 "Consolidated Financial Statements", which replaces Section 1600 of the same name. This guidance requires uniform accounting policies to be consistent throughout all consolidated entities and the difference between reporting dates of a parent and a subsidiary to be no longer than three months. The adoption of this Section did not have an impact on the Trust's consolidated financial statements.

CICA issued Section 1602 "Non-Controlling Interests", which replaces Section 1600, "Consolidated Financial Statements". Non-controlling interest ("NCI") is now presented within equity. Under this new guidance, when there is a loss or gain of control, the Trust's previously held interest is re-valued at fair value. In addition, NCI may be reported at fair value or at the proportionate share of the fair value of the acquired net assets and allocation of the net income to the NCI will be on this basis. The adoption of this Section has reclassified the NCI from liabilities to equity on the Trust's consolidated balance sheet on a retrospective basis.

The above CICA Handbook Sections are converged with International Financial Reporting Standards.

3. ACQUISITIONS

Oakmont Energy Ltd.

On September 9, 2010, a subsidiary of the Trust acquired all of the outstanding shares of Oakmont Energy Ltd. ("Oakmont"), a private oil and gas company, for consideration of $5.95 million. Consideration consisted of the issuance of 335,574 Zargon trust units valued at $17.72 per unit.

The results of operations for Oakmont have been included in the consolidated financial statements since September 9, 2010.

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



Net Assets Acquired

($ thousands)
----------------------------------------------------------------------------
Property and equipment 12,403
Working capital deficiency (3,410)
Future income tax liability (56)
Asset retirement obligations (2,991)
----------------------------------------------------------------------------
Total net assets acquired 5,946
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consideration

($ thousands)
----------------------------------------------------------------------------
Trust units issued 5,946
----------------------------------------------------------------------------
Total purchase price 5,946
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Acquisition costs for this transaction of $0.13 million have been included in General and Administrative expenses on the consolidated statements of earnings and comprehensive income as a result of the adoption of Section 1582 "Business Combinations" effective January 1, 2010.

Churchill Energy Inc.

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

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

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



Net Assets Acquired

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

Consideration

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


Masters Energy Inc.

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

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

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



Net Assets Acquired

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

Consideration

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


4. PROPERTY AND EQUIPMENT

September 30, 2010
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousands) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties and
other equipment (1) 835,353 399,445 435,908
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2009
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousands) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties and
other equipment (1) 775,257 349,293 425,964
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As a result of shareholders redeeming exchangeable shares, property and
equipment has cumulatively increased $57.72 million, $1.60 million
relating to 2010, $0.97 million relating to 2009 and $55.15 million
relating to prior years. The effect of these increases has resulted in
additional depletion and depreciation expense of approximately $30.58
million, $3.36 million relating to 2010, $4.91 million relating to 2009
and $22.31 million relating to prior years.


5. LONG TERM DEBT

On June 29, 2010, Zargon amended and renewed its syndicated committed credit facilities, the result of which was the maintaining of the available facilities and borrowing base of $180 million. These facilities consist of a $170 million tranche available to the Canadian borrower and a US $8 million tranche available to the US borrower. A $300 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities. The facilities are fully revolving for a 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 June 28, 2011. Should the facilities not be renewed, they convert to one year non-revolving term facilities at the end of the revolving 364 day period. Repayment would not be required until the end of the non-revolving term, and, as such, these facilities have been classified as long term debt.

Interest rates fluctuate under the syndicated facilities with Canadian prime, US prime and US base rates plus an applicable margin between 100 basis points and 250 basis points as well as with Canadian banker's acceptance and LIBOR rates plus an applicable margin between 250 basis points and 400 basis points. At September 30, 2010, $97.61 million (December 31, 2009 - $76.58 million) had been drawn on the syndicated committed credit facilities with any unused amounts subject to standby fees. In the normal course of operations Zargon enters into various letters of credit. At September 30, 2010, the approximate value of outstanding letters of credit totalled $0.68 million (December 31, 2009 - $0.61 million). The letters of credit reduce the amount of Zargon's available credit facilities to $81.71 million at September 30, 2010 (December 31, 2009 - $102.81 million).

Zargon reviews its compliance with its bank debt covenants on a quarterly basis and has no violations as at September 30, 2010.



6. ASSET RETIREMENT OBLIGATIONS

The following table reconciles Zargon's asset retirement obligations:

Nine Months Ended September 30,
----------------------------------------------------------------------------
($ thousands) 2010 2009
----------------------------------------------------------------------------
Balance, beginning of period 35,468 28,592
Net liabilities incurred/acquired 6,717 6,551
Liabilities settled (2,648) (1,563)
Accretion expense 2,572 1,992
Foreign exchange (16) (140)
----------------------------------------------------------------------------
Balance, end of period 42,093 35,432
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. UNITHOLDERS' EQUITY

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

Trust Units

Nine Months Ended September 30, 2010
----------------------------------------------------------------------------
(thousands) Number of units Amount ($)
----------------------------------------------------------------------------
Balance, beginning of period 23,097 188,840
Unit rights exercised for cash 125 2,032
Unit-based compensation recognized on
exercise of unit rights - 374
Issued on corporate acquisitions (note 3) 336 5,946
Issued on conversion of exchangeable shares 151 2,992
Issued pursuant to Distribution Reinvestment Plan 87 1,523
----------------------------------------------------------------------------
Balance, end of period 23,796 201,707
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The proforma total units outstanding at September 30, 2010, including trust units outstanding and trust units issuable upon conversion of exchangeable shares, after giving effect to the exchange ratio at the end of the period (see note 8) is 26.81 million units.

On April 9, 2010, the Trust Implemented a Distribution Reinvestment Plan ("DRIP"). Under the DRIP, Canadian unitholders are entitled to reinvest monthly cash distributions in additional trust units of the Trust. At the discretion of the Trust, these additional units will be issued from Treasury at 95 percent of the "weighted average closing price". For the purposes of the units issued, the "weighted average closing price" is calculated as the weighted average trading price of trust units for the five trading days prior to the distribution payment date.

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



Contributed Surplus

($ thousands) Nine Months Ended September 30, 2010
----------------------------------------------------------------------------
Balance, beginning of period 5,471
Unit-based compensation expense (1) 1,087
Unit-based compensation recognized on exercise of unit rights (374)
----------------------------------------------------------------------------
Balance, end of period 6,184
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The Trust issued 10,000 unit appreciation rights ("UARS") with an
intrinsic value decrease of $0.01 million at September 30, 2010 ($0.02
million increase at December 31, 2009). These UARS are awards entitling
the recipients to receive cash in an amount equivalent to any excess of
the market value of a stated number of units over a stated price. UARS
are included in unit-based compensation expense; however rewards settled
in cash are liabilities and therefore are not included in contributed
surplus.


Trust Unit Rights Incentive Plan and Unit-Based Compensation

The Trust has a unit rights incentive plan (the "Old Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and other service providers. On April 22, 2009, a new unit rights incentive plan (the "New Plan") was approved by the unitholders. The Trust is authorized to issue up to an aggregate of 2.13 million unit rights; however, the number of trust units reserved for issuance upon exercise of the rights shall not at any time exceed 10 percent of the aggregate number of the total outstanding units, including units issuable upon exchange of exchangeable shares of Zargon and other fully paid securities of Zargon entities exchangeable into units, which are the economic equivalent of units including full voting rights. At the time of grant, unit right exercise prices approximate the market price for the trust units. At the time of exercise, the rights holder has the option of exercising at the original grant price or the exercise price as calculated under the Old Plan or the New Plan (the "modified price"). Under the Old Plan, the modified price was based on the increment of the amount the monthly distribution exceeded a monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the Old Plan). Under the New Plan, if the monthly distribution exceeds the monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the New Plan), the entire amount (not the increment) of the distribution is deducted from the original grant price. Rights granted under either Plan generally vest over a three-year period and expire approximately five years from the grant date. Zargon uses a fair value methodology to value the unit rights grants.

The weighted average assumptions made for unit rights granted for the nine months ended September 30, 2010 include a volatility factor of expected market price of 33.22 percent, a risk-free rate of 2.25 percent and an expected life of the unit rights of four years. The fair value of the unit rights granted in the quarter was calculated at $4.83 per unit right. Unit-based compensation expense for the three and nine months ended September 30, 2010 were $0.34 million (2009 - $0.37 million) and $1.09 million (2009 - $0.81 million), respectively.

Compensation expense associated with unit rights granted under either Plan is recognized in earnings over the vesting period of the Plan with a corresponding increase in contributed surplus. The exercise of trust unit rights is recorded as an increase in trust units with a corresponding reduction in contributed surplus. Forfeiture of rights are recorded as a reduction in expenses in the period in which they occur if the rights have not yet vested.

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



Nine Months Ended September 30, 2010
----------------------------------------------------------------------------
Weighted Average
Number of Exercise Price
Unit Rights Initial and Modified
(thousands) ($/unit right)
----------------------------------------------------------------------------
Outstanding at beginning of period 1,322 25.97 / 23.52
Unit rights granted - -
Unit rights exercised (95) 17.00
Unit rights forfeited (402) 27.67
---------------------------------------------------
Outstanding at end of period 825 25.66 / 23.28
---------------------------------------------------
---------------------------------------------------
Unit rights exercisable at period end 728 26.02 / 23.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

Nine Months Ended September 30, 2010
----------------------------------------------------------------------------
Weighted Average
Number of Exercise Price
Unit Rights Initial and Modified
(thousands) ($/unit right)
----------------------------------------------------------------------------
Outstanding at beginning of period 421 15.81 / 14.58
Unit rights granted 476 19.72
Unit rights exercised (30) 13.90
Unit rights forfeited (82) 17.72
---------------------------------------------------
Outstanding at end of period 785 17.99 / 16.11
---------------------------------------------------
---------------------------------------------------
Unit rights exercisable at period end 120 15.87 / 13.05
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----------------------------------------------------------------------------


8. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

Zargon Oil & Gas Ltd. is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares are convertible into trust units at the option of the shareholder, based on the exchange ratio, which is adjusted monthly to reflect the distribution paid on the trust units. Cash distributions are not paid on the exchangeable shares. During the nine months ended September 30, 2010, a total of 0.09 million (2009 - 0.01 million) exchangeable shares were converted into 0.15 million (2009 - 0.02 million) trust units based on the exchange ratio at the time of conversion. At September 30, 2010, the exchange ratio was 1.78141 trust units per exchangeable share.



Non-Controlling Interest - Exchangeable Shares

Nine Months Ended September 30, 2010
----------------------------------------------------------------------------
(thousands, except exchange ratio) Number of Shares Amount ($)
----------------------------------------------------------------------------
Balance, beginning of period 1,784 26,477
Exchanged for trust units at book value
and including earnings attributed
during the period (91) (1,822)
Earnings attributable to non-controlling interest - 1,779
----------------------------------------------------------------------------
Balance, end of period 1,693 26,434
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, end of period 1.78141
Trust units issuable upon conversion of
exchangeable shares, end of period 3,016
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 and comprehensive income represents the cumulative share of net earnings attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable each 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
($ thousands) Units Shares Total
----------------------------------------------------------------------------
Balance at January 1, 2010 188,840 26,477 215,317
Issued on redemption of exchangeable
shares at book value 221 (221) -
Effect of EIC-151 2,771 178 2,949
Unit-based compensation recognized on
exercise of unit rights 374 - 374
Issued on corporate acquisition 5,946 - 5,946
Unit rights exercised for cash 2,032 - 2,032
Unit rights issued pursuant to
Distribution Reinvestment Plan 1,523 - 1,523
----------------------------------------------------------------------------
Balance at September 30, 2010 201,707 26,434 228,141
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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. Due to the fact that at the time of exercise, the rights holder has the option of exercising at the original grant price or a modified price as calculated under the Plan, the prices used in the treasury stock calculation are the lower prices calculated under the Plan.



Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
(thousands of units) 2010 2009 2010 2009
----------------------------------------------------------------------------
Basic 23,498 22,478 23,417 20,444
Diluted 26,427 25,325 26,237 23,102
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. CAPITAL DISCLOSURES

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

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

ii) finance internally generated growth as well as acquisitions.

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



September 30, December 31,
($ thousands, except ratio) 2010 2009
----------------------------------------------------------------------------
Net debt 107,895 88,008
Annualized funds flow from operating activities 79,026 86,352
----------------------------------------------------------------------------
Net debt to funds flow from operating activities
ratio 1.37 1.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at September 30, 2010, Zargon's net debt to funds flow from operating activities ratio was 1.37, an increase from 1.02 at December 31, 2009. This increase was primarily due to an increase in long term debt due to Zargon's capital distributions, field capital, and property and corporate acquisitions. On June 29, 2010, Zargon amended and renewed its syndicated committed credit facilities of $180 million. The next renewal date is June 28, 2011. These facilities continue to be available for general corporate purposes and the potential acquisition of oil and natural gas properties.

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

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

Zargon reviews its compliance with its bank debt covenants on a quarterly basis and has no violations as at September 30, 2010.

11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT CONTRACTS

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 CICA Section 3855.

Financial assets and financial liabilities classified as "held-for-trading" are measured at fair value with changes in fair value recognized in earnings. Financial assets classified as "available-for-sale" are measured at fair value, with changes in fair value recognized in other comprehensive income ("OCI") until the asset is removed from the consolidated balance sheets. Financial assets classified as "held-to-maturity", "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest method of amortization.

Fair Value of Financial Assets and Liabilities

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

A) Fair Value of Financial Assets and Liabilities

Accounts receivable are designated as "loans and receivables". Accounts payable and accrued liabilities, cash distributions payable and long term debt are designated as "other liabilities". The fair values of these accounts approximate their carrying amounts.

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

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

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

- Level I

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

- Level II

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

- Level III

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

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

B) Risk Management Assets and Liabilities

The Trust is a party to certain financial instruments that have fixed the price of a portion of its oil and natural gas production and electricity rates. The Trust enters into these contracts for risk management purposes only, in order to protect a portion of its future cash flow from the volatility of oil and natural gas commodity prices and electricity rates. For financial risk management contracts, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, any unrealized gains or losses are recorded in earnings based on the fair value (mark-to-market) of the contracts at each reporting period. The unrealized loss on the statement of earnings and comprehensive income and accumulated earnings for the first nine months of 2010 was $1.10 million and the unrealized loss for the first nine months of 2009 was $23.42 million.

As at September 30, 2010, the Trust had the following outstanding commodity and electricity risk management contracts:



Commodity Financial Risk Management Contracts:
Fair Market
Value
Weighted Liability
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Oil
swaps 1,700 bbl/d $74.91 US/bbl Oct. 1/10 - Dec. 31/10 (1,012)
400 bbl/d $77.40 US/bbl Oct. 1/10 - Jun. 30/11 (628)
300 bbl/d $77.25 US/bbl Jan. 1/11 - Sep. 30/11 (601)
1,100 bbl/d $83.33 US/bbl Jan. 1/11 - Dec. 31/11 (617)
600 bbl/d $83.05 US/bbl Jan. 1/11 - Jun. 30/12 (877)
200 bbl/d $83.50 US/bbl Jul. 1/11 - Aug. 31/12 (276)
----------------------------------------------------------------------------
Total Fair Market Value, Commodity Price Financial Contracts (4,011)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil swaps are settled against the NYMEX WTI pricing index.

Electricity Financial Risk Management Contracts:

Fair Market
Value
Weighted Liability
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Electricity
swaps 6 MWs/d $80.42/MWh Oct. 1/10 - Dec. 31/10 (19)
6 MWs/d $79.33/MWh Jan. 1/11 - Dec. 31/11 (77)
----------------------------------------------------------------------------
Total Fair Market Value, Electricity Financial Contracts (96)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Electricity swaps are settled against the AESO pricing index.

Commodity Physical Risk Management Contracts:

Fair Market
Weighted Value Gain
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Natural gas
fixed price 3,000 gj/d $4.29/gj Oct. 1/10 - Oct. 31/10 84
----------------------------------------------------------------------------
Total Fair Market Value, Natural Gas Physical Contracts 84
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

Electricity Physical Risk Management Contracts:

Fair Market
Weighted Value Loss
Rate Average Price Range of Terms ($ thousands)
----------------------------------------------------------------------------
Electricity
swaps 32 MWs/d $55.50/MWh Oct. 1/10 - Mar. 31/11 (67)
----------------------------------------------------------------------------
Total Fair Market Value, Electricity Physical Contracts (67)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Commodity Price Sensitivities

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

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



Three and Nine Months Ended September 30,
----------------------------------------------------------------------------
($ thousands) 2010 2009
----------------------------------------------------------------------------
Natural gas price - 18
Crude oil price 10,118 7,016
----------------------------------------------------------------------------
----------------------------------------------------------------------------


C) Risks Associated with Financial Assets and Liabilities

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

- Market Risk

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

- Commodity Price Risk

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

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

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

- Interest Rate Risk

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

At the September 30, 2010 debt pricing levels, the increase or decrease in net earnings for each one percent change in interest rates would amount to $0.70 million (2009 - $0.63 million).

- Foreign Exchange Risk

As Zargon operates in North America, fluctuations in the exchange rate between the US/Canadian dollar can have a significant effect on the Trust's reported results. A $0.01 change in the US to Canadian dollar exchange rate would have resulted in a $0.57 million (2009 - $0.45 million) increase or decrease in net earnings at September 30, 2010. In order to mitigate the Trust's exposure to foreign exchange fluctuations, the Trust from time to time enters into foreign exchange derivative agreements.

- Credit Risk

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

The maximum credit risk exposure associated with accounts receivable, accrued revenues and risk management assets is the total carrying value. The Trust monitors these balances monthly to limit the risk associated with collection. Of Zargon's accounts receivable at September 30, 2010, approximately 52 percent (December 31, 2009 - 40 percent) was owing from two companies and Zargon anticipates full collection.

The Trust's allowance for doubtful accounts was $0.10 million as at September 30, 2010 and $0.10 million as at December 31, 2009. To date, in 2010, the Trust did not record any additional provisions for non-collectible accounts receivable.

When determining whether amounts that are past due are collectible, management assesses the credit worthiness and past payment history of the counterparty, as well as the nature of the past due amount. Zargon considers all material amounts greater than 90 days to be past due. As at September 30, 2010, $0.82 million of accounts receivable are past due, excluding amounts described above, all of which are considered to be collectible.

- Liquidity Risk

Liquidity risk is the risk the Trust will encounter difficulties in meeting its financial liability obligations. The Trust manages its liquidity risk through cash and debt management. See note 10 for a more detailed discussion.

As at September 30, 2010, Zargon had available unused committed bank credit facilities of approximately $81.71 million compared to $102.81 million at December 31, 2009. The Trust believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.

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



($ thousands) 1 year 2-3 years Total
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 28,194 - 28,194
Cash distributions payable 4,014 - 4,014
Risk management liabilities (1) 3,517 876 4,393
Long term debt - 97,606 97,606
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) See the section titled "Commodity Price Sensitivities" in this note for
a better understanding of the volatility around these amounts.

12. CHANGES IN NON-CASH WORKING CAPITAL

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Changes in non-cash working capital
items:
Accounts receivable 3,234 (1,124) 5,858 (1,994)
Prepaid expenses and deposits 454 (839) (541) (1,190)
Accounts payable and accrued
liabilities (1,010) 4,914 (6,313) 2,335
Cash distributions payable 60 100 (143) 812
Working capital acquired from
corporate acquisitions (3,410) (6,576) (3,410) (6,681)
Foreign exchange and other (150) (505) (76) (821)
----------------------------------------------------------------------------
(822) (4,030) (4,625) (7,539)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Changes relating to operating
activities 1,558 462 (5,187) (638)
Changes relating to financing
activities 60 100 (143) 812
Changes relating to investing
activities (2,440) (4,592) 705 (7,713)
----------------------------------------------------------------------------
(822) (4,030) (4,625) (7,539)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


13. SUPPLEMENTAL CASH FLOW INFORMATION

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash interest paid 1,019 1,170 3,314 2,501
Cash taxes paid (148) 72 2,061 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------

14. SEGMENTED INFORMATION

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

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Petroleum and Natural Gas Revenue
Canada 40,911 36,867 125,043 98,077
United States 3,584 4,088 11,794 10,696
----------------------------------------------------------------------------
Total 44,495 40,955 136,837 108,773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Capital Expenditures(1)
Canada (1,776) 28,886 50,714 91,208
United States 508 431 1,020 509
----------------------------------------------------------------------------
Total (1,268) 29,317 51,734 91,717
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For net capital expenditures, amounts include capital expenditures
acquired for cash, equity issuances, acquisition costs (2009 only) and
net debt assumed on corporate acquisitions.


September 30, December 31,
($ thousands) 2010 2009
----------------------------------------------------------------------------
Property and Equipment, net
Canada 405,031 394,448
United States 30,877 31,516
----------------------------------------------------------------------------
Total 435,908 425,964
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill
Canada 2,969 2,969
United States - -
----------------------------------------------------------------------------
Total 2,969 2,969
----------------------------------------------------------------------------
----------------------------------------------------------------------------

15. CASH DISTRIBUTIONS

During the nine month period, the Trust declared distributions to the
unitholders in the aggregate amount of $37.88(1) million (2009 - $33.51
million) in accordance with the following schedule:

2010 Distributions Record Date Distribution Date Per Trust Unit
----------------------------------------------------------------------------
January January 31, 2010 February 15, 2010 $ 0.18
February February 28, 2010 March 15, 2010 $ 0.18
March March 31, 2010 April 15, 2010 $ 0.18
April April 30, 2010 May 17, 2010 $ 0.18
May May 31, 2010 June 15, 2010 $ 0.18
June June 30, 2010 July 15, 2010 $ 0.18
July July 31, 2010 August 16, 2010 $ 0.18
August August 31, 2010 September 15, 2010 $ 0.18
September September 30, 2010 October 15, 2010 $ 0.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The 2010 cash distributions include a non-cash equity issuance amount of
$1.53 million for the Distribution Reinvestment Plan which commenced in
April 2010.


Contact Information

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