Trilogy Energy Trust
TSX : TET.UN

Trilogy Energy Trust

November 01, 2005 20:00 ET

Trilogy Energy Trust Financial and Operating Results for the Quarter Ended September 30, 2005

CALGARY, ALBERTA--(CCNMatthews - Nov. 01, 2005) - Trilogy Energy Trust (TSX:TET.UN) ("Trilogy" or "the Trust") is pleased to announce its financial and operating results for the three months ended September 30, 2005.



FINANCIAL HIGHLIGHTS
(thousand dollars except per unit amounts and where stated otherwise)

(1) The financial statements prior to April 1, 2005 were prepared on a
carve-out basis from Paramount. These financial statements may not
be indicative of the results that would have been attained if the
Trust had operated as a stand-alone entity for these periods.


Three Months Ended Nine Months Ended
September 30 September 30
% %
2005 2004(1) Change 2005(1) 2004(1) Change
------------------------------------------------------------------------
FINANCIAL
Petroleum and
natural gas
sales 131,052 91,468 43% 348,949 225,082 55%
Funds flow(2)
From operations 68,170 45,489 50% 172,666 118,210 46%
Per unit
- basic(3) 0.86 0.57 50% 2.18 1.49 46%
- diluted(3) 0.86 0.57 50% 2.18 1.49 46%
Earnings
Earnings before
certain
items(7) 31,942 14,102 127% 65,277 37,697 73%
Net earnings
(loss) (2,529) 17,041 -115% (1,228) 31,021 -104%
Per unit
- basic(3) (0.03) 0.22 -115% (0.02) 0.39 -104%
- diluted(3) (0.03) 0.22 -115% (0.02) 0.39 -104%
Capital
expenditures
Exploration and
development 25,820 19,719 31% 94,887 72,562 31%
Acquisitions,
dispositions
and other 150 82,770 -100% 1,342 173,639 -99%
Net capital
expenditures 25,970 102,489 -75% 96,229 246,201 -61%
Total assets(4) 761,587 778,147 -2% - - -
Net debt(4)
and (5) 280,450 10,249 2636% - - -
Unitholders'
equity(4) 340,397 532,430 -36% - - -
Trust Units
outstanding
(thousands)
- As at
September 30,
2005 79,133 - - - - -
- As at
November 1,
2005 79,133 - - - - -
------------------------------------------------------------------------

OPERATING
Production
Natural gas
(MMcf/d) 116 104 12% 118 91 30%
Crude oil and
liquids (Bbl/d) 5,154 5,195 -1% 4,962 3,270 52%
Total production
(Boe/d) @ 6:1 24,404 22,521 8% 24,625 18,506 33%
------------------------------------------------------------------------

Average prices
Natural gas
(pre-financial
instruments)
($/Mcf) 9.31 6.88 35% 8.30 7.20 15%
Natural gas
($/Mcf)(6) 9.09 6.77 34% 8.16 7.13 14%
Crude oil and
liquids
(pre-financial
instruments)
($/Bbl) 67.72 53.64 26% 60.29 49.85 21%
Crude oil and
liquids
($/Bbl)(6) 62.38 53.28 17% 59.07 48.42 22%
------------------------------------------------------------------------

Drilling activity
(gross)
Gas 15 13 15% 46 48 -4%
Oil 3 2 50% 7 4 75%
D&A 1 0 - 4 1 300%
Total wells 19 15 27% 57 53 8%
Success rate 95% 100% -5% 93% 98% -5%
------------------------------------------------------------------------
------------------------------------------------------------------------

(2) Funds flow from operations is a non-GAAP term that represents net
earnings adjusted for non-cash items, dry hole costs and geological
and geophysical costs. The Trust considers funds flow from
operations a key measure as it demonstrates the Trust's ability to
generate the cash necessary to fund future growth through capital
investment and to repay debt. Funds flow should not be considered
an alternative to, or more meaningful than, net earnings as
determined in accordance with Canadian GAAP.

(3) Per unit amounts for all periods presented were calculated using the
weighted average number of units outstanding for the three months
ended September 30, 2005.

(4) Comparative figures are as at December 31, 2004 which were prepared
on a carve-out basis from Paramount.

(5) Net debt is equal to long-term debt plus/minus working capital.

(6) Excludes non-cash gains and losses on financial instruments.

(7) After excluding the impact of: unrealized gain (loss) on
financial instruments and unit-based compensation expense arising
since April 1, 2005. In addition, earnings before April 1, 2005 have
been adjusted for taxes, foreign exchange gains and losses, bad debt
recovery, and the premium on debt exchange.


REVIEW OF OPERATIONS

Trilogy Energy Trust ("Trilogy" or "the Trust") has successfully completed its second quarter of operations following the spin out from Paramount Resources Ltd. ("Paramount") on April 1, 2005. The third quarter of 2005 was significantly more active than the second quarter when activities were restricted due to unfavourable weather. The challenge, which is consistent with Trilogy's overall strategy, was to execute a plan that would generate enough activity to replace production declines and maintain production levels of 25,000 Boe/d that were forecast when the Trust was formed. Trilogy has executed the plan and completed the required capital activity to grow production back to the base forecast with September 2005 production averaging 25,185 Boe/d.

As mentioned previously, weather played a significant role in our second quarter activity. Road bans restricted access to certain operating areas and delayed plans to complete construction on a number of projects that were expected to replace declines and maintain a stable production profile. Some delayed projects were completed and added volumes to the third quarter production. The remaining projects will either add to fourth quarter production or will be completed in the winter and add to the 2006 production volumes.

Production for the Trust assets averaged 24,404 Boe/d; 116 MMcf/d of natural gas and 5,154 Bbl/d of oil and natural gas liquids, for the third quarter. This is a slight increase when compared with production of 24,287 Boe/d reported for the second quarter of 2005. This brings the year-to-date production average to 24,625 Boe/d for the Trust assets. Trilogy has forecast production to be 25,000 Boe/d for 2005 and in order to meet this annualized target, the Trust needs to produce in excess of 26,000 Boe/d in the fourth quarter. We are confident that we will be successful in reaching our forecast target.

The 2005 capital budget, excluding prior year carryovers, for the Trilogy properties is $100 million which was the amount forecast to replace production declines and reserves in 2005. Trilogy has budgeted $65 million to be spent during the nine months that the Trust will be in existence in 2005. Third quarter capital spending was $25.9 million, bringing our capital program to $42.1 million from the date of the Trust's inception. This includes the $5.5 million invested in Crown lands from April 1, 2005. Capital expenditures in the first quarter of 2005 related to the Trilogy properties have been reported by Paramount. In the Management's Discussion and Analysis and Interim Financial Statements sections of this report, such capital expenditures have been presented as part of the expenditures for the nine months ended September 30, 2005, on a carve-out basis from Paramount. Wet conditions have forced us to improvise our drilling procedures resulting in additional costs associated with the moving of drilling rigs, padding drilling surface locations and access roads, as well as increased costs for services as a result of increased demand by industry, have contributed to the increase in capital costs for Trilogy's capital program. Results from the capital program have been better than forecast so that although these unit costs are higher, the production and reserve addition expectations have been maintained.

Operating costs for the quarter have increased to $8.48/Boe which is up significantly from the $7.08/Boe reported for the same period in 2004. Costs have been increasing due to an increase in the costs of services as a result of overall increased industry demand as well as the higher per unit costs that are usually associated with more mature producing assets. Additional costs were incurred in the Kaybob area coincidental with an increase in workover activity and facility maintenance.

Trilogy participated in 19 (15.7 net) wells in the third quarter compared to 5 (3.6 net) wells drilled in the second quarter of 2005. All but one of the 19 wells drilled in the quarter were cased for oil or gas production, resulting in a 95 percent success rate. The one abandoned well was whip-stocked and subsequently cased for gas production from the Gething formation. We had three drilling rigs and four service rigs active drilling and completing wells during the quarter. Three of the 19 wells drilled in the third quarter have been tied in and are on production; an additional three wells are currently in the process of being tied in. The remaining twelve wells are in the process of being completed. It was expected that a number of these wells would have been on production prior to the end of the quarter to meet our production targets, however the operations will be completed and production volumes will be added in the next two quarters.

Trilogy has continued the workover and remediation program in the Kaybob South Beaverhill Lake Unit 3; encouraging results have prompted the addition of a second service rig to this project. There has also been a concerted effort to evaluate wells that were previously shut-in or suspended under lower price environments. We have enhanced our production growth with an acceleration of workover programs which, combined with new tie ins has helped to replace declining production. We expect that cased wells, recent completions and ongoing drilling activity will maintain our annual production target of 25,000 Boe/d.

In the Marten Creek area, production for the quarter was kept constant at 20 MMcf/d. The Marten Creek gas plant, operated by a mid-stream company, completed the expansion of the gas plant at the end of the third quarter. Capacity of the plant was increased from 32 MMcf/d to 38 MMcf/d, while Trilogy's net capacity in the plant increased from 20 MMcf/d to 25 MMcf/d. Trilogy has increased natural gas production to 24 MMcf/d at the end of the third quarter, which we forecast to be sustainable for the remainder of the year. Trilogy is planning a number of recompletions and workovers on current producing wells; there are also plans to drill approximately 12 wells in this area during the 2006 winter drilling season to ensure sufficient production capability to sustain the 24 MMcf/d of natural gas throughout 2006.

Trilogy will continue to focus the majority of our drilling activity and capital spending on exploiting the undeveloped resources within the Gething formation in the Kaybob area. As development continues on the Gething formation, other tight gas reservoirs are being evaluated for further reservoir development and exploitation. The Company will also continue our successful re-completion and workover programs at Kaybob. In the Marten Creek area, the shallow gas reservoirs in the Viking, Clearwater and Wabiskaw will be developed by drilling additional wells and re-completing additional zones in the existing well bores in the upcoming winter season.

Trilogy's strategy to undertake capital expenditures to maintain production and reserve levels and distribute the remaining cash flow generated from operations was continued through the third quarter of 2005. Trilogy generated cash flow of $ 68.2 million and subsequently spent $25.9 million and distributed $38.0 million for a total of $63.8 million. Trilogy increased monthly cash distributions from $0.16/unit to $0.25/unit for September in response to a substantial increase in commodity prices which the trust is receiving for its oil and natural gas production. Trilogy has increased the distributions to a level which we believe can be sustained based on the current commodity price forecast and future production estimates.

Trilogy continues to maintain a sustainable inventory of development opportunities. There exists a large, as yet, undeveloped resource in the central Alberta area that will replace produced reserves for Trilogy Unitholders. Successful production replacement, prudent asset management, strong commodity prices and continued control of operations will support a stable distribution. Acquisitions will continue to be evaluated for their strategic fit with Trilogy's business model and exploitation strategy and will be pursued when they are considered to be accretive to unitholder value. We are confident in our strategy, our high quality assets and the proven expertise of our employees; Trilogy will continue to be a rewarding investment for our unitholders.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") provides the details of the results of operations and financial condition of Trilogy Energy Trust ("Trilogy" or the "Trust") as at and for the three and nine months ended September 30, 2005. It should be read in conjunction with the Trust's interim consolidated financial statements and related notes for the three and nine months ended September 30, 2005, and for the three and six months ended June 30, 2005. The consolidated financial statements have been prepared in Canadian dollars in accordance with Canadian generally accepted accounting principles ("GAAP"). This MD&A was prepared using currently available information as of November 1, 2005.

This MD&A includes the historical information on financial condition and results of operations on a carve-out basis from Paramount Resources Ltd. ("Paramount") as if the Trust had operated as a stand-alone entity subject to Paramount's control prior to April 1, 2005. Commencing April 1, 2005, Trilogy holds the Trust Assets, with the earnings from April 1, 2005 being retained until distributed by Trilogy. The historical information pertaining to the periods prior to April 1, 2005 may not necessarily be indicative of the results that would have been attained if the Trust had operated as a stand-alone entity for such periods.

FORWARD-LOOKING STATEMENTS AND ESTIMATES

Certain information set forth in this MD&A, including management's assessment of the Trust's future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond management's control, including but not limited to the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of related 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. Trilogy's actual results, performance or achievement could differ significantly from those expressed in, or implied by, these forward-looking statements.

This MD&A provides management's analysis of Trilogy's historical financial and operating results and provides estimates of Trilogy's future financial and operating performance based on information currently available. Actual results will vary from estimates and the variances may be material. Also, readers should be aware that historical results are not necessarily indicative of future performance.

NON-GAAP MEASURE

Management uses funds flow from operations to analyze the operating performance of the Trust's energy assets. In order to facilitate comparative analysis, funds flow from operations is defined throughout this MD&A as cash flows from operating activities before net changes in operating working capital, which is reconciled to net earnings in the consolidated statements of cash flows. We believe that funds flow from operations is an indicative parameter to measure performance.

Funds flow from operations is not a measure recognized by GAAP and does not have a standardized meaning prescribed by GAAP. Therefore, funds flow from operations, as defined by the Trust, may not be comparable to similar measures presented by other issuers, and investors are cautioned that funds flow from operations should not be construed as an alternative to net earnings, cash flows from operating activities or other measures of financial performance calculated in accordance with GAAP. Funds flow from operations cannot be assured and future distributions may vary.

NUMERICAL REFERENCES

All references in this MD&A are to Canadian dollars unless otherwise indicated. Natural gas volumes recorded in thousand cubic feet (Mcf) are converted to barrels of oil equivalent (Boe) using the ratio of six (6) Mcf of natural gas to one (1) barrel (Bbl) of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method, primarily applicable at the burner tip and does not represent equivalency at the well head.

FORMATION OF TRILOGY

Pursuant to the plan of arrangement involving Paramount and its shareholders and optionholders as described in the Information Circular of Paramount dated February 28, 2005 (the "Plan of Arrangement"), the Trust acquired certain properties from Paramount effective April 1, 2005. These assets (the "Trust Assets") are located in the Kaybob and Marten Creek areas of Alberta. Through the Plan of Arrangement, shareholders of Paramount received in exchange for each of their common shares, one new common share of Paramount and one unit of the Trust ("Trust Unit"). At closing, shareholders of Paramount owned 81 percent of the issued and outstanding Trust Units with the remaining 19 percent of the issued and outstanding Trust Units being held by Paramount.

Trilogy, through a wholly-owned holding trust (Trilogy Holding Trust), owns the Trust Assets through an operating limited partnership (Trilogy Energy LP). Another wholly owned subsidiary of the Trust, Trilogy Energy Ltd., acts as the general partner of Trilogy Energy LP and as administrator to Trilogy and Trilogy Holding Trust.

IMPORTANT EVENTS

The following events which took place while the Trust Assets were still under Paramount's control impact this MD&A:

1. Kaybob Acquisition. On June 30, 2004, Paramount entered into an agreement to acquire oil and natural gas assets for cash consideration of $185.1 million, after adjustments. The assets acquired by Paramount are located in the Kaybob area in central Alberta, in the Fort Liard area in the Northwest Territories and in northeast British Columbia. From the properties acquired, only certain Kaybob area assets valued at $91.7 million were considered part of the Trust Assets. The consolidated financial statements of the Trust reflect the income of the properties that became part of the Trust Assets for the periods after the closing of the acquisition.

2. Marten Creek Acquisition. On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for a cash consideration of $86.9 million. All these properties were transferred as part of the Trust Assets and the income for the periods after the closing date of this acquisition is included in the Trust's consolidated financial statements.



RESULTS OF OPERATIONS

Production
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2005 2004 2005 2004
------------------------------------------------------------------------
Natural gas (Mcf/d) 115,503 103,957 117,977 91,421
Oil and natural gas
liquids (Boe/d) 5,154 5,195 4,962 3,270
------------------------------------------------------------------------
Total (Boe/d) 24,404 22,521 24,625 18,506
------------------------------------------------------------------------
------------------------------------------------------------------------


Total production increased from 22,521 Boe/d for the third quarter of 2004 to 24,404 Boe/d for the same quarter in 2005 due mainly to the acquisition of the Marten Creek properties during the third quarter of 2004. The acquisitions mentioned above also caused total production to increase from 18,506 Boe/d for the nine months ended September 30, 2004 to 24,625 Boe/d for the same nine-month period in 2005.



Commodity Prices
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2005 2004 2005 2004
------------------------------------------------------------------------
Natural gas prices ($/Mcf)
Before realized loss on financial
instruments 9.31 6.88 8.30 7.20
Realized loss on financial
instruments (0.22) (0.11) (0.14) (0.07)
------------------------------------------------------------------------
After realized loss on financial
instruments 9.09 6.77 8.16 7.13
------------------------------------------------------------------------
------------------------------------------------------------------------
Oil and natural gas liquids
prices ($/Boe)
Before realized loss on financial
instruments 67.72 53.64 60.29 49.85
Realized loss on financial
instruments (5.34) (0.36) (1.22) (1.43)
------------------------------------------------------------------------
After realized loss on financial
instruments 62.38 53.28 59.07 48.42
------------------------------------------------------------------------
------------------------------------------------------------------------

Energy commodity prices in 2005 were generally higher compared to the
energy commodity prices in 2004.

Revenue
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2005 2004 2005 2004
------------------------------------------------------------------------
Natural gas sales 98,942 65,832 267,280 180,422
Oil and natural gas liquid
sales 32,110 25,636 81,669 44,660
------------------------------------------------------------------------
Petroleum and natural gas
sales 131,052 91,468 348,949 225,082
Realized loss on financial
instruments(1) (4,904) (1,209) (6,237) (3,072)
Unrealized gain (loss) on
financial instruments(1) (29,019) 3,642 (50,802) (2,443)
Other (653) - (257) -
------------------------------------------------------------------------
Total revenue before royalties 96,476 93,901 291,653 219,567
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) See the Financial Instruments section of this MD&A.


Total revenue increased during the third quarter of 2005 and nine months ended September 30, 2005 compared to the same periods in 2004 due to increases in both production volumes and commodity prices as noted above.

For the three months ended September 30, 2005, petroleum and natural gas sales increased by $9.9 million as a result of the increase in natural gas production volume from the same three-month period of 2004. This increase in petroleum and natural gas sales was offset by $0.3 million as a result of a slight decrease in oil and natural gas liquids production volume during the third quarter of 2005 compared to the same quarter in 2004. The higher natural gas prices in the third quarter of 2005 contributed an increase of $23.3 million in petroleum and natural gas sales for the third quarter of 2005 compared to the same quarter in 2004. The higher oil and natural gas liquids prices also contributed an increase of $6.7 million in petroleum and natural gas sales during the third quarter of 2005 compared to the same quarter of the previous year.

For the nine months ended September 30, 2005, petroleum and natural gas sales increased by $59.4 million as a result of the increase in natural gas production volume from the same nine-month period of 2004. Petroleum and natural gas sales also increased by $27.7 million during the current nine-month period as a result of the increase in oil and natural gas liquids production volume compared to the same period in 2004. The higher natural gas prices during the current nine-month period contributed an increase in petroleum and natural gas sales by $27.5 million compared to the same period in 2004. The higher oil and natural gas liquids prices during the current nine-month period also contributed an increase in petroleum and natural gas sales by $9.4 million compared to the same period in 2004.



Royalties
------------------------------------------------------------------------
Three Months Nine Months
(thousand dollars except where Ended Sept. 30 Ended Sept. 30
stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------
Royalties, net of ARTC 28,839 17,032 79,610 44,133
Percentage of petroleum
and natural gas sales 22% 19% 23% 20%
------------------------------------------------------------------------
------------------------------------------------------------------------


Royalties, net of ARTC, increased 69 percent from $17.0 million for the third quarter of 2004 to $28.8 million for the same quarter in the current year, and 80 percent from $44.1 million for the nine months ended September 30, 2004 to $79.6 million for the same nine-month period in 2005, due to higher petroleum and natural gas sales as discussed above.

As a percentage of petroleum and natural gas sales, royalties averaged 22 percent - 23 percent for 2005 compared to 19 percent - 20 percent for 2004. The newly acquired properties described above have higher royalty rates than those owned prior to the property acquisitions.



Operating and Transportation Costs
------------------------------------------------------------------------
Three Months Nine Months
(thousand dollars except where Ended Sept. 30 Ended Sept. 30
stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------
Operating costs 19,029 14,664 51,394 30,945
Operating costs per Boe ($/Boe) 8.48 7.08 7.64 6.10

Transportation costs 4,864 4,286 15,139 12,868
Transportation costs per Boe
($/Boe) 2.17 2.07 2.25 2.54
------------------------------------------------------------------------
------------------------------------------------------------------------


Total operating costs for the three months ended September 30, 2005 were 30 percent higher at $19.0 million compared to $14.7 million for the three months ended September 30, 2004. Total operating costs for the nine months ended September 30, 2005 also increased 66 percent to $51.4 million compared to $30.9 million for the nine months ended September 30, 2004. These increases in operating costs are attributable mainly to the higher number of producing properties and increased production arising from the property acquisitions described above. On a per unit of production basis, operating costs increased in both periods of 2005 compared to 2004 reflecting general increases in the cost of goods and services in the energy sector, higher operating costs related to the acquired properties, and increased workovers.

Transportation costs also increased for both periods in 2005 compared to the corresponding periods in 2004 as a result of the increases in production volumes.


Netbacks
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
($ per Boe) 2005 2004 2005 2004
------------------------------------------------------------------------

Gross revenue before
financial instruments (1) 55.91 42.08 49.62 41.85
Royalties (12.84) (8.22) (11.84) (8.70)
Operating costs (8.48) (7.08) (7.64) (6.10)
------------------------------------------------------------------------
Operating netback 34.59 26.78 30.14 27.05
Realized loss on
financial instruments (2.18) (0.58) (0.93) (0.61)
Asset retirement
obligation expenditures (0.04) - (0.10) -
General and administrative
expenses(2) (0.95) (1.54) (1.52) (1.74)
Interest expense (0.95) (2.37) (1.04) (1.50)
Lease rentals (0.11) (0.13) (0.10) (0.13)
------------------------------------------------------------------------
Funds flow per Boe before certain
non-recurring allocated items 30.36 22.16 26.45 23.07
Realized foreign exchange loss - - (0.70) -
Bad debt recovery - 0.01 - 0.56
Large Corporation Tax and other - (0.21) (0.06) (0.32)
------------------------------------------------------------------------
Funds flow per Boe 30.36 21.96 25.69 23.31
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Net of transportation costs and other income (loss)
(2) Excluding non-cash general and administrative expenses

General and Administrative Expenses
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(thousand dollars except
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------

General and administrative
expenses before unit-based
compensation 2,123 3,861 11,237 10,142
Unit-based compensation expense 5,452 - 7,056 -
------------------------------------------------------------------------
Total general and
administrative expenses 7,575 3,861 18,293 10,142
------------------------------------------------------------------------
------------------------------------------------------------------------

Before unit-based
compensation ($/Boe) 0.95 1.86 1.67 2.00
After unit-based
compensation ($/Boe) 3.37 1.86 2.72 2.00
------------------------------------------------------------------------
------------------------------------------------------------------------


General and administrative expenses before unit-based compensation were lower during the third quarter of 2005 compared to the same quarter of 2004 due mainly to the normalization of costs of shared administration services between the Trust and Paramount. As discussed under the Related Party Transactions section of this MD&A, Paramount provides administration and operating services at cost to the Trust under a service agreement dated April 1, 2005. Costs billed by Paramount under this agreement are included in general and administrative expenses.

General and administrative expenses before unit-based compensation are slightly higher in the nine months ended September 30, 2005 compared to the corresponding period in 2004 due mainly to increases in office and administration expenditures during the transition periods for the commencement of the Trust's operations.

The amounts of unit-based compensation expenditures in the current periods represent the amortized market value of the unit appreciation rights granted to Trust employees, officers and directors on April 1, 2005, recognized according to the vesting schedules of the appreciation rights. The significant increase in the market price ($27.90 per Trust Unit at September 30, 2005) of Trilogy Trust Units resulted in an increase in the value of the appreciation units and the related amount recognized against earnings.

On a per unit of production basis, general and administrative expenses before unit-based compensation decreased during the nine months period ended September 30, 2005 compared to the same period in 2004 despite the increase in the total dollar value of general and administrative expenses due to the increase in production volumes to cover fixed expenses.

Interest Expense

Interest expense was 57 percent lower for the three months ended September 30, 2005 falling from $4.9 million for the three months ended September 30, 2004 to $2.1 million. For the nine months ended September 30, 2005, interest expense was 8 percent lower declining from $7.6 million for the nine months ended September 30, 2004 to $7.0 million. The lower interest expense during the current periods is due mainly to the lower interest rates on Trilogy's Canadian dollar denominated borrowing effective April 1, 2005. Prior to April 1, 2005, interest expense was recognized in the consolidated statements of earnings based on a deemed debt balance attributable to the Trust Assets using Paramount's borrowing rates, which were higher due to its U.S. dollar denominated debt.



Depletion and Depreciation
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(thousand dollars except
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------

Depletion and
depreciation expense 33,232 29,847 100,701 72,181
Depletion and
depreciation expense per Boe
($/Boe) 14.80 14.41 14.98 14.23
------------------------------------------------------------------------
------------------------------------------------------------------------


Total depletion and depreciation expense increased by 11 percent and 40 percent, respectively, during the three and nine months ended September 30, 2005 compared to the same periods in 2004 due mainly to higher production volumes. On a per unit basis, depletion and depreciation expense per Boe is up to $14.80/Boe and $14.98/Boe, respectively, for the three and nine months ended September 30, 2005 from $14.41/Boe and $14.23/Boe, respectively, for the comparable periods in 2004, as the depletion and depreciation rates are higher for the properties acquired during the third quarter of 2004. Expired mineral leases included in depletion and depreciation expense for the three and nine months ended September 30, 2005 amounted to $0.6 million and $4.6 million, respectively (2004 - $1.1 million and $2.4 million, respectively).

Capital costs associated with undeveloped land and exploratory, non-producing petroleum and natural gas properties of $68.3 million are excluded from costs subject to depletion at September 30, 2005 (December 31, 2004 - $55.2 million).

Dry Hole Costs

No dry hole costs and $4.3 million of dry hole costs were expensed, respectively, for the three and nine months ended September 30, 2005 (2004 - $nil and $0.9 million, respectively).

FINANCIAL INSTRUMENTS

To protect cash flow against commodity price volatility, the Trust utilizes, from time to time, forward commodity price contracts that require financial settlement between counterparties. The financial instruments program is generally for periods of less than one year and would not exceed 50 percent of Trilogy's current production volumes.



As at September 30, 2005, the Trust had the following forward financial
sales contracts in place:

------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------

AECO Fixed Price 10,000 GJ/d $ 7.06 April 2005 - October 2005
AECO Fixed Price 10,000 GJ/d $ 7.10 April 2005 - October 2005
AECO Fixed Price 20,000 GJ/d $ 7.10 April 2005 - October 2005
AECO Fixed Price 10,000 GJ/d $ 8.73 November 2005 - March 2006
AECO Fixed Price 10,000 GJ/d $ 8.71 November 2005 - March 2006
AECO Fixed Price 20,000 GJ/d $ 8.09 November 2005 - March 2006
NYMEX-WTI
Fixed Price 1,000 Bbl/d $ 57.70 May 2005 - December 2005
NYMEX-WTI
Fixed Price 1,000 Bbl/d $ 53.43 October 2005 - March 2006
------------------------------------------------------------------------
------------------------------------------------------------------------


The Trust follows the recommendations set out in Accounting Guideline ("AcG") 13 - Hedging Relationships and Emerging Issues Committee Abstract 128 - Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments issued by the Canadian Institute of Chartered Accountants. According to these recommendations, financial instruments that do not qualify as hedges under AcG 13 or are not designated as hedges are recorded in the consolidated balance sheets as either an asset or a liability, with changes in fair value recorded in net earnings. The Trust has elected not to designate any of its financial instruments as a hedge and accordingly, has used mark-to-market accounting for these instruments.

The change in the fair value of outstanding financial instruments is presented as 'unrealized gain (loss) on financial instruments' in the consolidated statements of earnings. Gains or losses arising from monthly settlement with counterparties are presented as 'realized gain (loss) on financial instruments.' The amounts of unrealized and realized gain (loss) on financial instruments during the periods are as follows:




------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2005 2004 2005 2004
------------------------------------------------------------------------

Realized loss on financial
instruments (4,904) (1,209) (6,237) (3,072)
Unrealized gain (loss) on
financial instruments (29,019) 3,642 (50,802) (2,443)
------------------------------------------------------------------------
Total gain (loss) on financial
instruments (33,923) 2,433 (57,039) (5,515)
------------------------------------------------------------------------
------------------------------------------------------------------------


The mark-to-market accounting of financial instruments causes significant fluctuations in gain (loss) on financial instruments due to the volatility of energy commodity prices.

Subsequent to September 30, 2005, the Trust has entered into the following financial arrangements:



------------------------------------------------------------------------
Quantity Floor Ceiling Term
------------------------------------------------------------------------

AECO Costless January 2006 -
Collar 10,000 GJ/d $12.00/GJ $17.65/GJ March 2006
AECO Costless April 2006 -
Collar 20,000 GJ/d $9.00/GJ $12.50/GJ October 2006
------------------------------------------------------------------------
------------------------------------------------------------------------


Under a service agreement described under the Related Party Transactions section, Paramount performs marketing functions on behalf of the Trust. The Trust is exposed to credit risk from financial instruments to the extent of non-performance by third parties. Credit risks associated with possible non-performance by financial instrument counterparties are minimized by entering into contracts with only highly rated counterparties and controls third party credit risk with credit approvals, limits on exposures to any one counterparty, and monitoring procedures. Production is sold to a variety of purchasers under normal industry sale and payment terms. The Trust's accounts receivable are with customers and joint venture partners in the petroleum and natural gas industry and are subject to normal credit risk.

The Trust is also exposed to fluctuations in interest rates relative to its bank credit facilities as discussed under the Liquidity and Capital Resources section of this MD&A.



CAPITAL EXPENDITURES

Wells Drilled
------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(no. of wells) 2005 2004 2005 2004
------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
(1) (2) (1) (2) (1) (2) (1) (2)

Natural gas 15.0 13.6 13.0 9.4 46.0 41.1 48.0 36.1
Oil 3.0 1.6 2.0 2.0 7.0 4.6 4.0 4.0
Dry 1.0 0.5 0.0 0.0 4.0 2.0 1.0 0.3
------------------------------------------------------------------------
Total 19.0 15.7 15.0 11.4 57.0 47.7 53.0 40.4
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) "Gross" wells means the number of wells in which Trilogy has a
working interest or a royalty interest that may be convertible to a
working interest.
(2) "Net" wells means the aggregate number of wells obtained by
multiplying each gross well by Trilogy's percentage working interest
therein.


The Trust participated in the drilling of 19.0 gross wells (15.7 net) during the three months ended September 30, 2005 compared to 15.0 gross wells (11.4 net) for the comparable three-month period in 2004. On a year-to-date basis, the Trust participated in the drilling of 57.0 gross wells (47.7 net) during the nine months ended September 30, 2005 compared to 53.0 gross wells (40.4 net) for the same period in 2004.



Capital Spending

Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(thousand dollars) 2005 2004 2005 2004
------------------------------------------------------------------------

Land 2,912 4,133 8,016 9,556
Geological and
geophysical costs 1,833 160 3,156 1,497
Drilling 16,825 12,158 60,991 41,826
Production equipment
and facilities 4,250 3,268 22,724 19,683
------------------------------------------------------------------------
Exploration and
development expenditures 25,820 19,719 94,887 72,562
Proceeds received on
property dispositions (2) - (174) (100)
Property acquisitions - 82,464 - 172,659
Other 152 306 1,516 1,080
------------------------------------------------------------------------
Net capital expenditures 25,970 102,489 96,229 246,201
------------------------------------------------------------------------
------------------------------------------------------------------------


Exploration and development expenditures for the three months ended September 30, 2005 were $6.1 million higher at $25.8 million compared to $19.7 million for the same period in 2004 due mainly to the higher number of drilled wells during the current period. On a year-to-date basis, exploration and development expenditures in 2005 were $22.3 million higher at $94.9 million compared to $72.6 million in 2004 due primarily to a higher number of drilled wells and level of development activities in the current period resulting from the property acquisitions described above.



LIQUIDITY AND CAPITAL RESOURCES

Working Capital
------------------------------------------------------------------------
(thousand dollars) Sept. 30, 2005 Dec. 31, 2004
------------------------------------------------------------------------

Current assets 67,999 78,102
Current liabilities (123,077) (88,351)
------------------------------------------------------------------------
Net working capital deficiency (55,078) (10,249)
------------------------------------------------------------------------
------------------------------------------------------------------------


The increase in the working capital deficiency from $10.2 million as at December 31, 2004 to $55.1 million as at September 30, 2005 is due mainly to the existence of a net financial instruments liability of $39.6 million at September 30, 2005 compared to a net financial instruments asset of $11.2 million at December 31, 2004. Financial instruments assets and liabilities are recognized on the fair value of forward financial sales contracts as discussed above. In addition, distributions payable of $19.8 million were recorded as at September 30, 2005 with respect to the September 2005 production month. Distributions were not made prior to the commencement of the Trust operations on April 1, 2005.

The Trust's working capital deficiency is funded by cash flows from operations and draw downs from the Trust's credit facility discussed below.

Bank Debt

On April 1, 2005, the Trust entered into a credit agreement with a syndicate of Canadian chartered banks. Under the terms of the credit agreement, the Trust has a $235 million committed revolving and term facility and a $25 million working capital facility. Borrowing under the facility bears interest at the lenders' prime rate, Bankers' Acceptance rate or LIBOR, plus an applicable margin dependent on certain conditions. The revolving nature of the Trust's credit facility is scheduled to expire on March 31, 2006. If the revolving term of any portion of the credit facility is not extended, that portion of the credit facility will have a term maturity date of 1 year from expiration.

Advances drawn on the Trust's facility are secured by a fixed and floating charge over the assets of the Trust. As at September 30, 2005, $225.4 million of the credit facility has been drawn down. The effective interest rate under this facility for the three months ended September 30, 2005 was 3.49 percent.

The Trust's lenders are currently finalizing a scheduled semi-annual review of its borrowing base and have indicated that the Trust's credit facility will be increased to no less than $300 million, with an effective date of October 31, 2005.

The Trust has letters of credit totaling $5.7 million as at September 30, 2005 outstanding with a Canadian chartered bank. These letters of credit reduce the amount available under the Trust's working capital facility.

Unitholders' Capital

As at September 30, 2005 and November 1, 2005, the Trust had 79,133,395 Trust Units outstanding.



Funds Flow from Operations and Cash Distributions

------------------------------------------------------------------------
Three Months Nine Months
(thousand dollars except Ended Sept. 30 Ended Sept. 30
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------
Funds flow from operations 68,170 45,489 172,666 118,210
Distributions declared(1) 45,106 - 83,090 -
Distribution payout
percentage 66% - - -
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Distributions to unitholders commenced only after the transfer of
the Trust Assets to the Trust on April 1, 2005.


Funds flow from operations increased during the current periods both on quarterly and year-to-date comparisons due mainly to the increases in revenue as discussed above. The amount of future funds flow from operations is highly sensitive to changes in commodity prices, interest rates and other factors.

Trilogy's approach is to maximize the distribution of distributable earnings to unitholders. The increase in distribution from $0.16 per Trust Unit to $0.25 per Trust Unit in September 2005 will increase the above distribution payout percentage. The amount of distributions in the future is highly dependent upon the amount of funds flow to be generated from operations and cannot be assured. Please refer to the Income Tax Section of this MD&A for the taxability of the Trust and its unitholders.

RELATED PARTY TRANSACTIONS

As described in more detail in the Trust's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2005, the following is a summary of the Trust's transactions with related parties:

- Paramount Resources, a wholly-owned subsidiary of Paramount, provides administrative and operating services to the Trust and its subsidiaries to assist Trilogy Energy Ltd. in carrying out its duties and obligations as general partner of Trilogy Energy LP and as the administrator of the Trust and Trilogy Holding Trust. The amount of expenses billed by Paramount Resources for such services was $1.4 million for the three months ended September 30, 2005.

- Under a Call on Production Agreement between Trilogy Energy LP and Paramount, Trilogy Energy LP sold 2,588,000 GJs of natural gas to Paramount for approximately $19.8 million for the three months ended September 30, 2005.

- The Trust and Paramount also had non-interest bearing cash advances from/to each other arising from normal business activities.

The net amount due from Paramount arising from the above related party transactions as at September 30, 2005 was $15.2 million, including an accrued receivable of $7.1 million arising from the delivery of gas in the month of September 2005 under the Call on Production Agreement, and Crown royalty deposit payment of $7.7 million which when refunded to Paramount will be collected by the Trust.

In addition to the letters of credit issued by the Trust as discussed under the Liquidity and Capital Resources Section, Paramount on behalf of the Trust, has issued letters of credit totaling $3.8 million as at September 30, 2005. The Trust has not recorded a liability as at September 30, 2005 with respect to such letters of credit which are set to expire in November 2005.

INCOME TAXES

Each year the Trust is required to file an income tax return and any otherwise taxable income of the Trust is allocated to unitholders. Income of the Trust that has been paid or is payable to unitholders, whether in cash, additional Trust Units or otherwise, will be deductible by the Trust in computing its income for tax purposes.

Future income taxes arise from differences between the accounting and tax basis of the operating entities' assets and liabilities. In our current structure, payments are made between the operating entities and the Trust, ultimately transferring any current income tax liabilities to the unitholders. The tax-efficient structure of the Trust should preclude any income taxes from being payable in the Trust or other direct/indirect subsidiaries of the Trust, and as such, no current or future income tax liabilities have been recognized in the financial statements. However, the determination of the Trust and its direct/indirect subsidiaries income and other tax liabilities require interpretation of complex laws and regulations over multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time.

As at September 30, 2005, tax pools were estimated to be $133 million for tangibles and $28 million for intangibles. Such estimates may differ significantly with the actual tax pools at year-end.

Canadian Taxpayers

The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and accordingly, Trust Units are qualified investments for Registered Retirement Savings Plans, Registered Retirement Income Funds, Registered Education Savings Plans and Deferred Profit Sharing Plans (subject to the specific provisions of any of these particular plans). To the best of our knowledge, Trilogy's foreign ownership level currently is approximated to be 15 percent. The Trust will continue to monitor the progress of any legislative changes to maintain its mutual fund trust status.

A unitholder generally will be required to include in computing income for their particular taxation year, such portion of the net income of the Trust for a taxation year, including net realized taxable capital gains paid or payable to the unitholder in that particular taxation year, whether received in cash, additional Trust Units or otherwise. An investor's adjusted cost basis (ACB) in a Trust Unit generally equals the purchase price of the unit less any non-taxable cash distributions received from the date of acquisition. To the extent a unitholder's ACB is reduced below to zero, such amount will be deemed to be a capital gain to the unitholder and the unitholder's ACB will be nil.

On September 8, 2005 the Department of Finance released its consultation paper "Tax and Other Issues Related to Publicly Listed Flow-Through Entities (Income Trusts and Limited Partnerships)". The Department of Finance stated the purpose of the paper which is to promote discussion and third-party input on a number of key questions by providing background information on, among other things, the estimated impact of flow-through entities on federal tax revenues. At this time it is unknown whether legislation will result from this consultation process. Any legislation could materially affect the Trust or unitholders.

U.S. Taxpayers

Distributions paid out of the Trust's current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, will be taxable as dividend income. Distributions in excess of current and accumulated earnings and profits will be a tax-free recovery of basis to the extent of the United States Holder's adjusted tax basis in the Trust Units and any remaining amount of distributions will generally be subject to tax as a capital gain. Dividends on Trust Units will generally be foreign sourced income for foreign tax credit limitation purposes and will not be eligible for a dividends received deduction.

Certain dividends received by United States individuals from a qualified foreign corporation are subject to a maximum U.S. federal income tax rate of 15 percent. The United States Treasury Department has identified the Canada/United States Income Tax Treaty as a qualifying treaty. The result is that the Trust should be considered a qualified foreign corporation. To qualify for the reduced rate of taxation on dividends, a holder must satisfy certain requirements with respect to their Trust Units.

United States holders are advised to seek legal advice from their professional advisors.




QUARTERLY FINANCIAL INFORMATION
------------------------------------------------------------------------
2005
(thousand dollars except 3rd 2nd 1st
per unit amounts) Quarter Quarter Quarter(1)
------------------------------------------------------------------------
Total revenue (net of financial
instruments) 67,637 80,928 63,478
Net earnings (loss) (2,529) 17,370 (16,069)
Earnings (loss) per Trust Unit(2)
Basic (0.03) 0.22 (0.20)
Diluted (0.03) 0.22 (0.20)
------------------------------------------------------------------------
------------------------------------------------------------------------
2004(1)
(thousand dollars except 4th 3rd 2nd 1st
per unit amounts) Quarter Quarter Quarter Quarter
------------------------------------------------------------------------
Total revenue (net of financial
instruments) 94,891 76,869 52,483 46,082
Net earnings (loss) (5,478) 17,041 6,002 7,978
Earnings (loss) per Trust Unit(2)
Basic (0.07) 0.22 0.08 0.10
Diluted (0.07) 0.22 0.08 0.10
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) The quarterly financial information prior to the 2nd quarter of 2005
was prepared on a carve-out basis from Paramount as the Trust did
not own the Trust Assets prior to April 1, 2005. Quarterly carve-out
financial statements are not available prior to 2004.
(2) Earnings (loss) per unit for all periods presented are based on the
weighted average number of outstanding Trust Units of 79,133,395 for
the three months ended September 30, 2005.


Total revenue and net earnings for the third and first quarters of 2005 declined from the respective previous quarters as a result mainly of losses on financial instruments of $33.9 million for the third quarter of 2005 and $17.2 million for the first quarter of 2005 compared to a loss of $5.9 million in the second quarter of 2005 and a gain of 15.8 million in the fourth quarter of 2004. In addition, a debt exchange premium expense of $15.8 million recorded on a carve-out basis during the first quarter of 2005 contributed to the net loss during the first quarter of 2005.

Total revenue increased consistently from quarter to quarter in 2004 as energy commodity prices continued to increase. In addition, the property acquisitions described above increased production volumes in the third and fourth quarters of 2004 contributing to significant increases in total revenue during those periods. There is a resulting net loss during the fourth quarter 2004 despite a significant increase in total revenue due mainly to the recording (on a carve-out basis) of stock-based compensation expense of $23.7 million. Paramount recorded a stock option liability using the intrinsic value method to account for stock options as at December 31, 2004.

RISKS AND UNCERTAINTIES

Entities involved in the exploration for and production of oil and natural gas face a number of risks and uncertainties inherent in the industry. Trilogy's performance is influenced by commodity pricing, transportation and marketing constraints and government regulation and taxation.

Natural gas prices are influenced by the North American supply and demand balance as well as transportation capacity constraints. Seasonal changes in demand, which are largely influenced by weather patterns, also affect the price of natural gas.

Stability in natural gas pricing is available through the use of short and long-term contract arrangements. Trilogy utilizes a combination of these types of contracts, as well as spot markets, in its natural gas pricing strategy. As the majority of the Trust's natural gas sales are priced to U.S. markets, the Canada/US exchange rate can strongly affect revenue.

Oil prices are influenced by global supply and demand conditions as well as by worldwide political events. As the price of oil in Canada is based on a U.S. benchmark price, variations in the Canada/U.S. exchange rate further affect the price received by Trilogy for its oil.

The Trust's access to oil and natural gas sales markets is restricted, at times, by pipeline capacity. In addition, it is also affected by the proximity of pipelines and availability of processing equipment. Trilogy intends to control as much of its marketing and transportation activities as possible in order to minimize any negative impact from these external factors.

The oil and gas industry is subject to extensive controls, regulatory policies and income taxes imposed by the various levels of government. These controls and policies, as well as income tax laws and regulations, are amended from time to time. Trilogy has no control over government intervention or taxation levels in the oil and gas industry; however, it operates in a manner intended to ensure that it is in compliance with all regulations and is able to respond to changes as they occur.

Trilogy's operations are subject to the risks normally associated with the oil and gas industry including hazards such as unusual or unexpected geological formations, high reservoir pressures and other conditions involved in drilling and operating wells. The Trust attempts to minimize these risks using prudent safety programs and risk management, including insurance coverage against potential losses.

The Trust recognizes that the industry is faced with an increasing awareness with respect to the environmental impact of oil and gas operations. Trilogy has reviewed the environmental risks to which it is exposed and has determined that there is no current material impact on the Trust's operations; however, the cost of complying with environmental regulations is increasing. Trilogy intends to ensure continued compliance with environmental legislation.

CRITICAL ACCOUNTING ESTIMATES

The MD&A is based on the Trust's consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Trilogy bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.

The following is a discussion of the critical accounting estimates that are inherent in the preparation of the Trust's consolidated financial statements and notes thereto.

Accounting for Petroleum and Natural Gas Operations

Under the successful efforts method of accounting, the Trust capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves, including acquisitions, successful exploratory wells, development costs and the costs of support equipment and facilities. Exploration expenditures, including geological and geophysical costs, lease rentals, and exploratory dry holes are charged to earnings (loss) in the period incurred. Certain costs of exploratory wells are capitalized pending determination that proved reserves have been found. Such determination is dependent upon, among other things, the results of planned additional wells and the cost of required capital expenditures to produce the reserves found.

The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results of a drilling operation can take considerable time to analyze, and the determination that proved reserves have been discovered requires both judgment and application of industry experience. The evaluation of petroleum and natural gas leasehold acquisition costs requires management's judgment to evaluate the fair value of exploratory costs related to drilling activity in a given area.

Reserve Estimates

Estimates of the Trust's reserves included in its consolidated financial statements are prepared in accordance with guidelines established by the Alberta Securities Commission. Reserve engineering is a subjective process of estimating underground accumulations of petroleum and natural gas that cannot be measured in an exact manner. The process relies on interpretations of available geological, geophysical, engineering and production data. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate.

Trilogy's reserve information is based on estimates prepared by its independent petroleum consultants. Estimates prepared by others may be different than these estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve estimates may be different from the quantities of petroleum and natural gas that are ultimately recovered. In addition, the results of drilling, testing and production after the date of an estimate may justify revisions to the estimate. Trilogy intends that 100 percent of its annual reserves information will be evaluated by independent petroleum consultants.

The present value of future net revenues should not be assumed to be the current market value of the Trust's estimated reserves. Actual future prices, costs and reserves may be materially higher or lower than the prices, costs and reserves used for the future net revenue calculations.

The estimates of reserves impact depletion, dry hole expenses and asset retirement obligations. If reserve estimates decline, the rate at which the Trust records depletion increases, reducing net earnings. In addition, changes in reserve estimates may impact the outcome of Trilogy's assessment of its petroleum and natural gas properties for impairment.

Impairment of Petroleum and Natural Gas Properties

The Trust reviews its proved properties for impairment annually on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and probable petroleum and natural gas reserves, as estimated by the Trust on the balance sheet date. Reserve estimates, as well as estimates for petroleum and natural gas prices and production costs may change, and there can be no assurance that impairment provisions will not be required in the future.

Unproved leasehold costs and exploratory drilling in progress are capitalized and reviewed periodically for impairment. Costs related to impaired prospects or unsuccessful exploratory drilling are charged to earnings. Acquisition costs for leases that are not individually significant are charged to earnings as the related leases expire. Further impairment expense could result if petroleum and natural gas prices decline in the future or if negative reserve revisions are recorded, as it may be no longer economic to develop certain unproved properties. Management's assessment of, among other things, the results of exploration activities, commodity price outlooks and planned future development and sales, impacts the amount and timing of impairment provisions.

Asset Retirement Obligations

The asset retirement obligations recorded in the consolidated financial statements are based on an estimate of the fair value of the total costs for future site restoration and abandonment of the Trust's petroleum and natural gas properties. This estimate is based on management's analysis of production structure, reservoir characteristics and depth, market demand for equipment, currently available procedures, the timing of asset retirement expenditures and discussions with construction and engineering consultants. Estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology and political and regulatory environments.

RECENT ACCOUNTING PRONOUNCEMENTS

The Canadian Institute of Chartered Accountants (the "CICA") has issued CICA Handbook Section 3855 (Financial Instruments - Recognition and Measurement) which sets out comprehensive requirements for recognition and measurement of financial instruments. Under this new standard, an entity would recognize a financial asset or liability only when the entity becomes a party to the contractual provisions of the financial instrument. Financial assets and financial liabilities would, with certain exceptions, be initially measured at fair value. After initial recognition, the measurement of financial assets would vary depending on the category of the asset: financial assets held for trading (at fair value with the unrealized gains and losses on assets recorded in income), held-to-maturity investments (at amortized cost), loans and receivables (at amortized cost), and available-for-sale financial assets (at fair value with the unrealized gains and losses on assets recorded in comprehensive income). Financial liabilities held for trading would be subsequently measured at fair value while all other financial liabilities would be subsequently measured at amortized cost using the effective interest method.

In conjunction with the new standard on financial instruments as discussed above, CICA Handbook Section 1530 (Comprehensive Income) has also been issued. A statement of comprehensive income would be included in a full set of financial statements for both interim and annual periods under this new standard. Comprehensive income is defined as the change in equity (net assets) of an enterprise during a period from transactions and other events and circumstances from non-owner sources. The new statement would present net income and each component to be recognized in other comprehensive income. Likewise, the CICA has issued Handbook Section 3251 (Equity) which requires the separate presentation of: the components of equity (retained earnings, accumulated other comprehensive income, the total of retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves); and the changes in equity arising from each of these components of equity.

These new standards will be effective for the Trust for the year ending December 31, 2007.

ADDITIONAL INFORMATION

Trilogy is a petroleum and natural gas-focused Canadian energy trust. Trilogy's Trust Units are listed on the Toronto Stock Exchange under the symbol "TET.UN". Additional information about Trilogy is available at www.sedar.com.



INTERIM FINANCIAL STATEMENTS

TRILOGY ENERGY TRUST

Consolidated Balance Sheets (Unaudited)
(thousand dollars)

September 30 December 31
2005 2004
(Note 1)
------------------------------------------------------------------------
ASSETS (note 5)
Current assets
Accounts receivable $ 51,492 $ 63,851
Due from Paramount Resources Ltd. (note 10) 15,209 -
Financial instruments (note 9) - 12,413
Prepaid expenses 1,298 1,838
------------------------------------------------------------------------
67,999 78,102
------------------------------------------------------------------------
Property, plant and equipment (note 3)
Property, plant and equipment, at cost 1,103,305 1,017,645
Accumulated depletion and depreciation (429,117) (337,000)
------------------------------------------------------------------------
674,188 680,645
------------------------------------------------------------------------

Goodwill 19,400 19,400
------------------------------------------------------------------------
$ 761,587 $ 778,147
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities $ 60,499 $ 87,091
Unit-based compensation
- current portion (note 8) 3,146 -
Distributions payable (note 7) 19,783 -
Financial instruments (note 9) 39,649 1,260
------------------------------------------------------------------------
123,077 88,351
------------------------------------------------------------------------
Long-term debt (note 5) 225,372 -
Unit-based compensation liability
- net of current portion (note 8) 3,910 -
Asset retirement obligations (note 4) 68,831 63,674
Future income taxes (note 11) - 93,692
------------------------------------------------------------------------
298,113 157,366
------------------------------------------------------------------------

Commitments and contingencies (note 9)

Unitholders' equity
Unitholders' capital (note 6) 408,646 -
Accumulated earnings 14,841 -
Accumulated distributions (note 7) (83,090) -
Net investment of Paramount Resources Ltd. - 532,430
------------------------------------------------------------------------
340,397 532,430
------------------------------------------------------------------------
$ 761,587 $ 778,147
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.



TRILOGY ENERGY TRUST

Consolidated Statements of Earnings and Accumulated Earnings
(Unaudited)
(thousand dollars except per unit information)

The financial statements prior to April 1, 2005 were prepared on a
carve-out basis from Paramount. As described in note 1, these financial
statements may not be indicative of the results that would have been
attained if the Trust had operated as a stand-alone entity for these
periods.

Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2005 2004 2005 2004
(Note 1) (Note 1) (Note 1)
------------------------------------------------------------------------
Revenue

Petroleum and natural
gas sales $131,052 $ 91,468 $348,949 $225,082
Realized loss on
financial instruments
(note 9) (4,904) (1,209) (6,237) (3,072)
Unrealized gain (loss)
on financial
instruments (note 9) (29,019) 3,642 (50,802) (2,443)
Royalties, net of ARTC (28,839) (17,032) (79,610) (44,133)
Other (653) - (257) -
------------------------------------------------------------------------
67,637 76,869 212,043 175,434
------------------------------------------------------------------------
Expenses
Operating 19,029 14,664 51,394 30,945
Transportation costs 4,864 4,286 15,139 12,868
General and
administrative
(notes 8 and 10) 7,575 3,861 18,293 10,142
Lease rentals 249 266 664 662
Geological and
geophysical 1,833 160 3,156 1,497
Dry hole costs - - 4,251 895
(Gain) loss on sale
of property, plant
and equipment (2) 183 (67) 1,407
Accretion on asset
retirement obligations
(note 4) 1,258 954 4,127 1,991
Depletion and
depreciation 33,232 29,847 100,701 72,181
Interest 2,128 4,904 6,966 7,592
Bad debt recovery - (18) - (2,833)
Unrealized foreign
exchange gain - (9,921) (4,224) (8,194)
Realized foreign
exchange loss - - 4,710 -
Premium on debt
exchange - - 15,810 -
------------------------------------------------------------------------
70,166 49,186 220,920 129,153
------------------------------------------------------------------------
Earnings (loss)
before taxes (2,529) 27,683 (8,877) 46,281
------------------------------------------------------------------------
Taxes (note 11)
Future income tax
expense (recovery) - 10,201 (8,059) 13,644
Large Corporations
Tax and other - 441 410 1,616
------------------------------------------------------------------------
- 10,642 (7,649) 15,260
------------------------------------------------------------------------
Net earnings (loss) (2,529) 17,041 (1,228) 31,021

Accumulated earnings,
beginning of period 17,370 - - -
(Earnings) loss
allocated to net
investment by Paramount - (17,041) 16,069 (31,021)
------------------------------------------------------------------------
Accumulated earnings,
end of period $ 14,841 $ - $ 14,841 $ -
------------------------------------------------------------------------

Earnings (loss) per
Trust Unit (note 6)
- basic $ (0.03) $ 0.22 $ (0.02) $ 0.39
- diluted $ (0.03) $ 0.22 $ (0.02) $ 0.39
------------------------------------------------------------------------
------------------------------------------------------------------------


See accompanying notes to consolidated financial statements.


TRILOGY ENERGY TRUST

Consolidated Statements of Cash Flows
(Unaudited)
(thousand dollars)

The financial statements prior to April 1, 2005 were prepared on a
carve-out basis from Paramount. As described in note 1, these financial
statements may not be indicative of the results that would have been
attained if the Trust had operated as a stand-alone entity for these
periods.

Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2005 2004 2005 2004
(Note 1) (Note 1) (Note 1)
------------------------------------------------------------------------
Operating activities
Net earnings (loss) $ (2,529) $ 17,041 $ (1,228) $ 31,021
Add (deduct) non-cash
and other items
Depletion and
depreciation 33,232 29,847 100,701 72,181
(Gain) loss on sale
of property, plant
and equipment (2) 183 (67) 1,407
Accretion of asset
retirement
obligations 1,258 954 4,127 1,991
Future income tax
expense (recovery)
(note 11) - 10,201 (8,059) 13,644
Non-cash general
and administrative
expenses 5,452 363 8,088 1,022
Non-cash loss (gain)
on financial
instruments (note 9) 29,019 (3,642) 50,802 2,443
Unrealized foreign
exchange gain - (9,921) (4,224) (8,194)
Asset retirement
obligation
expenditures (93) - (691) -
Dry hole costs - - 4,251 895
Amortization of
other assets - 303 - 303
Premium on debt
exchange - - 15,810 -
Geological and
geophysical costs 1,833 160 3,156 1,497
------------------------------------------------------------------------
Funds flow from
operations 68,170 45,489 172,666 118,210
Net changes in
operating working
capital 30,770 7,717 (61,361) (21,705)
------------------------------------------------------------------------
98,940 53,206 111,305 96,505
------------------------------------------------------------------------
Financing activities
Current and long-term
debt - draws 116,078 - 428,482 -
Current and long-term
debt - repayments (120,083) - (204,994) -
Net investment
by Paramount
Resources Ltd. - 49,747 18,270 144,950
Payment to Paramount
re the plan
of arrangement - - (220,000) -
Distributions
to unitholders (37,984) - (63,307) -
------------------------------------------------------------------------
(41,989) 49,747 (41,549) 144,950
------------------------------------------------------------------------
Investing activities
Property, plant and
equipment expenditures (24,139) (19,865) (93,247) (72,145)
Petroleum and natural
gas property
acquisitions (note 3) - (82,464) - (172,659)
Proceeds on sale of
property, plant
and equipment 2 - 174 100
Geological and
geophysical costs (1,833) (160) (3,156) (1,497)
Change in investing
working capital (30,981) (464) 26,473 4,746
------------------------------------------------------------------------
(56,951) (102,953) (69,756) (241,455)
------------------------------------------------------------------------

Increase (decrease)
in cash / cash,
end of period $ - $ - $ - $ -
------------------------------------------------------------------------

Cash interest paid $ 2,323 $ 4,904 $ 7,161 $ 7,592
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


TRILOGY ENERGY TRUST
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2005 and December 31, 2004
(tabular amounts expressed in thousand dollars except per unit
information)


1. BASIS OF PRESENTATION

The consolidated financial statements of Trilogy Energy Trust (the "Trust") have been prepared in accordance with Canadian generally accepted accounting principles. The Trust acquired its operating assets from Paramount Resources Ltd. ("Paramount") effective April 1, 2005. These consolidated financial statements present the historic financial position, results of operations and cash flows on a carve-out basis from Paramount as if the Trust had operated as a stand-alone entity subject to Paramount's control prior to April 1, 2005. Commencing April 1, 2005, the Trust holds the Trust Assets, with the earnings from April 1, 2005 being retained until distributed by the Trust.

As a result of the basis of presentation described above, these financial statements may not be indicative of the results that would have been attained if the Trust had operated as a stand-alone entity for the periods prior to April 1, 2005.

2. SIGNIFICANT ACCOUNTING POLICIES

The unaudited interim consolidated financial statements of the Trust follow the same accounting policies and basis of presentation as the interim consolidated financial statements as at and for the three months ended June 30, 2005 (the "First Financial Statements"). These interim financial statement note disclosures do not include all of those required by Canadian generally accepted accounting principles applicable for annual financial statements and the First Financial Statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the Trust's First Financial Statements.

These consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries, Trilogy Holding Trust, Trilogy Energy LP and Trilogy Energy Ltd.



3. PROPERTY, PLANT AND EQUIPMENT

September 30, 2005
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------------------------------------------
Petroleum and natural
gas properties 1,101,849 (429,016) 672,833
Other 1,456 (101) 1,355
------------------------------------------------------------------------
1,103,305 (429,117) 674,188
------------------------------------------------------------------------
------------------------------------------------------------------------


December 31, 2004
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------------------------------------------
Petroleum and natural
gas properties 1,011,217 (332,997) 678,220
Other 6,428 (4,003) 2,425
------------------------------------------------------------------------
1,017,645 (337,000) 680,645
------------------------------------------------------------------------
------------------------------------------------------------------------


For the three and nine months ended September 30, 2005, dry hole costs of $nil and $4.3 million, respectively, were expensed (2004 - $nil and $0.9 million, respectively).

Capital costs associated with non-producing petroleum and natural gas properties totaling approximately $68.3 million as at September 30, 2005 ($55.2 million as at December 31, 2004) are not subject to depletion.

In 2004, Paramount made the following property acquisitions relating to the Trust Assets:

(a) $185 Million Asset Acquisition

On June 30, 2004, Paramount completed an agreement to acquire oil and natural gas assets for cash consideration of $185.1 million, after adjustments. The assets acquired by Paramount are located in the Kaybob area in central Alberta, in the Fort Liard area in the Northwest Territories and in northeast British Columbia. From the properties acquired, only certain Kaybob area assets are included as part of the Trust Assets. The financial statements reflect the income for only the properties that were transferred to the Trust for the period after the closing date of the acquisition.

The acquisition was accounted for using the purchase method. The following table summarizes the estimated fair value of the net assets acquired:



------------------------------------------------------------------------
Property, plant, and equipment 211,947
Asset retirement obligation (26,847)
------------------------------------------------------------------------
185,100
------------------------------------------------------------------------
------------------------------------------------------------------------


The Trust Assets' portion of the above properties acquired is $91.7 million ($90.2 million before adjustments) of the $185.1 million. Asset retirement obligations for these properties were $22.1 million.

(b) $87 Million Asset Acquisition

On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for cash consideration of $86.9 million, after adjustments. The following table summarizes the estimated fair value of the net assets acquired:



------------------------------------------------------------------------
Property, plant, and equipment 89,015
Asset retirement obligation (2,115)
------------------------------------------------------------------------
86,900
------------------------------------------------------------------------
------------------------------------------------------------------------


All of these properties were transferred as part of the Trust Assets and the income for the period after the closing date of this acquisition is included in these financial statements.

4. ASSET RETIREMENT OBLIGATIONS

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of the Trust's oil and gas properties.



------------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, 2005 December 31, 2004
------------------------------------------------------------------------
Asset retirement obligations,
beginning of period 63,674 28,993
Liabilities incurred 1,721 30,260
Liabilities settled (691) -
Accretion expense 4,127 4,421
------------------------------------------------------------------------
Asset retirement obligations,
end of period 68,831 63,674
------------------------------------------------------------------------
------------------------------------------------------------------------


The undiscounted asset retirement obligation at September 30, 2005 is estimated to be $104.2 million (December 31, 2004 - $82.2 million). The Trust's credit-adjusted risk-free rate is 7.875% (2004 - 7.875%). These obligations will be settled based on the useful life of the underlying assets, the majority of which are not expected to be paid for several years, or decades, in the future and will be funded from the general resources of the Trust at the time of removal.

5. LONG-TERM DEBT

On April 1, 2005, the Trust entered into a credit agreement with a syndicate of Canadian chartered banks. Under the terms of the credit agreement, the Trust has a $235 million committed revolving and term facility and a $25 million working capital facility. Borrowing under the facility bears interest at the lenders' prime rate, Bankers' Acceptance rate or LIBOR, plus an applicable margin dependent on certain conditions. The revolving nature of the Trust's credit facility is scheduled to expire on March 31, 2006. If the revolving term of any portion of the credit facility is not extended, that portion of the credit facility will have a term maturity date of one year from expiration.

Advances drawn on the Trust's facility are secured by a fixed and floating charge over the assets of the Trust. As at September 30, 2005, $225.4 million of the credit facilities has been drawn down. The effective interest rate under this facility for the three months ended September 30, 2005 was 3.49%.

The Trust's lenders are currently finalizing a scheduled semi-annual review of its borrowing base and have indicated that the Trust's credit facility will be increased to no less than $300 million, with an effective date of October 31, 2005.

The Trust has letters of credit totaling $5.7 million as at September 30, 2005 outstanding with a Canadian chartered bank. These letters of credit reduce the amount available under the Trust's working capital facility.

6. UNITHOLDERS' CAPITAL

Authorized

The authorized capital of the Trust is comprised of an unlimited number of Trust Units and an unlimited number of Special Voting Rights. Compared to the holders of the Trust Units, holders of Special Voting Rights are not entitled to any distributions of any nature from the Trust nor have any beneficial interest in any property or assets of the Trust on termination or winding-up of the Trust.

Issued and Outstanding

No Special Voting Rights have been issued to date. The following is a summary of the changes in the Trust's unitholders' capital for the nine months ended September 30, 2005:



------------------------------------------------------------------------
Trust Units Number of Units Amount
------------------------------------------------------------------------
Balance at December 31, 2004 - -
Initial Trust Unit issued upon
settlement on February 25, 2005 1 1
Re-purchase of initial Trust Unit (1) (1)
Trust Units issued to Paramount
shareholders in exchange for the
Trust Assets 79,133,395 617,857
Cash paid for the transfer of the
Trust Assets - (190,000)
Purchase price of the general partnership
(1%) interest in Trilogy Energy LP - (15,211)
Estimated Trust organization costs - (4,000)
------------------------------------------------------------------------
Balance at September 30, 2005 79,133,395 408,646
------------------------------------------------------------------------
------------------------------------------------------------------------


Per Trust Unit Information

Earnings (loss) per Trust Unit for all periods presented were calculated using the weighted average number of Trust Units (79,133,395 Trust Units) outstanding for the three months ended September 30, 2005.

7. DISTRIBUTIONS

The Trust made the following cash distributions to unitholders from April 2005 to September 2005:



------------------------------------------------------------------------
Distribution Distribution per
Production Period Record Date Date Trust Unit
------------------------------------------------------------------------
April 2005 May 2, 2005 May 16, 2005 $0.16
May 2005 May 31, 2005 June 15, 2005 $0.16
June 2005 June 30, 2005 July 15, 2005 $0.16
July 2005 August 2, 2005 August 15, 2005 $0.16
August 2005 August 31, 2005 September 15, 2005 $0.16
September 2005 September 30, 2005 October 17, 2005 $0.25
------------------------------------------------------------------------
------------------------------------------------------------------------


On October 21, 2005, the Trust announced that its cash distribution for October 2005 will be $0.25 per Trust Unit. The distribution is payable on November 15, 2005 to unitholders of record on October 31, 2005.

8. UNIT BASED COMPENSATION

Unit Appreciation Plan

On April 1, 2005, the Trust offered certain employees, officers and directors a unit appreciation arrangement whereby such employees, officers and directors were granted appreciation units entitling the appreciation unitholders to receive cash payments calculated as the excess of the market price over the exercise price per appreciation unit on the exercise date. The exercise price per appreciation unit would be reduced by the aggregate unit distributions paid or payable on the Trust Units to unitholders of record from the grant date to the exercise date.

As at September 30, 2005, a total of 1,322,000 appreciation units have been granted to certain employees, officers and directors with an exercise price of $10.11 per appreciation unit (before unit distributions adjustment), of which 246,000 appreciation units will vest on October 19, 2005. No additional appreciation units will vest before December 31, 2005. The appreciation units will be vested at subsequent anniversary dates with a termination date of December 15, 2008. No appreciation units have been exercised, vested or cancelled for the period ended September 30, 2005.

A compensation expense amounting to $5.5 million relating to the unit appreciation plan has been recognized and presented as part of general and administrative expenses for the three months ended September 30, 2005. The amount of the accrued unit-based compensation liability as at September 30, 2005 was $7.1 million.

Proposed Unit Option and Bonus Plan

Subject to approval by the unitholders and appropriate regulatory authorities, the Trust is contemplating implementing a long-term incentive plan that will award unit options to, and set-up a market-based bonus plan for, eligible directors, officers, employees and consultants. No compensation expense or liabilities have been recognized by the Trust under these proposed unit option and bonus plan.

9. FINANCIAL INSTRUMENTS

Financial Sales Contracts

The Trust utilizes, from time to time, forward commodity price contracts that require financial settlements between counterparties. At September 30, 2005, the Trust has entered into financial forward sales arrangements as follows:



------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
AECO Fixed Price 10,000 GJ/d $ 7.06 April 2005 - October 2005
AECO Fixed Price 10,000 GJ/d $ 7.10 April 2005 - October 2005
AECO Fixed Price 20,000 GJ/d $ 7.10 April 2005 - October 2005
AECO Fixed Price 10,000 GJ/d $ 8.73 November 2005 - March 2006
AECO Fixed Price 10,000 GJ/d $ 8.71 November 2005 - March 2006
AECO Fixed Price 20,000 GJ/d $ 8.09 November 2005 - March 2006
NYMEX-WTI Fixed
Price 1,000 Bb l/d $ 57.70 May 2005 - December 2005
NYMEX-WTI Fixed
Price 1,000 Bb l/d $ 53.43 October 2005 - March 2006
------------------------------------------------------------------------
------------------------------------------------------------------------


The Trust elected not to designate the above financial instruments as hedges and therefore has recognized the fair value of these financial instruments on the balance sheet. The estimated fair values of these financial instruments are based on quoted prices or, in their absence, third-party market indications and forecasts. The fair values of forward financial contracts recognized as at the balance sheet dates are as follows:



---------------------------------------------------------------------
September 30, December 31,
2005 2004
---------------------------------------------------------------------
Financial instrument asset - 12,413
Financial instrument liability (39,649) (1,260)
---------------------------------------------------------------------
Net financial instrument asset
(liability) (39,649) 11,153
---------------------------------------------------------------------
---------------------------------------------------------------------


The changes in the fair value associated with the above financial instruments are recorded as unrealized gain or loss on financial instruments in the statement of earnings. Gains or losses arising from monthly settlement with counterparties are recognized as realized gain or loss in the statement of earnings. The following table presents a breakdown of unrealized and realized gains and losses on financial instruments:



------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
2005 2004 2005 2004
------------------------------------------------------------------------

Realized loss on financial
instruments (4,904) (1,209) (6,237) (3,072)
Unrealized gain (loss) on
financial instruments (29,019) 3,642 (50,802) (2,443)
------------------------------------------------------------------------
Total gain (loss) on
financial instruments (33,923) 2,433 (57,039) (5,515)
------------------------------------------------------------------------
------------------------------------------------------------------------


Subsequent to September 30, 2005, the Trust has entered into the following financial arrangements:



------------------------------------------------------------------------
Quantity Floor Ceiling Term
------------------------------------------------------------------------
AECO Costless January 2006 -
Collar 10,000 GJ/d $12.00/GJ $17.65/ GJ March 2006
AECO Costless April 2006 -
Collar 20,000 GJ/d $9.00/GJ $12.50/ GJ October 2006
------------------------------------------------------------------------
------------------------------------------------------------------------


Credit and Interest Rate Risks

Under a service agreement described in note 10, Paramount carries out marketing functions on behalf of the Trust. The Trust is exposed to credit risk from financial instruments to the extent of non-performance by third parties. Credit risks associated with possible non-performance by financial instrument counterparties are minimized by entering into contracts with only highly rated counterparties and controls third party credit risk with credit approvals, limits on exposures to any one counterparty, and monitoring procedures. Production is sold to a variety of purchasers under normal industry sale and payment terms. The Trust's accounts receivable are with customers and joint venture partners in the petroleum and natural gas industry and are subject to normal credit risk.

The Trust is also exposed to fluctuations in interest rates relative to its banks' credit facilities as disclosed in note 5.

10. RELATED PARTY TRANSACTIONS

Paramount is a unitholder of the Trust. On April 1, 2005, Paramount Resources, a wholly-owned subsidiary of Paramount, entered into a service agreement with the Trust's subsidiary and administrator (Trilogy Energy Ltd.) whereby Paramount Resources will provide administrative and operating services to the Trust and its subsidiaries to assist Trilogy Energy Ltd. in carrying out its duties and obligations as general partner of Trilogy Energy LP and as the administrator of the Trust and Trilogy Holding Trust. Under this agreement, Paramount Resources shall be reimbursed at cost for all expenses it incurs in providing the services to the Trust and its subsidiaries. The agreement is in effect until March 31, 2006 but may be terminated by either party with at least six months written notice. The amount of expenses billed by Paramount Resources as management fees under this agreement was $1.4 million for the three months ended September 30, 2005. This amount is included as part of general and administrative expenses in the Trust's consolidated statements of income.

Trilogy Energy LP and Paramount have entered into a Call on Production Agreement on March 29, 2005 whereby Paramount has the right to purchase all or any portion of Trilogy Energy LP's available gas production at a price no less favorable than the price Paramount will receive on the resale of the natural gas to a gas marketing limited partnership. The term of the Call on Production Agreement is no longer than five years. Trilogy Energy LP sold 2,588,000 GJs of natural gas to Paramount for approximately $19.8 million for the three months ended September 30, 2005 under this agreement.

The Trust and Paramount also had non-interest bearing cash advances from/to each other arising from normal business activities.

The net amount due from Paramount arising from the above related party transactions as at September 30, 2005 was $15.2 million, including an accrued receivable of $7.1 million arising from the delivery of gas in the month of September 2005 under the above-mentioned Call on Production Agreement, and a Crown royalty deposit claim of $7.7 million which when refunded to Paramount will be collected by the Trust.

In addition to the letters of credit issued by the Trust as discussed in note 5, Paramount on behalf of the Trust, has issued letters of credit totaling $3.8 million as at September 30, 2005. The Trust has not recorded a liability as at September 30, 2005 with respect to such letters of credit which are scheduled to expire in November 2005.

11. INCOME TAXES

No provision for income taxes has been made by the Trust since the transfer of the Trust Assets to the Trust on April 1, 2005. The income taxes prior to April 1, 2005 were calculated on a carve-out basis from Paramount.



Trilogy Energy Trust
Supplemental Oil and Gas Operating Statistics (Unaudited)
For the Period Ended September 30, 2005


Sales Volumes 2005 2004
------------------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3
------------------------------------------------------------------------
Gas (MMcf/d) 116 117 122 119 104
Oil and Natural Gas
Liquids (Bbl/d) 5,154 4,780 4,950 5,672 5,195
------------------------------------------------------------------------
Total Sales Volumes
(Boe/d) (6:1) 24,404 24,287 25,192 25,439 22,521
------------------------------------------------------------------------
------------------------------------------------------------------------


Per-unit Results 2005 2004
------------------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3
------------------------------------------------------------------------
Produced Gas ($/Mcf)

Price, before
transportation 9.31 8.15 7.46 7.38 6.88

Transportation 0.42 0.48 0.41 0.41 0.41

Royalties 1.95 1.82 1.79 1.76 1.31

Operating expenses,
net of processing
revenue 1.41 1.34 1.19 1.30 1.18
------------------------------------------------------------------------
Cash netback before
realized financial
instruments 5.52 4.51 4.06 3.91 3.98

Realized financial
instruments (0.22) 0.03 (0.21) 0.83 (0.11)
------------------------------------------------------------------------
Cash netback including
realized financial
instruments 5.30 4.54 3.85 4.74 3.87
------------------------------------------------------------------------
------------------------------------------------------------------------

Produced Oil & Natural
Gas Liquids ($/Bbl)

Price, before
transportation 67.72 57.84 54.76 49.85 53.64

Transportation 0.79 0.86 0.84 0.71 0.76

Royalties 17.18 14.11 12.78 7.55 9.48
Operating expenses,
net of processing
revenue 8.48 4.64 7.11 10.57 7.08
------------------------------------------------------------------------
Cash netback before
realized financial
instruments 41.27 38.23 34.03 31.02 36.32

Realized financial
instruments (5.34) 1.41 0.02 (2.62) (0.36)
------------------------------------------------------------------------
Cash netback including
realized financial
instruments 35.93 39.64 34.05 28.40 35.96
------------------------------------------------------------------------
------------------------------------------------------------------------

Total Produced ($/Boe)

Price, before
transportation 58.08 50.82 46.73 45.54 44.15

Transportation 2.17 2.47 2.12 2.10 2.07

Royalties 12.84 11.53 11.13 9.89 8.22
Operating expenses,
net of processing
revenue 8.48 7.35 7.12 8.42 7.08
------------------------------------------------------------------------
Cash netback before
realized financial
instruments 34.59 29.47 26.36 25.13 26.78

Realized financial
instruments (2.18) 0.43 (1.01) 3.31 (0.58)
------------------------------------------------------------------------
Cash netback including
realized financial
instruments 32.41 29.90 25.35 28.44 26.20
------------------------------------------------------------------------
------------------------------------------------------------------------


Note: The above information includes the results of properties acquired
in 2004 that became part of the Trust Assets, for the periods
after the closing of the acquisitions.


ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

This news release contains forward-looking statements within the meaning of applicable securities laws. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance and other statements that are not statements of fact. The forward-looking statements in this news release include statements with respect to future production, capital expenditures, drilling, operating costs, cash flow, and the magnitude of oil and natural gas reserves. Although Trilogy believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on them because Trilogy can give no assurance that such expectations will prove to have been correct. Factors that could cause actual results to differ materially from those set forward in the forward looking statements include general economic business and market conditions, fluctuations in interest rates, production estimates, our future costs, future crude oil and natural gas prices, reserve estimates and other risks associated with oil and gas operations. There is no guarantee by the Trust that actual results achieved will be the same as those forecast herein. Readers are cautioned that the foregoing list of important factors is not exhaustive. The Trust undertakes no obligation to update its forward-looking statements except as required by law. The Trust's forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Contact Information

  • Trilogy Energy Trust
    J.H.T. (Jim) Riddell
    President and Chief Executive Officer
    (403) 290-2900
    or
    Trilogy Energy Trust
    B.K. (Bernie) Lee
    Chief Financial Officer
    (403) 290-2900
    or
    Trilogy Energy Trust
    J. B. (John) Williams
    Chief Operating Officer
    (403) 290-2900
    or
    Trilogy Energy Trust
    4100 - 350 - 7th Avenue S. W.
    Calgary, Alberta T2P 3N9
    (403) 290-2900
    (403) 263-8915 (FAX)
    Website: www.trilogyenergy.com