Trilogy Energy Trust
TSX : TET.UN

Trilogy Energy Trust

August 03, 2005 02:36 ET

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

CALGARY, ALBERTA--(CCNMatthews - Aug. 3, 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 June 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 Six Months Ended
June 30 June 30
% %
2005 2004(1) Change 2005(1) 2004(1) Change
------------------------------------------------------------------------

FINANCIAL
Petroleum and natural
gas sales 111,929 71,148 57% 217,897 133,614 63%
Funds flow(2)
From operations 60,488 36,814 64% 104,496 72,721 44%
Per unit - basic(3) 0.76 0.47 64% 1.32 0.92 44%
- diluted(3) 0.76 0.47 64% 1.32 0.92 44%
Earnings
Earnings before certain
non-recurring allocated
items 17,370 9,959 74% 9,948 17,510 -43%
Net earnings (loss) 17,370 6,002 189% (4,490) 13,980 -132%
Per unit - basic(3) 0.22 0.08 189% (0.06) 0.18 -132%
- diluted(3) 0.22 0.08 189% (0.06) 0.18 -132%
Capital expenditures
Exploration and
development 15,426 22,655 -32% 69,067 52,842 31%
Acquisitions,
dispositions and
other 724 90,414 -99% 1,192 90,870 -99%
Net capital
expenditures 16,150 113,069 -86% 70,259 143,712 -51%
Total assets(4) 759,798 778,147 -2% - - -
Net debt(4) and (5) 246,092 10,249 2301% - - -
Unitholders'
equity(4) 388,032 532,430 -27% - - -
Trust Units
outstanding
(thousands)
- As at June 30, 2005 79,133 - - - - -
- As at August 1, 2005 79,133 - - - - -

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

OPERATING
Production
Natural gas (MMcf/d) 117 90 30% 119 85 40%
Crude oil and
liquids (Bbl/d) 4,780 2,323 106% 4,865 2,296 112%
Total production
(Boe/d) @ 6:1 24,287 17,250 41% 24,737 16,477 50%
------------------------------------------------------------------------

Average prices
Natural gas
(pre-financial
instruments) ($/Mcf) 8.15 7.52 8% 7.80 7.40 5%
Natural gas ($/Mcf)(6) 8.18 7.10 15% 7.70 7.35 5%
Crude oil and liquids
(pre-financial
instruments) ($/Bbl) 57.84 46.60 24% 56.29 45.52 24%
Crude oil and liquids
($/Bbl)(6) 59.25 44.19 34% 57.29 42.86 34%
------------------------------------------------------------------------

Drilling activity
(gross)
Gas 4 8 -50% 31 35 -11%
Oil 1 1 0% 4 2 100%
D&A 0 0 - 3 1 200%
Total wells 5 9 -44% 38 38 0%
Success rate 100% 100% 0% 92% 97% -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 the period prior to April 1, 2005 were
calculated using the weighted average number of units outstanding
for the three months ended June 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.


Review of Operations

Trilogy Energy Trust ("Trilogy" or "the Trust") was successfully spun out from Paramount Resources Ltd. ("Paramount") into a fully operational energy trust effective April 1, 2005 and as such this is the Trust's first complete quarter of public reporting. The process of transferring the assets into Trilogy was very efficient with daily activities seamlessly transitioning so that no operations or opportunities were missed.

Trilogy is defined by the assets it holds which are somewhat unique in that they provide a significant defined opportunity base within them. The Trust believes it has sufficient opportunities to replace production and reserves for a number of years. Trilogy's opportunity base is very predictable with low risk and is highly efficient from a rate of return standpoint. Trilogy is executing a capital expenditure program targeted to replace the reserves produced, maintain the current production rates and distributing the remaining cash flow to unitholders. In the second quarter of 2005, the Trust distributed and/or declared approximately 63 percent of cash flow to unitholders, reinvested approximately 27 percent with the remaining 10 percent of cash flow applied to the balance sheet resulting in the reduction of net debt by approximately $6 million. With appropriate financial management, the Trust intends to operate in a manner where all facets of the business are sustainable including maintaining a strong balance sheet, for the forecast period.

A majority of the assets that form the framework for the Trust are operated producing properties with relatively high working interests that are geographically concentrated in two areas of central Alberta. These areas contain a large number of lower-risk, development drilling opportunities, the Trust has continued its Gething downspacing program in the Kaybob area and we are looking at new tight gas reservoirs that can be developed in the same manner. There also exists a large resource potential that will be exploited in the future and we are continually identifying and evaluating strategic acquisitions that fit into Trilogy's expertise in core producing areas.

Production of the Trust grew 40.8 percent, from 17,250 Boe/d (89.6 MMcf/d of natural gas and 2,323 Bbl/d of oil and natural gas liquids) in the second quarter of 2004, to 24,287 Boe/d (117.0 MMcf/d and 4,780 Bbl/d of oil and natural gas liquids) in the second quarter of 2005. Approximately 7,000 Boe/d came from two acquisitions that were included in the Trust spinout, 2,000 Boe/d from the Marten Creek area and 5,000 Boe/d from the Kaybob area. The Trust was successful in replacing production declines in these assets as well as in the base producing assets that were transferred from Paramount.

Second quarter 2005 average production was down 3.5 percent from the first quarter 2005 average production of 25,192 Boe/d. Production shortfalls were the result of the early spring break up that prevented the completion of some major construction projects and the non-operated gas plants maintenance delays in the Kaybob area. There were also unexpected delays on the expansion of the gas plant in the winter-access Marten Creek area. As a result of these delays, pre-breakup production forecasts that included 6 MMcf/d of natural gas did not materialize. Some projects currently under construction will provide significant production additions for the third quarter while the remaining projects will be completed next winter. Production for the remainder of the year is expected to be above the targeted production level of 25,000 Boe/d that was forecasted for 2005. Current production levels are approximately 25,233 Boe/d, comprised of 122 MMcf/d of natural gas and 4,900 Bbl/d of oil and natural gas liquids.

Trilogy operates approximately 70 percent of its production and mandates the operatorship of its production when possible in order to have control over variables that may impact revenues and cash flow. We are then able to prioritize and focus our expertise diligently on any impediments to production that may arise. As a result of this diligence, overall properties that were operated by the Trust performed as well or better than expected for the second quarter. The non-operated properties that produce through third-party production facilities proved to be more challenging. Maintenance on non-operated plants impaired production for six weeks in the second quarter, resulting in a decrease in the average daily volumes from the previous quarter. The Trust will continue to focus its effort on maximizing the amount of production that flows through operated gas plants and oil batteries, in order to keep potential production losses and down time on Trilogy's producing wells to a minimum.

The 2005 capital spending program for the Trilogy properties is $100 million. This is the level of capital reinvestment required to replace production declines and produced reserves. Second quarter 2005 capital spending including land and adjustments was $16.1 million, and capital spending for the remainder of 2005 will be approximately $50 million. The first quarter capital expenditures incurred prior to the Trust spinout have been reported by Paramount Resources. Cost of finding and development reported by Paramount in the past for the Trust assets were among the lowest in the industry. It is expected that with the proven expertise of Trilogy staff and the well-designed development strategy of the Trust's properties, the go-forward cost of finding and development should continue to be in the top quartile for the industry. We will carry on with our aggressive drilling program with at least two active drilling rigs for the remainder of the year.

We were able to commence our summer drilling program by the middle of May and operations are proceeding smoothly considering the delays brought about with the wet summer that central Alberta has been experiencing. Trilogy participated in 5 (3.6 net) wells in the second quarter compared to 9 (5.0 net) wells as per the same period last year. Of the five wells drilled by the Trust, 4 (2.6 net) wells were cased for gas production and 1 (1.0 net) well was cased for oil production. In addition to an active drilling program there are four service rigs completing new wells and working over existing shut-in and suspended wells. The workover and remediation program on the Beaverhill Lake Unit 3 wells has been encouraging, and may warrant an additional service rig to complete the work sooner.

Trilogy and Paramount have drilled 38 (32.0 net) wells to date on the Trust properties as compared to 38 (28.9 net) wells for the same period last year. Trilogy has plans to drill up to an additional 61 (45.8 net) wells prior to the end of the year. There were 3 (1.5 net) dry and abandoned wells in the 38 well program in the first half of the year, resulting in a drilling and casing success rate of 92 percent. We expect similar drilling and completion results as we pursue a drilling program that focuses on the tight gas resource play in the Kaybob area as well as drilling prospects that offer multi-zone development potential.

We have a substantial inventory of development opportunities that exist on the large, as yet, undeveloped resource base which we control in the central Alberta area that will continue to fuel future growth and add tremendous value for Trilogy unitholders. Successful production replacement, prudent asset management, continued control of operations and strong commodity prices will support a stable distribution. 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 six months ended June 30, 2005, and should be read in conjunction with the Trust's consolidated financial statements and related notes for the three and six months then ended. The consolidated financial statements have been prepared in Canadian dollars in accordance with Canadian generally accepted accounting principles ("GAAP").

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.

This MD&A was prepared using currently available information as of August 2, 2005.

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. The transfer of the Trust Assets did not result in a substantial change in ownership of the Trust Assets by Paramount on the effective date of the Plan of Arrangement and therefore the transaction was accounted for at the carrying value of the assets transferred. The carrying values of the assets and related liabilities transferred to the Trust on April 1, 2005 were as follows:



------------------------------------------------------------------------
(thousand dollars)
------------------------------------------------------------------------
Property, plant and equipment - net of
accumulated depletion and depreciation 699,207
Asset retirement obligations (65,076)
Goodwill 19,400
Net working capital accounts (35,674)
------------------------------------------------------------------------
Net carrying value 617,857
------------------------------------------------------------------------
------------------------------------------------------------------------


The net carrying value of the assets and related liabilities accounts were credited to unitholders' capital account on April 1, 2005. In addition to the issuance of Trust Units described above, the Trust paid Paramount on April 1, 2005 an amount of $190 million in cash plus $30 million as an initial settlement of outstanding working capital distribution amounts in accordance with the Plan of Arrangement. The $190 million transfer consideration was charged against unitholders' capital account. (Please see Liquidity and Capital Resources section below.)

Trilogy, through a wholly-owned holding trust (Trilogy Holding Trust), indirectly 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 Ended Six Months Ended
June 30 June 30
2005 2004 2005 2004
------------------------------------------------------------------------
Natural gas (Mcf/d) 117,042 89,562 119,235 85,083
Oil and natural gas liquids (Boe/d) 4,780 2,323 4,865 2,296
------------------------------------------------------------------------
Total (Boe/d) 24,287 17,250 24,737 16,477
------------------------------------------------------------------------
------------------------------------------------------------------------


Total production increased from 17,250 Boe/d for the second quarter of 2004 to 24,287 Boe/d for the same quarter in 2005 due mainly to the acquisitions of properties described above. These acquisitions also caused total production to increase from 16,477 Boe/d for the six months ended June 30, 2004 to 24,737 Boe/d for the same period in 2005.



Commodity Prices
------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2005 2004 2005 2004
------------------------------------------------------------------------
Natural gas prices ($/Mcf)
Before realized gain (loss) on
financial instruments 8.15 7.52 7.80 7.40
Realized gain (loss) on
financial instruments 0.03 (0.42) (0.10) (0.05)
------------------------------------------------------------------------
After realized gain (loss) on
financial instruments 8.18 7.10 7.70 7.35
------------------------------------------------------------------------

Oil and natural gas liquids
prices ($/Boe)
Before realized gain (loss) on
financial instruments 57.84 46.60 56.29 45.52
Realized gain (loss) on
financial instruments 1.41 (2.41) 1.00 (2.66)
------------------------------------------------------------------------
After realized gain (loss) on
financial instruments 59.25 44.19 57.29 42.86
------------------------------------------------------------------------
------------------------------------------------------------------------


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


Revenue
------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
(thousand dollars) 2005 2004 2005 2004
------------------------------------------------------------------------
Natural gas sales 86,770 61,299 168,339 114,590
Oil and natural gas liquid sales 25,159 9,849 49,558 19,024
Realized gain (loss) on
financial instruments(1) 953 (3,941) (1,333) (1,863)
Unrealized loss on
financial instruments(1) (6,848) (420) (21,783) (6,085)
Other income 396 - 396 -
------------------------------------------------------------------------
106,430 66,787 195,177 125,666
------------------------------------------------------------------------
------------------------------------------------------------------------
(1)See the Financial Instruments section of this MD&A.


Total revenue increased during the second quarter of 2005 and six months ended June 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 June 30, 2005, the increase in natural gas production volume resulted in a $20.4 million increase in petroleum and natural gas sales, while the increase in oil and natural gas liquids production volume contributed a $12.9 million increase in petroleum natural gas sales compared to the same period in 2004. Higher natural gas prices in the second quarter of 2005 contributed an increase of $5.1 million in petroleum and natural gas sales, while higher oil and natural gas liquids contributed an increase of $2.4 million in petroleum and natural gas sales compared to the second quarter of the previous year.

For the six months ended June 30, 2005, petroleum and natural gas sales increased by $47.6 million as a result of higher natural gas production volumes, and $26.0 million as a result of higher oil and natural gas liquids production volume compared to the same period in 2004. Increases in petroleum and natural gas revenue of $6.2 million and $4.5 million for the six months ended June 30, 2005 compared to the same period in 2004 were due to higher natural gas and oil and natural gas liquids prices, respectively.



Royalties
------------------------------------------------------------------------
Three Months Ended Six Months Ended
(thousand dollars except June 30 June 30
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------
Royalties, net of ARTC 25,502 14,304 50,771 27,101
Percentage of petroleum and natural
gas sales 23% 20% 23% 20%
------------------------------------------------------------------------


Royalties, net of ARTC, increased 78 percent from $14.3 million for the second quarter of 2004 to $25.5 million for the same quarter in the current year, and 87 percent from $27.1 million for the six months ended June 30, 2004 to $50.8 million for the same six-month period in 2005, due mainly to higher petroleum and natural gas sales as discussed above.

As a percentage of petroleum and natural gas sales, royalties averaged 23 percent for 2005 compared to 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 Ended Six Months Ended
(thousand dollars except June 30 June 30
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------
Operating costs 16,242 9,301 32,365 16,281
Operating costs per Boe ($/Boe) 7.35 5.93 7.23 5.43

Transportation costs 5,470 4,372 10,275 8,582
Transportation costs per Boe ($/Boe) 2.47 2.79 2.29 2.86
------------------------------------------------------------------------


Total operating costs for the three months ended June 30, 2005 were 75 percent higher at $16.2 million compared to $9.3 million for the three months ended June 30, 2004. Total operating costs for the six months ended June 30, 2005 also increased 99 percent to $32.4 million compared to $16.3 million for the six months ended June 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 per Boe increased in both periods in 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 Ended Six Months Ended
June 30 June 30
($ per Boe) 2005 2004 2005 2004
------------------------------------------------------------------------

Gross revenue before financial
instruments (1) 48.35 42.54 46.46 41.69
Royalties (11.54) (9.11) (11.34) (9.04)
Operating costs (7.35) (5.93) (7.23) (5.43)
Asset retirement obligation
expenditures (0.03) - (0.13) -
------------------------------------------------------------------------
Operating netback 29.43 27.50 27.76 27.22
General and administrative
expenses (2) (1.38) (1.72) (1.81) (1.87)
Interest expense (1.05) (0.95) (1.08) (0.89)
Lease rentals (0.06) (0.13) (0.09) (0.13)
Realized gain (loss) on
financial instruments 0.43 (2.51) (0.30) (0.62)
------------------------------------------------------------------------
Funds flow netback before certain
non-recurring allocated items 27.37 22.19 24.48 23.71
Realized foreign exchange loss - - (1.05) -
Bad debt recovery - 1.79 - 0.94
Large Corporation Tax and other - (0.53) (0.09) (0.39)
------------------------------------------------------------------------
Funds flow netback 27.37 23.45 23.34 24.26
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Net of transportation costs
(2) Excluding non-cash general and administrative expenses


General and Administrative and Unit-based Compensation Expenses

------------------------------------------------------------------------
Three Months Ended Six Months Ended
(thousand dollars except June 30 June 30
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------

General and administrative
expenses 3,061 3,040 10,718 6,281
General and administrative
expenses per Boe ($/Boe) 1.38 1.94 2.39 2.09

Unit-based compensation 1,604 - - -
Unit-based compensation per Boe
($/Boe) 0.73 - - -
------------------------------------------------------------------------
------------------------------------------------------------------------


General and administrative expenses are higher in the six months ended June 30, 2005 compared to the corresponding period in 2004 due mainly to increases in office and administration personnel relative to the increase in its size resulting from the major asset acquisitions described above. The increase in personnel was also necessary to ensure compliance with new corporate and reporting obligations. 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. Costs billed by Paramount under this agreement are included in general and administrative expenses.

Interest Expense

Interest expense was 55 percent higher from $1.5 million for the three months ended June 30, 2004 to $2.3 million for the similar three-month period of 2005 due mainly to higher average debt balances during the current period. Prior to April 1, 2005, interest was recognized in the consolidated statements of earnings based on a deemed debt balance attributable to the Trust Assets. The higher debt balance resulting from the acquisitions during the second half of 2004 as discussed above is also the main reason why interest expense increased by 80 percent to $4.8 million for the six months ended June 30, 2005 compared to $2.7 million for the same period in 2004.



Depletion and Depreciation

------------------------------------------------------------------------
Three Months Ended Six Months Ended
(thousand dollars except June 30 June 30
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------

Depletion and depreciation
expense 31,770 21,933 67,469 42,334
Depletion and depreciation
expense per Boe ($/Boe) 14.37 13.97 15.07 14.12
------------------------------------------------------------------------
------------------------------------------------------------------------


Total depletion and depreciation expense increased significantly by 45 percent and 59 percent, respectively, during the three and six months ended June 30, 2005 compared to the same periods in 2004 due mainly to higher production volumes and a higher depletion and depreciation base as a result of the property acquisitions described above. On a per unit basis, depletion and depreciation expense per Boe is up to $14.37/Boe and $15.07/Boe, respectively, for the three and six months ended June 30, 2005 from $13.97/Boe and $14.12/Boe, respectively, for the comparable periods in 2004, as the depletion and depreciation rates are higher for the properties acquired during the second half of 2004. Expired mineral leases included in depletion and depreciation expense for the three and six months ended June 30, 2005 amounted to $1.4 million and $4.0 million, respectively (2004 - $1.0 million and $1.3 million, respectively).

Capital costs associated with undeveloped land and exploratory, non-producing petroleum and natural gas properties of $66.6 million are excluded from costs subject to depletion at June 30, 2005 (December 31, 2004 - $55.2 million).

Dry Hole Costs

$1.7 million and $4.3 million of dry hole costs were expensed, respectively, for the three and six months ended June 30, 2005 (2004 - nil and $0.9 million, respectively). The dry hole costs for the three months ended June 30, 2005 represent drilling wells that were in progress as at March 31, 2005 and were subsequently evaluated unsuccessful.

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 June 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 $ 53.26 April 2005 - September 2005
NYMEX-WTI Fixed Price 1,000 Bbl/d $ 55.25 April 2005 - September 2005
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 to 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 Ended Six Months Ended
June 30 June 30
(thousand dollars) 2005 2004 2005 2004
------------------------------------------------------------------------

Realized gain (loss) on
financial instruments 953 (3,941) (1,333) (1,863)
Unrealized loss on
financial instruments (6,848) (420) (21,783) (6,085)
------------------------------------------------------------------------
Total loss on
financial instruments (5,895) (4,361) (23,116) (7,948)
------------------------------------------------------------------------
------------------------------------------------------------------------


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.

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 Ended June 30 Six Months Ended June 30
(no. of
wells) 2005 2004 2005 2004
------------------------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)

Natural
gas 4.0 2.6 8.0 4.0 31.0 27.5 35.0 26.7
Oil 1.0 1.0 1.0 1.0 4.0 3.0 2.0 2.0
Dry 0.0 0.0 0.0 0.0 3.0 1.5 1.0 0.2
------------------------------------------------------------------------
Total 5.0 3.6 9.0 5.0 38.0 32.0 38.0 28.9
------------------------------------------------------------------------
------------------------------------------------------------------------
(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 5.0 gross wells (3.6 net) during the three months ended June 30, 2005 compared to 9.0 gross wells (5.0 net) for the comparable three-month period in 2004. On a year-to-date basis, the Trust participated in the drilling of 38.0 gross wells (32.0 net) during the six months ended June 30, 2005 compared to 38.0 gross wells (28.9 net) for the same period in 2004.



Capital Spending
------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
(thousand dollars) 2005 2004 2005 2004
------------------------------------------------------------------------

Land 2,463 4,308 5,104 5,423
Geological and geophysical costs 114 442 1,323 1,337
Drilling 9,160 10,730 44,166 29,668
Production equipment and facilities 3,689 7,175 18,474 16,414
------------------------------------------------------------------------
Exploration and development
expenditures 15,426 22,655 69,067 52,842
Proceeds received on property
dispositions (87) (100) (172) (100)
Property acquisitions - 90,195 - 90,195
Other 811 319 1,364 775
------------------------------------------------------------------------
Net capital expenditures 16,150 113,069 70,259 143,712
------------------------------------------------------------------------
------------------------------------------------------------------------


Exploration and development expenditures for the three months ended June 30, 2005 were $7.3 million lower at $15.4 million compared to $22.7 million for the same period in 2004 due mainly to the early season break-up in 2005. On a year-to-date basis, exploration and development expenditures in 2005 were $16.2 million higher at $69.1 million compared to $52.8 million in 2004 due primarily to a higher level of development activities in the first quarter of 2005 resulting from the property acquisitions described above.



LIQUIDITY AND CAPITAL RESOURCES

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

Current assets 58,390 78,102
Current liabilities (75,105) (88,351)
------------------------------------------------------------------------
Net working capital deficiency (16,715) (10,249)
------------------------------------------------------------------------
------------------------------------------------------------------------


The increase in working capital deficiency from $10.2 million as at December 31, 2004 to $16.7 million as at June 30, 2005 is due mainly to the existence of a net financial instruments liability of $10.6 million at June 30, 2005 compared to a net financial instruments asset of $11.2 million at December 31, 2004, partially offset by a positive impact of operating activities on working capital for the six months ended June 30, 2005. Financial instruments assets and liabilities are recognized on the fair value of forward financial sales contracts as discussed above.

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 June 30, 2005, $229.4 million of the credit facility has been drawn down. The effective interest rate under this facility for the three months ended June 30, 2005 was 3.42 percent.

The Trust has letters of credit totaling $5.4 million as at June 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

An analysis of the transactions impacting unitholders' capital from the formation date of the Trust to June 30, 2005 is as follows:



------------------------------------------------------------------------
Trust Units Outstanding Number of Units Amount
------------------------------------------------------------------------
(thousand
dollars)
Balance at December 31, 2004 - -
Initial trust unit issued upon settlement
on February 25, 2005 1 1
Transactions related to the Plan of Arrangement:
Re-purchase of initial Trust Unit (1) (1)
Trust Units issued to Paramount shareholders
for the transfer of the Trust Assets 79,133,395 617,857
Cash paid to Paramount for the transfer of
the Trust Assets - (190,000)
Purchase price of the general partnership
(1 percent) interest in Trilogy Energy LP - (15,211)
Estimated Trust set-up costs - (4,000)
------------------------------------------------------------------------
Balance at June 30, 2005 79,133,395 408,646
------------------------------------------------------------------------
------------------------------------------------------------------------


In addition to the issuance of Trust Units to Paramount shareholders and payment of $190 million to Paramount in exchange for the Trust Assets as described in the Formation of Trilogy section of this MD&A, the Trust also assumed a $15.0 million debt of and paid $0.2 million to, a Paramount subsidiary for the general partnership (1 percent) interest in Trilogy Energy LP. The set-up related costs, including those incurred by Paramount on behalf of the Trust, are estimated to be $4.0 million. These costs were charged against the Trust's unitholders' capital account.

As at August 1, 2005, the Trust had 79,133,395 Trust Units outstanding.



Funds Flow from Operations and Cash Distributions

------------------------------------------------------------------------
Three Months Ended Six Months Ended
(thousand dollars except June 30 June 30
where stated otherwise) 2005 2004 2005 2004
------------------------------------------------------------------------

Funds flow from operations 60,488 36,814 104,361 72,721
Distributions declared(1) 37,984 - 37,984 -
Distribution payout percentage 63% - - -
------------------------------------------------------------------------
------------------------------------------------------------------------
(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 as described in the Sensitivity Analysis section of this MD&A.

Trilogy's approach is to maximize the distribution of distributable earnings to unitholders. The amount of distribution 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.



Contractual Obligations and Commitments

The Trust has the following future commitments as at June 30, 2005:

------------------------------------------------------------------------
2005 2009
(thousand dollars) (Six Months) 2006 2007 2008 and after Total
------------------------------------------------------------------------
Pipeline
transportation
commitments 4,416 8,832 8,832 8,832 48,315 79,227
Office premises
operating lease 300 600 600 300 - 1,800
------------------------------------------------------------------------
Total 4,716 9,432 9,432 9,132 48,315 81,027
------------------------------------------------------------------------
------------------------------------------------------------------------


Some of the above commitments are covered by letters of credit issued by the Trust.

The Trust has entered into the following fixed price physical commodity sales contracts outstanding as at June 30, 2005:



------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Gas Sales Contract(1) 10,000 GJ/d $ 6.98 April 2005 - October 2005
Gas Sales Contract(1) 10,000 GJ/d $ 7.36 April 2005 - October 2005
------------------------------------------------------------------------
------------------------------------------------------------------------
(1)Physical sales contracts are not marked-to-market.


Please also see the details of the Call on Production Agreement between the Trust and a related party in the following section.

RELATED PARTY TRANSACTIONS

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 on a cost basis for all expenses it incurs and does not charge any other fees 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 $1.8 million for the three months ended June 30, 2005. This amount is included as part of the 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 would receive on the resale of the natural gas to a gas marketing limited partnership. It is expected that Paramount's resale price of the gas production would be higher than spot prices. The term of the Call on Production Agreement is no longer than five years. Trilogy Energy LP sold 2,657,264 GJs of natural gas to Paramount for $18.3 million for the three months ended June 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 balance due from Paramount arising from the above related party transactions amounted to $0.5 million as at June 30, 2005.

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 June 30, 2005. The Trust has not recorded a liability as at June 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.

The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations of multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from the estimated and recorded amounts.

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 both income and future income tax liabilities to our unitholders. Therefore it is our opinion that no cash income taxes are expected to be paid in the future, and as such, no current or future income tax liabilities have been recognized in the financial statements.

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).

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 as is paid or becomes 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.

As at June 30, 2005, the Trust paid or will pay distributions to unitholders in the amount of $38.0 million in accordance with the following schedule:



------------------------------------------------------------------------
Distribution per
Production Period Record Date Distribution 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
------------------------------------------------------------------------
------------------------------------------------------------------------


On July 21, 2005, the Trust announced that its cash distribution for July 2005 will be $0.16 per Trust Unit. The distribution is payable on August 15, 2005 to unitholders of record on August 2, 2005.

Draft legislation was released by the Department of Finance on September 16, 2004. The release proposed that a trust will not qualify as a "mutual fund trust" (within the meaning of the Income Tax Act (Canada)), to the extent more than 50 percent (by value) of outstanding trust units are owned by non-residents. To the best of our knowledge, Trilogy's foreign ownership level currently is approximated to be 21 percent. The Trust will continue to monitor the progress of the legislative changes to maintain its mutual fund trust status.

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 should be that the Trust should be a 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 should consult their tax advisors concerning their eligibility for the reduced rate of U.S. federal income tax on dividends.

ANNUAL FINANCIAL INFORMATION

As the transfer of the Trust Assets from Paramount to Trilogy did not occur until April 1, 2005, the following annual financial information was prepared on a carve-out basis from Paramount's consolidated financial statements.



------------------------------------------------------------------------
As at and for the years ended December 31
(thousand dollars) 2004 2003 2002
------------------------------------------------------------------------
Total revenue 270,325 145,718 136,175
Net earnings (loss) 25,543 6,117 (6,905)
Total assets 778,147 543,304 530,836
Net investment by Paramount 532,430 384,140 366,160
------------------------------------------------------------------------
------------------------------------------------------------------------


The increases in total revenue and net earnings from year to year are attributable mainly to higher petroleum and natural gas prices and higher production volumes resulting from major property acquisitions. These property acquisitions also caused significant increases in total assets and net investment by Paramount from December 31, 2002 to December 31, 2004.



QUARTERLY FINANCIAL INFORMATION
------------------------------------------------------------------------
(thousand dollars 2005(1) 2004(1)
except per unit 2nd 1st 4th 3rd 2nd 1st
amounts) Quarter Quarter Quarter Quarter Quarter Quarter
------------------------------------------------------------------------
Total revenue 80,928 63,478 94,891 76,869 52,483 46,082
Net earnings (loss) 17,370 (21,860) (5,478) 17,041 6,002 7,978
Earnings (loss) per
Trust Unit(2)
Basic 0.22 (0.28) (0.07) 0.22 0.08 0.10
Diluted 0.22 (0.28) (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 June 30, 2005.


Total revenue increased consistently from quarter to quarter up to the fourth quarter of 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.

Total revenue for the first quarter of 2005 declined from the fourth quarter of 2004 as a result mainly of the loss on financial instruments of $17.0 million in the first quarter of 2005 compared to a gain of 15.8 million in the fourth quarter of 2004. This change also contributed to the increase in net loss from the fourth quarter of 2004 to the first quarter of 2005. In addition, a debt exchange premium expense of $15.8 million was recorded on a carve-out basis during the first quarter of 2005.

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 US 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 US benchmark price, variations in the Canada/US 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.

SENSITIVITY ANALYSIS

The Trust's earnings and funds flow are highly sensitive to changes in commodity prices, exchange rates and other factors that are beyond the control of the Trust. Current volatility in commodity prices creates uncertainty as to the Trust's cash flow and capital expenditure budget. The Trust will therefore assess results throughout the remainder of the year and revise estimates as necessary to reflect current information. The analysis below reflects the magnitude of the sensitivities on the Trust's cash flow using the following base assumptions:



------------------------------------------------------------------------
Average Production
------------------------------------------------------------------------
Natural gas 120,000 Mcf/d
Crude oil/liquids 5,000 Bbl/d

Average Prices
------------------------------------------------------------------------
Natural gas Cdn$7.00/Mcf
Crude oil/liquids US$45.00/Bbl

Exchange rate (US$/Cdn$) $0.82
------------------------------------------------------------------------
------------------------------------------------------------------------


The estimated impact on annual cash flow of variations in production,
prices, interest and exchange rates is as follows:

------------------------------------------------------------------------
Effect on Annual Cash Flow
Sensitivity (million dollars)
------------------------------------------------------------------------
Natural gas sales volume change of 10 MMcf/d 17.56
Natural gas price change of $0.10/Mcf 3.29
Oil and natural gas liquids sales volume change of 100 Bbl/d 1.20
Oil and natural gas liquids price change of US$1.00/Bbl (WTI) 1.67
US dollar to Canadian dollar exchange rate fluctuation of $0.01 0.53
Average interest rate change of 1% 2.30
------------------------------------------------------------------------
------------------------------------------------------------------------


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 PRONOUNCEMENT

Financial Instruments, Other Comprehensive Income and Equity

The Canadian Institute of Chartered Accountants (the "CICA") is expected to adopt a new standard in 2005 that 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 proposed new standard on financial instruments as discussed above, a new standard on reporting and display of comprehensive income is also expected. 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 is expected to adopt a new standard on Equity that would require 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 are expected to be effective for Trilogy for the year ending December 31, 2006.

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.



TRILOGY ENERGY TRUST

Consolidated Balance Sheets (Unaudited)
(thousand dollars)

June 30 December 31
2005 2004
(Note 2)
------------------------------------------------------------------------
ASSETS (note 7)
Current assets
Accounts receivable $ 57,158 $ 63,851
Due from related parties (note 11) 476 -
Financial instruments (note 10) - 12,413
Prepaid expenses 756 1,838
------------------------------------------------------------------------
58,390 78,102
------------------------------------------------------------------------
Property, plant and equipment (note 5)
Property, plant and equipment, at cost 1,078,490 1,017,645
Accumulated depletion and depreciation (396,482) (337,000)
------------------------------------------------------------------------
682,008 680,645
------------------------------------------------------------------------
Goodwill 19,400 19,400
------------------------------------------------------------------------
$ 759,798 $ 778,147
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities $ 64,475 $ 87,091
Financial instruments (note 10) 10,630 1,260
------------------------------------------------------------------------
75,105 88,351
------------------------------------------------------------------------
Long-term debt (note 7) 229,377 -
Unit-based compensation liability
- net of current portion (note 9) 891 -
Asset retirement obligations (note 6) 66,393 63,674
Future income taxes (note 13) - 93,692
------------------------------------------------------------------------
296,661 157,366
------------------------------------------------------------------------

Commitments and contingencies (notes 10 and 12)

Unitholders' equity
Unitholders' capital (note 8) 408,646 -
Net investment of Paramount Resources Ltd.
(note 2) - 532,430
Accumulated earnings (deficit) (20,614) -
------------------------------------------------------------------------
388,032 532,430
------------------------------------------------------------------------
$ 759,798 $ 778,147
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


TRILOGY ENERGY TRUST

Consolidated Statements of Earnings and Accumulated Earnings (Deficit)
(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 2, 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 Six months
ended June 30 ended June 30
2005 2004 2005 2004
(Note 2) (Note 2) (Note 2)
------------------------------------------------------------------------
Revenue
Petroleum and natural
gas sales $ 111,929 $ 71,148 $ 217,897 $ 133,614
Realized gain (loss)
on financial
instruments (note 10) 953 (3,941) (1,333) (1,863)
Unrealized gain (loss)
on financial
instruments (note 10) (6,848) (420) (21,783) (6,085)
Royalties, net of ARTC (25,502) (14,304) (50,771) (27,101)
Other income 396 - 396 -
------------------------------------------------------------------------
80,928 52,483 144,406 98,565
------------------------------------------------------------------------
Expenses
Operating 16,242 9,301 32,365 16,281
Transportation costs 5,470 4,372 10,275 8,582
General and
administrative (note 11) 3,061 3,040 10,718 6,281
Unit-based compensation
(note 9) 1,604 - - -
Bad debt recovery - (2,815) - (2,815)
Lease rentals 132 201 415 396
Geological and geophysical 114 442 1,323 1,337
Dry hole costs 1,736 - 4,251 895
(Gain) loss on sale of
property, plant and
equipment (87) 1,224 (65) 1,224
Accretion on asset
retirement obligations
(note 6) 1,204 518 2,869 1,037
Depletion and
depreciation 31,770 21,933 67,469 42,334
Interest 2,312 1,493 4,838 2,688
Unrealized foreign
exchange loss (gain) - 1,280 (4,224) 1,727
Realized foreign exchange
loss - - 4,710 -
Premium on debt exchange - - 15,810 -
------------------------------------------------------------------------
63,558 40,989 150,754 79,967
------------------------------------------------------------------------
Earnings (loss) before
taxes 17,370 11,494 (6,348) 18,598
------------------------------------------------------------------------
Taxes (note 13)
Future income tax expense
(recovery) - 4,662 (2,268) 3,443
Large Corporations Tax
and other - 830 410 1,175
------------------------------------------------------------------------
- 5,492 (1,858) 4,618
------------------------------------------------------------------------
Net earnings (loss) 17,370 6,002 (4,490) 13,980

Accumulated earnings,
beginning of period - - - -
(Earnings) loss allocated
to net investment by
Paramount (note 2) - (6,002) 21,860 (13,980)
Distributions paid or
payable (37,984) - (37,984) -
------------------------------------------------------------------------
Accumulated earnings
(deficit), end of period $ (20,614) $ - $ (20,614) $ -
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings (loss) per
Trust Unit (note 3)
- basic $ 0.22 $ 0.08 $ (0.06) $ 0.18
- diluted $ 0.22 $ 0.08 $ (0.06) $ 0.18

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 2, 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 Six months
ended June 30 ended June 30
2005 2004 2005 2004
(Note 2) (Note 2) (Note 2)
------------------------------------------------------------------------
Operating activities
Net earnings (loss) $ 17,370 $ 6,002 $ (4,490) $ 13,980
Add (deduct) non-cash
items
Depletion and
depreciation 31,770 21,933 67,469 42,334
(Gain) loss on sale of
property, plant and
equipment (87) 1,224 (65) 1,224
Accretion of asset
retirement obligations 1,204 518 2,869 1,037
Future income tax
expense (recovery) - 4,662 (2,268) 3,443
Non-cash general and
administrative expenses 1,604 333 2,636 659
Non-cash loss on
financial instruments
(note 10) 6,848 420 21,783 6,085
Unrealized foreign
exchange (gain) loss - 1,280 (4,224) 1,727
Asset retirement
obligation expenditures (71) - (598) -
Dry hole costs 1,736 - 4,251 895
Premium on debt exchange - - 15,810 -
Geological and geophysical
costs 114 442 1,323 1,337
------------------------------------------------------------------------
Funds flow from operations 60,488 36,814 104,496 72,721
Net changes in operating
working capital (43,882) (8,820) (59,992) (29,422)
------------------------------------------------------------------------
16,606 27,994 44,504 43,299
------------------------------------------------------------------------
Financing activities
Current and long-term
debt - draws 312,404 - 312,404 -
Current and long-term
debt - repayments (84,911) - (84,911) -
Net investment by
Paramount Resources
Ltd. (note 2) - 107,259 (13,869) 95,203
Payment to Paramount
re the plan of arrangement
(note 1) (220,000) - (220,000) -
Distributions to
unitholders (25,323) - (25,323) -
------------------------------------------------------------------------
(17,830) 107,259 (31,699) 95,203
------------------------------------------------------------------------
Investing activities
Property, plant and
equipment expenditures (16,123) (22,532) (69,108) (52,280)
Petroleum and natural
gas property acquisitions
(note 4) - (90,195) - (90,195)
Proceeds on sale of
property, plant and
equipment 87 100 172 100
Geological and geophysical
costs (114) (442) (1,323) (1,337)
Change in non-cash working
capital 17,374 (22,184) 57,454 5,210
------------------------------------------------------------------------
1,224 (135,253) (12,805) (138,502)
------------------------------------------------------------------------

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

Cash interest paid $ 2,652 $ 1,493 $ 4,838 $ 2,688
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


TRILOGY ENERGY TRUST

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


1. STRUCTURE AND FORMATION OF THE TRUST

Trilogy Energy Trust (the "Trust") is an open-ended unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture dated February 25, 2005. The Trust is managed by Trilogy Energy Ltd., the administrator of the Trust. The beneficiaries of the Trust are the holders of Trust Units (the "Unitholders").

Pursuant to the plan of arrangement involving Paramount Resources Ltd. ("Paramount") and its shareholders and optionholders as described in the Information Circular of Paramount dated February 28, 2005, 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.

The transfer of the Trust Assets did not result in a substantial change in ownership of the Trust Assets by Paramount on the effective date of the plan of arrangement and therefore the transaction was accounted for at the carrying value of the assets transferred. The carrying values of assets and related liabilities transferred to the Trust on April 1, 2005 were as follows:



------------------------------------------------------------------------
Property, plant and equipment - net of
accumulated depletion and depreciation 699,207
Asset retirement obligations (65,076)
Goodwill 19,400
Net working capital accounts (35,674)
------------------------------------------------------------------------
Net carrying value (see note 8) 617,857
------------------------------------------------------------------------
------------------------------------------------------------------------


The net carrying value of the assets and related liabilities accounts were credited to unitholders' capital account on April 1, 2005. In addition to the issuance of Trust Units described above, the Trust paid Paramount on April 1, 2005 an amount of $190 million in cash plus $30 million as an initial settlement of outstanding working capital distribution amounts in accordance with the plan of arrangement. The $190 million transfer consideration was charged against unitholders' capital account.

The Trust, through a wholly-owned holding trust (Trilogy Holding Trust), indirectly owns the Trust Assets mainly through an operating limited partnership (Trilogy Energy LP). Another wholly owned subsidiary of the Trust, Trilogy Energy Ltd., acts as the general and managing partner of Trilogy Energy LP. As part of the plan of arrangement, the Trust also assumed a $15.0 million debt of and paid $0.2 million to, a Paramount subsidiary for the transfer of the general partnership interest in Trilogy Energy LP to Trilogy Energy Ltd. This amount was also charged against unitholders' capital on April 1, 2005.

2. BASIS OF PRESENTATION

The consolidated financial statements of the Trust have been prepared in accordance with Canadian generally accepted accounting principles. As mentioned in note 1, the Trust acquired its operating assets from 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.

For the periods up to March 31, 2005, the consolidated financial statements include Paramount's interests in the assets, liabilities, revenues and expenses attributable to the Trust Assets. The costs of petroleum and natural gas properties and other property, plant and equipment, the associated accumulated depletion and depreciation, the liability for asset retirement obligations and the carrying value of goodwill as at December 31, 2004 have been derived directly from the accounting records of Paramount. Other balance sheet accounts that relate to the Trust Assets but could not be derived directly from Paramount's accounting records such as accounts receivable, prepaid expenses, financial instrument assets and liabilities, and accounts payable and accrued liabilities have been allocated on a pro rata basis using production volumes of the Trust Assets as a proportion of the aggregate production volumes of Paramount for the period. Future income taxes on the Trust Assets have been calculated using the liability method.

The amounts of petroleum and natural gas sales, royalties-net of ARTC, operating costs, geological and geophysical costs, dry hole costs, lease rental costs, accretion of asset retirement obligations, write-down of petroleum and natural gas properties, and gain/losses on sale of property and equipment relating to the Trust Assets that are included in the consolidated financial statements for the periods up to March 31, 2005 have been derived directly from the accounting records of Paramount. Paramount's corporate costs such as general and administrative costs and gains and losses from financial instruments relating to petroleum and natural gas price and exchange rate contracts have been allocated for each period on a pro rata basis using production volumes of the Trust Assets as a proportion of the aggregate production volumes of Paramount for the respective periods. Gains and losses from financial instruments relating to interest rate swaps have been allocated in a pro rata basis using interest expense calculated for the Trust Assets as a proportion to interest expense for Paramount for the respective periods. Interest expense is calculated on the deemed debt balance attributable to the Trust Assets, while Large Corporation tax has been allocated using the ratio of Large Corporation tax base relating to the Trust Assets as a proportion of the consolidated Large Corporation tax base of Paramount. Premium on debt exchange and foreign exchange gains and losses were allocated to the Trust Assets using the ratio of deemed foreign currency denominated debt attributable to the Trust assets as a proportion of the foreign currency denominated debt of Paramount.

For purposes of presentation of the consolidated statements of cash flows for the periods prior to April 1, 2005, cash receipts and disbursements are deemed to be transferred to and from Paramount's corporate account concurrent with the respective inflow or outflow of cash and are presented as "Net investment by Paramount Resources Ltd."

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.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

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. The Trust obtains all of the economic benefits of the operations of Trilogy Energy LP.

Property, Plant and Equipment

The Trust follows the successful efforts method of accounting for petroleum and natural gas operations. Under this method, only those costs that result directly in the discovery of petroleum and natural gas reserves are capitalized. Exploration expenses, including geological and geophysical costs, lease rentals and exploratory dry hole costs, are charged to earnings as incurred. Leasehold acquisition costs, including costs of drilling and equipping successful wells, are capitalized. The net costs of unproductive wells, abandoned wells and surrendered leases are charged to earnings in the year of abandonment or surrender. Gains or losses are recognized on the disposition of property, plant and equipment.

Other property, plant and equipment are recorded at cost.

The net amount at which petroleum and natural gas costs on a property or project are carried is subject to a cost recovery test annually or as economic events dictate. An impairment loss is recognized when the carrying amount of the asset is less than the sum of the expected cash flows on an undiscounted basis. The amount of the impairment loss is then calculated as the difference between the carrying amount and the fair value of the asset. Fair value is calculated as the present value of estimated future cash flows.

Depletion and Depreciation

Depletion and depreciation of petroleum and natural gas properties including well development expenditures, production equipment, gas plants and gathering systems are provided on the unit-of-production method based on estimated proven recoverable reserves of each producing property or project. Depreciation of other property, plant and equipment is provided on a straight-line basis over the assets' estimated useful lives varying from 5 to 12 years.

Joint Operations

Certain exploration, development and production activities are conducted jointly with others. These financial statements reflect only the Trust's proportional interest in such activities.

Asset Retirement Obligations

The fair value of an asset retirement obligation is recognized in the period in which it is incurred or when a reasonable estimate of the fair value can be made. The asset retirement costs equal to the fair value of the retirement obligations are capitalized as part of the cost of the related long-lived asset and allocated to expense on a basis consistent with depreciation and depletion. The liability associated with the asset retirement costs is subsequently adjusted for the passage of time which is recognized as accretion expense in the statement of earnings (loss). The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. Actual costs incurred upon settlement of the asset retirement obligations will reduce the asset retirement liability to the extent of the liability recorded. Differences between the actual costs incurred upon settlement of the asset retirement obligations and the liability recorded are recognized in the earnings in the period in which the settlement occurs.

Goodwill

Goodwill, which represents the excess of purchase price over the fair value of net assets acquired, is not amortized and is assessed for impairment at least annually. Impairment is assessed based on a comparison of the fair value of the net assets acquired to the carrying value of the net assets, including goodwill. Any excess of the carrying value of goodwill over and above its fair value is the impairment amount, and is charged to earnings in the period the impairment is identified.

Revenue Recognition

Revenues associated with the sale of natural gas, crude oil, and natural gas liquids ("NGLs") are recognized when title passes to the customer. Revenues from oil and natural gas production from properties in which there is an interest with other producers are recognized on a net working interest basis.

Financial Instruments

Derivative financial instrument contracts such as forwards are periodically utilized to manage exposure to fluctuations in petroleum and natural gas prices. Emerging Issues Committee Abstract 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments" ("EIC 128") establishes accounting and reporting standards that require every derivative instrument that does not qualify for hedge accounting to be recorded in the balance sheet as either an asset or liability measured at fair value. Accounting Guideline 13, Hedging Relationships ("AcG 13") establishes the need for companies to formally designate, document and assess the effectiveness of relationships that receive hedge accounting treatment.

Derivative financial instruments in which management has formally documented its risk objectives and strategies for undertaking the hedged transaction are accounted for as hedges. For these instruments, it is determined that the derivative financial instruments are effective as hedges, both at inception and over the term of the hedging relationship, as the term to maturity, the notional amount, the commodity price, exchange rate, and interest rate basis of the instruments, all match the terms of the transaction being hedged. The assessment of the effectiveness of the hedging relationships is performed on an ongoing basis to ensure that the derivatives entered into are highly effective in offsetting changes in fair values or cash flows of the hedged items. The fair values of derivative financial instruments designated as hedges are not reflected in the financial statements. Derivative financial instruments not formally designated as hedges are measured at fair value and recognized on the balance sheet with changes in the fair value recognized in earnings during the period. As at June 30, 2005, the Trust has not designated any of its financial instruments as a hedge (note 10).

Income Taxes

The Trust and its subsidiaries are taxable entities under the Income Tax Act (Canada) but are taxable only on income that is not distributed or distributable to the Unitholders. As the Trust intends to distribute all of its taxable income to the Unitholders pursuant to its Trust Indenture and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income taxes has been made in these consolidated financial statements since the transfer of the Trust Assets to the Trust.

Unit Appreciation Plan

The Trust, subject to final approval by the Board of Directors, has offered certain directors, officers and employees a stock-based compensation arrangement in the form of a unit appreciation plan as described in note 9.

The Trust measures compensation cost under the proposed unit appreciation plan as the amount by which the quoted market value of Trust Units covered by the proposed grant exceeds the exercise price adjusted by unit distributions. Compensation cost under the proposed unit appreciation plan is accrued over the appreciation units' vesting period. The recorded liability is revalued at the end of each reporting period to reflect changes in the market price of the Trust Unit with the net change recognized in earnings. When appreciation rights are exercised, the accrued liability is reduced. The accrued compensation for a right that is forfeited or cancelled is adjusted by decreasing compensation cost in the period of forfeiture.

Per Trust Unit Information

Per Trust Unit amounts for all periods prior to April 1, 2005 have been presented on a pro-forma basis as if the Trust Units outstanding at April 1, 2005 were all outstanding for each period shown. Basic earnings per Unit were calculated using the weighted average number of Trust Units (79,133,395 Trust Units) outstanding for the three months ended June 30, 2005. The Trust uses the treasury stock method whereby only "in the money" dilutive instruments impact the diluted calculations. There were no dilutive instruments outstanding for the three months ended June 30, 2005.

Measurement Uncertainty

The amounts recorded for depletion and depreciation and impairment of petroleum and natural gas properties and equipment, and for asset retirement obligations and related accretion are based on estimates of reserves, future costs, petroleum and natural gas prices and other relevant assumptions. By their nature, these estimates and those related to the discounted cash flow used to assess impairment are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

4. PARAMOUNT ACQUISITIONS RELATED 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 obligation for these properties is $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.



5. PROPERTY, PLANT AND EQUIPMENT

------------------------------------------------------------------------
June 30, 2005
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------------------------------------------

Petroleum and natural gas
properties 1,077,186 (396,482) 680,704
Other 1,304 - 1,304
------------------------------------------------------------------------
1,078,490 (396,482) 682,008
------------------------------------------------------------------------
------------------------------------------------------------------------

-----------------------------------------------------------------------
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 six months ended June 30, 2005, $1.7 million and $4.3 million dry hole costs, respectively, were expensed (2004 - nil and $0.9 million, respectively).

Capital costs associated with non-producing petroleum and natural gas properties totaling approximately $66.6 million as at June 30, 2005 ($55.2 million as at December 31, 2004) are not subject to depletion.

6. 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.



------------------------------------------------------------------------
June 30, 2005 December 31, 2004
(Six Months) (One Year)
------------------------------------------------------------------------
Asset retirement obligations,
beginning of period 63,674 28,993
Liabilities incurred 448 30,260
Liabilities settled (598) -
Accretion expense 2,869 4,421
------------------------------------------------------------------------
Asset retirement obligations,
end of period 66,393 63,674
------------------------------------------------------------------------
------------------------------------------------------------------------


The undiscounted asset retirement obligation at June 30, 2005 is estimated to be $102.0 million (December 31, 2004 - $82.2 million). The Trust's credit-adjusted risk-free rate is 7.875 percent (2004 - 7.875 percent). 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.

7. 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 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 June 30, 2005, $229.4 million of the credit facilities has been drawn down. The effective interest rate under this facility for the three months ended June 30, 2005 was 3.42 percent.

The Trust has letters of credit totaling $5.4 million as at June 30, 2005 outstanding with a Canadian chartered bank. These letters of credit reduce the amount available under the Trust's working capital facility.

8. 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 six months ended June 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 of the Trust Assets (note 1) 79,133,395 617,857
Cash paid for the transfer of the Trust
Assets (note 1) - (190,000)
Purchase price of the general partnership
(1%) interest in Trilogy Energy LP (note 1) - (15,211)
Estimated Trust organization costs - (4,000)
------------------------------------------------------------------------
Balance at June 30, 2005 79,133,395 408,646
------------------------------------------------------------------------
------------------------------------------------------------------------


The set-up related costs, including those incurred by Paramount on behalf of the Trust, are estimated to be $4.0 million. These costs were charged against unitholders' capital account.

Redemption Right

Unitholders may redeem their Trust Units at any time by delivering their Trust Units Certificates to the Transfer Agent together with a duly completed and properly executed notice. The redemption price per Trust Unit is equal to the lesser of 90 percent of the market price of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units were tendered for redemption, and the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units were tendered for redemption. Cash payments for Units tendered for redemption are limited to $50,000 per month with redemption requests in excess of this amount eligible to receive notes from the holding trust or other assets held by the Trust. In addition, cash redemption may not apply if the outstanding Trust Units tendered for redemption are not listed for trading, the normal trading of the Trust Units is suspended or halted on any stock exchange or the redemption of Trust Units will result in the delisting of the Trust Units. In such cases, the fair market value of the Trust Units shall be determined by the Administrator and be paid and satisfied by way of asset distribution.

9. PROPOSED UNIT APPRECIATION PLAN

On April 1, 2005, subject to a final approval by the Board of Directors, the Trust has offered certain employees, officers and directors a proposed unit appreciation arrangement whereby employees, officers and directors are 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 shall 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 June 30, 2005, a total of 1,372,000 appreciation units have been proposed to be granted to employees, officers and directors with an exercise price of $10.11 per appreciation unit (before unit distributions adjustment), of which 258,500 appreciation units are expected to vest by 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 vested nor exercised or cancelled for the period ended June 30, 2005.

An accrued compensation expense amounting to $1.6 million relating to the proposed unit appreciation plan has been recognized in earnings for the three months ended June 30, 2005. The current portion of the accrued unit-based compensation liability amounting to $0.7 million is included in accounts payable and accrued liabilities in the consolidated balance sheet.

10. FINANCIAL INSTRUMENTS

Financial Sales Contracts

The Trust utilizes, from time to time, forward commodity price contracts that require financial settlements between counterparties. At June 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 Bbl/d $53.26 April 2005 - September 2005
NYMEX-WTI Fixed Price 1,000 Bbl/d $55.25 April 2005 - September 2005
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 to 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:



------------------------------------------------------------------------
June 30, 2005 December 31, 2004
------------------------------------------------------------------------
Financial instrument asset - 12,413
Financial instrument liability (10,630) (1,260)
------------------------------------------------------------------------
Net financial instrument asset
(liability) (10,630) 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 Six Months Ended
June 30 June 30
------------------------------------------------------------------------
2005 2004 2005 2004
------------------------------------------------------------------------
Realized gain (loss) on
financial instruments 953 (3,941) (1,333) (1,863)
Unrealized loss on
financial instruments (6,848) (420) (21,783) (6,085)
------------------------------------------------------------------------
Total loss on
financial instruments (5,895) (4,361) (23,116) (7,948)
------------------------------------------------------------------------
------------------------------------------------------------------------


Credit and Interest Rate Risks

Under a service agreement described in note 11, 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 7.

11. 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 $1.8 million for the three months ended June 30, 2005. This amount is included as part of the 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 2,657,264 GJs of natural gas to Paramount for $18.3 million for the three months ended June 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 balance due from Paramount arising from the above related party transactions amounted to $0.5 million as at June 30, 2005.

In addition to the letters of credit issued by the Trust as discussed in note 7, Paramount on behalf of the Trust, has issued letters of credit totaling $3.8 million as at June 30, 2005. The Trust has not recorded a liability as at June 30, 2005 with respect to such letters of credit which are set to expire in November 2005.

12. CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Trust has the following future commitments as at June 30, 2005:


------------------------------------------------------------------------
2005 2009
(Six Months) 2006 2007 2008 and after Total
------------------------------------------------------------------------
Pipeline
transportation
commitments 4,416 8,832 8,832 8,832 48,315 79,227
Office premises
operating lease 300 600 600 300 - 1,800
------------------------------------------------------------------------
Total 4,716 9,432 9,432 9,132 48,315 81,027
------------------------------------------------------------------------
------------------------------------------------------------------------


Some of the above commitments are covered by letters of credit issued by the Trust.

The Trust has entered into the following fixed price physical commodity sales contracts outstanding as at June 30, 2005:



------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Gas Sales Contract(1) 10,000 GJ/d $ 6.98 April 2005 - October 2005
Gas Sales Contract(1) 10,000 GJ/d $ 7.36 April 2005 - October 2005
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Physical sales contracts are not marked-to-market.


Also see note 11 for the details of the Call on Production Agreement between the Trust and Paramount.

13. INCOME TAXES

As disclosed in note 3, 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.

14. SUBSEQUENT EVENTS

On July 21, 2005, the Trust announced that its cash distribution for July 2005 will be $0.16 per Trust Unit. The distribution is payable on August 15, 2005 to unitholders of record on August 2, 2005.



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

Sales Volumes 2005 2004
------------------------------------------------------------------------
Q2 Q1 Q4 Q3
------------------------------------------------------------------------
Gas (MMcf/d) 117 122 119 104
Oil and Natural Gas Liquids
(Bbl/d) 4,350 4,950 5,672 5,204
------------------------------------------------------------------------
Total Sales Volumes (Boe/d) (6:1) 24,287 25,192 25,439 22,521
------------------------------------------------------------------------
------------------------------------------------------------------------


Per Unit Results 2005 2004
------------------------------------------------------------------------
Q2 Q1 Q4 Q3
------------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, before transportation and selling 8.15 7.48 7.38 6.95
Transportation 0.48 0.38 0.41 0.41
Royalties 1.82 1.85 1.76 1.54
Operating expenses, net of
processing revenue 1.34 1.25 1.30 1.34
------------------------------------------------------------------------
Cash netback before realized financial
instruments 4.51 4.00 3.91 3.66
Realized financial instruments 0.03 (0.21) 0.83 (0.34)
------------------------------------------------------------------------
Cash netback including realized
financial instruments 4.54 3.79 4.74 3.32
------------------------------------------------------------------------
------------------------------------------------------------------------

Produced Oil & Natural Gas Liquids ($/Bbl)
Price, before transportation and selling 57.84 55.42 49.85 53.68
Transportation 0.86 0.94 0.71 0.71
Royalties 14.11 11.32 7.55 9.36
Operating expenses, net of processing
revenue 4.64 6.70 10.57 6.22
------------------------------------------------------------------------
Cash netback before realized
financial instruments 38.23 36.46 31.02 37.39
Realized financial instruments 1.41 0.63 (2.62) (1.12)
------------------------------------------------------------------------
Cash netback including realized
financial instruments 39.64 37.09 28.40 36.27
------------------------------------------------------------------------
------------------------------------------------------------------------

Total Produced ($/Boe)
Price, before transportation and
selling 50.65 46.95 45.54 44.54
Transportation 2.47 2.01 2.10 2.12
Royalties 11.53 11.12 9.89 9.26
Operating expenses, net of
processing revenue 7.35 6.86 8.42 7.60
------------------------------------------------------------------------
Cash netback before realized
financial instruments 29.30 26.96 25.13 25.56
Realized financial instruments 0.43 3.11 3.31 (1.83)
------------------------------------------------------------------------
Cash netback including realized
financial instruments 29.73 30.07 28.44 23.73
------------------------------------------------------------------------
------------------------------------------------------------------------

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 or 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 the Trust believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on them because we 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, and our reserve estimates. The Trust's forward-looking statements are expressly qualified in their entirety by this cautionary statement. We undertake no obligation to update our forward-looking statements except as required by law.

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