Trilogy Energy Trust
TSX : TET.UN

Trilogy Energy Trust

August 07, 2006 13:03 ET

Trilogy Energy Trust Financial and Operating Results for the Quarter Ended June 30, 2006

CALGARY, ALBERTA--(CCNMatthews - Aug. 7, 2006) - Trilogy Energy Trust (TSX:TET.UN) ("Trilogy" or "the Trust") is pleased to announce its financial and operating results for the three and six months ended June 30, 2006.



Financial and Operating Highlights
(thousand dollars except per unit amounts and where stated otherwise)

Three Months ended Six Months ended
June 30, June 30,
Change Change
2006 2005 % 2006 2005 %

FINANCIAL
Petroleum and natural
gas sales 105,663 111,929 (6) 231,402 217,897 6
Funds flow(1)
From operations 79,100 60,488 31 143,420 104,496 37
Per unit - basic(2) 0.86 0.76 13 1.62 1.32 23
- diluted(2) 0.86 0.76 13 1.62 1.32 23
Earnings
Net earnings (loss) 19,819 17,370 14 77,943 (4,490) 1,836
Per unit - basic(2) 0.22 0.22 - 0.88 (0.06) 1,567
- diluted(2) 0.22 0.22 - 0.88 (0.06) 1,567
Distributions declared 59,561 37,984 57 125,037 37,984 229
Per unit 0.65 0.48 35 1.50 0.48 213
Capital expenditures
Exploration and
development 24,584 15,426 59 100,111 69,067 45
Acquisitions,
dispositions and
other(5) 932 724 29 131,461 1,192 10,929
Net capital
expenditures 25,516 16,150 58 231,572 70,259 230
Total assets 922,153 759,798 21 922,153 759,798 21
Net debt(3) 265,447 246,092 8 265,447 246,092 8
Unitholders' equity 540,097 388,032 39 540,097 388,032 39
Trust Units outstanding
(thousands)
- As at June 30, 2006
(June 30, 2005) 91,633 79,133 16 91,633 79,133 16

OPERATING
Production
Natural gas (MMcf/d) 118 117 1 118 119 (1)
Crude oil and natural
gas liquids (Bbl/d) 5,103 4,780 7 5,048 4,865 4
Total production
(Boe/d) @ 6:1 24,827 24,287 2 24,717 24,737 -

Average prices
Natural gas
(pre-financial
instruments)($/Mcf) 6.81 8.15 (16) 7.99 7.80 2
Natural gas ($/Mcf)(4) 9.91 8.18 21 9.52 7.70 24
Crude oil and natural
gas liquids (pre-
financial instruments)
($/Bbl) 69.55 57.84 20 66.52 56.29 18
Crude oil and natural
gas liquids ($/Bbl)(4) 66.25 59.25 12 65.02 57.29 13

Drilling activity
(gross)
Gas 6 4 50 43 31 39
Oil - 1 (100) - 4 (100)
D&A 1 - - 4 3 33
Total wells 7 5 40 47 38 24
Success rate 86% 100% - 91% 92% -

(1) 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.
(2) Per unit amounts were calculated for the quarters ended June 30 2006
and 2005, and the six months ended June 30, 2006 using the weighted
average number of units outstanding. For periods prior to April 1,
2005 the initial number of units outstanding was used.
(3) Net debt is equal to long-term debt plus/minus working capital.
(4) Excludes non-cash gains and losses on financial instruments.
(5) Includes the acquisition of Redsky Energy Ltd's petroleum and
natural gas properties effective March 31, 2006 for an allocated
amount of $130,451.


Review of Operations

Trilogy Energy Trust ("Trilogy" or "the Trust") is pleased to report its operating and financial results for the second quarter of 2006. We began this quarter with the successful acquisition of Redsky Energy Ltd., which closed on March 31, 2006. This acquisition has proved to be a good fit with Trilogy's strategy to grow with the exploitation of tight gas resources. The shallow conventional reserves and the deeper tight gas reservoirs of Redsky Energy Ltd. ("Redsky") have been fully integrated into our daily operations.

Production for the second quarter of 2006 averaged 24,827 Boe/d, 118.3 MMcf/d of natural gas, 2,343 Bbl/d of crude oil and 2,760 Boe/d of natural gas liquids. This is up one percent from the 24,605 Boe/d reported for the first quarter of the year. We met the challenges of weather-related and operational delays with a strategy of concentrating our resources where we could see immediate results by recompleting and optimizing production from existing wellbores. The original Trilogy assets at Kaybob and Marten Creek produced 23,000 Boe/d versus a forecast rate of 25,000 Boe/d; the shortfall was a result of normal production declines which were only partially offset by production additions. Additionally, second quarter production volumes were down by approximately 800 Boe/d as a result of a plant turnaround at the Trilogy operated Kaybob North Gas Plant, causing the shut-in of 38 MMcf/d and 1,500 Bbl/d of liquids for a ten day period. Turnarounds such as this happen approximately every four years and are crucial for the maintenance and successful day-to-day operations of the plant.

Drilling and completion operations were limited by wet road and lease conditions that typically occur during the spring period. There were 7 (5.8 net) wells drilled during the quarter. Of these wells, four were drilled prior to break-up and the remaining three were drilled prior to the end of the quarter, resulting in 6 (4.8 net) gas wells and 1 (1.0 net) dry hole. This brings the total Trust wells drilled to date to 47 (39.3 net). Of these wells, 43 (35.3 net) have been cased for potential gas and oil production and 4 (4.0 net) wells were dry holes, for a success rate of 91 percent. It is anticipated that we will have two drilling rigs active for most of the third quarter. A third rig will begin drilling in the fourth quarter and will remain active for the balance of the year in the Kaybob area.

Capital spending for the quarter was $25.5 million, bringing the year-to-date total to $101.1 million. Second quarter capital spending was higher than anticipated due to the expenditure of $11 million at Crown land sales during the quarter. The Trust's success at Crown sales has resulted in the acquisition of acreage that is expected to provide additional downspacing opportunities based on recent drilling and completion success. The balance of the capital for the quarter was used to tie in wells at the start of the second quarter that offset production declines during the period, and to execute the drilling activity that was described above.

Operating costs for the second quarter were $23.4 million, which equates to $10.37/Boe as compared to $9.00/Boe reported for the first quarter of the year. Costs were higher than expected due to Trilogy's concentration on workover activity, rather than drilling activity, in order to counteract the delays caused by wet weather. Approximately $0.9 million net was spent in the Simonette area to workover shut-in and suspended wells, the result of which is expected to increase net production volumes by approximately 350 Boe/d in the third quarter. Operating expenses of approximately $1.7 million net were incurred in the Kaybob South Beaverhill Lake Unit 3 area during the quarter to continue to bring existing suspended wellbores up to regulatory standards and to prepare them for gas lift evaluation that we expect to implement in the following quarters. As mentioned previously, the Kaybob North Gas Plant went through a ten-day maintenance period at a net cost of $0.5 million. Collectively these operations added $3.1 million ($1.36/Boe) to the operating costs in the quarter. It is anticipated that operating costs for the remaining two quarters should be approximately $8.00 /Boe, when the operational activity shifts back to the drilling and completion of new wells for the balance of the year.

Kaybob

Production in the Kaybob area was 19,783 Boe/d which was 9 percent below our annual forecast of 21,667 Boe/d (100 MMcf/d and 5,000 Bbl/d of oil and natural gas liquids); these volumes were close to our expectations considering the maintenance work at the gas plant. Production to the non-operated gas plant at Bigstone was redirected during the quarter to alternate pipelines to ensure the unrestricted flow of gas. Five of the seven wells drilled during the quarter were in the Kaybob area. The majority of the wells to be drilled in the balance of the year will be in this area and will continue to exploit the tight gas reservoirs identified to date in order to keep production at the 21,667 Boe/d level. During the third quarter, construction will begin on a project that will add field compression in the Pine Creek area. When completed, we expect this additional compression will allow us to bring on 1,000 Boe/d of shut-in production.

Marten Creek

The Marten Creek area is confined to winter-only access; minor field operations can be done in summer months with helicopter support. Production for the quarter averaged 19.3 MMcf/d (3,218 Boe/d) which was slightly below our expectation of 20 MMcf/d (3,333 Boe/d). Plans are currently being developed for the 2007 winter drilling program with the expectation that we will complete and tie in some of the wells that were drilled in the past winter and drill additional wells to replace declines and maintain production at 20 MMcf/d.

Grande Prairie

The Grande Prairie assets were acquired through the Trust's acquisition of Redsky. Production from the Grande Prairie area averaged 1,827 Boe/d versus the forecast of 2,000 Boe/d for the period. The production shortfall in this area is primarily caused by facility restrictions at non-operated compressor stations and gas plants. We are evaluating plans to redirect the shut-in gas to alternate pipelines and facilities. Approximately 1,000 Boe/d is shut-in as a result of these facility limitations; we anticipate that we will have some of the shut-in gas on stream prior to the end of the third quarter.

Two wells were drilled in this area during the quarter, one well is currently being completed while the other is awaiting dryer ground conditions in order to access the location without incurring additional costs related to the wet conditions. We anticipate production levels to increase prior to the end of the third quarter when we are able to negotiate access to the producing infrastructure and gas plants.

Risk Management

Trilogy believes that its focus on natural gas will provide significant upside for its unitholders in the future, as short-term price fluctuations will be offset by the long-term strength in natural gas prices as they reflect an increase in demand at a time when natural gas supply is not unlimited. Trilogy continues to enter into short-term gas purchase and sales contracts with a view to maintaining stable cash flow for unitholders. During the second quarter, Trilogy settled a portion of the financial instruments tied to commodity prices, realizing a financial gain of approximately $18 million. We will continue to manage the opportunities that present themselves in order to maximize cash flow for the Trust.

Key Personnel

We welcome Mike Kohut to Trilogy, our new Chief Financial Officer. Mike brings with him 16 years of experience and a fresh approach that will benefit the Trust. We would like to thank Bernie Lee for his contributions in forming the Trust and to its success during the first year of operations. As well, we would like to acknowledge that Gail Yester has been appointed to the position of General Counsel and Corporate Secretary. Gail will be replacing Chuck Morin who held these positions since the inception of Trilogy and was instrumental in the formation of the Trust. We wish Chuck and Bernie continued success at Paramount Resources.

Outlook

The second quarter was marked by a significant drop in the price of natural gas. We believe this drop in price stems from the concern that natural gas storage levels have been increasing above average levels due to low consumption caused by an unseasonably warm winter following a relatively cool summer. The effect in the near term may be that prices could fall even lower if natural gas continues to be injected into storage versus being consumed. If natural gas storage reaches maximum levels, we may see a period where prices are even weaker than current levels. This volatility has forced natural gas weighted production companies and trusts to reconsider corporate spending plans and strategies. In May, Trilogy's Board of Director's approved a distribution cut that reduced the monthly distribution from $0.25/unit to $0.20/unit for the foreseeable future. However, Trilogy continues to remain optimistic on the longer term future of natural gas prices and feels that the commodity cycle will recover in the winter months. As result we have decided not to adjust our capital spending for the remainder of the year, and will maintain our program of focusing on the development of tight gas in the Kaybob and Grande Prairie areas and shallow gas at Marten Creek.

During the quarter Trilogy implemented a distribution reinvestment plan ("DRIP") in order to allow resident unitholders an opportunity to reinvest monthly distributions back into the Trust at a discounted price excluding commissions. We feel that Trilogy has exceptional assets, high quality staff and a strategy that will continue to provide value to its unitholders and that the DRIP will allow for an ongoing quality investment for the unitholders that choose to reinvest.

We expect that our average daily production for the balance of the year, including the Redsky assets, will be approximately 26,000 Boe/d with an exit rate forecast of 27,000 Boe/d. We believe that Trilogy's large portfolio of natural gas prospects will continue to provide value to Trilogy Unitholders. Successful production replacement, prudent asset and capital management and continued control of operations will help support a stable monthly distribution. Acquisitions will continue to be evaluated for their strategic fit with Trilogy's business model and exploitation strategy and will be pursued when they are considered to be accretive to unitholder value.

Management's Discussion and Analysis

This Management's Discussion and Analysis ("MD&A") provides the details of the financial condition and results of operations of Trilogy Energy Trust ("Trilogy" or the "Trust") as at and for the three and six months ended June 30, 2006, and should be read in conjunction with the Trust's interim consolidated financial statements as at and for the three and six months ended June 30, 2006, and the consolidated financial statements as at and for the nine months ended December 31, 2005. 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 the 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 the Trust. 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.

Readers are also cautioned of the advisories on forward-looking statements, estimates, non-GAAP measures and numerical references which can be found towards the end of this MD&A. This MD&A is dated, and was prepared using currently available information as of, August 7, 2006.

FORMATION AND STRUCTURE 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 (16.4 percent at June 30, 2006) of the issued and outstanding Trust Units being held by Paramount.

Trilogy, through a wholly-owned holding trust (Trilogy Holding Trust or the "Holding Trust"), indirectly owns the Trust Assets through two operating limited partnerships (Trilogy Energy LP and Trilogy Redsky LP or the "Limited Partnerships"). Other wholly-owned subsidiaries of the Trust, Trilogy Energy Ltd. and Trilogy Redsky Ltd. (which has 100 percent subsidiary, 1230901 Alberta Ltd.), acts as the general partners (the "General Partners") of the Limited Partnerships and as Administrator to Trilogy and the Holding Trust.

CURRENT QUARTER HIGHLIGHTS

- On March 31, 2006 Trilogy completed the acquisition of all of the shares of Redsky Energy Ltd. ("Redsky"). During the quarter the assets and operations of Redsky were integrated with those of Trilogy.

- Production for the second quarter of 2006 averaged 24,827 Boe/d, a slight increase over average production for the first quarter of 2006 of 24,605 Boe/d. This includes 1,827 Boe/d that was added as a result of the Redsky acquisition. Production additions offset the impact of the scheduled plant shutdowns at Kaybob and natural production declines.

- The decline in natural gas prices decreased funds flow from operations by $25.1 million in the quarter versus the first quarter of 2006.

- Realized gains on financial instruments of $31.8 million in the second quarter of 2006 as opposed to a realized loss of $0.5 million in the first quarter was the major reason why funds flow from operations increased by 23 percent to $79.1 million from $64.3 million. The gain in the second quarter included $17.7 million from contracts that were terminated early.

- Capital expenditures excluding acquisitions totaled $25.1 million for the second quarter of 2006. The expenditures included land additions of $11.2 million.

- Distributions declared to unitholders for the second quarter of 2006 amounted to $59.6 million. Distributions were reduced from $0.25 per Trust Unit to $0.20 per Trust Unit effective May 2006 in order to maintain a healthy balance sheet.

- Trilogy has adopted a Distribution Reinvestment Plan which provides eligible unitholders with the opportunity to reinvest their monthly cash distributions in Trust Units at a price equal to 95 percent of the ten-day average trading price prior to the distribution date.



RESULTS OF OPERATIONS

Second Quarter 2006 vs. First Quarter 2006

------------------------------------------------------------------------
(thousand dollars except as otherwise
indicated) Q1 2006 Change Q2 2006
------------------------------------------------------------------------
Average sales volumes:
Natural gas (Mcf/d) 117,685 659 118,344
Oil and natural gas liquids (Bbl/d) 4,990 113 5,103
------------------------------------------------------------------------
Total (Boe/d) 24,605 222 24,827
------------------------------------------------------------------------
Average prices before realized financial
instruments and transportation:
Natural gas ($/Mcf) 9.18 (2.37) 6.81
Oil and natural gas liquids ($/Bbl) 63.38 6.17 69.55
------------------------------------------------------------------------
Average prices after realized financial
instruments and before transportation:
Natural gas ($/Mcf) 9.12 0.79 9.91
Oil and natural gas liquids ($/Bbl) 63.76 2.49 66.25
------------------------------------------------------------------------

Petroleum and natural gas sales before
financial instruments:
Natural gas 97,272 (23,908) 73,364
Oil and natural gas liquids 28,467 3,832 32,299
------------------------------------------------------------------------
125,739 (20,076) 105,663
------------------------------------------------------------------------
Gain on financial instruments(1) (29,779) 21,427 (8,352)
Royalties 31,941 (7,248) 24,693
Operating costs 19,929 3,507 23,436
Transportation costs 4,500 676 5,176
Depletion and depreciation 28,355 3,846 32,201
General and administrative expenses 2,301 1,144 3,445
Interest 1,959 1,120 3,079
Exploration expenditures 7,786 (6,386) 1,400
Other expenditures (net of other income) 623 143 766
------------------------------------------------------------------------
Net earnings 58,124 (38,305) 19,819
------------------------------------------------------------------------
------------------------------------------------------------------------
(1)See Risk Management section.


Petroleum and Natural Gas Sales - Natural gas sales before financial instruments decreased by approximately $25.1 million due to lower average sales prices, offset by an increase of $1.2 million due to increased sales volumes. Oil and natural gas liquids sales before financial instruments increased by $2.8 million and $1.1 million due to higher average sales prices and sales volumes, respectively. Sales volumes increased mainly due to the acquisition of Redsky as of March 31, 2006, adding production of 1,827 Boe/d to the current quarter. This was offset by decreases in production volumes as a result of a scheduled turnaround at the North Kaybob plant and to production declines.

Royalties - The decrease in royalties was due mainly to the decrease in petroleum and natural gas sales as noted above. As a percentage of petroleum and natural gas sales, royalties averaged 23 percent for the second quarter of 2006 as compared to 25 percent for the first quarter of 2006. The decrease is mainly the result of changes in the difference between the corporate prices and the Alberta Reference Price on which royalties are calculated. The royalty rate as a percentage of sales may fluctuate from period to period due to the fact that the Alberta Reference Price may differ significantly from Trilogy's actual corporate commodity prices.

Operating Costs - The increase in operating costs is attributable mainly to repairs and maintenance costs incurred during the second quarter of 2006 for scheduled plant turnarounds and workovers. On a per unit basis, operating costs increased to $10.37/Boe in the second quarter of 2006 from $9.00/Boe in the first quarter of 2006 due primarily to the costs described above.

Transportation Costs - The small increase in transportation costs is partly due to the corresponding increase in sales volumes. On a per unit basis, transportation costs increased from $2.03/Boe in the first quarter to $2.29/Boe in the second.

Depletion and Depreciation Expense - Depletion and depreciation expense increased by 14 percent due mainly to a higher capital asset base (now including Redsky), the increase in production and to an increase in expired mineral leases. On a per unit basis, depletion and depreciation is up to $14.25/Boe in the second quarter of 2006 from $12.80/Boe in the first quarter of 2006. In addition, the plant turnaround reduced sales volumes to cover fixed depreciation expenditures.

General and Administrative Expenses - General and administrative expenses excluding non-cash unit-based compensation were $1.6 million during the second quarter of 2006 as compared to $2.4 million during the first quarter of 2006. The decrease is due mainly to higher overhead recoveries during the current quarter. Total general and administrative expenses (including non-cash unit-based compensation) increased during the second quarter of 2006 due mainly to higher accrued compensation expense associated with the Trust's unit-based compensation plans. The decline in the market price of the Trust Units from December 31, 2005 to March 31, 2006 resulted in a unit-based compensation recovery of $0.7 million for the first quarter of 2006 as compared to the unit-based compensation expense of $1.3 million for the second quarter of 2006.

Interest Expense - Interest expense increased during the current quarter due mainly to the increase in average debt balances to fund operating requirements. Increases in prime borrowing rates also contributed to the increase in interest expense.

Exploration Expenditures -Exploration expenditures decreased from the first quarter of 2006 compared to the second quarter of 2006 due mainly to lower activity levels. Drilling activities are typically at the highest levels in the first and fourth quarters of each year due to access related issues.



Second Quarter 2006 vs. Second Quarter 2005

------------------------------------------------------------------------
(thousand dollars except as otherwise
indicated) Q2 2005 Change Q2 2006
------------------------------------------------------------------------
Average sales volumes:
Natural gas (Mcf/d) 117,042 1,302 118,344
Oil and natural gas liquids (Bbl/d) 4,780 323 5,103
------------------------------------------------------------------------
Total (Boe/d) 24,287 540 24,827
------------------------------------------------------------------------
Average prices before realized financial
instruments and transportation:
Natural gas ($/Mcf) 8.15 (1.34) 6.81
Oil and natural gas liquids ($/Bbl) 57.84 11.71 69.55
------------------------------------------------------------------------
Average prices after realized financial
instruments but before transportation:
Natural gas ($/Mcf) 8.18 1.73 9.91
Oil and natural gas liquids ($/Bbl) 59.25 7.00 66.25
------------------------------------------------------------------------

Petroleum and natural gas sales before
financial instruments:
Natural gas 86,770 (13,406) 73,364
Oil and natural gas liquids 25,159 7,140 32,299
------------------------------------------------------------------------
111,929 (6,266) 105,663
------------------------------------------------------------------------
Loss (gain) on financial instruments(1) 5,895 (14,247) (8,352)
Royalties 25,502 (809) 24,693
Operating costs 16,242 7,194 23,436
Transportation costs 5,470 (294) 5,176
Depletion and depreciation 31,683 518 32,201
General and administrative expenses 4,665 (1,220) 3,445
Interest 2,312 767 3,079
Exploration expenditures 1,982 (582) 1,400
Other expenditures (net of other income) 808 42 766
------------------------------------------------------------------------
Net earnings (loss) 17,370 2,449 19,819
------------------------------------------------------------------------
------------------------------------------------------------------------
(1)See Risk Management section.


Petroleum and Natural Gas Sales - In comparison to the second quarter of 2005 natural gas sales before financial instruments decreased by $14.2 million in the current quarter due to lower average sales prices. This decease in price was offset by the impact of higher sales volumes of approximately $0.8 million. Oil and natural gas liquid sales before financial instruments increased by $5.1 million and $2.0 million due to higher average sales prices and higher sales volumes, respectively. Average sales volumes were slightly higher during the current quarter due mainly to the Redsky acquisition, offset by the impact of the scheduled plant turnaround as described above.

Royalties - As a percentage of petroleum and natural gas sales, royalties averaged 23 percent for the second quarter of 2006 and 2005. The royalty rate as a percentage of sales may fluctuate from period to period due to the fact that the Alberta Reference Price may differ significantly from Trilogy's actual corporate commodity prices.

Operating Costs - The increase in operating costs is attributed to an increase in workover and maintenance activity during the second quarter of 2006. On a per unit basis, operating costs increased to $10.37/Boe in the second quarter of 2006 from $7.35/Boe in the same quarter of 2005, reflecting the costs described above as well as the impact of rising costs in the industry.

Transportation Costs - Transportation costs on a per unit basis were lower at $2.29/Boe for the second quarter of 2006 as compared to $2.47/Boe for the same quarter in 2005. Trilogy was able to reduce fixed transportation costs through the assignment of certain fixed contractual commitments to a third party towards the latter part of 2005. The seven percent reduction in transportation costs per Boe for the second quarter of 2006 versus the second quarter of 2005 reflects this benefit.

Depletion and Depreciation Expense - Depletion and depreciation expense was relatively consistent during the second quarter of 2006 and 2005. During 2005, the Trust added reserves at a lower average cost and this, combined with the downward revision in asset retirement obligation in the fourth quarter of 2005, resulted in a reduction in the depletion and depreciation rate. On a per unit of product sales volume basis, depletion and depreciation is down slightly from $14.33/Boe in the second quarter of 2005 to $14.25/Boe for the second quarter of 2006.

General and Administrative Expenses - General and administrative expenses were lower during the second quarter of 2006 when compared to the same quarter in 2005 partially due to higher expenses being incurred during the transition to the Trust in the second quarter of 2005. General and administrative expenses have normalized to lower levels after the second quarter of 2005. In addition, there was an increase in recoveries during the current quarter. Included within general and administrative expenses were unit and stock-based compensation expenses of $1.9 million for the second quarter of 2006 versus $1.6 million for the second quarter of 2005.

Interest Expense - Interest expense increased during the current quarter with the increase in average debt balances needed to fund operating requirements. Increases in prime borrowing rates also contributed to the increase in interest expense.

Exploration Expenditures - Exploration expenditures consist of lease rentals, dry hole costs and geological and geophysical costs. Exploration expenditures decreased slightly in the second quarter of 2006 compared to the same quarter of 2005 due mainly to lower dry hole costs.



Year to Date June 30, 2006 vs. Year to Date June 30, 2005

------------------------------------------------------------------------
Six Six
Months Months
Ended Ended
(thousand dollars except as otherwise June 30, June 30,
indicated) 2005 Change 2006
------------------------------------------------------------------------
Average sales volumes:
Natural gas (Mcf/d) 119,235 (1,219) 118,016
Oil and natural gas liquids (Bbl/d) 4,865 183 5,048
------------------------------------------------------------------------
Total (Boe/d) 24,737 (20) 24,717
------------------------------------------------------------------------
Average prices before realized financial
instruments and transportation:
Natural gas ($/Mcf) 7.80 0.19 7.99
Oil and natural gas liquids ($/Bbl) 56.29 10.23 66.52
------------------------------------------------------------------------
Average prices after realized financial
instruments but before transportation:
Natural gas ($/Mcf) 7.70 1.82 9.52
Oil and natural gas liquids ($/Bbl) 57.29 7.73 65.02
------------------------------------------------------------------------

Petroleum and natural gas sales before
financial instruments:
Natural gas 168,339 2,297 170,636
Oil and natural gas liquids 49,558 11,208 60,766
------------------------------------------------------------------------
217,897 13,505 231,402
------------------------------------------------------------------------
Loss (gain) on financial instruments(1) 23,116 (61,247) (38,131)
Royalties 50,771 5,863 56,634
Operating costs 32,365 11,000 43,365
Transportation costs 10,275 (599) 9,676
Depletion and depreciation 67,404 (6,848) 60,556
General and administrative expenses 10,718 (4,972) 5,746
Interest 4,838 200 5,038
Exploration expenditures 5,989 3,197 9,186
Other expenditures (net of other income) 18,769 (17,380) 1,389
Taxes (1,858) 1,858 -
------------------------------------------------------------------------
Net earnings (loss) (4,490) 82,433 77,943
------------------------------------------------------------------------
------------------------------------------------------------------------
(1)See Risk Management section.


Petroleum and Natural Gas Sales - In comparison to the six-month period ended June 30, 2005, natural gas sales, before financial instruments, increased by $4.1 million as compared to the same period of the current year due to higher average sales prices. This increase was offset by the impact of lower sales volumes of approximately $1.8 million. Natural gas sales volumes were lower with the temporary shut-in of production from the plant turnaround. Oil and natural gas liquid sales, before financial instruments, increased by $9.0 million and $2.2 million due to higher average sales prices and slightly higher sales volumes, respectively.

Royalties - The increase in royalties in 2006 was the result of increased petroleum and natural gas sales as noted above. As a percentage of petroleum and natural gas sales, royalties averaged 24 percent for the first six months of 2006 as compared to 23 percent for the same period of 2005. The royalty rate as a percentage of sales may fluctuate from period to period due to the fact that the Alberta Reference Price may differ significantly from Trilogy's actual corporate commodity prices.

Operating Costs - The increase in operating costs is attributed, for the most part, to the repairs and maintenance costs incurred during the first six months of 2006. On a per unit basis, operating costs increased to $9.69/Boe during the first six months of 2006 from $7.23/Boe during the same period of 2005, reflecting significant increases in the cost of goods and services in the energy sector and the costs described above.

Transportation Costs - The decrease in transportation cost is mainly the result of lower natural gas sales volume during the current period. On a per unit basis, transportation costs were lower at $2.16/Boe for the first six months of 2006 compared to $2.29/Boe for the same period in 2005. Trilogy was able to reduce fixed transportation costs through the assignment of certain fixed contractual commitments to a third party towards the latter part of 2005. The six percent reduction in transportation costs per Boe for the first six months of 2006 versus the first six months of 2005 reflects this benefit.

Depletion and Depreciation Expense - Depletion and depreciation expense decreased by 10 percent in the first six months of 2006 compared to the same period in 2005. During 2005, the Trust added reserves at a lower average cost and this, combined with the downward revision in asset retirement obligation in the fourth quarter of 2005, resulted in a reduction in the depletion and depreciation rate per Boe. On a per unit of product sales volume basis, depletion and depreciation is down from $15.05/Boe in the first six months of 2005 to $13.53/Boe for the first six months of 2006.

General and Administrative Expenses - General and administrative expenses decreased due in part to the recording (on a carve-out basis from Paramount) of stock-based compensation expense of $2.3 million in the first quarter of 2005, and the normalization of general and administrative expenditure levels from the Trust's transition period in 2005.

Interest Expense - Interest expense increased during the first six months of 2006 due mainly to the increase in average debt balances needed to fund operating requirements. Increases in the prime borrowing rates also contributed to the increase in interest expense.

Exploration Expenditures - Exploration expenditures consist of lease rentals, dry hole costs and geological and geophysical costs. Exploration expenditures increased in the first six months of 2006 as compared to the same period of 2005 due to an increase in the level of drilling activity and rising costs of services experienced across the industry.

Other Expenditures - Other expenditures consist mainly of accretion on asset retirement obligations, loss on sale of property, plant and equipment, other income and, for the six months ended June 30, 2005, non-recurring allocated expenditures such as premium on debt exchange and foreign exchange gain (loss) recorded on a carve-out basis from Paramount prior to April 1, 2005.

Taxes - No amounts in respect of taxes have been recorded since the Trust owned the assets (see Income Taxes section). Prior to April 1, 2005, the liability method was used to calculate future taxes.



FUNDS FLOW FROM OPERATIONS PER UNIT OF SALES VOLUMES

------------------------------------------------------------------------
Three Months Six Months
Ended Ended
June 30 June 30
(Dollars per Boe) 2006 2005 2006 2005
------------------------------------------------------------------------
Gross revenue before financial
instruments(1) 44.53 48.35 49.65 46.46
Royalties (10.93) (11.54) (12.66) (11.34)
Operating costs (10.37) (7.35) (9.69) (7.23)
Asset retirement obligation
expenditures (0.14) (0.03) (0.09) (0.13)
------------------------------------------------------------------------
Revenue after direct expenditures 23.09 29.43 27.21 27.76
General and administrative
expenses(2) (0.71) (1.38) (0.90) (1.81)
Interest expense (1.36) (1.05) (1.13) (1.08)
Lease rentals (0.08) (0.06) (0.11) (0.09)
Realized gain (loss) on financial
instruments 14.07 0.43 6.99 (0.30)
Non-recurring allocated
expenditures - - - (1.14)
------------------------------------------------------------------------
Funds flow from operations(3) 35.01 27.37 32.06 23.34
Net change in operating working
capital (17.29) (19.86) (1.99) (13.40)
------------------------------------------------------------------------
Cash flows from operating
activities 17.72 7.51 30.07 9.94
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Net of transportation costs and including other income
(2) Excluding non-cash general and administrative expenses.
(3) Please refer to the advisories on non-GAAP measures towards the end
of this MD&A.


RISK MANAGEMENT

To protect cash flows 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 forecasted annual production volumes.

The Trust had forward financial commodity sales contracts outstanding as at June 30, 2006 as disclosed in the interim consolidated financial statements.

The Trust follows the requirements 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 requirements, 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 hedges 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 and termination of contracts prior to their maturity are presented as 'realized gain (loss) on financial instruments.' The amounts of unrealized and realized gain (loss) on financial instruments are as follows:



------------------------------------------------------------------------
Three Months Six Months
Ended Ended
June 30 June 30
(thousand dollars) 2006 2005 2006 2005
------------------------------------------------------------------------
Realized gain (loss) on financial
instruments 31,798 953 31,276 (1,333)
Change in unrealized gain (loss)
on financial instruments (23,446) (6,848) 6,855 (21,783)
------------------------------------------------------------------------
Net gain (loss) on financial
instruments 8,352 (5,895) 38,131 (23,116)
------------------------------------------------------------------------
------------------------------------------------------------------------


Mark-to-market accounting of financial instruments causes significant fluctuations in net gain (loss) on financial instruments due to the volatility of energy commodity prices. Realized gains on financial instruments were significantly higher for the three and six months ended June 30, 2006 as compared to the same periods in 2005 due to the significant decline in natural gas market prices relative to the prices fixed under Trilogy's financial instrument contracts. In addition, certain financial instrument contracts were terminated prior to their maturity during the three months ended June 30, 2006 resulting in a net settlement payment to Trilogy of $17.7 million.

Under a services 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 third party credit risk is controlled 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 later in this MD&A.



QUARTERLY FINANCIAL INFORMATION

------------------------------------------------------------------------
Second First Fourth Third
(thousand dollars except Quarter Quarter Quarter Quarter
per unit amounts) 2006 2006 2005 2005
------------------------------------------------------------------------
Revenue after financial
instruments, royalties and
other income 89,450 123,833 145,643 67,637
Net earnings (loss) 19,819 58,124 87,675 (2,529)
Earnings (loss) per Trust Unit(2)
Basic 0.22 0.68 1.11 (0.03)
Diluted 0.22 0.68 1.11 (0.03)
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
Second First Fourth Third
(thousand dollars except Quarter Quarter Quarter Quarter
per unit amounts) 2005 2005(1) 2004(1) 2004(1)
------------------------------------------------------------------------
Revenue after financial
instruments, royalties
and other income 80,928 63,478 94,891 76,869
Net earnings (loss) 17,370 (16,069) (5,478) 17,041
Earnings (loss) per Trust Unit(2)
Basic 0.22 (0.20) (0.07) 0.22
Diluted 0.22 (0.20) (0.07) 0.22
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) The quarterly financial information prior to the second 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.
(2) Earnings (loss) per unit presented for all periods prior to the
fourth quarter 2005 are based on the outstanding Trust Units of
79,133,395 at April 1, 2005.


Please refer to the Results of Operations for the change from the first
quarter of 2006 to the second quarter of 2006.

LIQUIDITY AND CAPITAL RESOURCES

------------------------------------------------------------------------
(thousand dollars) June 30, 2006 December 31, 2005
------------------------------------------------------------------------
Working capital deficit 13,393 75,302
Long-term debt 252,054 108,375
Unit-based compensation liability -
long-term portion 3,717 2,876
------------------------------------------------------------------------
Net debt (including long-term
unit-based compensation liability) 269,164 186,553
Unitholders' equity 540,097 462,365
------------------------------------------------------------------------
Total 809,261 648,918
------------------------------------------------------------------------
------------------------------------------------------------------------


Working Capital

The decrease in the working capital deficit from $75.3 million as at December 31, 2005 to $13.4 million as at June 30, 2006 is due mainly to the decline in distributions payable from $68.1 million as at December 31, 2005 to $18.3 million as at June 30, 2006. The distributions payable at December 31, 2005 were significantly higher due to the special distribution of $0.55 per Trust Unit declared in December 2005. In addition, financial instruments were in a gain position of $3.5 million as at June 30, 2006 as compared to a loss position of $3.4 million as at December 31, 2005.

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

Long-term Debt

Trilogy's bank debt outstanding from a $370 million committed credit facility was $252 million as at June 30, 2006. The size of Trilogy's credit facility is based on the value of Trilogy's petroleum and natural gas assets.

Unit-based Compensation Liability

Unit-based compensation liability represents the accrued compensation expense relating to the unit appreciation plan discussed in the interim consolidated financial statements. This liability is the estimated value of outstanding unit appreciation rights as at the balance sheet dates, which consists of the appreciation value of vested unit rights and amortized appreciation value of unvested unit rights over the vesting period. This amount is periodically revalued with respect to outstanding unit rights due to the fluctuation in the market price of Trust Units and the decrease in the elapsed period of unvested unit rights.

Contractual Obligations

There were no significant changes to the Trust's contractual obligations as at December 31, 2005 except for the settlement of expired and the signing of new commodity contracts as disclosed in the interim consolidated financial statements. In addition, the Trust has entered into a drilling contract with a service provider which is effective for the period April 1, 2006 through March 31, 2008. Trilogy's total commitment under this contract is approximately $3.4 million per year with a maximum take or pay commitment of approximately $1.6 million per year.

Trust Units

On March 31, 2006, the Trust completed the acquisition of all of the shares of Redsky for a consideration of 6,500,000 Trust Units pursuant to a plan of arrangement. The acquisition was valued at $19.03 per Trust Unit issued, before Trust Unit issuance costs (estimated at $0.7 million).

As at June 30, 2006 and August 7, 2006, the Trust had 91,633,395 Trust Units and 91,652,301 outstanding, respectively.



Funds Flow from Operations and Cash Distributions

------------------------------------------------------------------------
Three Months Six Months
(thousand dollars except where Ended June 30 Ended June 30
stated otherwise) 2006 2005 2006 2005
------------------------------------------------------------------------
Cash flows from operating
activities 40,027 16,606 134,517 44,504
Net changes in operating
working capital 39,073 43,882 8,903 59,992
------------------------------------------------------------------------
Funds flow from operations(1) 79,100 60,488 143,420 104,496
------------------------------------------------------------------------
Distributions declared(2) 59,561 37,984 125,037 37,984
Distribution payout
percentage 75 63 87 -
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Please refer to the advisories on non-GAAP measures towards the end
of this MD&A.
(2) Distributions to unitholders commenced only after the transfer of
the Trust Assets to the Trust on April 1, 2005.


Funds flow from operations increased from the second quarter of 2005 to the same quarter of the current year due mainly to realized gains on financial instruments of $31.8 million in the current quarter versus $1.0 million in the previous quarter. 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 Outlook and Sensitivity Analysis section of this MD&A.

Trilogy's approach is to maximize distributable earnings to Unitholders. The amount of distributions in the future is highly dependent upon the amount of funds flow to be generated from operations. Please refer to the Income Taxes section of this MD&A for the taxability of the Trust and its Unitholders.



Capital Expenditures

------------------------------------------------------------------------
Three Months Six Months
Ended June 30 Ended June 30
(thousand dollars) 2006 2005 2006 2005
------------------------------------------------------------------------
Land 11,150 2,463 17,021 5,104
Geological and geophysical 404 114 1,212 1,323
Drilling 2,621 9,160 57,928 44,166
Production equipment and
facilities 10,409 3,689 23,950 18,474
------------------------------------------------------------------------
Exploration and development 24,584 15,426 100,111 69,067
expenditures
Proceeds received from
property dispositions - (87) - (172)
Property acquisitions(1) 401 - 401 -
Other 531 811 609 1,364
------------------------------------------------------------------------
Net capital expenditures 25,516 16,150 101,121 70,259
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Excluding the non-cash acquisition of Redsky through the issuance of
6,500,000 Trust Units


Exploration and development expenditures increased from the six months ended June 30, 2005 to the same period of the current year due primarily to the increase in development activities, expansion relating to new acquisitions and the rising costs of services. Expenditures for the quarter ending June 30, 2006 increased over 2005 because of higher land purchases.



Wells Drilled

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

(number of Three Months Ended June 30 Six Months Ended June 30
wells) 2006 2005 2006 2005
------------------------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
Natural
gas 6.0 4.8 4.0 2.6 43.0 35.3 31.0 27.5
Oil - - 1.0 1.0 - - 4.0 3.0
Dry 1.0 1.0 - - 4.0 4.0 3.0 1.5
------------------------------------------------------------------------
Total 7.0 5.8 5.0 3.6 47.0 39.3 38.0 32.0
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) "Gross" wells means the number of wells in which Trilogy has a
working interest or a royalty interest that may be converted into
a working interest.
(2) "Net" wells means the aggregate number of wells obtained by
multiplying each gross well by Trilogy's percentage of working
interest.


INCOME TAXES

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

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

Canadian Taxpayers

The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and accordingly, Trust Units are qualified investments for Registered Retirement Savings Plans, Registered Retirement Income Funds, Registered Education Savings Plans and Deferred Profit Sharing Plans (subject to the specific provisions of any of these particular plans). To the best of our knowledge, Trilogy's foreign ownership level currently is approximated to be 13 percent. The Trust will continue to monitor the progress of any legislative changes to maintain its mutual fund trust status.

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

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

Unitholders in the United States are advised to seek tax and legal advice from their professional advisors.

RELATED PARTY TRANSACTIONS

As described in more detail in the Trust's interim consolidated financial statements for the three months ended June 30, 2006, the following is a summary of the Trust's transactions with related parties:

- Paramount Resources, a wholly-owned subsidiary of Paramount (which owns 16.4 percent of the outstanding Trust Units at June 30, 2006), provides administrative and operating services to the Trust and its subsidiaries, pursuant to an agreement dated April 1, 2005, to assist Trilogy Energy Ltd. in carrying out its duties and obligations as general partner of Trilogy Energy LP and as the administrator of the Trust and Trilogy Holding Trust. The amount of expenses recorded for such services was $0.7 million for the three months ended June 31, 2006 ($1.3 million for the six months ended June 30, 2006). The parties have extended the terms of this agreement until March 31, 2007.

- In addition, the Trust and Paramount had transactions with each other arising from normal business activities, including a Crown royalty deposit claim of $5.5 million which, when refunded to Paramount, will be collected by the Trust.

The net amount due from Paramount arising from the above related party transactions as at June 30, 2006 was $2.4 million.

The Trust also had distributions payable to Paramount amounting to $3.0 million at June 30, 2006.

OUTLOOK AND 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. Volatility in commodity prices creates uncertainty as to the Trust's cash flow and capital expenditure budget. The Trust will assess results throughout the year and revise estimates as necessary to reflect current information. The analysis below reflects the magnitude of the sensitivities on the Trust's funds flow for the remaining six months ending December 31, 2006 using the following base assumptions:



------------------------------------------------------------------------
Average Production
------------------------------------------------------------------------
Natural gas 128,000 Mcf/d
Crude oil/liquids 4,800 Bbl/d
Average Prices
------------------------------------------------------------------------
Natural gas Cdn$6.30/Mcf
Crude oil/liquids U.S.$65.83/Bbl
------------------------------------------------------------------------
Exchange rate (U.S.$/Cdn$) $0.87
------------------------------------------------------------------------
------------------------------------------------------------------------


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

------------------------------------------------------------------------
Estimated
Effect on Cash
Flow
Sensitivity (million dollars)
------------------------------------------------------------------------
Natural gas price change of $0.10/Mcf 1.5
Oil and natural gas liquids price change of
U.S.$1.00/Bbl (WTI) 0.1
U.S. dollar to Canadian dollar exchange rate
fluctuation of $0.01 1.4
Average interest rate change of 1% 2.5
------------------------------------------------------------------------
------------------------------------------------------------------------


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 critical accounting estimates that are inherent in the preparation of the Trust's consolidated financial statements and notes thereto are discussed in the consolidated financial statements for the nine months ended December 31, 2005. In addition, the following critical accounting estimate was used during the six months ended June 30, 2006.

Purchase Price Allocation

Corporate acquisitions are accounted for by the purchase method of accounting whereby the purchase price is allocated to the assets and liabilities acquired based on their fair value, as estimated by management at the time of acquisition. The excess of the purchase price over the fair value represents goodwill. In order to estimate fair values, management has to make various assumptions, including commodity prices and discount rates. Differences from these estimates may impact the future financial statements of the Trust.

RISKS AND UNCERTAINTIES

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

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

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

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

ADVISORIES

Forward-looking Statements and Estimates

Certain statements included in this press release constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this press release include but are not limited to capital expenditures, business strategy and objectives, net revenue, future production levels, development plans and the timing thereof, operating and other costs, royalty rates, etc.

Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. In addition to other assumptions identified in this press release, assumptions have been made regarding, among other things:

- the ability of Trilogy to obtain equipment, services and supplies in a timely manner to carry out its activities;

- the ability of Trilogy to market oil and natural gas successfully to current and new customers;

- the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation;

- the timely receipt of required regulatory approvals;

- the ability of Trilogy to obtain financing on acceptable terms;

- currency, exchange and interest rates; and

- future oil and gas prices.

Although Trilogy believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Trilogy can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Trilogy and described in the forward-looking statements or information. These risks and uncertainties include but are not limited to:

- the ability of management to execute its business plan;

- the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand;

- risks and uncertainties involving geology of oil and gas deposits;

- risks inherent in Trilogy's marketing operations, including credit risk;

- the uncertainty of reserves estimates and reserves life;

- the uncertainty of estimates and projections relating to production, costs and expenses;

- potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

- Trilogy's ability to enter into or renew leases;

- fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;

- health, safety and environmental risks;

- uncertainties as to the availability and cost of financing;

- the ability of Trilogy to add production and reserves through development and exploration activities;

- general economic and business conditions;

- the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;

- uncertainty in amounts and timing of royalty payments;

- risks associated with existing and potential future law suits and regulatory actions against Trilogy;

- hiring/maintaining staff; and

- other risks and uncertainties described elsewhere in this press release or in Trilogy's other filings with Canadian securities authorities.

The forward-looking statements or information contained in this press release are made as of the date hereof and Trilogy undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Non-GAAP Measures

In this press release, Trilogy uses the term "funds flow from operations" and "funds flow from operations per unit of sales volume", collectively the "Non-GAAP measures", as indicators of Trilogy's financial performance. The Non-GAAP measures do not have a standardized meaning prescribed by GAAP and, therefore, are unlikely to be comparable to similar measures presented by other issuers.

"Funds flow from operations" refers to the cash flows from operating activities before net changes in operating working capital. Management of Trilogy believes that "funds flow from operations" provides useful information to investors as an indicative measure of performance. The most directly comparable measure to "funds flow from operations" calculated in accordance with GAAP is the cash flows from operating activities. "Funds flow from operations" can be reconciled to cash flows from operating activities by adding (deducting) the net change in working capital as shown in the consolidated statements of cash flows.

Investors are cautioned that the Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, as set forth above, or other measures of financial performance calculated in accordance with GAAP.

Numerical References

All references in this press release are to Canadian dollars unless otherwise indicated.

This press release contains disclosures expressed as "Boe", "MBoe", "Boe/d", "Mcf", "Mcf/d", "MMcf", "MMcf/d", and "Bcf" All oil and natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

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, including Trilogy's Annual Information Form, is available at www.sedar.com.



TRILOGY ENERGY TRUST

CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited)
AS AT AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2006


Consolidated Balance Sheets (Unaudited)
(thousands of dollars)

As at June 30, 2006 December 31, 2005
------------------------------------------------------------------------
ASSETS
Current Assets
Accounts receivable $ 51,187 $ 73,001
Due from related party (note 11) 2,406 6,439
Financial instruments (note 10) 10,408 5,830
Prepaid expenses 3,479 899
------------------------------------------------------------------------
67,480 86,169

Property, plant and equipment (note 4) 835,273 672,224

Goodwill 19,400 19,400
------------------------------------------------------------------------
$ 922,153 $ 777,793
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued
liabilities $ 50,068 $ 78,334
Distributions payable (note 11) 18,327 68,107
Unit-based compensation liability
(note 9) 5,536 5,810
Financial instruments (note 10) 6,942 9,220
------------------------------------------------------------------------
80,873 161,471
------------------------------------------------------------------------

Long-term debt (note 5) 252,054 108,375
Unit-based compensation liability
- net of current portion (note 9) 3,717 2,876
Asset retirement obligations (note 6) 45,412 42,706
------------------------------------------------------------------------
301,183 153,957
------------------------------------------------------------------------

Commitments and contingencies
(notes 10, 13 and 15)

Unitholders' equity
Unitholders' capital (note 7) 673,839 550,144
Contributed surplus (note 9) 1,599 468
Accumulated earnings 181,459 102,516
Accumulated distribution (note 8) (315,800) (190,763)
------------------------------------------------------------------------
540,097 462,365
------------------------------------------------------------------------
$ 922,153 $ 777,793
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


TRILOGY ENERGY TRUST
Consolidated Statements of Earnings (Loss) and Accumulated Earnings
(Unaudited)
(thousand dollars except per unit information)

Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
(Note 1)
------------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 105,663 $ 111,929 $ 231,402 $ 217,897
Realized gain (loss) on
financial instruments
(note 10) 31,798 953 31,276 (1,333)
Unrealized gain (loss) on
financial instruments
(note 10) (23,446) (6,848) 6,855 (21,783)
Royalties (24,693) (25,502) (56,634) (50,771)
Other income 128 396 384 396
------------------------------------------------------------------------
89,450 80,928 213,283 144,406
------------------------------------------------------------------------
Expenses
Operating 23,436 16,242 43,365 32,365
Transportation 5,176 5,470 9,676 10,275
General and administrative
(notes 9 and 11) 3,445 4,665 5,746 10,718
Exploration expenditures 1,400 1,982 9,186 5,989
Accretion on asset
retirement obligations
(note 6) 894 1,204 1,773 2,869
Depletion and depreciation 32,201 31,683 60,556 67,404
Interest 3,079 2,312 5,038 4,838
Other nonrecurring expenses - - - 16,296
------------------------------------------------------------------------
69,631 63,558 135,340 150,754
------------------------------------------------------------------------

Earnings before taxes 19,819 17,370 77,943 (6,348)
------------------------------------------------------------------------
Taxes (note 12)
Future income tax recovery - - - (2,268)
Large Corporation Tax and
other - - - 410
------------------------------------------------------------------------
- - - (1,858)
------------------------------------------------------------------------
Net earnings (loss) 19,819 17,370 77,943 (4,490)
Accumulated earnings,
beginning of period 160,640 - 102,516 -
Loss allocated to net
investment by Paramount
Resources Ltd. - - - 21,860
------------------------------------------------------------------------
Accumulated earnings, end
of period $ 180,459 $ 17,370 $ 180,459 $ 17,370
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings (loss) per Trust
Unit
- Basic $ 0.22 $ 0.22 $ 0.88 $ (0.06)
- Diluted $ 0.22 $ 0.22 $ 0.88 $ (0.06)
------------------------------------------------------------------------
------------------------------------------------------------------------

Weighted average Trust
Units outstanding
(in thousands) (note 7)
- Basic 91,633 79,133 88,437 79,133
- Diluted 91,633 79,133 88,441 79,133
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

The financial statements for the six months ended June 30, 2005 include
the operating results prior to the commencement of Trilogy's commercial
operations on April 1, 2005, and these results were prepared on a
carve-out basis from Paramount. As described in note 1, these financial
statements may not be indicative of the results that would have been
attained if the Trust had operated as a stand-alone entity prior to
April 1, 2005.


TRILOGY ENERGY TRUST
Consolidated Statements of Cash Flows (Unaudited)
(thousand dollars)

Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
(Note 1)
------------------------------------------------------------------------
Operating activities
Net earnings (loss) $ 19,819 $ 17,370 $ 77,943 $ (4,490)
Add (deduct) non-cash and
other items:
Depletion and depreciation 32,201 31,683 60,556 67,404
Accretion on asset
retirement obligations 894 1,204 1,773 2,869
Exploration expenditures 1,216 1,850 8,703 5,574
Asset retirement obligation
expenditures (316) (71) (399) (598)
Non-cash general and
administrative expenses 1,840 1,604 1,699 2,636
Non-cash (gain) loss on
financial instruments 23,446 6,848 (6,855) 21,783
Future income tax recovery - - - (2,268)
Other nonrecurring expenses - - - 11,586
------------------------------------------------------------------------
Funds flow from operations 79,100 60,488 143,420 104,496
Net change in operating
working capital (39,073) (43,882) (8,903) (59,992)
------------------------------------------------------------------------
40,027 16,606 134,517 44,504
------------------------------------------------------------------------
Financing activities
Credit facility - draws 215,862 312,404 568,007 312,404
Credit facility -
repayments (144,343) (84,911) (425,124) (84,911)
Distributions to
unitholders (64,143) (25,323) (174,817) (25,323)
Payment to Paramount
Resources Ltd. upon the
formation of the Trust - (220,000) - (220,000)
Net investment by Paramount
Resources Ltd. - - - (13,869)
------------------------------------------------------------------------
7,376 (17,830) (31,934) (31,699)
------------------------------------------------------------------------
Investing activities
Property, plant and
equipment expenditures (25,115) (16,237) (100,721) (70,431)
Property, plant and
equipment acquisitions (401) - (401) -
Proceeds on sale of
property, plant and
equipment - 87 - 172
Net change in investing
working capital (21,887) 17,374 (8,365) 57,454
------------------------------------------------------------------------
(47,403) 1,224 (109,487) (12,805)
------------------------------------------------------------------------
Cash acquired from Redsky
Energy Ltd. (note 3) - - 6,904 -
------------------------------------------------------------------------

Change in cash / cash, end
of period $ - $ - $ - $ -
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash interest paid $ 4,430 $ 2,652 $ 6,269 $ 4,838
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

The financial statements for the six months ended June 30, 2005 include
the operating results prior to the commencement of Trilogy's commercial
operations on April 1, 2005, and these results were prepared on a
carve-out basis from Paramount. As described in note 1, these financial
statements may not be indicative of the results that would have been
attained if the Trust had operated as a stand-alone entity prior to
April 1, 2005.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006
(tabular amounts expressed in thousands of dollars except per unit
information)


1. GENERAL

Trilogy Energy Trust ("Trilogy" or 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, as amended and restated as of April 1, 2005 and May 9, 2006. 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").

The interim consolidated financial statements of Trilogy have been prepared in accordance with Canadian generally accepted accounting principles. The Trust acquired its initial operating assets from Paramount Resources Ltd. ("Paramount") effective April 1, 2005. Accordingly, the comparative financial statements for the six months ended June 30, 2005 include 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.

As a result of the basis of presentation described above, the comparative financial statements for the six months ended June 30, 2005 may not be indicative of the results that would have been attained if the Trust had operated as a stand-alone entity prior to April 1, 2005.

2. SIGNIFICANT ACCOUNTING POLICIES

The unaudited interim consolidated financial statements of the Trust follow the same accounting policies and basis of presentation as the audited consolidated financial statements as at and for the nine months ended December 31, 2005 (the "Audited Financial Statements"). These interim financial statement note disclosures do not include all of those required by Canadian generally accepted accounting principles applicable for annual financial statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the Audited Financial Statements.

Trilogy's consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries, Trilogy Holding Trust, Trilogy Energy LP, Trilogy Energy Ltd., and new subsidiaries Trilogy Redsky LP, Trilogy Redsky Ltd. and 1230901 Alberta Ltd. established in connection with the acquisition of Redsky Energy Ltd. ("Redsky").

3. ACQUISITION

On March 31, 2006, Trilogy completed the acquisition of all of the shares of Redsky for a consideration of 6,500,000 Trilogy Trust Units pursuant to a plan of arrangement. The consolidated financial statements include the operating results of Redsky from April 1, 2006.

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



------------------------------------------------------------------------
Net assets acquired
------------------------------------------------------------------------
Working capital (net of cash of $6.9 million) (5,461)
Petroleum and natural gas properties 130,451
Asset retirement obligation (595)
------------------------------------------------------------------------
124,395
------------------------------------------------------------------------
Consideration
------------------------------------------------------------------------
Units issued 123,695
Estimated costs 700
------------------------------------------------------------------------
Estimated purchase price 124,395
------------------------------------------------------------------------
------------------------------------------------------------------------

4. PROPERTY, PLANT AND EQUIPMENT

------------------------------------------------------------------------
June 30, 2006
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------------------------------------------

Petroleum and natural gas properties 1,347,713 (514,037) 833,676
Other 2,031 (434) 1,597
------------------------------------------------------------------------
1,349,744 (514,471) 835,273
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
December 31, 2005
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------------------------------------------
Petroleum and natural gas properties 1,125,973 (454,964) 671,009
Other 1,423 (208) 1,215
------------------------------------------------------------------------
1,127,396 (455,172) 672,224
------------------------------------------------------------------------
------------------------------------------------------------------------


Capital costs totaling approximately $149.3 million as at June 30, 2006 ($72.1 million as at December 31, 2005) are not subject to depletion.

5. LONG-TERM DEBT

The Trust has a $335 million extendable revolving credit facility and a $35 million working capital facility with a syndicate of Canadian banks. 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 facilities are available on a revolving basis for a period of at least 364 days and can be extended a further 364 days upon request. In the event the revolving period is not extended, the facility would be available on a non-revolving basis for a one year term, at the end of which time amounts drawn down under the facility would be due and payable. Advances drawn on the Trust's facility are secured by a fixed and floating charge debenture over the assets of the Trust. The amount drawn from the credit facilities totaled $252 million as at June 30, 2006. The weighted average interest rate under this facility for the six months ended June 30, 2006 was 4.89%. The $370 million borrowing base is subject to semi-annual review by the banks.

The Trust has undrawn letters of credit totaling $9.3 million as at June 30, 2006. These letters of credit reduce the amount available under the Trust's working capital facility.



6. ASSET RETIREMENT OBLIGATIONS

------------------------------------------------------------------------
Three Months Six Months Ended
Ended June 30, 2006 June 30, 2006
------------------------------------------------------------------------
Asset retirement obligations,
beginning of period 44,691 42,706
Liabilities incurred 143 737
Liabilities settled (316) (399)
Accretion expense 894 1,773
Redsky acquisition (note 3) - 595
------------------------------------------------------------------------
Asset retirement obligations, end
of period 45,412 45,412
------------------------------------------------------------------------
------------------------------------------------------------------------


The undiscounted asset retirement obligation at June 30, 2006 is estimated to be $194.6 million (December 31, 2005 - $189.1 million). The Trust's credit-adjusted risk-free rate is 7.875%. These obligations will be settled over the expected life of the underlying assets, the majority of which are expected to be paid after 10 to 45 years and will be funded from the general resources of the Trust at the time of removal.

7. 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, 2006:



------------------------------------------------------------------------
Number of Units Amount
------------------------------------------------------------------------
Balance at December 31, 2005 85,133,395 550,144
Trust Units issued for the acquisition of
Redsky, net of estimated issuance
costs (note 3) 6,500,000 123,695
------------------------------------------------------------------------
Balance at June 30, 2006 91,633,395 673,839
------------------------------------------------------------------------
------------------------------------------------------------------------


Per Trust Unit Information

Earnings (loss) per Trust Unit for the six months ended June 30, 2005
were calculated using the number of Trust Units outstanding as at April
1, 2005.

8. ACCUMULATED DISTRIBUTIONS

------------------------------------------------------------------------
Three Months Six Months Ended
Ended June 30, 2006 June 30, 2006
------------------------------------------------------------------------
Balance at beginning of period 256,239 190,763
Distributions declared for the
period 59,561 125,037
------------------------------------------------------------------------
Balance at end of Period 315,800 315,800
------------------------------------------------------------------------
------------------------------------------------------------------------


On June 21, 2006, Trilogy adopted a Distribution Reinvestment Plan (the "DRIP") which provides eligible unitholders with the opportunity to reinvest their cash distributions, on each distribution payment date, in additional trust units at a price equal to 95% of the average market price. Eligible holders of 1,676,387 Trust Units have elected to participate in the DRIP with the monthly cash distribution payable on July 17, 2006.

On July 19, 2006, Trilogy announced that its cash distribution for July 2006 will be $0.20 per Trust Unit. The distribution is payable on August 15, 2006 to unitholders of record on July 31, 2006.

9. UNIT BASED COMPENSATION

Unit Appreciation Plan

On April 1, 2005, the Trust offered certain employees, officers and directors a unit appreciation arrangement whereby such employees, officers and directors were granted appreciation units entitling the appreciation unitholders to receive cash payments calculated as the excess of the market price over the exercise price per appreciation unit on the exercise date. The exercise price per appreciation unit 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. The appreciation units vest at subsequent anniversary dates with a termination date of December 15, 2008. A continuity of the unit appreciation rights for the three and six months ended June 30, 2006, is as follows:



------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, 2006 June 30, 2006
------------------------------------------------------------------------
No. of No. of
Exercise Unit Exercise Unit
Price Rights Price Rights
------------------------------------------------------------------------
Balance at beginning of period $ 7.01 1,296,250 $ 7.76 1,306,000
Exercised $ 6.76 (6,000) $ 6.87 (6,750)
Cancelled - - $ 7.76 (9,000)
------------------------------------------------------------------------
Balance at end of period $ 6.36 1,290,250 $ 7.76 1,290,250
------------------------------------------------------------------------
------------------------------------------------------------------------
Unit rights exercisable at end
of period $ 6.36 223,250 $ 6.36 223,250
------------------------------------------------------------------------
------------------------------------------------------------------------


A compensation expense of $1.3 million relating to the unit appreciation plan has been recognized in earnings for the three months ended June 30, 2006 ($0.6 million for the six months ended June 30, 2006), resulting from the mark-to-market valuation of the related unit-based compensation liability.

Unit Option Plan

The Trust has implemented a long-term incentive plan that allows management to award unit options to eligible directors, officers and employees. A total of 1,096,000 options with a weighted average strike price of $18.50 have been granted under the option plan as at June 30, 2006. The majority of these options will vest in 2009 and 2010, and expire on April 30, 2011. No options are exercisable as at June 30, 2006.

The Trust has accounted for its unit option plan using the fair value method and has recorded a compensation expense of $0.1 million for the three months ended June 30, 2006 ($0.3 million for the six months ended June 30, 2006), with a corresponding credit to contributed surplus. The weighted average fair value of the options that were granted was $2.23 per unit and was determined under the binomial model using the following key assumptions:



Risk-free interest rate - 3.90%
Expected life - 4.5 years
Expected volatility - 30.00%
Expected distributions - 14.00%


Non-reciprocal Awards to Trust Employees

The Trust also recognized compensation expense of $0.4 million for the three months ended June 30, 2006 ($0.8 million for the six months ended June 30, 2006) with respect to the non-reciprocal awards of stock options to Trust employees made by Paramount. This amount was also credited to contributed surplus.

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, 2006, the Trust has outstanding financial forward arrangements as follows:



------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Sales Contracts
AECO Call Option 20,000 GJ/d $12.50 April 2006 - October 2006
AECO Fixed Price 10,000 GJ/d $ 7.96 April 2006 - October 2006
NYMEX Fixed Price 10,000 MMBtu/d $10.14US November 2006 - March 2007
NYMEX Fixed Price 10,000 MMBtu/d $10.37US November 2006 - March 2007
NYMEX Fixed Price 10,000 MMBtu/d $11.16US November 2006 - March 2007
NYMEX Fixed Price 10,000 MMBtu/d $10.19US November 2006 - March 2007
NYMEX Fixed price 10,000 MMBtu/d $10.26US November 2006 - March 2007
WTI Fixed Price 1,000 Bbl/d $66.04US February 2006 - December 2006
WTI Fixed Price 1,000 Bbl/d $65.64US February 2006 - December 2006
WTI Fixed Price 1,000 Bbl/d $68.05US February 2006 - December 2006
WTI Fixed Price 1,000 Bbl/d $68.02US February 2006 - December 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 indicators and forecasts. The fair values of forward financial contracts recognized as at June 30, 2006 are as follows:



------------------------------------------------------------------------
Financial instrument asset 10,408
Financial instrument liability (6,942)
------------------------------------------------------------------------
Net financial instrument asset (liability) 3,466
------------------------------------------------------------------------
------------------------------------------------------------------------


The changes in the fair value associated with the above financial instruments are recorded as unrealized gains or losses on financial instruments in the statement of earnings. Gains or losses arising from monthly settlement with counterparties are recognized as realized gains or losses in the statement of earnings.

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 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 credit facilities as disclosed in note 5.

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 was initially in effect until March 31, 2006 and was extended until March 31, 2007, but may be terminated by either party with at least six months written notice. The amount of expenses recorded as management fees under this agreement was $0.7 million for the three months ended June 30, 2006 ($1.3 million for the six months ended June 30, 2006). This amount is included as part of the general and administrative expenses in the Trust's consolidated statement of earnings.

The Trust and Paramount also had transactions with each other arising from normal business activities, including a Crown royalty deposit claim of $5.5 million which, when refunded to Paramount, will be collected by the Trust.

The net amount due from Paramount arising from the above related party transactions as at June 30, 2006 was $2.4 million.

Trilogy also has distributions payable to Paramount of $3.0 million as at June 30, 2006.

12. INCOME TAXES

No provision for income taxes has been made by the Trust since the transfer of the Trust Assets to the Trust on April 1, 2005. The income taxes for the six months ended June 30, 2005 were calculated for the period prior to April 1, 2005 on a carve-out basis from Paramount.

13. COMMITMENTS

In addition to the commitments disclosed in the Audited Financial Statements and the commitments on the financial instrument contracts disclosed in notes 10 and 15, the Trust has entered into a drilling contract with a service provider which is effective April 1, 2006 through March 31, 2008. Trilogy's total commitment under this contract is approximately $3.4 million per year with a maximum take or pay commitment of approximately $1.6 million per year.



The following physical commodity contracts were outstanding as at June
30, 2006:

------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Sales Contract
AECO Fixed Price 30,000 GJ/d $ 6.50 July 2006 - October 2006

Purchase Contract
AECO Fixed Price 30,000 GJ/d $ 5.18 July 2006 - August 2006
------------------------------------------------------------------------
------------------------------------------------------------------------


14. COMPARATIVE FIGURES

Certain accounts in comparative financial statements have been
reclassified to conform to the current period financial statements.

15. SUBSEQUENT EVENTS

The Trust entered into the following financial contracts subsequent to
June 30, 2006:

------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Sales Contracts
NYMEX Fixed Price 10,000 MMBtu/d $ 10.00 US November 2006 - March 2007
NYMEX Fixed Price 10,000 MMBtu/d $ 10.88 US November 2006 - March 2007

Purchase Contracts
NYMEX Fixed Price 10,000 MMBtu/d $ 9.42 US November 2006 - March 2007
NYMEX Fixed Price 10,000 MMBtu/d $ 9.42 US November 2006 - March 2007
------------------------------------------------------------------------
------------------------------------------------------------------------


Some of the above contracts were used to offset the following financial
contracts outstanding at June 30, 2006 which also required a total
payment to Trilogy of US$2.4 million:

------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Sales Contract
NYMEX Fixed Price 10,000 MMBtu/d $ 10.19 US November 2006 - March 2007
NYMEX Fixed Price 10,000 MMBtu/d $ 10.26 US November 2006 - March 2007
------------------------------------------------------------------------
------------------------------------------------------------------------


In addition, Trilogy entered into the following physical commodity
contracts:

------------------------------------------------------------------------
Quantity Price Term
------------------------------------------------------------------------
Sales Contract
AECO Fixed Price 10,000 GJ/d $ 6.27 August 2006 - October 2006

Purchase Contract
AECO Fixed Price 10,000 GJ/d $ 5.34 September 2006 - October 2006
------------------------------------------------------------------------
------------------------------------------------------------------------


Trilogy Energy Trust
Supplemental Oil and Gas Operating Statistics (Unaudited)
For the Period Ended June 30, 2006

Sales Volumes 2006 2005
------------------------------------------------------------------------
Q2 Q1 Q4 Q3 Q2
------------------------------------------------------------------------
Gas (MMcf/d) 118 118 116 116 117
Oil and Natural Gas Liquids
(Bbl/d) 5,103 4,990 4,826 5,154 4,780
------------------------------------------------------------------------
Total Sales Volumes (Boe/d)
(6:1) 24,827 24,605 24,109 24,404 24,287
------------------------------------------------------------------------
------------------------------------------------------------------------


Per-unit Results

------------------------------------------------------------------------
Q2 Q1 Q4 Q3 Q2
------------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, before transportation 6.81 9.18 12.05 9.31 8.15
Transportation 0.43 0.38 0.41 0.42 0.48
Royalties 1.56 2.40 2.90 1.95 1.82
Operating expenses, net of
processing revenue 1.73 1.50 1.26 1.41 1.34
------------------------------------------------------------------------
Cash netback before realized
financial instruments 3.08 4.89 7.48 5.52 4.51
Realized financial instruments 3.10 (0.06) (1.08) (0.22) 0.03
------------------------------------------------------------------------
Cash netback including realized
financial instruments 6.18 4.83 6.40 5.30 4.54
------------------------------------------------------------------------

Produced Oil & Natural Gas
Liquids ($/Bbl)
Price, before transportation 69.55 63.38 71.38 67.72 57.84
Transportation 1.18 1.00 0.84 0.79 0.86
Royalties 17.01 14.63 17.58 17.18 14.11
Operating expenses, net of
processing revenue 10.37 9.00 7.55 8.48 7.35
------------------------------------------------------------------------
Cash netback before realized
financial instruments 40.99 38.75 45.41 41.27 35.52
Realized financial instruments (3.30) 0.38 (2.18) (5.34) 1.41
------------------------------------------------------------------------
Cash netback including realized
financial instruments 37.69 39.13 43.23 35.93 36.93
------------------------------------------------------------------------

Total Produced ($/Boe)
Price, before transportation 46.77 56.78 72.11 58.08 50.82
Transportation 2.29 2.03 2.11 2.17 2.47
Royalties 10.93 14.42 17.42 12.84 11.53
Operating expenses, net of
processing revenue 10.37 9.00 7.55 8.48 7.35
------------------------------------------------------------------------
Cash netback before realized
financial instruments 23.18 31.33 45.03 34.59 29.47
Realized financial instruments 14.07 (0.24) (5.59) (2.18) 0.43
------------------------------------------------------------------------
Cash netback including realized
financial instruments 37.25 31.09 39.44 32.41 29.90
------------------------------------------------------------------------
------------------------------------------------------------------------


ADVISORIES

Readers are referred to the advisories concerning forward-looking statements, non-GAAP measures and Boe conversions under the caption "Advisories" towards the end of the MD&A.

Contact Information

  • Trilogy Energy Trust
    J.H.T. (Jim) Riddell
    President and Chief Executive Officer
    (403) 290-2900
    or
    Trilogy Energy Trust
    J. B. (John) Williams
    Chief Operating Officer
    (403) 290-2900
    or
    Trilogy Energy Trust
    M.G. (Michael) Kohut
    Chief Financial 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