Trilogy Energy Trust
TSX : TET.UN

Trilogy Energy Trust

November 07, 2006 21:20 ET

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

CALGARY, ALBERTA--(CCNMatthews - Nov. 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 nine months ended September 30, 2006.



Financial and Operating Highlights

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

Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change % 2006 2005 Change %
---------------------------------------------------------------------------
FINANCIAL
Petroleum and natural
gas sales 103,021 131,052 (21) 334,423 348,949 (4)

Funds flow(1)
From operations 56,201 68,170 (18) 199,621 172,666 16
Per unit - basic and
diluted(2) 0.61 0.86 (29) 2.23 2.18 2

Earnings
Net earnings (loss) 38,338 (2,529) 1,616 116,281 (1,228) 9,569
Per unit - basic and
diluted(2) 0.42 (0.03) 1,500 1.30 (0.02) 6,600

Distributions declared 55,221 45,106 22 180,258 83,090 117
Per unit 0.60 0.57 5 2.00 2.35 (15)
Capital expenditures
Exploration and
development 31,219 25,820 21 131,330 94,887 38
Acquisitions,
dispositions and
other(5) 24 150 (84) 131,486 1,342 9,698
Net capital
expenditures 31,243 25,970 20 262,816 96,229 173
Total assets 927,653 761,587 22 927,653 761,587 22
Net debt(3) 263,772 284,360 (7) 263,772 284,360 (7)
Unitholders' equity 537,940 340,397 58 537,940 340,397 58
Trust Units
outstanding
(thousands)
- As at September 30, 92,425 79,133 17 92,425 79,133 17
---------------------------------------------------------------------------

OPERATING
Production
Natural gas (MMcf/d) 117 116 1 118 118 -
Crude oil and natural
gas liquids (Bbl/d) 4,854 5,154 (6) 4,982 4,962 -
Total production
(Boe/d @ 6:1) 24,288 24,404 - 24,572 24,625 -
---------------------------------------------------------------------------
Average prices
Natural gas
(pre-financial
instruments) ($/Mcf) 6.58 9.31 (29) 7.52 8.30 (9)
Natural gas ($/Mcf)(4) 7.22 9.09 (21) 8.75 8.16 7
Crude oil and natural
gas liquids
(pre-financial
instruments) ($/Bbl) 72.68 67.72 7 68.54 60.29 14
Crude oil and natural
gas liquids ($/Bbl)(4) 69.32 62.38 11 66.43 59.07 12
---------------------------------------------------------------------------

Drilling activity (gross)
Gas 14 15 (7) 57 46 24
Oil 1 3 (67) 1 7 (86)
D&A 2 1 100 8 4 100
Total wells 17 19 (11) 66 57 16
Success rate 88% 95% - 88% 93% -
---------------------------------------------------------------------------

(1) Funds flow from operations is a non-GAAP term that represents net
earnings adjusted for non-cash items such as unrealized gain (loss) on
financial instruments, depletion and depreciation expense and non-cash
exploration expenditures. 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 September 30
2006 and 2005, and the nine months ended September 30, 2006 using the
weighted average number of Trust Units outstanding. For the nine
months ended September 30, 2005, the initial number of Trust Units
outstanding was used.
(3) Net debt is equal to long-term debt and the long-term portion of
unit-based compensation liability plus/minus working capital.
(4) Excludes non-cash gains and losses on financial instruments.
(5) Acquisitions, dispositions and other for the nine months ended
September 30, 2006 include the acquisition of Redsky Energy Ltd's
petroleum and natural gas properties effective March 31, 2006 at an
allocated purchase price of $130,451.


Review of Operations

Trilogy Energy Trust ("Trilogy" or "the Trust") is pleased to report its operating and financial results for the third quarter of 2006. Trilogy has been active during the quarter with a drilling, completion and construction program that we believe will add significant production in the fourth quarter. In addition, there have been a number of significant events subsequent to the end of the third quarter that will impact the Trust as we move forward.

Significant and Subsequent Events

Trilogy entered into an agreement to sell its 9.77 percent working interest in the Kaybob South Beaverhill Lake Unit No. 1 to a private company for $12 million effective July 1, 2006. This transaction closed on November 3, 2006. Production from this property averaged 172 Boe/d during the third quarter. The sale price was a significant premium to the asset value we had assigned to the property. Trilogy will continue to evaluate opportunities to rationalize non-strategic properties that do not have significant upside and have higher operating costs.

On September 3, 2006, we announced the offer to purchase all of the existing shares of Blue Mountain Energy for $5.50 per share for a total cost of approximately $142 million. The transaction closed on October 26 subject to completion of the compulsory acquisition requirements. The acquisition complements the Redsky Energy Ltd. corporate acquisition by expanding the Grande Prairie area with additional production and undeveloped land that will provide significant drilling opportunities in the future. The acquisition will add approximately 2,000 Boe/d initially which we expect will increase when the drilling program on the Blue Mountain properties begins.

On October 31, 2006 Federal Finance Minister Jim Flaherty (the "Finance Minister") announced a proposal to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the Unitholders. The Finance Minister said existing trusts would have a four-year transition period and would not be subject to the new rules until 2011. Until such rules are released in legislative form and passed into law it is uncertain what the impact of such rules will be to the Trust and its Unitholders. Trilogy is currently reviewing all of its options in conjunction with this proposal.

On October 19, 2006 Trilogy announced that it has entered into an agreement to sell to a syndicate of underwriters, on a bought deal basis, $175 million principal amount of 6.25 percent convertible unsecured subordinated debentures due November 30, 2011. Under the agreement, the Trust has granted the underwriters an option to purchase an additional $26.25 million of debentures. In light of the recent statements from the Federal Minister of Finance respecting the taxation of income trusts and the ensuing impact to the capital markets, Trilogy has decided to delay the convertible debenture closing. Trilogy remains in discussions with its underwriters and is assessing various alternatives to proceed with the offering.



Below is a list of the current outstanding financial contracts as of
November 7, 2006.

Quantity Price Term
---------------------------------------------------------------------------
Sales Contracts
NYMEX Fixed Price 50,000 MMBtu/d $10.51 US November 2006 - March 2007
WTI Fixed Price 4,000 Bbl/d $66.94 US February 2006 - December 2006
Purchase Contracts
NYMEX Fixed Price 20,000 MMBtu/d $ 8.38 US November 2006 - March 2007
NYMEX Fixed Price 20,000 MMBtu/d $ 6.66 US November 2006
---------------------------------------------------------------------------


Trilogy has stressed the importance of maintaining a strong balance sheet over the long term coincident with our goal to build a sustainable Trust. In addition, we must continually evaluate our capital spending and distribution policies to manage our operation within the context of maximizing Unitholder return and production and reserve replacement. With this objective in mind and in response to the recent decrease in gas prices, we have reduced our monthly distribution from $0.20 to $0.16 per Trust Unit effective for the November 15, 2006 payment date. At the same time we anticipate reducing our capital spending requirements to approximately $100 million for 2007. This will provide for a payout ratio in the 60 percent range using the forward strip pricing. We anticipate these cuts will maintain our balance sheet strength by operating within our anticipated cash flow in 2007.

Production

Production in the third quarter decreased from 24,827 Boe/d in the second quarter to 24,288 Boe/d (117 MMcf/d natural gas, 2,508 Bbl/d of crude oil and 2,346 Bbl/d of natural gas liquids). Lower production volumes in the third quarter reflect the corporate decline rate of approximately 2 percent per month which was not offset by new well tie ins and workovers. Lower activity levels in the second quarter are typically reflected in lower third quarter production volumes. Production is down 2,712 Boe/d from our original forecast of 27,000 Boe/d, including the Redsky assets. We were able to successfully execute our drilling and completion program in the third quarter and production levels are expected to increase in the fourth quarter, reflecting the success of the third quarter drilling, completion and construction activity.

New production volumes in the Kaybob area were delayed with the late delivery of two sour gas compressors that are required to increase gross volumes by 12 MMcf/d in the Pine Creek area. We expect to have the first compressor operational in early November and the second compressor fully functioning by the end of the year. We anticipate that this project will add approximately 1,000 Boe/d of production by the end of the year plus it will provide additional compression and transportation capacity to handle the volumes that we anticipate adding given success from our 2007 winter drilling program in this area.

Additional volumes in the Grande Prairie area are shut in as a result of processing and gathering system constraints. We expect to have negotiated alternative tie in arrangements that will add approximately 250 Boe/d before the end of the year and an additional 250 Boe/d before the end of the first quarter of 2007. We also anticipate the tie in of approximately 3 MMcf/d (500 Boe/d) in the northern Grande Prairie area which is only accessible during the winter. This project may require additional modifications to the non-operated gas plant to handle the increase in volumes.

Capital Spending

Capital spending for the quarter totaled $31.2 million bringing the year to date total to $132.4 million. Anticipated capital spending has increased to $160 million for 2006 versus the original estimate of $145 million; this 10 percent increase in capital spending is the direct result of the cost pressures that our industry has experienced to date and expect to see for the balance of the year.

Quarterly spending decisions were focused on projects that would add production volumes prior to the end of the year. The Trust actively managed the capital spending during the quarter in order to become more sustainable in the lower commodity price environment. This was accomplished with the farm out of higher risk opportunities, the reduction of our working interests in lower impact projects and deferring projects that did not have immediate land tenure issues.

Operations

Drilling and completion operations were focused in the Kaybob area during the quarter. The Trust drilled 17 (15.7 net) wells during the quarter bringing the total to 66 (55.3 net) wells for the year. This compares to 19 (15.7 net) wells in the third quarter of 2005 and the pro forma total of 57 (47.7 net) wells to the end of the third quarter of 2005. Of the wells drilled in the third quarter 14 (13.2 net) were cased for natural gas potential, 1 (1.0 net) cased for oil production and 2 (1.5 net) were dry and abandoned, for a success rate of 88 (90.4 net) percent. The completion rigs were able to complete some of the wells that were drilled in the first quarter, thereby reducing the number of wells that were standing cased at the end of the first and second quarters.

The Kaybob South Beaverhill Lake Unit No.3 work over program continued into the third quarter. These operations are expected to add incremental volumes in the fourth quarter of 2006 and first quarter of 2007 when additional gas lift compression is installed in the area.

Operating Costs

Operating costs in the quarter were $9.88/Boe as compared to $10.37/Boe in the second quarter of 2006 and $8.48/Boe in the third quarter of 2005.

As a result of the aggressive work over and coiled tubing stimulation program executed in the Simonette area during the second quarter, net production increased from 950 Boe/d to 1,220 Boe/d for the $0.9 million net expense that was incurred. Additional Simonette optimization projects, such as ESP (electrical submersible pump) installation and well bore stimulations will be conducted in the fourth quarter and first quarter 2007 with the expectation that production from this area will be held flat or increase slightly in 2007.

In spite of aggressively managing our operating costs in the past year we have not been able to totally offset the effects of rising labor and material costs experienced industry wide. As a result, we are anticipating that operating costs will remain in the $10.00/Boe range for the balance of the year as we complete the well bore suspension program in the Kaybob South Beaverhill Lake Unit No. 3. Future operating costs will be influenced by the volume of workovers and well suspensions and also by the industry activity in 2007.

Distribution Reinvestment Program

The DRIP program was implemented in June as a means to allow resident Unitholders to reinvest monthly distributions back into the Trust at a discounted price and excludes commissions. Current DRIP participation is approximately 5 percent.

Outlook

The summer of 2006 was a period of continued natural gas price volatility. Spot prices declined dramatically as natural gas storage facilities approached maximum capacity. It is expected that prices will remain weak until the winter heating season demand impacts storage and supply drops as a result of declining drilling activity for natural gas.

The Trust's strategy to be sustainable for the long term requires that we adjust our distribution policy and capital spending estimates so that we operate within cash flow. This can provide a challenge as realized prices can differ significantly from our forecast price which is used to set our capital budget and distribution rate. Ultimately we must maintain a high quality prospect inventory so that we can have attractive capital efficiencies and high recycle ratios. We believe that the original Trust assets plus the two recent acquisitions will provide this high quality inventory so that we can maintain our reserve and production replacement strategy and also distribute a significant portion of our cash flow at the same time as we maintain a strong balance sheet.

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 and its subsidiaries ("Trilogy" or the "Trust") as at and for the three and nine months ended September 30, 2006, and should be read in conjunction with the Trust's interim consolidated financial statements as at and for the three and nine months ended September 30, 2006, and the audited consolidated financial statements as at and for the nine months ended December 31, 2005 and related MD&A. The consolidated financial statements have been prepared in Canadian dollars in accordance with Canadian generally accepted accounting principles ("GAAP").

The 2005 year-to-date information in 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, November 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 then issued and outstanding Trust Units with the remaining 19 percent (16 percent at September 30, 2006) of the issued and outstanding Trust Units being held by Paramount.

CURRENT QUARTER HIGHLIGHTS

- Production for the third quarter of 2006 averaged 24,288 Boe/d, a slight decrease from the average production for the second quarter of 2006 of 24,827 Boe/d caused primarily by natural production declines and delays in bringing on production additions.

- Funds flow from operations decreased by $22.9 million due mainly to lower realized gains on financial instruments of $5.4 million in the third quarter of 2006 as against $31.8 million in the second quarter of 2006. The gain on financial instruments in the second quarter included $17.7 million from contracts that were terminated early.

- Capital expenditures totaled $31.2 million for the third quarter of 2006.

- Distributions declared to Unitholders for the third quarter of 2006 amounted to $55.2 million, of which $40.4 million was paid in cash with the remaining $14.8 million reinvested for Trust Units under Trilogy's distribution reinvestment plan.

- Trilogy initiated the cash purchase of all of the outstanding shares, options and warrants of Blue Mountain Energy Ltd. ("Blue Mountain") with an estimated purchase price of $142 million. This acquisition is expected to add production of approximately 2,000 Boe/d when all of the assets are fully integrated to Trilogy.

SUBSEQUENT EVENTS

Blue Mountain Acquisition

On October 26, 2006, Trilogy completed the acquisition of all issued and outstanding Blue Mountain shares for a cash purchase price of $5.50 per Blue Mountain share plus the repayment of Blue Mountain's debt totaling approximately $20.4 million. The total aggregate estimated cost of this acquisition is $142.0 million. The acquisition was funded with amounts drawn on the existing and bridge credit facilities. As at September 30, 2006, Trilogy had acquired 479,300 shares of Blue Mountain from the open market representing 2.2 percent of the issued and outstanding shares of Blue Mountain.

Convertible Debenture

On October 19, 2006 Trilogy announced that it has entered into an agreement to sell to a syndicate of underwriters, on a bought deal basis, $175 million principal amount of 6.25 percent convertible unsecured subordinated debentures due November 30, 2011. Under the agreement, the Trust has granted the underwriters an option to purchase an additional $26.25 million of debentures. In light of the recent statements from the Federal Minister of Finance respecting the taxation of income trusts and the ensuing impact to the capital markets, Trilogy has decided to delay the convertible debenture closing. Trilogy remains in discussions with its underwriters and is assessing various alternatives to proceed with the offering.



Financial Instruments

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

---------------------------------------------------------------------------
Quantity Price Term
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Purchase Contracts
NYMEX Fixed Price 10,000 MMBtu/d $ 7.46 US November 2006
NYMEX Fixed Price 10,000 MMBtu/d $ 5.85 US November 2006
NYMEX Fixed Price 10,000 MMBtu/d $ 7.59 US November 2006 - March 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Income Tax Proposals

The Federal Government of Canada has announced new income tax proposals
which, if enacted, will impact the taxability of the Trust and its
Unitholders. Please see the Income Taxes Section of this MD&A.

RESULTS OF OPERATIONS

Third Quarter 2006 vs. Second Quarter 2006

---------------------------------------------------------------------------
(thousand dollars except as otherwise
indicated) Q2 2006 Change Q3 2006
---------------------------------------------------------------------------
Average sales volumes:
Natural gas (Mcf/d) 118,344 (1,741) 116,603
Oil and natural gas liquids (Bbl/d) 5,103 (249) 4,854
---------------------------------------------------------------------------
Total (Boe/d) 24,827 (539) 24,288
---------------------------------------------------------------------------
Average prices before realized financial
instruments and transportation:
Natural gas ($/Mcf) 6.81 (0.23) 6.58
Oil and natural gas liquids ($/Bbl) 69.55 3.13 72.68
---------------------------------------------------------------------------
Average prices after realized financial
instruments and before transportation:
Natural gas ($/Mcf) 9.91 2.69 7.22
Oil and natural gas liquids ($/Bbl) 66.25 3.07 69.32
---------------------------------------------------------------------------

Petroleum and natural gas sales before
financial instruments:
Natural gas 73,364 (2,798) 70,566
Oil and natural gas liquids 32,299 156 32,455
---------------------------------------------------------------------------
105,663 (2,642) 103,021
---------------------------------------------------------------------------
Gain on financial instruments(1) (8,352) (19,652) (28,004)
Royalties 24,693 (3,758) 20,935
Operating costs 23,436 (1,350) 22,086
Transportation costs 5,176 (377) 4,799
Depletion and depreciation 32,201 390 32,591
General and administrative expenses 3,445 (2,252) 1,193
Interest 3,079 115 3,194
Exploration expenditures 1,400 7,034 8,434
Other expenditures (net of other income) 766 (1,311) (545)
---------------------------------------------------------------------------
Net earnings 19,819 18,519 38,338
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1)See Risk Management section.


Petroleum and Natural Gas Sales - Natural gas sales, before financial instruments, decreased by $2.5 million and $0.3 million due to lower average sales prices and sales volumes, respectively. Oil and natural gas liquid sales, before financial instruments, increased by $1.5 million due to higher average sales prices, offset by a decrease of $1.3 million due to lower sales volume. The decreases in sales volumes are mainly due to production declines and delays in bringing on production additions.

Royalties - As a percentage of petroleum and natural gas sales, royalties averaged 20 percent for the third quarter of 2006 as compared to 23 percent for the second quarter of 2006. The decrease is mainly the result of changes in the difference between the corporate price and the Alberta Reference Price on which royalties are calculated, and low productivity royalty credits received. 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. This variability in price further impacts the royalty rate due to certain credits that reduce gross royalties.

Operating Costs - The decrease 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 decreased to $9.88/Boe in the third quarter of 2006 from $10.37/Boe in the second quarter of 2006 due primarily to the costs described above.

Transportation Costs - The small decrease in transportation costs is partly due to the corresponding decrease in sales volumes. On a per unit basis, transportation costs decreased from $2.29/Boe in the second quarter to $2.15/Boe in the current quarter.

Depletion and Depreciation Expense - Depletion and depreciation expense on a per unit basis is up to $14.59/Boe in the third quarter of 2006 from $14.25/Boe in the second quarter of 2006 due mainly to an increase in expired mineral leases and the slightly lower sales volumes during the current quarter.

General and Administrative Expenses - General and administrative expenses after recoveries and excluding non-cash unit-based compensation were consistent at $1.6 million during the second and third quarters of 2006. On a per unit basis, general and administration expenses after recoveries and excluding non-cash unit-based compensation increased slightly from $0.71/Boe for the second quarter to $0.74/Boe for the third quarter due to the decrease in sales volumes. Total general and administrative expenses after recoveries and non-cash unit-based compensation decreased during the third quarter of 2006 due mainly to lower accrued compensation expense associated with the Trust's unit appreciation rights plan. This decrease resulted in a corresponding decrease in general and administration expenses after recoveries and unit-based compensation per unit sold from $1.52/Boe for the second quarter to $0.95/Boe for the third quarter. The decline in the market price of the Trust Units from June 30, 2006 to September 30, 2006 resulted in a unit and stock-based compensation recovery of $0.5 million for the third quarter of 2006 as compared to the unit-based compensation expense of $1.9 million for the second quarter of 2006.

Interest Expense - Interest expense increased slightly during the current quarter due to the increase in average debt balances to fund operating and capital requirements.

Exploration Expenditures - Exploration expenditures consist of lease rentals, dry hole costs and geological and geophysical costs. Exploration expenditures increased from the second quarter of 2006 compared to the third quarter of 2006 due mainly to higher activity levels. Suspended wells drilled in previous periods were also written off after subsequent reevaluations were completed in light of current circumstances during the third quarter of 2006.



Third Quarter 2006 vs. Third Quarter 2005

---------------------------------------------------------------------------
(thousand dollars except as otherwise
indicated) Q3 2005 Change Q3 2006
---------------------------------------------------------------------------
Average sales volumes:
Natural gas (Mcf/d) 115,503 1,100 116,603
Oil and natural gas liquids (Bbl/d) 5,154 (300) 4,854
---------------------------------------------------------------------------
Total (Boe/d) 24,404 (116) 24,288
---------------------------------------------------------------------------
Average prices before realized financial
instruments and transportation:
Natural gas ($/Mcf) 9.31 (2.73) 6.58
Oil and natural gas liquids ($/Bbl) 67.72 4.96 72.68
---------------------------------------------------------------------------
Average prices after realized financial
instruments but before transportation:
Natural gas ($/Mcf) 9.09 (1.87) 7.22
Oil and natural gas liquids ($/Bbl) 62.38 6.94 69.32
---------------------------------------------------------------------------

Petroleum and natural gas sales before
financial instruments:
Natural gas 98,942 (28,376) 70,566
Oil and natural gas liquids 32,110 345 32,455
---------------------------------------------------------------------------
131,052 (28,031) 103,021
---------------------------------------------------------------------------
Loss (gain) on financial instruments(1) 33,923 (61,927) (28,004)
Royalties 28,839 (7,904) 20,935
Operating costs 19,029 3,057 22,086
Transportation costs 4,864 (65) 4,799
Depletion and depreciation 33,232 (641) 32,591
General and administrative expenses 7,575 (6,382) 1,193
Interest 2,128 1,066 3,194
Exploration expenditures 2,080 6,354 8,434
Other expenditures (net of other income) 1,911 (2,456) (545)
---------------------------------------------------------------------------
Net earnings (loss) (2,529) 40,867 38,338
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1)See Risk Management section.


Petroleum and Natural Gas Sales - In comparison to the third quarter of 2005 natural gas sales, before financial instruments, decreased by $29.0 million in the current quarter due to lower average sales prices. This decrease due to prices was offset by the impact of higher sales volumes of approximately $0.7 million. Oil and natural gas liquid sales, before financial instruments, increased by $2.4 million due to higher average sales prices, offset by a decrease of $2.0 million due to lower sales volumes. Average natural gas sales volumes were slightly higher during the current quarter due mainly to the Redsky acquisition at the end of the first quarter of 2006, offset by the impact of natural declines and delays in bringing on production additions. Natural declines were also the primary reason for the decrease in oil and natural gas liquid sales volumes.

Royalties - As a percentage of petroleum and natural gas sales, royalties averaged 20 percent for the third quarter of 2006 as compared to 22 percent for the third quarter of 2005. 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, and low productivity royalty credits received. 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. This variability in price further impacts the royalty rate due to certain credits that reduce gross royalties.

Operating Costs - The increase in operating costs primarily reflects the impact of inflation in the industry. This is also the main reason why operating costs per unit increased to $9.88/Boe in the third quarter of 2006 from $8.48/Boe in the same quarter of 2005.

Transportation Costs - Transportation costs on a per unit basis were relatively consistent for the third quarters of 2006 and 2005.

Depletion and Depreciation Expense - On a per unit of product sales volume basis, depletion and depreciation is down slightly from $14.80/Boe in the third quarter of 2005 to $14.59/Boe for the third quarter of 2006. 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.

General and Administrative Expenses - General and administrative expenses after recoveries but before unit-based compensation were lower at $0.74/Boe during the third quarter of 2006 when compared to $0.95/Boe for the same quarter in 2005 primarily due to an increase in recoveries, partially offset by increases in personnel costs resulting from increased staffing levels. As a result of the increase in staff, the management fees paid to a related party declined significantly. Included within general and administrative expenses were unit and stock-based compensation net recovery of $0.5 million for the third quarter of 2006 versus $5.5 million unit and stock-based compensation expense for the third quarter of 2005. The change from compensation expense to recovery caused general and administrative expenses after recoveries and unit-based compensation to decrease from $3.37/Boe for the third quarter of 2005 to $0.53/Boe for the third quarter of 2006, which was due primarily to the decline in the market price of Trilogy Trust Units reducing the amount accrued for compensation expense relating to Trilogy's units appreciation rights plan.

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

Exploration Expenditures - Exploration expenditures increased in the third quarter of 2006 compared to the same quarter of 2005 due mainly to higher activity levels. Suspended wells drilled in previous periods were also written off after subsequent reevaluations were completed in light of current circumstances during the third quarter of 2006.



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

---------------------------------------------------------------------------
Nine Nine
Months Months
Ended Ended
(thousand dollars except as otherwise Sept. 30, Sept. 30,
indicated) 2005 Change 2006
---------------------------------------------------------------------------
Average sales volumes:
Natural gas (Mcf/d) 117,977 (437) 117,540
Oil and natural gas liquids (Bbl/d) 4,962 20 4,982
---------------------------------------------------------------------------
Total (Boe/d) 24,625 (53) 24,572
---------------------------------------------------------------------------
Average prices before realized financial
instruments and transportation:
Natural gas ($/Mcf) 8.30 (0.78) 7.52
Oil and natural gas liquids ($/Bbl) 60.29 8.25 68.54
---------------------------------------------------------------------------
Average prices after realized financial
instruments but before transportation:
Natural gas ($/Mcf) 8.16 0.59 8.75
Oil and natural gas liquids ($/Bbl) 59.07 7.36 66.43
---------------------------------------------------------------------------

Petroleum and natural gas sales before
financial instruments:
Natural gas 267,280 (26,077) 241,203
Oil and natural gas liquids 81,669 11,551 93,220
---------------------------------------------------------------------------
348,949 (14,526) 334,423
---------------------------------------------------------------------------
Loss (gain) on financial instruments(1) 57,039 (123,174) (66,135)
Royalties 79,610 (2,041) 77,569
Operating costs 51,394 14,057 65,451
Transportation costs 15,139 (664) 14,475
Depletion and depreciation 100,701 (7,554) 93,147
General and administrative expenses 18,293 (11,354) 6,939
Interest 6,966 1,266 8,232
Exploration expenditures 8,004 9,616 17,620
Other expenditures (net of other income) 20,680 (19,836) 844
Taxes (7,649) 7,649 -
---------------------------------------------------------------------------
Net earnings (loss) (1,228) 117,509 116,281
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1)See Risk Management section.


Petroleum and Natural Gas Sales - Natural gas sales, before financial instruments, decreased by $25.2 million and $0.9 million in the current period due to lower average sales prices and sales volumes, respectively. Natural gas sales volumes were lower with the temporary shut-in of production from the plant turnaround during the second quarter of 2006 as well as natural declines, offset by the volumes from the Redsky acquisition. Oil and natural gas liquid sales, before financial instruments, increased by $11.2 million and $0.4 million due to higher average sales prices and slightly higher sales volumes, respectively.

Royalties - The decrease in royalties in 2006 was the result of decreased petroleum and natural gas sales as noted above. As a percentage of petroleum and natural gas sales, royalties averaged 23 percent for both periods in 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 partly to the repairs and maintenance costs incurred during the first six months of 2006 and also to the significant increase in costs experienced by the whole industry. On a per unit basis, operating costs increased to $9.76/Boe during the first nine months of 2006 from $7.64/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 - On a per unit basis, transportation costs were lower at $2.16/Boe for the first nine months of 2006 compared to $2.25/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 four percent reduction in transportation costs per Boe for the first nine months of 2006 versus the first nine months of 2005 reflects this benefit.

Depletion and Depreciation Expense - Depletion and depreciation expense decreased by eight percent in the first nine 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 the 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 $14.98/Boe in the first nine months of 2005 to $13.89/Boe for the first nine months of 2006.

General and Administrative Expenses - General and administrative expenses after recoveries and unit-based compensation decreased from $2.72/Boe for the first nine months of 2005 to $1.03/Boe for the same period in 2006 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, the normalization of general and administrative expenditure levels from the Trust's transition period in 2005, and the significant decrease in unit-based compensation expense from $7.1 million for the nine months ended September 30, 2005 to $1.3 million for the current period. The decrease in unit-based compensation expense was due to the decline in the market price of Trilogy Trust Units reducing the amount accrued for compensation expense relating to Trilogy's units appreciation rights plan. Excluding unit/stock-based compensation, general and administrative expenses after recoveries decreased from $1.67/Boe for the first nine months of 2005 to $0.84/Boe for the same period in 2006 due primarily to the normalization of expenditure levels from the Trust's transition period in 2005 as described above.

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

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

Other Expenditures - Other expenditures consist mainly of accretion on asset retirement obligations, gain (loss) on sale of property, plant and equipment, other income and, for the nine months ended September 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 Trust Assets on April 1, 2005 (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 VOLUME

---------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
(Dollars per Boe) 2006 2005 2006 2005
---------------------------------------------------------------------------
Gross revenue before financial
instruments(1) 44.61 55.91 47.97 49.62
Royalties (9.37) (12.84) (11.56) (11.84)
Operating costs (9.88) (8.48) (9.76) (7.64)
Asset retirement obligation
expenditures (0.41) (0.04) (0.20) (0.10)
---------------------------------------------------------------------------
Revenue after direct expenditures 24.95 34.55 26.45 30.04
General and administrative
expenses(2) (0.74) (0.95) (0.85) (1.52)
Interest expense (1.43) (0.95) (1.23) (1.04)
Lease rentals (0.05) (0.11) (0.09) (0.10)
Realized gain (loss) on financial
instruments 2.42 (2.18) 5.47 (0.93)
Non-recurring allocated
expenditures - - - (0.76)
---------------------------------------------------------------------------
Funds flow from operations(3) 25.15 30.36 29.75 25.69
Net change in operating working
capital 2.98 13.71 (0.33) (9.13)
---------------------------------------------------------------------------
Cash flows from operating
activities 28.13 44.07 29.42 16.56
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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, financial contracts that require financial settlement between counterparties. The financial instruments program is generally for periods of less than one year and financial commodity contracts would not exceed 50 percent of Trilogy's forecasted annual production volumes.

The Trust had forward financial commodity sales contracts outstanding as at September 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 gains (losses) 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 gains (losses) on financial instruments.' The amounts of unrealized and realized gains (losses) on financial instruments are as follows:



---------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
(thousand dollars) 2006 2005 2006 2005
---------------------------------------------------------------------------
Realized gain (loss) on financial
instruments 5,417 (4,904) 36,693 (6,237)
Net change in fair value of
financial instruments 22,587 (29,019) 29,442 (50,802)
---------------------------------------------------------------------------
Net gain (loss) on financial
instruments 28,004 (33,923) 66,135 (57,039)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 nine months ended September 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 second quarter of 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. In addition, foreign currency rate fluctuations may impact the Trust mainly due to its U.S. Dollar denominated financial instrument contracts with counterparties.



QUARTERLY FINANCIAL INFORMATION

---------------------------------------------------------------------------
Third Second First Fourth
(thousand dollars except per unit Quarter Quarter Quarter Quarter
amounts) 2006 2006 2006 2005
---------------------------------------------------------------------------
Revenue after financial instruments,
royalties and other income 111,540 89,450 123,833 145,643
Net earnings 38,338 19,819 58,124 87,675
Earnings per Trust Unit(2)
Basic 0.42 0.22 0.68 1.11
Diluted 0.42 0.22 0.68 1.11
---------------------------------------------------------------------------
---------------------------------------------------------------------------


---------------------------------------------------------------------------
Third Second First Fourth
(thousand dollars except per unit Quarter Quarter Quarter Quarter
amounts) 2005 2005 2005(1) 2004(1)
---------------------------------------------------------------------------
Revenue after financial instruments,
royalties and other income 67,637 80,928 63,478 94,891
Net earnings (loss) (2,529) 17,370 (16,069) (5,478)
Earnings (loss) per Trust Unit(2)
Basic (0.03) 0.22 (0.20) (0.07)
Diluted (0.03) 0.22 (0.20) (0.07)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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 as
at April, 1 2005.

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


LIQUIDITY AND CAPITAL RESOURCES

---------------------------------------------------------------------------
September 30, December 31,
(thousand dollars) 2006 2005
---------------------------------------------------------------------------
Working capital deficit 5,744 75,302
Long-term debt 254,538 108,375
Unit-based compensation liability - long-term
portion 3,490 2,876
---------------------------------------------------------------------------
Net debt (including long-term unit-based
compensation liability) 263,772 186,553
Unitholders' equity 537,940 462,365
---------------------------------------------------------------------------
Total 801,712 648,918
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Working Capital

The decrease in the working capital deficit from $75.3 million as at December 31, 2005 to $5.7 million as at September 30, 2006 is due mainly to the decline in distributions payable from $68.1 million as at December 31, 2005 to $18.5 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 $26.1 million as at September 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 and Credit Facilities

Trilogy's bank debt outstanding from its $370 million committed credit facility was $254.5 million as at September 30, 2006. The size of Trilogy's credit facility is based on the value of Trilogy's petroleum and natural gas assets. The committed credit facility increased to $390 million in conjunction with the acquisition of Blue Mountain.

The Trust has entered into a committed term sheet for a $100 million junior secured non-revolving bridge loan facility from which no amount has been drawn down as at September 30, 2006.

(See Subsequent Events section above and note 5 to the interim consolidated financial statements.)

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 increase 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, Options and Rights

In connection with Trilogy's distribution reinvestment plan ("DRIP"), 791,322 Trust Units were issued during the third quarter of 2006. As at September 30, 2006 and November 6, 2006, the Trust had 92,424,768 Trust Units and 92,496,026 Trust Units outstanding, respectively.

Outstanding unit rights issued under Trilogy's unit appreciation plan were 1,290,250 unit rights as at September 30, 2006 and November 6, 2006, of which 223,250 unit rights and 528,750 unit rights are exercisable at September 30, 2006 and November 6, 2006, respectively. There were no material changes to the outstanding and exercisable units under Trilogy's unit option plan from September 30, 2006 to November 6, 2006.



Funds Flow from Operations and Distributions

---------------------------------------------------------------------------
Three Months Ended Nine Months Ended
(thousand dollars except where Sept. 30 Sept. 30
stated otherwise) 2006 2005 2006 2005
---------------------------------------------------------------------------
Cash flows from operating
activities 62,867 98,940 197,384 111,305
Net changes in operating working
capital (6,666) (30,770) 2,237 61,361
---------------------------------------------------------------------------
Funds flow from operations(1) 56,201 68,170 199,621 172,666
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Distributions declared net of DRIP
units(2) 40,369 45,106 165,071 83,090
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Cash distribution payout percentage 72 66 83 -
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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 decreased from the third quarter of 2005 to the same quarter of the current year due mainly to lower petroleum and natural gas sales and higher operating costs, offset by higher realized gains on financial instruments, as discussed above. On a year-to-date basis, funds flow from operations were higher during the current period due primarily to the realized gains on financial instruments during the current period compared to realized losses on financial instruments in the prior year. The amount of future funds flow from operations is highly sensitive to changes in commodity prices, interest rates and other factors.

Trilogy has, during the nine months ended September 30, 2006, funded its distributions and capital expenditures from cash flows and draw downs from its line of credit, respectively. As a result of the sustained decline in natural gas prices, and the impact of this on cash flow, Trilogy reduced its distributions from $0.20 to $0.16 per Trust Unit commencing with the October 2006 distribution.

The amount of distributions in the future is highly dependent upon the amount of funds flow to be generated from operations. Trilogy's ability to generate funds flow that can be used to make distributions is subject to numerous risks and uncertainties which are detailed in a later section of this MD&A.

Please refer to the Income Taxes section of this MD&A for the taxability of the Trust and its Unitholders.




Capital Expenditures

---------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
(thousand dollars) 2006 2005 2006 2005
---------------------------------------------------------------------------

Land 1,500 2,912 18,521 8,016
Geological and geophysical 579 1,833 1,791 3,156
Drilling 23,171 16,825 81,051 60,991
Production equipment and facilities 5,969 4,250 29,967 22,724
---------------------------------------------------------------------------
Exploration and development
expenditures 31,219 25,820 131,330 94,887
Proceeds received from property
dispositions - (2) - (174)
Property acquisitions(1) - - 401 -
Other 24 152 634 1,516
---------------------------------------------------------------------------
Net capital expenditures 31,243 25,970 132,365 96,229
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Excluding the non-cash acquisition of Redsky through the issuance of
6,500,000 Trust Units in 2006.


Exploration and development expenditures increased from the three and nine
months ended September 30, 2005 to the same periods of the current year due
primarily to the increase in development activities, expansion relating to
new acquisitions and the rising costs of services.

Wells Drilled

---------------------------------------------------------------------------
Three Months Ended Nine Months Ended
(number of Sept. 30 Sept. 30
wells) 2006 2005 2006 2005
---------------------------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
Natural gas 14.0 13.2 15.0 13.6 57.0 48.8 46.0 41.1
Oil 1.0 1.0 3.0 1.6 1.0 1.0 7.0 4.6
Dry 2.0 1.5 1.0 0.5 8.0 5.5 4.0 2.0
---------------------------------------------------------------------------
Total 17.0 15.7 19.0 15.7 66.0 55.3 57.0 47.7
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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.

On October 31, 2006 Federal Finance Minister Jim Flaherty (the "Finance Minister") announced a proposal to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the Unitholders. The Finance Minister said existing trusts would have a four-year transition period and would not be subject to the new rules until 2011. Until such rules are released in legislative form and passed into law it is uncertain what the impact of such rules will be to the Trust and its Unitholders. However, assuming such proposals are ultimately enacted in the form proposed, the implementation of such proposals could be materially different than the consequences described herein under the sub-headings "Canadian Taxpayers" and "United States Taxpayers".

Furthermore, under the assumption the above proposals are ultimately enacted, the Trust would be required, in accordance with GAAP, to record provisions for both current and future income tax amounts.

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 11 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 and nine months ended September 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 16.2 percent of the outstanding Trust Units at September 30, 2006), provides administrative and operating services to the Trust and its subsidiaries, pursuant to an agreement dated April 1, 2005. The amount of expenses paid for such services was $0.4 million for the three months ended September 30, 2006 ($1.5 million for the nine months ended September 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 to Paramount arising from the above related party transactions as at September 30, 2006 was $6.0 million. This amount owing to Paramount represents billings from Paramount arising from normal business activities and the allocation of royalty credits received totaling $11.5 million less Trilogy's royalty deposit claim of $5.5 million described above.

The Trust also had distributions payable to Paramount amounting to $3.0 million at September 30, 2006 with respect to the September 2006 distribution to Unitholders.

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 assesses its results throughout the year and revises 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 three months ending December 31, 2006 using the following base assumptions:




---------------------------------------------------------------------------
Average Production
Natural gas 131,000 Mcf/d
Crude oil/liquids 5,600 Bbl/d
---------------------------------------------------------------------------
Average Prices before Financial Instruments
Natural gas Cdn$6.38/Mcf
Crude oil/liquids U.S.$56.51/Bbl
---------------------------------------------------------------------------
Exchange rate (U.S.$/Cdn$) $0.89
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The estimated impact on funds flow from operations for the three months
ending December 31, 2006 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 0.91
Oil and natural gas liquids price change of
U.S.$1.00/Bbl (WTI) 0.03
U.S. dollar to Canadian dollar exchange rate
fluctuation of $0.01 0.39
Average interest rate change of 1% 0.75
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 estimates were used during the nine months ended September 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 document 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;

- weather and 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.



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



TRILOGY ENERGY TRUST
Consolidated Balance Sheets (Unaudited)
(thousand dollars)

September 30, December 31,
As at 2006 2005
---------------------------------------------------------------------------
ASSETS
Current Assets
Accounts receivable $ 49,383 $ 73,001
Due from related party (note 11) - 6,439
Financial instruments (note 10) 26,053 5,830
Prepaid expenses 4,776 899
---------------------------------------------------------------------------
80,212 86,169

Property, plant and equipment (note 4) 825,931 672,224

Investment in common shares (note 15) 2,110 -

Goodwill 19,400 19,400
---------------------------------------------------------------------------
$ 927,653 $ 777,793
---------------------------------------------------------------------------
---------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 56,716 $ 78,334
Distributions payable (notes 8 and 11) 18,485 68,107
Due to related party (note 11) 5,996 -
Unit-based compensation liability (note 9) 4,759 5,810
Financial instruments (note 10) - 9,220
---------------------------------------------------------------------------
85,956 161,471
---------------------------------------------------------------------------

Long-term debt (note 5) 254,538 108,375
Unit-based compensation liability -- net of
current portion (note 9) 3,490 2,876
Asset retirement obligations (note 6) 45,729 42,706
---------------------------------------------------------------------------
303,757 153,957
---------------------------------------------------------------------------

Commitments and contingencies (notes 10, 13 and 15)

Unitholders' equity
Unitholders' capital (note 7) 688,013 550,144
Contributed surplus (note 9) 2,151 468
Accumulated earnings 218,797 102,516
Accumulated distribution (note 8) (371,021) (190,763)
---------------------------------------------------------------------------
537,940 462,365
---------------------------------------------------------------------------
$ 927,653 $ 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 Nine Months Ended
September 30 September 30
2006 2005 2006 2005
(Note 1)
---------------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 103,021 $ 131,052 $ 334,423 $ 348,949
Realized gain (loss) on
financial instruments
(note 10) 5,417 (4,904) 36,693 (6,237)
Unrealized gain (loss) on
financial instruments
(note 10) 22,587 (29,019) 29,442 (50,802)
Royalties (20,935) (28,839) (77,569) (79,610)
Other income (loss) 1,450 (653) 1,834 (257)
---------------------------------------------------------------------------
111,540 67,637 324,823 212,043
---------------------------------------------------------------------------
Expenses
Operating 22,086 19,029 65,451 51,394
Transportation 4,799 4,864 14,475 15,139
General and administrative
(notes 9 and 11) 1,193 7,575 6,939 18,293
Exploration expenditures
(note 4) 8,434 2,080 17,620 8,004
Accretion on asset retirement
obligations (note 6) 905 1,258 2,678 4,127
Depletion and depreciation 32,591 33,232 93,147 100,701
Interest 3,194 2,128 8,232 6,966
Other nonrecurring expenses - - 16,296
---------------------------------------------------------------------------
73,202 70,166 208,542 220,920
---------------------------------------------------------------------------

Earnings (loss) before taxes 38,338 (2,529) 116,281 (8,877)
---------------------------------------------------------------------------
Taxes (note 12)
Future income tax recovery - - - (8,059)
Large Corporation Tax and
other - - - 410
---------------------------------------------------------------------------
- - (7,649)
---------------------------------------------------------------------------
Net earnings (loss) 38,338 (2,529) 116,281 (1,228)
Accumulated earnings,
beginning of period 180,459 17,370 102,516 -
Loss allocated to net
investment by Paramount
Resources Ltd. - - - 16,069
---------------------------------------------------------------------------
Accumulated earnings, end
of period $ 218,797 $ 14,841 $ 218,797 $ 14,841
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Earnings (loss) per Trust
Unit
- Basic $ 0.42 $ (0.03) $ 1.30 $ (0.02)
- Diluted $ 0.42 $ (0.03) $ 1.30 $ (0.02)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Weighted average Trust Units
outstanding
(in thousands) (note 7)
- Basic 91,900 79,133 89,607 79,133
- Diluted 91,900 79,133 89,607 79,133
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


The financial statements for the nine months ended September 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 Nine Months Ended
September 30 September 30
2006 2005 2006 2005
(Note 1)
---------------------------------------------------------------------------
Operating activities
Net earnings (loss) $ 38,338 $ (2,529) $ 116,281 $ (1,228)
Add (deduct) non-cash and
other items:
Depletion and depreciation 32,591 33,232 93,147 100,701
Accretion on asset
retirement obligations 905 1,258 2,678 4,127
Exploration expenditures 8,317 1,831 17,020 7,340
Asset retirement obligation
expenditures (910) (93) (1,309) (691)
Non-cash general and
administrative expenses
(recovery) (453) 5,452 1,246 8,088
Non-cash (gain) loss on
financial instruments (22,587) 29,019 (29,442) 50,802
Future income tax recovery - - - (8,059)
Other nonrecurring expenses - - - 11,586
---------------------------------------------------------------------------
Funds flow from operations 56,201 68,170 199,621 172,666
Net change in operating
working capital 6,666 30,770 (2,237) (61,361)
---------------------------------------------------------------------------
62,867 98,940 197,384 111,305
---------------------------------------------------------------------------
Financing activities
Credit facility - draws 75,640 116,078 643,647 428,482
Credit facility - repayments (73,156) (120,083) (498,280) (204,994)
Distributions to unitholders (40,889) (37,984) (215,706) (63,307)
Payment to Paramount
Resources Ltd. upon the
formation of the Trust - - - (220,000)
Net investment by Paramount
Resources Ltd. - - - 18,270
---------------------------------------------------------------------------
(38,405) (41,989) (70,339) (41,549)
---------------------------------------------------------------------------
Investing activities
Property, plant and
equipment expenditures (31,243) (25,972) (131,964) (96,403)
Property, plant and
equipment acquisitions - - (401) -
Investment in Blue Mountain
Energy Ltd. (2,110) - (2,110) -
Cash acquired from Redsky
Energy Ltd. (note 3) - - 6,904 -
Proceeds on sale of
property, plant and
equipment - 2 - 174
Net change in investing
working capital 8,891 (30,981) 526 26,473
---------------------------------------------------------------------------
(24,462) (56,951) (127,045) (69,756)
---------------------------------------------------------------------------
Change in cash / cash, end
of period $ - $ - $ - $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Cash interest paid $ 4,316 $ 2,323 $ 10,080 $ 7,161
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

The financial statements for the nine months ended September 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
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2006
(Tabular amounts expressed in thousand 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 its 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 nine months ended September 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 nine months ended September 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.

3. ACQUISITION

On March 31, 2006, Trilogy completed the acquisition of all of the shares of Redsky Energy Ltd. ("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

---------------------------------------------------------------------------
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Accumulated Accumulated
Depletion Net Depletion Net
and Book and Book
Cost Depreciation Value Cost Depreciation Value
---------------------------------------------------------------------------
Petroleum
and natural
gas
properties 1,368,648 (544,195) 824,453 1,125,973 (454,964) 671,009
Other 2,056 (578) 1,478 1,423 (208) 1,215
---------------------------------------------------------------------------
1,370,704 (544,773) 825,931 1,127,396 (455,172) 672,224
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Capital costs totaling approximately $145.1 million as at September 30, 2006 ($72.1 million as at December 31, 2005) are not subject to depletion.

The costs of dry holes amounting to $7.7 million were written off during the three months ended September 30, 2006 ($15.2 million for the nine months ended September 30, 2006) and are included as part of exploration expenditures.

5. CREDIT FACILITIES

The Trust has a $335 million 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 revolving facility would be available for a one year term on a non-revolving basis, at the end of which time amounts drawn down under the facility would be due and payable. The working capital facility would continue on a revolving basis for a one year term. 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 $254.5 million as at September 30, 2006. The weighted average interest rate under this facility for the nine months ended September 30, 2006 was 4.95 percent. The $370 million borrowing base is subject to semi-annual review by the banks.

The Trust has entered into a committed term sheet for a $100 million junior secured non-revolving bridge loan facility from which no amount has been drawn down as at September 30, 2006. Borrowing under this facility will bear interest at 1 percent to 1.5 percent over the revolving credit facility interest rates, and advances are subject to the execution of a definitive documentation and certain other conditions precedent. Drawn amounts under the facility must be repaid no later than six months after the Blue Mountain Energy Ltd. ("Blue Mountain") acquisition closing date (see note 15).

The Trust has undrawn letters of credit totaling $9.2 million as at September 30, 2006. These letters of credit reduce the amount available under the Trust's working capital facility.



6. ASSET RETIREMENT OBLIGATION

---------------------------------------------------------------------------
Three Months Nine Months
Ended Ended
September 30, September 30,
2006 2006
---------------------------------------------------------------------------
Asset retirement obligations, beginning of period 45,412 42,706
Liabilities incurred 322 1,059
Liabilities settled (910) (1,309)
Accretion expense 905 2,678
Redsky acquisition (note 3) - 595
---------------------------------------------------------------------------
Asset retirement obligations, end of period 45,729 45,729
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The undiscounted asset retirement obligation at September 30, 2006 is estimated to be $195.9 million (December 31, 2005 - $189.1 million). The Trust's credit-adjusted risk-free rate is 7.875 percent. 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 nine months ended September 30, 2006:



---------------------------------------------------------------------------
Number of Units Amount
---------------------------------------------------------------------------
Balance at December 31, 2005 85,133,395 550,144
Trust Units issued upon the acquisition of Redsky,
net of issuance costs (note 3) 6,500,000 123,695
Units issued on the Distribution Reinvestment Plan
(note 8) 791,322 14,174
Additional Trust Units issued for the acquisition
of Redsky to make fractional Trust Units whole 51 -
---------------------------------------------------------------------------
Balance at September 30, 2006 92,424,768 688,013
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Per Trust Unit Information

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



8. ACCUMULATED DISTRIBUTIONS

---------------------------------------------------------------------------
Three Months Ended
September 30, 2006
---------------------------------------------------------------------------
Cash DRIP Accrual Total

Balance at beginning of period 297,473 - 18,327 315,800
Distributions paid/reinvested 40,889 14,174 - 55,063
Change in distribution accrual - - 158 158
---------------------------------------------------------------------------
Balance at end of period 338,362 14,174 18,485 371,021
---------------------------------------------------------------------------
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Nine Months Ended
September 30, 2006
---------------------------------------------------------------------------
Cash DRIP Accrual Total

Balance at beginning of period 122,656 - 68,107 190,763
Distributions paid/reinvested 215,706 14,174 - 229,880
Change in distribution accrual - - (49,622) (49,622)
---------------------------------------------------------------------------
Balance at end of period 338,362 14,174 18,485 371,021
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 percent of the average market price. Eligible holders of 5,069,602 Trust Units have elected to participate in the DRIP for the September 2006 monthly distribution.

On October 19, 2006, Trilogy announced that its cash distribution for October 2006 will be $0.16 per Trust Unit. The distribution is payable on November 15, 2006 to unitholders of record on October 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 nine months ended September 30, 2006, is as follows:



Three Months Ended Nine Months Ended
September 30, 2006 September 30, 2006
---------------------------------------------------------------------------
Exercise No. of Exercise No. of
Price Unit Rights Price Unit Rights
---------------------------------------------------------------------------
Balance at beginning of period $ 6.36 1,290,250 $ 7.76 1,306,000
Exercised - - $ 6.87 (6,750)
Cancelled - - $ 7.76 (9,000)
---------------------------------------------------------------------------
Balance at end of period $ 5.76 1,290,250 $ 5.76 1,290,250
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Unit rights exercisable at
end of period $ 5.76 223,250 $ 5.76 223,250
---------------------------------------------------------------------------
---------------------------------------------------------------------------


A compensation recovery of $1.0 million relating to the unit appreciation plan has been recognized in earnings for the three months ended September 30, 2006 ($0.4 million for the nine months ended September 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. The majority of the outstanding options under this plan will vest in 2009 and 2010, and expire on April 30, 2011. A continuity of the unit option plan for the three and nine months ended September 30, 2006, is as follows:



---------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, 2006 September 30, 2006
---------------------------------------------------------------------------
Weighted Weighted
Average Average
Exercise No. of Exercise No. of
Price Options Price Options
---------------------------------------------------------------------------
Balance at beginning of period $ 18.50 1,096,000 - -
Granted 19.02 20,000 $ 18.51 1,116,000
Cancelled 22.77 (30,000) $ 22.77 (30,000)
---------------------------------------------------------------------------
Balance at end of period $ 18.40 1,086,000 $ 18.40 1,086,000
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Unit options exercisable at end of
period - - - -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Trust has accounted for its unit option plan using the fair value method and has recorded a compensation expense of $0.2 million for the three months ended September 30, 2006 ($0.5 million for the nine months ended September 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 September 30, 2006 ($1.2 million for the nine months ended September 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 Commodity Contracts

The Trust utilizes, from time to time, forward commodity price contracts that require financial settlements with counterparties. At September 30, 2006, the Trust had outstanding financial forward arrangements as follows:



---------------------------------------------------------------------------
Quantity Price Term
---------------------------------------------------------------------------
Sales Contracts
AECO Fixed Price 10,000 GJ/d $ 7.96 April 2006-October 2006
NYMEX Fixed Price 10,000 MMBtu/d $ 10.14 US November 2006-March 2007
NYMEX Fixed Price 10,000 MMBtu/d $ 10.37 US November 2006-March 2007
NYMEX Fixed Price 10,000 MMBtu/d $ 11.16 US November 2006-March 2007
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
WTI Fixed Price 1,000 Bbl/d $ 66.04 US February 2006-December 2006
WTI Fixed Price 1,000 Bbl/d $ 65.64 US February 2006-December 2006
WTI Fixed Price 1,000 Bbl/d $ 68.02 US February 2006-December 2006
WTI Fixed Price 1,000 Bbl/d $ 68.05 US February 2006-December 2006
Purchase Contract
NYMEX Fixed price 10,000 MMBtu/d $ 9.16 US November 2006-March 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Forward Currency Contract

At September 30, 2006, Trilogy had an outstanding forward currency contract to sell US$2.5 million to a counterparty at the rate of $1.12/US$1 on October 25, 2006. The exchange rate at September 30, 2006 was $1.1177/US$1.

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 September 30, 2006 are as follows:



---------------------------------------------------------------------------
Financial instrument asset 26,053
Financial instrument liability -
---------------------------------------------------------------------------
Net financial instrument asset (liability) 26,053
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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, Interest Rate and Foreign Currency 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. In addition, foreign currency rate fluctuations may impact the Trust mainly due to the U.S. Dollar denominated financial instrument contracts mentioned above.

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 provides administrative and operating services to the Trust and its subsidiaries. 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, however may be terminated by either party with at least six months written notice. The amount of expenses paid as management fees under this agreement was $0.4 million for the three months ended September 30, 2006 ($1.5 million for the nine months ended September 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 to Paramount arising from the above related party transactions as at September 30, 2006 was $6.0 million. This amount owing to Paramount represents billings from Paramount arising from normal business activities and the allocation of royalty credits received totaling $11.5 million less the royalty deposit claim of $5.5 million described above.

Trilogy also has distributions payable to Paramount of $3.0 million as at September 30, 2006 with respect to the September 2006 distribution to Unitholders.

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 nine months ended September 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 sales contract was outstanding as
September 30, 2006:

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

14. COMPARATIVE FIGURES

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

15. SUBSEQUENT EVENTS

Financial Instruments

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

---------------------------------------------------------------------------
Quantity Price Term
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Purchase Contracts
NYMEX Fixed Price 10,000 MMBtu/d $ 7.46 US November 2006
NYMEX Fixed Price 10,000 MMBtu/d $ 5.85 US November 2006
NYMEX Fixed Price 10,000 MMBtu/d $ 7.59 US November 2006-March 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Blue Mountain Acquisition

On October 26, 2006, Trilogy completed the acquisition of all issued and outstanding Blue Mountain shares for a cash purchase price of $5.50 per Blue Mountain share plus the repayment of Blue Mountain's debt totaling approximately $20.4 million. The total aggregate estimated cost of this acquisition is $142.0 million. The acquisition was funded with amounts drawn on the existing and bridge credit facilities. As at September 30, 2006, Trilogy acquired 479,300 shares of Blue Mountain from the open market representing 2.2 percent of the issued and outstanding shares of Blue Mountain.

Convertible Debenture

On October 19, 2006 Trilogy announced that it has entered into an agreement to sell to a syndicate of underwriters, on a bought deal basis, $175 million principal amount of 6.25 percent convertible unsecured subordinated debentures due November 30, 2011. Under the agreement, the Trust has granted the underwriters an option to purchase an additional $26.25 million of debentures. In light of the recent statements from the Federal Minister of Finance respecting the taxation of income trusts and the ensuing impact to the capital markets, Trilogy has decided to delay the convertible debenture closing. Trilogy remains in discussions with its underwriters and is assessing various alternatives to proceed with the offering.



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

2006 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3 Q2
Sales Volumes
---------------------------------------------------------------------------
Gas (MMcf/d) 117 118 118 116 116 117
Oil and Natural Gas Liquids
(Bbl/d) 4,854 5,103 4,990 4,826 5,154 4,780
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Sales Volumes (Boe/d)
(6:1) 24,288 24,827 24,605 24,109 24,404 24,287
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Per-unit Results
---------------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, before
transportation(1) 6.58 6.81 9.18 12.05 9.31 8.15
Transportation 0.40 0.43 0.38 0.41 0.42 0.48
Royalties 1.36 1.56 2.40 2.90 1.95 1.82
Operating expenses, net of
processing revenue 1.65 1.73 1.50 1.26 1.41 1.34
---------------------------------------------------------------------------
Cash netback before
realized financial 3.17 3.08 4.89 7.48 5.52 4.51
instruments
Realized financial
instruments 0.64 3.10 (0.06) (1.08) (0.22) 0.03
---------------------------------------------------------------------------
Cash netback including
realized financial
instruments 3.81 6.18 4.83 6.40 5.30 4.54
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Produced Oil and Natural
Gas Liquids ($/Bbl)
Price, before
transportation (1) 72.68 69.55 63.38 71.38 67.72 57.84
Transportation 1.06 1.18 1.00 0.84 0.79 0.86
Royalties 14.24 17.01 14.63 17.58 17.18 14.11
Operating expenses, net of
processing revenue 9.88 10.37 9.00 7.55 8.48 7.35
---------------------------------------------------------------------------
Cash netback before
realized financial 47.50 40.99 38.75 45.41 41.27 35.52
instruments
Realized financial
instruments (3.35) (3.30) 0.38 (2.18) (5.34) 1.41
---------------------------------------------------------------------------
Cash netback including
realized financial
instruments 44.15 37.69 39.13 43.23 35.93 36.93
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Total Produced ($/Boe)
Price, before
transportation(1) 46.11 46.77 56.78 72.11 58.08 50.82
Transportation 2.15 2.29 2.03 2.11 2.17 2.47
Royalties 9.37 10.93 14.42 17.42 12.84 11.53
Operating expenses, net of
processing revenue 9.88 10.37 9.00 7.55 8.48 7.35
---------------------------------------------------------------------------
Cash netback before
realized financial 24.71 23.18 31.33 45.03 34.59 29.47
instruments
Realized financial
instruments 2.42 14.07 (0.24) (5.59) (2.18) 0.43
---------------------------------------------------------------------------
Cash netback including
realized financial
instruments 27.13 37.25 31.09 39.44 32.41 29.90
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Excluding other income


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