Fairborne Energy Trust
TSX : FEL.UN

Fairborne Energy Trust

March 08, 2007 00:05 ET

Fairborne Energy Trust Announces 2006 Financial and Operating Results and Reserve Summary

CALGARY, ALBERTA--(CCNMatthews - March 8, 2007) - Fairborne Energy Trust (TSX:FEL.UN) ("Fairborne" or the "Trust") Announces 2006 Financial and Operating Results and Reserve Summary.



2006 FINANCIAL AND OPERATING SUMMARY

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2006 2005(1) change
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FINANCIAL ($thousands, except per unit
amounts)
Petroleum and natural gas sales 204,129 226,648 (10%)
Funds generated from operations (2) 112,897 125,243 (10%)
Per unit - basic $ 2.39 $ 2.65 (10%)
Per unit - diluted $ 2.05 $ 2.39 (14%)
Net income 44,079 43,553 1%
Per unit - basic $ 0.93 $ 0.92 1%
Per unit - diluted $ 0.90 $ 0.89 1%
Exploration and development expenditures 69,643 126,139 (45%)
Acquisitions, net of dispositions 22,378 (44,634) -
Working capital surplus 7,158 1,373 421%
Bank indebtedness 101,156 136,302 (26%)
Convertible debentures 90,302 - -
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OPERATIONS (Units as noted)
Average production
Natural gas (Mcf per day) 45,660 48,099 (5%)
Crude oil (bbls per day) 2,577 2,764 (7%)
Natural gas liquids (bbls per day) 375 415 (10%)
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Total (BOE per day) 10,562 11,195(1) (6%)
Proved and probable reserves
Natural gas (Bcf) 165.4 153.0 8%
Crude oil (Mbbl) 7,971 8,649 (8%)
Natural gas liquids (Mbbl) 2,533 2,039 24%
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BOE (MBOE) 38,078 36,182 5%
Netback per BOE ($ per BOE)
Petroleum and natural gas sales 52.95 55.47 (5%)
Royalties (8.61) (11.74) (27%)
Transportation (1.38) (0.89) 55%
Operating expenses (9.38) (8.58) 9%
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Operating netback 33.58 34.26 (2%)
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Wells drilled (gross) 62 72 (14%)
Undeveloped land (net acres) 174,511 193,191 (10%)
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(1) Fairborne's 2005 results include results from properties prior to their
disposition to Fairquest on June 1, 2005.

(2) Funds generated from operations is calculated using cash flow from
operations as presented in the consolidated statement of cash flows
before non-cash working capital and asset retirement expenditures.


2006 HIGHLIGHTS

- Reserve growth in 2006 replaced 150% of production.

- Proved plus probable reserves increased 5% to 38.1 MMBOE at year end 2006.

- Proved plus probable reserves per unit increased 5%.

- Finding, development and acquisition costs were $16.00 per BOE, excluding change in future capital ($18.73 including change in future capital), representing a recycle ratio of 2.1 times for proved plus probable reserves.

- Three year finding, development and acquisition costs, excluding change in future capital, averaged $13.43 per BOE for proved plus probable reserves.

- The Trust's reserve life index increased 7% to 9.9 years, up from 9.2 years in 2005, based on average annual production.

- The Trust drilled 62 (32.3 net) wells resulting in 24 (9.7 net) natural gas wells, 30 (17.9 net) CBM wells and five (3.2 net) crude oil wells for an overall success rate of 95%.

- Stable production throughout the year, averaging 10,562 BOE per day.

- Funds generated from operations was $112.9 million ($2.39 per unit) with an average operating netback of $33.58 per BOE.

- Fourth quarter production averaged 10,623 BOE per day.

SUMMARY OF RESERVES

The Trust's independent engineering evaluation, effective December 31, 2006, was prepared by the independent engineering firms of GLJ Petroleum Consultants Ltd. ("GLJ") and Sproule Associates Ltd. ("Sproule") in accordance with the definitions set out under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101").



SUMMARY OF OIL AND GAS RESERVES -
GROSS (1) AND NET (2) RESERVES (FORECAST PRICES)

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Light/Medium Heavy Natural
Crude Oil Oil Gas Liquids
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Gross Net Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
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Proved reserves
Developed producing 3,700 3,146 26 23 977 663
Developed non-producing 525 467 27 24 155 106
Undeveloped 904 768 354 314 380 262
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Total Proved 5,128 4,382 407 361 1,512 1,030
Probable 2,148 1,847 288 249 1,022 692
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Total Proved plus Probable 7,276 6,229 695 610 2,533 1,722
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Natural Coal Bed 2006
Gas Methane BOE
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Gross Net Gross Net Gross Net
(Bcf) (Bcf) (Bcf) (Bcf) (MBOE) (MBOE)
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Proved reserves
Developed producing 51.6 39.6 14.4 12.6 15,695 12,529
Developed non-producing 3.8 2.9 0.8 0.7 1,459 1,192
Undeveloped 15.1 11.3 19.0 16.4 7,321 5,958
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Total Proved 70.4 53.8 34.2 29.6 24,475 19,679
Probable 46.2 36.3 14.7 12.7 13,603 10,967
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Total Proved plus Probable 116.6 90.2 48.9 42.4 38,078 30,647
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NOTE: May not add due to rounding.
(1) "Gross" reserves means the total working interest (operating and non-
operating) share before deduction of royalties payable to others and
without including any royalty interest of Fairborne.
(2) "Net" reserves means the total working interest (operating and non-
operating) share after deduction of royalty obligations plus
Fairborne's royalty interests in reserves.


RESERVES PER TRUST UNIT

One of the key measures of trust performance is the year over year change in reserves per unit. This calculation takes into account the volumes discovered during the year and combines it with capital efficiency, while incorporating the effect of any units issued during the year. The following table summarizes Fairborne's gross reserves per unit changes for 2006:



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Proved Proved plus Probable

Reserves Reserves
per per
thousand % of thousand % of
Units opening Units opening
(BOE) balance (BOE) balance
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December 31, 2005 483 100 696 100
Exploration & development (1) 49 10 94 14
Acquisitions, net of dispositions 12 3 17 2
Production (74) (15) (74) (11)
Change in trust units (3) (1) (4) (1)
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December 31, 2006 468 97 728 105
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NOTE: May not add due to rounding.
(1) Includes extensions, improved recovery, discoveries and revisions.


NET PRESENT VALUE OF RESERVES, BEFORE INCOME TAXES

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December 31, 2006 (1),(2),(3),(4) Discounted at:
($thousands) Undiscounted 5% 10% 15% 20%
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Proved reserves
Developed producing 461,527 381,103 327,696 289,368 260,376
Developed non-producing 47,360 37,088 30,196 25,278 21,620
Undeveloped 142,685 102,695 75,313 55,887 41,695
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Total Proved 651,572 520,886 433,204 370,534 323,691
Probable 397,822 250,922 172,898 125,954 95,424
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Total Proved plus Probable 1,049,395 771,808 606,102 496,487 419,115
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NOTE: May not add due to rounding
(1) Utilizing GLJ January 1, 2007 price forecast
(2) As required by NI 51-101, undiscounted well abandonment costs of $14.4
million for total proved reserves and $18.3 million for total proved
plus probable reserves are included in the Net Present Value
determination.
(3) Prior to provision of income taxes, interest, debt service charges and
general and administrative expenses. It should not be assumed that the
undiscounted and discounted future net revenues estimated by GLJ
represent the fair market value of the reserves.
(4) Fairborne is entitled to deduct from its income all amounts which are
paid or payable to its unitholders in a given financial year. As
Fairborne distributes all its taxable income to its unitholders, net
present values of the future net revenues have not been included on an
after-tax basis. Fairborne has not considered the effect of the
proposed tax changes for Trusts.


2006 CAPITAL EFFICIENCY HIGHLIGHTS

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Proved plus
Proved Probable
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Capital costs ($thousands)
Exploration and development 69,643 69,643
Acquisitions, net of dispositions 22,378 22,378
Change in future development costs (1) 2,738 15,685
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Reserve additions (MBOE)
Exploration and development 2,569 4,890
Acquisitions, net of dispositions 640 861
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Finding and development costs, including change in future
capital (1)(2) ($ per BOE) 28.18 17.45
Finding and development costs, excluding change in future
capital (1)(5) ($ per BOE) 27.11 14.24
Finding, development and acquisition costs,
including change in future capital (1)(4)(5) ($ per BOE)29.53 18.73
Finding, development and acquisition costs,
excluding change in future capital (1)(4)(5) ($ per BOE)28.68 16.00
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Operating netback ($ per BOE) 33.58 33.58
Finding, development and acquisition costs,
excluding change in future capital (1)(5) ($ per BOE) 28.68 16.00
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Recycle ratio 1.2 2.1
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Reserve additions, including acquisitions and
revisions (MBOE) 3,209 5,751
Total 2006 production (MBOE) 3,855 3,855
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Reserve replacement ratio 0.8 1.5
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Gross reserves (3) (MBOE) 24,475 38,078
Fourth quarter 2006 production (BOE per day) 10,623 10,623
Annual 2006 production (BOE per day) 10,562 10,562
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Reserve Life Index, using annualized Q4 production
(years) 6.3 9.8
Reserve Life Index, using 2006 annual production (years) 6.3 9.9
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(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserve additions for that year.
(2) Calculated in accordance with NI 51-101 as exploration and development
costs incurred in the year along with the change in estimated future
development costs divided by the applicable reserve additions. In 2005,
F&D costs as calculated in accordance with NI 51-101 were $26.19 per
BOE for proved reserves and $37.04 per BOE for proved plus probable
reserves. F&D costs on a three year average were $19.19 per BOE for
proved reserves and $15.35 per BOE for proved plus probable reserves.
(3) Gross reserves means the total working interest (operating and non-
operating) share before deduction of royalties payable to others and
without including any royalty interest.
(4) Fairborne also calculates finding, development and acquisition ("FD&A")
costs which incorporate both the costs and associated reserve additions
related to acquisitions net of any dispositions during the year. Since
acquisitions can have a significant impact on Fairborne's annual
reserve replacement costs, the Trust believes that FD&A costs provide a
more meaningful portrayal of Fairborne's cost structure.
(5) F&D costs, excluding change in future capital for proved reserves were
$27.19 per BOE in 2005 (proved plus probable - $20.92 per BOE) and
$16.01 per BOE on a three year average (proved plus probable - $11.50
per BOE). FD&A costs, including change in future capital for proved
reserves were $27.54 per BOE in 2005 (proved plus probable - $70.15 per
BOE) and $21.22 per BOE on a three year average (proved plus probable
- $16.53 per BOE). FD&A costs, excluding change in future capital for
proved reserves were $19.69 per BOE in 2005 (proved plus probable
- $44.58 per BOE) and $18.67 per BOE on a three year average (proved
plus probable - $13.43 per BOE).


Advisories

The following Management Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") was prepared at, and is dated, March 7, 2007. This MD&A is provided by the management of Fairborne Energy Trust ("Fairborne" or the "Trust") to review 2006 activities and results as compared to the previous year, and should be read in conjunction with the audited consolidated financial statements including notes for the year ended December 31, 2006 and 2005. Additional information relating to Fairborne, including Fairborne's annual information form, is available on SEDAR at www.sedar.com.

Nature of Business: Fairborne Energy Ltd. was incorporated as a private company and commenced active operations in June, 2002. In 2003, Fairborne Energy Ltd. became a publicly traded company. Effective June 1, 2005, Fairborne Energy Ltd. was reorganized resulting in two new entities, Fairquest Energy Limited ("Fairquest"), a publicly traded exploration-focused company, and Fairborne Energy Trust, an open-ended unincorporated investment trust. If the context requires, reference herein to "Fairborne" also includes a reference to Fairborne Energy Ltd. prior to the reorganization.

The Trust maintains its head office in Calgary and is engaged in the business of developing, acquiring and producing crude oil and natural gas in Western Canada. Fairborne follows a strategy of balancing risk and reward by focusing on opportunities by geographic area and prospect type. The Trust's mandate is to generate stable, monthly distributions while maintaining a solid production base.

Forward Looking Statements: This MD&A contains forward-looking statements. Management's assessment of future plans and operations, production estimates and expected production rates, levels of distributions on Trust Units and the payout ratio, cash available for distribution and its availability for capital expenditures and distributions, expected commodity prices, whether cash tax will be payable, expected royalty rates, transportation costs and operating costs, capital expenditures, and methods of financing capital expenditures may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, the Trust's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhausted. Additional information on these and other factors that could effect the Trust's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at the Trust's website (www.fairbornetrust.com). Furthermore, the forward-looking statements contained in this MD&A are made as at the date of this MD&A and the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Non-GAAP Terms: This document contains the terms "funds generated from operations", "distributable cash/cash available for distribution", "payout ratio" and "netbacks" which are non-GAAP terms. The Trust uses these measures to help evaluate its performance. The Trust considers corporate netback a key measure as it demonstrates its profitability relative to current commodity prices. The Trust considers funds generated from operations, distributable cash/cash available for distribution and payout ratio key measures as they demonstrate Fairborne's ability to generate funds necessary to repay debt, make distributions to Unitholders and to fund future growth through capital investment. Funds generated from operations should not be considered as an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with Canadian GAAP as an indicator of Fairborne's performance. Fairborne's determination of funds generated from operations, distributable cash/cash available for distribution and payout ratio may not be comparable to that reported by other companies. The reconciliation between cash flow from operations and funds generated from operations can be found in the section entitled "Distributable Cash and Distributions" with funds generated from operations calculated before non-cash working capital and asset retirement expenditures. Fairborne also presents funds generated from operations per unit whereby per unit amounts are calculated using weighted average units outstanding consistent with the calculation of income per unit with diluted per unit calculations including the effect of convertible debentures.

BOE Conversions: Barrel of oil equivalent ("BOE") amounts may be misleading, particularly if used in isolation. A BOE conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel and is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalency at the wellhead.

Management's Discussion and Analysis of Financial Condition and Results of Operations



HIGHLIGHTS
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2006 2005(1) change
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FINANCIAL ($thousands, except per unit
amounts)
Petroleum and natural gas sales 204,129 226,648 (10%)
Funds generated from operations 112,897 125,243 (10%)
Per unit - basic $ 2.39 $ 2.65 (10%)
Per unit - diluted $ 2.05 $ 2.39 (14%)
Cash flow from operations (including changes
in working capital) 107,774 108,880 (1%)
Per unit - basic $ 2.28 $ 2.31 (1%)
Per unit - diluted $ 1.97 $ 2.23 (12%)
Net income 44,079 43,553 1%
Per unit - basic $ 0.93 $ 0.92 1%
Per unit - diluted $ 0.90 $ 0.89 1%
Exploration and development expenditures 69,643 126,139 (45%)
Acquisitions, net of dispositions 22,378 (44,634) -
Working capital surplus 7,158 1,373 421%
Bank indebtedness 101,156 136,302 (26%)
Convertible debentures 90,302 - -
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OPERATIONS (Units as noted)
Average production
Natural gas (Mcf per day) 45,660 48,099 (5%)
Crude oil (bbls per day) 2,577 2,764 (7%)
Natural gas liquids (bbls per day) 375 415 (10%)
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Total (BOE per day) 10,562 11,195(1) (6%)
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Average sales price
Natural gas ($ per Mcf) 7.88 8.84 (11%)
Crude oil ($ per bbl) 68.22 61.78 10%
Natural gas liquids ($ per bbl) 49.11 50.15 (2%)
Netback per BOE ($ per BOE)
Petroleum and natural gas sales 52.95 55.47 (5%)
Royalties (8.61) (11.74) (27%)
Transportation (1.38) (0.89) 55%
Operating expenses (9.38) (8.58) 9%
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Operating netback 33.58 34.26 (2%)
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(1) Fairborne's 2005 results include results from properties prior to their
disposition to Fairquest on June 1, 2005.


SELECT ANNUAL INFORMATION
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($thousands, except per unit amounts) 2006 2005 2004
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Petroleum and natural gas sales 204,129 226,648 125,604
Funds generated from operations 112,897 125,243 66,399
Per unit - basic $ 2.39 $ 2.65 $ 1.65
Per unit - diluted $ 2.05 $ 2.39 $ 1.54
Cash flow from operations (including changes
in working capital) 107,774 108,880 51,403
Per unit - basic $ 2.28 $ 2.31 $ 1.28
Per unit - diluted $ 1.97 $ 2.23 $ 1.19
Net income 44,079 43,553 13,702
Per unit - basic $ 0.93 $ 0.92 $ 0.34
Per unit - diluted $ 0.90 $ 0.89 $ 0.32
Total assets 539,579 499,920 434,830
Working capital surplus (deficit), including
current bank indebtedness 7,158 1,373 (98,058)
Long term financial liabilities
Bank indebtedness 101,156 136,302 -
Convertible debentures 90,302 - -
Non-controlling interest 27,132 27,598 -
Asset retirement obligations 10,994 11,386 13,196
Future income taxes 41,592 51,465 35,860
Cash distributions per unit $ 1.56 $ 1.36 -
Unitholders' equity 200,715 204,359 247,777
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In 2004, Fairborne Energy Ltd. drilled 109 wells as part of an extensive exploration and development program which resulted in average production and funds generated from operations that were more than double the previous year. Also in 2004, Fairborne Energy Ltd. completed a significant property acquisition in West Pembina and the corporate acquisition of Case Resources Inc. Fairborne Energy Ltd. financed its acquisition, exploration and development activities through a combination of funds generated from operations, bank debt and common share equity financings which included the issue of flow-through shares.

Effective June 1, 2005, Fairborne Energy Trust was established as part of a Plan of Arrangement whereby Fairborne Energy Ltd. was reorganized into two new entities, Fairquest, a publicly traded exploration-focused company, and Fairborne Energy Trust. The trust conversion was undertaken as a method to offer all shareholders greater liquidity and flexibility to participate in an income trust, a junior oil and natural gas company or the combined future of both entities. Pursuant to the Plan of Arrangement, Fairquest acquired certain petroleum and natural gas properties of Fairborne Energy Ltd. In addition, the companies have entered into farm-in agreements whereby Fairquest received an option to farm-in on 83,000 net acres of Fairborne's exploratory lands.

In 2006, in its first full year as a trust, Fairborne met its objective to maintain stable production, funds generated from operations and distributions to unitholders by focusing on the development of its core properties and using an active commodity price risk management program. In a year marked by volatility in natural gas prices, Fairborne recorded $112.9 million in funds generated from operations ($2.39 per unit), of which 65% was distributed to Unitholders ($1.56 per unit) through consistent monthly distributions of $0.13 per unit. The balance of funds generated from operations was used, in part, to fund capital expenditures of $92.0 million, which included a property acquisition of $22.4 million. Fairborne's capital program was focused on the development of core properties with 62 wells drilled (32.3 net) resulting in 24 (9.7 net) natural gas wells, 30 (17.9 net) CBM wells and five (3.2 net) oil wells. Financing for the remainder of the 2006 capital program was obtained through a combination of bank debt and proceeds from a $100 million convertible debenture financing completed in October 2006.

For 2007, Fairborne's focus will be on sustainability with a stable production base, a diversity of development projects and access to exploration upside through its farmout to Fairquest.



QUARTERLY FINANCIAL INFORMATION

The following is a summary of select financial information for the
quarterly periods indicated:
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2006
Q4 Q3 Q2 Q1
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FINANCIAL ($thousands, except per
unit amounts)
Petroleum and natural gas sales 49,581 48,845 50,914 54,789
Funds generated from operations 26,108 27,825 30,340 28,624
Per unit - basic $ 0.54 $ 0.58 $ 0.65 $ 0.62
Per unit - diluted $ 0.43 $ 0.51 $ 0.57 $ 0.54
Cash flow from operations
(including changes in working
capital) 10,189 29,969 38,037 29,579
Per unit - basic $ 0.19 $ 0.63 $ 0.82 $ 0.64
Per unit - diluted $ 0.15 $ 0.55 $ 0.71 $ 0.56
Net income 8,900 10,439 13,881 10,859
Per unit - basic $ 0.18 $ 0.22 $ 0.30 $ 0.23
Per unit - diluted $ 0.17 $ 0.22 $ 0.28 $ 0.23
Total assets 539,579 514,681 499,826 522,482
Working capital surplus (deficit) 7,158 (2,395) (3,199) 35
Bank indebtedness 101,156 177,595 147,202 153,933
Convertible debentures 90,302 - - -
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OPERATIONS
Average production
Natural gas (Mcf per day) 46,752 45,966 43,441 46,472
Crude oil (bbls per day) 2,522 2,604 2,607 2,575
Natural gas liquids (bbls per day) 308 376 432 384
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Total (BOE per day) 10,623 10,640 10,280 10,705
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2005
Q4 Q3 Q2(i) Q1(i)
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FINANCIAL ($thousands, except per
unit amounts)
Petroleum and natural gas sales 68,751 61,656 48,807 47,434
Funds generated from operations 40,783 35,406 23,760 25,294
Per unit - basic $ 0.89 $ 0.78 $ 0.47 $ 0.51
Per unit - diluted $ 0.77 $ 0.67 $ 0.47 $ 0.48
Cash flow from operations
(including changes in working
capital) 30,731 30,001 18,466 29,682
Per unit - basic $ 0.67 $ 0.66 $ 0.38 $ 0.60
Per unit - diluted $ 0.74 $ 0.57 $ 0.36 $ 0.56
Net income 20,444 15,482 2,719 4,908
Per unit - basic $ 0.43 $ 0.34 $ 0.05 $ 0.10
Per unit - diluted $ 0.42 $ 0.33 $ 0.05 $ 0.09
Total assets 499,920 458,603 451,849 480,089
Working capital surplus (deficit) 1,373 984 (7,758) (16,823)
Bank indebtedness 136,302 128,548 124,580 106,513
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OPERATIONS
Average production
Natural gas (Mcf per day) 46,886 49,412 47,077 49,030
Crude oil (bbls per day) 2,770 2,684 2,558 3,047
Natural gas liquids (bbls per day) 438 402 422 398
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Total (BOE per day) 11,022 11,321 10,826(i) 11,617(i)
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(i) Amounts shown include amounts prior to the effective date of the Plan
of Arrangement (June 1, 2005) in respect of Fairborne Energy Ltd.


Production declined 5% from the third quarter of 2005 to the first quarter of 2006. Through the four quarters of 2006, Fairborne's production has been stable, with fluctuations from quarter to quarter primarily due to interruptions on sales pipelines and gas facility turnarounds. Production for the first two quarters of 2005 included operations of Fairborne Energy Ltd. prior to the trust conversion on June 1, 2005 and, therefore, included production from properties subsequently disposed to Fairquest.

Fairborne's revenue, funds generated from operations and cash flow from operations over the past two years have reflected its stable production base with revenue variances from quarter to quarter largely influenced by changes in natural gas prices. Beginning in the first quarter of 2005 and continuing into the first quarter of 2006, natural gas prices were gradually increasing which resulted in a corresponding increase in the Trust's petroleum and natural gas revenue and funds generated from operations through the same period. This trend started to reverse in the second quarter of 2006 with declining natural gas prices influencing a corresponding decrease in the Trust's revenues and funds generated from operations.

The most significant impact to Fairborne's net income over the past two years is related to the trust conversion undertaken on June 1, 2005. In addition to mirroring the changes in the Trust's funds generated from operations over the eight quarters, net income also reflects an increase in DD&A rates beginning in the third quarter of 2005 offset by future tax recoveries beginning in the same period. The increase in Fairborne's DD&A rate since the trust conversion is due to an increase in its depletable base as a result of capital spending and accounting for exchangeable shares, whereby the conversion of exchangeable shares results in an increase to depletable assets, with no corresponding increase in reserves. Future tax recoveries recognized since June 2005 result from additional interest deductions associated with Fairborne's new Trust structure as well as reductions in rates for both federal and provincial taxes which were enacted during 2006.

FOURTH QUARTER 2006 RESULTS

Fairborne's fourth quarter 2006 production remained stable at 10,623 BOE per day (Q3 2006 - 10,640 BOE per day). Revenues of $49.6 million for the fourth quarter were also consistent with the preceding quarter (Q3 2006 - $48.8 million). Despite an escalating cost environment, the Trust reduced operating costs by 7% from $9.88 per BOE in the preceding quarter to $9.20 per BOE in the fourth quarter of 2006. Recovering commodity prices and lower operating costs were reflected in an operating netback of $32.16 per BOE in the fourth quarter consistent with the preceding third quarter (Q3 - $32.51 per BOE).

The Trust recorded funds generated from operations of $26.1 million ($0.54 per unit) during the fourth quarter with cash flow from operations (including changes in working capital) of $10.2 million ($0.19 per unit). Distributions were maintained at $0.13 per unit per month with total distributions for the fourth quarter of $18.6 million, representing a payout ratio of 71%. Fairborne completed a $100 million convertible debenture financing in October 2006 with proceeds from the debenture financing initially applied against outstanding bank indebtedness.

Capital expenditures in the fourth quarter were $16.7 million which included $9.0 million for drilling and completions and $7.3 million for well equipment and facilities. The Trust drilled eight (4.7 net) wells during the fourth quarter resulting in two (0.3 net) natural gas wells, three (2.2 net) CBM wells, and three (2.2 net) oil wells. The fourth quarter capital program was financed through a combination of debt and funds generated from operations after distributions to unitholders.

TRUST CONVERSION ACCOUNTING

The conversion to a Trust has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for 2005 reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by Fairborne Energy Ltd. Specifically, the December 31, 2005 consolidated financial statements reflect the results of operations and cash flows of Fairborne Energy Ltd. and its subsidiaries prior to the Plan of Arrangement (June 1, 2005). As a result of the conversion to a trust, certain information for prior periods may not be directly comparable.

RELATIONSHIP WITH FAIRQUEST ENERGY LIMITED

In conjunction with the Plan of Arrangement, Fairborne and Fairquest entered into a Technical Services Agreement ("TSA") which provides for the shared services required to manage Fairquest's activities and govern the allocation of general and administrative expenses between the entities. Under the TSA, Fairquest is charged a technical services fee by Fairborne, on a cost recovery basis, in respect of the management, development, exploitation, operations and marketing activities on the basis of relative production and capital expenditures. The TSA has no set termination date and will continue until terminated by either party with six months prior written notice to the other party or on some other date as may be mutually agreed.



2006 FINANCIAL RESULTS

PRODUCTION
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2006 2005(1) change
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Natural gas (Mcf per day) 45,660 48,099 (5%)
Crude oil (bbls per day) 2,577 2,764 (7%)
Natural gas liquids (bbls per day) 375 415 (10%)
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Total (BOE per day) 10,562 11,195 (6%)
Natural gas % of production 72% 72% -
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(1) Includes production from properties prior to their disposition to
Fairquest on June 1, 2005.


Fairborne reported average production of 10,562 BOE per day in 2006. Daily production remained consistent throughout the year with the exception of second quarter production, that was negatively impacted by unscheduled interruptions on the Nova pipeline and turnarounds at third party operated gas facilities. In the prior year, production of 11,195 BOE per day included five months of production from properties disposed to Fairquest in conjunction with the trust conversion on June 1, 2005.

Natural gas production of 45.7 MMcf per day for 2006 was impacted by interruptions on the Nova pipeline and turnarounds at major gas facilties but also reflected the Trust's successful development drilling programs in Columbia/Harlech, Clive CBM and Westerose with new production replacing natural declines. Excluding production attributable to Fairquest properties in 2005, natural gas production from Trust properties was consistent with the prior year.

Crude oil and NGL production of 2,952 bbls per day for 2006 was marginally lower than the 2005 average of 3,179 bbls per day, with the majority of the Trust's 2006 development activities focused on natural gas properties.

In 2007, the Trust expects to continue its development of core properties with the objective to maintain production between 10,500 and 10,800 BOE per day.



COMMODITY PRICES & RISK MANAGEMENT ACTIVITIES
---------------------------------------------------------------------------
2006 2005 change
---------------------------------------------------------------------------
Average prices
Natural gas ($ per Mcf) 7.88 8.84 (11%)
Crude oil ($ per bbl) 68.22 61.78 10%
Natural gas liquids ($ per bbl) 49.11 50.15 (2%)
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BOE ($ per BOE) 52.45 55.08 (5%)
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Benchmark prices
AECO Daily Index (Cdn$ per Mcf) 6.51 8.71 (25%)
AECO Monthly Index (Cdn$ per Mcf) 6.99 8.48 (18%)
WTI - Edmonton par (Cdn$ per bbl) 73.29 69.13 6%
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---------------------------------------------------------------------------


Risk Management - Physical Sales Contracts

The Trust's risk management strategy is based on the following objectives:

- provide greater certainty and stability to distributions;

- protect unitholder return on investment;

- reduce risk exposure in budgeted annual funds flow projections; and

- help ensure transaction economics on acquisitions.

Natural Gas

2006 was a year of declining natural gas prices with average AECO daily prices decreasing 25% and AECO monthly prices decreasing 18% compared to 2005. In 2006, Fairborne continued to realize above-average natural gas prices due to the higher heat content of the Trust's production and an active risk management program. An average of 19,911 Mcf per day was sold under fixed price physical sales contracts during 2006 representing 44% of the Trust's natural gas production. Risk management activities during 2006 increased the Trust's natural gas revenue by $19.6 million which had an effect of increasing the Trust's realized natural gas price by $1.18 per Mcf to $7.88 per Mcf, a 21% premium to the daily AECO index.

In the first two months of 2007, natural gas prices have recovered to trade around $8.02 per Mcf. However, based on high current storage levels in the North American market together with an expectation that natural gas inventories may remain at historically high levels, there is considerable downward potential for natural gas prices in the summer of 2007. To manage some of this price risk and provide stability to expected funds generated from operations, Fairborne has 54% of its gas production under fixed price physical sales contracts for the first 6 months of 2007 at a minimum average price of $8.72 per Mcf and 22% of the Trust's production for the last half of 2007 at a minimum average price of $8.79 per Mcf.

The following table summarizes the outstanding fixed price physical sales contracts for natural gas, including contracts outstanding at December 31, 2006 as well as contracts entered into after December 31, 2006:



---------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Q1
---------------------------------------------------------------------------
2007 2007 2007 2007 2008
---------------------------------------------------------------------------
Collars
Volume (Mcf per day) 16,387 - - 4,510 2,706
Average floor ($ per Mcf) $ 9.58 - - $ 8.87 $ 8.87
Average ceiling ($ per Mcf) $ 12.50 - - $ 10.59 $ 11.09
Puts and participating swaps
Volume (Mcf per day) 2,706 1,804 5,863 451 -
Average floor ($ per Mcf) $ 10.14 $ 8.36 $ 8.20 $ 8.45 -
Swaps
Volume (Mcf per day) 4,059 26,158 4,510 6,164 4,961
Average price ($ per Mcf) $ 9.46 $ 7.96 $ 8.99 $ 9.20 $ 9.60
---------------------------------------------------------------------------
Total volume (Mcf per day) 23,152 27,962 10,373 11,125 7,667
Average floor price ($ per Mcf) $ 9.63 $ 7.99 $ 8.54 $ 9.03 $ 9.35
---------------------------------------------------------------------------
Conversion factor: 1Mcf = 1.109GJ


Crude oil

Crude oil prices in 2006 increased by 6% compared to average market prices in 2005. During the fourth quarter of 2006, OPEC announced production cuts which were intended to help reduce the growing inventories and provide support to crude oil prices. These initiatives were met with limited success as crude oil prices declined 18% from the third quarter as supply/demand fundamentals continued to override the ongoing threats of supply disruptions and limited global excess production.

During 2006, the Trust had an average of 652 bbls per day of crude oil under fixed price physical sales contracts representing 25% of crude oil production. Risk management activities, including option costs for puts purchased during the year had a minimal effect on the Trust's realized crude price, decreasing it by $0.01 per bbl for the year. Compared to the prior year, the Trust's realized crude oil price of $68.22 per bbl for 2006 represented an increase of 10% from 2005. For 2007, the Trust has 34% of its estimated crude oil production protected at a minimum average price of US$67.40 per bbl.

The following table summarizes the outstanding fixed price physical sales contracts on crude oil, including contracts outstanding at December 31, 2006 as well as contracts entered into after December 31, 2006:



---------------------------------------------------------------------------
Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
2007 2007 2007 2007
---------------------------------------------------------------------------
Collars
Volume (bbls per day) - 500 - -
Average floor ($ per bbl) - $ 63.00 - -
Average ceiling ($ per bbl) - $ 70.00 - -
Puts and participating swaps
Volume (bbls per day) 900 500 - -
Average floor ($ per bbl) $ 64.22 $ 70.50 - -
Swaps
Volume (bbls per day) - - 500 500
Average price ($ per bbl) - - $ 70.68 $ 70.98
---------------------------------------------------------------------------
Total volume (bbls per day) 900 1,000 500 500
Average floor price ($ per bbl) $ 64.22 $ 66.75 $ 70.68 $ 70.98
---------------------------------------------------------------------------

PETROLEUM AND NATURAL GAS REVENUE
---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
Natural gas 131,319 155,147 (15%)
Crude oil 64,168 62,322 3%
Natural gas liquids 6,719 7,595 (12%)
Other income 1,923 1,584 21%
---------------------------------------------------------------------------
Total 204,129 226,648 (10%)
---------------------------------------------------------------------------
Per BOE $ 52.95 $ 55.47 (5%)
---------------------------------------------------------------------------


Fairborne reported revenue of $204.1 million in 2006, which reflected weakened commodity prices and reduced production compared to the prior year. Included in 2005 revenue of $226.6 million was five months of revenue from properties disposed to Fairquest on June 1, 2005 as part of the trust conversion.



ROYALTIES

---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
Crown 23,790 38,320 (38%)
Freehold and overriding 9,395 9,642 (3%)
---------------------------------------------------------------------------
Total 33,185 47,962 (31%)
---------------------------------------------------------------------------
Crown (% of revenue) 11.7% 16.9% (31%)
Freehold and overriding (% of revenue) 4.6% 4.3% 7%
---------------------------------------------------------------------------
Total (% of revenue) 16.3% 21.2% (23%)
---------------------------------------------------------------------------
Per BOE $8.61 $11.74 (27%)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Fairborne recorded $33.2 million in royalties in 2006 (2005 - $48.0 million), representing a royalty rate of 16.3% (2005 - 21.2%). Several factors reduced effective crown royalty rates during 2006, including royalty credits of $2.6 million which related to adjustments for 2005 crown cost deductions. In addition, Fairborne's overall effective crown royalty rate for 2006 decreased as a result of increased deductions for allowable operating costs and gas cost allowance. Finally, due to the Trust's risk management program, Fairborne's realized gas price was well in excess of the reference price utilized in calculating crown royalties. In 2007, Fairborne expects royalties to average between 18% and 20% based on new allowable cost deductions, market reference prices, and the elimination of the ARTC program (2006 - $0.5 million crown royalty credit).



TRANSPORTATION EXPENSES

---------------------------------------------------------------------------
2006 2005 change
---------------------------------------------------------------------------
Transportation costs ($thousands) 5,313 3,627 46%
Per BOE $ 1.38 $ 0.89 55%
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Transportation costs of $5.3 million ($1.38 per BOE) for 2006 include clean oil trucking, trucking of natural gas liquids, certain third party fuel charges and transportation and fuel costs associated with the usage of natural gas pipelines. Prior to June 1, 2005, Fairborne's natural gas sales contracts were all paid net of transportation; therefore, the Trust did not incur transportation expenses for its natural gas production in the first five months of 2005. Effective June 1, 2005, Fairborne entered into a contract for transportation of its natural gas and became directly responsible for payment of transportation costs.

In 2007, based on expected production and continued weighting toward natural gas, the Trust expects per BOE transportation costs to remain consistent with 2006.



OPERATING COSTS

---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
Operating costs
Natural gas 25,022 24,502 2%
Oil and NGLs 11,160 10,533 6%
---------------------------------------------------------------------------
Total 36,182 35,035 3%
---------------------------------------------------------------------------
Per BOE $ 9.38 $ 8.58 9%
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Fairborne recorded operating costs of $36.2 million for 2006 ($9.38 per BOE) compared to $35.0 million ($8.58 per BOE) in 2005. The increase in operating costs reflects major turnaround costs at the West Pembina gas plant as well as the continued upward pressure of industry service costs throughout the year. Based on current industry service costs and assuming no major gas plant turnarounds, the Trust expects operating costs to average approximately $9.00 per BOE in 2007.



OPERATING NETBACKS

---------------------------------------------------------------------------
2006
Natural
Gas CBM Crude oil
($ per Mcf) ($ per Mcf) ($ per bbl)
---------------------------------------------------------------------------
Petroleum and natural gas
sales 7.86 8.01 68.22
Other income 0.13 - -
Royalty expense (1.27) (0.96) (12.14)
Transportation expense (0.34) (0.15) (0.15)
Operating costs (1.65) (0.60) (10.42)
---------------------------------------------------------------------------
Operating netback 4.73 6.30 45.51
---------------------------------------------------------------------------
---------------------------------------------------------------------------


---------------------------------------------------------------------------
2005
BOE BOE
NGL's Production Production
($ per bbl) ($ per BOE) ($ per BOE) change
---------------------------------------------------------------------------
Petroleum and natural gas
sales 49.11 52.45 55.08 (5%)
Other income - 0.50 0.39 28%
Royalty expense (10.09) (8.61) (11.74) (27%)
Transportation expense - (1.38) (0.89) 55%
Operating costs (9.97) (9.38) (8.58) 9%
---------------------------------------------------------------------------
Operating netback 29.05 33.58 34.26 (2%)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Fairborne's operating netback of $33.58 was only 2% lower than 2005 despite decreased natural gas prices and increased operating costs. The operating netback remained strong as a direct result of the Trust's risk management activities and reduced royalty rates in 2006.



GENERAL AND ADMINISTRATIVE ("G&A") EXPENSES

---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
G&A expenses, net of recoveries 7,279 5,602 30%
Trust Unit compensation costs 5,007 2,158 132%
---------------------------------------------------------------------------
Total G&A expenses 12,286 7,760 58%
---------------------------------------------------------------------------
G&A expenses, per BOE $ 1.89 $ 1.37 38%
Compensation costs, per BOE $ 1.30 $ 0.53 145%
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Fairborne recorded $7.3 million (2005 - $5.6 million) of G&A expenses in 2006, net of recoveries, representing $1.89 per BOE (2005 - $1.37 per BOE). Compared to the prior year, G&A costs per BOE have increased by 38% due to increased costs associated with regulatory compliance and the attraction and retention of staff.

Pursuant to the Technical Services Agreement entered into with Fairquest in connection with completion of the Plan of Arrangement, effective June 1, 2005, Fairborne is reimbursed by Fairquest for a portion of G&A expenditures. In 2006, $2.6 million was credited to G&A under this agreement with $0.9 million credited to G&A expenses in the prior year for the period June 1 to December 31, 2005.

Compensation expense of $5.0 million in 2006 included amortization of the fair value of units anticipated to be issued pursuant to the Trust Incentive Plan. In 2005, compensation expense of $2.2 million included amortization under the Trust Incentive Plan beginning June 1, 2005 as well as regular amortization of stock options of Fairborne Energy Ltd. issued prior to the Plan of Arrangement. The increase in compensation expense for the Trust results from the valuation of units, which are based on current trading prices at the date of grant as compared to valuation of stock options, which value future increases in market price.



INTEREST AND FINANCING COSTS

---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
Interest expense 9,070 4,772 90%
Accretion of convertible debentures 362 - -
---------------------------------------------------------------------------
Total interest and financing costs 9,432 4,772 98%
Per BOE $ 2.45 $ 1.17 109%
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Fairborne recorded $9.4 million in interest expense and financing costs in 2006, up from $4.8 million in 2005. The increase in interest expense reflects a rise in borrowing rates during 2006 as well as an increase in the Trust's debt levels which include $100 million of convertible debentures issued in October 2006. At December 31, 2006, Fairborne had a total of $191.5 million of debt outstanding compared to $136.3 million at the end of 2005, with a portion of the Trust's 2006 capital expenditure program financed by debt. Also included in interest and financing costs in 2006 is the accretion of convertible debentures. The costs associated with the debenture offering along with the amount allocated to the conversion feature are charged to earnings over the life of the debentures.

TRUST CONVERSION COSTS

In accordance with the Plan of Arrangement in June 2005, all outstanding stock options of Fairborne Energy Ltd. vested. As a result, $3.4 million of remaining unamortized stock based compensation costs relating to options was charged to earnings. The Trust also incurred $3.4 million of restructuring costs which, together with stock compensation expense, has been included in trust conversion costs on the consolidated statement of operations and retained earnings for the year ended December 31, 2005.



DEPLETION, DEPRECIATION AND ACCRETION (DD&A)

---------------------------------------------------------------------------
2006 2005 change
---------------------------------------------------------------------------
Depletion, depreciation and accretion
($thousands) 74,185 69,312 7%
Per BOE $ 19.24 $ 16.97 13%
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Trust recorded $74.2 million in depletion and depreciation of capital assets and accretion of asset retirement obligations during 2006. On a BOE basis, the DD&A rate of $19.24 per BOE in 2006 was 13% higher than the prior year rate of $16.97 per BOE. The increase in DD&A rates in 2006 is due to an increase in Fairborne's depletable base as a result of capital spending and accounting for exchangeable shares, whereby the conversion of exchangeable shares results in an increase to depletable assets, with no corresponding increase in reserves.



TAXES

---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
Future (reduction) (15,272) 1,306 -
Capital 203 1,068 -
---------------------------------------------------------------------------
Total taxes (15,069) 2,374 -
---------------------------------------------------------------------------
Per BOE $(3.91) $0.58 -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Fairborne has recorded a future tax recovery of $15.3 million in 2006 compared to a provision of $1.3 million in 2005. The future tax recovery results from additional interest deductions associated with Fairborne's new trust structure as well as reductions in rates for both federal and provincial taxes which were enacted during 2006. The Trust is a taxable entity under the Income Tax Act which, under current legislation, is only taxable on income that is not distributed or distributable to unitholders. In 2006, the federal government announced proposals regarding the taxation of distributions paid by Trusts. Management is assessing the proposals and the potential implications to the Trust. See "Business Environment and Risks".

Fairborne paid provincial capital tax and large corporations tax in its operating entities in 2005. The elimination of the federal Large Corporations Tax beginning January 1, 2006, eliminated the Trust's liability for federal capital taxes; however, the Trust continues to incur provincial capital taxes on its Saskatchewan properties in 2006. Fairborne does not anticipate paying cash income taxes in its operating entities in 2007 as these entities have sufficient tax pools to offset taxable income.

NON-CONTROLLING INTEREST

As a result of the Plan of Arrangement, Fairborne issued 7.0 million exchangeable shares of a subsidiary of the Trust to former shareholders of Fairborne Energy Ltd. The exchangeable shares are listed on the Toronto Stock Exchange (trading symbol: FXL), trade separately from the Trust Units and represent a non-controlling interest to the Trust. Holders of exchangeable shares do not receive cash distributions from the Trust; however, the conversion ratio is adjusted monthly to reflect accumulated distributions. The exchangeable shares are recorded as a non-controlling interest and are allocated a pro rata share of net income as required by Canadian accounting standards.

During 2006, 989,712 exchangeable shares (2005 - 1,388,270) were converted into 1,074,626 Trust units (2005 - 1,421,413). The exchange ratio for the retraction of exchangeable shares into Trust units was 1:1.15773 at December 31, 2006.




NET INCOME, FUNDS GENERATED FROM OPERATIONS AND CASH FLOW FROM OPERATIONS

---------------------------------------------------------------------------
($thousands except as noted) 2006 2005 change
---------------------------------------------------------------------------
Funds generated from operations 112,897 125,243 (10%)
Per unit - basic $ 2.39 $ 2.65 (10%)
Per unit - diluted $ 2.05 $ 2.39 (14%)
Cash flow from operations (including changes
in working capital) 107,774 108,880 (1%)
Per unit - basic $ 2.28 $ 2.31 (1%)
Per unit - diluted $ 1.97 $ 2.23 (12%)
Net income 44,079 43,553 1%
Per unit - basic $ 0.93 $ 0.92 1%
Per unit - diluted $ 0.90 $ 0.89 1%
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---------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Capital Expenditures

---------------------------------------------------------------------------
($thousands) 2006 2005
---------------------------------------------------------------------------

Exploration and development
Land and lease acquisitions 2,763 2,739
Geological and geophysical 1,723 633
Drilling, completions and workovers 40,594 64,723
Well equipment and facilities 23,989 52,636
Other assets - 3,275
Corporate assets 574 2,133
---------------------------------------------------------------------------
69,643 126,139
Acquisitions, net of dispositions 22,378 (44,634)
Conversion of exchangeable shares 15,879 21,526
---------------------------------------------------------------------------
Total 107,900 103,031
---------------------------------------------------------------------------
---------------------------------------------------------------------------


During 2006, Fairborne's exploration and development expenditures totaled $69.6 million with an additional $22.4 million spent to acquire an increased working interest in the Trust's Wild River property. Capital expenditures were financed through a combination of debt, including convertible debentures and bank debt, and funds generated from operations after distributions to unitholders.

Fairborne spent $40.6 million on drilling and completion activities in 2006 with a total of 62 wells (32.3 net) drilled resulting in 24 (9.7 net) natural gas wells, 30 (17.9 net) coal bed methane wells and five (3.2 net) oil wells for an overall success rate of 95%. The majority of 2006 drilling activities were focused on the Trust's Columbia/Harlech and Clive properties, with 13 (4.1 net) wells drilled in Columbia/Harlech and 25 (16.3 net) CBM wells drilled on the Trust's Clive property. Exploration expenditures also included $2.8 million on land and lease acquisitions as well as $1.7 million for completion of the 150 km2 3D seismic program on the Trust's Brazeau property.

The conversion of exchangeable shares to Trust units was recorded as a $15.9 million (2005 - $21.5 million) acquisition of petroleum and natural gas assets for the year. The addition to petroleum and natural gas assets is based on the market value of Trust Units issued on conversion and the carrying value of the non-controlling interest.

In 2007, the Trust has a $60.0 million capital expenditure program which includes $42.3 million on drilling and completions, $4.1 million on land and seismic and $13.6 million on facilities and infrastructure. Financing for the capital program will be through a combination of bank indebtedness and cash flow from operations after distributions to unitholders.

WORKING CAPITAL AND BANK INDEBTEDNESS

The Trust had $101.2 million (2005 - $136.3 million) of bank indebtedness outstanding at December 31, 2006 with working capital of $7.2 million (2005 - $1.4 million). During the third quarter of 2006, the Trust had an additional $20 million outstanding under a non-revolving, non-extendible term facility which was used to complete a property acquisition. The reduction in bank indebtedness from 2005 to the end of 2006 reflects the convertible debenture financing, with proceeds initially applied against outstanding bank debt. Proceeds from the issue of the convertible debentures were also used to repay the $20 million facility on October 31, 2006.

The Trust's credit facilities at December 31, 2006 included a $165 million extendible revolving term credit facility and a $15 million demand operating credit facility for a total available facility of $180 million. The extendible revolving term facility is available on a revolving basis until May 31, 2007 (364 day facility) at which time it may be extended, at the lenders option. If the revolving period is not extended, the undrawn portion of the facility will be cancelled and the amount outstanding will convert to a 365 day non-revolving term facility. The amounts outstanding under the non-revolving term facility are required to be repaid at the end of the term facility being May 31, 2008. Interest payable on amounts drawn under the facilities is at the prevailing bankers' acceptance rates plus stamping fees, lenders' prime rate or LIBOR rates plus applicable margins, depending on the form of borrowing by the Trust. The margins and stamping fees vary from 0% to 1.5% depending on financial statement ratios and the form of borrowing. The credit facilities are secured by a general security agreement and a first ranking floating charge on the assets of the Trust and by a guarantee and subordination provided by Fairborne Energy Ltd. and all related partnerships and subsidiaries in respect of the Trust's obligations. The facility is subject to a semi-annual valuation of the Trust's petroleum and natural gas assets.

CONVERTIBLE DEBENTURES

On October 31, 2006, Fairborne issued 100,000 Convertible Unsecured Subordinated Debentures (the "Debentures") through a public issue for gross proceeds of $100 million. The Debentures bear interest at a rate of 6.5% per annum, which is payable semi-annually in arrears on December 31 and June 30 of each year commencing June 30, 2007. The Debentures, which have a face value of $1,000 per Debenture, mature on December 31, 2011 and can be converted into trust units of Fairborne at any time at the option of the holders at a conversion price of $13.50 per unit. After December 31, 2009 and prior to December 31, 2010, the Trust will have the right to redeem all or a portion of the Debentures at a price of $1,050 plus accrued and unpaid interest. After December 31, 2010 and prior to the maturity date, the Debentures will be redeemable in whole or in part at the option of the Trust at a redemption price of $1,025 plus accrued and unpaid interest. Net proceeds from the issue of the Debentures were initially used to reduce the outstanding indebtedness of the Trust.

Based on the convertible nature of the Debentures, they are considered to represent both debt and equity to the Trust under generally accepted accounting principles. The estimated fair value of the debt component of the Debentures of $94.4 million is based on the fair value of a similar debt instrument without the conversion feature. The balance of the proceeds, $5.6 million, represents the fair value of the conversion feature and is recorded as the equity component of the Debentures. Issue costs of $4.5 million have been offset against the debt component. The debt component will accrete up to the principal balance at maturity and the accretion will be included in interest expense.

UNITHOLDERS' EQUITY

The Trust is authorized to issue an unlimited number of trust units. Pursuant to the Plan of Arrangement effective June 1, 2005, former shareholders of Fairborne Energy Ltd. were issued in aggregate approximately 45 million trust units and 7 million exchangeable shares.

From June 1, 2005 to December 31, 2005, 1,388,270 exchangeable shares were converted into 1,421,413 trust units. During the year ended December 31, 2006, 1,074,626 trust units have been issued on the conversion of 989,712 exchangeable shares. The exchange ratio is calculated monthly and is increased, on a cumulative basis, for each distribution by an amount which assumes the reinvestment of distributions in trust units at the then prevailing market price of a trust unit. At December 31, 2006, the exchange ratio for the retraction of exchangeable shares into trust units was 1:1.15773.



The following table provides a summary of outstanding trust units,
exchangeable shares and units under Trust Incentive Plans at the dates
indicated:

---------------------------------------------------------------------------
February 28 December 31 December 31
(thousands) 2007 2006 2005
---------------------------------------------------------------------------
Trust units 47,762 47,677 46,400
Exchangeable shares 4,552 4,622 5,612
Trust incentive plans
Restricted units (1) 499 496 562
Performance units (1),(2) 630 629 323
Weighted average trust units
Basic n/a 47,244 47,174
Diluted n/a 53,741 48,858
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---------------------------------------------------------------------------
(1) The number of trust units that may be issued pursuant to the Restricted
Units and Performance Units will be increased for accumulated
distributions.
(2) The number of trust units that may be issued pursuant to the
Performance Units is dependent on a payout multiplier which is based on
the relative return on trust units as compared to trust units of
members of a selected peer group. Depending on the payout multiplier,
the number of trust units issuable may range between zero and two trust
units per Performance Unit.


DISTRIBUTABLE CASH AND DISTRIBUTIONS

Management monitors the Trust's distribution payout policy with respect to forecast net cash flow, debt levels and capital expenditures. Fairborne's current distribution policy targets the use of approximately 60-70% of cash available for distribution to unitholders, excluding exchangeable shares which do not receive distributions. Depending upon various factors including commodity prices and capital budgets, it is expected that the remaining 30-40% of cash available for distribution will fund debt repayments or a portion of the Trust's annual capital expenditure program, including minor property acquisitions.

The Trust's monthly distributions of $0.13 per unit in 2006 resulted in a payout ratio of 65% of cash available for distribution (excluding exchangeables). Consistent with 2005 for tax purposes, all 2006 distributions are expected to be 100% taxable as a return on capital with no return of capital.



---------------------------------------------------------------------------
June 1 (1) to
December 31,
2006 2005
---------------------------------------------------------------------------
Cash flow from operating activities 107,774 75,811
Change in non-cash working capital 3,450 7,911
Asset retirement expenditures 1,673 2,713
---------------------------------------------------------------------------
Funds generated from operations 112,897 86,435
Cash withheld for capital expenditures and debt
repayment (39,104) (49,309)
---------------------------------------------------------------------------
Cash distributions declared 73,793 37,126
---------------------------------------------------------------------------
Cash distributions per unit per month $ 0.13 $ 0.11 to $0.13
---------------------------------------------------------------------------
Payout ratio 65% 43%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Commencement of operations as a Trust


CONTRACTUAL OBLIGATIONS & COMMITMENTS

Fairborne has certain lease commitments for its office premises through to June 2011. As at December 31, 2006, the payments due under these leases is approximately $929,000 per year.

Fairborne has entered into a three year contractual agreement with a third party drilling company for the use of one of their drilling rigs. The commitment commenced on December 30, 2006 with an annual commitment of $4.3 million.

OFF-BALANCE-SHEET ARRANGEMENTS

Fairborne has no off-balance-sheet arrangements.

BUSINESS ENVIRONMENT AND RISK

The business risks the Trust is exposed to are those inherent in the oil and gas industry as well as those governed by the individual nature of Fairborne's operations. Geological and engineering risks, the uncertainty of discovering commercial quantities of new reserves, commodity prices, interest rate and foreign exchange risks, competition and government regulations - all of these govern the businesses and influence the controls and management at the Trust. Fairborne manages these risks by:

- attracting and retaining a team of highly qualified and motivated professionals who have a vested interest in the success of the Trust;

- operating properties in order to maximize opportunities;

- employing risk management instruments to minimize exposure to volatility of commodity prices, interest rate and foreign exchange rates;

- maintaining a strong financial position; and

- maintaining strict environmental, safety and health practices.

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 certain entities, including 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 (provided that the trust only experiences "normal growth" and no "undue expansion" before then). Until such rules are 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 would be expected to result in adverse tax consequences to the Trust and certain of its Unitholders which would be materially different than the consequences previously described in our disclosure documents and would impact cash distributions from the Trust. It is not known at this time when the proposals will be enacted by Parliament, if at all, or whether the proposals will be enacted in the form currently proposed.

CRITICAL ACCOUNTING ESTIMATES

DEPLETION AND DEPRECIATION EXPENSE

The Trust uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, including future development costs, net of certain costs related to unproved properties is subject to amortization as depletion and depreciation expense. Depletion and depreciation expense is calculated on a unit-of-production method based on estimated proved reserves.

The costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of impairment is added to the costs subject to depletion.

FULL COST ACCOUNTING CEILING TEST

The carrying value of petroleum and natural gas properties and equipment is reviewed at least annually for impairment. Any impairment would be included as additional depletion and depreciation in the period which it occurred. The carrying value is based on estimates of proved reserves, production rates, commodity prices, future capital costs, royalty rates and other assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

ASSET RETIREMENT OBLIGATION ("ARO")

The Trust estimates the fair value of ARO in the period in which it is incurred and records an ARO liability with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit-of-production method based on estimated proved reserves. The liability amount is increased each reporting period due to the passage of time based on an estimated risk-free interest rate, and the amount of accretion is expensed to income in the period.

INCOME TAXES

The Trust follows the liability method of accounting for income taxes. The determination of the Trust's income and other tax liabilities requires interpretation of laws and regulations, which are revised periodically. All tax filings are subject to audit and could be reassessed after a considerable period of time. Future tax assets and liabilities are booked at substantively enacted future income tax rates which include changes over a period of time. The rate used by the Trust is based on estimated future net revenues, estimated future depletion rates and other assumptions. Accordingly, the actual income tax liability may differ significantly from the amounts estimated and can impact the current and future income tax expense recorded in future periods.

CHANGE IN ACCOUNTING POLICIES

FINANCIAL INSTRUMENTS - RECOGNITION AND MEASUREMENT

Effective January 1, 2007, Fairborne will be required to prospectively adopt new Canadian accounting standards relating to accounting for financial instruments. Under the new standards, the Trust must recognize all financial instruments and non-financial derivatives, including embedded derivatives, as assets or liabilities and report them in its financial statements. Fair value accounting is deemed to be the most relevant measure for financial instruments and the only relevant measure for derivative financial instruments. Fair value accounting involves recording the financial instrument in the balance sheet as either an asset or a liability with changes in the fair value reflected in net earnings, regardless of whether the change in fair value has been realized or not. In addition, the new standards provide that hedge accounting treatment is available for items designated as being part of an effective hedging relationship. The most significant impact of the new accounting standard to Fairborne's financial statements is the change in the treatment of physical price contracts. Whereas all of these contracts were previously considered to be set price contracts which did not require fair value accounting, certain of these contracts will now qualify as derivatives, which will be accounted for using fair value accounting. Management is in the process of assessing all of its financial instruments and the corresponding impact on its financial statements.

CONTROLS AND PROCEDURES

MANAGEMENT'S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Trust is accumulated and communicated to the Trust's management as appropriate to allow timely decisions regarding required disclosure. Fairborne Energy Ltd's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the annual filings, that the Trust's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information related to the Trust, including its consolidated subsidiaries, is made known to them by others within those entities.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

Fairborne Energy Ltd.'s Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision, internal controls over financial reporting related to the Trust, including its consolidated subsidiaries, to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

Fairborne Energy Ltd.'s Chief Executive Officer and Chief Financial Officer are required to cause the Trust to disclose herein any change in the Trust's internal control over financial reporting that occurred during the Trust's most recent interim period that has material affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. During 2006, the Trust engaged external consultants to assist in documenting and assessing the Trust's design of internal controls over financial reporting. No material changes in the Trust's internal control over financial reporting were identified during the three months ended December 31, 2006, that has materially affected, or are reasonably likely to materially affect, the Trust's internal control of financial reporting.

It should be noted that a control system, including the Trust's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

MANAGEMENT'S REPORT

To the Unitholders of Fairborne Energy Trust

The accompanying consolidated financial statements of Fairborne Energy Trust and all the information in this Annual Report are the responsibility of management and have been approved by the Board of Directors.

The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly, in all material respects. The financial information contained elsewhere in this report has been reviewed to ensure consistency with the consolidated financial statements.

Management has established systems of internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. It exercises its responsibilities primarily through the Audit Committee, which is comprised of independent, non-management directors. The Audit Committee has reviewed the consolidated financial statements with management and the auditors and has reported to the Board of Directors which have approved the consolidated financial statements.

The consolidated financial statements have been audited by KPMG LLP, the external auditors, in accordance with auditing standards generally accepted in Canada on behalf of the unitholders.

Steven R. VanSickle, President and Chief Executive Officer

Aaron G. Grandberg, Chief Financial Officer

Calgary, Canada, March 7, 2007

AUDITORS' REPORT

To the Unitholders of Fairborne Energy Trust

We have audited the consolidated balance sheets of Fairborne Energy Trust as at December 31, 2006 and 2005 and the consolidated statements of operations and retained earnings (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2006 and 2005 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

KPMG LLP

Chartered Accountants

Calgary, Canada, March 7, 2007



Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS
As at December 31,

---------------------------------------------------------------------------
($thousands) 2006 2005
---------------------------------------------------------------------------

Assets
Current assets
Cash and cash equivalents $ 764 $ 217
Accounts receivable 70,804 67,055
Prepaid expenses and deposits 3,278 2,911
---------------------------------------------------------------------------
74,846 70,183
Capital assets (Note 3) 448,563 413,567
Goodwill 16,170 16,170
---------------------------------------------------------------------------
$ 539,579 $ 499,920
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 61,490 $ 62,778
Distributions payable 6,198 6,032
---------------------------------------------------------------------------
67,688 68,810
Bank indebtedness (Note 4) 101,156 136,302
Convertible debentures (Note 5) 90,302 -
Non-controlling interest (Note 6) 27,132 27,598
Asset retirement obligation (Note 7) 10,994 11,386
Future income taxes (Note 8) 41,592 51,465

Unitholders' Equity
Unitholders' capital (Note 9) 216,575 199,022
Equity component of convertible debentures (Note 5) 5,581 -
Contributed surplus (Note 9) 4,694 1,758
Retained earnings (deficit) (26,135) 3,579
---------------------------------------------------------------------------
200,715 204,359
---------------------------------------------------------------------------
Commitments (Note 12)
$ 539,579 $ 499,920
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements


Approved on behalf of the Board:

Robert B. Hodgins, Director

Richard A. Walls, Director


CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT)
For the years ended December 31,

---------------------------------------------------------------------------
($thousands except per unit amounts) 2006 2005
---------------------------------------------------------------------------

Revenue
Petroleum and natural gas $ 204,129 $ 226,648
Royalties (33,185) (47,962)
Transportation (5,313) (3,627)
---------------------------------------------------------------------------
165,631 175,059
Expenses
Operating 36,182 35,036
General and administrative 12,286 7,760
Interest and financing costs 9,432 4,772
Trust conversion costs (Note 2) - 6,762
Depletion, depreciation and accretion 74,185 69,312
---------------------------------------------------------------------------
132,085 123,642
---------------------------------------------------------------------------
Income before taxes 33,546 51,417
Taxes (Note 8)
Future (reduction) (15,272) 1,306
Capital 203 1,068
---------------------------------------------------------------------------
(15,069) 2,374
---------------------------------------------------------------------------
Net Income before non-controlling interest 48,615 49,043
Non-controlling interest (Note 6) 4,536 5,490
---------------------------------------------------------------------------
Net income 44,079 43,553
Retained earnings, beginning of year 3,579 26,532
Plan of Arrangement (Note 2) - (36,212)
Reclassification of deficit pursuant to Plan of
Arrangement (Note 2) - 6,832
Distributions declared (73,793) (37,126)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Retained earnings (deficit), end of year $ (26,135) $ 3,579
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net income per unit (Note 9)
Basic $ 0.93 $ 0.92
Diluted $ 0.90 $ 0.89
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,

---------------------------------------------------------------------------
($thousands) 2006 2005
---------------------------------------------------------------------------

Cash provided by (used in):

Operating activities
Net income $ 44,079 $ 43,553
Items not involving cash:
Depletion, depreciation and accretion 74,185 69,312
Non-controlling interest 4,536 5,490
Compensation expense 5,007 2,158
Future taxes (reduction) (15,272) 1,306
Accretion of convertible debentures 362 -
Trust conversion costs - 3,424
Asset retirement expenditures (1,673) (2,801)
---------------------------------------------------------------------------
111,224 122,442
Change in non-cash working capital (3,450) (13,562)
---------------------------------------------------------------------------
107,774 108,880

Financing activities
Convertible debentures, net of costs 95,521 -
Distributions to unitholders (73,627) (31,094)
Bank indebtedness (35,146) 59,083
Issuance of common shares, net of costs - 214
Buy-out of stock options (Note 2) - (9,805)
---------------------------------------------------------------------------
(13,252) 18,398
---------------------------------------------------------------------------
Investing activities
Capital expenditures (69,643) (126,139)
Acquisition of petroleum and natural gas
properties (22,378) -
Disposition of petroleum and natural gas
properties - 13,543
Change in non-cash working capital (1,954) (14,706)
---------------------------------------------------------------------------
(93,975) (127,302)
---------------------------------------------------------------------------
Change in cash and cash equivalents 547 (24)
Cash and cash equivalents, beginning of year 217 241
---------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 764 $ 217
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Cash interest paid $ 7,829 $ 4,788
Capital taxes paid $ 921 $ 1,416
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2006 and 2005

(tabular amounts are stated in thousands and thousands of dollars except per unit amounts)

NATURE OF OPERATIONS:

Fairborne Energy Trust (the "Trust" or "Fairborne") is an open-end, unincorporated investment trust governed by the laws of the Province of Alberta. The Trust was established as part of a Plan of Arrangement entered into by Fairborne Energy Ltd., Fairborne Energy Trust, Fairquest Energy Limited ("Fairquest") and security holders of Fairborne Energy Ltd. (the "Plan of Arrangement") that became effective June 1, 2005.

Pursuant to the Plan of Arrangement, Fairborne Energy Ltd. was reorganized resulting in two new entities, Fairquest, a publicly traded exploration-focused company, and Fairborne Energy Trust. Shareholders of Fairborne Energy Ltd. received one trust unit of the Trust or one exchangeable share of a subsidiary of the Trust and 0.333 of a common share of Fairquest for each common share of Fairborne Energy Ltd.

The purpose of the Trust is to indirectly explore for, develop and hold interests in petroleum and natural gas properties through investments in securities of subsidiaries. The business of the Trust is carried on by Fairborne Energy Ltd. and its subsidiaries and partnerships. The Trust owns, directly and indirectly, 100% of the common shares, (excluding the exchangeable shares - see Note 6) of Fairborne Energy Ltd. The activities of Fairborne Energy Ltd. are financed through interest bearing notes from the Trust and third party debt.

The Trust is required, pursuant to the Trust Indenture, to make distributions to the Unitholders in amounts equal to the net income of the Trust. The Trust earns income from interest on the notes due from Fairborne Energy Ltd. and from any dividends paid on the common shares of Fairborne Energy Ltd., less any expenses of the Trust.

The conversion to a Trust has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for 2005 reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by Fairborne Energy Ltd. Due to the conversion to a trust, certain information included in the financial statements for prior periods may not be directly comparable. For purposes of the consolidated financial statements, the share capital of Fairborne Energy Ltd. is reported under Unitholders' Equity (Note 9).

1. SIGNIFICANT ACCOUNTING POLICIES

a) BASIS OF PRESENTATION

The consolidated financial statements of the Trust have been prepared by management in accordance with generally accepted accounting principles in Canada and they include the accounts of the Trust and its wholly owned subsidiaries. All inter-company transactions have been eliminated.

b) PETROLEUM AND NATURAL GAS OPERATIONS

The Trust follows the full cost method of accounting for petroleum and natural gas properties and facilities whereby all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical costs, lease rental costs on non-producing properties, costs of both productive and unproductive drilling and production equipment. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the depletion rate of 20% or more.

The accumulated costs, less the costs of unproved properties, are depleted and depreciated using the unit-of-production method based on total proved reserves before royalties as determined by independent evaluators. Natural gas reserves and production are converted into equivalent barrels of oil based upon the estimated relative energy content.

The costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of impairment is added to the costs subject to depletion.

The Trust places a limit on the carrying value of petroleum and natural gas properties and equipment, which may be depleted against revenues of future periods (the "ceiling test"). The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

Repairs and maintenance are expensed as operating costs as incurred.

c) ASSET RETIREMENT OBLIGATION ("ARO")

The Trust recognizes the fair value of ARO in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit-of-production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO.

d) INTEREST IN JOINT VENTURES

Substantially all of the Trust's oil and gas exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Trust's proportionate interest in such activities.

e) GOODWILL

The Trust records goodwill relating to acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. Goodwill is assessed for impairment annually at year-end or if events occur that could result in an impairment. Impairment is recognized if the estimated fair value of the Trust is less than the book value of the Trust. If the fair value of the Trust is less than the book value, impairment is measured by allocating the fair value to the identifiable assets and liabilities as if the Trust had been acquired for a purchase price equal to its fair value. The excess of the fair value of the Trust over the amounts assigned to the assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value of goodwill is the impairment amount. Impairment is charged to income in the period in which it occurs.

f) RISK MANAGEMENT

Financial instruments may be utilized by the Trust to manage its exposure to commodity price fluctuations and foreign currency exposures. The Trust's practice is not to utilize financial instruments for trading or speculative purposes.

The Trust formally documents relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process includes linking derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Trust also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items.

Foreign exchange gains and losses on foreign currency exchange swaps used to hedge US dollar denominated commodity contracts are recognized in income as a component of oil and gas sales during the same period as the corresponding hedged position.

The Trust may use forwards, futures and swap contracts to manage its exposure to commodity price fluctuations. The net receipts or payments arising from these contracts are recognized in income as a component of oil and gas sales during the same period as the corresponding hedged position.

g) UNIT BASED COMPENSATION

The Trust has a Trust Incentive plan, which is described in Note 9. Compensation expense associated with the unit based compensation plan is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. Compensation expense is based on the fair value of the unit based compensation at the date of the grant.

The amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in unitholders' capital when unit based compensation plans are exercised.

h) INCOME TAXES

The Trust is a taxable trust under the Canadian Income Tax Act. As income taxes are the responsibility of the individual unitholders and, as the Trust distributes all of its taxable income to its unitholders, no provision has been made for income taxes by the Trust in these financial statements. During 2006 the taxation authorities have released from comment draft legislation which would result in a tax structure for trusts similar to that of corporate entities. If the proposed legislation is implemented the Trust would be required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.

Subsidiary corporations of the Trust and their associated partnerships use the liability method of accounting for future income taxes. Under the liability method, future income tax assets and liabilities are determined based on "temporary differences" (differences between the accounting basis and the tax basis of the assets and liabilities), and are measured using the substantively enacted tax rates and laws expected to apply when these differences reverse. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized.

i) FLOW-THROUGH SHARES

The resource expenditure deductions for income tax purposes related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. A future tax liability is recognized upon the renunciation of tax pools and unitholders' capital is reduced by a corresponding amount.

j) CORPORATE ASSETS

Corporate assets are stated at cost. Depreciation is provided on a declining balance basis at a rate of 20%.

k) CASH AND CASH EQUIVALENTS

The Trust considers cash and short term deposits with original maturities of three months or less as cash and cash equivalents.

l) Convertible debentures

Convertible debentures are recorded at the amount of proceeds received less the amount attributed to the conversion feature, which is included as part of unitholders' equity, and the costs incurred related to the financing. The difference between the recorded amount and the face value of the convertible debentures is charged to income on an effective yield basis.

m) MEASUREMENT UNCERTAINTY

The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenue and expenses for the period then ended. Actual results could differ from those estimates.

The amounts recorded for depletion is based on estimates of reserve volumes and ARO is based on estimated costs and timing of expenditures. The ceiling test calculation is based on estimates of proved and probable reserves, production rates, petroleum and natural gas prices, future costs and relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

n) PER UNIT INFORMATION

Basic per unit amounts are calculated using the weighted average number of units outstanding during the year. Diluted per unit amounts are calculated using the treasury stock method which is based on units that would be issued under Trust incentive plans and the conversion of outstanding exchangeable shares at the end of the period. The dilutive effect of convertible debentures is calculated using the if-converted method which is based on the number of units issuable on conversion of outstanding convertible debentures. In addition, in calculating diluted net income per unit, net income is increased by the non-controlling interest, interest on the convertible debentures and accretion of the convertible debenture discount.

o) REVENUE RECOGNITION

Revenue from the sale of oil and natural gas is recognized when the product is delivered and collection is reasonably assured. Revenue from processing and other miscellaneous sources is recognized upon completion of the relevant service.

2. PLAN OF ARRANGEMENT

Pursuant to the Plan of Arrangement, Fairborne Energy Ltd. transferred to Fairquest certain producing petroleum and natural gas properties and undeveloped lands. At the time of the transaction, Fairborne Energy Ltd. and Fairquest were related parties, therefore, the assets and liabilities transferred to Fairquest were accounted for at their carrying values as follows:



---------------------------------------------------------------------------
Petroleum and natural gas properties and equipment $ 41,712
Future income tax asset 1,908
Cash received on transfer (10,000)
Asset retirement obligations (757)
---------------------------------------------------------------------------
Net assets transferred and reduction in share capital $ 32,863
---------------------------------------------------------------------------
---------------------------------------------------------------------------


In accordance with the Plan of Arrangement, all outstanding stock options of Fairborne Energy Ltd. vested. As a result, the remaining unamortized stock based compensation costs of $3.4 million was charged to earnings. The Trust also incurred $3.4 million of restructuring costs, which together with stock compensation expense has been included in trust conversion costs on the consolidated statement of operations.

Fairborne Energy Ltd. amended its stock option and warrant agreements to permit options and warrants to be exercised on a cashless basis and, in the case of the options, to allow the holder thereof on exercise to receive the intrinsic value payable in cash. As a result, Fairborne Energy Ltd. issued 2,702,292 common shares valued at $34.6 million and paid $9.8 million in cash in settlement of outstanding options and warrants and recorded a reduction in retained earnings as follows:



---------------------------------------------------------------------------
Settlement of outstanding options and warrants for common shares $ 34,643
Settlement of outstanding options for cash 9,805
Contributed surplus related to outstanding options (4,902)
Future tax benefit of cash settlement (3,334)
---------------------------------------------------------------------------
Plan of arrangement costs and reduction in retained earnings $ 36,212
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Pursuant to the Plan of Arrangement, the deficit balance of $6.8 million at May 31, 2005 was reclassified against share capital.

RELATIONSHIP WITH FAIRQUEST ENERGY LIMITED

In conjunction with the Plan of Arrangement, Fairborne and Fairquest entered into a Technical Services Agreement which provides for the shared services required to manage Fairquest's activities and govern the allocation of general and administrative expenses between the entities. Under the Technical Services Agreement, Fairquest is charged a technical services fee by Fairborne, on a cost recovery basis, in respect of the management, development, exploitation, operations and marketing activities on the basis of relative production and capital expenditures. For the year ended December 31, 2006, the technical services fee was $2.6 million (June 1 to December 31, 2005 - $0.9 million). The Technical Services Agreement has no set termination date and will continue until terminated by either party with six months prior written notice to the other party or on some other date as may be mutually agreed.

As a result of the Plan of Arrangement, Fairquest and Fairborne have joint interests in certain properties and undeveloped land. In addition, the companies have entered into farm-in agreements whereby Fairquest received an option to farm-in on 83,000 net acres of Fairborne exploratory lands. As at December 31, 2006, accounts receivable included $6.7 million (December 31, 2005 - $12.4 million) due from Fairquest.



3. CAPITAL ASSETS
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Petroleum and natural gas properties and equipment $ 645,350 $ 537,724
Accumulated depletion (199,111) (126,706)
Corporate assets 3,672 3,099
Accumulated depreciation (1,348) (550)
---------------------------------------------------------------------------
$ 448,563 $ 413,567
---------------------------------------------------------------------------
---------------------------------------------------------------------------



As at December 31, 2006, future development costs of $90 million (2005 - $86.7 million) were included in the depletion calculation and costs of acquiring unproved properties in the amount of $20.7 million (2005 - $22.5 million) were excluded from the depletion calculation. Included in the Trust's petroleum and natural gas properties and equipment balance is $5.9 million (2005 - $6.5 million) relating to asset retirement obligation, net of accumulated depletion.

Fairborne performed a ceiling test calculation at December 31, 2006 and December 31, 2005 to assess the recoverable value of petroleum and natural gas properties and equipment. The oil and gas future prices for the December 31, 2006 ceiling test are based on the January 1, 2007 commodity price forecast of our independent reserve evaluators. The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net revenues from Fairborne's proved reserves exceeded the carrying value of petroleum and natural gas properties and equipment at December 31, 2006.



---------------------------------------------------------------------------
WTI Foreign Edmonton Light AECO
Oil Exchange Crude Oil Gas
Year ($U.S./bbl) Rate ($Cdn/bbl) ($Cdn/mmbtu)
---------------------------------------------------------------------------
2007 62.00 0.87 70.25 7.20
2008 60.00 0.87 68.00 7.45
2009 58.00 0.87 65.75 7.75
2010 57.00 0.87 64.50 7.80
2011 57.00 0.87 64.50 7.85
2012 57.50 0.87 65.00 8.15
2013 58.50 0.87 66.25 8.30
2014 59.75 0.87 67.75 8.50
2015 61.00 0.87 69.00 8.70
2016 62.25 0.87 70.50 8.90
2017 63.50 0.87 71.75 9.10
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Escalate thereafter 2.0% per year


4. BANK INDEBTEDNESS

At December 31, 2006 the Trust had a $165 million extendible revolving term credit facility and a $15 million demand operating credit facility available from a syndicate of Canadian chartered banks, subject to the banks' semi-annual valuation of the Trust's petroleum and natural gas properties. The extendible revolving term facility is available on a revolving basis until May 31, 2007 (364 day facility) at which time it may be extended, at the lenders option. If the revolving period is not extended, the undrawn portion of the facility will be cancelled and the amount outstanding will convert to a 365 day non-revolving term facility. The amounts outstanding under the non-revolving term facility are required to be repaid at the end of the term facility being May 31, 2008. Interest payable on amounts drawn under the facilities is at the prevailing bankers' acceptance rates plus stamping fees, lenders' prime rate or LIBOR rates plus applicable margins, depending on the form of borrowing by the Trust. The margins and stamping fees vary from 0% to 1.5% depending on financial statement ratios and the form of borrowing. The credit facilities are secured by a general security agreement and a first ranking floating charge on the assets of the Trust and by a guarantee and subordination provided by Fairborne Energy Ltd. and all related partnerships and subsidiaries in respect of the Trust's obligations.

Under the terms of the credit facilities and subordination agreements related thereto, any present or future indebtedness of the subsidiaries of the Trust, including the notes owed from Fairborne Energy Ltd. to the Trust, are subordinate to the amounts owing under the credit facilities. Under the terms of the credit facilities and subordination agreements, the Trust is restricted from making distributions when: (i) a default or event of default under the credit facilities has occurred and is continuing; and (ii) outstanding loans under the credit facilities exceeds the borrowing base set by the lenders.

5. CONVERTIBLE DEBENTURES

On October 31, 2006, Fairborne issued 100,000 Convertible Unsecured Subordinated Debentures for gross proceeds of $100 million. The debentures bear interest at a rate of 6.5% per annum, which is payable semi-annually in arrears on December 31 and June 30 of each year commencing June 30, 2007. The debentures have a face value of $1,000 per debenture and mature on December 31, 2011. The debentures can be converted into trust units of Fairborne at any time at the option of the holders at a conversion price of $13.50 per unit. After December 31, 2009 and prior to December 31, 2010, the Trust will have the right to redeem all or a portion of the debentures at a price of $1,050 plus accrued and unpaid interest. After December 31, 2010 and prior to the maturity date, the debentures will be redeemable in whole or in part at the option of the Trust at a redemption price of $1,025 plus accrued and unpaid interest.

Based on the convertible nature of the debentures, they are considered to represent both debt and equity to the Trust under generally accepted accounting principles. The estimated fair value of the debt component of the debentures of $94.4 million is based on the fair value of a similar debt instrument without the conversion feature. The balance of the proceeds, $5.6 million, represents the fair value of the conversion feature and is recorded as the equity component of the debentures. Issue costs of $4.5 million have been offset against the debt component. The debt component will accrete up to the principal balance at maturity and the accretion will be included in interest expense.



The following table shows the convertible debenture activity for the year
ended December 31, 2006:

---------------------------------------------------------------------------
Number of Debt Equity
Debentures Component Component
---------------------------------------------------------------------------
Issued on October 31, 2006 100,000 $ 94,419 $ 5,581
Debt issue costs - (4,479) -
Accretion - 362 -
---------------------------------------------------------------------------
Balance, end of year 100,000 $ 90,302 $ 5,581
---------------------------------------------------------------------------
---------------------------------------------------------------------------


6. NON-CONTROLLING INTEREST

In conjunction with the Plan of Arrangement, Fairborne issued 7.0 million exchangeable shares of a subsidiary of the Trust to former shareholders of Fairborne Energy Ltd. The exchangeable shares are listed on the Toronto Stock Exchange, trade separately from the trust units and represent a non-controlling interest in the financial statements of the Trust. Holders of exchangeable shares do not receive cash distributions.



The following table sets forth a reconciliation of the non-controlling
interest for the years ended December 31, 2006 and 2005:

---------------------------------------------------------------------------
2006 2005
Number of Number of
Exchangeable Exchangeable
Shares Amount Shares Amount
---------------------------------------------------------------------------
Balance, beginning
of year 5,612 $ 27,598 - $ -
Issued pursuant to
Plan of Arrangement
(Note 9b) - - 7,000 27,859
Non-controlling
interest net income - 4,536 - 5,490
Converted to Trust
Units (990) (5,002) (1,388) (5,751)
---------------------------------------------------------------------------
Balance, end of year 4,622 $ 27,132 5,612 $ 27,598
---------------------------------------------------------------------------
---------------------------------------------------------------------------


RETRACTION OF EXCHANGEABLE SHARES

The exchangeable shares can be retracted, at the option of the holder, into trust units at any time based on the exchange ratio in effect on the date of retraction. At December 31, 2006, the exchange ratio was 1:1.15773. The exchange ratio is calculated monthly and is increased, on a cumulative basis, for each distribution by an amount which assumes the reinvestment of distributions in trust units at the then prevailing market price of a trust unit. Similarly, the exchange ratio would be decreased in respect of any dividends paid on the exchangeable shares by the amount of such dividend at the then prevailing market price of a trust unit.

The retraction price is satisfied with trust units equal to the amount determined by multiplying the exchange ratio on the last business day prior to the conversion date by the number of exchangeable shares converted. The non-controlling interest is reduced by the carrying value of exchangeable shares converted.

REDEMPTION OF EXCHANGEABLE SHARES

The exchangeable shares may be redeemed for trust units or an amount in cash equal to the amount determined by multiplying the exchange ratio on the last business day prior to the redemption date by the current market price of a trust unit on the last business day prior to such redemption date ("Redemption Price").

In addition, on a date within the first 90 days of any calendar year, up to 40% of the exchangeable shares originally issued pursuant to the Plan of Arrangement may be redeemed annually at the Redemption Price. On June 1, 2016, subject to extension of such date by the board of directors, the outstanding exchangeable shares will be redeemed at the Redemption Price.

7. ASSET RETIREMENT OBLIGATION

The Trust's asset retirement obligation results from ownership interests in petroleum and natural gas assets including well site, gathering systems and processing facilities. The Trust estimated the total undiscounted amount required to settle its asset retirement obligation to be approximately $47.6 million (2005 - $46.3 million) which is scheduled to be incurred between 2014 and 2025. The majority of the costs are scheduled to be incurred between 2014 and 2020. A credit-adjusted risk-free interest rate of 8.5 percent and an inflation rate of 1.5 percent was used to calculate the fair value of the asset retirement obligation.



A reconciliation of the asset retirement obligation is provided below:
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Balance, beginning of year $ 11,386 $ 13,196
Liabilities incurred 299 622
Liabilities settled (1,673) (2,801)
Dispositions - (757)
Accretion expense 982 1,126
---------------------------------------------------------------------------
Balance, end of year $ 10,994 $ 11,386
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---------------------------------------------------------------------------


8. FUTURE INCOME TAXES

The provision for income taxes in the financial statements differs from the result which would have been obtained in applying the combined federal and provincial tax rate to the Trust's earnings before income taxes. The difference results from the following items:



---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Earnings before taxes $ 33,546 $ 51,417
Combined federal and provincial tax rate 34.86% 37.64%
---------------------------------------------------------------------------
Computed "expected" income tax expense 11,694 19,353
Increase (decrease) in income taxes resulting from:
Non-deductible crown charges 4,119 5,614
Non-deductible unit based compensation 1,745 2,101
Resource allowance (4,550) (6,301)
Net Income attributable to the Trust (25,332) (13,081)
Effect of change in tax rate (2,939) (3,624)
Other (9) (2,756)
---------------------------------------------------------------------------
Future taxes (reduction) (15,272) 1,306
Capital taxes 203 1,068
---------------------------------------------------------------------------
Total taxes $ (15,069) $ 2,374
---------------------------------------------------------------------------
---------------------------------------------------------------------------

The components of the future income tax liability at December 31, 2006
and 2005 are as follows:
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Future income tax liabilities:
Petroleum and natural gas properties and equipment $ 82,496 $ 88,942
Future income tax assets:
Asset retirement obligation (3,207) (3,754)
Share issue costs (646) (1,311)
Loss carryforwards (expire 2007 to 2016) (37,051) (32,412)
---------------------------------------------------------------------------
(40,904) (37,477)
---------------------------------------------------------------------------
Net future income tax liability $ 41,592 $ 51,465
---------------------------------------------------------------------------
---------------------------------------------------------------------------


As income taxes currently are the responsibility of the individual unitholders and the Trust distributes all of its taxable income to its unitholders, no provision has been made for income taxes by the Trust in these financial statements; therefore, excluded from future income tax assets are $5.2 million of share issue costs and convertible debenture issue costs and $1.5 million of loss carryforwards available to the Trust.



9. UNITHOLDERS' CAPITAL AND SHARE CAPITAL OF FAIRBORNE ENERGY LTD.

The Trust Indenture provides that an unlimited number of trust units are
authorized and may be issued.

a) TRUST UNITS OF FAIRBORNE ENERGY TRUST

---------------------------------------------------------------------------
2006 2005
Number Number
of Units Amount of Units Amount
---------------------------------------------------------------------------
Balance, beginning of
year 46,400 $ 199,022 - $ -
Issued pursuant to the
Plan of Arrangement - - 44,979 179,006
Issued on conversion of
exchangeable shares 1,075 15,482 1,421 20,016
Issued on vesting of
restricted units 202 2,071 - -
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Balance, end of year 47,677 $ 216,575 46,400 $ 199,022
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---------------------------------------------------------------------------


During the year ended December 31, 2006, 989,712 exchangeable shares were converted into 1,074,626 trust units. The market value of trust units issued on conversion was $15.5 million resulting in a reduction in non-controlling interest of $5.0 million, an increase in capital assets of $15.9 million and a future tax liability of $5.4 million. During the period June 1 to December 31, 2005, 1,388,270 exchangeable shares were converted into 1,421,413 trust units. The market value of trust units issued on conversion was $20.0 million resulting in a reduction in non-controlling interest of $5.8 million, an increase in capital assets of $21.5 million and a future tax liability of $7.3 million.

REDEMPTION RIGHT

Unitholders may redeem their trust units for cash at any time, up to a maximum value of $100,000 in any calendar month, by delivering their unit certificates to the Trustee, together with a properly completed notice regarding redemption. The redemption amount per trust unit will be the lesser of 95% of the market price of the trust units during the 10 day trading period commencing immediately after the date on which the units were tendered for redemption and the closing market price of the trust units on the principal market on which the units are quoted for trading on the day the units were tendered for redemption, or the average of the last bid and ask prices of the units on that day if there were no trades on that date. If trust units in excess of $100,000 are tendered for redemption in any month, the Trust may, at its sole discretion, issue Notes of the Trust or a subsidiary of the Trust instead of cash for the excess amount.



b) COMMON SHARES OF FAIRBORNE ENERGY LTD.
---------------------------------------------------------------------------
2005
Number of Shares Amount
---------------------------------------------------------------------------
Balance, beginning of year 49,202 $ 220,151
Issued for cash on exercise of options 75 230
Issued on cashless exercise of warrants 1,425 18,267
Issued on cashless exercise of options 1,277 16,376
Reduction in capital for disposition to
Fairquest (Note 2) - (32,863)
Reduction in capital for reclassification
of deficit (Note 2) - (6,832)
Future tax impact of flow through shares - (8,464)
Exchanged for trust units (44,979) (179,006)
Exchanged for exchangeable shares (Note 6) (7,000) (27,859)
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Balance, end of year - $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------

c) PER UNIT AMOUNTS

The following table summarizes the computation of net income per unit:
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Numerator
Net income - basic $ 44,079 $ 43,553
Non-controlling interest 4,536 -
---------------------------------------------------------------------------
Numerator for diluted net income per unit $ 48,615 $ 43,553
---------------------------------------------------------------------------
Denominator
Weighted average units - basic 47,244 47,174
Exchangeable shares 5,296 -
Restricted units 584 294
Performance units 617 168
Stock options - 505
Warrants - 717
---------------------------------------------------------------------------
Denominator for diluted net income per unit 53,741 48,858
---------------------------------------------------------------------------
Basic net income per unit $ 0.93 $ 0.92
Diluted net income per unit $ 0.90 $ 0.89
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Excluded from the diluted number of trust units in 2006 is the effect of convertible debentures (1.2 million units) which are anti-dilutive to net income.

Excluded from the diluted number of trust units in 2005 is the weighted average number of exchangeable shares (3.6 million units) which were anti-dilutive to net income per unit.

d) TRUST INCENTIVE PLAN

In conjunction with the Plan of Arrangement, the Trust established a Trust Incentive Plan (the "Plan") which includes granting of restricted trust units ("Restricted Units") and performance trust units ("Performance Units") to directors, officers, employees and consultants and other service providers to the Trust and its subsidiaries. The total number of trust units issuable under the Plan shall not exceed 5% of the aggregate number of issued and outstanding trust units including the aggregate number of trust units issuable upon exchange of outstanding exchangeable shares.

Restricted Units vest annually over a three-year period and, upon vesting, entitle the holder to receive the number of trust units designated by the Restricted Unit plus the value of accumulated distributions on the vested Restricted Units. Performance Units vest on the third anniversary of the date of grant and actual payouts will be determined based on the performance of the Trust compared to its peers. Performance factors range from zero to two times the initial Performance Unit grant. Performance Units also receive additional trust units equal to the value of accumulated distributions paid to unitholders during the vesting period. Payouts under the Trust Incentive Plan may be in cash, trust units or some combination thereof at the discretion of the board of directors.



The following tables set forth a reconciliation of the Trust Incentive Plan
activity for the years ended December 31, 2006 and 2005:

---------------------------------------------------------------------------
2006
Number of Number of
Restricted Performance
Units Units Total
---------------------------------------------------------------------------
Balance, beginning of year 562 323 885
Issued 144 326 470
Exercised (183) - (183)
Forfeited (27) (20) (47)
---------------------------------------------------------------------------
Balance, end of year 496 629 1,125
---------------------------------------------------------------------------
Exercisable, end of year - - -
---------------------------------------------------------------------------
Equivalent trust units, end of year (1) 554 721 1,275
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) including additional trust units to be issued for accumulated
distributions earned under the Trust Incentive Plans.

---------------------------------------------------------------------------
2005
Number of Number of
Restricted Performance
Units Units Total
---------------------------------------------------------------------------
Balance, beginning of year - - -
Issued 562 323 885
---------------------------------------------------------------------------
Balance, end of year 562 323 885
---------------------------------------------------------------------------
Exercisable, end of year - - -
---------------------------------------------------------------------------
Equivalent trust units, end of year 590 339 929
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The fair value of Performance and Restricted Units were determined using the unit price at the grant date and, in the case of the Performance Units, a performance factor of one time was used. The weighted average fair value of Restricted and Performance Units granted during 2006 was $14.03 and $15.03 per unit respectively. For the period June 1 to December 31, 2005, the weighted average fair value was $11.34 per unit for Restricted Units and $11.47 per unit for Performance Units granted. The estimated fair value of units granted is amortized through compensation expense over the vesting period with a corresponding increase in contributed surplus.

e) STOCK OPTIONS

The following table sets forth a reconciliation of the stock option plan activity for the year ended December 31, 2005:




---------------------------------------------------------------------------
2005
Weighted
average
Number of exercise
Options price
---------------------------------------------------------------------------
Outstanding, beginning of year 3,624 $ 5.40
Granted 158 14.25
Exercised (75) 2.87
Settled for cash or shares (3,707) 5.83
---------------------------------------------------------------------------
Outstanding, end of year - $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The weighted average fair value of stock options granted during 2005 was $4.50 per option using the Black-Scholes option pricing model with the following weighted average assumptions: risk free interest rate of 4 percent, expected volatility of 40 percent and expected life of 3 years.

f) CONTRIBUTED SURPLUS

The following table sets forth a reconciliation of the contributed surplus for the years ended December 31, 2006 and 2005:



---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Balance, beginning of year $ 1,758 $ 1,094
Restricted and Performance Units issued 5,134 1,759
Restricted Units exercised (2,071) -
Trust Incentive Plan grants forfeited (127) (1)
Options granted - 400
Options exercised - (16)
Options vested under Plan of Arrangement - 3,424
Options settled for cash and shares - (4,902)
---------------------------------------------------------------------------
Balance, end of year $ 4,694 $ 1,758
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10. FINANCIAL INSTRUMENTS

a) CREDIT RISK

Virtually all of the Trust's accounts receivable are from counterparties in the oil and gas industry and are subject to normal industry credit risks.

b) FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying value of the Trust's financial instruments, other than bank indebtedness, approximate their fair value due to their short maturity. The fair value of the bank indebtedness approximates its carrying value as it bears interest at a floating rate. The fair value of the convertible debentures approximates its carrying value excluding debt issue costs.

11. FORWARD SALES CONTRACTS

The Trust has a price risk management program whereby the Trust sells forward a portion of its future production through fixed price physical sales contracts with customers.



The following table summarizes the natural gas fixed price physical sales
contracts outstanding at December 31, 2006:

---------------------------------------------------------------------------
Volume Price
Remaining Term (GJ per day) (CDN$ per GJ) Settlement Index
---------------------------------------------------------------------------
AECO Collars
Jan 1,2007 - Mar 31,2007 2,500 8.50 - 13.22 AECO C Daily
Jan 1,2007 - Mar 31,2007 2,500 9.00 - 13.00 AECO C Daily
Jan 1,2007 - Mar 31,2007 2,000 9.00 - 10.30 AECO C Daily
Jan 1,2007 - Mar 31,2007 2,000 9.00 - 11.65 AECO C Daily
Jan 1,2007 - Mar 31,2007 5,000 8.50 - 11.20 AECO C Daily
Jan 1,2007 - Mar 31,2007 3,000 9.00 - 10.55 AECO C Daily

AECO Participating Swaps
Jan 1,2007 - Mar 31,2007 3,000 9.15 + 50% Partic. AECO C Daily

AECO Swaps
Jan 1,2007 - Mar 31,2007 2,000 9.20 AECO C Monthly
Jan 1,2007 - Mar 31,2007 2,500 8.00 AECO C Monthly
Apr 1,2007 - Oct 31,2007 2,500 8.10 AECO C Monthly
Apr 1,2007 - Oct 31,2007 2,500 8.11 AECO C Monthly
Apr 1,2007 - Jun 30,2007 3,000 6.785 AECO C Monthly
Apr 1,2007 - Jun 30,2007 4,000 6.80 AECO C Monthly
Apr 1,2007 - Jun 30,2007 3,000 6.70 AECO C Monthly
Apr 1,2007 - Jun 30,2007 3,000 6.745 AECO C Monthly
Apr 1,2007 - Jun 30,2007 3,000 6.75 AECO C Monthly
Oct 1,2007 - Dec 31,2007 2,500 8.16 AECO C Monthly
Nov 1,2007 - Mar 31,2008 1,500 8.25 AECO C Monthly
Nov 1,2007 - Mar 31,2008 2,500 8.71 AECO C Monthly
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---------------------------------------------------------------------------

The following crude oil fixed price physical sales contract were
outstanding at December 31, 2006:

---------------------------------------------------------------------------
Volume Price
Remaining Term (bbls/day) (US$ per bbl) Settlement Index
---------------------------------------------------------------------------
Puts
Jan 1,2007 - Mar 31,2007 500 $ 70.00 WTI
Jan 1,2007 - Mar 31,2007 400 $ 70.00 WTI
Apr 1,2007 - Jun 30,2007 500 $ 77.00 WTI
Collars
Apr 1,2007 - Jun 30,2007 500 $ 63.00-$70.00 WTI
Swaps
Jul 1,2007 - Sep 30,2007 500 $ 70.68 WTI
Oct 1,2007 - Dec 31,2007 500 $ 70.98 WTI

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


12. COMMITMENTS

The Trust has certain lease commitments for its office premises through to June 2011. As at December 31, 2006 the payments due under these commitments are approximately $929,000 per annum.

Fairborne has entered into a three year contractual agreement with a third party drilling company for the use of one of their drilling rigs. The contract, which commenced on December 30, 2006, involves an annual commitment of $4.3 million.

FORWARD LOOKING STATEMENTS: This document contains forward-looking statements. Management's assessment of future plans and operations, production estimates and expected production rates, levels of distributions on Trust Units and the payout ratio, cash available for distribution and its availability for capital expenditures and distributions, expected commodity prices, whether cash taxes will be payable, expected royalty rates, the effect of infrastructure interruptions, timing of tie-in of wells, capital expenditures and methods of financing capital expenditures may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, the Trust's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhausted. Additional information on these and other factors that could effect the Trust's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or at the Trust's website (www.fairbornetrust.com). Furthermore, the forward-looking statements contained in this document are made as at the date of this document and the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

BOE CONVERSIONS: Barrel of oil equivalent ("BOE") amounts may be misleading, particularly if used in isolation. A BOE conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel and is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalency at the wellhead.

Contact Information

  • Fairborne Energy Trust
    S.R. VanSickle
    President & CEO
    (403) 290-7750
    (403) 290-7724 (FAX)
    or
    Fairborne Energy Trust
    A. G. Grandberg
    Chief Financial Officer
    (403) 290-7750
    (403) 290-7724 (FAX)
    or
    Fairborne Energy Trust
    3400, 450 - 1st Street S.W.
    Calgary, Alberta T2P 5H1
    Email: info@fairbornetrust.com
    Website: www.fairbornetrust.com