NAL Oil & Gas Trust
TSX : NAE.UN

NAL Oil & Gas Trust

February 26, 2009 16:30 ET

NAL Oil & Gas Trust Posts Strong 2008 Year End Reserves, Financial and Operating Performance

CALGARY, ALBERTA--(Marketwire - Feb. 26, 2009) - NAL Oil & Gas Trust (TSX:NAE.UN) ("NAL" or the "Trust") today announced its financial and operational results for the fourth quarter and year ended December 31, 2008 as well as 2008 year-end reserves. All amounts are in Canadian dollars unless otherwise stated.

SUMMARY

NAL delivered impressive results in 2008 characterized by excellent reserves performance, meeting 2008 guidance and maintaining a strong financial position. Andrew Wiswell, President and CEO commented "Strong reserves replacement performance and improved finding and development ("F&D") costs are successful outcomes of NAL's strategy to continually generate opportunities organically. Maintaining an active development program in the fourth quarter enabled the Trust to meet guidance in 2008, hit its target exit rate and position it for success in 2009. The Trust exited 2008 with a total debt to cash flow ratio of 1.28 times and possesses an attractive 2009 hedge portfolio supporting cash flows in a challenging environment. NAL's relatively strong financial standing, positions the Trust well to capture opportunities in the future".

2008 RESERVES AND FINDING & DEVELOPMENT HIGHLIGHTS

- In 2008, NAL continued to improve its reserves added performance primarily through internally generated opportunities. Year-end proved plus probable reserves increased 7.2 percent from 68.2 million boe at year-end 2007 to 73.1 million boe at the end of 2008 through additions across all of our core areas.

- Overall, the Trust replaced 156 percent of its 2008 production. Excluding acquisitions, the replacement of production through discoveries, extensions, infill drilling, well recompletions and technical revisions increased from 96 percent in 2007 to 116 percent in 2008.

- NAL's total reserve base continues to be stable and reliable with proved reserves representing 72 percent of total proved plus probable reserves and proved producing reserves representing 94 percent of the total proved category. The reserves mix remains relatively consistent at 43 percent crude oil, 10 percent natural gas liquids and 47 percent natural gas.

- The Trust continued its solid F&D performance in 2008 with costs of $14.18 per boe proved and $16.24 per boe proved plus probable, including changes in future development costs ("FDC"), representing a proved recycle ratio of 2.8 times. Including the effects of acquisitions, the finding, development and acquisition costs were $19.41 per boe proved and $19.66 on a proved plus probable basis, representing a proved plus probable recycle ratio of 2.3 times.

- At the end of 2008, NAL's reserve life index ("RLI") was 8.8 years, an increase from 8.2 years at year-end 2007 and higher than the Trust's historical range of 8.0 to 8.6 years over the past five years.

- Proved plus probable reserves per unit increased from 0.754 boe at the end of 2007 to 0.760 boe at the end of 2008.



2008 RESERVES AND FINDING & DEVELOPMENT SUMMARY

2008 2007 % Change
----------------------------------------------------------------------------
Proved + Probable Reserves (MMboe) 73.1 68.2 +7.2
RLI (years) 8.8 8.2 +7.3

% of Production Replaced(1) 116% 96% +20.8

Proved Reserves
F&D(2) ($/boe) 14.18 13.99 +1.4
FD&A(2) ($/boe) 19.41 23.20 -16.3
Recycle Ratio(3) 2.3 1.5 +53.3

P+P Reserves
F&D(2) ($/boe) 16.24 17.71 -8.3
FD&A(2) ($/boe) 19.66 21.67 -9.3
Recycle Ratio(3) 2.3 1.6 +43.8
Operating Netback ($/boe) 45.39 34.27 +32.4
----------------------------------------------------------------------------

(1) Excludes acquisitions.
(2) Includes changes in FDC.
(3) Recycle ratio defined as operating netback divided by FD&A including
changes in FDC.


2008 OPERATING AND FINANCIAL PERFORMANCE HIGHLIGHTS

- Record quarterly average production of 23,984 boe/d was achieved in the fourth quarter, despite a challenging commodity price environment. Full year average production of 23,797 boe/d is the highest in NAL's 13 year history. NAL remained committed to its fourth quarter development program in order to set-up opportunities for 2009.

- Funds flow from operations ("FFO") of $3.29 per unit represents a 24 percent increase over 2007 FFO of $2.65 per unit. NAL maintained distributions of $0.16 per month for a total of $1.92 per unit in 2008, representing a basic payout ratio of 58 percent versus 73 percent in 2007.

- A year-end net debt to cash flow ratio of 1.0 times (total debt to cash flow of 1.28 times) provides financial flexibility to complete a transaction should the right opportunity present itself.

- On December 31, 2008 the effective interest rate on amounts outstanding under the credit facility was 3.57 percent versus 5.74 percent in 2007.

- Excluding acquisitions, capital spending totaled $150.5 million in 2008, up from $118.0 million in 2007. Of the $150.5 million, 71 percent ($107.3 million) was directed toward drilling, completions and tie-in activities.

- Premium crude oil price realizations continue to support a top quartile operating netback of $45.39 per boe, up 32 percent over the 2007 average of $34.27 per boe.

OUTLOOK FOR 2009

On January 12, 2009, NAL announced full year guidance based on annual average commodity price assumptions of US$50/bbl WTI and Cdn$6.50/GJ AECO natural gas. Actual commodity prices have been significantly below these assumptions year-to-date and the Trust continues to manage the capital program and level of distributions with a target of living within forecast cash flow. Also within the guidance announcement, the Trust announced a revised monthly distribution of $0.11 per unit beginning with the January 2009 distribution payable in February 2009.

In light of the persistently low commodity price and cash flow environment, management has elected to defer $15 million in capital projects originally planned for the first half of 2009 until economic conditions, service costs and cash flows improve. NAL has substantially more attractive opportunities in inventory than capital and remains prepared to ramp up its development program should conditions improve throughout the year. The table below summarizes the impact of the $15 million deferral on 2009 full year guidance.



2009 Guidance

Revised January 2009
----------------------------------------------------------------------------
Average total production (boe/d) 22,000 - 23,000 22,200 - 23,500
Capital expenditures ($ millions) 95 110
Operating costs ($/boe) 11.60 - 11.90 11.60 - 11.90


The Trust will announce the March distribution on or before March 11, 2009.

FORWARD-LOOKING INFORMATION

Please refer to the disclaimer on forward-looking information set forth under the Management's Discussion and Analysis in this document. The disclaimer is applicable to all forward-looking information in this document, including the outlook for full year 2009 and the 2009 full year guidance set forth above.

NON-GAAP MEASURES

Please refer to the discussion of non-GAAP measures set forth under the Management's Discussion and Analysis regarding the use of the following terms: "funds from operations", "payout ratio" and "operating netbacks".

CONFERENCE CALL DETAILS

At 3:30 p.m. MST (5:30 p.m. EST) on Thursday, February 26, 2009, NAL will hold a conference call to discuss the fourth quarter and year-end 2008 results. Mr. Andrew Wiswell, President and CEO, will host the conference call with other members of the Management Team. The call is open to analysts, investors, and all interested parties. If you wish to participate, call 1-866-300-4047 toll free across North America. The conference call will also be accessible through the internet at http://events.onlinebroadcasting.com/nal/022609/index.php

A recorded playback of the call will be available until March 5, 2009 by calling 1-800-408-3053, reservation 3282777.

Notes:
(1) All amounts are in Canadian dollars unless otherwise stated.

(2) When converting natural gas to barrels of oil equivalent (boe) within this report, NAL uses the widely recognized standard of six thousand cubic feet (Mcf) to one barrel of oil. However, boe's may be misleading, particularly if used in isolation. A conversion ratio of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.



FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)

-----------------------------------------
(unaudited)
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
FINANCIAL
Gross revenue, net of royalties,
before hedging $ 86,874 $ 98,413 $ 492,484 $ 328,766
Cash flow from operating activities 77,326 45,111 320,042 215,364
Cash flow per unit - basic 0.80 0.50 3.39 2.61
Cash flow per unit - diluted 0.77 0.48 3.24 2.56
Funds from operations 67,040 59,537 311,071 218,745
Funds from operations per unit -
basic 0.70 0.66 3.29 2.65
Funds from operations per unit -
diluted 0.67 0.63 3.15 2.60
Net income 55,374 10,556 162,580 56,457
Distributions declared 46,167 43,340 181,462 158,601
Distributions per unit 0.48 0.48 1.92 1.92
Basic payout ratio:
based on cash flow from operating
activities 60% 96% 57% 74%
based on funds from operations 69% 73% 58% 73%
Basic payout ratio including
capital expenditures(5) :
based on cash flow from operating
activities 110% 183% 101% 128%
based on funds from operations 126% 139% 104% 126%
Units outstanding (000's)
Period end 96,181 90,494 96,181 90,494
Weighted average 96,145 90,194 94,415 82,556
Capital expenditures(1) 41,212 39,194 150,472 118,011
Property acquisitions
(dispositions), net (127) - 8,082 1,423
Corporate acquisitions 315 - 58,356 245,687
Net debt(2) 319,044 291,059 319,044 291,059
Convertible debentures (at face
value) 79,744 100,000 79,744 100,000

OPERATING
Daily production(3)
Crude oil (bbl/d) 10,223 9,722 10,188 9,366
Natural gas (mcf/d) 69,049 71,067 68,898 55,422
Natural gas liquids (bbl/d) 2,254 2,090 2,126 2,078
Oil equivalent (boe/d) 23,984 23,656 23,797 20,681

OPERATING NETBACK (boe)
Revenue before hedging gains
(losses) 48.51 56,59 70.62 54.85
Royalties (9.59) (11.78) (14.52) (11.66)
Operating costs (11.67) (9.90) (10.90) (9.26)
Other income(4) 0.18 0.32 0.19 0.34
----------------------------------------------------------------------------
Operating netback before hedging 27.43 35.23 45.39 34.27
Hedging gains (losses) 7.49 (2.53) (3.14) (0.32)
----------------------------------------------------------------------------
Operating netback 34.92 32.70 42.25 33.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes property and corporate acquisitions.
(2) Bank debt plus working capital, excluding derivative contracts, notes
payable/receivable and future income tax balances.
(3) Includes royalty income volumes.
(4) Excludes interest on notes with MFC.
(5) Capital expenditures included are net of NCI amount of $7.9 million
attributable to the Tiberius and Spear properties.


OIL AND GAS RESERVES

NAL's 2008 year-end reserves were evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel"), independent engineering consultants in Calgary, in accordance with National Instrument ("NI") 51-101. At December 31, 2008, the Trust's proved reserves totaled 52.4 million barrels of oil equivalent ("boe") and proved plus probable ("P+P") reserves amounted to 73.1 million boe.

NAL has a reserves committee, composed entirely of independent directors, which is responsible for appointing the Trust's independent engineering consultants and determining the scope of the annual reserves review.

Some key points regarding NAL's 2008 reserves summary are:

- Additions for improved recovery, which includes discoveries, extensions, infill drilling and well recompletions, amounted to 3,897 Mboe of proved and 7,747 Mboe of P+P reserves. This represents new reserves added from development activity, over and above volumes that were previously booked in the reserves report. These reserves additions occurred across all of NAL's core areas, with the larger ones resulting from successful drilling results in the Alida, Midale and Steelman areas in Saskatchewan, the Garrington, Westward Ho and Hanna areas in Alberta, as well as the Sukunka area in British Columbia.

- Overall technical revisions amounted to 5,663 Mboe for proved and 2,213 Mboe for P+P reserves. The technical revisions were widespread among all producing areas, and were largely the result of positive performance trends observed in numerous producing wells and the reclassification of reserves from probable to proved to reflect increased levels of certainty.

- The total P+P reserves additions for improved recovery and technical revisions amount to 9,960 Mboe, which represents a 116 percent replacement ratio of 2008 production of 8,617 Mboe. Including acquisitions, the Trust's total reserves replacement ratio for 2008 was 156 percent.

- At December 31, 2008, over 94 percent of NAL's proved reserves were in the Proved Producing category. NAL continues to take a conservative approach in booking undeveloped reserves in the Proved Undeveloped category.

- Using the P+P reserves of 73,055 Mboe and the number of outstanding trust units at December 31, 2008 of 96,181,397, the P+P reserves at year-end 2008 amounted to 0.760 boe per unit. This represents a slight increase from 0.754 boe per unit at year-end 2007.

The following tables summarize NAL's estimated reserves volumes and values using McDaniel price forecasts as of January 1, 2009. Gross reserves volumes are based on the Trust's working interests before deduction of royalties payable, and exclude any wells or properties in which NAL has only a royalty interest. Net reserves represent the Trust's working interest reserves after deducting royalties payable, plus royalty interest reserves. The Natural Gas category includes non-associated gas, solution gas from oil wells and coal bed methane volumes, as the solution gas and coal bed methane volumes are not considered material in terms of requiring separate reporting. For the properties acquired in the Tiberius Exploration Inc. ("Tiberius") and Spear Exploration Inc. ("Spear") corporate acquisitions, the gross reserves reported represent the totals for NAL Energy Limited Partnership, as NAL is the controlling partner in the partnership holding those assets. A related party owns a 50 percent non-controlling interest in the partnership, and as such, receives a Net Profits Interest ("NPI") royalty payment from the partnership. This NPI is deducted from NAL's net reserves, such that the resulting net (after royalty) reserves reflect NAL's net share.



Numbers may not add exactly due to rounding.

----------------------------------------------------------------------------
Summary of Oil and Gas Reserves
As at December 31, 2008
Forecast Prices and Costs
----------------------------------------------------------------------------
Reserves
Light and Natural Gas Total BOE
Medium Oil Natural Gas Liquids (6:1)
Reserves Gross Net Gross Net Gross Net Gross Net
Category (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
----------------------------------------------------------------------------
Proved
Developed
Producing 21,134 17,967 139,580 119,273 4,870 3,329 49,268 41,175
Developed
Non
-Producing 100 82 7,110 5,338 52 36 1,337 1,007
Undeveloped 738 603 5,620 4,759 101 64 1,775 1,460
---------------------------------------------------------------
Total Proved 21,972 18,652 152,311 129,370 5,022 3,429 52,380 43,642
Probable 9,581 7,862 54,548 44,869 2,003 1,351 20,675 16,692
---------------------------------------------------------------
Total Proved
Plus
Probable 31,553 26,514 206,859 174,239 7,026 4,780 73,055 60,334
----------------------------------------------------------------------------



----------------------------------------------------------------------------
Net Present Values of Future Net Revenue
Forecast Prices and Costs
----------------------------------------------------------------------------


Before Income Taxes, Discounted at (percent/year)
0% 5% 10% 15%
Reserves Category (million $) (million $) (million $) (million $)
----------------------------------------------------------------------------

Proved
Developed Producing 1,727 1,325 1,077 911
Developed Non-Producing 41 32 26 22
Undeveloped 43 29 20 14
---------------------------------------------
Total Proved 1,811 1,385 1,123 947
Probable 839 488 320 227
---------------------------------------------
Total Proved Plus Probable 2,650 1,873 1,443 1,174
----------------------------------------------------------------------------


The table above shows the before-tax net present value ("NPV") of the Trust's reserves at various discount rates.

It should not be assumed that the estimated future net revenue is representative of the fair market value of the properties of the Trust. There is no assurance that such price and cost assumptions will be attained and variances could be material.



----------------------------------------------------------------------------
Summary of Pricing and Inflation Rate Assumptions
As at December 31, 2008
Forecast Prices and Costs
----------------------------------------------------------------------------
Oil

Edmonton Cromer Natural Gas
WTI Cushing Par Price Medium AECO Spot
Oklahoma 40(degrees) API 29.3(degrees) Price
Year ($US/bbl) ($Cdn/bbl) API ($Cdn/bbl) ($Cdn/MMBtu)
----------------------------------------------------------------------------

2009 60.00 69.60 61.80 7.40
2010 71.40 83.00 73.70 8.00
2011 83.20 91.40 81.20 8.45
2012 90.20 93.90 83.40 8.80
2013 97.40 96.30 85.60 9.05
2014 99.40 98.30 87.40 9.25
Thereafter(i) +2%/yr +2%/yr +2%/yr +2%/yr


Natural Gas
Liquids
Edmonton Mix Inflation Rates Exchange Rate
Year ($Cdn/bbl) Percent/Year ($US/Cdn)
----------------------------------------------------------------------------

2009 52.00 2.0 0.850
2010 61.10 2.0 0.850
2011 66.90 2.0 0.900
2012 68.90 2.0 0.950
2013 70.70 2.0 1.000
2014 72.20 2.0 1.000
Thereafter(i) +2%/yr 2.0 1.000

(i) Price escalation rates are approximate.


----------------------------------------------------------------------------
Reconciliation of
Company Gross Reserves
By Principal Product Type
Forecast Prices and Costs
----------------------------------------------------------------------------
Associated and Non-
Light and Medium Oil Associated Gas
Proved Proved
Plus Plus
Proved Probable Proved Probable
----------------------------------------------------------------------------
Factors (Mbbl) (Mbbl) (MMcf) (MMcf)
----------------------------------------------------------------------------

December 31, 2007 20,410 27,652 146,347 202,590

Improved Recovery(i) 1,732 3,676 11,291 21,318
Technical Revisions 1,941 866 18,837 6,517
Acquisitions 1,575 3,044 793 1,391
Dispositions 0 0 0 0
Production (3,686) (3,686) (24,957) (24,957)

December 31, 2008 21,972 31,553 152,311 206,859
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Natural Gas Liquids Total BOE
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (Mbbl) (Mbbl) (Mboe) (Mboe)
----------------------------------------------------------------------------

December 31, 2007 4,816 6,795 49,618 68,212

Improved Recovery(i) 283 518 3,897 7,747
Technical Revisions 583 261 5,663 2,213
Acquisitions 111 223 1,818 3,499
Dispositions 0 0 0 0
Production (772) (772) (8,617) (8,617)

December 31, 2008 5,022 7,026 52,380 73,055
----------------------------------------------------------------------------
(i) Improved Recovery includes discoveries, extensions, infill drilling and
well recompletions.


FINDING AND DEVELOPMENT COSTS

Finding and Development ("F&D") costs are reported below for proved and P+P reserves, in each case after eliminating the effects of acquisitions and dispositions, and including changes in future development costs as per NI 51-101 guidelines. The total reserves changes in the improved recovery and technical revisions categories of the reconciliation table, excluding the changes that relate to the acquired properties, are used in the F&D calculation.

The capital spending of $132.73 million used in the F&D calculation for 2008 represents the Trust's total expenditures for drilling, completion and production equipment, plant and facility costs (including maintenance capital items that supported NAL's base production volumes and helped maintain NAL's low operating cost structure), plus seismic and land costs, capitalized G&A and unit-based incentive costs. The capital that was spent within properties that were acquired in 2008 is not included in the F&D calculation, as it is included in the Finding, Development and Acquisition ("FD&A") calculation in the section which follows.

The F&D costs for 2008, as shown in the table below, were $14.18 per boe for proved and $16.24 per boe for P+P reserves. It should be noted that the aggregate of the development costs incurred during the year and the change in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. As a result, the three-year weighted average, with changes tracked over time, provides a useful indicator of capital effectiveness as it relates to reserves development. As shown in the table below, the weighted average F&D costs for the three-year period from 2006 through 2008 are $16.47 per boe for proved and $20.68 per boe for P+P reserves.



2008
----------------------------------------------------------------------------
Actual Spending Change in Estimated
During 2008 Future Development Costs Total
------------- ------------------------ --------
Capital Proved 132,730 2,020 134,750
($000s) Proved +
Probable 132,730 36,051 168,781
----------------------------------------------------------------------------


Improved Recovery Technical Revisions Total
------------------- --------------------- --------
Reserves Proved 3,770 5,736 9,505
(Mboe) Proved +
Probable 7,849 2,542 10,392
----------------------------------------------------------------------------

F&D Proved
($/boe) Proved + $ 14.18
Probable $ 16.24
----------------------------------------------------------------------------


3-YEAR WEIGHTED AVERAGE
----------------------------------------------------------------------------
Change in
Actual Estimated
Spending Future
Over Development
3 Years Costs Total
----------- ------------- ---------
Capital ($000s) Proved 359,482 (9,614) 349,868
Proved +
Probable 359,482 26,684 386,166
----------------------------------------------------------------------------
Improved Technical
Recovery Revisions Total
----------- ------------- ---------
Reserves (Mboe) Proved 7,502 13,739 21,241
Proved +
Probable 13,747 4,923 18,670
----------------------------------------------------------------------------
F&D ($/boe) Proved $16.47
Proved +
Probable $20.68
----------------------------------------------------------------------------


Some reporting issuers report F&D costs excluding changes in future development capital ("FDC"). Although not NAL's usual practice, such numbers are provided for comparison purposes. Excluding changes in FDC, the Trust's F&D costs for 2008 would have been $13.96 per boe for proved and $12.77 per boe for P+P. Another methodology excludes capitalized G&A costs and unit-based incentive costs from the current year capital. On that basis, NAL's F&D costs for 2008 would have used $127.7 million of capital spending in the F&D calculation, resulting in $13.43 per boe for proved and $12.29 per boe for P+P.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

A significant part of NAL's business activity in any given year is the acquisition and, to a lesser degree, the disposition of properties. In order to provide a more representative measure of the company's total capital spending as it relates to reserves development, FD&A costs are reported including the effects of acquisitions and dispositions.

During 2008 the Trust completed the acquisition of Tiberius and Spear, along with some minor property acquisitions in Alberta and Saskatchewan. For detailed discussion of the Tiberius and Spear acquisition, see page 12 of the MD&A. The FD&A calculation incorporates all the components used in the F&D calculation, plus the adjustments to capital spending and reserves related to the acquisition and disposition activities completed during the year, as shown in the table below.

The FD&A costs for 2008 were $19.41 per boe for proved and $19.66 per boe for P+P reserves. The weighted average FD&A costs for the three-year period from 2006 through 2008 were $22.47 per boe for proved and $22.76 per boe for P+P reserves. These three-year averages provide a measure of the Trust's overall capital spending effectiveness.



2008
----------------------------------------------------------------------------
Change in
Actual Estimated
Spending Future Total
During Development Acquisi- Disposi- including
2008 Costs tions tions A&D
--------- ----------- --------- --------- ----------
Capital
($000s) Proved 148,527 4,710 67,594 0 220,831
Proved +
Probable 148,527 48,496 67,594 0 264,617

Total
Improved Technical Acquisi- Disposi- including
Recovery Revisions tions tions A&D
--------- ----------- --------- --------- ----------
Reserves
(Mboe) Proved 3,897 5,663 1,818 0 11,378
Proved +
Probable 7,747 2,213 3,499 0 13,459
----------------------------------------------------------------------------
FD&A ($/boe) Proved $19.41
Proved +
Probable $19.66
----------------------------------------------------------------------------


3-YEAR WEIGHTED AVERAGE
----------------------------------------------------------------------------
Change in
Actual Estimated
Spending Future Total
Over Development Acquisi- Disposi- including
3 Years Costs tions tions A&D
--------- ----------- --------- --------- ----------
Capital
($000s) Proved 384,032 (3,079) 317,816 (1,940) 696,828
Proved +
Probable 384,032 46,714 317,816 (1,940) 746,621
----------------------------------------------------------------------------

Total
Improved Technical Acquisi- Disposi- including
Recovery Revisions tions tions A&D
--------- ----------- --------- --------- ----------
Reserves
(Mboe) Proved 8,079 13,882 9,120 (71) 31,010
Proved +
Probable 14,506 4,432 13,957 (86) 32,810
----------------------------------------------------------------------------
FD&A ($/boe) Proved $22.47
Proved +
Probable $22.76
----------------------------------------------------------------------------


As discussed in the previous section for F&D costs, NAL is providing the FD&A numbers excluding changes in FDC for comparison purposes. Excluding changes in FDC, the Trust's FD&A costs for 2008 would be $18.99 per boe for proved and $16.06 per boe for P+P reserves. If the capitalized G&A and unit based incentive costs are excluded from the current year capital, the calculation would be based on 2008 capital spending of $143.5 million, resulting in FD&A costs of $18.55 per boe for proved and $15.68 per boe for P+P.

RESERVE LIFE INDEX

Reserve Life Index ("RLI") is calculated by dividing reserves at December 31, 2008 by expected annual production for 2009. RLI is useful in making generalized comparisons between companies but does not accurately represent the anticipated life of the Trust's reserves. Due to the natural decline of oil and gas production, the actual producing life of oil and gas properties is much longer than the RLI calculation would suggest.

In the McDaniel reserves report, the average production forecasted for 2009 in the P+P reserves case is 22,827 boe/d. This number is within NAL's 2009 guidance range of 22,000 to 23,000 boe/d. For consistency, the RLI calculation is based on the reserves at December 31, 2008 and the forecasted annual production for 2009 from the reserves report. Using those numbers, NAL's RLI for P+P reserves has increased from 8.2 years at year-end 2007 to 8.8 years at year-end 2008.

LAND AND SEISMIC

At December 31, 2008, NAL held an average 29.5 percent working interest in 1,053,398 gross acres (310,852 net acres) of undeveloped land. Most of NAL's land is owned in common with Manulife Financial Corporation ("MFC"), which results in NAL operating over 80 percent of its production and prospective acreage. Based on an internal estimate and using market benchmarks, NAL estimates that its undeveloped land and seismic value is approximately $114.1 million.

NET ASSET VALUE

The following net asset value calculations are based on what is generally referred to as the "produce-out" net present values of the Trust's oil and gas reserves as evaluated by independent engineering consultants in accordance with National Instrument 51-101.



December 31, 2008 December 31, 2007
----------------------------------------------------------------------------
Using Forecast Using Forecast
($000s, except per unit data) Prices(5) Prices(6)
----------------------------------------------------------------------------

Proved plus probable reserves
(before tax, discounted at 10 percent) 1,443,004 1,282,473
Undeveloped land and seismic(1) 114,063 83,758
Working capital (deficiency)(2) (36,712) (15,429)
Long-term debt(3) (357,226) (368,254)
Asset retirement obligation(4) (52,132) (55,986)

Net asset value 1,110,997 926,562

Units outstanding (000s) 96,181 90,494
NAV per unit $11.55 $10.24
----------------------------------------------------------------------------

(1) Internal estimate.
(2) Working capital deficiency excludes the fair value of derivative
contracts, future income taxes and notes due to/from MFC.
(3) Includes bank debt, convertible debentures and long-term payables for
unit-based compensation.
(4) The Asset Retirement Obligation ("ARO") is calculated based on the same
methodology that was used to calculate the ARO on NAL's year-end
financial statements, with two exceptions. Future expected ARO costs are
discounted at 10 percent and a deduction is made for abandonment costs
incorporated in the value of the proved plus probable reserves. The
balances on the year-end balance sheet, $90.8 million for 2008 and $89.6
million for 2007, when discounted at 10 percent, results in a total
discounted ARO of $76.1 million and $75.1 million, at the respective
balance sheet dates. These balances are further reduced by $24.0 million
and $19.1 million, respectively, relating to abandonment costs
incorporated in the reserves value.
(5) McDaniel price forecast as of January 1, 2009.
(6) McDaniel price forecast as of January 1, 2008.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis ("MD&A") should be read in conjunction with the consolidated financial statements for the years ended December 31, 2008 and December 31, 2007 of NAL Oil & Gas Trust ("NAL" or the "Trust"). It contains information and opinions on the Trust's future outlook based on currently available information. All amounts are reported in Canadian dollars, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("boe") based on a ratio of six thousand cubic feet of natural gas to one barrel of oil. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of boe in isolation may be misleading.

NON-GAAP FINANCIAL MEASURES

Throughout this discussion and analysis, Management uses the terms funds from operations, funds from operations per unit, payout ratio, cash flow from operations per unit, net debt to trailing 12 month cash flow, operating netback and cash flow netback. These are considered useful supplemental measures as they provide an indication of the results generated by the Trust's principal business activities. Management uses the terms to facilitate the understanding of the results of operations. However, these terms do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). Investors should be cautioned that these measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of NAL's performance. NAL's method of calculating these measures may differ from other income funds and companies and, accordingly, they may not be comparable to measures used by other income funds and companies.

Funds from operations is calculated as cash flow from operating activities before changes in non-cash working capital. Funds from operations does not represent operating cash flows or operating profits for the period and should not be viewed as an alternative to cash flow from operating activities calculated in accordance with GAAP. Funds from operations is considered by Management to be a more meaningful key performance indicator of NAL's ability to generate cash to finance operations and to pay monthly distributions. Funds from operations per unit and cash flow from operations per unit are calculated using the weighted average units outstanding for the period.

Payout ratio is calculated as distributions declared for a period as a percentage of either cash flow from operating activities or funds from operations; both measures are stated.

Net debt to trailing 12 months cash flow is calculated as net debt as a proportion of funds from operations for the previous 12 months. Net debt is defined as bank debt, plus convertible debentures at face value, plus working capital, excluding derivative contracts, notes payable/receivable and future income tax balances.



The following table reconciles cash flows from operating activities to funds
from operations:

----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
$ (000s) 2008 2007 2008 2007
----------------------------------------------------------------------------

Cash flow from operating activities 77,326 45,111 320,042 215,364
Add back change in non-cash working
capital (10,286) 14,426 (8,971) 3,381
----------------------------------------------------------------------------
Funds from operations 67,040 59,537 311,071 218,745
----------------------------------------------------------------------------
----------------------------------------------------------------------------


FORWARD-LOOKING INFORMATION

This discussion and analysis contains forward-looking information as to the Trust's internal projections, expectations and beliefs relating to future events or future performance. Forward looking information is typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "could", "plan", "intend", "should", "believe", "outlook", "project", "potential", "target", and similar words suggesting future events or future performance. In addition, statements relating to "reserves" are forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities estimated and can be profitably produced in the future.

In particular, this MD&A contains forward-looking information pertaining to the following, without limitation: the amount and timing of cash flows and distributions to unitholders; reserves and reserves values; 2009 production; future tax treatment of the Trust; future structure of the Trust and its subsidiaries; the Trust's tax pools; future oil and gas prices; operating costs; the amount of future asset retirement obligations; future liquidity and future financial capacity; future results from operations; payout ratios; cost estimates and royalty rates; drilling plans; tie-in of wells; future development, exploration, and acquisition and development activities and related expenditures.

With respect to forward-looking statements contained in this MD&A and the press release through which it was disseminated, we have made assumptions regarding, among other things: future oil and natural gas prices; future capital expenditure levels; future oil and natural gas production levels; future exchange rates; the amount of future cash distributions that we intend to pay; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities.

Although NAL believes that the expectations reflected in the forward-looking information contained in the MD&A and the press release through which it was disseminated, and the assumptions on which such forward-looking information are made, are reasonable, readers are cautioned not to place undue reliance on such forward looking statements as there can be no assurance that the plans, intentions or expectations upon which the forward-looking information are based will occur. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated and which may cause NAL's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance. These risks and uncertainties include, without limitation: changes in commodity prices; unanticipated operating results or production declines; the impact of weather conditions on seasonal demand and ability to execute the capital program; risks inherent in oil and gas operations; the imprecision of reserve estimates; limited, unfavorable or no access to capital or credit markets; the impact of competitors; the lack of availability of qualified operating or management personnel; the ability to obtain industry partner and other third party consents and approvals, when required; failure to realize the anticipated benefits of acquisitions; general economic conditions in Canada, the United States and globally; fluctuations in foreign exchange or interest rates; changes in government regulation of the oil and gas industry, including environmental regulation; changes in royalty rates; changes in tax laws; including the impact of legislation relating to the taxation of "specified investment flow-through" entities and proposed amendments to the Income Tax Act (Canada) to permit the conversion of income trusts into corporations by the Federal government; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand for crude oil at desired price levels; political uncertainty, including the risk of hostilities in the petroleum producing regions of the world; and other risk factors discussed in other public filings of the Trust including the Trust's current Annual Information Form.

NAL cautions that the foregoing list of factors that may affect future results is not exhaustive. The forward-looking information contained in the MD&A is made as of the date of this MD&A. The forward-looking information contained in the MD&A is expressly qualified by this cautionary statement.

ACQUISITION OF TIBERIUS EXPLORATION INC. AND SPEAR EXPLORATION INC.

Effective February 27, 2008 the Trust acquired all the issued and outstanding common shares of Tiberius Exploration Inc. ("Tiberius") and Spear Exploration Inc. ("Spear"), which have interests in southeast Saskatchewan.

On February 29, 2008 the Trust transferred the assets into a newly formed limited partnership ("Partnership") in exchange for a 50 percent partnership interest and a note receivable of $3.7 million. A wholly owned subsidiary of Manulife Financial Corporation ("MFC") acquired the remaining 50 percent share in the Partnership and a note receivable of $3.7 million, by payment in cash of one half of the total purchase price for Tiberius and Spear. MFC is a related party to the Trust, see "Administrative Services and Cost Sharing Agreement".

The net acquisition cost to the Trust for its 50 percent share in the acquired properties was $57.8 million, before acquisition costs, comprised of $28.3 million in cash and $29.5 million from the issuance of 2.4 million trust units at a price of $12.24 per unit. The unit price was based on the average market price of the units at the announcement date for the acquisition of February 11, 2008.

In addition, both the Trust and MFC entered into net profit interest royalty agreements ("NPI") with the Partnership. These agreements entitle each royalty holder to a 49.5 percent interest in the cash flow from the Partnership's reserves. In exchange for this interest, the royalty holders each paid $49.6 million to the Partnership by way of promissory notes. The equivalent carrying amounts of property, plant and equipment related to this interest are recorded on the books of each royalty holder and were removed from the books of the Partnership.

The Trust, by virtue of being the owner of the general partner under the partnership agreement, is required to consolidate the results of the Partnership into its financial statements on the basis that the Trust has control over the Partnership. Accordingly, the Trust reports all revenues, expenses, assets and liabilities of the Partnership, together with its wholly owned subsidiaries and partnerships, in its consolidated financial statements. The 50 percent share of net income and net assets of the Partnership attributable to MFC is then deducted from net income and net assets, as a one-line entry, in the income statement and balance sheet, ensuring that the bottom line net income and net assets reported represent only the Trust's interest.

Consequently, substantially all analysis in the MD&A includes 100 percent of the results of the Partnership, with 50 percent of these results being removed through the non-controlling interest.

The results of operations from the Tiberius and Spear properties have been included in the consolidated financial statements of the Trust commencing February 27, 2008, the closing date of the transaction.

The fair values assigned to the net assets acquired from Tiberius and Spear and the consideration paid by the Trust is as follows:



----------------------------------------------------------------------------
Total Disposition Trust, net Net to
Net assets acquired Acquisition to Manulife Acquisition NPI(1) Trust
$(000s):
----------------------------------------------------------------------------
Cash $ 9,734 $ - $ 9,734 $- $ 9,734
Working capital
deficiency (5,622) - (5,622) - (5,622)
Notes receivable,
net from MFC - (3,750) (3,750) 49,599 45,849
Property, plant and
equipment 111,258 - 111,258 (49,599) 61,659
Future income taxes (23,544) 11,588 (11,956) - (11,956)
Asset retirement
obligations (1,636) - (1,636) - (1,636)
Goodwill 26,724 (12,002) 14,722 - 14,722
Non-controlling
interest - (54,057) (54,057) - (54,057)
----------------------------------------------------------------------------
$ 116,914 $(58,221) $58,693 $- $58,693
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Consideration:
----------------------------------------------------------------------------
Cash $86,118 $(57,807) $28,311 $- $28,311
Issuance of trust
units 29,496 - 29,496 - 29,496
Acquisition costs 1,300 (414) 886 - 886
----------------------------------------------------------------------------
$116,914 $(58,221) $58,693 $- $58,693
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net profit interest agreement entered into with MFC in exchange for a
note receivable.

The operations attributable to the Tiberius and Spear assets were as
follows:

----------------------------------------------------------------------------
Three
months Net Net
ended Impact Impact
Dec. 31, to Year-to- to
$(000s) 2008(1) Trust(2) date(1) Trust(2)
----------------------------------------------------------------------------
Total production
volumes (boes) 80,881 40,440 269,023 134,512
Production volumes (boe/d) 879 439 735 367

Oil, natural gas and liquid sales 4,758 2,379 25,910 12,955
Royalties (522) (261) (2,968) (1,484)
Operating costs (2,018) (1,009) (4,502) (2,251)
General and administrative (81) (41) (276) (138)
Unit-based incentive compensation 16 8 (57) (28)
Interest income, net 1,452 726 5,686 2,843
Bad debt expense - - (46) (23)
Depletion, depreciation and accretion (1,079) (539) (2,866) (1,433)
Net profit interest income (expense) 905 453 (13,236) (6,618)
----------------------------------------------------------------------------
Net income $3,431 $1,716 $7,645 $3,823
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Total results of the Partnership consolidated into the results of the
Trust.
(2) Net impact to the Trust, removing 50 percent of results attributable to
MFC.


The non-controlling interest presented in the statement of income has two components: the royalty paid to MFC under the NPI, being a cash payment to the royalty holder, and 50 percent of net income remaining in the Partnership, after NPI expense, attributable to MFC. This share of net income attributable to MFC is a non-cash item.



The non-controlling interest in the consolidated statement of income is
comprised of:

----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
---------------------------------------
$(000s) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net profits interest expense
(income) ($453) $- $6,618 $-
Share of net income attributable
to MFC 1,716 - 3,823 -
----------------------------------------------------------------------------
$1,263 $- $10,441 $-
----------------------------------------------------------------------------
----------------------------------------------------------------------------


EXPLORATION & DEVELOPMENT ACTIVITIES

The Trust spent $27.8 million on drilling, completion and tie-in operations during the fourth quarter of 2008, versus $31.0 million during the fourth quarter of 2007. For the full year, NAL spent $107.3 million on drilling, completion and tie-in operations versus $95.3 million in 2007. The Trust participated in the drilling of 31 (10.82 net) wells during the fourth quarter, compared to 45 (18.06 net) wells during the same period in 2007. Total participation in drilling was 131 gross (57.02 net) wells in 2008 compared to 126 gross (49.8 net) wells a year earlier.

Historically, NAL's assets have been concentrated in southeast Saskatchewan and central Alberta. The purchase of Seneca Energy Canada Inc. ("Seneca") in 2007 added a new core area at Sukunka in northeast British Columbia and expanded the Trust's W4M operations in the Hanna and Drumheller area of southeast Alberta. The Tiberius/Spear acquisition added to NAL's Nottingham/Alida operations in southeast Saskatchewan.



Fourth Quarter Drilling Activity

Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 14 7.54 2 1.21 0 0 1 0.5 17 9.25
Non-operated
wells 7 0.44 7 1.13 0 0 0 0 14 1.57
----------------------------------------------------------------------------
Total wells
drilled 21 7.98 9 2.34 0 0 1 0.5 31 10.82
----------------------------------------------------------------------------

2008 Full Year Drilling Activity

Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 70 40.35 14 9.8 0 0 1 0.5 85 50.65
Non-operated
wells 25 1.85 21 4.52 0 0 0 0 46 6.37
----------------------------------------------------------------------------
Total wells
drilled 95 42.20 35 14.32 0 0 1 0.5 131 57.02
----------------------------------------------------------------------------


In 2009, over 80 percent of the Trust's drilling program will be horizontal with a significant number of multi-stage frac stimulations required. NAL has drilled several hundred horizontal wells in Saskatchewan and will be transporting that knowledge to opportunities in Alberta.

Southeast Saskatchewan (Alida, Nottingham, Rosebank, Midale, Elswick)

In Saskatchewan, there were 16 (5.9 net) horizontal oil wells drilled during the fourth quarter. Activity was focused on the Mississippian, Tilston and Bakken in Steelman, Edenvale, Torquay and Pinto with results in line with expectations.

Field operations were focused on construction of new processing infrastructure for the Tiberius and Spear production with facilities coming on line in January 2009. NAL is currently optimizing pumps to ensure that all production is on line at maximum rates now that trucking of emulsion has been replaced with efficient gathering and disposal capability. Field construction of the Nottingham gas plant expansion is 75 percent complete but delivery of some components has been significantly delayed due to material defects found in welded fittings and piping. Start-up is now expected by mid-year 2009.

Alberta (Garrington, Westward Ho, Drumheller, Pine Creek, Lacombe, Medicine River, Sylvan Lake)

In Alberta, NAL drilled 13 (4.7 net) locations with operated drilling accounting for six (3.3 net) wells during the quarter.

Production from the four (2.1 net) well horizontal Cardium oil program is now on stream with three month production rates of 100 - 200 boe/d. These early positive results have validated a significant program for 2010. There were also two (1.2 net) gas wells drilled in eastern Alberta with gross production of 1 MMcf/d expected to be on stream in the first quarter of 2009. Non-operated activity included seven (1.4 net) wells focused on gas drilling in central Alberta.

During the first quarter of 2009, the Trust has commenced drilling on two additional Cardium locations which are expected to be on stream by April of 2009.

Northeast British Columbia (Sukunka)

In Monkman, there were two (0.2 net) wells at c-21-K and d-27-F that reached total depth during the fourth quarter. Both wells are currently being evaluated and the tie-in of any successful tests will be dependent on processing capacity in the Spectra Pine River Gas plant. A third well at a-100-C (20 percent working interest) commenced drilling in December and is expected to reach total depth by June, 2009.

Commingling approval for the a-26-E well was received in December and production from this well was increased by 400 boed net during the month with rates being dependent on available plant capacity. NAL is encouraged by the interruptible plant capacity that continues to be available and the future potential for incremental mid-stream take away capacity from this area that is in the approval stage.

CAPITAL EXPENDITURES

Capital expenditures, before property acquisitions, for the quarter ended December 31, 2008 totaled $41.2 million compared with $39.2 million for the quarter ended December 31, 2007. For the year ended December 31, 2008, capital expenditures, before property acquisitions, totaled $150.5 million compared to $118.0 million in 2007. In 2008, as illustrated in the table below, the Trust more than doubled its investment in land and facilities as compared to 2007. These investments are strategic, adding additional prospects to NAL's drilling inventory and longer term revenue generation for NAL's existing infrastructure.

The Trust's net capital expenditures for 2008, before property acquisitions, after deducting the non-controlling interest of $2.7 million for the fourth quarter and $7.9 million for the full year, were $38.5 million and $142.6 million respectively.

In response to weaker commodity prices, capital for the first half of 2009 has been reduced by $15 million which translates to a full year capital program of $95 million versus previous guidance of $110 million. The Trust has a significant inventory of prospects that can be executed in the third and fourth quarters should commodity prices improve.

Reducing costs for drilling and completing horizontal wells is a priority for the Trust during 2009. NAL expects that costs will improve by 20 - 30 percent toward the end of the year due to a decline in demand for services as well as targeted efficiencies in the execution of NAL's programs. Reducing capital in the first half of the year will allow the Trust to maintain maximum flexibility and preserve its balance sheet in these uncertain times.



Capital Expenditures ($000s)
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------

Drilling, completion and production
equipment 27,766 30,971 107,286 95,327
Plant and facilities 9,760 3,308 21,009 9,988
Seismic 326 149 1,202 708
Land 1,855 2,545 13,970 5,330
----------------------------------------------------------------------------
Total exploitation and development 39,707 36,973 143,467 111,353
----------------------------------------------------------------------------

Office equipment 764 792 1,945 1,297
Capitalized G&A 1,146 999 4,313 4,486
Capitalized unit-based compensation (405) 430 747 875
----------------------------------------------------------------------------
Total other capital 1,505 2,221 7,005 6,658
----------------------------------------------------------------------------

Total capitalized expenditures before
acquisitions 41,212 39,194 150,472 118,011
----------------------------------------------------------------------------

Property acquisitions (dispositions),
net (127) - 8,082 1,423
----------------------------------------------------------------------------
Total capitalized expenditures 41,085 39,194 158,554 119,434
----------------------------------------------------------------------------
----------------------------------------------------------------------------


PRODUCTION

Fourth quarter 2008 production of 23,984 boe/d exceeded production of 23,656 boe/d in the comparable period of 2007. The increase is due to the Tiberius and Spear acquisition as well as the ongoing execution of the Trust's capital program.

For the year ended December 31, 2008, production of 23,797 boe/d exceeded the 20,681 boe/d for the comparable period in 2007 by 15 percent. The increase is attributable to the acquisition of Seneca Energy Canada Inc. ("Seneca"), which closed on August 31, 2007, Tiberius and Spear production as well as the ongoing execution of the Trust's capital program. Volumes for December 2008 and January 2009 exceeded 24,000 boe/d setting up a strong start to the year.

In response to the reduction of capital ($15 million) in the first and second quarters of 2009, our full year production guidance has been reduced to 22,000 - 23,000 boe/d. The Trust is poised to layer in more capital during the third and fourth quarters to fund opportunities should commodity prices improve, however, the annualized impact on production of this spending is expected to be limited due to execution later in the year.



Average Daily Production Volumes
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008(1) 2007(1) 2008(1) 2007(1)
----------------------------------------------------------------------------

Oil (bbl/d) 10,223 9,722 10,188 9,366
Natural gas (Mcf/d) 69,049 71,067 68,898 55,422
NGLs (bbl/d) 2,254 2,090 2,126 2,078
Oil equivalent (boe/d) 23,984 23,656 23,797 20,681
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Volumes include royalty income volumes.


The oil equivalent volumes of 23,984 boe/d for the fourth quarter of 2008 and 23,797 boe/d for the full year include 440 boe/d and 368 boe/d, respectively, attributable to the non-controlling interest in the Tiberius and Spear properties. The Trust's net production, after deducting the non-controlling interest, is 23,544 boe/d for the fourth quarter of 2008 and 23,429 boe/d for the full year.

For the year ended December 31, 2008, oil and natural gas liquids totaled 52 percent of production with natural gas at 48 percent.



Production Weighting
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------

Oil 43% 41% 43% 45%
Natural gas 48% 50% 48% 45%
NGLs 9% 9% 9% 10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


REVENUE

Gross revenue from oil, natural gas and natural gas liquids sales, after transportation costs, totaled $107.0 million for the three months ended December 31, 2008, 13 percent lower than the fourth quarter of 2007. The decrease is primarily due to a 14 percent decrease in the average realized price per boe, driven by a 28 percent decrease in crude oil price, a reflection of lower West Texas Intermediate ("WTI") prices in the fourth quarter of 2008, partially offset by a 10 percent increase in the average realized price for natural gas during the fourth quarter of 2008.

For the year ended December 31, 2008, revenue, after transportation costs, totaled $615.0 million, an increase of 49 percent from the comparable period in 2007. The increase is attributable to a 15 percent increase in production and an increase of 29 percent in the average realized price per boe, due to a 25 percent increase in natural gas prices and a 33 percent increase in crude oil prices year-over-year.



Revenue
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------

Revenue(1) ($000s)
Oil 54,017 70,607 351,911 241,607
Gas 43,393 41,121 208,784 133,785
NGL's 9,009 11,425 50,815 38,620
Sulphur 622 9 3,529 22
----------------------------------------------------------------------------
Total revenue 107,041 123,162 615,039 414,034
$/boe 48.51 56.59 70.62 54.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties.


OIL MARKETING

NAL sells its crude oil based on refiners' posted prices at Edmonton, Alberta and Cromer, Manitoba adjusted for transportation and the quality of crude oil at each field battery. The refiners' posted prices are influenced by the WTI benchmark price, transportation costs, exchange rates and the supply/demand situation of particular crude oil quality streams during the year.

NAL's fourth quarter average realized Canadian crude oil price per barrel, net of transportation costs, was $57.44, as compared to $79.43 for the comparable quarter of 2007. The decrease in realized price quarter-over-quarter of 28 percent, or $21.99/bbl, was primarily driven by a 35 percent decrease in WTI (U.S.$/bbl) over the comparable period, partially offset by a weakening Canadian dollar.

For the fourth quarter of 2008, NAL's crude oil price differential was 81 percent, a decrease of 8 percent from the comparable period in 2007. The differential is calculated as realized price as a percentage of WTI stated in Canadian dollars. The decrease in 2008 resulted from a wider differential between WTI and Edmonton and Cromer posted prices, due to lower demand for light crude in Western Canada during the fourth quarter.

For the year ended December 31, 2008, NAL's average oil price was $94.38 per barrel as compared to $70.79 for the comparable period in 2007, an increase of 33 percent. The increase in realized price was driven by an average 38 percent increase in WTI (US$/bbl) during the year.

Natural gas liquids averaged $43.45/bbl in the fourth quarter of 2008, a 26 percent decrease from $58.52/bbl realized in 2007. For the year ended December 31, 2008, natural gas liquids averaged $65.31/bbl, an increase of 29 percent from the comparable period in 2007.

On July 22, 2008, SemGroup L.P. ("SemCanada") announced that it and certain of its North American subsidiaries had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code as well as an application for creditor protection under the Companies' Creditors Arrangement Act in Canada. NAL has retained legal counsel to manage this matter. It has been determined that the likelihood of recovering any of the amount owed to the Trust is unlikely. Therefore, the Trust recorded an expense of $6.9 million, in the third quarter of 2008, to write off the total amount outstanding from SemCanada. NAL continues to work with legal counsel to attempt to recover amounts due. Any future amounts received will be recorded to income.

NATURAL GAS MARKETING

Approximately 75 percent of NAL's current gas production is sold under marketing arrangements tied to the Alberta monthly or daily spot price ("AECO"), with the remaining 25 percent tied to NYMEX or other indexed reference prices.

For the three months ended December 31, 2008, the Trust's natural gas sales averaged $6.83/mcf compared to $6.20/mcf in the comparable period of 2007, an increase of 10 percent. The quarter-over-quarter increase in gas prices was attributable to a 9 percent increase in the benchmark AECO daily spot prices.

Prices for Lake Erie natural gas increased to $8.47/mcf in the fourth quarter of 2008, compared to $7.37/mcf in 2007, an increase of 15 percent. Lake Erie production of 3.25 MMcf/d accounted for five percent of the Trust's natural gas production in the fourth quarter of 2008, the same percentage experienced in the comparable period of 2007. Natural gas sales from the Lake Erie property generally receive a higher price due to the close proximity to the Ontario and Northeastern U.S. markets.

For the year ended December 31, 2008, NAL averaged $8.28/mcf, a 25 percent increase from the $6.60/mcf realized in the comparable period in 2007. The year-over-year increase in gas prices was attributable to a 27 percent increase in the benchmark AECO daily spot prices.



Average Pricing
(net of transportation charges)
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------

Liquids
WTI (US$/bbl) 58.74 90.62 99.65 72.30
NAL average oil (Cdn$/bbl) 57.44 79.43 94.38 70.79
NAL natural gas liquids
(Cdn$/bbl) 43.45 58.52 65.31 50.82

Natural Gas (Cdn$/Mcf)
AECO - daily spot 6.69 6.15 8.15 6.44
AECO - monthly 6.79 6.00 8.13 6.61
NAL Western Canada natural
gas 6.75 6.13 8.19 6.47
NAL Lake Erie natural gas 8.47 7.37 9.97 7.90
NAL average natural gas 6.83 6.20 8.28 6.60

NAL Oil Equivalent before
hedging (Cdn$/boe - 6:1) 48.51 56.59 70.62 54.85
Average Foreign Exchange Rate
(Cdn$/U.S.$) 1.2125 0.9807 1.0671 1.0738
----------------------------------------------------------------------------
----------------------------------------------------------------------------


RISK MANAGEMENT

NAL employs risk management practices to assist in managing cash flows and to support capital programs and distributions. NAL currently has derivative contracts in place to assist in managing the risks associated with commodity prices and interest rates.

NAL's management has authorization to hedge up to 50 percent of forecasted total production, net of royalties. Management's practice is to hedge more near-term volumes on a six month forward basis with more limited volumes hedged in future periods. The execution of NAL's commodity hedging program is layered in using a combination of swaps and collars. As at December 31, 2008, NAL had several financial WTI oil contracts and AECO natural gas contracts in place.

NAL's management has authorization to fix the interest rate on up to 50 percent of outstanding debt for periods of up to five years. As at December 31, 2008, NAL had two interest rate swaps outstanding.

All derivative contract counterparties are Canadian chartered banks in the Trust's lending syndicate.

The following is a summary of the realized gains and losses on commodity based risk management contracts:



----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------

Average crude volumes hedged (bbl/d) 5,100 3,966 4,810 3,106
Crude oil realized gain (loss)
($000's) 13,460 (7,756) (24,691) (7,132)
Gain (loss) per bbl hedged ($) 28.69 (21.26) (14.03) (6.29)

Average natural gas volumes hedged 30,337 19,978 27,640 16,633
(GJ/d)
Natural gas realized gain (loss)
($000's) 3,071 2,246 (2,626) 4,697
Gain (loss) per GJ hedged ($) 1.10 1.22 (0.26) 0.77

Average BOE hedged (boe/d) 9,893 7,122 9,178 5,733
Total realized gain (loss) ($000's) 16,531 (5,510) (27,317) (2,435)
Gain (loss) per boe hedged ($) 18.16 (8.41) (8.13) (1.16)
Gain (loss) per boe ($) 7.49 (2.53) (3.14) (0.32)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the fourth quarter, the Trust entered into two three-year interest rate swaps. The contracts have a combined notional debt amount of $39.0 million and require NAL to make fixed quarterly payments at an interest rate of 1.5864 percent. In exchange, the counterparties are required to pay the Trust a floating rate of interest based on the average three month rate for Canadian dollar bankers acceptances. Two additional swaps were entered into subsequent to year-end. The Trust's interest charge includes this fixed interest rate component plus a standby fee, a stamping fee and the fee for renewal.

No realized amounts were recorded for the interest rate swap contracts in 2008.

All derivative contracts are recorded on the balance sheet at fair value based upon forward curves at December 31, 2008. Changes in the fair value of the derivative contracts are recognized in net income for the period.

Fair value is calculated at a point in time based on an approximation of the amounts that would be received or paid to settle these instruments, with reference to forward prices. Accordingly, the magnitude of the unrealized gain or loss will continue to fluctuate with changes in commodity prices and interest rates.

The fair value of the derivatives at December 31, 2008 was a net asset of $65.4 million, comprised of a $55.7 million asset on oil contracts, a $10.0 million asset on gas contracts, partially offset by a $0.3 million liability on interest rate swaps.

Fourth quarter income for 2008 includes a $56.6 million unrealized gain on derivatives resulting from the change in the fair value of the derivative contracts during the quarter from an unrealized gain of $8.8 million at September 30, 2008 to an unrealized gain of $65.4 million at December 31, 2008. The $56.6 million unrealized gain was comprised of a $55.4 million unrealized gain on crude oil contracts, a $1.5 million unrealized gain on natural gas contracts partially offset by a $0.3 million unrealized loss on interest rate swaps. The unrealized gain in the fourth quarter is attributable to significantly lower crude oil and natural gas forward prices compared to September 30, 2008. Average hedged boes for the fourth quarter were 9,893 as compared to 9,839 for the third quarter of 2008.

For the year ended December 31, 2008, income includes an unrealized gain of $75.0 million, resulting from the change in the fair value of the derivatives during the period. The unrealized gain was comprised of a $68.7 million unrealized gain on crude oil contracts, a $6.6 million unrealized gain on natural gas contracts, offset by a $0.3 million unrealized loss on the interest rate swaps. The unrealized gain in the period is reflective of additional contracts entered into during the first half of 2008 at significantly higher commodity prices.



The gain/loss on derivative contracts is as follows:

Gain / (Loss) on Derivative Contracts ($000's)

----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
---------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Unrealized gain (loss)
Crude oil contracts 55,438 (5,789) 68,674 (15,709)
Natural gas contracts 1,456 (2,424) 6,590 1,604
Interest rate swap (274) - (274) -
----------------------------------------------------------------------------
Unrealized gain (loss) 56,620 (8,213) 74,990 (14,105)
Realized gain (loss) 16,531 (5,510) (27,317) (2,435)
Reclassification from other
comprehensive income - 874 - 4,521
----------------------------------------------------------------------------
Gain (loss) on derivative contracts 73,151 (12,849) 47,673 (12,019)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NAL has the following interest rate risk management contracts outstanding:

----------------------------------------------------------------------------
Trust
Amount Fixed Counterparty
INTEREST RATE Remaining Term (millions)(1) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating CAD-BA-CDOR
to fixed Jan 2009 - Dec 2011 $39.0 1.5864% (3 months)
----------------------------------------------------------------------------
Swaps-floating CAD-BA-CDOR
to fixed(i) Jan 2009 - Jan 2013 $22.0 1.3850% (3 months)
----------------------------------------------------------------------------
Swaps-floating CAD-BA-CDOR
to fixed(i) Jan 2009 - Jan 2014 $22.0 1.5100% (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(i) Entered into subsequent to year-end
(1) Notional debt amount


For 2009, NAL has the following commodity risk management contracts
outstanding:

----------------------------------------------------------------------------
CRUDE OIL U.S.$ Contracts CDN$ Contracts
----------------------------------------------------------------------------
Swap (bbls) - 717,400
Swap (bbl/d) - 1,965
$/bbl - $98.26
Collars (bbls) 36,400 516,800
Collars (bbl/d) 100 1,416
$/bbl $110.00 - $154.96 $119.13 - $159.84
Total (bbls) - 1,234,200
Total (bbl/d) - 3,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
NATURAL GAS CDN$ Contracts
----------------------------------------------------------------------------
Swap (GJ) 4,352,000
Swap (GJ/d) 11,923
$/GJ $7.02
Collars (GJ) 2,510,000
Collars (GJ/d) 6,877
$/GJ $8.44 - $10.36
Total GJ 6,862,000
Total (GJ/d) 18,800
----------------------------------------------------------------------------
----------------------------------------------------------------------------

For 2009, the Trust has outstanding contracts representing approximately 35
percent of the net liquids and natural gas production after royalties,
assuming a royalty rate of 20 percent.

For 2010, the Trust has the following commodity risk management contracts
outstanding:

----------------------------------------------------------------------------
CRUDE OIL CDN$ Contracts
----------------------------------------------------------------------------
Collars (bbls) 27,000
Collars (bbl/d) 74
$/bbl $66.00 - $80.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
NATURAL GAS CDN$ Contracts
----------------------------------------------------------------------------
Swap (GJ) 1,620,000
Swap (GJ/d) 4,438
$/GJ $6.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------


ROYALTY EXPENSES

Crown, freehold and overriding royalties were $21.2 million for the three months ended December 31, 2008. Expressed as a percentage of gross sales net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 19.8 percent for the quarter ended December 31, 2008, a decrease from the 20.8 percent experienced in the same period of the previous year.

Royalties decreased to $9.59 per boe for the fourth quarter of 2008, a decrease of 19 percent compared to the fourth quarter of 2007. The decrease is attributable to lower commodity prices on a quarter-over-quarter basis.

For the year ended December 31, 2008, royalties were $126.4 million, up 44 percent from $88.0 million in 2007. Expressed as a percentage of gross sales net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 20.6 percent, as compared to 21.3 percent in the comparable period in 2007.

Royalties increased to $14.52 per boe for the year ended December 31, 2008, an increase of 25 percent compared to the same period in 2007. Higher average commodity prices on a year-over-year basis are responsible for the increase.

On January 1, 2009, the new royalty framework for Alberta became effective. This new framework, first announced on October 25, 2007, provides for conventional oil and gas royalties calculated on a sliding scale that is determined by commodity price and productivity. Natural gas royalty rates have increased from 35 percent to 50 percent, with rate caps at $16.59/GJ. Crude oil royalty rates have increased from 35 percent to 50 percent, with rates capped at $120/bbl.

In response to the recent economic downturn, on November 19, 2008 the Government of Alberta announced special transitional rates for some conventional oil and gas wells. The lower transitional rates apply to newly drilled oil and gas wells at depths between 1,000 and 3,500 metres.

The Trust has assessed the impact of these new royalties, including the transitional rates, on its production for 2009. Given the Trust's relatively low crude oil production in Alberta and a significant weighting towards low producing gas wells, the impact is expected to be minimal. NAL's analysis indicates that, in the majority of cases, the Trust expects to elect the special transitional rates for oil wells and adopt the new royalty framework for natural gas wells. For the year ended December 31, 2008, 25 percent of crude oil and 71 percent of natural gas production is from Alberta.



Royalty Expenses
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Royalties ($000s) 21,163 25,646 126,430 88,047
As % of revenue 19.8 20.8 20.6 21.3
$/boe 9.59 11.78 14.52 11.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------


OPERATING COSTS

Operating costs averaged $11.67 per boe for the quarter ended December 31, 2008, an 18 percent increase from the $9.90 per boe for the quarter ended December 31, 2007. On a year-to-date basis, operating costs were $10.90 per boe as compared to $9.26 in 2007, an increase of 18 percent.

Approximately $0.75 per boe is due to significant increases in fuel, power, and processing expenses which are related to cost pressures driven by increased commodity prices.

In Saskatchewan, industry costs are up 20 percent year-over-year due to the higher level of activity and limited availability of equipment, services and people. With sustained lower commodity prices, activity levels are expected to be significantly reduced in 2009 which should translate into a lower cost structure.

Operating costs are budgeted to be higher in 2009 due to notification of some significant increases in property taxes and mandated increases for power affecting the Trust's Saskatchewan operations. Third party processing costs are adjusted based on the previous year's actual costs so reductions in these rates will not be felt immediately. The Trust has engaged in a process to capture rate reductions from contractors and service companies that are required in this difficult economic climate. All aspects of the business are being examined in an effort to realize meaningful cost reductions as we progress through the year.



Operating Costs
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Operating costs ($000s) 25,749 21,537 94,928 69,916
As a % of revenue 24.1 17.5 15.4 16.9
$/boe 11.67 9.90 10.90 9.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


OTHER INCOME

Other income was $0.51 per boe for the fourth quarter of 2008 compared to $0.32 per boe in the comparable quarter of 2007. Effective with the Tiberius and Spear acquisitions in February 2008, other income includes interest income and interest expense on the notes due from and to MFC. In the fourth quarter of 2008, this interest totaled $0.7 million.

Similar trends are noted for full year 2008. The net interest on notes with MFC totaled $2.8 million in 2008.



Other Income
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest on notes with MFC
($000s) 726 - 2,836 -
Other ($000s) 405 698 1,628 2,587
----------------------------------------------------------------------------
Total other income ($000s) 1,131 698 4,464 2,587
As a % of revenue 1.1 0.6 0.7 0.6
Interest on notes with MFC
($/boe) 0.33 - 0.33 -
Other ($/boe) 0.18 0.32 0.19 0.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total other income ($/boe) 0.51 0.32 0.52 0.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------


OPERATING NETBACK

For the quarter ended December 31, 2008, NAL's operating netback before hedging gains was $27.43 per boe, a decrease of 22.1 percent from $35.23 per boe for the quarter ended December 31, 2007. The decrease was due to lower revenues as a result of lower commodity prices and increased operating costs. Hedging gains were $7.49 per boe in the fourth quarter of 2008, as compared to a loss of $2.53 per boe in 2007.

On a full year 2008 basis, NAL's operating netback before hedging losses was $45.39 per boe, an increase of $11.12 from 2007. The increase was due to higher revenues driven by stronger commodity prices, partially offset by increases in royalties and operating expenses. Hedging losses were $3.14 per boe for the year ended December 31, 2008, as compared to $0.32 per boe in 2007.



Operating Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue 48.51 56.59 70.62 54.85
Royalties (9.59) (11.78) (14.52) (11.66)
Operating expenses (11.67) (9.90) (10.90) (9.26)
Other income(1) 0.18 0.32 0.19 0.34
-----------------------------------------
Operating netback, before hedging 27.43 35.23 45.39 34.27
Hedging gains (losses) 7.49 (2.53) (3.14) (0.32)
-----------------------------------------
Operating netback, after hedging 34.92 32.70 42.25 33.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Excludes interest on notes with MFC.


GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative ("G&A") expenses include direct costs incurred by the Trust plus the reimbursement of the G&A expenses incurred by NAL Resources Management Limited (the "Manager") on the Trust's behalf.

For the three months ended December 31, 2008, G&A expenses were $3.8 million, compared with $4.1 million in the comparable quarter of 2007. In addition, $1.1 million of G&A costs relating to exploitation and development activities were capitalized in the fourth quarter of 2008, compared with $1.0 million in the fourth quarter of 2007. G&A expense per boe, excluding retention bonus, was $1.73 in the quarter, as compared to $1.85 for the same period in 2007.

For the year ended December 31, 2008, G&A expense increased 10 percent to $15.8 million from $14.4 million in the comparable period in 2007. In addition, $4.3 million of G&A costs relating to exploitation and development activities were capitalized, compared with $4.5 million in 2007. The retention bonus program concluded on June 30, 2008, ($0.01 per boe for the full year) and there will be no further expense relating to this program. G&A expense per boe, excluding the one-time retention bonus was $1.80 for the year ended December 31, 2008, as compared to $1.78 for the same period in 2007.



General and Administrative Expenses
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
G&A expenses ($000s)
G&A 3,814 4,039 15,658 13,435
Retention bonus - 57 106 969
----------------------------------------------------------------------------
Expensed G&A ($000s) 3,814 4,096 15,764 14,404
Capitalized G&A ($000s) 1,146 999 4,313 4,486
----------------------------------------------------------------------------
Total G&A ($000s) 4,960 5,095 20,077 18,890

Expensed G&A costs:
G&A, excluding retention bonus ($/boe) 1.73 1.85 1.80 1.78
Retention bonus ($/boe) - 0.03 0.01 0.13
----------------------------------------------------------------------------
Total G&A expenses ($/boe) 1.73 1.88 1.81 1.91
As % of revenue 3.6 3.3 2.6 3.5
Per trust unit ($) 0.04 0.05 0.17 0.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------


UNIT-BASED INCENTIVE COMPENSATION PLAN

The employees of the Manager are all members of a unit-based incentive plan (the "Plan"). The Plan results in employees receiving cash compensation based upon the value and overall return of a specified number of notional trust units. The Plan consists of Restricted Trust Units ("RTUs") and Performance Trust Units ("PTUs"). RTUs vest one third on November 30 in each of three years after the date of grant. PTUs vest on November 30, three years after their date of grant. Distributions paid on the Trust's outstanding trust units during the vesting period are assumed to be paid on the awarded notional trust units and reinvested in additional notional units on the date of distribution. Upon vesting, the employee is entitled to a cash payout based on the trust unit price at the date of vesting of the units held. In addition, the PTUs have a performance multiplier which is based on the Trust's performance relative to its peers and may range from zero to two times the market value of the notional trust units held at vesting.

During the fourth quarter of 2008, the Trust recorded a $0.7 million recovery of unit-based incentive compensation as compared to a $1.1 million charge in the comparable quarter of 2007. The recovery in unit-based compensation in the fourth quarter of 2008 reflects a 36 percent decrease in the unit price of the Trust, from $12.53 at September 30, 2008 to $8.05 at December 31, 2008. A decrease in unit price results in previously accrued amounts being reversed, although the impact is partially offset by additional vesting.

For the year ended December 31, 2008, the Trust has accrued $2.6 million for unit-based compensation as compared to $3.0 million in the comparable period in 2007. The decrease in unit-based compensation in 2008 is primarily a result of a decrease in the unit price to $8.05 as compared to $11.60 at December 31, 2007.

At December 31, 2008, the unit price used to determine unit-based incentive compensation was $8.05. The closing unit price of the Trust on the Toronto Stock Exchange on February 25, 2009 was $6.16.

The calculation of unit-based compensation expense is made at the end of each quarter based on the quarter end trust unit price and estimated performance factors. The compensation charges relating to the units granted are recognized over the vesting period based on the trust unit price, number of RTUs and PTUs outstanding, and the expected performance multiplier. As a result, the expense recorded in the accounts will fluctuate in each quarter and over time.

At December 31, 2008, the Trust has recorded a liability for unit-based incentive compensation in the amount of $5.8 million, of which $2.4 million was paid in January 2009. The remaining balance represents the Trust's estimated liability for the unit-based incentive plan as at December 31, 2008, with $2.5 million recorded as a current liability as it is payable in December 2009, and $0.9 million recorded as a long-term liability as it is payable in December 2010 and December 2011.



Unit-Based Compensation
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Unit-based compensation ($000s):
Expensed (693) 1,080 1,826 2,152
Capitalized (405) 430 747 875
----------------------------------------------------------------------------
Total unit-based compensation (1,098) 1,510 2,573 3,027

Expensed unit-based compensation:
As % of revenue (0.65) 0.90 0.30 0.50
$/boe (0.31) 0.50 0.21 0.29
Per trust unit ($) (0.01) 0.01 0.02 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------


ADMINISTRATIVE SERVICES AND COST SHARING AGREEMENT(1) AND RELATED PARTY TRANSACTIONS

The Trust is managed by the Manager. The Manager is a wholly-owned subsidiary of MFC and also manages NAL Resources Limited ("NAL Resources"), another wholly-owned subsidiary of MFC. NAL Resources and the Trust maintain ownership interests in many of the same oil and natural gas properties in which NAL Resources is the joint operator. As a result, a significant portion of the net operating revenues and capital expenditures during the year are based on joint amounts from NAL Resources. These transactions are in the normal course of joint operations and are measured using the fair value established through the original transactions with third parties.

The Manager provides certain services to the Trust and its subsidiary entities pursuant to an administrative services and cost sharing agreement (the "Agreement"). This agreement requires the Trust to reimburse the Manager at cost for G&A and unit-based compensation expenses incurred by the Manager on behalf of the Trust calculated on a unit of production basis. The Agreement does not provide for any base or performance fees to be payable to the Manager.

The Trust paid $2.8 million (2007 - $3.1 million) for the reimbursement of G&A expenses during the fourth quarter, and $12.4 million (2007 - $11.6 million) for the year ended December 31, 2008. The increase in G&A of $0.8 million, charged to the Trust from the Manager in 2008, is due to the relative increase in Trust production as compared to MFC production, a result of the Seneca acquisition in August 2007. The Trust also pays the Manager its share of unit-based incentive compensation expense when cash compensation is paid to employees under the terms of the Plan, of which $1.8 million was paid in 2008, representing units that vested on November 30, 2007 (2007 - $2.2 million).

At December 31, 2008 the Trust owed the Manager $3.9 million for the reimbursement of G&A and had a payable to NAL Resources of $10.0 million, relating to net operating revenues less capital expenditures.

In addition, there are notes outstanding with MFC arising from the Tiberius and Spear acquisition. These notes are included on consolidation of the Partnership but are effectively eliminated through the non-controlling interest. At December 31, 2008, there is a note payable of $9.6 million and a note receivable of $49.6 million. The notes are due on demand, unsecured and bear interest at prime plus three percent with the note receivable due to be settled by March 31, 2009. Net interest of $0.7 million for the fourth quarter, $2.8 million for the year-end at December 31, 2008 was received by the Trust and is reported as other income. The amount of the note payable to MFC is adjusted to reflect MFC's share of the capital expenditures of the Partnership which MFC has funded, less any loan repayments made.

(1) Previously called "Management Contract".

INTEREST

Interest on bank debt includes charges on borrowings, plus standby fees on the unused portion of the bank credit facility. Interest on bank debt for the fourth quarter of 2008 was $3.0 million, a decrease of $0.8 million from $3.8 million for the comparable period in 2007. The decrease was due to a decrease in the average effective interest rate offset by a slight increase in the average debt levels. Average outstanding bank debt for the fourth quarter of 2008 was $276.5 million, $9.9 million higher than the $266.6 million outstanding for the fourth quarter of 2007. NAL's effective interest rate averaged 4.16 percent during the fourth quarter of 2008, compared to 5.61 percent during the comparable period in 2007. The decrease in the rate from the fourth quarter of 2007 is attributable to lower rates in the market. NAL's interest is calculated based upon a floating rate.

For the year ended December 31, 2008, interest on bank debt was $14.1 million, an increase of $0.8 million from the comparable period in 2007. The increase was due to higher average debt levels, partially offset by a decrease in the average effective interest rate. Average debt was $295.0 million, compared to $242.9 million for 2007. NAL's effective interest rate averaged 4.71 percent in 2008, compared to 5.38 percent in 2007.

Interest on convertible debentures represents interest charges of $1.3 million for the three months ended December 31, 2008 as compared to $1.7 million for the same period in 2007, based on interest at 6.75 percent, and accretion of the debt discount of $0.4 million (2007 - $0.5 million). The decrease in interest and accretion in 2008 is due to conversions to equity that occurred earlier in 2008.

For the year ended December 31, 2008 the interest charge on the convertible debentures was $5.9 million as compared to $2.3 million for the comparable period in 2007, as 2007 includes only four months of interest charges. Accretion of the debt discount was $1.7 million for the year ended December 31, 2008 as compared to $0.6 million for the same period in 2007. The debentures were issued on August 28, 2007.



Interest and Debt
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest on bank debt
($000s) 2,961 3,820 14,116 13,356
Interest and accretion on
convertible debentures 1,679 2,178 7,631 2,965
($000s)
----------------------------------------------------------------------------
Total interest ($000) 4,640 5,998 21,747 16,321

Bank debt outstanding at
period end ($000s) 282,332 275,630 282,332 275,630
Convertible debentures at
period end ($000s)(1) 74,004 90,876 74,004 90,876

$/boe:
Interest on bank debt 1.34 1.76 1.62 1.77
Interest on convertible
debentures 0.59 0.77 0.68 0.31
Accretion on convertible
debentures 0.17 0.23 0.20 0.08
----------------------------------------------------------------------------
Total interest 2.10 2.76 2.50 2.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Debt component of the debentures, as reported on the balance sheet.


CASH FLOW NETBACK

For the quarter ended December 31, 2008, NAL's cash flow netback was $31.90 per boe, a 15 percent increase from $27.79 for the comparable period in 2007. The increase is due to higher operating netbacks after hedging in 2008, lower G&A expenses including unit-based incentive compensation and lower interest charges, offset by interest on the notes with MFC.

For the year ended December 31, 2008, NAL's cash flow netback increased 29 percent to $38.26 per boe from $29.67 per boe for the comparable period in 2007. The increase is due to higher operating netbacks after hedging in 2008 and decreased G&A expenses, partially offset by an increase in interest charges for bank debt and convertible debentures and interest on notes with MFC.



Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Operating netback, after hedging 34.92 32.70 42.25 33.95
G&A expenses, including unit-based
incentive compensation (1.42) (2.38) (2.02) (2.20)
Interest on bank debt and convertible
debentures(1) (1.93) (2.53) (2.30) (2.08)
Interest on notes with MFC(2) 0.33 - 0.33 -
----------------------------------------------------------------------------
Cash flow netback 31.90 27.79 38.26 29.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.
(2) Reported as other income.


DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATIONS ("DDA")

Depletion of oil and natural gas properties, including the capitalized portion of the asset retirement obligations, and depreciation of equipment is provided for on a unit-of-production basis using estimated proved reserves volumes.

For the quarter ended December 31, 2008, depletion on property, plant and equipment and accretion on the asset retirement obligations was $20.21 per boe as compared to $20.42 for the same period in 2007.

The DDA rate will fluctuate period-over-period depending on the amount and type of capital expenditures and the amount of reserves added. The decrease in depletion rate for the fourth quarter of 2008 as compared to the prior quarters in 2008 is due to the incorporation of the positive year-end reserve revisions into the fourth quarter depletion rate.

For the year ended December 31, 2008, the DDA rate per boe was $22.18 as compared to $21.32 for 2007.



Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 42,743 42,888 185,894 155,392
Accretion of asset retirement
obligation ($000s) 1,841 1,564 7,299 5,533
----------------------------------------------------------------------------
Total DDA ($000s) 44,584 44,452 193,193 160,925
DDA rate per boe ($) 20.21 20.42 22.18 21.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------


TAXES

In the fourth quarter of 2008, NAL had a future income tax expense of $25.5 million compared with a $2.0 million recovery in the corresponding period for the prior year. For the year ended December 31, 2008, NAL had a future income tax expense of $33.6 million compared to a $3.4 million recovery in 2007. The increase in future taxes of $37.0 million during 2008 is attributable to $15.0 million recognized for the change in the taxation of income trusts, which will be effective in 2011, and $19.4 million recognized in relation to derivative contracts.

The Trust is a taxable entity and files a trust income tax return annually. The Trust's taxable income consists of royalty income, distributions from a subsidiary trust and interest and dividends from other subsidiaries, less deductions for the Trust's G&A expenses, Canadian Oil and Gas Property Expense ("COGPE"), and issue costs. In addition, Canadian Exploration Expense ("CEE"), Canadian Development Expense ("CDE") and Undepreciated Capital Cost ("UCC") are incurred and deducted by the Trust's subsidiaries. The Trust is taxable only on remaining income, if any, that is not distributed to unitholders.

As at December 31, 2008, the Trust's (including all subsidiaries) estimated tax pools (unaudited) available for deduction from future taxable income approximated $737.7 million, of which approximately 41 percent represented COGPE and 28 percent UCC, with the remaining balance represented by CEE, CDE, trust unit issue costs and non-capital loss carry forwards.



December 2008 December 2007
$MM $MM
----------------------------------------------------------------------------
Canadian exploration expense 12 12
Canadian development expense 202 150
Canadian oil and gas property expense 301 308
Undepreciated capital costs 209 203
Other (including loss carry forwards) 14 19
----------------------------------------------------------------------------
Total 738 692
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Based on current strip prices at December 31, 2008, the Trust is not expected to be taxable in 2009.

On June 22, 2007, the Budget Implementation Act, 2007 (Canada) was enacted to, among other things, implement the October 31, 2006 announcement of the changes to taxability of income trusts made by the Department of Finance. Under this legislation, distributions to unitholders will not be deductible by publicly traded income trusts and, as a result, the Trust will be taxed on its income similar to corporations. These measures are considered enacted for purposes of GAAP. Accordingly, the Trust has measured future income tax assets and liabilities associated with this new tax. For 2008, and in total, the Trust has recognized $15.0 million of future income tax liability in the financial statements associated with this new tax ($10.0 million in the fourth quarter). It is expected that all remaining taxable temporary differences will reverse prior to January 1, 2011, the date the taxation changes take effect. The scheduling of the reversal of temporary differences is based on management's best estimates and current assumptions, which may change.

NET INCOME

Net income is a measure impacted by both cash and non-cash items. The largest non-cash items impacting the Trust's net income are DDA, unrealized gains or losses on derivative contracts and future income taxes.

Net income for the fourth quarter of 2008 was $55.4 million compared to $10.6 million for the comparable period in 2007. The increase of $44.8 million is due to an increased gain on derivative contracts ($86.0 million), partially offset by decreased revenue, net of royalties ($11.5 million), increases in operating costs ($4.2 million), and future income tax expense ($27.5 million).

Net income for the year ended December 31, 2008 of $162.6 million was $106.1 million greater than the $56.5 million for 2007. The increase of $106.1 million is due to higher revenue, net of royalties ($163.7 million) and an increased gain on derivative contracts ($59.7 million), partially offset by increases in operating costs ($25.0 million), future income tax expense ($37.0 million), DDA ($32.3 million), interest on debentures ($4.7 million), a bad debt expense ($6.9 million) and a non-controlling interest ($10.4 million).



Net Income ($000s)
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Net income 55,374 10,556 162,580 56,457
----------------------------------------------------------------------------
----------------------------------------------------------------------------


CAPITAL RESOURCES AND LIQUIDITY

The capital structure of the Trust is comprised of trust units, bank debt and convertible debentures.

As at December 31, 2008, NAL had 96,181,397 trust units outstanding, compared with 90,494,151 trust units at December 31, 2007. The increase from December 31, 2007 is attributable to 2,408,898 trust units issued on the acquisition of Tiberius and Spear, 1,446,844 trust units issued on the conversion of outstanding convertible debentures and 1,831,504 trust units issued under the Trust's distribution reinvestment program ("DRIP").

Under the equity issuance associated with the acquisition of Tiberius and Spear, 2.4 million trust units were issued at a price of $12.24 per trust unit for a total consideration of $29.5 million.

For the year ended December 31, 2008, the DRIP resulted in 1.8 million trust units being issued at an average price of $12.77 per trust unit for total proceeds of $23.4 million.

Under the DRIP, unitholders may elect to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP at 95 percent of the average market price with no additional fees or commissions. Due to market conditions, relatively low unit prices, and the strength of its balance sheet, the Trust suspended the DRIP program effective October 9, 2008. The Trust will assess reinstatement of the plan on an ongoing basis.

The premium distribution reinvestment plan ("Premium DRIP") allows unitholders to exchange such units for a cash payment, from the plan broker, equal to 102 percent of the monthly distribution. The Premium DRIP program has been suspended since March 10, 2006.

As at December 31, 2008 the Trust had net debt of $398.8 million (net of working capital and excluding derivative contracts, notes payable/receivable with MFC and future income taxes) including convertible debentures at face value of $79.7 million. Excluding the convertible debentures, net debt was $319.0 million, compared with $291.1 million at December 31, 2007. The increase in net debt, excluding convertible debentures, of $28.0 million during 2008 is attributable to a $21.3 million negative change in working capital and increased bank debt of $6.7 million.

Bank debt outstanding was $282.3 million at December 31, 2008 compared with $275.6 million as at December 31, 2007. Of the $282.3 million outstanding at December 31, 2008, $0.3 million is outstanding under the working capital facility with $282.0 million outstanding under the production facility. The bank debt of $28.3 million relating to the acquisition of Tiberius and Spear was repaid during 2008. The increase in bank debt during 2008 of $6.7 million is a reflection of the fourth quarter increase in debt of $11.4 million, due to lower commodity prices producing lower cash flows.

At the end of 2008, the Trust had a net debt (excluding convertible debentures) to 12 months trailing cash flow ratio of 1.03 times and a total net debt (including convertible debentures) to 12 months trailing cash flow ratio of 1.28 times.

The credit facility was increased by $50 million to $450 million during 2008. Concurrent with this increase, two new banks were added to the banking syndicate. The credit facility is a fully secured, extendible, revolving facility and will revolve until April 29, 2009 at which time it is extendible for a further 364-day revolving period upon agreement between the Trust and the bank syndicate. The facility consists of a $440 million production facility and a $10 million working capital facility. The credit facility is fully secured by first priority security interests in all present and after acquired properties and assets of the Trust and its subsidiary and affiliated entities. The purpose of the facility is to fund property acquisitions and capital expenditures. Principal repayments to the bank are not required at this time. Should principal repayments become mandatory, and in the absence of refinancing arrangements, the Trust would be required to repay the facility in five equal quarterly installments commencing April 30, 2010. As the available lending limits of the facility are based on the bank syndicate's interpretation of the Trust's reserves and future commodity prices, there can be no assurance that the amount of available facility will not decrease at the next scheduled review on April 29, 2009.

The Trust has outstanding $79.7 million principal amount of 6.75% convertible extendible unsecured subordinated debentures. Interest on these debentures is paid semi-annually in arrears, on February 28 and August 31, and the debentures are convertible at the option of the holder, at any time, into fully paid trust units at a conversion price of $14.00 per trust unit. During 2008, face value of $20.3 million in debentures were converted at $14.00 per unit into 1,446,844 trust units (no conversions in the fourth quarter). The debentures mature on August 31, 2012 at which time they are due and payable. The debentures are redeemable by the Trust at a price of $1,050 per debenture on or after September 1, 2010 and on or before August 31, 2011, and at a price of $1,025 per debenture on or after September 1, 2011 and on or before August 31, 2012. On redemption or maturity, the Trust may opt to satisfy its obligation to repay the principal by issuing trust units. If all of the outstanding debentures were converted at the conversion price, an additional 5.7 million trust units would be required to be issued.

The convertible debentures are classified as debt on the balance sheet with a portion of the proceeds allocated to equity, representing the value of the conversion feature. As the debentures are converted to trust units, a portion of the debt and equity amounts are transferred to Unitholders' Capital. The debt component of the convertible debentures is carried net of issue costs of $4 million. The debt balance, net of issue costs, accretes over time to the principal amount owing on maturity. The accretion of the debt discount and the interest paid to debenture holders are expensed each period as part of the line item "interest and accretion on convertible debentures" in the consolidated statement of income.

The Trust recognized $0.4 million (2007 - $0.5 million) of accretion of the debt discount in the fourth quarter of 2008 and $1.7 million (2007 - $0.6 million) for the year ended December 31, 2008.

As at February 25, 2009, the Trust has 96,181,397 trust units and $79.7 million in convertible debentures outstanding.



Year-end Capitalization
----------------------------------------------------------------------------
2008 2007
----------------------------------------------------------------------------
Trust unit equity ($000s) 557,263 504,717

Bank debt ($000s) 282,332 275,630
Working capital deficit(1) ($000s) 36,712 15,429
----------------------------------------------------------------------------
Net debt excluding convertible debentures 319,044 291,059
Convertible debentures ($000s)(2) 79,744 100,000
----------------------------------------------------------------------------
Net debt 398,788 391,059

Net debt excluding convertible debentures to
trailing 12-month cash flow(3) 1.03 1.33
Total net debt to trailing 12-month cash flow(3) 1.28 1.79
Trust units outstanding (000s) 96,181 90,494
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Working capital excludes derivative contracts and future income tax
asset.
(2) Convertible debentures included at face value.
(3) Calculated as net debt divided by funds from operations for the previous
12 months.


The current economic slowdown, reduced availability of credit, and challenging equity markets has resulted in the Trust setting its liquidity objective for 2009, to operating within forecasted funds from operations, targeting a total payout ratio of 100 percent (distribution plus capital). Funds from operations is a non-GAAP measure used by management as an indicator of the ability to generate cash from operations. Currently, the Trust has a bank line of $450 million of which $282 million is drawn down at December 31, 2008, leaving capacity of $168 million.

On January 12, 2009 the Trust announced a reduction in distributions from $0.16 per unit to $0.11 per unit commencing with the distribution payable as at February 16, 2009. This reduction was made in response to declining commodity prices, taking into account the need for an ongoing capital program and maintenance of a strong balance sheet.

For 2009, the Trust is benefiting from an active hedging program at prices above current market levels. Currently, the Trust has in place oil hedges for 52 percent of net budgeted production (after royalty) for the first half of 2009 with a total of 42 percent of 2009 average volume hedged for the full year. Volumes are hedged at an average floor price of $107.71 per boe. For natural gas, first half 2009 hedges total 38 percent of net budgeted production or 36 percent on a full year basis with volumes hedged at an average floor price in excess of $7.53 per GJ (or $7.95 per mcf).

In the 2009 guidance presentation released January 12, 2009, the Trust used a US$50 WTI per barrel crude oil price (US$45 for the first six months and US$55 for the last six months of the year), a 1.20 Cdn/US$ exchange and $6.50 per GJ natural gas price. Fluctuations in commodity prices, other market factors, or growth opportunities may make it necessary to adjust forecasted capital expenditures or distributions levels.

NAL's capital program for 2009 has been designed to be scalable and flexible in response to uncertain commodity price and market conditions. NAL initially planned a $110 million capital program with the expectation to drill approximately 82 (40 net) wells at forecasted prices as set out above. Capital for the first half of 2009 has been reduced by $15 million in response to weaker commodity prices, which translates to a full year program of $95 million. The Trust operates over 90 percent of the assets to which the capital program is directed allowing for significant flexibility over the timing and scale of the program.

Under the tax legislation regarding the change in the taxation of income trusts, the Trust has a grandfathering period to 2011, when the rules come into effect. The grandfathering period restricts "undue expansion" of the Trust by placing growth limits for issuances of equity and convertible debt, based on the market capitalization of the Trust on October 31, 2006, the date of the announcement of the changes in the tax legislation. For 2009 and 2010, the Trust has approximately $1.11 billion of available safe harbour, all of which is currently available.

ASSET RETIREMENT OBLIGATION

At December 31, 2008, the Trust reported an asset retirement obligation ("ARO") balance of $90.8 million ($89.6 million as at December 31, 2007) for future abandonment and reclamation of the Trust's oil and gas properties and facilities. The ARO balance was increased by $1.6 million due to the Tiberius and Spear acquisitions, $1.2 million due to liabilities incurred and revisions to estimates, and $7.3 million from accretion expense and was reduced by $8.9 million for actual abandonment and environmental expenditures incurred in 2008.

DISTRIBUTIONS TO UNITHOLDERS

For the three months and full year ended December 31, 2008, the Trust distributed 60 percent and 57 percent, respectively, of its cash flow from operating activities, as compared to 96 percent and 74 percent, respectively, for the same periods in 2007. The payout associated with cash flow from operating activities will fluctuate significantly period over period as cash flow from operating activities includes changes in non-cash working capital associated with operating activities. In the fourth quarter of 2008, the Trust distributed 83 percent of net income, resulting in excess net income of $9.2 million over distributions paid. For 2008, the Trust has distributed in excess of its net income by $18.9 million. The Trust usually distributes in excess of its net income each period, due to the non-cash charges included in net income. However, in the fourth quarter of 2008, a $56.6 million unrealized gain on derivative contracts ensured net income exceeded distributions paid. Cash flow from operations usually exceeds net income, as net income includes non-cash charges such as DDA, future income tax expense and unrealized gains and losses on derivative contracts.

The Board of Directors of NAL Energy Inc. sets distribution levels taking into consideration commodity prices, forecast cash flow of the Trust, financial market conditions, availability of financing, internal capital investment opportunities and taxability.

Given that distributions exceeded net income during 2008, the excess could be considered to be an economic return of capital to the unitholders. The Trust's business model is such that it distributes a certain proportion of its cash flow while retaining cash to execute planned capital programs. As a result of the depleting nature of oil and gas assets some capital expenditure is required in order to minimize production declines as well as to invest in facilities and infrastructure. NAL's 2009 capital program may not fully replace production. When the Trust sets distribution levels, depletion expense is not considered to be indicative of a measure for maintaining productive capacity, and therefore, net income is not considered a driver of distribution levels. The Trust grows its productive capacity and sustains its cash flow through development activities and acquisitions. NAL's productive capacity and future cash flow will be dependent on its ability to acquire assets and continue to find economic reserves. Acquisitions are financed through equity, debt or a combination of the two.

Generally, the capital expenditures of the Trust and the distributions in any given period exceed the cash flow from operating activities. The shortfall is financed from the credit facility. However, given the current economic slowdown, the Trust is targeting cash flow to equal distributions and capital expenditures in order to preserve the Trust's balance sheet. Fluctuations in commodity prices, other market factors, or growth opportunities may make it necessary to adjust forecasted capital expenditures or distributions levels.

NAL intends to continue to make cash distributions to unitholders. However, these cash distributions cannot be guaranteed. The primary drivers of the level of distributions are the assumptions that contribute to cash flow, namely production, operating costs and commodity prices. The implication of this policy is that the Trust is likely to continue to distribute in excess of its net income for any given period. The future sustainability of this distribution policy will be dependent upon maintaining productive capacity through both capital expenditures and acquisitions. A significant further decrease in commodity prices or continuing low commodity prices may impact cash from operating activities, access to credit facilities and the Trust's ability to fund operations and maintain distributions.



Distributions
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
($000s except for percentages) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash flow from operating
activities 77,326 45,111 320,042 215,364
Net income 55,374 10,556 162,580 56,457
Actual cash distributions paid
or payable 46,167 43,340 181,462 158,601
Excess of cash flow from
operating activities over cash
distribution paid 31,159 1,771 138,580 56,763
Percentage of cash flow from
operations distributed 60% 96% 57% 74%
Excess (shortfall) of net
income over cash distributions
paid 9,207 (32,784) (18,882) (102,144)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As stated in the non-GAAP measures section of the MD&A, NAL uses funds from operations as a key performance indicator to measure the ability of the Trust to generate cash from operations and to pay monthly distributions.

For the three months ended December 31, 2008, funds from operations amounted to $67.0 million, compared with $59.5 million for the three months ended December 31, 2007. The 13 percent increase is due to the realized hedging gains of $16.5 million, offset by lower revenues due to lower commodity prices. On a per trust unit basis, funds from operations increased six percent from $0.66 in 2007 to $0.70 in 2008, the increase in funds from operations being partially offset by the increase in the number of trust units outstanding due to the equity issuance associated with the acquisition of Tiberius and Spear.

For the year ended December 31, 2008, funds from operations increased 42 percent to $311.1 million from $218.7 million in 2007. The increase is primarily due to increased revenues driven by higher prices and production.



Funds from Operations
----------------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Funds from operations ($000s) 67,040 59,537 311,071 218,745
Funds from operations per trust unit 0.70 0.66 3.29 2.65
Payout ratio based on funds from
operations 69% 73% 58% 73%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


VARIABLE INTEREST ENTITIES

NAL has no variable interest entities.

CONTRACTUAL OBLIGATIONS

NAL has entered into several contractual obligations as part of conducting day-to-day business. NAL has the following commitments for the next five years:



----------------------------------------------------------------------------
($000s) 2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Office lease(1) 4,145 3,799 - - -
Transportation agreement 1,673 1,673 589 - -
Processing agreement(2) 446 428 414 401 384
Convertible debentures(3) - - - 79,744 -
Bank debt - 169,399 112,933 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 6,264 175,299 113,936 80,145 384
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including both
base rent and operating costs, in relation to the lease held by the
Manager, of which the Trust is allocated a pro rata share (currently
approximately 58 percent) of the expense on a monthly basis.
(2) Represents a gas processing agreement with a take or pay component.
(3) Principal amount.


QUARTERLY INFORMATION

2008
----------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Revenue, net of royalties 161,156 234,993(2) 58,861(3) 89,611
Per unit 1.68 2.46 0.63 0.98
Funds from operations(1) 67,040 79,233 88,578 76,220
Per unit 0.70 0.83 0.94 0.83
Net income (loss) 55,374 111,045 (17,572) 13,733
Per unit
basic 0.58 1.16 (0.19) 0.15
diluted 0.56 1.11 (0.19) 0.15
Average oil equivalent
production (boe/d - 6:1) 23,984 23,808 23,791 23,601
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2007
----------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Revenue, net of royalties 86,262 78,573 83,268 71,231
Per unit 0.96 0.95 1.06 0.91
Funds from operations(1) 59,537 50,817 54,156 54,234
Per unit 0.66 0.61 0.69 0.69
Net income (loss) 10,556 7,801 21,390 16,710
Per unit
basic 0.12 0.09 0.27 0.21
diluted 0.12 0.09 0.27 0.21
Average oil equivalent
production (boe/d - 6:1) 23,656 20,369 19,094 19,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
(2) Excluding the unrealized gain on derivative contracts of $111,053,000;
Revenue, net of royalties would be $123,940,000.
(3) Excluding the unrealized loss on derivative contracts of $70,148,000;
Revenue net of royalties would be $129,009,000.


SELECTED ANNUAL INFORMATION

Years ended December 31
----------------------------------------------------------------------------
($000s except per unit amounts) 2008 2007 2006
----------------------------------------------------------------------------
Oil, natural gas and liquid sales 618,914 416,813 385,624
Net income 162,580 56,457 60,198
Net income per trust unit 1.72 0.68 0.79
Net income per trust unit - diluted 1.69 0.68 0.79
Distributions paid and declared 181,462 158,601 169,589
Distributions paid or declared per
trust unit 1.92 1.92 2.22
Total assets 1,210,597 1,063,160 796,902
Total liabilities 653,334 558,443 340,402
Long term debt(1) 356,336 366,506 220,785
Unitholders' equity 557,263 504,717 456,500

Number of trust units outstanding at
year-end 96,181 90,494 77,971
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes bank debt and convertible debentures.


DISCLOSURE CONTROLS AND PROCEDURES

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining disclosure controls and procedures ("DC&P"), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109"), for NAL. They have, as at the financial year ended December 31, 2008, designed such DC&P, or caused them to be designed under their supervision, to provide reasonable assurance that information required to be disclosed by NAL in its annual filings, interim filings or other reports filed or submitted by NAL under applicable securities legislation is recorded, processed, summarized and reported within the time periods specified in applicable securities legislation and that all material information relating to NAL is made known to them by others, particularly during the period in which NAL's annual and interim filings are being prepared.

Under the supervision of the Chief Executive Officer and the Chief Financial Officer, NAL conducted an evaluation of the effectiveness of its DC&P as at December 31, 2008. Based on this evaluation, the officers concluded that as of December 31, 2008, NAL's DC&P provide reasonable assurance that information required to be disclosed by NAL in its annual filings, interim filings or other reports that it files or submits under applicable securities legislation is recorded, processed, summarized and reported within the time periods specified in such legislation and that these controls and procedures also provide reasonable assurance that material information relating to NAL is made known to our Chief Executive Officer and Chief Financial Officer by others.

INTERNAL CONTROL OVER FINANCIAL REPORTING

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (ICFR), as such term is defined in NI 52-109, for NAL. They have, as at the financial year ended December 31, 2008, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The control framework the officers used to design NAL's ICFR is the Internal Control - Integrated Framework (COSO Framework) published by The Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Under the supervision of the Chief Executive Officer and the Chief Financial Officer (the "Officers"), NAL conducted an evaluation of the effectiveness of its ICFR as at December 31, 2008 based on the COSO Framework. Based on this evaluation, the Officers concluded that as of December 31, 2008, NAL's ICFR does provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

It should be noted that while the Officers believe that NAL's controls provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the disclosure controls and procedures or internal controls over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

There were no changes in the Trust's ICFR during the year ended December 31, 2008 that materially affected the Trust's ICFR.

CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by NAL are disclosed in the notes to NAL's December 31, 2008 consolidated financial statements. Certain accounting policies require that management make appropriate decisions when formulating estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The Manager reviews the estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes in estimated amounts that differ materially from current estimates. NAL might realize different results from the application of new accounting standards published, from time to time, by various regulatory bodies.

Proved Oil and Gas Reserves

Under National Instrument 51-101 ("NI 51-101"), "proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable (it is possible that the actual remaining quantities recovered will exceed the estimated proved reserves). The level of certainty should result in at least a 90 percent probability at a company aggregate level that the quantities actually recovered will equal or exceed the estimated reserves. In the case of "probable" reserves, which are less certain to be recovered than proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable ("P+P") reserves. As for certainty, in order to report reserves as P+P, the reporting company must believe that there is at least a 50 percent probability at a company aggregate level that the quantities actually recovered will equal or exceed the sum of the estimated P+P reserves.

The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in NAL's plans. The effect of changes in proved oil and gas reserves on the financial results and position of NAL is described under the heading "Impairment of Property, Plant and Equipment" below.

Depletion Expense

NAL uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether or not the activities funded were successful. The aggregate of net capitalized costs and estimated future development costs is amortized using the unit of production method on estimated proved oil and gas reserves.

An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense.

Unproved Properties

The cost of acquisition and evaluation of unproved properties are initially excluded from the depletion calculation. These properties are assessed to ascertain whether impairment in value has occurred. When proved reserves are assigned or a property is considered to be impaired, the cost of the property or the amount of the impairment will be added to the capitalized costs for the calculation of depletion.

Impairment of Property, Plant & Equipment

NAL is required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived oil and gas asset is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the property, plant and equipment is charged to net income.

The cash flows used in the impairment assessment require management to make assumptions and estimates about recoverable reserves (see Proved Oil and Gas Reserves above), future commodity prices and operating costs. Changes in any of the assumptions, such as downward revision in reserves, a decrease in future commodity prices, or an increase in operating costs could result in an impairment of an asset's carrying value.

Goodwill

Goodwill is subject to impairment tests annually, or as economic events dictate, by comparing the fair value of the reporting entity to its carrying value, including goodwill. If the fair value of the reporting entity is less than its carrying value, a goodwill impairment loss is recognized as the excess of the carrying value of the goodwill over the implied value of the goodwill. The determination of fair value requires management to make assumptions and estimates about recoverable reserves (see the Proved Oil and Gas Reserves discussion above), future commodity prices, operating costs, production profiles and discount rates. Adverse changes in any of these assumptions could result in an impairment of all or a portion of the goodwill carrying value in future periods.

Fair Value of Derivative Instruments

NAL utilizes financial derivatives to manage market risk. The purpose of hedging activity is to provide an element of stability to NAL's cash flow in a volatile market environment. NAL recognizes the fair value of derivative contracts on its balance sheet with the change in fair value recognized in net income of the period. The fair value of commodity derivative contracts is based on forward commodity prices. The fair value of interest rate derivative contracts is based on forward interest rates. Any change in commodity prices and interest rates will impact the fair value of the contracts and therefore net income of the period.

Asset Retirement Obligation

NAL is required to recognize and measure liabilities associated with capital assets. A liability is recognized equal to the discounted fair value of the obligation in the period in which the asset is recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value with the passage of time. Management is required to estimate the timing and future costs to settle liabilities. Changes in the estimated future costs, the timing of these costs, and the discount rate will impact the liability, related asset and expense.

Legal, Environmental Remediation and Other Contingent Matters

NAL is required to determine whether a loss is probable based on judgment, the interpretation of laws and regulations and whether the loss can reasonably be estimated. When the loss is determined, it is charged to net income. NAL's management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.

Income Tax Accounting

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

Future income taxes are recognized for temporary differences arising in the Trust's subsidiaries and also those arising in the Trust that reverse after 2011. Should the assumptions underlying the estimate of the reversal of temporary differences change, including future commodity prices, payout ratio, capital expenditures and reserves, future taxes recorded may be adjusted for the Trust.

NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Trust implemented the provisions of CICA Handbook Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", and Section 3863 "Financial Instruments - Presentation".

Section 1535 establishes standards for disclosing information about an entity's capital and how it is managed. This Section specifies disclosure about objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and if it has not complied, the consequences of such non-compliance. Sections 3862 and 3863 establish standards for the presentation and disclosure of information that enable users to evaluate the significance of financial instruments to the entity's financial position, and the nature and extent of risks arising from financial instruments and how the entity manages those risks.

The implementation of these new standards did not impact the Trust's financial results but did, however, result in additional disclosures.

FUTURE ACCOUNTING CHANGES

Goodwill and Intangible Assets

In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Section 3064 will be effective for the Trust on January 1, 2009. The Trust is currently evaluating the impact of adoption of this new section, however the impact is expected to be minimal on its consolidated financial statements.

Business Combinations

In December 2008, the CICA issued Section 1582, "Business Combinations," replacing Section 1581. Section 1582 includes potentially significant changes to the measurement of purchase consideration in a business combination. Under Section 1582, the fair value ascribed to units issued as consideration will be based on their market value at the date of exchange, as compared to the current standard which prescribes market price for a reasonable period of time before and after the date of acquisition. In addition, the majority of acquisition costs will likely have to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. Section 1582 also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting date until settled. Currently standards require only contingent liabilities that are payable to be recognized. Section 1582 also requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-currents assets in the purchase price allocation. Section 1582 will be effective for the Trust on January 1, 2011, with prospective application.

International Financial Reporting Standards ("IFRS")

In February 2008, the CICA Accounting Standards Board ("AcSB"), confirmed that the changeover to IFRS from Canadian GAAP will be required for publicly accountable enterprises' interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010. The changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Trust's reported financial position and results of operations.

The International Accounting Standards Board ("IASB") has also issued an exposure draft relating to certain amendments and exemptions to IFRS 1 in order to make it more useful to Canadian entities adopting IFRS for the first time. One of the exemptions relating to full cost oil and gas accounting would reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment, if implemented, will permit the Trust to apply IFRS prospectively to its full cost pool, rather than the performing retrospective assessment of capitalized exploration and development expenses, with the provision that a ceiling test, under IFRS standards, be conducted at the transition date.

In response, the Trust has completed a high level IFRS changeover plan and established a preliminary timeline for the execution and completion of the conversion project. The changeover plan was determined following a preliminary assessment of the differences between Canadian GAAP and IFRS and the potential effects of IFRS to accounting and reporting processes, information systems, business processes and external disclosures. The plan addresses project structure and governance, resourcing and training, an initial impact assessment and establishes the key milestones that must be met to complete the conversion project. The Trust will also establish a Convergence Committee, made up of key Trust stakeholders, to begin the execution stage of the conversion project.

During the next phase of the project, due to take place during 2009, the Trust will perform an in-depth review of the significant areas of differences, in order to identify all specific Canadian GAAP and IFRS differences and select ongoing IFRS policies. Key areas addressed will also be reviewed to determine any information technology issues, the impact on internal controls over financial reporting and the impact on business activities including the effect, if any, on covenants and compensation arrangements.

The Trust will also continue to monitor standards development as issued by the IASB and the AcSB as well as regulatory developments as issued by the Canadian Securities Administrators which may affect the timing, nature or disclosure of its adoption of IFRS.

Dated: February 26, 2009



CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
December 31, December 31,
2008 2007
----------------------------------------------------------------------------

Assets
Current assets
Cash $5,584 $1,394
Accounts receivable and other 57,825 70,791
Note receivable (Notes 4 and 5) 49,599 -
Derivative contracts (Note 14) 65,680 3,389
Future income tax asset (Note 13) - 2,602
----------------------------------------------------------------------------
178,688 78,176

Future income tax asset (Note 13) - 4,096
Goodwill (Note 4) 14,722 -
Property, plant and equipment (Notes 4 and 6) 1,017,187 980,888
----------------------------------------------------------------------------
$1,210,597 $1,063,160
----------------------------------------------------------------------------

Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $84,732 $73,135
Note payable (Notes 4 and 5) 9,609 -
Distributions payable to unitholders 15,389 14,479
Derivative contracts (Note 14) - 12,973
Future income tax liability (Note 13) 16,788 -
----------------------------------------------------------------------------
126,518 100,587

Bank debt (Note 7) 282,332 275,630
Convertible debentures (Note 8) 74,004 90,876
Derivative contracts (Note 14) 274 -
Unit-based incentive compensation (Note 9) 890 1,748
Asset retirement obligations (Note 10) 90,844 89,602
Future income tax liability (Note 13) 22,092 -
Non-controlling interest (Note 11) 56,380 -
----------------------------------------------------------------------------
653,334 558,443

Unitholders' equity
Unitholders' capital (Note 12) 1,042,183 969,588
Equity component of convertible
debentures (Note 8) 4,592 5,759
Deficit (Note 12) (489,512) (470,630)
----------------------------------------------------------------------------
557,263 504,717
----------------------------------------------------------------------------
$1,210,597 $1,063,160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (Note 15)

Trust units outstanding (000s) (Note 12) 96,181 90,494
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes.


CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)

Three months ended Years ended
December 31 December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue
Oil, natural gas and liquid sales $108,037 $124,059 $618,914 $416,813
Crown royalties (16,438) (19,138) (94,535) (64,798)
Freehold and other royalties (4,725) (6,508) (31,895) (23,249)
----------------------------------------------------------------------------
86,874 98,413 492,484 328,766
Gain (loss) on derivative
contracts (Note 14):
Realized gain (loss) 16,531 (5,510) (27,317) (2,435)
Unrealized gain (loss) 56,620 (8,213) 74,990 (14,105)
Reclassification from other
comprehensive income - 874 - 4,521
----------------------------------------------------------------------------
73,151 (12,849) 47,673 (12,019)
Other income 1,131 698 4,464 2,587
----------------------------------------------------------------------------
161,156 86,262 544,621 319,334
----------------------------------------------------------------------------
Expenses
Operating 25,749 21,537 94,928 69,916
Transportation 996 897 3,875 2,779
General and administrative 3,814 4,096 15,764 14,404
Unit-based incentive
compensation
(Note 9) (693) 1,080 1,826 2,152
Interest on bank debt 2,961 3,820 14,116 13,356
Interest and accretion on
convertible debentures 1,679 2,178 7,631 2,965
Bad debt expense (Note 14) - - 6,901 -
Depletion, depreciation and
amortization 42,743 42,888 185,894 155,392
Accretion on asset retirement
obligations 1,841 1,564 7,299 5,533
----------------------------------------------------------------------------
79,090 78,060 338,234 266,497
----------------------------------------------------------------------------
Income before taxes and
non-controlling interest 82,066 8,202 206,387 52,837

Income tax recovery 53 350 256 267
Future income tax reduction
(provision) (25,482) 2,004 (33,622) 3,353
----------------------------------------------------------------------------
Total income tax reduction
(provision) (Note 13) (25,429) 2,354 (33,366) 3,620
----------------------------------------------------------------------------
Income before non-controlling
interest 56,637 10,556 173,021 56,457

Non-controlling interest (Note 11) (1,263) - (10,441) -

----------------------------------------------------------------------------
Net income 55,374 10,556 162,580 56,457
Other comprehensive income:
Reclassification to net income,
net of tax - (613) - (3,172)
----------------------------------------------------------------------------
Comprehensive income 55,374 9,943 162,580 53,285
----------------------------------------------------------------------------

Deficit, beginning of period (498,719) (437,846) (470,630) (368,486)
Net income 55,374 10,556 162,580 56,457
Distributions declared (Note 12) (46,167) (43,340) (181,462) (158,601)
----------------------------------------------------------------------------
Deficit, end of period $(489,512)$(470,630)$(489,512)$(470,630)
----------------------------------------------------------------------------

Net income per trust unit (Note 12)
Basic $0.58 $0.12 $1.72 $0.68
Diluted $0.56 $0.12 $1.69 $0.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average trust units
outstanding (000s) 96,145 90,194 94,415 82,556
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes.


CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)

Three months ended Years ended
December 31 December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Operating Activities
Net income $55,374 $10,556 $162,580 $56,457
Items not involving cash:
Depletion, depreciation and
amortization 42,743 42,888 185,894 155,392
Accretion on asset retirement
obligations 1,841 1,564 7,299 5,533
Unrealized loss (gain) on
derivative contracts (56,620) 8,213 (74,990) 14,105
Reclassification from other
comprehensive income - (874) - (4,521)
Future income tax provision
(reduction) 25,482 (2,004) 33,622 (3,353)
Non-cash accretion expense on
convertible debentures 376 477 1,696 635
Non-controlling interest 1,716 - 3,823 -
Abandonment and environmental
expenditures (3,872) (1,283) (8,853) (5,503)
Change in non-cash working capital 10,286 (14,426) 8,971 (3,381)
----------------------------------------------------------------------------
77,326 45,111 320,042 215,364
----------------------------------------------------------------------------

Financing Activities
Distributions paid to unitholders (43,609) (36,834) (157,159) (129,862)
Issue of trust units, net of issue
costs (15) - (29) 117,867
Increase in bank debt 11,350 19,145 6,702 54,127
Issuance of convertible debentures - - - 96,000
Partnership distribution paid to
MFC (Note 5) - - (1,500) -
Change in non-cash working capital - 426 (426) 1,341
----------------------------------------------------------------------------
(32,274) (17,263) (152,412) 139,473
----------------------------------------------------------------------------

Investing Activities
Acquisition of Tiberius and Spear
(Note 4) (315) - (77,684) -
Disposition of Tiberius and Spear
(Note 4) - - 58,221 -
Acquisition of Seneca (Note 4) - 323 337 (245,687)
Additions to property, plant and
equipment (41,212) (39,194) (150,472) (118,011)
Property acquisitions (8) - (8,122) (1,449)
Proceeds from dispositions 135 - 40 26
Change in non-cash working capital (577) 6,325 14,240 5,383
----------------------------------------------------------------------------
(41,977) (32,546) (163,440) (359,738)
----------------------------------------------------------------------------

Increase (decrease) in cash 3,075 (4,698) 4,190 (4,901)
Cash, beginning of period 2,509 6,092 1,394 6,295
----------------------------------------------------------------------------
Cash, end of period $5,584 $1,394 $5,584 $1,394
----------------------------------------------------------------------------

Supplementary disclosure of cash
flow information:
Cash paid (received) during the
period for:
Interest $1,959 $4,777 $17,130 $16,913
Tax (recovery) $(586) $(350) $4,219 $(267)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 2008 and 2007
(Tabular amounts in thousands of dollars, except per unit amounts)
(unaudited)


1. STRUCTURE OF THE TRUST

The Trust is an open-ended investment trust formed under the laws of the Province of Alberta. Operations commenced on May 9, 1996. The principal undertakings of the Trust are to indirectly acquire and hold, through its direct and indirect subsidiary entities, interests in oil and natural gas properties and to distribute the net cash generated by such properties to its unitholders.

The Trust is managed by NAL Resources Management Limited (the "Manager"). The Manager is a wholly-owned subsidiary of Manulife Financial Corporation ("MFC") and manages, on their behalf, NAL Resources Limited ("NAL Resources"), another wholly-owned subsidiary of MFC. NAL Resources and the Trust maintain ownership interests in many of the same oil and natural gas properties and, in addition, MFC and the Trust jointly own a limited partnership that holds working interests in certain oil and gas properties. NAL Resources operates these properties on behalf of the Trust and MFC. As a result, a significant portion of the net operating revenues and capital expenditures represent joint operations amounts from NAL Resources. These transactions are in the normal course of joint operations and are based on the original exchange amounts established through transactions with third parties.

2. SUMMARY OF ACCOUNTING POLICIES

Basis of Presentation

The Trust's financial statements are stated in Canadian dollars and have been prepared by management in accordance with Generally Accepted Accounting Principles ("GAAP") in Canada and they include the accounts of the Trust and its subsidiary entities. All inter-entity transactions and balances have been eliminated.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimated. In particular, the amounts recorded for depletion and depreciation of property, plant and equipment and for the accretion of asset retirement obligations are based on estimates of reserves and future costs. The amounts recorded for unit-based compensation are based on quotes for the price of trust units and performance factors. The fair value estimates for commodity derivatives are based on expected future oil and natural gas prices and expected volatility in these prices while the fair value of interest rate derivatives are based on expected future interest rates. The amount recorded for goodwill is based on estimates of the fair value of identifiable assets and liabilities at the date of acquisition, and is subject to impairment testing which is based on estimates of reserves, future commodity prices, future costs, production profiles, discount rates and other relevant assumptions. The ceiling test calculation is based on estimates of reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. Future income taxes are based on estimates as to the timing of the reversal of temporary differences, and tax rates currently substantively enacted. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

Property, Plant and Equipment

The Trust follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of acquiring petroleum and natural gas properties and related development costs are capitalized and accumulated in one cost centre. Such costs include land acquisition, geological and geophysical expenditures, costs of drilling both productive and non-productive wells, related plant and production equipment costs and related overhead charges.

Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such sale would alter the depletion rate by 20 percent or more.

Depletion of petroleum and natural gas properties and depreciation of equipment is calculated using the unit of production method based on total proved reserves before royalties, as determined by independent petroleum engineers. Natural gas reserves are converted to barrels of oil equivalent based on relative energy content (6:1). The depletion base includes capitalized costs, plus future costs to be incurred in developing proved reserves and excludes the unimpaired cost of undeveloped land. Costs associated with undeveloped land are not subject to depletion and are assessed periodically to assess whether impairment has occurred. When proved reserves are assigned or the value of the unproved property is considered to be impaired, the cost of the undeveloped land or the amount of impairment is added to the costs subject to depletion.

Petroleum and natural gas properties are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre.

The carrying amount of petroleum and natural gas properties is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves plus the lower of cost and market of undeveloped land, exceeds the carrying amount. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, plus the lower of cost and market of undeveloped land. The cash flows are estimated using expected future commodity prices and costs and discounted using a risk-free rate.

Asset Retirement Obligations

The Trust recognizes the fair value of an asset retirement obligation in the period in which it is incurred, on a discounted basis, with a corresponding increase to the carrying amount of property, plant and equipment. The asset recorded is depleted on a unit of production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to income in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded.

Income Taxes

The Trust is a taxable entity under the Canadian Income Tax Act and until 2011 is taxable only on income that is not distributed or distributable to unitholders, provided that the Trust continues to adhere to the transition rules provided for under the Federal legislation. The Trust currently meets the criteria qualifying for income tax treatment permitting a tax deduction for distributions paid to the unitholders in addition to other deductions available in the Trust. Beginning in 2011, distributions paid to unitholders will not be deductible for tax and the Trust will be taxed on its income similar to corporations.

The Trust follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Trust's subsidiaries financial statements and their respective tax bases, using substantively enacted income tax rates. In addition, income tax liabilities and assets are recognized for the estimated tax consequences of temporary differences arising in the Trust that reverse after 2011. The effect of the change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs. 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.

Financial Instruments

A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument to another entity. Upon initial recognition, all financial instruments, including derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then dependent on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale or other liabilities. Cash and cash equivalents have been designated as held for trading which are measured at fair value. Accounts receivable and notes receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities, distributions payable, notes payable and bank debt are classified as other liabilities which are measured at amortized cost, which is determined using the effective interest method. The convertible debentures are classified as debt on the balance sheet with a portion of the proceeds allocated to equity. The debt component has been measured at amortized cost.

All derivative contracts are classified as held for trading and are recorded on the balance sheet at fair value, with changes in the fair value recognized in net income, unless specific hedge criteria are met. The Trust has entered into certain derivative contracts in order to reduce its exposure to market risks from fluctuations in commodity prices and interest rates. These instruments are not used for trading or speculative purposes. The Trust has not designated its derivative contracts as effective accounting hedges, even though the Trust considers all derivative contracts to be effective economic hedges. Therefore, changes in the fair value of the derivative contracts are recognized in net income for the period. Proceeds and costs realized from holding the derivative contracts are recognized in net income at the time each transaction under a contract is settled. The fair value of derivative contracts is based on an approximation of the amounts that would be received or paid to settle these instruments at the end of the period, with reference to forward prices.

The Trust will assess at each reporting period whether a financial asset is impaired. An impairment loss, if any, is included in net income.

Transaction costs are frequently attributed to the issue of a financial asset or liability. The Trust has selected a policy of netting all transaction costs with the related financial assets and liabilities, and recording its bank debt net of deferred interest payments. In accordance with this policy convertible debentures are presented net of issue costs and bank debt is presented net of deferred interest payments, with interest recognized in net income on an effective interest basis.

The Trust applies trade date accounting for the recognition of a purchase or sale of short term investments and derivative contracts.

The Trust measures and recognizes embedded derivatives separately from host contracts when the economic characteristics and risks of the embedded derivative are not closely related to those of the host contract, when it meets the definition of a derivative, and when the contract is not measured at fair value. Embedded derivatives are recorded at fair value.

Joint Operations

Substantially all development and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Trust's proportionate interests in such activities.

Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title passes to the purchaser.

Unit-Based Incentive Compensation

The Manager has established a unit-based incentive compensation plan (the "Plan") for all employees. Under the Plan, employees receive cash compensation based upon the value and overall return of a specified number of awarded notional trust units on a fixed vesting date. The notional trust unit grants are in the form of Restricted Trust Units ("RTUs") and Performance Trust Units ("PTU's"). Distributions paid on the Trust's outstanding trust units during the vesting period are assumed to be reinvested in the awarded notional trust units on the date of distribution. Compensation expense incorporates the trust unit price and the number of RTUs and PTU's outstanding at each period end. In addition, for the PTU's there is a performance multiplier which is based on the Trust's performance relative to its peers and may range from zero to two times the value of the notional trust units held at vesting.

Compensation expense is recognized over the vesting period and is determined based on the market price of the notional trust units at each period end and an expected performance multiplier with a corresponding increase or decrease in liabilities. Classification between current liabilities and long-term liabilities is dependent on the expected payout date.

The Trust charges the accrued compensation amounts relating to head office employees to general and administrative expenses, the amounts relating to field staff to operating costs, and the amounts relating to exploitation and development personnel to property, plant and equipment.

The Trust has not incorporated an estimated forfeiture rate for performance units that will not vest and accounts for actual forfeitures as they occur.

Basic and Diluted per Trust Unit Calculation

Basic net income per trust unit is calculated by dividing net income by the weighted average number of trust units outstanding. Diluted net income per unit is calculated using the if converted method to determine the dilutive effects of the convertible debentures. Dilutive trust units are arrived at by taking the weighted average trust units and the trust units issuable on conversion of the convertible debentures, giving effect to the potential dilution that would occur had conversion occurred at the beginning of the period or on issuance of the convertible instrument, whichever is later. Interest and accretion on convertible debentures is added back to net income in calculating diluted net income per unit.

Goodwill

Goodwill is recorded on a business acquisition when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired business. The goodwill balance is not amortized but, instead, is assessed for impairment annually at year-end, or more frequently if events or changes in circumstances indicate the asset might be impaired. To assess impairment, the fair value of the reporting entity, deemed to be the consolidated Trust, is compared to the carrying value of the reporting entity. If the fair value of the Trust is less than the carrying value, then a second test is performed to determine the amount of impairment. Any impairment is measured by allocating the fair value of the consolidated Trust to the identifiable assets and liabilities as if the Trust had been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value of the consolidated Trust over the amounts assigned to the identifiable assets and liabilities is the implied value of the goodwill. Any excess of the book value of goodwill over the implied value of goodwill is the impairment amount. Any impairment will be charged to net income in the period in which it occurs.

Comparative Information

Certain comparative figures have been reclassified to conform with current year presentation.

3. CHANGES IN ACCOUNTING POLICIES

New Accounting Standards

Effective January 1, 2008 the Trust implemented the provisions of CICA Handbook Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", and Section 3863 "Financial Instruments - Presentation".

Section 1535 establishes standards for disclosing information about an entity's capital and how it is managed. This Section specifies disclosure about objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with all capital requirements, and if it has not complied, the consequences of such non-compliance. Sections 3862 and 3863 establish standards for the presentation and disclosure of information that enable users to evaluate the significance of financial instruments to the entity's financial position, and the nature and extent of risks arising from financial instruments and how the entity manages those risks.

The implementation of these new standards did not impact the Trust's financial results but did, however, result in additional disclosures, as provided in Note 14.

Future Accounting Changes

Goodwill and Intangible Assets:

In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Section 3064 will be effective for the Trust on January 1, 2009. The Trust is currently evaluating the impact of adoption of this new section, however the impact is expected to be minimal.

Business Combinations:

In December 2008, the CICA issued Section 1582, "Business Combinations," replacing Section 1581. Section 1582 includes potentially significant changes to the measurement of purchase consideration in a business combination. Under Section 1582, the fair value ascribed to units issued as consideration will be based on their market value at the date of exchange, as compared to the current standard which prescribes market price for a reasonable period of time before and after the date of acquisition. In addition, the majority of acquisition costs will likely have to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. Section 1582 also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting date until settled. Currently, standards require only contingent liabilities that are payable to be recognized. Section 1582 also requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-currents assets in the purchase price allocation. Section 1582 will be effective for the Trust on January 1, 2011, with prospective application.

International Financial Reporting Standards ("IFRS"):

In February 2008, the CICA Accounting Standards Board ("AcSB"), confirmed that the changeover to IFRS from Canadian GAAP will be required for publicly accountable enterprises' interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010. The changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Trust's reported financial position and results of operations.

The International Accounting Standards Board ("IASB") has also issued an exposure draft relating to certain amendments and exemptions to IFRS 1 in order to make it more useful to Canadian entities adopting IFRS for the first time. One of the exemptions relating to full cost oil and gas accounting would reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment, if implemented, will permit the Trust to apply IFRS prospectively to its full cost pool, rather than the performing retrospective assessment of capitalized exploration and development expenses, with the provision that a ceiling test, under IFRS standards, be conducted at the transition date.

In response, the Trust has completed a high level IFRS changeover plan and established a preliminary timeline for the execution and completion of the conversion project. The changeover plan was determined following a preliminary assessment of the differences between Canadian GAAP and IFRS and the potential effects of IFRS to accounting and reporting processes, information systems, business processes and external disclosures. The plan addresses project structure and governance, resourcing and training, an initial impact assessment and establishes the key milestones that must be met to complete the conversion project. The Trust will also establish a Convergence Committee, made up of key Trust stakeholders, to begin the execution stage of the conversion project.

During the next phase of the project, due to take place during 2009, the Trust will perform an in-depth review of the significant areas of differences, in order to identify all specific Canadian GAAP and IFRS differences and select ongoing IFRS policies. Key areas addressed will also be reviewed to determine any information technology issues, the impact on internal controls over financial reporting and the impact on business activities including the effect, if any, on covenants and compensation arrangements.

The Trust will also continue to monitor standards development as issued by the IASB and the AcSB as well as regulatory developments as issued by the Canadian Securities Administrators which may affect the timing, nature or disclosure of its adoption of IFRS.

4. CORPORATE ACQUISITIONS

(1) Tiberius Exploration Inc. and Spear Exploration Inc.

Effective February 27, 2008 the Trust acquired all the issued and outstanding common shares of Tiberius Exploration Inc. ("Tiberius") and Spear Exploration Inc. ("Spear"), which have interests in southeast Saskatchewan.

On February 29, 2008, the Trust transferred the assets into a limited partnership (the "Partnership") in exchange for a 50 percent partnership interest and a note receivable of $3.7 million. A wholly-owned subsidiary of MFC acquired the remaining 50 percent share in the Partnership and a note receivable of $3.7 million, by payment in cash of one half of the total purchase price for Tiberius and Spear. Accordingly, the net acquisition cost to the Trust for its 50 percent share in the acquired properties was $57.8 million, before acquisition costs, comprised of $28.3 million in cash and $29.5 million from the issuance of 2.4 million trust units at a price of $12.24 per unit. The unit price was based on the weighted average market price of the units at the announcement date for the acquisition of February 11, 2008.

The Trust and MFC have entered into net profit interest royalty agreements ("NPI") with the Partnership. These agreements entitle each royalty holder to a 49.5 percent interest in the cash flow from the Partnership's reserves. In exchange for this interest the royalty holders each paid $49.6 million to the Partnership by way of promissory notes. The equivalent carrying amount of property, plant and equipment related to this interest in the reserves is recorded on the books of each royalty holder.

The results of operations from these properties have been included in the consolidated financial statements of the Trust commencing February 27, 2008. A subsidiary of the Trust is the general partner under the partnership agreement governing the Partnership and therefore controls the Partnership. As a result, the Trust is required to consolidate the results into its consolidated financial statements, with the share of net income and net assets attributable to MFC presented as a non-controlling interest.

The transaction was accounted for using the purchase method of accounting. The fair values assigned to the net assets, and the consideration paid by the Trust are as follows:



----------------------------------------------------------------------------
Net assets Total Disposition Trust, net Net to
acquired: Acquisition to Manulife Acquisition NPI(1) Trust
----------------------------------------------------------------------------
Cash $ 9,734 $ - $ 9,734 $ - $ 9,734
Working
capital
deficiency (5,622) - (5,622) - (5,622)
Notes
receivable,
net from
MFC - (3,750) (3,750) 49,599 45,849
Property,
plant and
equipment 111,258 - 111,258 (49,599) 61,659
Future
income
taxes (23,544) 11,588 (11,956) - (11,956)
Asset
retirement
obligations (1,636) - (1,636) - (1,636)
Goodwill 26,724 (12,002) 14,722 - 14,722
Non-controlling
interest - (54,057) (54,057) - (54,057)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 116,914 $ (58,221) $ 58,693 $ - $ 58,693
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Consideration:
----------------------------------------------------------------------------
Cash $ 86,118 $ (57,807) $ 28,311 $ - $ 28,311
Issuance of
trust units 29,496 - 29,496 - 29,496
Acquisition
costs 1,300 (414) 886 - 886
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 116,914 $ (58,221) $ 58,693 $ - $ 58,693
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net profits interest agreement entered into with MFC, in exchange for a
note receivable.
(2) Seneca Energy Canada Inc.


On August 31, 2007 the Trust acquired all the issued and outstanding shares of Seneca Energy Canada Inc. ("Seneca"), which has interests in oil and natural gas properties and undeveloped land in east central Alberta, northeast British Columbia and Saskatchewan. The results of operations from these properties have been included in the consolidated financial statements commencing September 1, 2007. The transaction was accounted for using the purchase method of accounting with the fair values assigned to net assets and consideration paid as follows:



----------------------------------------------------------------------------
Net assets acquired:
----------------------------------------------------------------------------
Working capital deficiency (including bank indebtedness of $718) $ (5,498)
Property, plant and equipment 263,473
Asset retirement obligations (12,625)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 245,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Consideration:
----------------------------------------------------------------------------
Cash $ 244,773
Acquisition costs 577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 245,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. RELATED PARTY TRANSACTIONS

The Trust is managed by the Manager. The Manager is a wholly-owned subsidiary of MFC and manages on their behalf NAL Resources, another wholly-owned subsidiary of Manulife.

The disposition of a 50 percent interest in the Partnership holding the Tiberius and Spear assets was to MFC, as outlined in Note 4.

The Manager provides certain services to the Trust pursuant to an administrative services and cost sharing agreement. This agreement requires the Trust to reimburse the Manager, at cost, for general and administrative ("G&A") expenses incurred by the Manager on behalf of the Trust. The Trust paid $2.8 million (2007 - $3.1 million) for the reimbursement of G&A expenses during the fourth quarter, and $12.4 million (2007 - $11.6 million) for 2008. The Trust also pays the Manager its share of unit-based compensation expense when cash compensation is paid to employees under the terms of the Plan. During 2008, $1.8 million was paid in the first quarter of 2008 relating to notional units that vested on November 30, 2007 (2007 - $2.2 million).

The notes payable to, and receivable from, MFC reside in the Partnership and are consolidated into the accounts of the Trust, due to the control relationship discussed in Note 4. The notes are due on demand, unsecured and bear interest at prime plus three percent with the loan receivable due to be settled by March 31, 2009. Net interest of $2.8 million relating to these notes was received by the Trust for the year ended December 31, 2008 and is reported as other income. The amount of the note payable to MFC is adjusted to reflect MFC's share of the capital expenditures of the Partnership which MFC has funded.

During 2008 the Partnership paid a distribution to its partners, MFC's share being $1.5 million, as shown in non-controlling interest (see Note 11).

The following amounts are due to and from related parties as at December 31, 2008 and have been included in accounts receivable, note receivable, accounts payable and accrued liabilities and note payable on the balance sheet:



2008 2007
----------------------------------------------------------------------------
Due (to) from NAL Resources Limited $ (10,042) $ 14,203
Due to NAL Resources Management Limited (3,881) (2,826)
Due from Manulife Financial Corporation(1) 45,512 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 31,589 $ 11,377
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Included on consolidation, eliminated through non-controlling interest.
Represents note receivable $49.6 million, less note payable $9.6
million, plus amounts due from MFC of $5.5 million, presented in
accounts receivable, relating to the net interest and NPI amounts due.


6. PROPERTY, PLANT AND EQUIPMENT

2008 2007
----------------------------------------------------------------------------
Petroleum and natural gas properties, at cost $ 1,909,524 $ 1,687,331
Less: Accumulated depletion and depreciation (892,337) (706,443)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 1,017,187 $ 980,888
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Costs associated with undeveloped land of $39.0 million (2007 - $30.1 million) have been excluded from the depletion calculation for the year ended December 31, 2008.

Future development costs for proved reserves of $46.3 million (2007 - $41.6 million) have been included in the depletion calculation.

During 2008, the Trust capitalized $4.3 million (2007 - $4.5 million) of G&A costs and $0.8 million (2007 - $0.9 million) of unit-based incentive compensation that were directly related to exploitation and development programs.

The Trust performed a ceiling test calculation at December 31, 2008 to assess the recoverable value of property, plant and equipment. The oil and gas future prices are based on the January 1, 2009 commodity price forecast of the Trust's independent reserve evaluators, adjusted for commodity differentials specific to the Trust. The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, the undiscounted value of net reserves from the Trust's proved reserves exceeded the carrying value of property, plant and equipment as at December 31, 2008.



WTI Oil US$/Cdn$ WTI Oil AECO Gas
Year (US$/bbl) Exchange Rate (Cdn$/bbl) (Cdn$/GJ)
----------------------------------------------------------------------------
2009 60.00 0.85 70.58 7.40
2010 71.40 0.85 83.99 8.00
2011 83.20 0.90 92.44 8.45
2012 90.20 0.95 94.94 8.80
2013 97.40 1.00 97.40 9.05
----------------------------------------------------------------------------

Remainder(1) 2% 1.00 2% 2%

(1) Percentage change represents the change in each year after 2013 to the
end of the reserve life.


7. BANK DEBT

2008 2007
----------------------------------------------------------------------------
Production loan facility $ 281,984 $ 273,528
Working capital facility 348 2,102
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt outstanding $ 282,332 $ 275,630
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Trust maintains a fully secured, extendible, revolving term credit facility with a syndicate of Canadian chartered banks. The facility consists of a $440 million production facility and a $10 million working capital facility. The total amount of the facility is determined by reference to a borrowing base. The borrowing base is calculated by the bank syndicate and is based on the net present value of the Trust's oil and gas reserves and other assets.

The credit facility is fully secured by first priority security interests in all existing and future acquired properties and assets of the Trust and its subsidiary and affiliated entities. The facility will revolve until April 29, 2009 at which time it may be extended for a further 364-day revolving period upon agreement between the Trust and the bank syndicate. If the credit facility is not extended in April 2009, the amounts outstanding at that time will be converted to a two-year term loan. The term loan will be payable in five equal quarterly installments commencing, April 30, 2010 concluding with a final residual payment in May 2011. As the available lending limits of the facility are based on the bank syndicate's interpretation of the Trust's reserves and future commodity prices there can be no assurance that the amount of available facility will not decrease at the next scheduled review on April 29, 2009.

The Trust is restricted under the credit facility from making distributions to its unitholders in excess of its consolidated operating cash flow during the 18 month period preceding the distribution date. The Trust is in compliance with this covenant.

Amounts are advanced under the credit facility in Canadian dollars by way of prime interest rate based loans and by issues of bankers' acceptances and in U.S. dollars by way of U.S. based interest rate and Libor based loans. The interest charged on advances is at the prevailing interest rate for bankers' acceptances, Libor loans, lenders' prime or U.S. base rates plus an applicable margin or stamping fee. The applicable margin or stamping fee, if any, varies based on the consolidated debt-to-cash flow ratio of the Trust. As at December 31, 2008 and 2007 all amounts outstanding were in Canadian dollars.

On December 31, 2008 the effective interest rate on amounts outstanding under the credit facility was 3.57 percent (2007 - 5.74 percent).

8. CONVERTIBLE DEBENTURES

On August 28, 2007 the Trust issued $100 million principal amount of 6.75 percent convertible extendible unsecured subordinated debentures, at a price of $1,000 per debenture. Interest on these debentures is paid semi-annually in arrears, on February 28 and August 31, and the debentures are convertible at the option of the holder at anytime into trust units at a conversion price of $14.00 per trust unit. The debentures mature on August 31, 2012 at which time they are due and payable. The debentures are redeemable by the Trust at a price of $1,050 per debenture on or after September 1, 2010 and on or before August 31, 2011, and at a price of $1,025 per debenture on or after September 1, 2011 and on or before August 31, 2012. On redemption or maturity the Trust may opt to satisfy its obligation to repay the principal by issuing trust units.

The debentures are classified as debt on the balance sheet with a portion of the proceeds allocated to equity, representing the value of the conversion feature. As the debentures are converted to trust units, a portion of the debt and equity amounts will be transferred to Unitholders' Capital. The debt component of the convertible debentures is carried net of issue costs of $4 million. The debt balance, net of issue costs, accretes over time to the principal amount owing on maturity. The accretion of the debt discount and the interest paid to debenture holders are expensed each period as part of the caption "interest and accretion on convertible debentures" in the consolidated statements of income.

The following table reconciles the principal amount, debt component and equity component of the convertible debentures.



Principal Debt Equity
amount of component of component of
debentures debentures debentures
----------------------------------------------------------------------------
August 28, 2007 issuance $ 100,000 $ 94,241 $ 5,759
Issue costs - (4,000) -
Accretion - 635 -
----------------------------------------------------------------------------
Balance, December 31, 2007 100,000 90,876 5,759
Conversion to trust units (20,256) (18,568) (1,167)
Accretion - 1,696 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, December 31, 2008 $ 79,744 $ 74,004 $ 4,592
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. UNIT-BASED INCENTIVE COMPENSATION PLAN

The Manager has a long term incentive plan under which employees receive cash compensation based upon the value and overall return of a specified number of awarded notional trust units on a fixed vesting date. The notional trust unit grants are in the form of Restricted Trust Units ("RTU's") and Performance Trust Units ("PTU's"). RTU's vest one third on November 30 in each of the three years after the date of grant. PTU's vest on November 30, three years after the date of grant.

The Trust recorded a total compensation expense of $2.6 million in 2008, of which $1.8 million was recorded as an expense and $0.8 million as property, plant and equipment ($2.1 million was expensed and $0.9 million recorded as property, plant and equipment for the year ended December 31, 2007). The compensation expense was based on the December 31, 2008 trust unit price of $8.05 (2007 - $11.60), accrued distributions, performance factors, and the number of units vesting on maturity.

The following table reconciles the change in total accrued trust unit-based incentive compensation relating to the plan:



2008 2007
----------------------------------------------------------------------------
Balance, beginning of year $ 4,996 $ 4,153
Increase in liability 2,573 3,027
Cash payout, relating to units vested (1,767) (2,184)
----------------------------------------------------------------------------
Balance, end of year $ 5,802 $ 4,996
----------------------------------------------------------------------------
Current portion of liability(1) $ 4,912 $ 3,248
----------------------------------------------------------------------------
Long-term liability $ 890 $ 1,748
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.


10. ASSET RETIRMENT OBLIGATIONS

The total future asset retirement obligation was estimated by the Manager based on the Trust's net ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. NAL has estimated the net present value of its asset retirement obligations to be $90.8 million as at December 31, 2008 (2007 - $89.6 million) based on a total undiscounted and inflated amount of cash flows required to settle its asset retirement obligations of $279.8 million (2007 - $276.0 million). These costs are expected to be made over the next 44 years with the majority of the costs incurred between 2009 and 2033. NAL's estimated credit-adjusted risk-free rate of eight to nine percent (2007 - eight percent) and an inflation rate of two percent (2007 - two percent) were used to calculate the present value of the asset retirement obligations.



The following table reconciles the Trust's asset retirement obligations.

2008 2007
----------------------------------------------------------------------------
Balance, beginning of year $ 89,602 $ 65,574
Accretion expense 7,299 5,533
Revisions to estimates (262) 10,294
Liabilities incurred 1,422 1,079
Liabilities acquired (Note 4) 1,636 12,625
Liabilities settled (8,853) (5,503)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of year $ 90,844 $ 89,602
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. NON-CONTROLLING INTEREST

The Trust has recorded a non-controlling interest in respect of the 50 percent ownership interest held by MFC in the Partnership holding the Tiberius and Spear assets (Note 4). The non-controlling interest on the balance sheet represents 50 percent of the net assets of the Partnership as follows:



2008 2007
----------------------------------------------------------------------------
Non-controlling interest, beginning of year $ - $ -
Non-controlling interest on acquisition (Note 4) 54,057 -
Net income attributable to non-controlling interest 3,823 -
Distributions to limited partner (Note 5) (1,500) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-controlling interest, end of year $ 56,380 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The non-controlling interest in the statement of income is comprised of:

Three months ended Years ended
December 31 December 31
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Net profits interest $ (453) $ - $ 6,618 $ -
Share of net income attributable to
MFC 1,716 - 3,823 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 1,263 $ - $ 10,441 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. UNITHOLDERS EQUITY

Unitholders' Capital

The Trust is authorized to issue 500 million trust units of which 96 million units were issued and outstanding as at December 31, 2008 (December 31, 2007 - 90 million). Each trust unit is transferable, carries the right to one vote and represents an equal undivided beneficial interest in any distributions from the Trust and in the assets of the Trust in the event of termination or winding up of the Trust. All trust units are of the same class with equal rights and privileges.

Redemption

Unitholders may redeem their trust units for cash at any time, up to an aggregate maximum value of $100,000 in any calendar month, by delivering their trust unit certificates to the Trustee, accompanied by a properly completed notice requesting redemption. The redemption amount per trust unit will be the lesser of 95 percent of the market price of the trust units on the principal market on which the trust units are quoted as trading during the ten-trading day period commencing immediately after the date on which the trust units are surrendered 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 date that the trust units are tendered for redemption.



Units Issued:

2008 2007
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of the year 90,494 $ 969,588 77,971 $ 824,986
Issued on corporate acquisitions
(Note 4) 2,409 29,496 10,246 125,001
Less issue expenses (29) (7,134)
Issued from Distribution
Reinvestment Plan 1,831 23,393 2,277 26,735
Issued on conversion of debentures 1,447 19,735 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of the year 96,181 $ 1,042,183 90,494 $ 969,588
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Distribution Reinvestment Plan

The Trust has in place a Distribution Reinvestment Plan ("DRIP") and a Premium Distribution Reinvestment Plan ("Premium DRIP"). The regular DRIP entitles unitholders to reinvest cash distributions or make optional cash payments to acquire trust units from treasury under the DRIP at 95 percent of the average market price with no additional fees or commissions. The average market price is the arithmetic average of the daily volume weighted average trading price of the trust units during a defined period before the distribution payment date.

The Premium DRIP component of the plan allows unitholders to exchange new trust units, acquired by reinvesting their cash distributions, for a cash payment from the plan broker equal to 102 percent of the monthly distribution on the applicable distribution payment date.

The trust units issued under the Premium DRIP component of the plan at a five percent discount to the average market price will be delivered to the plan broker in exchange for 102 percent of the cash distribution payable on the participant's existing trust units.

At certain times and at the discretion of management, the DRIP and Premium DRIP may be suspended. Currently both the DRIP and Premium DRIP are suspended.

Cash Distributions

The Trust is required to distribute all of its cash available for distribution each calendar month, in accordance with the terms of the Trust Indenture. The cash available for distribution is defined as all cash amounts received less all costs, expenses, liabilities or obligations of the Trust, plus net proceeds from the issuance of units, less any amounts the Trustee, upon recommendations of the Manager, considers it necessary to retain. The amount considered necessary to retain includes: any costs, expenses, liabilities or obligations which are reasonably expected to be incurred such as for property, plant and equipment; amounts required to be retained for repayment in order to comply with loan agreements; an allowance for contingencies, working capital, investments or acquisitions; or any amount appropriate to retain for a reserve to stabilize distributions. The Trust intends to continue to make cash distributions, however, these cash distributions cannot be guaranteed.



Distributions since the inception of the Trust are as follows:

Total
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2006 $ 702,480
2007 distributions 158,601
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2007 $ 861,081
2008 distributions 181,462
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2008 $ 1,042,543
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Per Unit Information

Basic net income per trust unit is calculated using the weighted average number of trust units outstanding. The calculation of diluted net income per trust unit includes the weighted average trust units potentially issuable on the conversion of the convertible debentures. For the three months and year ended December 31, 2008, an additional 5,696,013 and 6,341,206 trust units, respectively, were included in the diluted net income per trust unit calculation. Interest charges of $1.7 million for the quarter and $7.6 million year-to-date were included in the diluted net income per trust unit calculation as additions to net income. For the three months and year ended December 31, 2007, the impact of the conversion of the convertible debentures was anti-dilutive to the calculation of net income per unit. Total weighted average trust units issuable on conversion of the convertible debentures and excluded from the diluted net income per trust unit for the three months and year ended December 31, 2007 were 7,142,857 and 2,465,753, respectively. As at December 31, 2008, the total convertible debentures outstanding were immediately convertible to 5,696,000 trust units.

Deficit

The deficit is comprised of the following:



2008 2007
----------------------------------------------------------------------------
Accumulated income $ 553,031 $ 390,451
Accumulated cash distributions (1,042,543) (861,081)
----------------------------------------------------------------------------
Deficit, end of year $ (489,512) $ (470,630)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Trust has historically paid cash distributions in excess of accumulated income as cash distributions are based on cash flow generated in the period whereas accumulated income is based on net income which includes non-cash items such as depletion, depreciation, accretion, future income taxes and unrealized gains and losses on derivative contracts.



Accumulated Other Comprehensive Income

2008 2007
----------------------------------------------------------------------------
Balance, beginning of year $ - $ -
Fair value of derivative instruments on transition
to new accounting standards, net of tax of $1,349 - 3,172
Reclassification to net income in period, net of
tax $1,349 - (3,172)
----------------------------------------------------------------------------
Balance, end of year $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


13. INCOME TAXES

The provision for income taxes in the consolidated financial statements differs from the result that would have been obtained by applying the combined federal and provincial tax rate to income before taxes as follows:



2008 2007
----------------------------------------------------------------------------
Income before taxes $ 206,387 $ 52,837

Statutory income tax rate 29.5% 33.4%
Expected income tax expense 60,884 17,648

Increase (decrease) resulting from:
Valuation allowance (37) 32
Net income of the Trust (21,449) (24,831)
Rate variance (3,192) 1,159
Other (2,840) 2,414
Effect of future tax rate reductions - (42)
----------------------------------------------------------------------------
Current and future income tax provision
(reduction) $ 33,366 $ (3,620)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The future income tax asset (liability) is comprised of:

2008 2007
----------------------------------------------------------------------------
Property, plant and equipment $ (32,323) $ (3,768)
Future tax liability resulting from different year
ends (4,038) (2,570)
Non-capital tax loss carry forward 5,637 4,396
Asset retirement obligations 9,804 6,985
Derivative contracts (16,939) 2,472
Other 357 449
----------------------------------------------------------------------------
(37,502) 7,964
Valuation allowance (1,378) (1,266)
----------------------------------------------------------------------------
Future income tax asset (liability) $ (38,880) $ 6,698
----------------------------------------------------------------------------

Current asset (liability) $ (16,788) $ 2,602
Long-term asset (liability) $ (22,092) $ 4,096
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Trust has non-capital loss carry forwards of $22 million of which $11 million expire between 2009 and 2015, and $11 million expire between 2025 and 2028.

The Trust meets the criteria qualifying it for income tax treatment permitting a tax deduction for distributions paid to the unitholders, in addition to other deductions available in the Trust. From 2011, following the changes to the taxation of income trusts announced in 2006, the Trust will be taxed on its income similar to corporations. Accordingly, the Trust has measured future income tax assets and liabilities associated with this new tax. For 2008, and in total, the Trust has recognized $15.0 million of future income tax liability in the financial statements associated with this new tax ($10.0 million in the fourth quarter). It is expected that all remaining taxable temporary differences will reverse prior to January 1, 2011, the date the taxation changes take effect. The scheduling of the reversal of temporary differences is based on management's best estimates and current assumptions, which may change. At December 31, 2008, the book amounts of the Trust's assets and liabilities exceed the tax basis by $153.0 million (2007 - $213.5 million), of which $100.0 million has a zero percent tax rate applied.

14. FINANCIAL RISK MANAGEMENT

Overview

The Trust has exposure to the following risks from its use of financial instruments: credit risk, liquidity risk and market risk.

This note presents information about the Trust's exposure to each of the above risks, the Trust's objectives, policies and processes for measuring and managing risk, and the Trust's management of capital. Certain other quantitative disclosures are included throughout these financial statements.

The Board of Directors has the responsibility to understand the principal risks of the business and to achieve a proper balance between the risks incurred and the potential return to Unitholders. The Board of Directors have oversight for ensuring systems are in place which effectively monitor and manage those risks with a view to the long term viability of the Trust.

Credit risk

Credit risk is the risk of financial loss to the Trust if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Trust's receivables and note receivable. The Trust is managed by the Manager. The Manager is a wholly-owned subsidiary of MFC and manages on their behalf NAL Resources, another wholly-owned subsidiary of MFC. NAL Resources and the Trust maintain ownership interests in many of the same oil and natural gas properties in which NAL Resources is the operator. As a result, a significant portion of the Trust's net operating revenues represent joint operations from NAL Resources. Accordingly, accounts receivable include amounts due from NAL Resources for oil, natural gas and natural gas liquids sales. Oil and gas marketing is conducted by the Manager on behalf of the Trust and NAL Resources generally with large creditworthy purchasers, for which the Trust views the credit risk as low. Except as noted below, NAL Resources, and ultimately the Trust, have not historically experienced any collection issues with its oil and gas marketers. The Manager does not obtain collateral from oil and natural gas marketers.

Cash and cash equivalents, when outstanding, consist of cash bank balances and short-term deposits maturing in less than 90 days. Derivative contracts consist of commodity contracts denominated in U.S. or Canadian dollars for periods of up to two years and interest rate contracts for periods of up to five years. The Trust manages the credit exposure related to short-term investments and derivative contracts by dealing with established counter-parties with high credit ratings and monitors all investments, avoiding complex investment vehicles with higher risks such as asset backed commercial paper. All derivative contract counterparties are Canadian chartered banks in NAL's lending syndicate.

On July 22, 2008 SemCanada Crude Company ("SemCanada") filed application for creditor protection under the Companies' Creditors Arrangement Act in Canada. SemCanada marketed a portion of the Trust's oil, butane and condensate sales. It has been determined that the full amount due from SemCanada is unlikely to be received. Accordingly, the Trust has recorded a bad debt expense of $6.9 million to write off the entire amount due to the Trust. NAL continues to work with legal counsel to attempt to recover amounts due. Any future amounts received will be recorded to income. NAL continues to sell to SemCanada with cash received in advance of delivery.

NAL management has concluded that its existing credit policy is appropriate but has implemented more regular review of purchasers. The events for the SemCanada insolvency were not foreseen. However, management is currently reviewing all existing purchasers against its credit policy to ensure credit worthiness given the current market conditions.

The carrying amount of accounts receivable, derivatives and note receivable represents the maximum credit exposure.

The Trust does not have any receivable balances past due as at December 31, 2008.

Liquidity risk

Liquidity risk is the risk that the Trust will not be able to meet its financial obligations as they are due. The Trust manages liquidity by ensuring, as far as possible, that it will have sufficient liquidity under both normal and stressed conditions.

The Trust prepares annual capital expenditure budgets, which are regularly monitored and updated as necessary. As well, the Manager utilizes authorizations for expenditure on both operated and non-operated projects. Furthermore, the Manager operates a high percentage of the Trust's properties, which allows for significant control over future expenditures. To support the capital spending program, the Trust maintains a fully secured, extendible, revolving term credit facility, as outlined in Note 7.

The following are the contractual maturities of financial liabilities as at December 31, 2008.



Financial Liability less than 1 Year 1 - 2 Years 2 - 5 Years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 84,732
Distributions payable 15,389
Unit-based incentive
compensation(1) 890
Note payable 9,609
Derivative contracts 274
Bank debt, principal (May 2010) 169,399 112,933
Convertible debentures, principal 79,744
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total $ 109,730 $ 170,289 $ 192,951
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amount due within one year classified in accounts payable and accrued
liabilities.


Market risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Trust's net income or the value of financial instruments.

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Trust's oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and U.S. dollar. As at December 31, 2008, if the Canadian dollar had weakened $0.10 against the U.S. dollar, with all other variables held constant, net income would have been $0.2 million higher due to changes in the foreign exchange component of U.S. dollar denominated commodity contracts. An equal and opposite impact would have occurred to net income had the Canadian dollar improved $0.10 against the U.S. dollar.

The Trust had no material foreign exchange related derivative contracts in place as at, or during the year ended, December 31, 2008.

Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by not only the relationship between the Canadian and U.S. dollar, but also macroeconomic events that dictate the levels of supply and demand. The Trust has attempted to mitigate commodity price risk by entering into financial derivative contracts. The Trust's policy is to enter into commodity contracts to a maximum of 50 percent of forecasted, net of royalty, production volumes for a period of up to two years.

For 2009, NAL has the following commodity risk management contracts outstanding:



----------------------------------------------------------------------------
CRUDE OIL U.S.$ Contracts CDN$ Contracts
----------------------------------------------------------------------------
Swap (bbls) - 717,400
Swap (bbl/d) - 1,965
$/bbl - $ 98.26
Collars (bbls) 36,400 516,800
Collars (bbl/d) 100 1,416
$/bbl $ 110.00 - $154.96 $ 119.13 - $159.84
Total (bbls) - 1,234,200
Total (bbl/d) - 3,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
NATURAL GAS CDN$ Contracts
----------------------------------------------------------------------------
Swap (GJ) 4,352,000
Swap (GJ/d) 11,923
$/GJ $7.02
Collars (GJ) 2,510,000
Collars (GJ/d) 6,877
$/GJ $ 8.44 - $10.36
Total GJ 6,862,000
Total (GJ/d) 18,800
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For 2009, the Trust has outstanding contracts representing approximately 35 percent of the net liquids and natural gas production after royalties, assuming a royalty rate of 20 percent.

For 2010, the Trust has the following commodity risk management contracts outstanding:



----------------------------------------------------------------------------
CRUDE OIL CDN$ Contracts
----------------------------------------------------------------------------
Collars (bbls) 27,000
Collars (bbl/d) 74
$/bbl $ 66.00 - $80.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
NATURAL GAS CDN$ Contracts
----------------------------------------------------------------------------
Swap (GJ) 1,620,000
Swap (GJ/d) 4,438
$/GJ $6.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------


These contracts and the contracts that expired during the year ended December 31, 2008 resulted in settlement losses of $27.3 million (2007 - $2.4 million). The fair value of derivative contracts has been included on the balance sheet with changes in the fair value reported separately on the statement of income as unrealized gain (loss). As at December 31, 2008, if oil and natural gas liquids prices had been $1.00 per barrel lower and natural gas prices $0.10 per mcf lower, with all other variables held constant, net income for the period would have been $1.4 million higher, due to changes in the fair value of the derivative contracts. An equal and opposite effect would have occurred to net income had oil and natural gas liquids prices been $1.00 per barrel higher and natural gas $0.10 per mcf higher.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Trust is exposed to interest rate fluctuations on its bank debt, which bears a floating rate of interest. As at December 31, 2008, if interest rates had been one percentage point lower, with all other variables held constant, net income for the quarter would have been $0.5 million ($2.4 million for the year ended December 31, 2008) higher, due to lower interest expense. An equal and opposite impact would have occurred to net income had interest rates been one percentage point higher.

During the fourth quarter the Trust entered into two three-year interest rate swaps that expire in December 2011. The contracts have a combined notional debt amount of $39 million and require NAL to make fixed quarterly payments at an interest rate of 1.5864 percent. In exchange, the counterparties are required to pay the Trust a floating rate of interest based on the average rate for Canadian dollar bankers' acceptances. The Trust's interest charge includes this fixed interest rate component plus a standby fee, a stamping fee and the fee for renewal. The Trust's policy is to enter into interest rate swap contracts to fix the interest rate on 50 percent of outstanding bank debt for periods of up to five years.



NAL has the following interest rate swaps in place:

----------------------------------------------------------------------------
Amount Trust
(millions) Fixed Counterparty
INTEREST RATE Remaining Term (1) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating
to fixed Jan 2009 - Dec 2011 $39.0 1.5864% CAD-BA-CDOR (3 months)
Swaps-floating
to fixed (i) Jan 2009 - Jan 2013 $22.0 1.3850% CAD-BA-CDOR (3 months)
Swaps-floating
to fixed (i) Jan 2009 - Jan 2014 $22.0 1.5100% CAD-BA-CDOR (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(i) Entered into subsequent to year-end
(1) Notional debt amount


The fair value of the interest rate contracts has been included on the balance sheet with the changes in the fair value reported separately on the statement of income as unrealized gain/(loss), consistent with the treatment and presentation of commodity contracts. No realized amount for interest rate swaps has been recognized during 2008.

Fair Values

The carrying amount of the Trust's financial instruments, including accounts receivable, accounts payable and accrued liabilities, and distributions payable, approximate their fair value due to their short term to maturity.

The notes payable and receivable due to/from MFC, are due on demand and bear interest at prime plus three percent. As the notes bear interest at a floating market rate, the fair market value approximates the carrying amount.

The Trust's bank debt and cash bear interest at floating market rates and, accordingly, the fair market value approximates the carrying amount.

The fair value of the Trust's convertible debentures at December 31, 2008 was $67.8 million, based on a quoted and observable market value (2007 - $98.0 million).

Derivative contracts are recorded at fair value on the balance sheet as current or long-term, assets or liabilities, based on their fair values on a contract by contract basis. The fair value of commodity contracts is determined as the difference between the contracted prices and published forward curves (ranging from US$44.60 per barrel to US$60.94 per barrel for oil and $5.83 per GJ to $7.71 per GJ for natural gas) as of the balance sheet date, using the remaining contracted oil and natural gas volumes. The fair value of the interest rate swaps is determined by discounting the difference between the contracted interest rate and forward bankers' acceptances rates as of the balance sheet date, using the notional debt amount and outstanding term of the swap. The fair value of the derivative contracts is as follows:



2008 2007
----------------------------------------------------------------------------
Fair value of commodity contracts $ 65,680 $ (9,584)
Fair value of interest rate swaps (274) -
----------------------------------------------------------------------------
$ 65,406 $ (9,584)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


These contracts are presented on the balance sheet as short term / long
term, assets and liabilities as follows:

2008 2007
----------------------------------------------------------------------------
Long term unrealized loss on derivative contracts $ (274) $ -
----------------------------------------------------------------------------
Current unrealized gain on derivative contracts 65,680 3,389
Current unrealized loss on derivative contracts - (12,973)
----------------------------------------------------------------------------
Net current unrealized gain (loss) on derivative
contracts 65,680 (9,584)
----------------------------------------------------------------------------
Net fair value of derivative contracts $ 65,406 $ (9,584)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2008, the total fair value of derivative contracts was a net asset of $65.4 million (2007 - net liability of $9.6 million). The change in the fair value for year ended December 31, 2008 of $75.0 million has been recognized as an unrealized gain in the statement of income (2007 - $14.1 million loss).

The following table reconciles the movement in the fair value of the Trust's derivative contracts:



Three months ended Years ended
December 31 December 31
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Unrealized gain (loss), beginning of
period $ 8,786 $ (1,371) $ (9,584) $ -
Unrealized gain on adoption of new
accounting standards - - - 4,521
Unrealized gain (loss), end of
period 65,406 (9,584) 65,406 (9,584)
----------------------------------------------------------------------------
Unrealized gain (loss) for the
period 56,620 (8,213) 74,990 (14,105)
Realized gain (loss) in the period 16,531 (5,510) (27,317) (2,435)
Reclassification from other
comprehensive income - 874 - 4,521
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Gain (loss) on derivative contracts $ 73,151 $(12,849) $ 47,673 $(12,019)
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Capital Management

The Trust's policy is to maintain a strong and flexible capital base to ensure that distribution levels are sustainable, while at the same time providing the flexibility to take advantage of operational and acquisition opportunities.

The Trust manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying oil and natural gas assets. The Trust considers its capital structure to include Unitholders' Capital, bank debt, convertible debentures and working capital (excluding derivative contracts, notes with MFC and future income tax) as shown below. In order to maintain or adjust its capital structure, the Trust may adjust the amount of distributions paid to unitholders, issue new trust units, adjust its capital spending to modify debt levels, or suspend/resume its DRIP or Premium DRIP programs.

The Trust monitors its capital based on the ratio of its net debt to 12 months trailing funds from operations. This ratio, which is a non-GAAP measure, is calculated as net debt as a proportion of funds from operations for the previous 12 months. Funds from operations is defined as cash flow from operating activities prior to the change in non-cash working capital. Net debt is defined as bank debt, plus convertible debentures at face value, plus working capital (excluding derivative contracts, notes with MFC and future income tax balances). Net debt is measured with and without convertible debentures. The Trust's strategy is to maintain a conservative net debt to 12 month trailing funds from operations as compared to other oil and gas trusts, both before and after taking into account the convertible debentures. The Trust will, for the appropriate opportunity, increase its debt to funds from operations ratio above the Trust's average. In order to facilitate the management of this ratio, the Trust prepares an annual budget which is approved by the Board of Directors. On a monthly basis a reforecast for the year is prepared based on updated commodity prices, results of operational activity and other events. The monthly forecast is provided to the Board of Directors.

As at December 31, 2008, the Trust had a total net debt to 12 months trailing funds from operations ratio of 1.28, as calculated in the table below. At December 31, 2007, the Trust had a total net debt to 12 months trailing funds from operations ratio of 1.79, primarily attributable to borrowings incurred to fund the Seneca acquisition.

The credit facility is determined based on the reserves of the Trust (see Note 7) and is therefore commodity price sensitive. The Trust is restricted under its credit facility from making distributions to its unitholders in excess of its consolidated operating cash flow during the 18 month period preceding the distribution date. As at December 31, 2008 and 2007, the Trust was in full compliance with this external restriction on distributions.

The Trust has no restrictions on the issuance of units other than the authorized limit of 500 million.

Under the tax legislation regarding the change in the taxation of income trusts, the Trust has a grandfathering period to 2011, when the rules come into effect. The grandfathering period restricts "undue expansion" of the Trust by placing growth limits for issuances of equity and convertible debt, based on the market capitalization of the Trust on October 31, 2006, the date the announcement of the changes in the tax legislation. For 2009 and 2010, the Trust has approximately $1.11 billion of available safe harbour, all of which is currently available.

There has been no change in the approach to capital management during 2008.



Capitalization

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2008 2007
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Trust unit equity $ 557,263 $ 504,717

Bank debt 282,332 275,630
Working capital deficit(1) 36,712 15,429
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Net debt 319,044 291,059
Convertible debentures(2) 79,744 100,000
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Total net debt(2) $ 398,788 $ 391,059

Cash flow from operating activities for last 12
months $ 320,042 $ 215,364
Add back change in non-cash working capital (8,971) 3,381
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Trailing 12 months funds from operations $ 311,071 $ 218,745

Net debt to trailing 12 month funds from
operations(3) 1.03 1.33
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Total net debt to trailing 12-month funds from
operations(4) 1.28 1.79
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(1) Working capital excludes derivative contracts, future income taxes and
the notes receivable/payable with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt excluding convertible debentures divided by funds
from operations for the previous 12 months.
(4) Calculated as total debt divided by funds from operations for the
previous 12 months.


15. COMMITMENTS

At December 31, 2008 the Trust had the following contractual obligations and
commitments:

2009 2010 2011 2012 2013
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Office lease(1) $ 4,145 $ 3,799 $ - $ - $ -
Transportation agreement 1,673 1,673 589 - -
Processing agreement(2) 446 428 414 401 384
Convertible debentures(3) - - - 79,744 -
Bank debt - 169,399 112,933 - -
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Total $ 6,264 $175,299 $ 113,936 $ 80,145 $ 384
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(1) Represents the full amount of office lease commitments and both base
rent and operating costs, in relation to the lease held by the Manager
of which the Trust is allocated a pro rata share (currently
approximately 58 percent) of the expense on a monthly basis.
(2) Represents gas processing agreement under take or pay arrangement.
(3) Principal amount.


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TRADING PERFORMANCE

For the Quarter Ended Full Year
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31-Dec-08 30-Sept-08 31-Dec-07 30-Sept-07 2008 2007
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PRICE
High $ 13.14 $ 17.10 $ 12.90 $ 13.65 $ 17.10 $ 13.80
Low $ 5.90 $ 11.50 $ 10.94 $ 11.52 $ 5.90 $ 10.86
Close $ 8.05 $ 12.53 $ 11.60 $ 12.22 $ 8.05 $ 11.60
Daily Average
Volume 475,410 380,141 291,677 284,893 406,602 269,937
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NAL Oil & Gas Trust provides investors with a yield-oriented opportunity to participate in the Canadian Upstream Conventional Oil and Gas Industry. The Trust generates monthly cash distributions for its Unitholders by pursuing a strategy of acquiring, developing, producing and selling crude oil, natural gas and natural gas liquids from pools in southeastern Saskatchewan, central Alberta, northeastern British Columbia and Lake Erie, Ontario. Trust units trade on the Toronto Stock Exchange under the symbol "NAE.UN".

Contact Information