NAL Oil & Gas Trust
TSX : NAE.UN

NAL Oil & Gas Trust

February 28, 2008 16:37 ET

NAL Reports Strong 2007 Performance and Reserves Additions

CALGARY, ALBERTA--(Marketwire - Feb. 28, 2008) - 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, 2007 as well as 2007 year end reserves. All amounts are in Canadian dollars unless otherwise stated.

HIGHLIGHTS

NAL was successful in achieving all of its key performance objectives for 2007. The Trust delivered strong operating and financial performance, added opportunities, improved reserves replacement, lowered finding and development costs, completed a strategic acquisition, and maintained financial flexibility.

2007 Operating and Financial Performance

- The $245.7 million acquisition of Seneca Energy Canada Inc. ("Seneca") in September, 2007 added natural gas production in NAL's East Central Alberta core area, a significant amount of undeveloped acreage in West Central Alberta, and opened up a new opportunity area at Monkman, B.C. The Trust added new geological and geophysical leadership and retained Seneca's experienced technical team who will continue to focus on new opportunities.

- Fourth quarter 2007 production volumes averaged 23,413 boe/d, equally weighted between liquids and natural gas. Volume performance set a new record for NAL, reflecting the first full quarter of Seneca production. 2007 full year production averaged 20,501 boe/d, on track with guidance. Excluding the volumes acquired with Seneca, production averaged 19,037 boe/d, exceeding the 18,500 - 19,000 boe/d guidance that the Trust provided in January, 2007.

- Crude oil prices, expressed in US$WTI, increased significantly during 2007 but those increases were partly offset by lower natural gas prices and the strengthening of the Canadian dollar. NAL's realized price was relatively flat year over year at $54.88 per boe. The Trust's royalty rate was essentially unchanged at 21.7 percent in 2007 and higher costs related to Seneca volumes led to operating costs being slightly higher than guidance at $9.34 per boe. Overall operating netbacks before hedging gains or losses were flat at $34.57 per boe in 2007 versus $34.59 per boe in 2006.

- Revenue and funds from operations were largely unchanged in 2007. Funds flow from operations per unit decreased by eight percent to $2.65 per unit, compared to $2.88 per unit in 2006. This decrease reflects the issue of 2.3 million units under the DRIP program during the year, and 10.2 million units that were issued to finance a portion of the purchase of Seneca, effective September 1, 2007. On a weighted average basis, units outstanding were 82.6 million in 2007, compared to 76.4 million units in 2006, an increase of eight percent. NAL maintained distributions of $0.16 per month for a total of $1.92 per unit in 2007, representing a lower payout ratio of 73 percent versus 77 percent in 2006.

- Excluding acquisitions, capital spending totaled $118.0 million in 2007, down slightly from $123.0 million in 2006. Of the $118.0 million, $111.3 million was spent on exploration and development which was comprised of $95.3 million in drilling, completions and tie-ins, with $10.0 million spent on facilities and $6.0 million on land and seismic, with significant focus on oil core areas of Southeast Saskatchewan.

- The Trust's $245.7 million acquisition of Seneca was financed with $125.0 million in new equity and $100.0 million in the form of convertible debentures, with the balance funded through bank debt. Net bank debt, excluding the debentures, totaled $291.0 million at year end representing a multiple of 1.1 times NAL's base case cash flow for 2008. The Trust had $400.0 million in committed bank lines at year end, resulting in over $100.0 million in unused borrowing capacity.

- NAL increased its inventory of undeveloped land by nearly 100,000 net acres in 2007. After expirees, the undeveloped land at December 31, 2007 totaled 304,479 net acres, an increase of 48 percent from 205,916 net acres at December 31, 2006.

- As to risk management, the Trust continues with its strategy to layer in forward sale positions to protect cash flows, capital programs and distributions. For 2008, the Trust has hedged 37 percent of its forecast oil production (47 percent of net production after royalty) through swaps and collars. Currently, the Trust's swap positions average $87.40 in contracted U.S. dollars and $87.10 in contracted Canadian dollars with collars being $74.93 - $83.58 in U.S dollars and $80.53 - $88.73 contracted in Canadian dollars. In natural gas, current hedges represent 30 percent (38 percent of net production after royalty), 90 percent with swaps averaging Cdn$7.38 per GJ and 10 percent with collars with a Cdn$7.98 per GJ floor and $9.57 ceiling.

- NAL continued to build tax pool balances in 2007, finishing the year with a total of $697.8 million, up 41 percent from $494.0 million at year end 2006. Tax pools are forecast to grow while NAL remains a trust, allowing it to shelter a portion of its future income from taxation after 2010.

2007 RESERVES ADDED / FINDING AND DEVELOPMENT COSTS

- NAL improved its reserves added performance significantly during 2007. Year end proved plus probable reserves increased 17.2 percent from 58.2 million boe at year end 2006 to 68.2 million boe at the end of 2007 due to the Seneca acquisition and performance of our core areas. Overall, the Trust replaced 234 percent of its production. Excluding acquisitions, the replacement of production through discoveries, extensions, infill drilling, well recompletions and technical revisions increased from 25 percent in 2006 to 96 percent in 2007.

- At year end 2007, NAL's total reserves base continues to be relatively conservative with a high percentage of proved to total proved plus probable reserves (73 percent) with the proved producing reserves representing 95 percent of the total proved category. The reserves mix remains relatively consistent with NAL's current production at 41 percent crude oil, 10 percent natural gas liquids and 49 percent natural gas.

- The Trust delivered solid finding and development costs performance in 2007 with $13.99 per boe proved and $17.71 per boe proved plus probable, including changes in future development costs, representing a proved plus probable recycle ratio of 1.95 times. Including the effects of acquisitions, the finding, development and acquisition costs were $23.20 per boe proved and $21.67 on a proved plus probable basis.

- At the end of 2007, NAL's reserve life index was 8.2 years, remaining relatively consistent with the historical range of 8.0 to 8.6 years over the past five years.

- On a per unit basis, proved plus probable reserves per unit increased from 0.747 boe at the end of 2006 to 0.754 boe at the end of 2007.

OUTLOOK FOR 2008

- On January 23, 2008, NAL provided guidance for full year 2008 with production volumes and funds from operations forecast to be higher than in 2007. The capital program will be consistent with 2007 spending levels while rig and service costs are expected to be lower. NAL has increased its inventory of opportunities significantly by adding new prospecting capability, broadening opportunities and extensions in our core areas, and working through the new prospects acquired in the Seneca acquisition. NAL expects to be able to maintain distributions assuming current commodity prices, and has an active hedging program which has locked in average prices above our base case forecast. The Trust's debt to cash flow ratios are expected to improve in 2008, and NAL has over $100.0 million of available committed bank lines to take advantage of opportunities which continue to be available.

2008 Guidance



-------------------------------------------------------------
Average total production (boe per day) 23,000 - 24,000
Capital expenditures ($ millions) 110 - 120
Operating costs ($/boe) 9.50 - 9.80
G&A ($/boe) 1.90 - 2.10
-------------------------------------------------------------


SUBSEQUENT EVENTS

- NAL participated in three significant exploratory wells during 2007 and early 2008. Two of those wells are expected to be onstream early in the second quarter of 2008. The Trust has a 19 percent working interest in an Upper Devonian natural gas discovery at Peppers 16-16 in West Central Alberta. The well is expected to produce at an initial rate of 10.0 MMcf/d of raw gas or 8.0 MMcf/d sales gas, representing approximately 250 boe/d net to NAL, subject to gathering and plant capacity constraints. Monkman a-26-E, in Northeast B.C., encountered two productive sheets in the Permian Belcourt formation. The lower sheet tested 30 MMcf/d of raw gas and the upper sheet tested 35 MMcf/d. NAL has a 20 percent working interest in the well. The operator is still evaluating pressure data to determine if it is possible to commingle production from the two sheets. NAL has forecast this well to be onstream at approximately 27 MMcf/d raw or 22 MMcf/d sales gas, representing 700 boe/d net to NAL. Testing operations at a third well are still ongoing at Monkman b-44-B where NAL has an 8.55 percent working interest. A fourth exploratory well was spudded at Monkman a-31-K early in 2008, and it will be evaluated later in the year. Following a vertical pooling agreement with Talisman Energy, NAL has a 10 percent working interest.

- The Trust closed two private company acquisitions and one asset purchase by February 27, 2008, all with interests in Southeast Saskatchewan, for a total purchase price of approximately $64.4 million net to the Trust. These transactions will add 2.1 million boe of proved plus probable reserves in close proximity to existing fields at Alida and Steelman/Elswick. For 2008, these acquisitions are expected to add approximately 700 boe/d of production on an annualized basis with an additional $5 million in capital expenditures. NAL's strategic partner, Manulife Financial Corporation, participated equally in these acquisitions, demonstrating the value of our strategic partnership and their continued interest in adding investments in the oil and gas sector. These 'tuck-in acquisitions' add to the Trust's cornerstone presence in Southeast Saskatchewan, and position NAL for further reserves additions as well as infrastructure and cost synergies.

SUMMARY

"2007 was the beginning of NAL's transition to become a dividend paying corporation by 2011. We turned in very strong operating and financial results in 2007, exceeding the guidance that was set out early in the year, concluding a significant acquisition, adding land, opportunities and capability, and achieving much improved F&D costs," said Andrew Wiswell, President and Chief Executive Officer. "We have positive momentum heading into 2008 supported by a well defined operating plan, a growing opportunity base, a strong financial position and a motivated team committed to delivering for our unitholders."

FORWARD-LOOKING INFORMATION

Please refer to our 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.

NON-GAAP MEASURES

Please refer to our 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 28, 2008, NAL will hold a conference call to discuss the fourth quarter and 2007 year end 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 by webcast at http://events.onlinebroadcasting.com/nal/022808/index.php

A recorded playback of the call will be available until March 6, 2008 by calling 1-800-408-3053, reservation 3252987.



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


SENSITIVITY ANALYSIS

In our January 23, 2008 press release outlining 2008 guidance, NAL provided a base and sensitivity case based upon different commodity price scenarios. We have updated the scenarios including production from the recent acquisition announced in February 2008 and adjusted the gas and exchange rate in the Sensitivity case.




Key Assumptions
----------------------------------------------------------------------
Base Case Sensitivity Case
----------------------------------------------------------------------
Production (boe/d) 24,000 24,000
WTI Oil Price (US$/bbl) 80.00 90.00
AECO Natural Gas Price
(C$/GJ) 6.50 7.50
Exchange Rate (Cdn/USD) 1.00 1.00
----------------------------------------------------------------------


2008 Pro Forma Financial Results
----------------------------------------------------------------------
Base Case(i) Sensitivity Case(i)
----------------------------------------------------------------------
Funds from Operations
($MM) 267 298
Funds from Operations
($ per unit) $2.85 $3.18
Weighted average Units
Outstanding (MM) 93.7 93.7
Debt / Cash Flow 1.2 / 1.6(i)(i) 1.0 / 1.3(i)(i)
----------------------------------------------------------------------

(i)Includes realized hedging gains (losses)
(i)(i)Including convertible debentures


Impact on Annual Funds from Operations(i)
----------------------------------------------------------------------
Assumptions Change Amount (000s) Per Unit
----------------------------------------------------------------------
Commodity Prices
WTI oil (US$/bbl) $1.00 $3,000 $0.03
AECO natural gas (Cdn$/GJ) $0.10 $2,300 $0.02
----------------------------------------------------------------------

Volume Changes
Oil 100 bbl/d $1,800 $0.02
Natural gas 1,000 mcf/d $1,600 $0.02
----------------------------------------------------------------------
Rates
Exchange Rate - Cdn$/US$ $0.01 $2,400 $0.03
Interest Rate - Bank
prime lending rate 1% $2,900 $0.03
----------------------------------------------------------------------

(i)Compared to base case



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

Three Months Ended Years Ended December 31
---------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
FINANCIAL
Gross revenue, net of
royalties $86,262 $75,358 $319,334 $310,416
Cash flow from operating
activities 45,111 48,678 215,364 238,445
Cash flow per unit - basic 0.50 0.63 2.61 3.12
Cash flow per unit -
diluted 0.48 0.63 2.56 3.12
Funds from operations 59,537 55,795 218,745 219,776
Funds from operations per
Unit - basic 0.66 0.72 2.65 2.88
Funds from operations per
Unit - diluted 0.63 0.72 2.60 2.88

Net income 10,556 20,472 56,457 60,198
Distributions declared 43,340 39,663 158,601 169,589
Distributions per unit 0.48 0.51 1.92 2.22
Payout ratio:
based on cash flow from
operating activities 96% 81% 74% 71%
based on funds from
operations 73% 71% 73% 77%
Units outstanding (000's)
December 31 90,494 77,971 90,494 77,971
Weighted average 90,194 77,697 82,556 76,350
Capital expenditures 39,194 34,788 119,434 124,042
Corporate acquisitions - - 245,687 -
Net debt(1) 291,059 223,061 291,059 223,061
Convertible debentures
(at face value) 100,000 - 100,000 -


OPERATING
Daily production
Crude Oil (bbl/d) 9,633 9,700 9,305 9,367
Natural gas (mcf/d) 70,120 47,153 54,773 48,804
Natural gas liquids (bbl/d) 2,094 1,958 2,067 1,944
Oil equivalent (boe/d) 23,413 19,517 20,501 19,444


COST STRUCTURE
Costs per boe
Revenue before hedging
gains (losses) 56.48 49.78 54.88 53.97
Royalties (12.08) (10.36) (11.91) (11.79)
Operating costs (10.00) (7.13) (9.34) (8.31)
Other income 1.20 1.20 0.94 0.72
-------------------------------------------------------------------------
Operating netback before
hedging gains (losses) 35.60 33.49 34.57 34.59
Hedging gains (losses) (2.56) 1.00 (0.33) 0.48
-------------------------------------------------------------------------
Operating netback 33.04 34.49 34.24 35.07
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excluding convertible debentures


OIL AND GAS RESERVES

NAL's 2007 year end reserves were evaluated by McDaniel & Associates Consultants Ltd. ("McDaniels"), independent engineering consultants in Calgary, in accordance with National Instrument ("NI") 51-101. At December 31, 2007, the Trust's proved reserves totaled 49.6 million barrels of oil equivalent ("boe") and proved plus probable ("P+P") reserves amounted to 68.2 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 2007 reserves summary are:

- The acquisition of Seneca Energy Canada Inc. ("Seneca"), effective September 1, 2007, along with some minor property acquisitions in Alberta, added 10,262 Mboe of P+P reserves to the Trust.

- Additions for improved recovery, which includes discoveries, extensions, infill drilling and well recompletions, amounted to 3,502 Mboe of proved and 4,981 Mboe of P+P reserves. This represents new reserves added for development activity, over and above volumes that were previously booked in the reserves report. These reserves additions occurred across all of our core areas, with the larger ones resulting from successful drilling results in the Alida, Midale, Elswick and Steelman areas in Saskatchewan, the Garrington, Westward Ho and Pine Creek areas in Alberta, as well as the new core property at Sukunka in British Columbia.

- Overall technical revisions amounted to 5,630 Mboe for proved and 2,238 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 recharacterization of reserves from probable to proved to reflect increased levels of certainty.

- The total P+P reserves additions for improved recovery and technical revisions of 7,219 Mboe represents a 96 percent replacement ratio of the 2007 production of 7,483 Mboe. Including acquisitions, the Trust's total reserves replacement ratio for 2007 was 234 percent.

- At December 31, 2007, over 95 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, leading to a high degree of confidence in exceeding our booked proved reserves.

- Using the P+P reserves of 68,212 Mboe and the number of outstanding trust units at December 31, 2007 of 90,494,151, the P+P reserves at year end 2007 amounted to 0.754 boe per unit. This represents a slight increase from 0.747 boe per unit at year end 2006.

The following tables summarize NAL's estimated reserves volumes and values using McDaniels price forecasts as of January 1, 2008. 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 Light and Medium Oil category includes a small amount of reserves classified as "heavy oil" (approximately 20(o) API) under NI 51-101 guidelines. These reserves represent approximately two percent of the Total Proved plus Probable oil reserves and, as such, are not considered material in terms of separate reporting. Similarly, 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.



Numbers may not add exactly due to rounding.

-------------------------------------------------------------------
Summary of Oil and Gas Reserves
As at December 31, 2007
Forecast Prices and Costs
-------------------------------------------------------------------
Reserves
Light and Medium Oil Natural Gas
Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (MMcf) (MMcf)
-------------------------------------------------------------------

Proved
Developed Producing 19,616 17,174 138,075 116,702
Developed Non-Producing 199 173 3,580 2,898
Undeveloped 595 547 4,691 3,965
------------------------------------------
Total Proved 20,410 17,894 146,347 123,565
Probable 7,242 6,354 56,244 46,553
------------------------------------------
Total Proved Plus Probable 27,652 24,248 202,590 170,118
-------------------------------------------------------------------


-------------------------------------------------------------------
Reserves
Natural Gas Liquids Total BOE (6:1)
Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (Mbbl) (Mbbl)
-------------------------------------------------------------------
Proved
Developed Producing 4,629 3,388 47,258 40,012
Developed Non-Producing 104 73 900 730
Undeveloped 83 60 1,459 1,268
------------------------------------------
Total Proved 4,816 3,522 49,618 42,010
Probable 1,979 1,428 18,595 15,540
------------------------------------------
Total Proved Plus Probable 6,795 4,949 68,212 57,550
-------------------------------------------------------------------


--------------------------------------------------------------------------
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 1,487 1,181 988 856
Developed Non-Producing 28 21 17 14
Undeveloped 32 24 18 14
------------------------------------------------
Total Proved 1,547 1,226 1,023 88
Probable 639 382 259 190
------------------------------------------------
Total Proved Plus Probable 2,186 1,608 1,282 1,075
--------------------------------------------------------------------------


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.

A sensitivity case of the reserves evaluation was done to incorporate the impact of the proposed new royalty regime in Alberta. The result of that analysis, done using McDaniel's published price forecasts of January 1, 2008, shows an increase to the Trust's NPV due to the net benefit of reduced royalties on shallow gas wells which more than offsets any increased royalties on deeper wells. The before tax NPV discounted at 10 percent for the proved plus probable case increases from $1,282 million to $1,286 million under the proposed new royalty regime.



--------------------------------------------------------------------------
Summary of Pricing and Inflation Rate Assumptions
As at December 31, 2007
Forecast Prices and Costs
--------------------------------------------------------------------------
Oil

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

2008 90.00 89.00 78.20 6.80
2009 86.70 85.70 75.30 7.38
2010 83.20 82.20 72.20 7.38
2011 79.60 78.50 69.00 7.38
2012 78.50 77.40 68.00 7.49
2013 77.30 76.20 66.90 7.70
Thereafter(i) +2%/yr +2%/yr +2%/yr +3%/r
--------------------------------------------------------------------------


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

2008 61.60 2.0 1.000
2009 60.20 2.0 1.000
2010 58.00 2.0 1.000
2011 55.80 2.0 1.000
2012 55.20 2.0 1.000
2013 54.70 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, 2006 18,291 26,494 109,580 152,626

Improved Recovery(i) 1,731 1,947 8,575 15,059
Technical Revisions 2,542 894 13,568 4,886
Acquisitions 1,242 1,714 34,616 50,011
Dispositions 0 0 0 0
Production (3,396) (3,396) (19,992) (19,992)

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


--------------------------------------------------------------
Natural Gas Liquids Total BOE
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (Mbbl) (Mbbl) (Mboe) (Mboe)
--------------------------------------------------------------
December 31, 2006 4,250 6,282 40,804 58,214

Improved Recovery(i) 342 524 3,502 4,981
Technical Revisions 827 530 5,630 2,238
Acquisitions 152 213 7,164 10,262
Dispositions 0 0 0 0
Production (754) (754) (7,483) (7,483)

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

(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 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 $107.96 million used in the F&D calculation for 2007 represents the Trust's total expenditures for drilling, completion and production equipment, plant and facility costs (including maintenance capital items that supported our base production volumes and helped maintain our 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 2007 is not included in the F&D calculation, as it is included in the FD&A calculation in the section which follows.

The F&D costs for 2007, as shown in the table below, were $13.99 per boe for proved and $17.71 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 2005 through 2007 are $17.87 per boe for proved and $24.89 per boe for P+P reserves.



------------------------------------------------------------------------
2007
------------------------------------------------------------------------
Change in
Estimated
Actual Future
Spending Development
During 2007 Costs Total
------------- ----------- ---------

Capital (M$) Proved 107,961 10,458 118,419
Proved + Probable 107,961 7,486 115,447
------------------------------------------------------------------------

Improved Technical
Recovery Revisions Total
---------- ----------- ---------

Reserves (Mboe) Proved 3,053 5,415 8,467
Proved + Probable 4,120 2,400 6,519
------------------------------------------------------------------------

F&D ($/boe) Proved $13.99
Proved + Probable $17.71
------------------------------------------------------------------------


------------------------------------------------------------------------
3-YEAR WEIGHTED AVERAGE
------------------------------------------------------------------------
Change in
Estimated
Actual Future
Spending Development
Over 3 years Costs Total
------------- ----------- ---------

Capital (M$) Proved 280,952 (10,614) 270,338
Proved + Probable 280,952 12,434 293,386
------------------------------------------------------------------------

Improved Technical
Recovery Revisions Total
---------- ----------- ---------
Reserves (Mboe) Proved 4,996 10,131 15,126
Proved + Probable 9,211 2,579 11,789
------------------------------------------------------------------------

F&D ($/boe) Proved $17.87
Proved + Probable $24.89
------------------------------------------------------------------------


Some reporting issuers report F&D costs excluding changes in future development capital ("FDC"). Although not NAL's usual practice, we will provide the numbers on that basis for comparison purposes. Excluding changes in FDC, the Trust's F&D costs for 2007 would be $12.75 per boe for proved and $16.56 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, our F&D costs for 2007 would use $102.6 million of capital spending in the F&D calculation, resulting in $12.12 per boe for proved and $15.74 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, we report Finding, Development and Acquisition ("FD&A") costs, which include the effects of acquisitions and dispositions.

During 2007, the Trust completed the acquisition of Seneca, along with some minor property acquisitions in Alberta. 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 acquisitions and disposition activities completed during the year, as shown in the table below.

The FD&A costs for 2007 were $23.20 per boe for proved and $21.67 per boe for P+P reserves. The weighted average FD&A costs for the three-year period from 2005 through 2007 were $21.79 per boe for proved and $19.24 per boe for P+P reserves. These three year averages provide an appropriate measure of the Trust's overall capital spending effectiveness.



2007
--------------------------------------------------------------------------
Change in
Actual Estimated
Spending Future Total
During Development Acquis- Dispos- Including
2007 Costs itions itions A&D
--------- ----------- -------- -------- ----------

Capital (M$) Proved 116,714 14,303 247,110 0 378,127
Proved +
Probable 116,714 15,070 247,110 0 378,894
--------------------------------------------------------------------------

Total
Improved Technical Acquis- Dispos- Including
Recovery Revisions itions itions A&D
--------- ----------- -------- -------- ----------

Reserves
(Mboe) Proved 3,502 5,631 7,164 0 16,297
Proved +
Probable 4,981 2,238 10,262 0 17,481
--------------------------------------------------------------------------

FD&A ($/boe) Proved $23.20
Proved +
Probable $21.67
--------------------------------------------------------------------------



3-YEAR WEIGHTED AVERAGE
--------------------------------------------------------------------------

Change in
Actual Estimated
Spending Future Total
Over Development Acquis- Dispos- Including
3 Years Costs itions itions A&D
--------- ----------- -------- -------- ----------
Capital (M$) Proved 310,166 24,851 634,707 (3,504) 966,220
Proved +
Probable 310,166 62,362 634,707 (3,504) 1,003,73
--------------------------------------------------------------------------

Total
Improved Technical Acquis- Dispos- Including
Recovery Revisions itions itions A&D
--------- ----------- -------- -------- ----------

Reserves
(Mboe) Proved 5,445 9,756 29,241 (104) 44,338
Proved +
Probable 10,072 2,638 39,586 (126) 52,170
--------------------------------------------------------------------------

FD&A ($/boe) Proved $21.79
Proved +
Probable $19.24
--------------------------------------------------------------------------


RESERVE LIFE INDEX

Reserve Life Index ("RLI") is calculated by dividing reserves at December 31, 2007 by expected annual production for 2008. 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 McDaniels reserves report, the average production forecasted for 2008 in the P+P reserves case is 22,910 boe/d. This number is slightly below NAL's published guidance range of 23,000 to 24,000 boe/d because the McDaniels report does not incorporate all of NAL's proposed capital projects for 2008 or the related production uplift expected. For consistency, the RLI calculation should be based on the reserves at December 31, 2007 and the forecasted annual production for 2008 from the reserves report. Using those numbers, NAL's RLI at December 31, 2007 was 8.2 years for P+P, down slightly from 8.5 years at year end 2006.

LAND AND SEISMIC

At December 31, 2007, NAL owned an average 36.0 percent working interest in 845,232 gross acres (304,479 net acres) of undeveloped land. Most of NAL's land is owned in partnership with Manulife Financial Corporation, which results in NAL operating over 80 percent of its production and prospective acreage. Based on an internal estimate and using market benchmarks, NAL's undeveloped land and seismic value is approximately $83.8 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, 2007 December 31, 2006
------------------------------------------------------------------------
($000s, except per unit data) Using Forecast Using Forecast
Prices(4) Prices(5)
------------------------------------------------------------------------

Proved plus probable reserves
(before tax, discounted at 10%) 1,282,473 1,017,713
Undeveloped land and seismic(1) 83,758 47,800
Working capital (deficiency)(2) (15,429) (2,276)
Long-term debt (368,254) (221,790)
Asset retirement obligation(3) (55,986) (34,191)

Net asset value 926,562 807,256

Units outstanding (000s) 90,494 77,971
NAV per unit $10.24 $10.35
------------------------------------------------------------------------

(1) Internal estimate.
(2) Working capital deficiency excludes, the fair value of derivative
contracts and future income tax asset.
(3) 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 balance on the year end balance sheets, $89.6 million for
2007 and $65.6 million for 2006, when discounted at 10 percent, result
in a total discounted ARO of $75.1 million and $54.0 million, at the
respective balance sheet dates. These balances are further reduced by
$19.1 million and $19.8 million, respectively, relating to abandonment
costs included in the reserve value.
(4) McDaniels price forecasts as of January 1, 2008.
(5) McDaniels price forecasts as of January 1, 2007.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis ("MD&A") should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2007 and December 31, 2006 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, 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 and financial position. 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 is 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 and future income tax balances.

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



----------------------------------------------------------------------------
Three months ended December 31 Years ended December 31
-------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flow from
Operating activities 45,111 48,678 215,364 238,445
Add back change in non-cash
working capital 14,426 7,117 3,381 (18,669)
----------------------------------------------------------------------------
Funds from operations 59,537 55,795 218,745 219,776
----------------------------------------------------------------------------
----------------------------------------------------------------------------



FORWARD-LOOKING INFORMATION

This discussion and analysis contains forward-looking information as to the Trust's internal projections, expectations or 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", "potential", "target", and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that are reserves and resources 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, 2008 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; the amount of future asset retirement obligations; future liquidity and future financial capacity; future results from operations; 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, 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 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 risk 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; imprecision of reserve estimates; limited, unfavorable or no access to capital markets; the impact of competitors; the lack of availability of qualified operating or management personnel; 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 the royalty rates, particularly in light of the Alberta government's review; changes in tax laws; the impact of the new SIFT legislation following the October 31, 2006 announcement 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 and MD&A for the year ended December 31, 2007.

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, and the Trust does not assume any obligation to publicly update or revise it to reflect new events or circumstances except as required by law. The forward-looking information contained in the MD&A is expressly qualified by this cautionary statement.

ACQUISITION OF SENECA ENERGY CANADA INC. ("Seneca")

NAL successfully closed the acquisition of Seneca on August 31, 2007 for a price of $245.7 million including costs of $0.6 million. The acquisition added 10.3 million boe of P+P reserves and production averaging 4,400 boe/d from September 2007 to year end 2007. This production is weighted 85 percent to natural gas. The transaction also added 157,287 acres of net undeveloped land and growth opportunities to the Trust.

The net cash consideration was financed by the issuance of 10.2 million units at a price of $12.20 per trust unit for proceeds of $125 million ($117.9 million net of issue costs), $100 million in 6.75% convertible extendible unsecured subordinated debentures ($96 million net of issue costs), and $31.8 million of bank debt.

EXPLORATION & DEVELOPMENT ACTIVITIES

The Trust spent $31.0 million on drilling operations during the fourth quarter of 2007, versus $25.6 million a year earlier. For the full year, NAL spent $95.3 million on drilling versus $87.9 million in 2006, plus another $10.0 million on plant and facilities construction, and $6.0 million on land and seismic data acquisition.

The Trust participated in the drilling of 45 (18.06 net) wells during the fourth quarter of 2007, and 126 gross (49.8 net) wells during the year, compared to 191 gross (87.6 net) in 2006. Drilling for shallow gas in Lake Erie and the Lacombe, Alberta areas was deferred due to low natural gas prices.

Historically, NAL's assets have been concentrated in Southeast Saskatchewan and Central Alberta, while the purchase of Seneca in 2007 added a new core area at Monkman in Northeast B.C. These areas are accessible year-round and are well serviced by both production infrastructure and oilfield services.



Fourth Quarter Drilling Activity

Crude Oil Natural Gas
-----------------------------
Gross Net Gross Net
-----------------------------------------------------------------
Operated wells 21 9.43 8 6.15
Non-operated wells 7 0.09 9 2.39
-----------------------------------------------------------------
Total wells drilled 28 9.52 17 8.54
-----------------------------------------------------------------


Service Wells Dry & Abandoned Total
----------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Operated wells - - - - 29 15.58
Non-operated wells - - - - 16 2.48
--------------------------------------------------------------------
Total wells drilled - - - - 45 18.06
--------------------------------------------------------------------


2007 Full Year Drilling Activity

Crude Oil Natural Gas
-----------------------------
Gross Net Gross Net
-----------------------------------------------------------------
Operated wells 64 29.50 20 14.40
Non-operated wells 16 1.55 26 4.35
-----------------------------------------------------------------
Total wells drilled 80 31.05 46 18.75
-----------------------------------------------------------------


Service Wells Dry & Abandoned Total
----------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Operated wells - - - - 84 43.90
Non-operated wells - - - - 42 5.90
--------------------------------------------------------------------
Total wells drilled - - - - 126 49.80
--------------------------------------------------------------------


Southeast Saskatchewan

NAL drilled 46 wells in Southeast Saskatchewan in 2007, testing new exploration play concepts and adding over 2,000 boe/d of production net to the Trust. Five of those wells were drilled to test the Bakken formation in the Viewfield area, and results exceeded expectations. NAL was also active in land acquisition, purchasing 31,013 gross acres (15,531 net) of undeveloped land, including a block of 23,040 gross (11,520 net) acres of contiguous land in the Hoffer area.

Central, Alberta

Through the purchase of Seneca, NAL added significant new land holdings adjacent to its properties in the Brent, Hanna and Provost areas. During the year, the Trust completed a number of cost-efficient recompletion projects in the Drumheller area delivering attractive returns and capital efficiency. The Trust now produces 2,050 boe/d in the Drumheller area.

Sylvan Lake, Alberta

NAL completed a successful turnaround of its Sylvan Lake gas plant in 2007 with minimal impact on production volumes. Immediately south of Sylvan Lake in the Garrington and Westward Ho areas, the Trust enjoyed success from the drilling of both crude oil and natural gas wells in the Mannville formation. A total of 17 wells were recompleted in the Glauconite, Cardium and Edmonton horizons.

Pine Creek, Alberta

NAL enjoyed continued success drilling infill wells in the Cardium formation in the Pine Creek area of West Central Alberta. The Trust participated in a deep, Devonian exploration well late in the year, and that well is expected to be put on-stream as a natural gas producer at the beginning of the second quarter of 2008.

Monkman, B.C.

Through the purchase of Seneca, NAL added a large block of contiguous land in the Monkman area of Northeast B.C. There were already three natural gas wells on the property producing a combined 12.2 million cubic feet of gas or 2,040 boe/d net to the Trust. During the year NAL participated in the drilling of two additional deep tests, at 20 percent and 8.5 percent working interests respectively, both of which were being evaluated at year end. In December, 2007, NAL bought interests in an additional 6,782 gross (796 net) hectares of exploratory acreage at the provincial Crown sale.

CAPITAL EXPENDITURES

Capital expenditures for the quarter ended December 31, 2007 totaled $39.2 million compared with $34.8 million for the quarter ended December 31, 2006. For the year ended December 31, 2007 capital expenditures totaled $119.4 million as compared to $124.0 million for the same period in 2006. Included in capital expenditures is $8.7 million relating to the Seneca properties for 2007.



Capital Expenditures ($000s)

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------

Drilling, completion and
production equipment 30,971 25,619 95,327 87,901
Plant and facilities 3,308 4,715 9,988 14,598
Seismic 149 404 708 2,628
Land 2,545 2,243 5,330 7,730
----------------------------------------------------------------
Total exploitation and
development 36,973 32,981 111,353 112,857
----------------------------------------------------------------

Office equipment 792 772 1,297 4,080
Capitalized G&A 999 1,290 4,486 4,275
Capitalized unit-based
compensation 430 (295) 875 1,659
----------------------------------------------------------------
Total other capital 2,221 1,767 6,658 10,014
----------------------------------------------------------------

Property acquisitions
(dispositions), net - 40 1,423 1,171
----------------------------------------------------------------
Total capitalized
expenditures 39,194 34,788 119,434 124,042
----------------------------------------------------------------
----------------------------------------------------------------


PRODUCTION

Fourth quarter 2007 production of 23,413 boe/d (19,023 boe/d excluding Seneca) exceeded production of 19,517 boe/d in the comparable period of 2006 by 20 percent. The increase is mainly attributable to Seneca production of 4,390 boe/d. The average production for December was 23,365 boe/d, which includes 4,246 boe/d related to Seneca.

For the year ended December 31, 2007, production of 20,501 boe/d (19,037 boe/d excluding Seneca) exceeded production in the comparable period of 2006 of 19,444 boe/d. During 2007, NAL did not experience any shut-in due to Enbridge capacity constraints although trucking volume has increased.



Average Daily Production Volumes

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------

Oil (bbl/d) 9,633 9,700 9,305 9,367
Natural gas (Mcf/d) 70,120 47,153 54,773 48,804
NGL's (bbl/d) 2,094 1,958 2,067 1,944
Oil equivalent (boe/d) 23,413 19,517 20,501 19,444
----------------------------------------------------------------
----------------------------------------------------------------


Oil and natural gas liquids totaled 50 percent of production in the fourth quarter with natural gas increasing to 50 percent due to the Seneca acquisition.



Production Weighting

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Oil 41% 50% 45% 48%
Natural gas 50% 40% 45% 42%
NGL's 9% 10% 10% 10%
----------------------------------------------------------------
----------------------------------------------------------------


REVENUE

Gross revenue from oil, natural gas and natural gas liquids sales, after transportation costs, totaled $121.7 million for the three months ended December 31, 2007, 36 percent higher than the fourth quarter of 2006. The increase in revenue is attributable to a 20 percent increase in production and a 13 percent increase in the average price per boe.

Compared to the fourth quarter of 2006, average commodity prices increased by 13 percent due to higher crude oil and natural gas liquids prices.

For the year ended December 31, 2007 gross revenue totaled $410.6 million, an increase of seven percent from the comparable period in 2006. This increase is attributable to a five percent increase in production and a two percent increase in NAL oil equivalent pricing.



Revenue

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------

Revenue(1) ($000s) 121,651 89,374 410,647 383,077
$/boe 56.48 49.78 54.88 53.97
----------------------------------------------------------------
----------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation 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 quality of crude oil at each field battery. The refiners' posted prices are influenced by the West Texas Intermediate ("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 Canadian crude oil price per barrel, net of transportation costs, was $79.43, as compared to $58.53 for the comparable quarter of 2006. The increase in realized price quarter over quarter of 36 percent, or $20.90/bbl, was primarily driven by a 51 percent increase in WTI (US$/bbl), over the comparable period (US$90.62 versus US$60.21), offset by a strengthening Canadian dollar. In addition, NAL's crude differentials compared to WTI priced in Canadian dollars increased realized prices.

For the fourth quarter of 2007, NAL's realized oil price was 89 percent of WTI in Canadian dollars, an increase of four percent from the 85 percent for the corresponding period in 2006. The increase in the fourth quarter of 2007 resulted from a narrower differential between WTI and Edmonton and Cromer posted prices, due to greater demand for light crude in Western Canada in that time frame.

For the year ended December 31, 2007 similar trends were experienced. NAL's average oil price was $70.79/bbl compared to $65.30/bbl for 2006. The eight percent increase in realized price, year over year, was driven by a nine percent increase in WTI (US$72.30 versus US$66.22), a four percent increase in differentials, offset by a five percent decrease in the exchange rate.

For the year ended December 31, 2007 NAL's realized oil price was 91 percent of WTI in Canadian dollars as compared to 87 percent in 2006.

Natural gas liquids averaged $58.52/bbl in the fourth quarter of 2007, a 35 percent increase from $43.24/bbl realized in 2006. For the year ended December 31, 2007, natural gas liquids pricing averaged $50.82/bbl, four percent higher than 2006.

NATURAL GAS MARKETING

Approximately 77 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 23 percent tied to NYMEX or other indexed reference prices.

Lake Erie production accounted for seven percent of the Trust's natural gas production in 2007, compared to eight percent in 2006. For the fourth quarter of 2007, five percent of natural gas was produced from Lake Erie; the decrease attributable to the gas weighted Seneca acquisition.

For the three months ended December 31, 2007, the Trust's natural gas sales averaged $6.20/mcf compared to $6.96/mcf in the comparable period of 2006, a decrease of 11 percent. The quarter over quarter decrease in gas prices was attributable to an 11 percent decrease in the benchmark AECO prices. Natural gas prices from the Lake Erie property averaged $7.37/mcf in the fourth quarter of 2007 compared to $8.16/mcf in 2006, a decrease of 10 percent.

For the year ended December 31, 2007, NAL averaged $6.60/mcf, compared to $7.03/mcf in 2006, a decrease of six percent. The decrease is attributable to a two percent decrease in the benchmark daily AECO prices and to marketing a portion of gas based on the monthly AECO, which decreased five percent year over year. During 2007, the spread between the spot and the monthly AECO prices was $0.17/mcf compared to $0.42/mcf for 2006.



Average Pricing
(net of transportation charges)

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------

Liquids
WTI (US$/bbl) 90.62 60.21 72.30 66.22
NAL average oil (Cdn$/bbl) 79.43 58.53 70.79 65.30
NAL natural gas liquids
(Cdn$/bbl) 58.52 43.24 50.82 48.70

Natural Gas (Cdn$/Mcf)
AECO - daily spot 6.15 6.90 6.44 6.56
AECO - monthly 6.00 6.36 6.61 6.98
NAL Western Canada natural gas 6.13 6.84 6.47 6.98
NAL Lake Erie natural gas 7.37 8.16 7.90 8.09
NAL average natural gas 6.20 6.96 6.60 7.03

NAL Oil Equivalent before
hedging (Cdn$/boe - 6:1) 56.48 49.78 54.88 53.97
Average Foreign Exchange
Rate (Cdn$/US$) 0.9807 1.139 1.0738 1.134
----------------------------------------------------------------
----------------------------------------------------------------


RISK MANAGEMENT

NAL employs risk management practices to assist in managing cash flows and to support capital programs and distributions. NAL's management is authorized to hedge up to 50 percent of its annual net of royalty production. NAL's risk management programs are scaled in over time using a combination of swaps and collars. During 2007, NAL had several financial WTI oil contracts and AECO natural gas contracts in place.

The following is a summary of the realized gains and losses on risk management contracts for the quarter and year:



----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------

Average crude volumes
hedged (bbl/d) 3,966 4,263 3,106 3,244
Crude oil realized
gain (loss) ($000's) (7,756) 1,170 (7,132) 1,158
Gain (loss) per bbl
hedged (21.26) 2.98 (6.29) 0.98

Average natural gas
volumes hedged (GJ/d) 19,978 7,304 16,633 3,337
Natural gas realized
gain ($000's) 2,246 628 4,697 2,217
Gain per GJ hedged 1.22 0.94 0.77 1.82

Average BOE hedged
(boe/d) 7,122 5,417 5,733 3,771
Total realized gain
(loss) ($000's) (5,510) 1,798 (2,435) 3,375
Gain (loss) per boe
hedged (8.41) 3.61 (1.16) 2.45
Gain (loss) per boe (2.56) 1.00 (0.33) 0.48
----------------------------------------------------------------
----------------------------------------------------------------


The Trust has recorded the fair value of risk management contracts on the balance sheet effective January 1, 2007 in accordance with new accounting standards, issued by the Canadian Institute of Chartered Accountants ("CICA"), addressing financial instruments and hedges. These standards require all derivative instruments to be 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 not designated any of its derivative contracts as effective accounting hedges, even though the Trust considers all commodity contracts to be effective economic hedges. Therefore, changes in the fair value of the derivative contracts are recognized in net income for the period.

The gain on derivative contracts presented in the statement of income includes realized gains and losses, unrealized gains and losses since January 1, 2007, and a reclassification from other comprehensive income. The realized gain/loss represents actual cash settlements or receipts under the respective contracts. The unrealized gain/loss represents the change in the fair value of the contracts during the period. The reclassification from other comprehensive income represents the amortization of the fair value of the contracts on transition to the new accounting standards, over the term of the contracts. On January 1, 2007, the fair value of the outstanding contracts of $4.5 million was recorded as an asset with the offset being recorded in accumulated other comprehensive income, a component of unitholders' equity. The amount recorded in accumulated other comprehensive income was reclassified to net income over the term of the respective contracts. During 2007, the full amount of $4.5 million has been reclassified to net income, of which $0.9 million was reclassified in the fourth quarter of 2007.

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.

The fair value of the derivatives at December 31, 2007 was a liability of $9.6 million. The fair value of the liability of $9.6 million at December 31, 2007 was comprised of a $13.0 million liability on oil contracts offset by a $3.4 million asset on gas contracts.

Fourth quarter income of 2007 includes an $8.2 million unrealized loss on derivatives resulting from the change in the fair value of the derivative contracts during the quarter from a liability of $1.4 million at September 30, 2007 to a liability of $9.6 million at December 31, 2007. The $8.2 million unrealized loss was comprised of a $2.4 million unrealized loss on natural gas contracts, and a $5.8 million unrealized loss on crude oil contracts. The unrealized loss in the fourth quarter is primarily attributable to stronger crude oil forward prices compared to September 30, 2007 and an increase in derivative instruments held.

For the year ended December 31, 2007, income includes a $14.1 million unrealized loss resulting from the change in the fair value of the derivative contracts during the year. The unrealized loss was comprised of a $15.7 million loss on oil contracts, offset by a $1.6 million gain on gas contracts.

The gain/loss on derivative contracts for the quarter is as follows:



Gain (loss) on Derivative Contracts ($000's)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Unrealized gain (loss)
Crude oil contracts (5,789) - (15,709) -
Natural gas contracts (2,424) - 1,604 -
----------------------------------------------------------------
Unrealized loss (8,213) - (14,105) -
Realized gain (loss) (5,510) 1,798 (2,435) 3,375
Reclassification from
other comprehensive
income 874 - 4,521 -
----------------------------------------------------------------
Gain (loss) on
derivative contracts (12,849) 1,798 (12,019) 3,375
----------------------------------------------------------------
----------------------------------------------------------------

For 2008, NAL has the following risk management contracts outstanding:

-------------------------------------------------------------------------
CRUDE OIL US$ CDN$
-------------------------------------------------------------------------
Swap (bbls) 418,800 668,000
Swap (bbl/d) 1,144 1,825
$/bbl $87.40 $87.10
Collars (bbls) 407,800 122,000
Collars (bbl/d) 1,114 333
$/bbl $74.93 - $83.58 $80.53 - $88.73
Total (bbls) 826,600 790,000
Total (bbl/d) 2,258 2,158
-------------------------------------------------------------------------
-------------------------------------------------------------------------

---------------------------------------------------------
NATURAL GAS CDN$
---------------------------------------------------------
Swap (GJ) 7,434,500
Swap (GJ/d) 20,313
$/GJ 7.38
Collars (GJ) 882,000
Collars (GJ/d) 2,410
$/GJ $7.98 - $9.57
Total GJ 8,316,500
Total (GJ/d) 22,723
---------------------------------------------------------
---------------------------------------------------------


For 2009, NAL currently has AECO natural gas swap contracts in place for 810,000 GJ or 2,219 GJ/d at an average price of $7.36, and collars for 630,000 GJ or 1,726 GJ/d at average prices of $7.61 - $9.01. In addition, WTI oil swap contracts are in place for 127,600 bbls or 350 bbls/d at Cdn$96.89 and 54,600 bbls or 150 bbls/d at US$96.92. In addition, the Trust has WTI crude oil collar contracts in place for 54,600 bbls or 150 bbls/d at average prices of US$92.66 - $101.17.

ROYALTY EXPENSES

Crown, freehold and overriding royalties were $26.0 million for the three months ended December 31, 2007. Expressed as a percentage of gross sales, net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 21.4 percent for the quarter ended December 31, 2007, up slightly from 20.8 percent experienced in the comparable period the previous year.

For the year ended December 31, 2007, royalties were $89.1 million, up from $83.7 million in 2006. Expressed as a percentage of gross sales, net of transportation costs, before gain/loss on derivative contracts, the royalty rate is consistent year over year at 21.7 percent for 2007 as compared to 21.8 percent in the prior year.

On October 25, 2007, Premier Stelmach announced the new royalty regime for Alberta, effective January 2009. This new framework will affect NAL in that conventional oil and gas royalties will now be on a sliding scale that is determined by commodity price and productivity. Natural gas royalties will increase from a cap of 35 percent to 50 percent, with rate caps at $16.59/GJ. Crude oil royalty rates will increase from the current maximum of 35 percent to 50 percent, with rate caps raised to $120/bbl.

The Trust has assessed the impact of these new royalties on its production and the impact is minimal to the Trust, given the low level of crude oil production in Alberta and a significant weighting towards low producing gas wells. For the year ended December 31, 2007, 24 percent of crude oil and 80 percent of natural gas production is from Alberta.



Royalty Expenses
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Net royalties ($000s) 26,013 18,594 89,139 83,668
As % of revenue 21.4 20.8 21.7 21.8
$/boe 12.08 10.36 11.91 11.79
----------------------------------------------------------------
----------------------------------------------------------------


OPERATING COSTS

For the quarter ended December 31, 2007, operating costs averaged $10.00 per boe a 40 percent increase from the $7.13 per boe for the quarter ended December 31, 2006. On a comparative basis, the fourth quarter of 2006 was lower than expected as it includes several downward adjustments for the activity from earlier in 2006 where actual costs were less than estimated.

The Trust assumed full responsibility for the Seneca properties in September and has since undertaken significant operating cost related projects, some of which had been deferred during the sales process. These activities include turnarounds, pipeline replacements, pump changes and corrosion inhibition programs, which contributed towards higher fourth quarter operating costs.

Full year 2007 operating costs increased 12 percent to $9.34 per boe from $8.31 per boe in 2006. The Seneca properties contributed an incremental $0.08 per boe in overall operating costs for 2007. In addition, approximately $0.17 per boe is attributed to third party processing fees relating to prior periods. The remaining cost increase was a direct result of significant labour, third party processing fee and property tax increases which had been included in our forecasts. For 2008, operating costs are expected to average $9.50 to $9.80 per boe.



Operating Costs

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Operating costs ($000s) 21,537 12,796 69,916 58,964
As a % of revenue 17.7 14.3 17.0 15.4
$/boe 10.00 7.13 9.34 8.31
----------------------------------------------------------------
----------------------------------------------------------------


OPERATING NETBACK

For the quarter ended December 31, 2007, NAL's operating netback, before hedging gains (losses), was $35.60 per boe, an increase of six percent from $33.49 for the quarter ended December 31, 2006. A 13 percent increase in average realized prices was offset by increased royalties and operating costs in the fourth quarter of 2007.

For the year ended December 31, 2007, the operating netback, before hedging gains (losses), was $34.57 per boe, comparable with 2006. The increase in realized prices, year over year, of $0.91 per boe was offset by a $1.03 per boe increase in operating costs.



Operating Netback ($/boe)

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Revenue 56.48 49.78 54.88 53.97
Royalties, net (12.08) (10.36) (11.91) (11.79)
Operating expenses (10.00) (7.13) (9.34) (8.31)
Other income 1.20 1.20 0.94 0.72
-------------------------------------
Operating netback, before
hedging 35.60 33.49 34.57 34.59
Hedging gains (losses) (2.56) 1.00 (0.33) 0.48
-------------------------------------
Operating netback, after
hedging 33.04 34.49 34.24 35.07
----------------------------------------------------------------
----------------------------------------------------------------


GENERAL AND ADMINISTRATIVE EXPENSES

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

For the three months ended December 31, 2007, G&A expenses were $4.1 million, compared with $2.4 million in the comparable quarter of 2006. In addition, $1.0 million of G&A costs relating to exploitation and development activities were capitalized in the fourth quarter of 2007 compared with $1.3 million in the fourth quarter of 2006.

For the year ended December 31, 2007, total G&A has increased 24 percent to $18.9 million from $15.2 million. In 2007, $4.5 million of G&A costs relating to exploitation and development activities were capitalized, compared with $4.3 million in 2006. G&A expenses increased to $14.4 million in 2007 compared with $10.9 million in 2006.

Total G&A increased $3.7 million year over year due to increased compensation costs associated with hiring, compensating and retaining staff. Included in G&A expenses in 2007 is a retention bonus of $1.0 million associated with an employee retention program established at year end 2006. This represents a $0.13 per boe charge in 2007. G&A excluding the retention bonus and unit-based compensation was $1.79 per boe, on the lower end our full year guidance of $1.75 - $1.95 per boe.



General and Administrative Expenses

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
G&A expenses ($000s)
G&A 4,039 2,395 13,435 10,946
Retention bonus 57 - 969 -
----------------------------------------------------------------
Expensed G&A ($000s) 4,096 2,395 14,404 10,946
Capitalized G&A ($000s) 999 1,290 4,486 4,275
----------------------------------------------------------------
Total G&A ($000s) 5,095 3,685 18,890 15,221

Expensed G&A costs:
G&A, excluding retention
bonus ($/boe) 1.87 1.33 1.79 1.54
Retention bonus ($/boe) 0.03 0.13
----------------------------------------------------------------
Total G&A expenses ($/boe) 1.90 1.33 1.92 1.54
As % of revenue 3.4 2.6 3.5 2.8
Per trust unit ($) 0.05 0.03 0.17 0.14
----------------------------------------------------------------
----------------------------------------------------------------


UNIT-BASED INCENTIVE COMPENSATION PLAN

The employees of NAL Resources Management Limited (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 grant date. PTUs vest on November 30, three years after 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 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 2007, the Trust accrued $1.5 million of unit based incentive compensation charges as compared to a $0.4 million recovery in the comparable quarter of 2006. The fourth quarter recovery of unit based compensation in 2006 is a reflection of a significant drop in unit price that occurred following the Federal government's announcement, on October 31, 2006, of their intentions to tax income trusts.

On a year to date basis, the Trust has accrued $3.0 million compared to $4.2 million in the comparable period in 2006. The reduction in unit based compensation in 2007 is a reflection of a decrease in the unit price and a decrease in the performance factors attached to the PTUs. These reductions have resulted in the reversal of amounts accrued prior to December 31, 2006 for units vesting in 2007 and 2008.

This calculation is made at the end of each quarter based on the quarter end trust unit price and 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 over time.

At December 31, 2007, the Trust has recorded a liability for unit based incentive compensation in the amount of $5.0 million, of which $1.7 million was paid in January 2008. The remaining balance represents the Trust's estimated liability for the unit based incentive plan as at December 31, 2007, of which $1.5 million is recorded as current as it is payable by December 2008, and $1.7 million is long-term as it is payable by December 2009.



Unit-Based Compensation

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 1,080 (131) 2,152 2,495
Capitalized ($000s) 430 (295) 875 1,659
----------------------------------------------------------------
Total unit-based
compensation ($000s) 1,510 (426) 3,027 4,154

Expensed unit-based
compensation:
As % of revenue 0.9 (0.1) 0.5 0.6
$/boe 0.50 (0.07) 0.29 0.35
Per trust unit ($) 0.01 0.00 0.03 0.03
----------------------------------------------------------------


MANAGEMENT CONTRACT AND FEES

The Trust is managed by 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, 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 pursuant to a management contract. This agreement requires the Trust to reimburse the Manager at cost for general and administrative and unit based compensation expenses incurred by the Manager on behalf of the Trust.

The Trust paid $3.1 million (2006 - $1.3 million) for the reimbursement of G&A expenses during the fourth quarter and $11.6 million (2006 - $6.6 million) year to date. The increase in charges from the Manager is due to increased compensation charges (see General and Administrative Expenses). 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, on a year to date basis, $2.2 million was paid in the first quarter of 2007 relating to notional units that vested November 30, 2006.

The management contract was restructured effective May 31, 2006, after which no further management fees are payable. Prior to this date the Trust was required to pay a monthly management fee, of which $1.4 million was paid during 2006. Under the restructuring, the Trust agreed to pay one-time $30 million restructuring fee in exchange for the elimination of any management fees and for the acquisition of a 50 percent ownership in the Manager's administrative capital assets. Of the $30 million restructuring fee $2.8 million was allocated to administrative assets and capitalized as property, plant, and equipment. The balance of $27.2 million, representing the elimination of future management fees was recorded as a non-cash charge in income. In payment of the restructuring fee, the Trust issued, to an affiliate of the Manager, 1,592,357 units of the Trust at a price of $18.84 per unit. The subscription price was based on the weighted average trading price of the trust units over the five consecutive trading days ending on the third trading day preceding March 1, 2006, the date of the agreement.

INTEREST

Interest on bank debt includes charges on borrowings plus standby fees on the unused portion of the bank credit facility. NAL's average outstanding bank debt for the fourth quarter of 2007 was $266.6 million, as compared to $213.9 million for the fourth quarter of 2006. NAL's effective interest rate averaged 5.61 percent in 2007, compared with 5.06 percent in the fourth quarter of 2006. NAL's interest is at a floating rate. The increase in the rate from the fourth quarter of 2006 is attributable to rate increases in the market.

For the year ended December 31, 2007 NAL's average outstanding debt was $242.9 million, as compared with $203.2 million for the corresponding period in 2006. NAL's effective interest rate in 2007 averaged 5.38 percent compared with 4.83 percent in 2006.

Interest on convertible debentures represents interest charges, since the issuance of the debentures on August 28, 2007, at 6.75 percent, of $1.7 million and accretion of the debt discount of $0.5 million for the fourth quarter of 2007, and $2.3 million and $0.6 million, respectively, for full year 2007.



Interest and Debt ($000s)

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Interest on bank debt 3,820 2,759 13,356 9,963
Interest on convertible
Debentures 2,178 - 2,965 -
----------------------------------------------------------------
Total interest 5,998 2,759 16,321 9,963
Bank debt outstanding
at period end 275,630 220,785 275,630 220,785
Convertible debentures
at period end 90,876 - 90,876 -
----------------------------------------------------------------
----------------------------------------------------------------


CASH FLOW NETBACK

For the quarter ended December 31, 2007, NAL's cash flow netback was $28.08 per boe, an 11 percent decrease from $31.69 for the comparable period in 2006. The decrease is due to lower operating netbacks after hedging in 2007 and higher expenses.

For the year ended December 31, 2007, NAL's cash flow netback decreased five percent to $29.93 compared to $31.59 in 2006. The decrease is primarily attributable to lower operating netbacks after hedging, higher G&A and interest expenses, offset partially by lower unit based compensation and management fees.



Cash Flow Netback ($/boe)

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Operating netback,
after hedging 33.04 34.49 34.24 35.07
Management fees - - - (0.19)
G&A expenses, excluding
retention bonus (1.87) (1.33) (1.79) (1.54)
Retention bonus (0.03) - (0.13) -
Unit-based incentive
Compensation (0.50) 0.07 (0.29) (0.35)
Interest and fees on
bank debt (1.77) (1.54) (1.78) (1.40)
Interest on convertible
debentures(1) (0.79) - (0.32) -
----------------------------------------------------------------
Cash flow netback 28.08 31.69 29.93 31.59
----------------------------------------------------------------
----------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.



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, 2007, depletion on property, plant and equipment and accretion on the asset retirement obligations increased by 20 percent over the comparable period in 2006 due to a 20 percent increase in production volumes.

For the year ended December 31, 2007, depletion and accretion increased by 17 percent over the comparable period due to a five percent increase in production and an 11 percent increase in the DDA rate per boe of production.

The increase in the DDA rate per boe is largely attributable to the Seneca acquisition.

The DDA rate will fluctuate period over period depending on the amount and type of capital expenditures and the amount of reserves added.

Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment. The carrying value 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 value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of P+P reserves plus the lower of cost and market of undeveloped land. The cash flows are estimated using expected future commodity prices and costs and are discounted using a risk-free interest rate. There was a significant surplus in the ceiling test at the year end 2007.



Depletion, Depreciation and Accretion Expenses

----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Depletion and depreciation
($000s) 42,888 35,725 155,392 133,079
Accretion of asset
retirement obligation
($000s) 1,564 1,258 5,533 4,984
----------------------------------------------------------------
Total DDA ($000s) 44,452 36,983 160,925 138,063
DDA rate per boe ($) 20.63 20.60 21.51 19.45
----------------------------------------------------------------
----------------------------------------------------------------


TAXES

In the fourth quarter of 2007, NAL had a future income tax reduction of $2.0 million compared with $0.3 million in the corresponding period for the prior year.

NAL had a future income tax reduction of $3.4 million in 2007 compared to $1.2 million in 2006.

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. The Trust does not expect to incur any cash taxes in 2008.

The following tax pools are available to the Trust and subsidiaries (subject to assessment by income tax authorities) for future use as deductions from taxable income:



----------------------------------------------------------------
($000s) 2007 2006
----------------------------------------------------------------
Intangible resource pools $463,715 $323,818
Undepreciated capital cost 202,632 149,383
Unit issue costs 13,815 9,437
Non-capital losses 17,661 11,495
----------------------------------------------------------------
Total tax pools $697,823 $494,133
----------------------------------------------------------------
----------------------------------------------------------------


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. Although further clarifications are expected, these measures are now considered substantively enacted for purposes of Canadian generally accepted accounting principles. Accordingly, the Trust has measured future income tax assets and liabilities associated with this new tax. There is no impact on the future tax recognized in the financial statements resulting from the implementation of this tax legislation, as it is expected that all existing taxable temporary differences will reverse prior to January 1, 2011, the date the taxation changes take effect. Accordingly, all taxable temporary differences have been recognized at a zero taxation rate. 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 depletion, accretion, unrealized gain or loss on derivative contracts and future income taxes.

Net income for the fourth quarter of 2007 was $10.6 million compared to $20.5 million for the comparable period in 2006. The decrease in net income of $9.9 million is primarily due to a $7.2 million increase in depletion, increased
operating costs of $8.7 million, increased G&A and unit based compensation of $2.9 million, and increased interest expense of $3.2 million, partially offset by higher revenues, net of royalties and gain/loss on derivative contracts, of $11.0 million and an increase in the future income tax reduction of $1.7 million.

Net income for the year ended December 31, 2007 of $56.5 million was $3.7 million lower than the same period in 2006. In 2006, net income includes a non-cash expense of $27.3 million relating to the restructuring of the management contract. Excluding this amount net income decreased year over year by $31.0 million, primarily due to a $22.3 million increase in depletion, increased interest expense of $6.4 million, a $11.0 million increase in operating costs, offset by a $8.9 million increase in revenues, net of royalties and gain/loss on derivative contracts.



Net Income ($000s)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Net income 10,556 20,472 56,457 60,198
----------------------------------------------------------------
----------------------------------------------------------------


CAPITAL RESOURCES AND LIQUIDITY

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

As at December 31, 2007, NAL had 90,494,151 trust units outstanding, compared with 77,971,268 trust units at December 31, 2006. The increase from December 31, 2006 is attributable to 10,246,000 trust units issued on close of the equity offering on August 31, 2007, and 2,276,883 trust units issued under the distribution reinvestment program ("DRIP").

Under the equity offering, 10.2 million trust units were issued at a price of $12.20 per trust unit for net proceeds, after issue costs, of $117.9 million.

For the year ended December 31, 2007, the distribution reinvestment plan resulted in 2.3 million trust units being issued at an average price of $11.74 per trust unit for total proceeds of $26.7 million.

Unitholders electing to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP may do so at 95 percent of the average market price with no additional fees or commissions. 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.

The participation rate in the regular DRIP averaged 16 percent over the three months ended December 31, 2007 and 17 percent for full year 2007, consistent with recent experience. The Trust continues to monitor the participation in this plan in conjunction with its capital requirements.

As at December 31, 2007 the Trust had total debt of $391.1 million, including convertible debentures at face value of $100 million and a working capital deficit of $15.4 million (excluding derivative contracts and future income tax asset). Excluding the convertible debentures, net debt was $291.1 million, compared with $223.1 million at December 31, 2006, and $274.5 million as at September 30, 2007.

At the end of the fourth quarter, the Trust had a net debt to equity ratio of 0.77 compared to 0.49 at December 31, 2006. In addition, at the end of the fourth quarter, the Trust had a net debt (excluding convertible debentures) to 12 months trailing cash flow of 1.33 and a total net debt to 12 months trailing cash flow of 1.79.

The Trust maintains a $400 million fully secured, extendible, revolving credit facility. The credit facility revolves until April 30, 2008 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 $390 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 four equal quarterly installments commencing May 2009.

Bank debt amounted to $275.6 million at December 31, 2007 compared with $220.8 million as at December 31, 2006. Of the debt outstanding at December 31, 2007, $273.5 million was outstanding under the production facility and $2.1 million under the working capital facility.

Bank debt increased from $220.8 million as at December 31, 2006 to $275.6 million as at December 31, 2007 primarily due to $31.8 million required for the acquisition of Seneca.

On August 28, 2007, in connection with the acquisition of Seneca, the Trust issued $100 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. 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. Assuming conversion of all outstanding debentures 7.1 million trust units would 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 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 Trust recognized $0.5 million of accretion of the debt discount in the fourth quarter of 2007, and $0.6 million year to date.

As at February 28, 2008 the Trust has 93,331,575 trust units and $100 million in convertible debentures outstanding.



Year-end Capitalization
---------------------------------------------------------------------------
December December
31, 2007 31, 2006
---------------------------------------------------------------------------
Trust unit equity ($000s) 504,717 456,500

Bank debt ($000s) 275,630 220,785
Working capital deficit(1) ($000s) 15,429 2,276
---------------------------------------------------------------------------
Net debt excluding convertible debentures 291,059 223,061
Convertible debentures ($000s)(3) 100,000 -
---------------------------------------------------------------------------
Net debt 391,059 223,061

Net debt to equity 0.77 0.49
Net debt excluding convertible debentures
to trailing 12-month cash flow(2) 1.33 1.01
Net debt to trailing 12-month cash flow(2) 1.79 1.01
Trust units outstanding (000s) 90,494 77,971
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Working capital excludes derivative contracts and future income
tax asset.
(2) Calculated as net debt divided by funds from operations for the
previous 12 months.
(3) Convertible debentures included at face value.


Subject to fluctuations in commodity prices, the Trust anticipates that it will continue to maintain adequate liquidity to fund planned capital spending during 2008 through a contribution of funds from operations, funds received from its DRIP and bank debt.

If assumptions underlying the forecast, including commodity prices and production, change then the Trust may be required to reconsider is financing, distribution level or capital expenditures.

Under the tax legislation regarding the change in the taxability of the trusts, the Trust has a grandfathering period to 2011 until the rules come into effect. The grandfathering period restricts "undue expansion" of the Trust by placing growth limits for equity and convertible debt based on the market capitalization of the Trust on October 31, 2006, the date of the announcement. For 2008 the Trust has approximately $597 million of room and for each of 2009 and 2010 an additional $280 million each year.

ASSET RETIREMENT OBLIGATION

At December 31, 2007, the Trust reported an asset retirement obligation ("ARO") balance of $89.6 million (2006 -$65.6 million) for future abandonment and reclamation of the Trust's oil and gas properties and facilities. The ARO balance was increased by $12.6 million due to the Seneca acquisition, $11.4 million due to liabilities incurred and revisions to estimates (2006 - $3.1 million), $5.5 million from accretion expense (2006 - $5.0 million) and was reduced by $5.5 million for actual abandonment and environmental expenditures incurred in 2007 (2006 - $4.4 million).

DISTRIBUTIONS TO UNITHOLDERS

For the three months ended December 31, 2007 the Trust distributed 96 percent of its cash flow from operating activities and 74 percent for the full year, as compared to 81 percent and 71 percent respectively in 2006. 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. The Trust has distributed in excess of its net income each period, due to the non-cash charges included in net income. Cash flow from operations usually exceeds net income as net income includes non-cash charges such as depletion, depreciation, accretion, future income tax expense and unrealized gains and losses on derivative contracts.

The Trust bases its distributions on the cash flow of the Trust, commodity prices, financial market conditions, internal capital investment opportunities and the resulting impact on taxability. The Trust develops an annual forecast, which is updated regularly by management. The Board sets distributions at a level it believes will be sustainable for a period of time and formally reviews distribution levels quarterly.

Given that distributions exceed net income, 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 2008 capital program is not expected to 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 acquisition. NAL's productive capacity and future cash flow will be dependent on its ability to acquire assets and find reserves at appropriate economics. 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 proceeds from the DRIP and debt. Over the medium term, fluctuations in commodity prices, other market factors, or development opportunities may make it necessary to fund the excess of distributions and capital expenditures over cash, from the credit facility. The credit facility and other sources of cash are expected to be sufficient to meet NAL's near term capital requirements, sustain distributions and provide for the resources to pursue potential growth opportunities.

NAL intends to continue to make cash distributions to unitholders. However, these cash distributions cannot be guaranteed. The intent is to continue to distribute a certain proportion of cash flow from operating activities, the level of distributions being dependent on the drivers of cash flow, namely production 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 decrease in commodity prices could impact cash from operating activities, access to credit facilities and the Trust's ability to fund operations and maintain distributions.



Distributions
-------------------------------------------------------------------
($000s except for Three months ended Years ended
percentages) December 31 December 31
----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------
Cash flow from operating
activities 45,111 48,678 215,364 238,445
Net income 10,556 20,472 56,457 60,198
Actual cash distributions
paid or payable 43,340 39,663 158,601 169,589
Excess (shortfall) of cash
flow from operating
activities over cash
distribution paid 1,771 9,015 56,763 68,856
Percentage of cash flow
from operations
distributed 96% 81% 74% 71%
Excess (shortfall) of net
income over cash
distributions paid (32,784) (19,191) (102,144) (109,391)
-------------------------------------------------------------------
-------------------------------------------------------------------


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, 2007, funds from operations amounted to $59.5 million compared with $55.8 million for the three months ended December 31, 2006. The increase is due to increased revenue driven by higher production and pricing offset partially by higher costs. On a per trust unit basis funds from operations decreased eight percent from $0.72 in 2006 to $0.66 in 2007 due to the increase in trust units from the equity offering associated with the acquisition of Seneca.

For the year ended December 31, 2007, funds from operations was comparable with 2006 though decreased eight percent on a per unit basis from $2.88 to $2.65 in 2007. The decrease is due to the equity offering and units issued under the DRIP.



Funds from Operations

-------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------
Funds from operations ($000s) 59,537 55,795 218,745 219,776
Funds from operations per
trust unit 0.66 0.72 2.65 2.88
Payout ratio based on funds
from operations 73% 71% 73% 77%
-------------------------------------------------------------------
-------------------------------------------------------------------


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) 2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Office lease(1) 3,672 3,672 3,366 - - -
Transportation agreement 1,123 1,123 84 - - -
Processing agreement(2) 469 446 428 414 401 384
Drilling rigs(3) 494 - - - - -
Retention bonus(4) 578 - - - - -
----------------------------------------------------------------------------
Total 6,336 5,241 3,878 414 401 384
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including
office space acquired with the Seneca acquisition, 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 a gas processing agreement with a take or pay agreement.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.


ACQUISITION OF TIBERIUS EXPLORATION INC. ("Tiberius") AND SPEAR EXPLORATION INC. ("Spear").

On February 27, 2008, the Trust completed the acquisition of all of the issued and outstanding shares of Tiberius and Spear. Total consideration is approximately $115 million, before closing adjustments, consisting of approximately 2.4 million trust units and $86.25 million in cash.

Concurrently, the Trust entered into an agreement with a wholly owned subsidiary of Manulife Financial Corporation ("MFC"), to contribute the assets and liabilities of Tiberius and Spear to a limited partnership owned 50 percent by the Trust and 50 percent by MFC. MFC will acquire its 50 percent interest in the limited partnership by payment of one half of the purchase price, being approximately $57.5 million.

Consequently, the total acquisition cost to the Trust for its 50 percent interest in the acquired companies will be approximately $57.5 million, comprising 2.4 million trust units and $28.75 million in cash.

MFC is a related party to the Trust, see Management Contract and Fees.

The new properties will contribute primarily light oil production from the Tilston formation, along with associated natural gas and natural gas liquids.



QUARTERLY INFORMATION
2007 2006
----------------------------------------------------------------------------
($000s, except per unit and production amounts)

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Revenue,
net of
royalties 86,262 78,573 83,268 71,231 75,358 75,798 77,988 81,272
Per unit 0.96 0.95 1.06 0.91 0.97 0.98 1.03 1.08
Funds from
operations
(1) 59,537 50,817 54,156 54,235 55,795 54,107 52,210 57,664
Per unit 0.66 0.61 0.69 0.69 0.72 0.70 0.69 0.77
Net income
(loss) 10,556 7,801 21,390 16,710 20,472 20,473 (5,357) 24,610
(2)
Per unit
- basic and
diluted 0.12 0.09 0.27 0.21 0.26 0.27 (0.07) 0.33
Average oil
equivalent
production
(boe/d-6:1) 23,413 20,182 18,946 19,422 19,517 19,079 19,012 20,181
----------------------------------------------------------------------------

(1) Represents cash flow from operating activities prior to the change
in non-cash working capital items.
(2) Includes non-cash management restructuring fee of $27.2 million.



SELECTED ANNUAL INFORMATION

Years ended December 31
----------------------------------------------------------------------------
($000s except per unit amounts) 2007 2006 2005
----------------------------------------------------------------------------
Oil, natural gas and liquid sales(1) 413,426 385,624 406,007
Net income 56,457 60,198 98,538
Net income per trust unit 0.68 0.79 1.41
Net income per trust unit - diluted 0.68 0.79 1.41
Distributions paid and declared 158,601 169,589 142,050
Distributions paid or declared per trust unit 1.92 2.22 2.01
Total assets 1,063,160 796,902 834,883
Total liabilities 558,443 340,402 340,393
Long term debt(2) 366,506 220,785 220,519
Unitholders' equity 504,717 456,500 494,490

Number of trust units outstanding at year end 90,494 77,971 73,977
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) 2005 restated as a result of a change in presentation.
(2) Includes bank debt and convertible debentures.


FINANCIAL REPORTING DISCLOSURE CONTROLS

Management has designed and evaluated the effectiveness of the Trust's financial reporting disclosure controls and procedures as at December 31, 2007 and has concluded that such controls and procedures were effective as at that date.

While NAL's management believes that the Trust's disclosure controls and procedures provide a reasonable level of assurance with respect to their effectiveness, they do not expect that such controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, provides only reasonable, and not absolute, assurance that the objectives of the control system are met.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management has designed or caused to be designed under its supervision, internal control over financial reporting related to the Trust and its subsidiaries, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

There were no changes to the Trust's internal control over financial reporting since September 30, 2007 that have materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting

CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by NAL are disclosed in the notes to NAL's December 31, 2007 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 following discusses such accounting policies and is included in this MD&A to assist investors in assessing the critical accounting policies and practices of NAL and the likelihood of materially different results being reported. 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. The following assessment of significant accounting estimates is not meant to be exhaustive. 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). In accordance with this definition, the level of certainty targeted by the reporting company 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. There was no such consideration of probability under previous reporting rules. 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 implementation of NI 51-101 has resulted in a more rigorous and uniform standardization of reserve evaluation.

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".

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.

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), 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.

Fair Value of Derivative Instruments

NAL utilizes financial derivatives to manage market risk. The purpose of the hedge is to provide an element of stability to NAL's cash flow in a volatile 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 the derivative contracts is based on forward commodity prices. Any change in commodity prices 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 and interpretation of laws and regulations 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. No future taxes have been recognized for the Trust based on management's estimates that the reversal of all temporary differences will occur prior to 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 maybe recorded for the Trust.

NEW ACCOUNTING POLICY

Effective January 1, 2007 the Trust implemented the provisions of CICA Handbook Section 3855 "Financial Instruments -- recognition and measurement", Section 3861 "Financial Instruments -- disclosure and presentation", Section 3865 "Hedges", Section 1530 "Comprehensive Income", and certain provisions of Section 3251 "Equity".

These standards address the recognition and measurement of financial assets, financial liabilities and non-financial derivatives. Financial instruments are classified into one of four categories, and each category determines how an instrument is measured and when and where gains and losses are recognized. Instruments are either measured at fair value or amortized cost, which is determined using the effective interest method. The hedging standard provides guidance on when and how hedge accounting may be performed and Section 1530 provides standards on the reporting and display of comprehensive income and its components.

These standards have been applied by the Trust, on a prospective basis, in accordance with the relevant transitional provisions. For full details on the implications to the Trust of these standards, see Note 3 to the consolidated financial statements.

FUTURE ACCOUNTING CHANGES

The CICA issued new accounting standards: Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", and Section 3863 "Financial Instruments -- Presentation". These standards will effective January 1, 2008.

Section 1535 "Capital Disclosures" establishes standards for disclosing information about an entity's capital and how it is managed. The 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 to revise and enhance disclosure on financial instruments. These standards require entities to provide disclosure in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance, and the nature and extent of risks arising from financial instruments and how the entity manages those risks. The standards establish presentation guidelines for financial instruments and non-financial derivatives and deal with the classification of financial instruments from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and liabilities are offset.

The Trust is currently assessing the impact of these standards on its financial statements. However, it is not anticipated that the adoption of these new standards will impact the amounts reported in the Trust's financial statements as they primarily relate to disclosure.

Dated: February 28, 2008



CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
December December
31, 2007 31, 2006
--------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1,394 $ 6,295
Accounts receivable and other 70,791 44,467
Derivative contracts (Note 13) 3,389 -
Future income tax asset (Note 12) 2,602 -
--------------------------------------------------------------------------
78,176 50,762

Future income tax asset (Note 12) 4,096 3,345
Property, plant and equipment (Notes 4 and 6) 980,888 742,795
--------------------------------------------------------------------------
$ 1,063,160 $ 796,902
--------------------------------------------------------------------------

Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 73,135 $ 40,563
Distributions payable to unitholders 14,479 12,475
Derivative contracts (Note 13) 12,973 -
--------------------------------------------------------------------------
100,587 53,038

Bank debt (Note 7) 275,630 220,785
Convertible debentures (Note 8) 90,876 -
Unit-based incentive compensation (Note 9) 1,748 1,005
Asset retirement obligations (Note 10) 89,602 65,574
--------------------------------------------------------------------------
558,443 340,402

Unitholders' equity
Unitholders' capital (Note 11) 969,588 824,986
Equity component of convertible debentures
(Note 8) 5,759 -
Deficit (Note 11) (470,630) (368,486)
--------------------------------------------------------------------------
504,717 456,500
--------------------------------------------------------------------------
$ 1,063,160 $ 796,902
--------------------------------------------------------------------------
Commitments (Note 14)
Subsequent event (Note 15)
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Trust units outstanding (000s) 90,494 77,971
--------------------------------------------------------------------------
--------------------------------------------------------------------------

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
----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue
Oil, natural gas and liquid sales $ 122,548 $ 89,994 $ 413,426 $ 385,624
Crown royalties (19,138) (13,156) (64,798) (61,570)
Freehold and other royalties (6,875) (5,438) (24,341) (22,098)
----------------------------------------------------------------------------
96,535 71,400 324,287 301,956

Gain (loss) on derivative contracts
(Note 13):
Realized gain (loss) (5,510) 1,798 (2,435) 3,375
Unrealized loss (8,213) - (14,105) -
Reclassification from other
comprehensive income 874 - 4,521 -
----------------------------------------------------------------------------
(12,849) 1,798 (12,019) 3,375

Royalty and other income 2,576 2,160 7,066 5,085
----------------------------------------------------------------------------
86,262 75,358 319,334 310,416
----------------------------------------------------------------------------
Expenses
Operating 21,537 12,796 69,916 58,964
Transportation 897 620 2,779 2,547
General and administrative 4,096 2,395 14,404 10,946
Unit-based incentive compensation
(Note 9) 1,080 (131) 2,152 2,495
Management fees (Note 5) - - - 1,350
Restructuring fee (Note 5) - - - 27,299
Interest on bank debt 3,820 2,759 13,356 9,963
Interest and accretion on
convertible debentures 2,178 - 2,965 -
Depletion, depreciation and
amortization 42,888 35,725 155,392 133,079
Accretion on asset retirement
obligations 1,564 1,258 5,533 4,984
----------------------------------------------------------------------------
78,060 55,422 266,497 251,627
----------------------------------------------------------------------------
Income before taxes 8,202 19,936 52,837 58,789

Income tax recovery 350 274 267 200
Future income tax reduction 2,004 262 3,353 1,209
----------------------------------------------------------------------------
Total income taxes (Note 12) 2,354 536 3,620 1,409
----------------------------------------------------------------------------
Net income 10,556 20,472 56,457 60,198
Other comprehensive income:
Reclassification to net income, net
of tax of $1,349 (Notes 3 and 13) (613) - (3,172) -
----------------------------------------------------------------------------
Comprehensive income 9,943 20,472 53,285 60,198
----------------------------------------------------------------------------

Deficit, beginning of period (437,846) (349,295) (368,486) (259,095)
Net income 10,556 20,472 56,457 60,198
Distributions declared (Note 11) (43,340) (39,663) (158,601) (169,589)
----------------------------------------------------------------------------
Deficit, end of period $(470,630)$(368,486) $(470,630)$(368,486)
----------------------------------------------------------------------------

Net income per trust unit - basic
and diluted (Note 11) $ 0.12 $ 0.26 $ 0.68 $ 0.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average trust units
outstanding (000s) 90,194 77,697 82,556 76,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes.


CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
Three Months Ended Years Ended
December 31 December 31
----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net income $ 10,556 $ 20,472 $ 56,457 $ 60,198
Items not involving cash:
Depletion, depreciation and
amortization 42,888 35,725 155,392 133,079
Accretion on asset retirement
obligations 1,564 1,258 5,533 4,984
Unrealized loss on derivative
contracts 8,213 - 14,105 -
Reclassification from other
comprehensive income (874) - (4,521) -
Future income tax reduction (2,004) (262) (3,353) (1,209)
Non-cash accretion expense on
convertible debentures 477 - 635 -
Restructuring fee - - - 27,159
Abandonment and environmental
expenditures (1,283) (1,398) (5,503) (4,435)
Change in non-cash working capital (14,426) (7,117) (3,381) 18,669
----------------------------------------------------------------------------
45,111 48,678 215,364 238,445
----------------------------------------------------------------------------

Financing Activities
Distributions paid to unitholders (36,834) (34,025) (129,862) (129,769)
Issue of trust units, net of issue
costs - - 117,867 -
Increase in bank debt 19,145 12,592 54,127 266
Issue of convertible debentures,
net of issue costs - - 96,000 -
Change in non-cash working capital 426 186 1,341 2,241
----------------------------------------------------------------------------
(17,263) (21,247) 139,473 (127,262)
----------------------------------------------------------------------------

Investing Activities
Acquisition of Seneca Energy
Canada Inc. (Note 4) 323 - (245,687) -
Additions to property, plant and
equipment (39,194) (34,828) (118,011) (120,030)
Property acquisitions - - (1,449) (1,267)
Proceeds from dispositions - 40 26 96
Reclamation reserve - 4,294 - 3,898
Change in non-cash working capital 6,325 2,169 5,383 11,291
----------------------------------------------------------------------------
(32,546) (28,325) (359,738) (106,012)
----------------------------------------------------------------------------

Increase (decrease) in cash and
cash equivalents (4,698) (894) (4,901) 5,171
Cash and cash equivalents,
beginning of period 6,092 7,189 6,295 1,124
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 1,394 $ 6,295 $ 1,394 $ 6,295
----------------------------------------------------------------------------

Supplementary disclosure of cash
flow information:
Cash paid during the period for:
Interest $ 4,777 $ 2,726 $ 16,913 $ 9,816
Tax recovery $ (350) $ 62 $ (267) $ 136
----------------------------------------------------------------------------

Cash and cash equivalents is
comprised of:
Cash $ 1,394 $ 303 $ 1,394 $ 303
Short term investments - 5,992 - 5,992
----------------------------------------------------------------------------
$ 1,394 $ 6,295 $ 1,394 $ 6,295
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Years ended December 31, 2007 and 2006

(Tabular amounts in thousands of dollars, except per unit amounts)

(unaudited)

The financial results for the three months ended December 31, 2007 have not been separately reviewed by the external auditors.

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 wholly owned subsidiaries and partnerships, interests in oil and natural gas properties and to distribute the net cash proceeds 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 in which NAL Resources is the operator. 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 have been prepared in accordance with Generally Accepted Accounting Principles ("GAAP") in Canada and they include the accounts of the Trust, its subsidiaries and partnerships, which are wholly owned. 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 estimates of trust unit price and performance factors, while the fair value estimates for derivatives are based on expected future oil and natural gas prices and volatility in these prices. 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% 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 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. In addition, the Trust is currently exempt from future income taxes because it is contractually committed to distribute all of its income to its unitholders. This tax treatment is only applicable up to 2011, at which time the 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

Financial instruments are required to be 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 are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities, distributions 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. 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 commodity 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.

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. The compensation 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 treasury stock 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.

Cash and Cash Equivalents

Cash and cash equivalents include short-term investments with a maturity of three months or less when purchased.

Comparative Information

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

3. CHANGES IN ACCOUNTING POLICIES

Financial Instruments, Hedges, Comprehensive Income

Effective January 1, 2007 the Trust implemented the provisions of CICA Handbook Section 3855 "Financial Instruments - recognition and measurement", Section 3861 "Financial Instruments - disclosure and presentation", Section 3865 "Hedges", Section 1530 "Comprehensive Income" and certain provisions of Section 3251 "Equity".

Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives. Financial instruments are classified into one of five categories, each category determines how an instrument is measured and when and where gains and losses are recognized. Instruments are either measured at fair value or amortized cost, which is determined using the effective interest method. There were no changes to the measurement or presentation of these financial assets or liabilities at the date of adoption, other than bank debt as discussed below. Section 3865 provides guidance on when and how hedge accounting may be used. Section 1530 provides standards on the reporting and display of comprehensive income and its components. Other comprehensive income comprises certain revenues, expenses, gains and losses not included in the determination of net income. Section 3251 provides guidance on the presentation and disclosure of the components of equity, including accumulated other comprehensive income.

These standards were applied on a prospective basis on January 1, 2007, in accordance with the relevant transitional provisions with no restatement of prior periods.

As a result of the new standards, the Trust began to fair value its derivative contracts. On January 1, 2007, the Trust had derivative contracts in place with a fair value of $4.5 million. The transitional provisions of the new standards allowed for NAL's derivatives to be recorded as an asset on January 1, 2007 with the offset being recorded in accumulated other comprehensive income ("AOCI"), a component of unitholders' equity. The amount recorded in AOCI has been reclassified to net income during 2007 in accordance with the terms of the derivatives.

On adoption, the Trust elected to recognize, as separate assets and liabilities, only those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. The Trust did not identify any material embedded derivatives which required separate recognition and measurement.

In accordance with Section 3855, bank debt is presented net of deferred interest payments, with interest recognized in net income on an effective interest basis. Previously, interest was recognized on a straight-line basis with the deferred amount included in accounts receivable. There was no impact at January 1, 2007 resulting from this change.

Future Accounting Changes

The CICA issued new accounting standards: Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", and Section 3863 "Financial Instruments - Presentation". These standards are effective January 1, 2008.

Section 1535 "Capital Disclosures" establishes standards for disclosing information about an entity's capital and how it is managed. The 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 to revise and enhance disclosure on financial instruments. These standards require entities to provide disclosure in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance, and the nature and extent of risks arising from financial instruments and how the entity manages those risks.

The Trust is currently assessing the impact of these standards on its financial statements, however, it is not anticipated that the adoption of these new standards will impact the amounts reported in the Trust's financial statements as they primarily relate to disclosure.

4. CORPORATE ACQUISITION

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) $ (4,366)
Property, plant and equipment 262,678
Asset retirement obligations (12,625)
----------------------------------------------------------------------------
$ 245,687
----------------------------------------------------------------------------

Consideration:
----------------------------------------------------------------------------
Cash $ 245,110
Acquisition costs 577
----------------------------------------------------------------------------
$ 245,687
----------------------------------------------------------------------------


The above amounts are estimates made by management based on currently available information. Amendments may be made to the purchase allocation as cost estimates and balances are finalized.

5. RELATED PARTY TRANSACTIONS

The Manager provides certain services pursuant to a management contract. This contract requires the Trust to reimburse the Manager, at cost, for general and administrative expenses ("G&A") incurred by the Manager on behalf of the Trust. In 2007, the Trust paid $11.6 million (2006 - $6.6 million) for the reimbursement of G&A. The Trust accrues for its share of unit based incentive compensation as units vest, but only pays the Manager its share of the expense when cash compensation is paid to employees under the terms of the unit based incentive compensation plan. During 2007, $2.2 million was paid in the first quarter of 2007 relating to notional units that vested November 30, 2006.

On May 31, 2006, the Trust's unitholders approved the restructuring of the management contract with the Manager. Prior to this date the Trust was required to pay an interim monthly management fee, of which $1.4 million was paid during 2006. Prior to January 1, 2006, the Trust was required to pay a monthly base management fee equal to three percent of its net production revenue and a quarterly performance fee based on the Trust's overall return compared to the S&P / TSX Capped Energy Trust Index.

Under the terms of the restructuring, the Trust agreed to pay a one-time $30 million restructuring fee in exchange for the elimination of any further base and performance management fees payable by the Trust and the acquisition of a 50 percent ownership in the Manager's administrative capital assets, effective January 1, 2006. In payment of the restructuring fee, the Trust issued, to an affiliate of the Manager, 1,592,357 trust units of the Trust at a price of $18.84 per trust unit. The subscription price was based on the weighted average trading price of the trust units over the five consecutive trading days ending on the third trading day preceding March 1, 2006, the date of the agreement.

Of the $30 million restructuring fee, $2.8 million was allocated to the administrative assets acquired and capitalized as property, plant and equipment. The balance of $27.2 million, representing the elimination of future management and performance fees, has been recorded as a non-cash charge to income.

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



2007 2006
----------------------------------------------------------------------------
Due from NAL Resources Limited $ 14,203 $ 1,478
Due to NAL Resources Management Limited $ (2,826) $ (3,718)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. PROPERTY, PLANT AND EQUIPMENT

Net book value as at December 31: 2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties, at cost $ 1,687,331 $ 1,293,854
Less: Accumulated depletion and depreciation (706,443) (551,059)
----------------------------------------------------------------------------
$ 980,888 $ 742,795
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Costs associated with undeveloped land of $30.1 million (2006 - $nil) have been excluded from the depletion calculation for the year ended December 31, 2007.

Future development costs for proved reserves of $41.6 million (2006 - $49.3 million) have been included in the depletion calculation.

During 2007, the Trust capitalized $4.5 million (2006 - $4.3 million) of general and administrative costs and $0.9 million (2006 - $1.7 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, 2007 to assess the recoverable value of property, plant and equipment. The oil and gas future prices are based on the January 1, 2008 commodity price forecast of our 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, 2007.



WTI Oil US$/Cdn$ WTI Oil AECO Gas
Year (US$/bbl) Exchange Rate (Cdn$/bbl) (Cdn$/GJ)
---------------------------------------------------------
2008 90.00 1.0 90.00 6.45
2009 86.70 1.0 86.70 7.00
2010 83.20 1.0 83.20 7.00
2011 79.60 1.0 79.60 7.00
2012 78.50 1.0 78.50 7.10
---------------------------------------------------------

Remainder(1) 2% 1.0 2% 2%

(1) Percentage change represents the change in each year after 2012 to the
end of the reserve life.


7. BANK DEBT

2007 2006
----------------------------------------------------------------------------
Production loan facility 273,528 $ 219,000
Working capital facility 2,102 1,785
----------------------------------------------------------------------------
Total debt outstanding 275,630 $ 220,785
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Trust maintains a $400 million fully secured, extendible, revolving term credit facility with a syndicate of Canadian chartered banks. This facility consists of a $390 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 a function of 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 was renewed in April 2007, and revised in conjunction with the Seneca acquisition in September 2007, and will revolve until April 30, 2008 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 2008, the amounts outstanding at that time will be converted to a two-year term loan. The term loan will be payable in four equal quarterly installments commencing May 2009 with a final residual payment, if any, in May 2010.

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.

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, 2007 and 2006 all amounts outstanding were in Canadian dollars.

On December 31, 2007 the effective interest rate on amounts outstanding under the credit facility was 5.74 percent (2006 - 5.18 percent).

8. CONVERTIBLE DEBENTURES

On August 28, 2007 the Trust issued $100 million principal amount of 6.75% 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 amount Debt component Equity component
of debentures of debentures of debentures
----------------------------------------------------------------------------
August 28, 2007 issuance $ 100,000 $ 94,241 $ 5,759
Issue costs - (4,000) -
----------------------------------------------------------------------------
100,000 90,241 5,759
Accretion - 635 -
----------------------------------------------------------------------------
Balance, December 31, 2007 $ 100,000 $ 90,876 $ 5,759
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 grant. PTU's vest on November 30, three years after grant.

The Trust recorded a total compensation expense of $3.0 million in 2007 of which $2.1 million was recorded as an expense and $0.9 million as property, plant and equipment (2006 - $2.5 million expense, $1.7 million property, plant and equipment). The compensation expense was based on the December 31, 2007 trust unit price of $11.60 (2006 - $12.31), 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:



2007 2006
----------------------------------------------------------------------------
Balance, beginning of year $ 4,153 $ -
Increase in liability 3,027 4,153
Cash payout, relating to units vested November 30, 2006 (2,184) -
----------------------------------------------------------------------------
Balance, end of year $ 4,996 $ 4,153
----------------------------------------------------------------------------
Current portion of liability(1) $ 3,248 $ 3,148
----------------------------------------------------------------------------
Long-term liability $ 1,748 $ 1,005
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Included in accounts payable and accrued liabilities.


10. ASSET RETIREMENT 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 $89.6 million as at December 31, 2007 (2006 - $65.6 million) based on a total undiscounted and inflated amount of cash flows required to settle its asset retirement obligations of $276.0 million (2006 - $224.7 million). These costs are expected to be made over the next 45 years with the majority of the costs incurred between 2008 and 2033. NAL's credit-adjusted risk-free rate of eight percent (2006 - eight percent) and an inflation rate of two percent (2006 - two percent) were used to calculate the present value of the asset retirement obligations.

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



2007 2006
----------------------------------------------------------------------------
Balance, beginning of year $ 65,574 $ 61,908
Accretion expense 5,533 4,984
Revisions to estimates 10,294 39
Liabilities incurred 1,079 3,078
Liabilities acquired (Note 4) 12,625 -
Liabilities settled (5,503) (4,435)
----------------------------------------------------------------------------
Balance, end of year $ 89,602 $ 65,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. UNITHOLDERS EQUITY

Unitholders' Capital

The Trust is authorized to issue 500 million trust units of which 90 million units were issued and outstanding as at December 31, 2007 (December 31, 2006 - 78 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 or the principal market on which the units are quoted for trading on the date that the trust units are tendered for redemption.



Units Issued:
2007 2006
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of the year 77,971 $ 824,986 73,977 $ 753,585
Issued for cash 10,246 125,001 - -
Issued under management agreement
restructuring (Note 5) - - 1,592 30,000
Less issue expenses - (7,134) - (29)
Issued from Distribution
Reinvestment Plan 2,277 26,735 2,402 41,430
----------------------------------------------------------------------------
Balance, end of the year 90,494 $ 969,588 77,971 $ 824,986
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 in additional units of the Trust 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 Premium DRIP may be 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, 2005 $ 532,891
2006 distributions 169,589
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2006 $ 702,480
2007 distributions 158,601
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2007 $ 861,081
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 excludes the convertible debentures as the trust units potentially issuable on the conversion of the convertible debentures are anti-dilutive for the three months and year ended December 31, 2007. Total weighted average trust units issuable on conversion of the convertible debentures and excluded from the diluted net income per trust unit calculation for the three months and year ended December 31, 2007 were 7,142,857 and 2,465,753 respectively. As at December 31, 2007, the total convertible debentures outstanding were immediately convertible to 7,142,857 trust units.

Deficit

The deficit is comprised of the following:



2007 2006
------------------------------------------------------
Accumulated income $ 390,451 $ 333,994
Accumulated cash distributions (861,081) (702,480)
------------------------------------------------------
Deficit, end of year $ (470,630) $ (368,486)
------------------------------------------------------
------------------------------------------------------


The Trust has historically paid cash distributions in excess based on cash flow generated in the period whereas accumulated non-cash items such as depletion, depreciation, accretion, on derivative contracts.



Accumulated Other Comprehensive Income

2007 2006
----------------------------------------------------------------------------
Balance, beginning of year $ - $ -
Fair value of derivative instruments on transition
to new accounting standards, net of tax of $1,349
(Note 3) 3,172 -
Reclassification to net income in period, net of
tax $1,349 (Note 3) (3,172) -
----------------------------------------------------------------------------
Balance, end of year $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. 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 income taxes as follows:



2007 2006
----------------------------------------------------------------------------
Income before taxes $ 52,837 $ 58,789

Statutory income tax rate 33.4% 39.0%
Expected income tax expense 17,648 22,928

Increase (decrease) resulting from:
Non-deductible Crown charges - 8,471
Resource allowance - (9,208)
Alberta Royalty Tax Credit 17 (39)
Valuation allowance 32 200
Net income of the Trust (23,672) (24,937)
Other 2,397 968
Effect of future tax rate reductions (42) 208
----------------------------------------------------------------------------
Current and future income tax recovery (3,620) (1,409)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The future income tax asset is comprised of:

2007 2006
----------------------------------------------------------------------------
Property, plant and equipment $ (3,768) $ (6,794)
Future tax liability resulting from different year ends (2,570) -
Non-capital tax loss carry forward 4,396 3,197
Asset retirement obligations 6,985 7,889
Other 2,921 400
----------------------------------------------------------------------------
7,964 4,692
Valuation allowance (1,266) (1,347)
----------------------------------------------------------------------------
Future income tax asset $ 6,698 $ 3,345
----------------------------------------------------------------------------

Current asset $ 2,602 $-
Long-term asset $ 4,096 $ 3,345
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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. At December 31, 2007, the book amounts of the Trust's assets and liabilities exceed the tax basis by $213.5 million (2006 - $192.2 million).

The Trust has non-capital loss carry forwards of $17.0 million of which $9.1 million expire between 2009 and 2015, and $7.9 million expire between 2025 and 2027.

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 substantively enacted for purposes of Canadian generally accepted accounting principles. Accordingly, the Trust measured future income tax assets and liabilities associated with this new tax. There is no impact on the future tax recognized in the financial statements, resulting from the implementation of this tax legislation as it is expected that all taxable temporary differences of the Trust will reverse prior to January 1, 2011, the date the taxation changes take effect. Accordingly, all taxable temporary differences have been recognized at a zero taxation rate. The scheduling of the reversal of temporary differences is based on management's best estimates and current assumptions, which may change.

13. DERIVATIVE CONTRACTS AND RISK MANAGEMENT

Commodity Price Risk Management

NAL employs risk management practices to assist in managing cash flows and support capital programs and distributions. NAL's management is authorized to hedge up to 50% of its estimated annual net of production. NAL's risk management programs tend to be scaled-in over time using a combination of swaps and collars.

NAL currently has the following WTI oil contracts in place for 2008, denominated in U.S. dollars:



Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
January-June 2-way 100 18,200 75.00 81.00 -
January-December 2-way 100 36,600 85.00 100.00 -
January-December 2-way 100 36,600 83.00 100.00 -
July-December 2-way 100 18,400 75.00 85.50 -
January-June 2-way 100 18,200 73.00 79.00 -
January-June 2-way 100 18,200 72.00 78.00 -
January-June 2-way 100 18,200 71.00 78.50 -
January 2-way 100 3,100 70.50 75.50 -
January-June 2-way 100 18,200 70.00 76.25 -
January 2-way 100 3,100 70.00 75.00 -
April-June 2-way 100 9,100 69.00 74.25 -
January-June 2-way 100 18,200 69.00 74.00 -
January-June 2-way 200 36,400 68.50 73.00 -
January-March 2-way 100 9,100 68.00 74.35 -
January-March 2-way 100 9,100 68.00 73.60 -
January-March 2-way 100 9,100 66.00 71.90 -
January-June 2-way 200 36,400 64.00 72.26 -
January-June 2-way 100 18,200 70.00 75.05 -
January-December 2-way 100 36,600 76.00 87.00 -
July-December 2-way 100 18,400 94.00 100.50 -
July-December 2-way 100 18,400 92.00 101.50 -
----------------------------------------------------------------------------
Weighted Average Collars 407,800 74.93 83.58 -
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Volume Total Bought Put Sold Call Swap
Volume
----------------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
SWAPS
January-December swap 100 36,600 - - 73.50
April-December swap 100 27,500 - - 94.00
January-December swap 100 36,600 - - 92.18
January-December swap 100 36,600 - - 87.10
January-December swap 100 36,600 - - 79.10
January-December swap 100 36,600 - - 71.00
January-December swap 100 36,600 - - 80.75
March-October swap 100 24,500 - - 88.10
July-December swap 100 18,400 - - 94.50
July-December swap 100 18,400 - - 94.04
July-December swap 100 18,400 - - 92.00
July-December swap 100 18,400 - - 98.50
July-December swap 100 18,400 - - 98.25
July-December swap 100 18,400 - - 98.10
July-December swap 100 18,400 - - 97.25
July-December swap 100 18,400 - - 96.75
----------------------------------------------------------------------------
Weighted Average Swaps 418,800 - - 87.40
----------------------------------------------------------------------------

NAL currently has the following WTI oil contracts in place for 2008,
denominated in Canadian dollars:

Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
----------------------------------------------------------------------------
COLLARS
July-December 2-way 100 18,400 85.00 94.40 -
July-December 2-way 100 18,400 85.00 96.00 -
January-December 2-way 100 36,600 87.10 97.35 -
February-June 2-way 100 15,100 71.75 76.88 -
February-December 2-way 100 33,500 72.40 77.54 -
----------------------------------------------------------------------------
Weighted Average 2-way 122,000 80.53 88.73 -
----------------------------------------------------------------------------

SWAPS
January-December swap 100 36,600 - - 84.90
January-December swap 100 36,600 - - 90.05
April-June swap 100 9,100 - - 71.55
February-December swap 100 33,500 - - 90.15
February-December swap 100 33,500 - - 90.05
April-December swap 100 27,500 - - 90.20
January-December swap 100 36,600 - - 89.05
January-December swap 100 36,600 - - 87.00
January-December swap 100 36,600 - - 83.80
January-June swap 100 18,200 - - 77.07
January-June swap 200 36,400 - - 75.05
January-December swap 100 36,600 - - 73.55
January-March swap 200 18,200 - - 70.00
July-December swap 100 18,400 - - 93.00
January-June swap 100 18,200 - - 73.77
July-December swap 100 18,400 - - 98.50
January-December swap 100 36,600 - - 90.70
April-December swap 100 27,500 - - 91.00
March-October swap 100 24,500 - - 87.50
January-June swap 100 18,200 - - 84.90
April-December swap 100 27,500 - - 96.50
April-December swap 100 27,500 - - 97.00
July-December swap 100 18,400 - - 94.00
July-December swap 200 36,800 - - 97.00
----------------------------------------------------------------------------
Weighted Average Swaps 668,000 - - 87.10
----------------------------------------------------------------------------


NAL currently has the following AECO natural gas contracts in place for 2008:



Volume Total Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
January-March 2-way 1,000 91,000 8.40 10.15 -
January-March 2-way 2,000 182,000 8.40 10.25 -
January-March 2-way 1,000 91,000 8.40 10.40 -
January-March 2-way 1,000 91,000 8.00 9.40 -
November-December 2-way 1,000 61,000 7.30 8.50 -
November-December 2-way 1,000 61,000 7.75 9.05 -
November-December 2-way 1,000 61,000 7.55 9.10 -
November-December 2-way 1,000 61,000 7.55 9.05 -
November-December 2-way 1,000 61,000 7.30 8.60 -
November-December 2-way 1,000 61,000 7.85 9.25
November-December 2-way 1,000 61,000 8.00 9.50 -
----------------------------------------------------------------------------
Weighted Average 2-ways 882,000 7.98 9.57 -
----------------------------------------------------------------------------


Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
SWAPS
January-March swap 1,000 91,000 - - 8.90
January-March swap 1,000 91,000 - - 9.13
January-December swap 2,000 732,000 - - 7.60
April-December swap 1,000 275,000 - - 7.40
January-December swap 2,000 732,000 - - 7.40
April-December swap 1,000 275,000 - - 7.31
January-December swap 2,000 732,000 - - 7.26
April-December swap 1,000 275,000 - - 7.05
February-December swap 1,000 335,000 - - 7.20
January-March swap 1,500 136,500 - - 7.20
March-December swap 1,000 306,000 - - 7.10
April-December swap 1,000 275,000 - - 7.15
April-December swap 1,000 275,000 - - 7.10
April-December swap 1,000 275,000 - - 7.05
April-December swap 1,000 275,000 - - 7.23
April-October swap 1,000 214,000 - - 7.35
April-October swap 1,000 214,000 - - 7.60
April-October swap 1,000 214,000 - - 7.85
April-December swap 1,000 275,000 - - 7.30
April-October swap 1,000 214,000 - - 7.65
April-October swap 1,000 214,000 - - 7.43
March-December swap 1,000 306,000 - - 7.10
April-October swap 1,000 214,000 - - 7.15
April-October swap 1,000 214,000 - - 7.09
April-October swap 1,000 214,000 - - 7.80
November-December swap 1,000 61,000 - - 8.66
----------------------------------------------------------------------------
Weighted Average Swaps 7,434,500 - - 7.38
----------------------------------------------------------------------------


For 2009, NAL has the following WTI contracts in place, denominated in U.S.
dollars:


Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
January-December 2-way 100 36,500 92.00 101.50 -
January-June 2-way 100 18,100 94.00 100.50 -
----------------------------------------------------------------------------
Weighted Average 2-ways 54,600 92.66 101.17 -
----------------------------------------------------------------------------


Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
SWAPS
January-June Swap 100 18,100 - - 97.25
January-December Swap 100 36,500 - - 96.75
----------------------------------------------------------------------------
Weighted Average Swaps 54,600 - - 96.92
----------------------------------------------------------------------------

For 2009, NAL has the following WTI contracts in place, denominated in
Canadian dollars:


Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbl/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
----------------------------------------------------------------------------
SWAPS
January-September swap 100 27,300 - - 96.50
January-December swap 200 73,000 - - 97.00
January-September swap 100 27,300 - - 97.00
----------------------------------------------------------------------------
Weighted Average Swaps 127,600 - - 96.89
----------------------------------------------------------------------------


For 2009, NAL has the following AECO natural gas contracts in place:


Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
January-March 2-way 1,000 90,000 8.00 9.50 -
January-March 2-way 1,000 90,000 7.75 9.05 -
January-March 2-way 1,000 90,000 7.85 9.25 -
January-March 2-way 1,000 90,000 7.55 9.10 -
January-March 2-way 1,000 90,000 7.55 9.05 -
January-March 2-way 1,000 90,000 7.30 8.60 -
January-March 2-way 1,000 90,000 7.30 8.50 -
----------------------------------------------------------------------------
Weighted Average 2-way 630,000 7.61 9.01 -
----------------------------------------------------------------------------


Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
SWAPS
January-March swap 1,000 90,000 - - 7.40
January-March swap 1,000 90,000 - - 7.05
January-March swap 1,000 90,000 - - 7.05
January-March swap 1,000 90,000 - - 7.10
January-March swap 1,000 90,000 - - 7.15
January-March swap 1,000 90,000 - - 7.23
January-March swap 1,000 90,000 - - 7.31
January-March swap 1,000 90,000 - - 7.30
January-March swap 1,000 90,000 - - 8.66
----------------------------------------------------------------------------
Weighted Average Swaps 810,000 - - 7.36
----------------------------------------------------------------------------


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

The fair value of the Trust's convertible debentures at December 31, 2007 was $98.0 million, based on market price.

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.



2007 2006
----------------------------------------------------------------------------
Current unrealized gain on derivative contracts $ 3,389 $-
Current unrealized loss on derivative contracts (12,973) -
----------------------------------------------------------------------------
Fair value of derivative contracts $ (9,584) $-
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On transition to Section 3865 on January 1, 2007, the fair value of the outstanding contracts of $4.5 million was recorded in accumulated other comprehensive income, with related tax of $1.3 million, and was transferred to net income over the term of the respective contracts. During 2007, the full amount of $4.5 million has been reclassified to net income and is included in the gain (loss) on derivative contracts.

As at December 31, 2007, the total fair value of derivative contracts was a liability of $9.6 million. The change in the fair value for the year of $14.1 million has been recognized as an unrealized loss in the statement of income.

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
-----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Unrealized loss, beginning
of period $ (1,371) $ - $ - $ -
Unrealized gain on adoption
of new accounting standards
(Note 3) - - 4,521 -
Unrealized loss, end of period (9,584) - (9,584) -
----------------------------------------------------------------------------
Unrealized loss (8,213) - (14,105) -
Realized gain (loss) in the period (5,510) 1,798 (2,435) 3,375
Reclassification from other
comprehensive income 874 - 4,521 -
----------------------------------------------------------------------------
Gain (loss) on derivative
contracts $(12,849) $ 1,798 $(12,019) $ 3,375
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Credit Risk Management

Accounts receivable includes 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. The credit risk associated with NAL Resources is also considered to be minimal as amounts owing are from actual collections of oil and gas sales.

Interest Rate Risk

The Trust is exposed to interest rate risk to the extent that bank debt is at a floating interest rate.

Foreign Exchange Risk

The Trust is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices.

14. COMMITMENTS

At December 31, 2007 the Trust had the following contractual obligations and commitments:



2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Office lease(1) $3,672 $3,672 $3,366 $ - $ - $ -
Transportation agreement 1,123 1,123 84 - - -
Processing agreement(2) 469 446 428 414 401 384
Drilling rigs(3) 494 - - - - -
Retention bonus(4) 578 - - - - -
----------------------------------------------------------------------------
Total $6,336 $5,241 $3,878 $ 414 $ 401 $ 384
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Represents the full amount of office lease commitments, including office
space acquired with the Seneca acquisition; 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) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.


15. SUBSEQUENT EVENT

On February 27, 2008, the Trust completed the acquisition all of the issued and outstanding common shares of two private oil and gas companies ("Private Companies"). Total consideration is approximately $115 million before closing adjustments, consisting of approximately 2.4 million trust units and $86.25 million in cash.

In addition, the Trust entered into an agreement with a wholly owned subsidiary of MFC, to contribute the assets and liabilities of the Private Companies to a limited partnership owned 50 percent by the Trust and 50 percent by MFC. MFC acquired its 50 percent interest in the limited partnership by payment in cash for one half of the purchase price for the Private Companies.

Consequently, the total acquisition cost to the Trust for its 50 percent interest in the acquired companies is approximately $57.5 million, comprising approximately 2.4 million trust units and $28.75 million in cash.



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

TRADING PERFORMANCE

For the Quarter Ended Full Year
31-Dec-07 30-Sep-07 31-Dec-06 30-Sep-06 2007 2006
----------------------------------------------------------------------------
PRICE
High $ 12.90 $ 13.65 $ 18.74 $ 21.70 $ 13.80 $ 21.70
Low $ 10.94 $ 11.52 $ 11.80 $ 16.14 $ 10.86 $ 11.80
Close $ 11.60 $ 12.22 $ 12.31 $ 17.57 $ 11.60 $ 12.31
Volume 18,375,644 17,663,336 27,691,472 12,786,792 68,024,233 65,412,678
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NAL Oil & Gas Trust is an open-ended investment trust that generates distributions through the acquisition, development, production and marketing of oil, natural gas and natural gas liquids. The Trust owns high quality assets in Alberta, Saskatchewan and Ontario. Trust units trade on the Toronto Exchange under the symbol "NAE.UN".

Contact Information

  • NAL Oil & Gas Trust
    Gordon Currie
    Manager, Investor Relations
    (403) 294-3620 or Toll Free: 1-888-223-8792
    (403) 515-3407 (FAX)
    Email: investor.relations@nal.ca
    Website: www.nal.ca