NAL Oil & Gas Trust
TSX : NAE.UN

NAL Oil & Gas Trust

May 01, 2008 16:30 ET

NAL Oil & Gas Trust Reports Higher First Quarter Production and Cash Flow and Announces Increased Capital Program

CALGARY, ALBERTA--(Marketwire - May 1, 2008) - NAL Oil & Gas Trust ("NAL" or the "Trust") (TSX:NAE.UN) today announced its financial and operational results for the first quarter ended March 31, 2008. All amounts are in Canadian dollars unless otherwise stated.

Summary of First Quarter

- Production volumes increased by 21 percent in the first quarter to 23,601 boe/d, up from 19,561 in the first quarter 2007, driven primarily by the September 1, 2007 gas focused acquisition of Seneca Energy Canada Inc. ("Seneca"). Production mix was 52 percent crude oil and natural gas liquids and 48 percent natural gas compared to 59 percent and 41 percent a year earlier.

- Funds from operations equaled $76.2 million, an increase of 41 percent from $54.2 a year earlier, due to higher volumes and netbacks per boe ($41.86 versus $35.72 in the first quarter 2007). On a per unit basis, $0.83 ($0.79 fully diluted) was 20 percent higher compared to $0.69 ($0.69 fully diluted) despite the number of units outstanding increasing by 17 percent year over year.

- Capital expenditures in the first quarter were $29.3 million, excluding property and corporate acquisitions, compared to $27.0 million a year earlier. Property acquisitions were $6.9 million in the first quarter 2008.

- The Trust completed the corporate acquisitions of Tiberius Exploration Inc. and Spear Exploration Inc. on February 27, 2008 for a net purchase price of $58.1 million, which added light oil production in Southeast Saskatchewan directly adjacent to NAL's core holdings in the area.

- Distributions per unit remained consistent at $0.48 in the quarter, and payout ratio decreased year over year from 69 percent to 58 percent.

- Net debt was $309.3 million at March 31, 2008, compared to $291.1 million at December 31, 2007. The increase is a result of the Tiberius Exploration Inc. and Spear Exploration Inc. acquisitions slightly offset by higher funds from operations. Debt to cash flow excluding convertible debentures equaled 1.29 times trailing 12 months funds from operations and approximately 1.0 times NAL's New Base outlook for 2008 cash flow based upon $95 WTI, $7.50 per GJ AECO and a 1.00 exchange rate.

2008 Guidance and Outlook

NAL's first quarter 2008 performance is on track with its guidance and expectations. After adjusting for acquisitions, production of 23,601 boe/d and $29.3 million in capital expenditures, are in line with January 2008 first quarter guidance of 23,200 boe/d and $26.0 million, excluding corporate and property acquisitions. NAL's Board of Directors has approved an increase in capital expenditures from $113 million to $140 - 150 million. This investment is focused in Saskatchewan with $15 million new capital to exploit NAL's Tiberius and Spear acquisition, new land purchases, more wells on 86 net sections of Bakken acreage and other multi-zone prospects. Increased capital is also targeted on Cardium oil and Mannville gas in Alberta and on NAL's higher potential Permian gas play in British Columbia, tieing in our A26 discovery and participating in three new wells in 2008.

As to updated guidance for full year 2008, NAL provides the following ranges:



January 23, 2008 May 1, 2008(1)
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Production (boe/d) 23,000 - 24,000 24,400 - 24,800
Capital expenditures ($MM) $110 - 120 $140 - 150
Operating costs ($/boe) 9.50 - 9.80 9.50 - 9.80
G&A ($/boe) 1.90 - 2.10 1.90 - 2.10
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(1) Includes non-controlling interest.


As to the 2008 outlook, NAL's Base Case has been updated to reflect a New Base - May 2008 and an Upside Sensitivity representing higher pricing commodity prices and volumes.



Base Case New Base Upside
2008 Forecast Update (Dec. '07) (May '08)(1)(2) Sensitivity(1)(2)
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WTI oil price (U.S.$/bbl) 80.00 95.00 105.00
AECO natural gas price
(C$/GJ) 6.50 7.50 8.00
Exchange rate (Cdn/USD) 1.00 1.00 1.00
Capital expenditures (C$ MM) 113 140 150
Production (Mboe/d) 23,500 24,600 24,800
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(1) Including February 2008 acquisitions of Tiberius/Spear.
(2) Includes non-controlling interest.


Base Case New Base Upside
2008 Financial Forecast (Dec. '07) (May '08)(1)(3) Sensitivity(1)(3)
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Funds from operation ($MM) 248 316 333
Funds from operation ($/unit
basic) $2.70 $3.37 $3.56
Funds from operation ($/unit
fully diluted) $2.50 $3.13 $3.30
Payout ratio (%) 71 57 54
Payout with capital (%) 117 99 97
Payout with DRIP (%) 105 90 88
Debt / cash flow (%) 1.2 / 1.6(2) 0.9 / 1.2(2) 0.8 / 1.1(2)
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(1) Includes realized hedging gains (losses) and Tiberius/Spear
acquisitions.
(2) Includes convertible debentures.
(3) Excludes non-controlling interest.


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 3:00 p.m. MST (5:00 p.m. EST) on Thursday, May 1, 2008, NAL will hold a conference call to discuss the first quarter 2008 results. Mr. Andrew Wiswell, President and CEO, will host the conference call with other members of the Management Team. The call is open to analysts, investors, and all interested parties. If you wish to participate, call 1-866-300-4047 toll free across North America. The conference call will also be accessible by webcast at http://events.onlinebroadcasting.com/nal/050108/index.php

A recorded playback of the call will be available until May 7, 2008 by calling 1-800-408-3053, reservation 3259648.

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

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.



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

-------------------------------------------------
March 31, 2008 March 31, 2007 December 31, 2007
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FINANCIAL
Gross revenue, net of
royalties $89,611 $71,231 $86,262
Cash flow from operating
activities 70,561 52,966 45,111
Cash flow per unit - basic 0.77 0.68 0.50
Cash flow per unit -
diluted 0.73 0.68 0.48
Funds from operations 76,220 54,234 59,537
Funds from operations per
unit - basic 0.83 0.69 0.66
Funds from operations per
unit - diluted 0.79 0.69 0.63
Net income 13,733 16,710 10,556
Distributions declared 44,025 37,606 43,340
Distributions per unit 0.48 0.48 0.48
Payout ratio:
based on cash flow from
operating activities 62% 71% 96%
based on funds from
operations 58% 69% 73%
Units outstanding (000's)
Period end 93,519 78,534 90,494
Weighted average 91,717 78,258 90,194
Capital expenditures 36,193 27,058 39,194
Corporate acquisitions 58,107 - -
Net debt(1) 309,347 227,014 291,059
Convertible debentures (at
face value) 100,000 - 100,000

OPERATING
Daily production(2)
Crude Oil (bbl/d) 10,254 9,367 9,722
Natural gas (mcf/d) 67,210 48,186 71,067
Natural gas liquids
(bbl/d) 2,145 2,163 2,090
Oil equivalent (boe/d) 23,601 19,561 23,656

OPERATING NETBACK (boe)
Revenue before hedging
gains (losses) 67.61 53.56 56.59
Royalties (13.65) (11.54) (11.78)
Operating costs (9.91) (8.02) (9.90)
Other income 0.37 0.43 0.32
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Operating netback before
hedging 44.42 34.43 35.23
Hedging gains (losses) (2.56) 1.29 (2.53)
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Operating netback 41.86 35.72 32.70
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(1) Excluding convertible debentures.
(2) Includes royalty income volumes.


MANAGEMENT'S DISCUSSION AND ANALYSIS

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

NON-GAAP FINANCIAL MEASURES

Throughout this discussion and analysis, Management uses the terms funds from operations, funds from operations per unit, payout ratio, cash flow from operations per unit, net debt to trailing 12 month cash flow, operating netback and cash flow netback. These are considered useful supplemental measures as they provide an indication of the results generated by the Trust's principal business activities. Management uses the terms to facilitate the understanding of the results of operations 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 and cash flow from operation per unit are calculated using the weighted average units outstanding for the period.

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

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

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



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$(000s) Three months ended March 31
-----------------------------
2008 2007
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Cash flow from operating activities 70,561 52,966
Add back change in non-cash working capital 5,659 1,268
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Funds from operations 76,220 54,234
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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 the 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; the ability to obtain industry partner and other third party consents and approvals, when required; failure to realize the anticipated benefits of acquisitions; general economic conditions in Canada, the United States and globally; fluctuations in foreign exchange or interest rates; changes in government regulation of the oil and gas industry, including environmental regulation; changes in the royalty rates, particularly in light of the Alberta government's royalty 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. The forward-looking information contained in the MD&A is expressly qualified by this cautionary statement.

ACQUISITION OF TIBERIUS EXPLORATION INC. AND SPEAR EXPLORATION INC.

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

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

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

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

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

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

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

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



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Net assets
Acquired Total Disposition Trust, net Net to
($(000s): Acquisition to Manulife Acquisition NPI(1) Trust
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Cash $ 9,734 $ - $ 9,734 $ - $ 9,734
Working capital
deficiency (4,007) - (4,007) - (4,007)
Notes receivable,
net from MFC - (3,750) (3,750) 49,599 45,849
Property, plant
and equipment 111,258 - 111,258 (49,599) 61,659
Future income
taxes (23,692) 11,736 (11,956) - (11,956)
Asset
retirement
obligations (1,636) - (1,636) - (1,636)
Goodwill 24,557 (12,036) 12,521 - 12,521
Non-controlling
interest - (54,057) (54,057) - (54,057)
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$ 116,214 $ (58,107) $ 58,107 $ - $ 58,107
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Consideration:
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Cash $ 86,118 $ (57,807) $ 28,311 $ - $ 28,311
Issuance of
trust units 29,496 - 29,496 - 29,496
Acquisition
costs 600 (300) 300 - 300
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$ 116,214 $ (58,107) $ 58,107 $ - $ 58,107
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(1) Net profit interest agreement entered into with MFC in exchange for a
note receivable.


The operations attributable to the Tiberius and Spear assets for March 2008,
were as follows:

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$(000s) Month of Net Impact
March 2008(1) to Trust(2)
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Total production volumes (boes) 38,680 19,340

Oil, natural gas and liquid sales $ 3,910 $ 1,955
Royalties (538) (269)
Operating costs (321) (161)
General and administrative (28) (14)
Unit-based incentive compensation (20) (10)
Interest income, net 646 323
Depletion, depreciation and accretion (199) (99)
Net profit interest expense (2,957) (1,478)
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Net income $ 493 $ 247
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(1) Total March results of the Partnership consolidated into the results of
the Trust.
(2) Net impact to the Trust, removing 50 percent of results attributable to
MFC.


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

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



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$(000s) Three months ended March 31
----------------------------
2008 2007
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Net profits interest expense $1,478 $-
Share of net income attributable to MFC 247 -
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$1,725 $-
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EXPLORATION & DEVELOPMENT ACTIVITIES

The Trust spent $22.5 million on drilling operations during the first quarter of 2008, versus $23.7 million in 2007 and participated in the drilling of 43 (18.4 net) wells during the first quarter of 2008, compared to 37 (14.54 net) wells in 2007. First quarter drilling achieved a 100 percent success rate. This activity was supported by up to seven operated drilling rigs and 14 service rigs operating during the quarter.

Historically, NAL's assets have been concentrated in Southeast Saskatchewan and Central Alberta. The purchase of Seneca in 2007 added a new core area at Monkman in Northeast B.C. and expanded the Trust's W4M operations in the Hanna to Drumheller area of Alberta. The Tiberius / Spear acquisition added to our Nottingham / Alida operations in Southeast Saskatchewan.



First Quarter Drilling Activity

Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
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Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 24.0 12.73 5.0 4.2 0.0 0.0 0.0 0.0 29 16.9
Non-operated wells 8.0 0.37 6.0 1.1 0.0 0.0 0.0 0.0 14 1.5
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Total wells drilled 32.0 13.1 11.0 5.3 0.0 0.0 0.0 0.0 43 18.4
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Southeast Saskatchewan (Alida , Nottingham, Stoughton, Rosebank, Steelman, Elswick)

There were 18 (6.83 net) horizontal oil wells drilled during the quarter, of which 13 were Mississippian and five were Bakken. Mississippian drilling was spread across Alida, Nottingham and Elswick and the results are on track with forecast. Three Stoughton Bakken wells were brought on with three month average production rates of greater than 200 boe/d per well. The Trust has more than 86 net sections of Bakken rights in southeast Saskatchewan, which will be evaluated and developed taking a measured approach using the newest information from offset drills and regional geological work, supported by our extensive 2D and 3D seismic data base.

Two successful wells were drilled on the recently acquired Tiberius lands and construction of the infrastructure to connect production from the area into Alida / Nottingham has started. There was approximately 250 boe/d of production shut in over break up due to road bans which restricted trucking from many of the single well batteries on these new properties. Most of the Tiberius production will be pipeline connected by July, which will significantly reduce operating costs and increase operating efficiency.

Pipeline capacity on Enbridge continues to be tight but our extensive operations and multiple delivery points on the system enables us the flexibility to minimize shut in production.

Engineering and procurement work is nearing completion for the Nottingham gas plant expansion. It is expected that equipment delivery and construction will commence in the fourth quarter, with commissioning at year end. This expansion will increase capacity from 13 mmcf/d to 18 mmcf/d and NAL has plans to fill this space with working interest gas from development as well as attract significant third party solution gas through our extensive pipeline network in the area. The Trust continues to look at new ways to leverage the significant infrastructure it controls in the area. Large battery consolidations and blending operations have been brought on line and will be expanded in the Elswick area this year, while other blending operations are being evaluated through the remainder of 2008. Custom processing and blending operations contribute significant incremental value for the Trust.

It is forecast that there will be three rigs working continuously for the remainder of the year, drilling between 25 - 30 gross wells. These wells will be a combination of Mississippian development, Bakken and some limited new pool tests on emerging plays.

Central Alberta (Garrington, Westward Ho, Medicine River, Sylvan Lake)

There were 11 (4.49 net) wells drilled during the quarter, of which six targeted oil wells with three of these wells being infill Cardium oil wells at Garrington. NAL has experienced continued success with results ranging between 30 - 100 boe/d which has validated further down spacing potential along this trend. Recompletion work in the Cardium has also continued to be successful in the area adding cost effective reserves and production from existing wellbores.

Non-operated drilling (Trust 15 percent) in the Leduc area encountered significant oil pay with completion and production expected early in the second quarter.

The Trust expects to drill an additional 10 - 15 wells in this area for the remainder of the year targeting stacked potential in the Mannville (Glauconite, Ostracod, Ellerslie), as well as a horizontal test in the Cardium utilizing horizontal frac technology and a follow up well to the successful Leduc test.

Gas Focus Areas (Hanna, Drumheller, Pine Creek, Nevis Lacombe)

There were 13 (6.97 net) wells drilled during the quarter. Two successful infill oil wells (65 boe/d/well) were drilled in the Stanmore Glauconite oil pool and an additional well was converted to injection. Facility design is under way to increase fluid handling at the battery to accommodate additional water flood and infill drilling plans.

Other operated drilling success included two Glauconite oil wells at Hussar with testing and tie in to be completed by the end of April. A Pine Creek Gething well has been tied in at 700 mcf/d, and two Mannville gas wells are waiting on completion in Hanna.

A significant non-operated tie in was completed at Peppers 16-16 (Trust 19 percent) with production on stream in early April at 5 mmcf/d gross raw. Gathering system constraints will be evaluated in order to maximize production as the well deliverability during the test was 10 mmcf/d. Five non-operated low working interest shallow gas wells were also drilled and are in various stages of completion and tie in.

In all areas of operations, the Trust has 600 boe/d of behind pipe production awaiting tie in during the second quarter, and it is expected that the Trust will be drilling 8-10 wells targeting the Cardium in Pine Creek and Willisden Green for the remainder of the year. There will also be a sustained recompletion program across the area with anticipated spending of $2 million.

Northeast British Columbia (Monkman)

At Monkman, NAL continues to partner with Talisman to add production and pursue opportunities. The a-26-E well (Trust WI 20 percent) drilled in 2007 was tested from two intervals with a combined rate of 60 mmcf/d of raw gas. The well is expected to be on stream by the end of April at a rate of 30 - 35 mmcf/d gross raw (5 - 6 mmcf/d net sales to the Trust), which is in line with expectations. Additional throughput will depend on commingling approval and processing capacity through the Spectra Pine River plant.

As to our 2008 exploration programs, c-21-K (Trust 10 percent WI) continued to drill through the quarter with rig release expected in the fourth quarter. The Trust has recently spudded a-37-F (Trust 10 percent WI - April Spud) and one additional location expected to commence drilling in July (Trust 20 percent WI), which will complete the 2008 drilling program. NAL is not forecasting production from these exploration wells to commence during 2008.

CAPITAL EXPENDITURES

Capital expenditures for the quarter ended March 31, 2008 totaled $36.2 million (including $6.9 million of property acquisitions) compared with $27.1 million for the quarter ended March 31, 2007.



Capital Expenditures ($000s)
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Three months ended March 31
-----------------------------
2008 2007
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Drilling, completion and production equipment 22,530 23,650
Plant and facilities 3,231 2,252
Seismic 756 259
Land 994 251
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Total exploitation and development 27,511 26,412
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Office equipment 315 43
Capitalized G&A 942 767
Capitalized unit-based compensation 555 (139)
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Total other capital 1,812 671
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Property acquisitions (dispositions), net 6,870 (25)
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Total capitalized expenditures 36,193 27,058
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PRODUCTION

First quarter 2008 production of 23,601 boe/d exceeded production of 19,561 boe/d in the comparable period of 2007 by 21 percent. The increase is attributable to Seneca production of 4,278 boe/d, which was acquired effective September 1, 2007. In addition, Tiberius and Spear added production of 424 boe/d, which was acquired effective February 27, 2008.



Average Daily Production Volumes
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Three months ended March 31
-----------------------------
2008(1) 2007(1)
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Oil (bbl/d) 10,254 9,367
Natural gas (Mcf/d) 67,210 48,186
NGLs (bbl/d) 2,145 2,163
Oil equivalent (boe/d) 23,601 19,561
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(1) Volumes include royalty income volumes.


The oil equivalent volumes of 23,601 boe/d for the first quarter of 2008 include 212 boe/d attributable to the non-controlling interest in the Tiberius and Spear properties. The Trust's production, after deducting the non-controlling interest, is 23,389 boe/d for the first quarter of 2008, slightly exceeding first quarter guidance of 23,200 boe/d.

Oil and natural gas liquids totaled 52 percent of production in the first quarter with natural gas increasing to 48 percent due to the natural gas weighted Seneca acquisition.



Production Weighting
---------------------------------------------------------------------------
Three months ended March 31
-----------------------------
2008 2007
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Oil 43% 48%
Natural gas 48% 41%
NGLs 9% 11%
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REVENUE

Gross revenue from oil, natural gas and natural gas liquids sales, after transportation costs, totaled $145.2 million for the three months ended March 31, 2008, 54 percent higher than the first quarter of 2007. The increase is due to a 21 percent increase in production as a result of the Seneca acquisition, and a 26 percent increase in average price per boe. The Trust's realized commodity prices increased for all production, highlighted by a 46 percent quarter over quarter increase in realized crude oil prices.



Revenue
---------------------------------------------------------------------------
Three months ended March 31
-----------------------------
2008 2007
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Revenue(1) ($000s) 145,209 94,284
$/boe 67.61 53.56
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(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 first quarter average realized Canadian crude oil price per barrel, net of transportation costs, was $89.90, as compared to $61.60 for the comparable quarter of 2007. The increase in realized price quarter over quarter of 46 percent, or $28.30/bbl, was primarily driven by a 68 percent increase in WTI (U.S.$/bbl) over the comparable period, offset by a strengthening Canadian dollar.

For the first quarter of 2008, NAL's crude oil differential compared to WTI priced in Canadian dollars were consistent year over year at 91 percent of WTI. The differential is calculated as realized price as a percentage of WTI stated in Canadian dollars.

Natural gas liquids averaged $63.57/bbl in the first quarter of 2008, a 40 percent increase from $45.36/bbl realized in 2007.

NATURAL GAS MARKETING

Approximately 78 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 22 percent tied to NYMEX or other indexed reference prices.

For the three months ended March 31, 2008, the Trust's natural gas sales averaged $7.98/mcf compared to $7.58/mcf in the comparable period of 2007, an increase of five percent. The quarter over quarter increase in gas prices was attributable to an eight percent increase in the benchmark AECO daily spot prices. As well, prices for Lake Erie natural gas increased to $9.23/mcf in the first quarter of 2008, compared to $8.75/mcf in 2007, an increase of five percent.

Lake Erie production accounted for five percent of the Trust's natural gas production in the first quarter of 2008, compared to eight percent in the same period of 2007; the decrease is attributable to the gas weighted Seneca acquisition effective September 1, 2007. Natural gas sales from the Lake Erie property receive a higher price due to the close proximity to the Ontario and Northeastern U.S. markets.



Average Pricing
(net of transportation charges)
---------------------------------------------------------------------------
Three months ended March 31
-----------------------------
2008 2007
---------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 97.90 58.16
NAL average oil (Cdn$/bbl) 89.90 61.60
NAL natural gas liquids (Cdn$/bbl) 63.57 45.36

Natural Gas (Cdn$/Mcf)
AECO - daily spot 7.97 7.41
AECO - monthly 7.06 7.46
NAL Western Canada natural gas 7.93 7.48
NAL Lake Erie natural gas 9.23 8.75
NAL average natural gas 7.98 7.58

NAL Oil Equivalent before hedging (Cdn$/boe - 6:1) 67.61 53.56
Average Foreign Exchange Rate (Cdn$/U.S.$) 1.004 1.172
---------------------------------------------------------------------------
---------------------------------------------------------------------------


RISK MANAGEMENT

NAL employs risk management practices to assist in managing cash flows and to support capital programs and distributions. NAL's management has authorization to hedge up to 50 percent of budgeted total production, net of royalties, for a period of up to two years. Management's practice is to hedge more near-term volumes on a rolling 12 month forward basis with less volumes hedged in the 13 - 24 month forward period. NAL's risk management programs are scaled in over time using a combination of swaps and collars. As at March 31, 2008, 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:



---------------------------------------------------------------------------
Three months ended March 31
-----------------------------
2008 2007
---------------------------------------------------------------------------
Average crude volumes hedged (bbl/d) 4,200 2,300
Crude oil realized gain (loss) ($000's) (7,031) 2,238
Gain (loss) per bbl hedged (18.40) 10.81

Average natural gas volumes hedged (GJ/d) 20,841 14,500
Natural gas realized gain ($000's) 1,540 36
Gain per GJ hedged 0.81 0.03

Average BOE hedged (boe/d) 7,492 4,592
Total realized gain (loss) ($000's) (5,491) 2,274
Gain (loss) per boe hedged (8.05) 5.50
Gain (loss) per boe (2.56) 1.29
---------------------------------------------------------------------------
---------------------------------------------------------------------------


All derivative contracts are recorded on the balance sheet at fair value. 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.

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 March 31, 2008 was a liability of $32.1 million, comprised of a $16.7 million liability on oil contracts and a $15.4 million liability on gas contracts.

First quarter income for 2008 includes a $22.5 million unrealized loss on derivatives resulting from the change in the fair value of the derivative contracts during the quarter from a liability of $9.6 million at December 31, 2007 to a liability of $32.1 million at March 31, 2008. The $22.5 million unrealized loss was comprised of a $3.8 million unrealized loss on crude oil contracts, and a $18.7 million unrealized loss on natural gas contracts. The unrealized loss in the first quarter is primarily attributable to stronger natural gas forward prices compared to December 31, 2007 and an increase in derivative instruments held.

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



Loss on Derivative Contracts ($000's)
---------------------------------------------------------------------------
Three months ended March 31
------------------------------
2008 2007
---------------------------------------------------------------------------
Unrealized loss
Crude oil contracts (3,763) (3,529)
Natural gas contracts (18,772) (4,221)
---------------------------------------------------------------------------
Unrealized loss (22,535) (7,750)
Realized gain (loss) (5,491) 2,274
Reclassification from other comprehensive
income - 1,379
---------------------------------------------------------------------------
Loss on derivative contracts (28,026) (4,097)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

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

---------------------------------------------------------------------------
CRUDE OIL U.S.$ CDN$
---------------------------------------------------------------------------
Swap (bbls) 416,200 550,000
Swap (bbl/d) 1,513 2,000
$/bbl $90.46 $89.63
Collars (bbls) 246,900 165,100
Collars (bbl/d) 898 600
$/bbl $77.37 - $86.81 $90.17 - $106.17
Total (bbls) 663,100 715,100
Total (bbl/d) 2,411 2,600
---------------------------------------------------------------------------
---------------------------------------------------------------------------

---------------------------------------------------------------------------
NATURAL GAS CDN$
---------------------------------------------------------------------------
Swap (GJ) 7,304,000
Swap (GJ/d) 26,560
$/GJ $7.43
Collars (GJ) 885,000
Collars (GJ/d) 3,218
$/GJ $8.02 - $9.75
Total GJ 8,189,000
Total (GJ/d) 29,778
---------------------------------------------------------------------------
---------------------------------------------------------------------------

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

---------------------------------------------------------------------------
CRUDE OIL U.S.$ CDN$
---------------------------------------------------------------------------
Swap (bbls) 236,100 209,100
Swap (bbl/d) 647 573
$/bbl $100.62 $100.21
Collars (bbls) 72,700 69,400
Collars (bbl/d) 199 190
$/bbl $93.24 - $102.12 $100.65 - $118.09
Total (bbls) 308,800 278,500
Total (bbl/d) 846 763
---------------------------------------------------------------------------
---------------------------------------------------------------------------

---------------------------------------------------------------------------
NATURAL GAS CDN$
---------------------------------------------------------------------------
Swap (GJ) 1,384,000
Swap (GJ/d) 3,792
$/GJ $7.92
Collars (GJ) 1,440,000
Collars (GJ/d) 3,945
$/GJ $8.09 - $9.55
Total GJ 2,824,000
Total (GJ/d) 7,737
---------------------------------------------------------------------------
---------------------------------------------------------------------------


ROYALTY EXPENSES

Crown, freehold and overriding royalties were $29.3 million for the three months ended March 31, 2008. Expressed as a percentage of gross sales net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 20.2 percent for the quarter ended March 31, 2008, down from 21.5 percent experienced in the comparable period of the previous year.

Royalties increased to $13.65 per boe for the first quarter of 2008, an increase of 18 percent compared to the first quarter of 2007. The increase is mainly attributable to higher crude oil prices.

In response to industry concerns regarding the Alberta New Royalty Framework (the "Framework"), on April 10, 2008 the Government of Alberta announced two new royalty programs designed to encourage the continued development of deep oil and gas reserves. The new royalty programs are not expected to have an impact on the Trust as most of the Alberta natural gas portfolio is shallow and low cost. The Trust has assessed the impact of the new royalties prescribed by the Framework and the overall impact to the Trust is minimal given the low level of crude oil production in Alberta and the nature of the Trust's natural gas production.



Royalty Expenses
---------------------------------------------------------------------------
Three months ended March 31
-------------------------------
2008 2007
---------------------------------------------------------------------------
Royalties ($000s) 29,311 20,314
As % of revenue 20.2 21.5
$/boe 13.65 11.54
---------------------------------------------------------------------------
---------------------------------------------------------------------------


OPERATING COSTS

Operating costs averaged $9.91 per boe for the quarter ended March 31, 2008, a 24 percent increase from the $8.02 per boe for the quarter ended March 31, 2007.

The 24 percent change in operating costs year over year is due to 2008 negative prior period adjustments, higher property taxes and freehold lease rentals, increased third party processing costs, hydrocarbon dew point issues at Lacombe, the inclusion of Seneca operating costs in 2008 and lower operating costs in 2007 associated with positive prior period adjustments.

Taxes and processing costs are anticipated to impact the remainder of the year. Full year forecasted operating costs will be at the higher end of our guidance of $9.60 - $9.80 per boe.



Operating Costs
---------------------------------------------------------------------------
Three months ended March 31
-------------------------------
2008 2007
---------------------------------------------------------------------------
Operating costs ($000s) 21,273 14,126
As a % of revenue 14.6 15.0
$/boe 9.91 8.02
---------------------------------------------------------------------------
---------------------------------------------------------------------------


OPERATING NETBACK

For the quarter ended March 31, 2008, NAL's operating netback before hedging gains (losses) was $44.42 per boe, an increase from $34.43 for the quarter ended March 31, 2007. The increase was due to higher revenues driven by stronger commodity prices, offset by increases in royalties and operating expenses. Hedging losses were $2.56 per boe in the first quarter of 2008 as compared to a gain of $1.29 per boe in 2007.



Operating Netback ($/boe)
---------------------------------------------------------------------------
Three months ended March 31
--------------------------------
2008 2007
---------------------------------------------------------------------------
Revenue 67.61 53.56
Royalties (13.65) (11.54)
Operating expenses (9.91) (8.02)
Other income 0.37 0.43
--------------------------------
Operating netback, before hedging 44.42 34.43
Hedging gains (losses) (2.56) 1.29
--------------------------------
Operating netback, after hedging 41.86 35.72
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 March 31, 2008, G&A expenses were $3.7 million, compared with $3.9 million in the comparable quarter of 2007. In addition, $0.9 million of G&A costs relating to exploitation and development activities were capitalized in the first quarter of 2008 compared with $0.8 million in the first quarter of 2007. G&A expense per boe, excluding retention bonus, was $1.70 in the quarter as compared to $1.90 in the first quarter of 2007. While increasing production by 21 percent quarter over quarter by acquisition, the Trust has maintained its level of G&A expenses, which has resulted in lower G&A per boe rates.

The decrease in expensed G&A is partially attributable to lower retention expense in the first quarter of 2008 as compared to the same period in 2007. The retention bonus was a two payment program. The first payment was made on June 30, 2007 with the cost accrued over the six months January 1, 2007 to June 30, 2007. The second and final payment for the retention bonus will occur on June 30, 2008 and is accrued over the 18 months January 1, 2007 to June 30, 2008.

Full year 2008 G&A guidance of $1.90 - $2.10 per boe includes unit-based compensation expense. For the first quarter of 2008, G&A expense, including $0.52 of unit-based compensation expense, was $2.26 per boe as a result of a higher than estimated trust unit price and stronger relative performance factors.



General and Administrative Expenses
----------------------------------------------------------------------------
Three months ended March 31
---------------------------------
2008 2007
----------------------------------------------------------------------------
G&A expenses ($000s)
G&A 3,641 3,355
Retention bonus 96 560
----------------------------------------------------------------------------
Expensed G&A ($000s) 3,737 3,915
Capitalized G&A ($000s) 942 767
----------------------------------------------------------------------------
Total G&A ($000s) 4,679 4,682

Expensed G&A costs:
G&A, excluding retention bonus ($/boe) 1.70 1.90
Retention bonus ($/boe) 0.04 0.32
----------------------------------------------------------------------------
Total G&A expenses ($/boe) 1.74 2.22
As % of revenue 2.6 4.2
Per trust unit ($) 0.04 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 first quarter of 2008, the Trust accrued $1.7 million of unit-based incentive compensation charges as compared to a $0.2 million recovery in the comparable quarter of 2007. The increase in unit-based compensation in 2008 reflects an increase in unit price and the performance factors attached to the PTUs. In the first quarter of 2007, the Trust recorded a recovery of unit-based compensation expense due to a decrease in unit price and performance factors from December 31, 2006, which 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 in each quarter and over time.

At March 31, 2008, the Trust has recorded a liability for unit-based incentive compensation in the amount of $4.9 million, of which $1.9 million is recorded as current as it is payable in December 2008, and $3.0 million is long-term as it is payable in December 2009 and December 2010.



Unit-Based Compensation
---------------------------------------------------------------------------
Three months ended March 31
--------------------------------
2008 2007
---------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 1,108 (24)
Capitalized ($000s) 555 (139)
---------------------------------------------------------------------------
Total unit-based compensation ($000s) 1,663 (163)

Expensed unit-based compensation:
As % of revenue 0.76 -
$/boe 0.52 (0.01)
Per trust unit ($) 0.01 -
---------------------------------------------------------------------------


MANAGEMENT CONTRACT AND FEES

The Trust is managed by the Manager. The Manager is a wholly-owned subsidiary of "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 $2.9 million (2007 - $2.9 million) for the reimbursement of G&A expenses during the first quarter. 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.

INTEREST

Interest on bank debt includes charges on borrowings plus standby fees on the unused portion of the bank credit facility. The increase in interest on bank debt, year over year, of 39 percent is due to higher debt levels and higher effective interest rates. NAL's average outstanding bank debt for the first quarter of 2008 was $295.5 million, as compared to $223.6 million for the first quarter of 2007. The increase in average debt levels is largely attributable to the debt required for the acquisitions of Seneca ($31.8 million) and Tiberius and Spear ($28.3 million). NAL's effective interest rate averaged 5.35 percent in the first quarter of 2008, compared with 5.14 percent in the first quarter of 2007. NAL's interest is at a floating rate.

Interest on convertible debentures represents interest charges, at 6.75 percent, of $1.7 million and accretion of the debt discount of $0.5 million for the first quarter of 2008. The debentures were issued on August 28, 2007.



Interest and Debt
----------------------------------------------------------------------------
Three months ended March 31
----------------------------
2008 2007
----------------------------------------------------------------------------
Interest on bank debt ($000s) 3,981 2,859
Interest and accretion on convertible
debentures ($000s) 2,142 -
----------------------------------------------------------------------------
Total interest 6,123 2,859

Bank debt outstanding at period end ($000s) 313,370 229,633
Convertible debentures at period end ($000s) 91,353 -

$/boe:
Interest on bank debt 1.85 1.62
Interest on convertible debentures 0.78 -
Accretion on convertible debentures 0.22
----------------------------------------------------------------------------
Total interest 2.85 1.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------


CASH FLOW NETBACK

For the quarter ended March 31, 2008, NAL's cash flow netback was $36.97 per boe, a 16 percent increase from $31.89 for the comparable period in 2007. The increase is due to higher operating netbacks after hedging in 2008, partially offset by a $1.01 per boe increase in interest charges as compared to 2007.



Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended March 31
----------------------------
2008 2007
----------------------------------------------------------------------------
Operating netback, after hedging 41.86 35.72
G&A expenses, including unit-based incentive
compensation (2.26) (2.21)
Interest on bank debt and convertible
debentures(1) (2.63) (1.62)
----------------------------------------------------------------------------
Cash flow netback 36.97 31.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 March 31, 2008, depletion on property, plant and equipment and accretion on the asset retirement obligations increased by nine percent on a boe basis over the comparable period in 2007.

The increase in the DDA rate per boe is largely attributable to the acquisition of Seneca in August 2007 and Tiberius and Spear in February 2008.

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



Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months ended March 31
----------------------------
2008 2007
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 45,712 34,428
Accretion of asset retirement obligation
($000s) 1,798 1,297
----------------------------------------------------------------------------
Total DDA ($000s) 47,510 35,725
DDA rate per boe ($) 22.12 20.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------


TAXES

In the first quarter of 2008, NAL had a future income tax reduction of $6.5 million compared with a $2.7 million reduction in the corresponding period for the prior year.

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.

As at March 31, 2008, the Trust's (including all subsidiaries) estimated tax pools (unaudited) available for deduction from future taxable income approximate $708.9 million, of which approximately 45 percent represents COGPE and 30 percent UCC, with the remaining balance represented by CEE, CDE, trust unit issue costs and non-capital loss carry forwards.

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 gains or losses on derivative contracts and future income taxes.

Net income for the first quarter of 2008 was $13.7 million compared to $16.7 million for the comparable period in 2007. The decrease of $3.0 million is primarily due to an increased loss on derivative contracts of $23.9 million, increased depletion of $11.3 million, increased operating costs of $7.1 million and increased interest expense of $3.3 million, partially offset by higher revenues, net of royalties, of $42.3 million.



Net Income ($000s)
----------------------------------------------------------------------------
Three months ended March 31
----------------------------
2008 2007
----------------------------------------------------------------------------
Net income 13,733 16,710
----------------------------------------------------------------------------
----------------------------------------------------------------------------


CAPITAL RESOURCES AND LIQUIDITY

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

As at March 31, 2008, NAL had 93,518,723 trust units outstanding, compared with 90,494,151 trust units at December 31, 2007. The increase from December 31, 2007 is attributable to 2,408,902 trust units issued on the acquisition of Tiberius and Spear, and 615,670 trust units issued under the distribution reinvestment program ("DRIP").

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

For the three months ended March 31, 2008, the DRIP resulted in 0.6 million trust units being issued at an average price of $11.64 per trust unit for total proceeds of $7.2 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 March 31, 2008 consistent with recent experience. The Trust continues to monitor the participation in this plan in conjunction with its capital requirements.

As at March 31, 2008 the Trust had net debt of $409.3 million (net of working capital excluding derivative contracts, notes payable/receivable with MFC and future income tax asset), including convertible debentures at face value of $100 million. Excluding the convertible debentures, net debt was $309.3 million, compared with $291.1 million at December 31, 2007, and $227.0 million as at March 31, 2007. The increase in net debt of $18.3 million during the first quarter of 2008 is attributable to increased bank debt of $37.7 million offset by a positive change in working capital of $19.5 million.

Bank debt amounted to $313.4 million at March 31, 2008 compared with $275.6 million as at December 31, 2007. All the debt outstanding at March 31, 2008 was outstanding under the production facility. The increase in the bank debt during the first quarter of 2008 is due to the acquisition of Tiberius and Spear, of which $28.3 million was funded by debt. During the first quarter of 2008, working capital increased $19.5 million, which is a reflection of the increase in funds from operations over the quarter. Funds from operations increased to $76.2 million from $59.5 million in the fourth quarter of 2007, an increase of $16.7 million or 28 percent. The increase in funds from operations was driven by increased commodity prices.

At the end of the first quarter, the Trust had a net debt (excluding convertible debentures) to 12 months trailing cash flow of 1.29 and a total net debt to 12 months trailing cash flow of 1.70.

The Trust is currently in negotiations to increase its credit facility to $450 million and it is expected that this increase will occur during the second quarter. The current credit facility has been renewed for $400 million. The credit facility is a fully secured, extendible, revolving facility and will revolve until April 30, 2009 at which time it is extendible for a further 364-day revolving period upon agreement between the Trust and the bank syndicate. The facility consists of a $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 2010.

The Trust has outstanding $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 at the conversion price, 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 line item "interest and accretion on convertible debentures" in the consolidated statement of income.

The Trust recognized $0.5 million of accretion of the debt discount in the first quarter of 2008.

As at May 1, 2008, the Trust has 93,694,810 trust units and $100 million in convertible debentures outstanding.



Capitalization
----------------------------------------------------------------------------
Mar 31, 2008 Dec 31, 2007 Mar 31, 2007
----------------------------------------------------------------------------
Trust unit equity ($000s) 511,072 504,717 444,366

Bank debt ($000s) 313,370 275,630 229,633
Working capital deficit
(surplus)(1) ($000s) (4,023) 15,429 (2,619)
----------------------------------------------------------------------------
Net debt excluding convertible
debentures 309,347 291,059 227,014
Convertible debentures
($000s)(2) 100,000 100,000 -
----------------------------------------------------------------------------
Net debt 409,347 391,059 227,014

Net debt excluding convertible
debentures to trailing 12 month
cash flow(3) 1.29 1.33 1.05
Net debt to trailing 12 month
cash flow(2) 1.70 1.79 1.05
Trust units outstanding (000s) 93,519 90,494 78,534
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


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 combination 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 its 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 $560 million of available safe harbour and for each of 2009 and 2010 an additional $280 million each year.

ASSET RETIREMENT OBLIGATION

At March 31, 2008, the Trust reported an asset retirement obligation ("ARO") balance of $91.5 million ($89.6 million as at December 31, 2007) for future abandonment and reclamation of the Trust's oil and gas properties and facilities. The ARO balance was increased by $1.6 million due to the Tiberius and Spear acquisitions, $0.2 million due to liabilities incurred and revisions to estimates, $1.8 million from accretion expense and was reduced by $1.8 million for actual abandonment and environmental expenditures incurred in 2008.

DISTRIBUTIONS TO UNITHOLDERS

For the three months ended March 31, 2008 the Trust distributed 62 percent of its cash flow from operating activities, as compared to 71 percent in 2007. The payout associated with cash flow from operating activities will fluctuate significantly period over period as cash flow from operating activities includes changes in non-cash working capital associated with operating activities. 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 acquisitions. NAL's productive capacity and future cash flow will be dependent on its ability to acquire assets and continue to find economic reserves. Acquisitions are financed through equity, debt or a combination of the two.

Generally, the capital expenditures of the Trust and the distributions in any given period exceed the cash flow from operating activities. The shortfall is financed from 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 percentages) Three months ended March 31
----------------------------
2008 2007
----------------------------------------------------------------------------
Cash flow from operating activities 70,561 52,966
Net income 13,733 16,710
Actual cash distributions paid or payable 44,025 37,606
Excess (shortfall) of cash flow from operating
activities over cash distribution paid 26,536 15,360
Percentage of cash flow from operations
distributed 62% 71%
Excess (shortfall) of net income over cash
distributions paid (30,292) (20,896)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 March 31, 2008, funds from operations amounted to $76.2 million compared with $54.2 million for the three months ended March 31, 2007. The 41 percent 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 increased 20 percent from $0.69 in 2007 to $0.83 in 2008, the increase in funds from operations being partially offset by the increase in the number of trust units outstanding due to equity issuances associated with the acquisitions of Seneca, Tiberius and Spear.



Funds from Operations
----------------------------------------------------------------------------
Three months ended March 31
----------------------------
2008 2007
----------------------------------------------------------------------------
Funds from operations ($000s) 76,220 54,234
Funds from operations per trust unit 0.83 0.69
Payout ratio based on funds from operations 58% 69%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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) 3,027 4,036 3,700 - - -
Transportation agreement 1,665 1,239 1,239 - - -
Processing agreement(2) 352 446 428 414 401 384
Retention bonus(3) 578 - - - - -
----------------------------------------------------------------------------
Total 5,622 5,721 5,367 414 401 384
----------------------------------------------------------------------------

(1) Represents the full amount of office lease commitments, including both
base rent and operating costs, in relation to the lease held by the
Manager, of which the Trust is allocated a pro rata share (currently
approximately 58 percent) of the expense on a monthly basis.
(2) Represents a gas processing agreement with a take or pay component.
(3) Represents the Trust's share of the expected future payments under a
staff retention program.


QUARTERLY INFORMATION

2008 2007 2006
----------------------------------------------------------------------------
($000s, except
per unit
and production
amounts) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
----------------------------------------------------------------------------
Revenue, net of
royalties 89,611 86,262 78,573 83,268 71,231 75,358 75,798 77,988
Per unit 0.98 0.96 0.95 1.06 0.91 0.97 0.98 1.03
Funds from
operations(1) 76,220 59,537 50,817 54,156 54,234 55,795 54,107 52,210
Per unit 0.83 0.66 0.61 0.69 0.69 0.72 0.70 0.69
Net income
(loss) 13,733 10,556 7,801 21,390 16,710 20,472 20,473 (5,357)(2)
Per unit
- basic
and diluted 0.15 0.12 0.09 0.27 0.21 0.26 0.27 (0.07)
Average oil
equivalent
production
(boe/d - 6:1) 23,601 23,656 20,369 19,094 19,561 19,517 19,079 19,012
----------------------------------------------------------------------------
(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.


FINANCIAL REPORTING DISCLOSURE CONTROLS

Management has designed and evaluated the effectiveness of the Trust's financial reporting disclosure controls and procedures as at March 31, 2008 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 December 31, 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 Manager reviews the estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes in estimated amounts that differ materially from current estimates. NAL might realize different results from the application of new accounting standards published, from time to time, by various regulatory bodies. An assessment of NAL's significant accounting estimates is discussed in the MD&A filed with NAL's audited consolidated financial statements for the year ended December 31, 2007.

NEW ACCOUNTING STANDARDS

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

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

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

FUTURE ACCOUNTING CHANGES

International Financial Reporting Standards ("IFRS")

In February 2008, the Canadian Institute of Chartered Accountants confirmed that Canadian GAAP for publicly accountable enterprises will be converted to IFRS on January 1, 2011. This change in GAAP will be applicable for the Trust for the year beginning January 1, 2011.

Dated: May 1, 2008



CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)

As at As at
March 31, December 31,
2008 2007
---------------------------------------------------------------------------

Assets
Current assets
Cash and cash equivalents $15,177 $1,394
Accounts receivable and other 82,833 70,791
Note receivable (Note 3) 49,599 -
Derivative contracts (Note 12) - 3,389
Future income tax asset 8,499 2,602
---------------------------------------------------------------------------
156,108 78,176

Derivative contracts (Note 12) 594 -
Future income tax asset - 4,096
Goodwill (Note 3) 12,521 -
Property, plant and equipment (Notes
3 and 5) 1,032,981 980,888
---------------------------------------------------------------------------
$1,202,204 $1,063,160
---------------------------------------------------------------------------

Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued
liabilities $79,024 $73,135
Note payable (Note 3) 3,750 -
Distributions payable to unitholders 14,963 14,479
Derivative contracts (Note 12) 31,761 12,973
---------------------------------------------------------------------------
129,498 100,587

Bank debt (Note 6) 313,370 275,630
Convertible debentures (Note 7) 91,353 90,876
Derivative contracts (Note 12) 952 -
Unit-based incentive compensation
(Note 8) 2,961 1,748
Asset retirement obligations (Note 9) 91,465 89,602
Future income tax liability 7,229 -
---------------------------------------------------------------------------
636,828 558,443

Non-controlling interest (Note 10) 54,304 -

Unitholders' equity
Unitholders' capital (Note 11) 1,006,235 969,588
Equity component of convertible
debentures (Note 7) 5,759 5,759
Deficit (500,922) (470,630)
---------------------------------------------------------------------------
511,072 504,717
---------------------------------------------------------------------------
$1,202,204 $1,063,160
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Trust units outstanding (000s) 93,519 90,494
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes.


CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
Three months ended March 31,
(thousands of dollars, except per unit amounts) (unaudited)

2008 2007
---------------------------------------------------------------------------
Revenue
Oil, natural gas and liquid sales $146,143 $94,881
Crown royalties (21,848) (15,029)
Freehold and other royalties (7,463) (5,285)
---------------------------------------------------------------------------
116,832 74,567
Gain (loss) on derivative contracts (Note 12):
Realized gain (loss) (5,491) 2,274
Unrealized loss (22,535) (7,750)
Reclassification from other comprehensive income - 1,379
---------------------------------------------------------------------------
(28,026) (4,097)
Other income 805 761
---------------------------------------------------------------------------
89,611 71,231
---------------------------------------------------------------------------
Expenses
Operating 21,273 14,126
Transportation 934 597
General and administrative 3,737 3,915
Unit-based incentive compensation (Note 8) 1,108 (24)
Interest on bank debt 3,981 2,859
Interest and accretion on convertible debentures 2,142 -
Depletion, depreciation and amortization 45,712 34,428
Accretion on asset retirement obligations 1,798 1,297
---------------------------------------------------------------------------
80,685 57,198
---------------------------------------------------------------------------
Income before taxes and non-controlling interest 8,926 14,033

Income tax recovery (provision) 4 (24)
Future income tax reduction 6,528 2,701
---------------------------------------------------------------------------
Total income taxes 6,532 2,677
---------------------------------------------------------------------------
Income before non-controlling interest 15,458 16,710

Non-controlling interest (Note 10) (1,725) -

---------------------------------------------------------------------------
Net income 13,733 16,710
Other comprehensive income:
Reclassification to net income, net of tax of
$412 - (967)
---------------------------------------------------------------------------
Comprehensive income 13,733 15,743
---------------------------------------------------------------------------

Deficit, beginning of period (470,630) (368,486)
Net income 13,733 16,710
Distributions declared (44,025) (37,606)
---------------------------------------------------------------------------
Deficit, end of period $(500,922) $(389,382)
---------------------------------------------------------------------------

Net income per trust unit - basic and diluted
(Note 11) $0.15 $0.21
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Weighted average trust units outstanding (000s) 91,717 78,258
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes.


CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended March 31,
(thousands of dollars) (unaudited)

2008 2007
---------------------------------------------------------------------------
Operating Activities
Net income $13,733 $16,710
Items not involving cash:
Depletion, depreciation and amortization 45,712 34,428
Accretion on asset retirement obligations 1,798 1,297
Unrealized loss on derivative contracts 22,535 7,750
Reclassification from other comprehensive income - (1,379)
Future income tax reduction (6,528) (2,701)
Non-cash accretion expense on convertible
debentures 477 -
Non-controlling interest 247 -
Abandonment and environmental expenditures (1,754) (1,871)
Change in non-cash working capital (5,659) (1,268)
---------------------------------------------------------------------------
70,561 52,966
---------------------------------------------------------------------------

Financing Activities
Distributions paid to unitholders (36,376) (37,516)
Issue of trust units, net of issue costs (14) 6,557
Increase in bank debt 37,740 8,848
Change in non-cash working capital (426) 915
---------------------------------------------------------------------------
924 (21,196)
---------------------------------------------------------------------------

Investing Activities
Acquisition of Tiberius and Spear (Note 3) (76,984) -
Disposition of Tiberius and Spear (Note 3) 58,107 -
Acquisition of Seneca 337 -
Additions to property, plant and equipment (29,323) (27,083)
Property acquisitions (6,870) -
Proceeds from dispositions - 25
Change in non-cash working capital (2,969) (5,884)
---------------------------------------------------------------------------
(57,702) (32,942)
---------------------------------------------------------------------------

Increase (decrease) in cash and cash equivalents 13,783 (1,172)
Cash and cash equivalents, beginning of period 1,394 6,295
---------------------------------------------------------------------------
Cash and cash equivalents, end of period $15,177 $5,123
---------------------------------------------------------------------------

Supplementary disclosure of cash flow information:
Cash paid during the period for:
Interest $6,522 $2,831
Tax $- $24
---------------------------------------------------------------------------

Cash and cash equivalents is comprised of:
Cash $10,183 $130
Short term investments 4,994 4,993
---------------------------------------------------------------------------
$15,177 $5,123
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Three months ended March 31, 2008

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

(unaudited)

1. SUMMARY OF ACCOUNTING POLICIES

Management prepared the interim consolidated financial statements of NAL Oil & Gas Trust ("NAL" or the "Trust") in accordance with accounting principles generally accepted in Canada and following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2007, except as described below. The following disclosure is incremental to the disclosure included within the annual financial statements. Please read the interim consolidated financial statements in conjunction with the consolidated financial statements and notes thereto in NAL's annual report for the year ended December 31, 2007.

2. CHANGES IN ACCOUNTING POLICIES

New Accounting Standards

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

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

The implementation of these new standards did not impact the Trust's financial results, however did result in additional disclosures as provided in Note 12.

Basis of Presentation

The Trust's financial statements include the accounts of the Trust and all its subsidiaries and partnerships. All inter-entity transactions and balances have been eliminated. Non-controlling interests in subsidiaries and partnerships are presented as separate line items on the consolidated balance sheet and the consolidated statement of income, comprehensive income and deficit.

Goodwill

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

Comparative Information

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

3. CORPORATE ACQUISITIONS

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

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

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

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

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



---------------------------------------------------------------------------
Net assets Total Disposition Trust, net Net to
acquired: Acquisition to Manulife Acquisition NPI(1) Trust
---------------------------------------------------------------------------
Cash $ 9,734 $ - $ 9,734 $- $ 9,734
Working capital
deficiency (4,007) - (4,007) - (4,007)
Notes receivable,
net from MFC - (3,750) (3,750) 49,599 45,849
Property, plant
and equipment 111,258 - 111,258 (49,599) 61,659
Future income taxes (23,692) 11,736 (11,956) - (11,956)
Asset retirement
obligations (1,636) - (1,636) - (1,636)
Goodwill 24,557 (12,036) 12,521 - 12,521
Non-controlling
interest - (54,057) (54,057) - (54,057)
---------------------------------------------------------------------------
$116,214 $(58,107) $58,107 $- $58,107
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Consideration:
---------------------------------------------------------------------------
Cash $ 86,118 $(57,807) $28,311 $- $28,311
Issuance of
trust units 29,496 - 29,496 - 29,496
Acquisition costs 600 (300) 300 - 300
---------------------------------------------------------------------------
$116,214 $(58,107) $58,107 $- $58,107
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Net profits interest agreement entered into with MFC, in exchange for
a note receivable.


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.

4. 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 ("G&A") expenses incurred by the Manager on behalf of the Trust. The Trust paid $2.9 million (2007 - $2.9 million) for the reimbursement of G&A expenses during the first quarter. The Trust also pays the Manager its share of unit-based compensation expense when cash compensation is paid to employees under the terms of the Plan.

The Manager is a wholly-owned subsidiary of MFC and manages on their behalf NAL Resources Limited ("NAL Resources"), another wholly-owned subsidiary of Manulfie. The disposition of a 50 percent interest in the Partnership holding the Tiberius and Spear assets was to MFC, see Note 3.

The notes payable and receivable are due to/from MFC, are due on demand and bear interest at prime plus three percent.

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



March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Due from NAL Resources Limited $15,047 $14,203
Due to NAL Resources Management Limited (1,357) (2,826)
Due from Manulife Financial Corporation 44,693 -
---------------------------------------------------------------------------
$58,383 $11,377
---------------------------------------------------------------------------
---------------------------------------------------------------------------



5. PROPERTY, PLANT AND EQUIPMENT

March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Petroleum and natural gas
properties, at cost $1,785,136 $1,687,331
Less: Accumulated depletion
and depreciation (752,155) (706,443)
---------------------------------------------------------------------------
$1,032,981 $980,888
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Costs associated with undeveloped land of $31.2 million (2007 - $nil) have been excluded from the depletion calculation for the three months ended March 31, 2008.

Future development costs for proved reserves of $49.8 million (2007 - $27.3 million) have been included in the depletion calculation.

During 2008, the Trust capitalized $0.9 million (2007 - $0.8 million) of G&A costs and $0.6 million (2007 - $(0.1) million) of unit-based incentive compensation that were directly related to exploitation and development programs.



6. BANK DEBT

March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Production loan facility $313,370 $273,528
Working capital facility - 2,102
---------------------------------------------------------------------------
Total debt outstanding $313,370 $275,630
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 will revolve until April 30, 2009 at which time it may be extended for a further 364-day revolving period upon agreement between the Trust and the bank syndicate. If the credit facility is not extended in April 2009, the amounts outstanding at that time will be converted to a two-year term loan. The term loan will be payable in four equal quarterly installments commencing May 2010 with a final residual payment, if any, in May 2011.

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

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

On March 31, 2008 the effective interest rate on amounts outstanding under the credit facility was 5.26 percent (2007 - 5.26 percent).

7. CONVERTIBLE DEBENTURES

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



Principal Debt Equity
amount of component of component of
debentures debentures debentures
---------------------------------------------------------------------------
August 28, 2007 issuance $100,000 $94,241 $5,759
Issue costs - (4,000) -
Accretion - 635 -
---------------------------------------------------------------------------
Balance, December 31, 2007 100,000 90,876 5,759
Accretion - 477 -
---------------------------------------------------------------------------
Balance, March 31, 2008 $100,000 $91,353 $5,759
---------------------------------------------------------------------------
---------------------------------------------------------------------------


8. UNIT-BASED INCENTIVE COMPENSATION PLAN

The Trust recorded a total compensation expense of $1.7 million in the first three months of 2008, of which $1.1 million was recorded as an expense and $0.6 million as property, plant and equipment ($2.1 million expensed, $0.9 million to property, plant and equipment for the year ended December 31, 2007). The compensation expense was based on the March 31, 2008 trust unit price of $13.25 (2007 - $11.60), accrued distributions, performance factors, and the number of units vesting on maturity.

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



Three months ended Year ended
March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Balance, beginning of period $4,996 $4,153
Increase in liability 1,670 3,027
Cash payout, relating to units vested (1,767) (2,184)
---------------------------------------------------------------------------
Balance, end of period $4,899 $4,996
---------------------------------------------------------------------------
Current portion of liability(1) $1,938 $3,248
---------------------------------------------------------------------------
Long-term liability $2,961 $1,748
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.


9. 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 $91.5 million as at March 31, 2008 (2007 - $89.6 million) based on a total undiscounted and inflated amount of cash flows required to settle its asset retirement obligations of $273.8 million (2007 - $270.5 million). These costs are expected to be made over the next 44 years with the majority of the costs incurred between 2008 and 2033. NAL's credit-adjusted risk-free rate of eight percent (2007 - eight percent) and an inflation rate of two percent (2007 - two percent) were used to calculate the present value of the asset retirement obligations.

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



Three months ended Year ended
March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Balance, beginning of period $89,602 $65,574
Accretion expense 1,798 5,533
Revisions to estimates (261) 10,294
Liabilities incurred 444 1,079
Liabilities acquired (Note 3) 1,636 12,625
Liabilities settled (1,754) (5,503)
---------------------------------------------------------------------------
Balance, end of period $91,465 $89,602
---------------------------------------------------------------------------
---------------------------------------------------------------------------


10. NON-CONTROLLING INTEREST

The Trust has recorded a non-controlling interest in respect of the 50 percent ownership interest held by MFC in the Partnership holding the Tiberius and Spear assets (Note 3). The non-controlling interest on the balance sheet represents 50 percent of the net assets of the Partnership. The non-controlling interest in the statement of income is comprised of:



Three months ended March 31,
-----------------------------
2008 2007
---------------------------------------------------------------------------
Net profits interest $1,478 $-
Share of net income attributable to MFC 247 -
---------------------------------------------------------------------------
$1,725 $-
---------------------------------------------------------------------------
---------------------------------------------------------------------------



11. UNITHOLDERS EQUITY

Units Issued:

Three months ended Year ended
March 31, 2008 December 31, 2007
Units Amount Units Amount
---------------------------------------------------------------------------
Balance, beginning of the period 90,494 $969,588 77,971 $824,986
Issued on corporate
acquisition (Note 3) 2,409 29,496 10,246 125,001
Less issue expenses (14) (7,134)
Issued from Distribution
Reinvestment Plan 616 7,165 2,277 26,735
---------------------------------------------------------------------------
Balance, end of the period 93,519 $1,006,235 90,494 $969,588
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 ended March 31, 2008. 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 ended March 31, 2008 were 7,142,857.

12. FINANCIAL RISK MANAGEMENT

Overview

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

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

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

Credit Risk

Credit risk is the risk of financial loss to the Trust if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Trust's receivables. 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 Manulife. 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 represent joint operations from NAL Resources. Accordingly, accounts receivable include amounts due from NAL Resources for oil, natural gas and natural gas liquids sales. Oil and gas marketing is conducted by the Manager on behalf of the Trust and NAL Resources generally with large creditworthy purchasers, for which the Trust views the credit risk as low. NAL Resources, and ultimately the Trust, have not historically experienced any collection issues with its oil and gas marketers. The Manager does not obtain collateral from oil and natural gas marketers or joint venture partners.

Cash and cash equivalents consist of cash bank balances and short-term deposits maturing in less than 90 days. The Trust manages the credit exposure related to short-term investments by selecting established counter parties with high credit ratings and monitors all investments, avoiding complex investment vehicles with higher risks such as asset backed commercial paper.

The carrying amounts of accounts receivable and cash and cash equivalents represent the maximum credit exposure. The Trust does not have an allowance for doubtful accounts as at March 31, 2008 and did not write-off any receivables during the first quarter of 2008. The Trust does not have any receivable balances past due as at March 31, 2008.

Liquidity Risk

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

The Trust prepares annual capital expenditure budgets, which are regularly monitored and updated as necessary. As well, the Manager utilizes authorizations for expenditure on both operated and non-operated projects. Furthermore, the Manager operates a high percentage of the Trust's properties, which allows for significant control over future expenditures. To support the capital spending program, the Trust maintains a fully secured, extendible, revolving term credit facility, as outlined in Note 6.

The following are the contractual maturities of financial liabilities and associated interest payments as at March 31, 2008.


less than 1 - 2 2 - 5
Financial Liability 1 Year Years Years
---------------------------------------------------------------------------
Accounts payable and accrued liabilities $ 79,024 $ - $ -
Distributions payable 14,963
Unit-based incentive compensation - 2,508 453
Note payable 3,750
Derivative contracts 31,761 952
Bank debt, principal 313,370
Convertible debentures, principal 100,000
---------------------------------------------------------------------------
Total $129,498 $3,460 $413,823
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Market risk

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

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Trust's oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and U.S. dollar. As at March 31, 2008, if the Canadian dollar had weakened $0.10 against the U.S. dollar, with all other variables held constant, net income would have been $0.7 million lower due to changes in the foreign exchange component of U.S. dollar denominated commodity contracts. An equal and opposite impact would have occurred to net income had the Canadian dollar improved $0.10 against the U.S. dollar.

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

Commodity price risk

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

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 U.S.$/bbl U.S.$/bbl U.S.$/bbl
---------------------------------------------------------------------------
COLLARS
April-June 2-way 100 9,100 75.00 81.00 -
April-December 2-way 100 27,500 85.00 100.00 -
April-December 2-way 100 27,500 83.00 100.00 -
July-December 2-way 100 18,400 75.00 85.50 -
April-June 2-way 100 9,100 73.00 79.00 -
April-June 2-way 100 9,100 72.00 78.00 -
April-June 2-way 100 9,100 71.00 78.50 -
April-June 2-way 100 9,100 70.00 76.25 -
April-June 2-way 100 9,100 69.00 74.25 -
April-June 2-way 100 9,100 69.00 74.00 -
April-June 2-way 200 18,200 68.50 73.00 -
April-June 2-way 200 18,200 64.00 72.26 -
April-June 2-way 100 9,100 70.00 75.05 -
April-December 2-way 100 27,500 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 2-ways 246,900 77.37 86.81 -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls U.S.$/bbl U.S.$/bbl U.S.$/bbl
---------------------------------------------------------------------------
SWAPS
April-December swap 100 27,500 - - 73.50
April-December swap 100 27,500 - - 94.00
April-December swap 100 27,500 - - 92.18
April-December swap 100 27,500 - - 87.10
April-December swap 100 27,500 - - 79.10
April-December swap 100 27,500 - - 71.00
April-December swap 100 27,500 - - 80.75
April-October swap 100 21,400 - - 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
July-December swap 100 18,400 - - 100.00
November-December swap 100 6,100 - - 100.03
November-December swap 100 6,100 - - 103.00
May-December swap 100 24,500 - - 108.00
---------------------------------------------------------------------------
Weighted Average Swaps 416,200 - - 90.46
---------------------------------------------------------------------------

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 -
April-December 2-way 100 27,500 87.10 97.35 -
April-June 2-way 100 9,100 71.75 76.88 -
April-December 2-way 100 27,500 72.40 77.54 -
June-December 2-way 100 21,400 103.00 132.75 -
June-December 2-way 100 21,400 104.00 134.75 -
June-December 2-way 100 21,400 107.00 130.45 -
---------------------------------------------------------------------------
Weighted Average 2-ways 165,100 90.17 106.17 -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
---------------------------------------------------------------------------
SWAPS
April-December swap 100 27,500 - - 84.90
April-December swap 100 27,500 - - 90.05
April-June swap 100 9,100 - - 71.55
April-December swap 100 27,500 - - 90.15
April-December swap 100 27,500 - - 90.05
April-December swap 100 27,500 - - 90.20
April-December swap 100 27,500 - - 89.05
April-December swap 100 27,500 - - 87.00
April-December swap 100 27,500 - - 83.80
April-June swap 100 9,100 - - 77.07
April-June swap 200 18,200 - - 75.05
April-December swap 100 27,500 - - 73.55
July-December swap 100 18,400 - - 93.00
April-June swap 100 9,100 - - 73.77
April-December swap 100 27,500 - - 90.70
April-December swap 100 27,500 - - 91.00
April-October swap 100 21,400 - - 87.50
April-June swap 100 9,100 - - 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
July-December swap 100 18,400 - - 98.50
May-December swap 100 24,500 - - 110.50
---------------------------------------------------------------------------
Weighted Average Swaps 550,000 - - 89.63
---------------------------------------------------------------------------

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

---------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------------
COLLARS
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 -
November-December 2-way 1,000 61,000 8.00 9.50 -
November-December 2-way 1,000 61,000 8.25 9.50 -
November-December 2-way 1,000 61,000 8.25 9.75 -
November-December 2-way 1,000 61,000 8.25 10.00 -
June-October 2-way 1,000 153,000 8.50 11.00 -
November-December 2-way 1,000 61,000 9.00 12.00 -
---------------------------------------------------------------------------
Weighted Average 2-ways 885,000 8.02 9.75 -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------------
SWAPS
April-December swap 2,000 550,000 - - 7.60
April-December swap 1,000 275,000 - - 7.40
April-December swap 2,000 550,000 - - 7.40
April-December swap 1,000 275,000 - - 7.31
April-December swap 2,000 550,000 - - 7.26
April-December swap 1,000 275,000 - - 7.05
April-December swap 1,000 275,000 - - 7.20
April-December swap 1,000 275,000 - - 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
April-December swap 1,000 275,000 - - 7.10
April-October swap 1,000 214,000 - - 7.20
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
April-October swap 1,000 214,000 - - 7.90
April-October swap 1,000 214,000 - - 8.02
April-October swap 1,000 214,000 - - 8.25
April-October swap 1,000 214,000 - - 8.40
---------------------------------------------------------------------------
Weighted Average Swaps 7,304,000 - - 7.43
---------------------------------------------------------------------------

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 U.S.$/bbl U.S.$/bbl U.S.$/bbl
---------------------------------------------------------------------------
COLLARS
January-December 2-way 100 36,500 92.00 101.50 -
January-June 2-way 100 18,100 94.00 100.50 -
January-June 2-way 100 18,100 95.00 105.00 -
---------------------------------------------------------------------------
Weighted Average 2-ways 72,700 93.24 102.12 -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls U.S.$/bbl U.S.$/bbl U.S.$/bbl
---------------------------------------------------------------------------
SWAPS
January-June swap 100 18,100 - - 97.25
January-December swap 100 36,500 - - 96.75
January-June swap 100 18,100 - - 100.00
January-June swap 100 18,100 - - 100.03
January-June swap 100 18,100 - - 103.00
January-December swap 100 36,500 - - 102.00
January-June swap 100 18,100 - - 97.50
January-June swap 100 18,100 - - 102.00
January-March swap 100 9,000 - - 101.50
April-June swap 100 9,100 - - 103.25
April-June swap 100 9,100 - - 103.27
January-June swap 100 18,100 - - 104.25
July-September swap 100 9,200 - - 105.00
---------------------------------------------------------------------------
Weighted Average Swaps 236,100 - - 100.62
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------
COLLARS
January-June 2-way 100 18,100 100.00 115.00 -
January-June 2-way 100 18,100 100.00 114.00 -
January-June 2-way 100 18,100 100.00 113.05 -
January-May 2-way 100 15,100 103.00 132.75 -
---------------------------------------------------------------------------
Weighted Average 2-way 69,400 100.65 118.09 -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
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
January-March swap 100 9,000 - - 102.00
January-March swap 100 9,000 - - 102.75
January-March swap 100 9,000 - - 106.10
April-June swap 100 9,100 - - 105.10
January-March swap 100 9,000 - - 105.02
January-March swap 100 9,000 - - 106.05
April-June swap 100 9,100 - - 105.50
April-September swap 100 18,300 - - 108.00
---------------------------------------------------------------------------
Weighted Average Swaps 209,100 - - 100.21
---------------------------------------------------------------------------

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 -
January-March 2-way 1,000 90,000 8.00 9.50 -
January-March 2-way 1,000 90,000 8.25 9.50 -
January-March 2-way 1,000 90,000 8.25 9.75 -
January-March 2-way 1,000 90,000 8.25 10.00 -
January-March 2-way 1,000 90,000 8.50 10.00 -
January-March 2-way 1,000 90,000 8.50 9.50 -
January-March 2-way 1,000 90,000 8.65 9.75 -
January-March 2-way 1,000 90,000 8.75 9.75 -
January-March 2-way 1,000 90,000 9.00 12.00
---------------------------------------------------------------------------
Weighted Average 2-way 1,440,000 8.09 9.55 -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
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
January-March swap 1,000 90,000 - - 9.00
January-March swap 1,000 90,000 - - 9.10
January-March swap 1,000 90,000 - - 9.16
January-March swap 1,000 90,000 - - 9.23
April-October swap 1,000 214,000 - - 8.00
---------------------------------------------------------------------------
Weighted Average Swaps 1,384,000 - - 7.92
---------------------------------------------------------------------------


These contracts and the contracts expired in the quarter, for the three months ended March 31, 2008 resulted in settlement losses of $5.5 million (2007 - $2.3 million gain). The unrealized gain or loss from derivative contracts has been included on the balance sheet with changes in the fair value reported separately on the statement of income. As at March 31, 2008, if oil and natural gas liquids prices had been $1.00 per barrel lower and natural gas prices $0.10 per mcf lower, with all other variables held constant, net income for the period would have been $2.5 million higher, due to changes in the fair value of the derivative contracts. An equal and opposite effect would have occurred to net income had oil and natural gas liquids prices been $1.00 per barrel higher and natural gas $0.10 per mcf higher.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Trust is exposed to interest rate fluctuations on its bank debt, which bears a floating rate of interest. As at March 31, 2008, if interest rates had been one percentage point lower, with all other variables held constant, net income for the period would have been $0.6 million higher, due to lower interest expense. An equal and opposite impact would have occurred to net income had interest rates been one percentage point higher.

The Trust had no interest related derivative contracts in place as at or during the three months ended March 31, 2008.

Fair Values

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

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

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

The fair value of the Trust's convertible debentures at March 31, 2008 was $101 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. The fair value of derivative contracts is determined by discounting the difference between the contracted prices and published forward curves as of the balance sheet date, using the remaining contracted oil and natural gas volumes.



Three months ended Year ended
March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Long term unrealized gain on
derivative contracts $ 594 $ -
Long term unrealized loss on
derivative contracts (952) -
---------------------------------------------------------------------------
Long term unrealized loss on
derivative contracts (358) -
Current unrealized gain on
derivative contracts - 3,389
Current unrealized loss on
derivative contracts (31,761) (12,973)
---------------------------------------------------------------------------
Current unrealized loss on
derivative contracts (31,761) (9,584)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Fair value of derivative contracts $(32,119) $(9,584)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


As at March 31, 2008, the total fair value of derivative contracts was a liability of $32.1 million. The change in the fair value for the quarter of $22.5 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 March 31
------------------------------
2008 2007
---------------------------------------------------------------------------
Unrealized loss, beginning of period $ (9,584) $ -
Unrealized gain on adoption of
new accounting standards - 4,521
Unrealized loss, end of period (32,119) (3,229)
---------------------------------------------------------------------------
Unrealized loss (22,535) (7,750)
Realized gain (loss) in the period (5,491) 2,274
Reclassification from other
comprehensive income - 1,379
---------------------------------------------------------------------------
Loss on derivative contracts $(28,026) $(4,097)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Capital Management

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

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

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

As at March 31, 2008, the Trust had a net debt to 12 months trailing funds from operations ratio of 1.70 to 1, see the calculation in the table below. At December 31, 2007, the Trust had a net debt to 12 months trailing funds from operations ratio of 1.79 to 1, primarily attributable to the Seneca acquisition.

The credit facility is determined by reference to the reserves of the Trust (see Note 6) and is therefore commodity price sensitive. The Trust is restricted under its credit facility from making distributions to its unitholders in excess of its consolidated operating cash flow during the 18 month period preceding the distribution date. As at March 31, 2008, the Trust is in full compliance with the external capital restriction.

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

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



Capitalization
---------------------------------------------------------------------------
March 31, 2008 December 31, 2007
---------------------------------------------------------------------------
Trust unit equity ($000s) 511,072 504,717

Bank debt ($000s) 313,370 275,630
Working capital deficit (surplus)(1) ($000s) (4,023) 15,429
---------------------------------------------------------------------------
Net debt excluding convertible debentures 309,347 291,059
Convertible debentures ($000s)(2) 100,000 100,000
---------------------------------------------------------------------------
Net debt ($000s) 409,347 391,059

Cash flow from operating activities
for last 12 months ($000s) 232,959 215,364
Add back change in non-cash
working capital ($000s) 7,771 3,381
---------------------------------------------------------------------------
Trailing 12 months funds
from operations ($000s) 240,730 218,745

Net debt excluding convertible
debentures to trailing 12 month
funds from operations(2) 1.29 1.33
Net debt to trailing 12-month funds
from operations 1.70 1.79
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Working capital excludes derivative contracts, the future income tax
asset and the notes receivable/payable with MFC.
(2) Convertible debentures included at face value.



TRADING PERFORMANCE

For the Quarter Ended
31-Mar-08 31-Dec-07 31-Mar-07 31-Dec-06
---------------------------------------------------------------------------
PRICE
High $13.47 $12.90 $13.00 $18.74
Low $10.81 $10.94 $10.86 $11.80
Close $13.25 $11.60 $11.75 $12.31
Volume 19,937,583 18,375,644 16,390,680 27,691,472
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 British Columbia, Alberta, Saskatchewan and Ontario. Trust units trade on the Toronto Stock Exchange under the symbol "NAE.UN".

Contact Information