NAL Oil & Gas Trust Reports Third Quarter 2009 Results

Tuesday, November 03, 2009 4:09 PM

CALGARY, ALBERTA, Nov. 3, 2009 (Marketwire) -- NAL Oil & Gas Trust ("NAL" or the "Trust") (TSX:NAE.UN) today announced its financial and operational results for the third quarter of 2009. All amounts are in Canadian dollars unless otherwise stated.

On NAL's third quarter, Mr. Andrew Wiswell stated "After posting another solid quarter, the Trust remains on track to deliver results within guidance for 2009. Over the past twelve months, NAL has created positive momentum through consistent and reliable operations in southeast Saskatchewan, the Cardium oil resource play in central Alberta and the successful execution of several transactions to add attractive opportunities, all while maintaining a strong balance sheet position. The Trust is well positioned to create sustainable value and deliver competitive total returns for its unitholders. As we look toward 2011, we remain committed to a plan of converting to a dividend paying corporation and to continue to deliver results and capture value adding opportunities with our financial partner Manulife Financial Corporation".

THIRD QUARTER 2009 ACCOMPLISHMENTS

NAL's overall performance exceeded management's financial, operational and strategic objectives. Accomplishments include:

- On October 13, 2009, NAL announced the acquisition of Breaker Energy Ltd. ("Breaker"), an oil weighted junior E&P company (see comments below).

- The Trust remains on track to deliver 2009 full year average production volumes consistent with guidance;

- Third quarter operating costs of $10.52/boe represent a 10 percent decrease from the same period of 2008 and reflect the focus of NAL's operations teams to reduce costs;

- At September 30, 2009, the Trust currently has approximately $200 million in available credit on its lines of $450 million, providing financial flexibility to fund NAL's capital program and continue to participate selectively in corporate and property acquisitions;

- NAL's debt to trailing 12 month cash flow ratios remain solid at 1.25 times excluding convertible debentures and 1.59 times including convertible debentures.

ACQUISITION OF BREAKER ENERGY LTD.

On October 13, 2009, NAL announced the acquisition of Breaker for total consideration of approximately $400 million. The acquisition is consistent with NAL's strategy to grow by adding quality assets with future upside opportunity while maintaining financial capability. The acquisition is expected to increase NAL's year-end production by 28 percent to over 31,000 boe/d and increase reserves by more than 30 percent to approximately 96 MMboe. Breaker's operated assets add significant low risk development projects which complement the Trust's Cardium horizontal multi-stage frac program.

The acquisition is expected to close December 10, 2009, with full integration expected to occur by the end of the first quarter of 2010.

2009 UPDATED GUIDANCE

Based upon positive year-to-date performance, the Trust has updated its
guidance for 2009.

January 2009 August 2009 November 2009
Guidance Guidance Updated Guidance(1)
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Production (boe/d) 22,000 - 23,000 23,000 - 24,000 23,500 - 24,000
Net capital expenditures
($MM) 95 125 -135 135
Operating costs ($/boe) 11.60- 11.90 11.60 - 11.90 11.30 - 11.60
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Note (1) Excludes proposed Breaker acquisition.

OUTLOOK

NAL will outline its 2010 guidance and forecast in mid-January 2010.

FORWARD-LOOKING INFORMATION

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

NON-GAAP MEASURES

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

CONFERENCE CALL DETAILS

At 3:00 p.m. MDT (5:00 p.m. EDT) on November 3, 2009, NAL will hold a conference call to discuss the third quarter 2009 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 1-800-769-8320 toll free across North America. The conference call will also be accessible through the internet at http://events.digitalmedia.telus.com/nal/110309/index.php

A recorded playback of the call will be available until November 10, 2009 by calling 1-800-408-3053, reservation 3565817.

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

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

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Three months ended Nine months ended
Sept. 30 Sept. 30
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2009 2008 2009 2008
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FINANCIAL
Revenue(1) 86,298 175,448 249,610 507,998
Cash flow from operating activities 52,999 98,860 183,235 242,716
Cash flow per unit - basic 0.47 1.03 1.77 2.59
Cash flow per unit - diluted 0.44 0.99 1.64 2.46
Funds from operations 53,766 79,233 167,788 244,031
Funds from operations per unit
- basic 0.48 0.83 1.62 2.60
Funds from operations per unit
- diluted 0.44 0.79 1.50 2.48
Net income 8,249 111,045 3,566 107,206
Distributions declared 30,290 45,968 87,528 135,295
Distributions per unit 0.27 0.48 0.85 1.44
Basic payout ratio:
based on cash flow from operating
activities 57% 46% 48% 56%
based on funds from operations 56% 58% 52% 55%
Basic payout ratio including capital
expenditures(2) :
based on cash flow from operating
activities 136% 96% 100% 99%
based on funds from operations 134% 119% 109% 98%
Units outstanding (000's)
Period end 112,327 95,945 112,327 95,945
Weighted average 112,109 95,664 103,444 93,834
Capital expenditures(3) 42,375 53,189 96,264 109,260
Property acquisitions
(dispositions), net - 373 2,534 8,209
Corporate acquisitions, net 11,035 14 48,385 58,378
Net debt, excluding convertible
debentures(4) 293,680 303,330 293,680 303,330
Convertible debentures (at face
value) 79,744 79,744 79,744 79,744

OPERATING
Daily production
Crude oil (bbl/d) 9,467 9,989 9,725 10,176
Natural gas (Mcf/d) 69,706 70,425 68,778 68,847
Natural gas liquids (bbl/d) 2,334 2,081 2,244 2,083
Oil equivalent (boe/d) 23,418 23,808 23,433 23,733

OPERATING NETBACK (boe)
Revenue before hedging gains 40.06 80.11 39.02 78.12
Royalties (6.94) (16.90) (6.99) (16.19)
Operating costs (10.52) (11.63) (11.42) (10.64)
Other income(5) 0.17 0.12 0.17 0.19
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Operating netback before hedging 22.77 51.70 20.78 51.48
Hedging gains (losses) 8.84 (7.59) 10.82 (6.74)
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Operating netback 31.61 44.11 31.60 44.74
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(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties.
(2) Capital expenditures included are net of non-controlling interest amount
of $0.4 million (2008 - $4.7) for the three months ended September 30,
2009 and $1.5 million (2008 - $5.2) for the nine months ended September
30, 2009, attributable to the Tiberius and Spear properties.
(3) Excludes property and corporate acquisitions.
(4) Bank debt plus working capital and other liabilities, excluding
derivative contracts, notes payable/receivable and future income tax
balances.
(5) Excludes minimal Trust interest paid on notes with Manulife Financial
Corporation.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis ("MD&A") should be read in conjunction with the interim unaudited consolidated financial statements for the three and nine month periods ended September 30, 2009 and the audited consolidated financial statements and MD&A for the year ended December 31, 2008 of NAL Oil & Gas Trust ("NAL" or the "Trust"). It contains information and opinions on the Trust's future outlook based on currently available information. All amounts are reported in Canadian dollars, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("boe") based on a ratio of six thousand cubic feet of natural gas to one barrel of oil. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of boe in isolation may be misleading.

NON-GAAP FINANCIAL MEASURES

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

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

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

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

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

FORWARD-LOOKING INFORMATION

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

In particular, this MD&A contains forward-looking information pertaining to the following, without limitation: the amount and timing of cash flows and distributions to unitholders; reserves and reserves values; 2009 and 2010 production; future tax treatment of the Trust; future structure of the Trust and its subsidiaries; the Trust's tax pools; future oil and gas prices; operating, drilling and completion costs; the amount of future asset retirement obligations; future liquidity and future financial capacity; future results from operations; payout ratios; cost estimates and royalty rates; drilling plans; tie-in of wells; future development, exploration and acquisition activities and related expenditures; rates of return; and the successful acquisition of Breaker Energy Ltd.

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

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

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

RECENT DEVELOPMENTS

PLAN OF ARRANGEMENT - BREAKER ENERGY LTD.

On October 13, 2009, NAL and Breaker Energy Ltd. ("Breaker") entered into an arrangement agreement pursuant to which NAL will acquire all of the issued and outstanding common shares of Breaker by way of Plan of Arrangement. Under the arrangement, Breaker shareholders will receive 0.475 NAL trust units for each share of Breaker held, resulting in the expected issuance of approximately 24.7 million trust units. The transaction is subject to the approval of the Breaker shareholders, the Court of Queen's Bench of the Province of Alberta and regulatory authorities, and is expected to close on December 10, 2009.

The acquisition is anticipated to add 6,700 boe/d of production to the Trust and 23 million boe of proved plus probable reserves, in addition to 140,000 acres of net undeveloped land and $270 million of tax pools.

DISPOSITION OF NON-CORE PROPERTY

The sale of a non-operated property is expected to close in the fourth quarter for net proceeds of $15 million, subject to final adjustments.

ACQUISITION OF SPEARPOINT ENERGY CORP.

Effective August 10, 2009, the Trust acquired all of the issued and outstanding common shares of Spearpoint Energy Corp. ("Spearpoint") for cash of $10.6 million, prior to acquisition costs. The assets of Spearpoint include natural gas production in Alberta and a farm-in agreement with BP Canada Energy Company.

Concurrent with the corporate acquisition, the Trust entered into an Asset Purchase and Sale Agreement ("PSA") with Manulife Financial Corporation ("MFC"), pursuant to which MFC acquired a 40 percent working interest in all of the Spearpoint petroleum and natural gas properties and the farm-in agreement for a base price of $6.5 million payable in cash.

Included within the PSA is a base price adjustment clause that ensures the Trust and MFC share 60 percent / 40 percent, respectively, in all assets or liabilities related to Spearpoint that pertain to periods on or prior to the effective date of the acquisition, regardless of their date of discovery or disclosure. The base price adjustment calculation adjusts the purchase price that MFC pays the Trust for any change in working capital from amounts determined at the time the base price of $6.5 million was established. As at September 30, 2009, the Trust had a receivable from MFC of $0.3 million relating to these price adjustments.

After taking into effect the MFC disposition and MFC's share of the assets and liabilities to be settled under the base price adjustment clause, the Trust acquired property, plant and equipment of $10.7 million and a future income tax asset of $0.5 million and assumed liabilities including a note payable of $5.7 million, a working capital deficiency of $0.9 million and asset retirement obligations of $0.4 million, for consideration of $4.2 million.

MFC is a related party to the Trust, see "Related Party Transactions".

ACQUISITION OF ALBERTA CLIPPER ENERGY INC.

Effective June 1, 2009, the Trust acquired all of the issued and outstanding common shares of Alberta Clipper Energy Inc. ("Clipper"), which has interests in petroleum and natural gas properties and undeveloped land in Alberta and northeast British Columbia.

The Trust issued 5.7 million trust units at a price of $6.45 a trust unit for total consideration, before acquisition costs, of $36.6 million. The trust unit price was based on the weighted average market price of trust units at the date of announcement, being March 23, 2009. The purchase price included the assumption of $78.9 million in bank debt.

Concurrent with the corporate acquisition, the Trust entered into an Asset Purchase and Sale Agreement (the "Clipper PSA") with MFC, pursuant to which MFC acquired a 50 percent working interest in all of the Clipper petroleum and natural gas properties for a base price of $52.5 million payable in cash. The proceeds received from MFC were used to partially repay the assumed bank debt.

Included within the Clipper PSA is a base price adjustment clause that ensures the Trust and MFC share equally in all assets or liabilities related to Clipper that pertain to periods on or prior to the effective date of the acquisition, regardless of their date of discovery or disclosure. The base price adjustment calculation will adjust the purchase price that MFC pays the Trust for any change in working capital from amounts determined at the time the base price of $52.5 million was established. In addition, the costs associated with contracts outstanding at the date of acquisition will be equally shared between both parties on an ongoing basis, as the obligations are settled by the Trust. The amounts due under this base price adjustment clause are to be settled no more frequently than quarterly commencing December 2009. As at September 30, 2009, the Trust had a receivable from MFC of $0.8 million relating to these price adjustments.

As a result, after taking into effect the MFC disposition and MFC's share of the assets and liabilities to be settled under the base price adjustment clause, the Trust acquired property, plant and equipment of $55.4 million, a derivative contract of $0.4 million and a future tax asset (reflecting the excess of tax pools over book value) of $17.9 million, representing assets totaling $73.7 million, and assumed liabilities including asset retirement obligations of $7.3 million, bank debt of $26.4 million, a working capital deficiency of $1.1 million and a lease obligation of $1.5 million, for consideration of $37.4 million, including estimated acquisition costs of $0.8 million.

EXPLORATION & DEVELOPMENT ACTIVITIES

The Trust spent $34.6 million on drilling, completion and tie-in operations during the third quarter of 2009, compared to $39.2 million during the third quarter of 2008 and drilled 26 (12.3 net) wells as compared to 33 (15.7 net) wells during the same period in 2008.

Drilling in the quarter was focused on horizontal oil wells in Saskatchewan and Alberta. The Trust is expecting to drill 78 (37 net) wells for full year 2009 including 57 (25 net) that have been drilled year-to-date and a 21 (12 net) well program to be executed in the fourth quarter. The remaining drilling program will also be heavily weighted to oil including 8 (6 net) Cardium and 11 (5 net) Mississippian horizontals. Full year estimates consist of 17 (4 net) gas wells and 61 (33 net) oil wells of which 24 (16 net) will be Cardium and 32 (15 net) will be Mississippian wells.

Third Quarter Drilling Activity

Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
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Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 19 11.3 0 0 0 0 0 0 19 11.3
Non-operated wells 1 0.2 6 0.8 0 0 0 0 7 1.0
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Total wells drilled 20 11.5 6 0.8 0 0 0 0 26 12.3
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Southeast Saskatchewan

In Saskatchewan, there were 10 (4.7 net) horizontal oil wells drilled during the third quarter. Activity was focused on the Mississippian in Alida, Torquay and Nottingham with initial production rates ranging from 50-250 bbls/d. The Trust intends to drill 11 (5.0 net) horizontal Mississippian oil wells in the fourth quarter following up on successful new pool discoveries, infills and extensions. While the Cardium play in Alberta has recently been the focus of market attention, the economics in Mississippian light oil projects remain as good or better and is the reason the Trust continues to balance its capital expenditures between the two distinctly different resource plays. The Nottingham gas plant expansion was commissioned in October and plans to bring on incremental volumes in November are currently underway.

Alberta

In Alberta, NAL participated in drilling 15 (7.4 net) wells including 10 (6.7 net) wells in the Cardium at Garrington, Cochrane and Pine Creek. Many completion and tie-in operations were running through the end of the quarter with first month production numbers after load fluid recovery expected in November. Overall, results remain in-line with expectations and management remains encouraged by the potential of this resource. For the remainder of the year, the Trust intends to drill 8 (6 net) horizontal Cardium oil wells in Garrington and Pine Creek to delineate significant Cardium acreage related to recently announced transactions. Reduced drilling and completion costs coupled with execution efficiency gains continue to be a focus for NAL and it is expected that costs will be lower as the program matures. Current drill, completion and tie-in costs for Cardium horizontal wells are in the $3.0 million range.

Northeast British Columbia

Production in Sukunka was significantly impacted by failures related to third party operated gathering systems and several unplanned outages at the Pine River Plant. This down time equated to 600 boe/d of lost production in the quarter. However, due to low gas prices throughout the period, funds flow from operations was only impacted by $330,000. The first week of production in October was back at full capability, producing approximately 2,600 boe/d. The non-operated well at a-100-c (Trust 20 percent working interest) reached total depth during the quarter, initial completion work was done and the well is currently standing while further completion operations are being evaluated.

FOCUS OF FUTURE ACTIVITY

Commodity prices have been challenging in 2009 but NAL's strong balance sheet, balanced production mix, hedging strategy and support from its partner MFC have positioned the Trust well to take advantage of challenging market conditions. Upon the completion of the recently announced acquisition of Breaker, the Trust will have completed four significant transactions during 2009, increasing production and reserves by more than 30 percent and adding access to a broad land position of more than 1.5 million gross acres. The Trust has also added significant prospecting capability with the addition of key technical staff. Efforts are underway to catalogue a multi-year oil and gas drilling inventory from this significantly expanded land portfolio.

The use of cost effective horizontal drilling techniques with multi-stage fracing has unlocked significant low risk oil reserves and value for our unitholders. NAL is well positioned in the Cardium oil resource with acreage at Garrington, Cochrane and Pine Creek in central Alberta, and in Mississippian oil in southeast Saskatchewan with new opportunities added in the Wabamun formation (at Irricana) and Leduc formation (at Millard Lake) through the proposed Breaker transaction. Current oil prices coupled with provincial royalty incentive programs drive compelling economics for oil development that produce recycle ratios exceeding two times, rates of return in the 30 - 50 percent range, and attractive netbacks. The Trust currently intends to remain focused on an oil weighted program through 2010, but retains significant leverage and flexibility to shift capital toward gas projects should a recovery in natural gas prices emerge.

NAL continues to build gas inventory on its expanded land position but will wait on a gas price recovery which yields economics that can compete with the Trust's expanded oil portfolio. The use of horizontal drilling and multi stage fracing will play a large part in any gas development program in the future as the Trust currently has catalogued more than 100 ready-to-drill horizontal wells in the Rock Creek, Falher, Halfway, Viking, Doig and Mannville zones. It is expected that NAL will spend 20 - 30 percent of its exploration and development budget in 2010 on strategic gas drilling to prove up reserves. Selective prospects with high initial gas rate potential and high liquid yields that deliver competitive economic returns will be considered in the program to take advantage of attractive government incentives.

CAPITAL EXPENDITURES

Capital expenditures, before property acquisitions, for the quarter ended September 30, 2009 totaled $42.4 million compared with $53.2 million for the quarter ended September 30, 2008. The decrease in capital spending year-over-year is largely a function of relatively higher land and facilities spending during the third quarter of 2008. NAL is on track with plans to evaluate the significant oil opportunities that have been compiled over the course of the year through strategic partnerships and land acquisitions. Crude prices in the quarter have continued to be relatively strong, supporting increased spending, with full year capital expenditures expected to be $135 million excluding acquisitions.

On a year-to-date basis, capital expenditures, before property acquisitions, totaled $96.3 million compared to $109.3 million in the comparable period of 2008.

Capital Expenditures ($000s)

Drilling, completion and production
equipment 34,599 39,237 72,685 79,520
Plant and facilities 1,264 4,542 9,654 11,249
Seismic 806 69 1,053 876
Land 2,829 8,293 5,290 12,115
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Total exploitation and development 39,498 52,141 88,682 103,760
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Office equipment 128 562 508 1,181
Capitalized G&A 1,266 824 4,260 3,167
Capitalized unit-based compensation 1,484 (338) 2,814 1,152
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Total other capital 2,878 1,048 7,582 5,500
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Total capitalized expenditures
before acquisitions 42,376 53,189 96,264 109,260
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Property acquisitions
(dispositions), net - 373 2,534 8,209
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Total capitalized expenditures 42,376 53,562 98,798 117,469
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PRODUCTION

Third quarter 2009 production was 23,418 boe/d, compared to production of 23,808 boe/d in the same period of 2008. This two percent decline was entirely attributed to unplanned third party facilities outages at Sukunka that negatively impacted the quarter by 600 boe/d. The Trust's internal forecast was 23,700 boe/d for the third quarter and, without this outage volumes would have been in the 24,000 boe/d range. It is anticipated that fourth quarter production will be 24,000-24,400 boe/d dependent on the timing of new production tie-ins. Full year average production is still expected to be at the higher end of our guidance of 23,000 - 24,000 boe/d. Provided the proposed Breaker acquisition closes as scheduled, the Trust anticipates fourth quarter average production to be 25,000 - 25,500 boe/d, with the impact on full year average volumes being muted due to the December 10, 2009 close date. Year-over-year, oil production was down five percent in the quarter which was mainly attributable to production declines in Saskatchewan. The development program in Saskatchewan was reduced in response to substantially lower commodity prices during the first quarter of 2009 and the program was not ramped back up until after spring break-up.

Average Daily Production Volumes

Oil equivalent volumes of 23,418 boe/d for the third quarter of 2009 and 23,433 boe/d year-to-date include 370 boe/d (2008 - 379 boe/d) and 412 boe/d (2008 - 343 boe/d), respectively, attributable to the non-controlling interest in the Tiberius and Spear properties (see "Related Party Transactions"). The Trust's net production, after deducting the non-controlling interest, is 23,048 boe/d for the third quarter of 2009 (2008 - 23,429 boe/d) and 23,021 boe/d (2008 - 23,390 boe/d) year-to-date.

Oil and natural gas liquids totaled 51 percent of production with natural gas at 49 percent during the first nine months of 2009.

Production Weighting

REVENUE

Gross revenue from oil, natural gas and natural gas liquids sales, after transportation costs and prior to hedging, totaled $86.3 million for the three months ended September 30, 2009, 51 percent lower than the third quarter of 2008. The decrease is due to a two percent decrease in production and a 50 percent decrease in the average realized price per boe, driven by a 41 percent decrease in the realized crude oil price and a 63 percent decrease in the realized natural gas price. The decrease in realized prices reflects lower West Texas Intermediate ("WTI") prices, partially offset by a weaker Canadian dollar, and lower AECO prices in the third quarter of 2009.

For the nine month period ended September 30, 2009, revenue after transportation costs totaled $249.6 million, a decrease of 51 percent from the comparable period in 2008. The decrease is attributable to a 50 percent decrease in the average realized price per boe and a one percent decrease in production. The decrease in realized price reflects lower WTI prices, partially offset by a weaker Canadian dollar, and lower AECO prices in 2009.

Revenue
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Three months ended Nine months ended
Sept. 30 Sept. 30
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2009 2008 2009 2008
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Revenue(1) ($000s)
Oil 58,543 104,949 154,024 297,894
Gas 19,718 53,152 73,834 165,392
NGLs 8,069 15,034 21,199 41,805
Sulphur (32) 2,313 553 2,907
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Total revenue 86,298 175,448 249,610 507,998
$/boe 40.06 80.11 39.02 78.12
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(1) Oil, natural gas and liquid sales less transportation costs and prior
to royalties and hedging.

OIL MARKETING

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

NAL's third quarter average realized Canadian crude oil price per barrel, net of transportation costs excluding hedging, was $67.22, as compared to $114.20 for the comparable quarter of 2008. The decrease in realized price quarter-over-quarter of 41 percent, or $46.98/bbl, was primarily driven by a 42 percent decrease in WTI (U.S.$/bbl) over the comparable period, partially offset by a five percent decrease in the value of the Canadian dollar.

For the third quarter of 2009, NAL's crude oil price differential was 90 percent, a decrease of three percentage points from the comparable period in 2008. The differential is calculated as realized price as a percentage of WTI stated in Canadian dollars. The decrease in 2009 resulted from a wider differential between WTI and Edmonton/Cromer posted prices, due to lower demand for light crude in western Canada during the third quarter.

For the nine months ended September 30, 2009, NAL's average oil price was $58.01 per barrel as compared to $106.84 for the comparable period in 2008. The 46 percent decrease in realized price was driven by a 50 percent decrease in WTI (US$/bbl) and a decrease in crude oil differentials to 87 percent from 92 percent in 2008, partially offset by a 15 percent decrease in the value of the Canadian dollar.

Natural gas liquids averaged $37.58/bbl in the third quarter of 2009, a 52 percent decrease from the $78.53/bbl realized in 2008. For the nine months ended September 30, 2009, natural gas liquids averaged $34.60/bbl, a decrease of 53 percent from the comparable period in 2008.

NATURAL GAS MARKETING

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

For the three months ended September 30, 2009, the Trust's natural gas sales averaged $3.07/Mcf compared to $8.20/Mcf in the comparable period of 2008, a decrease of 63 percent. The quarter-over-quarter decrease in gas prices was attributable to a 61 percent decrease in the benchmark AECO daily spot prices.

Prices for Lake Erie natural gas decreased to $3.77/Mcf in the third quarter of 2009, compared to $9.98/Mcf in 2008, a decrease of 62 percent. Lake Erie production of 3.5 mmcf/d accounted for five percent of the Trust's natural gas production in the third quarter of 2009, the same percentage experienced during the comparable period of 2008. Natural gas sales from the Lake Erie property generally receive a higher price due to the proximity of the Ontario and Northeastern U.S. markets.

For the nine months ended September 30, 2009, NAL averaged $3.93/Mcf, a 55 percent decrease from the $8.77/Mcf realized in the comparable period of 2008. The decrease in natural gas prices was attributable to a 56 percent decrease in the benchmark AECO daily spot prices.

Average Pricing
(net of transportation charges)
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Three months ended Nine months ended
Sept. 30 Sept. 30
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2009 2008 2009 2008
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Liquids
WTI (US$/bbl) 68.30 117.98 57.00 113.29
NAL average oil (Cdn$/bbl) 67.22 114.20 58.01 106.84
NAL natural gas liquids (Cdn$/bbl) 37.58 78.53 34.60 73.25

Natural Gas (Cdn$/mcf)
AECO - daily spot 2.98 7.73 3.78 8.64
AECO - monthly 3.02 9.25 4.11 8.55
NAL Western Canada natural gas 3.04 8.11 3.88 8.68
NAL Lake Erie natural gas 3.77 9.98 5.05 10.44
NAL average natural gas 3.07 8.20 3.93 8.77

NAL oil equivalent before hedging
(Cdn$/boe - 6:1) 40.06 80.11 39.02 78.12
Average foreign exchange rate
(Cdn$/US$) 1.0974 1.0418 1.1698 1.0186
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RISK MANAGEMENT

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

NAL's commodity hedging policy currently provides authorization to hedge up to 60 percent of forecasted total production, net of royalties. This was increased from 50 percent to 60 percent at the November 3, 2009 Board meeting. Management's practice is to hedge more near-term volumes on a six month forward basis with more limited volumes hedged in future periods. The execution of NAL's commodity hedging program is layered in using a combination of swaps and collars. As at September 30, 2009, NAL had several financial WTI oil contracts and AECO natural gas contracts in place.

NAL's interest rate hedging policy currently provides authorization to hedge up to 50 percent of outstanding debt for periods of up to five years. As at September 30, 2009, NAL had several interest rate swaps outstanding with a total notional value of $139 million.

NAL's foreign exchange hedging policy currently provides authorization to hedge up to 50 percent of the Trust's U.S. dollar exposure for periods of up to 24 months. As at September 30, 2009, NAL had several exchange rate swaps outstanding with a total notional value of U.S.$64.0 million.

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

All derivative contracts are recorded on the balance sheet at fair value based upon forward curves at September 30, 2009. 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 at September 30, 2009. Accordingly, the magnitude of the unrealized gain or loss will continue to fluctuate with changes in commodity prices, interest rates and foreign exchange rates.

The fair value of the derivatives at September 30, 2009 was a net asset of $12.3 million, comprised of a $2.5 million asset on interest rate swaps, a $4.8 million asset on gas contracts and a $5.4 million asset on foreign exchange contracts, partially offset by a $0.4 million liability on oil contracts.

Third quarter income for 2009 includes a $5.5 million unrealized loss on derivatives resulting from the change in the fair value of the derivative contracts during the quarter from an unrealized gain of $17.8 million at June 30, 2009, to an unrealized gain of $12.3 million at September 30, 2009. The $5.5 million unrealized loss was comprised of a $0.2 million unrealized loss on crude oil contracts, an $8.2 million unrealized loss on natural gas contracts and a $0.4 million unrealized loss on interest rate swaps, partially offset by a $3.3 million unrealized gain on foreign exchange swaps.

For the nine months ended September 30, 2009, income includes an unrealized loss of $53.5 million, resulting from the change in the fair value of the derivative contracts during the period, from an unrealized gain of $65.4 million at December 31, 2008 and a $0.4 million unrealized gain acquired with Clipper, to an unrealized gain of $12.3 million at September 30, 2009. The unrealized loss was comprised of a $56.1 million unrealized loss on crude oil contracts and a $5.6 million unrealized loss on natural gas contracts, partially offset by a $2.8 million unrealized gain on interest rate swaps and a $5.4 million unrealized gain on foreign exchange swaps.

The risk management policies for 2010 are expected to remain consistent with 2009. The Trust's current positions are summarized in the tables below.

The gain/loss on all forward derivative contracts is as follows:

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

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Three months ended Nine months ended
Sept. 30 Sept. 30
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2009 2008 2009 2008
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Unrealized gain (loss):
Crude oil contracts (184) 70,892 (56,151) 13,236
Natural gas contracts (8,251) 40,161 (5,560) 5,134
Interest rate swaps (374) - 2,776 -
Exchange rate swaps 3,310 - 5,448 -
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Unrealized gain (loss) (5,499) 111,053 (53,487) 18,370
Realized gain (loss):
Crude oil contracts 7,526 (13,119) 44,179 (38,151)
Natural gas contracts 8,331 (3,508) 19,794 (5,697)
Interest rate swaps (226) - (433) -
Exchange rate swaps 3,188 - 5,200 -
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Realized gain (loss) 18,819 (16,627) 68,740 (43,848)
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Gain (loss) on derivative
contracts 13,320 94,426 15,253 (25,478)
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The following is a summary of the realized gains and losses on risk
management contracts:

Realized Gain (Loss) on Derivative Contracts

Average natural gas volumes hedged
(GJ/d) 23,130 30,000 20,850 26,735
Natural gas realized gain (loss)
($000s) 8,331 (3,508) 19,794 (5,697)
Gain (loss) per GJ hedged ($) 3.92 (1.27) 3.48 (0.78)

Average BOE hedged (boe/d) 8,387 9,839 7,656 8,936
Total realized commodity contracts
gain ($000s) 15,857 (16,627) 63,973 (43,848)
Gain (loss) per boe hedged ($) 20.55 (18.37) 30.61 (17.91)
Gain (loss) per boe ($) 7.36 (7.59) 10.00 (6.74)

Interest rate swaps realized loss
($000s) (226) - (433) -
Loss per boe ($) (0.10) - (0.07) -

Exchange rate swaps realized gain
($000s) 3,188 - 5,200 -
Gain per boe ($) 1.48 - 0.82 -

Total realized gain (loss) ($000s) 18,819 (16,627) 68,740 (43,848)
Gain (loss) per boe ($) 8.74 (7.59) 10.75 (6.74)
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Average hedged boes for the third quarter of 2009 were 8,387 as compared to
6,394 for the second quarter of 2009.

NAL has the following interest rate risk management contracts outstanding:

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INTEREST Remaining Amount Trust Fixed Counterparty
RATE Term (Cdn$ MM)(1) Rate Floating Rate
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Swaps-floating Oct 2009 -
to fixed Dec 2011 $ 39.0 1.5864% CAD-BA-CDOR (3 months)
Swaps-floating Oct 2009 -
to fixed Jan 2013 $ 22.0 1.3850% CAD-BA-CDOR (3 months)
Swaps-floating Oct 2009 -
to fixed Jan 2014 $ 22.0 1.5100% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2013 $ 14.0 1.8500% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2013 $ 14.0 1.8750% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2014 $ 14.0 1.9300% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2014 $ 14.0 1.9850% CAD-BA-CDOR (3 months)
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(1) Notional debt amount

NAL has the following exchange rate risk management contracts outstanding:

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EXCHANGE Remaining Amount Trust Fixed Counterparty
RATE Term (US$ MM)(1) Rate Floating Rate
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Swaps-floating Oct 2009 -
to fixed Nov 2009 $ 4.0 1.2730 BofC Average Noon Rate
Swaps-floating Oct 2009 -
to fixed Nov 2009 $ 4.0 1.2875 BofC Average Noon Rate
Swaps-floating Oct 2009 -
to fixed Nov 2009 $ 4.0 1.2625 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1583 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1100 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1200 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1225 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1300 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1420 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1525 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1000 BofC Average Noon Rate
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(1) Notional US$ denominated commodity sales

NAL has the following commodity risk management contracts outstanding:

CRUDE OIL Q4-09 Q1-10 Q2-10 Q3-10 Q4-10
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US$ Collar Contracts
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$US WTI Collar Volume (bbl/d) 300 3,500 3,300 2,600 2,400
Bought Puts - Average Strike
Price ($US/bbl) $ 62.67 $ 61.86 $ 62.27 $ 64.90 $ 65.10
Sold Calls - Average Strike
Price ($US/bbl) $ 71.85 $ 72.90 $ 73.23 $ 76.42 $ 76.88

US$ Swap Contracts
-------------------
$US WTI Swap Volume (bbl/d) 1,700 700 1,200 - -
Average WTI Swap Price
($US/bbl) $ 61.94 $ 75.36 $ 75.67 - -

Cdn$ Collar Contracts
----------------------
$Cdn WTI Collar Volume
(bbl/d) 1,500 300 - - -
Bought Puts - Average
Strike Price ($Cdn/bbl) $ 102.07 $ 66.00 - - -
Sold Calls - Average
Strike Price ($Cdn/bbl) $ 137.63 $ 80.17 - - -

Cdn$ Swap Contracts
--------------------
$Cdn WTI Swap Volume (bbl/d) 1,300 - - - -
Average WTI Swap Price
($Cdn/bbl) $ 92.55 - - - -

Total Oil Volume (bbl/d) 4,800 4,500 4,500 2,600 2,400
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NATURAL GAS Q4-09 Q1-10 Q2-10 Q3-10 Q4-10
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Collar Contracts
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AECO Collar Volume (GJ/d) 1,685 - - - -
Bought Puts - AECO Average
Strike Price ($Cdn/GJ) $ 8.90 - - - -
Sold Calls - AECO Average
Strike Price ($Cdn/GJ) $ 11.44 - - - -

Swap Contracts
---------------
AECO Swap Volume (GJ/d) 32,663 30,000 30,000 31,000 14,337
AECO Average Price ($Cdn/GJ) $ 5.57 $ 5.86 $ 5.60 $ 5.62 $ 5.67

Total Natural Gas Volume
(GJ/d) 34,348 30,000 30,000 31,000 14,337
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For the remainder of 2009, the Trust has outstanding contracts representing approximately 49 percent of its net liquids and natural gas production after royalties, assuming a royalty rate of 17.5 percent.

ROYALTY EXPENSES

Crown, freehold and overriding royalties were $15.0 million for the three months ended September 30, 2009. Expressed as a percentage of gross sales net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 17.3 percent for the quarter ended September 30, 2009, a decrease from the 21.1 percent experienced in the same period of the previous year.

Royalties decreased to $6.94 per boe for the third quarter of 2009, a decrease of 59 percent compared to the third quarter of 2008. The decrease is attributable to lower commodity prices on a quarter-over-quarter basis.

On a year-to-date basis, royalties were $44.7 million, down from $105.3 million in the comparable period of 2008. Expressed as a percentage of gross sales net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 17.9 percent as compared to 20.7 percent in the comparable period of 2008.

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

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

On March 3, 2009, the Government of Alberta announced a new three point incentive program for the energy sector. Firstly, there is a drilling royalty credit for new conventional oil and natural gas wells. The credit is on a sliding scale, based on prior year production levels, to a maximum of $200 per metre drilled or 50 percent of the royalties owed. Secondly, there is a new well incentive program that provides for a maximum five per cent royalty rate for the first 12 months of production up to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas. The 12 month period starts on the date of production provided it occurs between April 1, 2009 and March 31, 2010. Thirdly, the province will invest $30 million in a fund committed to abandoning and reclaiming old well sites, to encourage the clean up of inactive oil and gas wells. On June 25, 2009, the Government of Alberta announced a one year extension to the drilling royalty credit and new well incentive program to March 31, 2011. The five percent royalty rate incentive is reported within royalties and the $200 per metre drilling credit is reported against capital.

For the nine months ended September 30, 2009, 29 percent of crude oil and 70 percent of natural gas production is from Alberta.

Royalty Expenses

OPERATING COSTS

Operating costs averaged $10.52 per boe for the quarter ended September 30, 2009, a ten percent decrease from $11.63 per boe for the quarter ended September 30, 2008. Year-over-year operating cost decreases are a direct result of an aggressive program focused on cost reduction in NAL's operations.

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