CALGARY--(CCNMatthews - March 1) - NAL Oil
& Gas Trust (TSX:NAE.UN) (the "Trust" or "NAL") today announced its
financial and operational results for the fourth quarter and full year
2005. All amounts are in Canadian dollars unless otherwise stated.
Highlights
- NAL continued to deliver positive production momentum in the
fourth quarter of 2005 through performance of the assets acquired from
Addison Energy earlier in the year, through focused capital expenditures
and through strong operating performance in all core areas. Fourth
quarter 2005 production volumes averaged 20,514 barrels of oil
equivalent (boe) per day, an increase of 58% over the fourth quarter of
2004. 2005 production averaged 19,018 boe per day versus 13,139 boe/day
in 2004, an increase of 45 percent year-over-year. NAL's exit rate was
20,641 boe/day.
- Funds from operations for the year ended December 31, 2005
amounted to $221 million ($3.17/unit), an increase of 94 percent from
$114 million ($2.20/unit) in 2004. Funds from operations in the fourth
quarter of 2005 were $66 million ($0.90/unit), an increase of 128
percent from $29 million ($0.54/unit) in the same period in 2004.
- Higher oil and gas prices, combined with higher production
volumes, allowed NAL to increase its monthly distribution from $0.16 per
unit to $0.19 per unit beginning with the distribution paid in
November, 2005.
- For full-year 2005, NAL moved toward a more balanced production
mix, producing 59 percent crude oil and natural gas liquids, and 41
percent natural gas.
- Driven by high quality production, low operating costs and
proximity to markets, NAL continued to achieve top quartile operating
netbacks of $37.49 per boe, before hedging losses, in 2005.
- Proven plus probable reserves totaled 63.4 million boe at year-end
2005, up 69 percent from 37.6 million boe in 2004. Seventy percent of
NAL's reserves are classified as Proved, and 65 percent are classified
as Proved Producing. Consequently, 93 percent of NAL's proved reserves
are onstream and producing.
- NAL's proven plus probable reserves per trust unit increased by 21
percent to 0.858 boe per unit at year-end 2005, up from 0.708 boe per
unit at year-end 2004.
- Based on NAL's production guidance for 2006, the Trust's reserve
life index at December 31, 2005 was 8.9 years (proved plus probable
reserves), up from 8.0 years at year-end 2004.
- NAL's 2005 finding, development and acquisition cost - including
the purchase of Addison Energy and changes in future development costs -
was $15.90 per boe on a proven plus probable basis. Its investment of
$74.7 million on development activities increased average production in
December 2005 by approximately 3,200 boe per day, yielding a capital
efficiency rate of $23,500 per boe per day.
- Long-term debt (net of working capital) was reduced from over $250
million at the time of the Addison acquisition to under $200 million by
year-end 2005, delivering a debt to cash flow ratio of 0.88 based on
2005 funds from operations.
- NAL paid out a total of $142 million in 2005, representing a
payout ratio of 64 percent versus 84 percent in 2004. Fourth quarter
distributions totaled nearly $42 million representing a payout ratio of
64 percent, compared to distributions of $25 million in the fourth
quarter of 2004, representing a payout ratio of 88 percent.
- NAL was awarded the Canadian Association of Petroleum Producers
("CAPP") Steward of Excellence Award, Health and Safety Category for its
Improved Safety Management System in early 2005. In addition, NAL was
recently recognized with the Workers' Compensation Board Alberta
Worksafe award for Safety Leadership as part of the Alberta Business
Awards of Distinction.
- NAL was included among the Income Trusts added to the S&P/TSX Composite Index in December 2005.
- Restructuring of the Trust's management contract with NAL
Resources is expected to be completed by the end of the second quarter
of 2006, and will result in lower management fees for the Trust.
President and Chief Executive Officer Andrew Wiswell characterized
2005 as a year of change and positive momentum for NAL, and said that
the outlook for 2006 was very positive. "The Trust achieved its revised
2005 guidance of 19,000 boe/day production, and finished the year
strongly at over 20,500 boe/day.
"Our acquisition of Addison Energy early in 2005 extended our
reserve life index, delivered better crude oil / natural gas production
balance, and positioned us for future opportunities primarily in Central
Alberta. Our quality asset base continued to deliver top quartile
netbacks and our management agreement restructuring will allow us to
better manage our costs. We reduced our debt steadily through the year
and were able to increase our monthly distribution from $0.16 per unit
to $0.19 per unit in November. As we approach our 10th anniversary in
the spring of 2006, NAL can be justifiably proud of its track record of
increasing production and distributions.
"As we look forward, NAL will undertake an ambitious $95 million
capital program in 2006, and while the majority of that spending will
come in the second half, the ability to access our properties in
Southeast Saskatchewan and Central Alberta allows us to drill
year-round. We expect to be able to maintain or increase our production
in 2006, and sustain our distributions throughout the year."
Management Contract
The Trust recently announced the restructuring of the management
contract with NAL Resources Management Limited (the "Manager"). The
Manager is a wholly owned subsidiary of Manulife Financial Corporation
("Manulife"). The Agreement has been in place since the Trust's
inception in 1996.
In connection with the restructuring of the Agreement, the Trust
will pay a one time $30 million restructuring fee (the "Restructuring
Fee") to the Manager. The Manager will then subscribe for 1,592,357
trust units of the Trust at a price of $18.84 per trust unit. The trust
units will be subject to a contractual lock-up agreement, which will
restrict their disposition over a three-year period. The transaction is
expected to close on or about May 31, 2006 and is subject to completion
of final documentation and unitholder approval.
The Trust, NAL Energy Inc. and the Manager have agreed to prepare
and enter into a new management agreement (the "New Agreement"), which
will provide the following principal benefits for the Trust:
- Eliminating the base and performance fees payable by the Trust
effective January 1, 2006. These fees totaled approximately $21 million
over the period 2003 to 2005, with $10 million being paid in full-year
2005.
- Maintaining the existing management team to manage the Trust's assets and the oil and gas assets of Manulife.
- Committing the Manager to a 10-year contract with two five-year
renewal terms (at the Trust's option) with the Manager having the right
to give an 18-month termination notice effective at the end of each of
the five-year renewal periods. The Trust will be permitted to terminate
the New Agreement at any time on 90 days notice with no further
termination payment required.
- Enhancing the Trust's oversight and governance of the affairs of
the Manager by including representatives of the Trust on the Manager's
board of directors.
- Requiring the Manager and Manulife to obtain the consent of the
Trust prior to the completion of certain transactions involving the
Manager.
- Providing the Trust the right to purchase the Manager in certain
circumstances for nominal value plus a portion of the book value of the
capital assets of the Manager.
In addition to the benefits outlined above, the elimination of the
base and performance fees payable by the Trust to the Manager is
expected to be accretive to unitholders on a net asset value per unit
basis and 2006 cash flow per unit basis.
RBC Capital Markets has provided the Independent Committee with a
verbal opinion subject to a review of the definitive documentation, that
the consideration to be paid to the Manager by the Trust is fair, from a
financial point of view, to the Trust. The Independent Committee and
the Trust Board have approved the transaction.
Outlook for 2006
NAL has established a capital budget of $95 million for 2006, and
expects to drill 197 gross (72 net) wells this year. Production is
expected to average between 19,200 and 19,800 boe/day. Because of a high
level of oilfield activity and demand for services, operating costs are
expected to trend higher in 2006. General and administrative expense is
also expected to increase this year, reflecting the competitive nature
of the employment market and generally higher costs of goods and
services. Interest rates have trended higher, but the impact on interest
expense should be offset by a lower level of long-term debt
outstanding.
NAL has the capacity to make acquisitions in 2006, and actively
reviews all acquisition opportunities. However, the Trust has more than
two years of attractive drilling opportunities, which will allow it to
continue to replace production from its existing properties.
At 8:00 a.m. MST on Thursday, March 2, 2006 NAL will conduct a
conference call to discuss its fourth quarter and full year 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
403-398-9531 (Calgary Local) or 1-800-814-4862 (Toll-Free). Those
who are unable to listen to the call live may listen to a recording of
it by calling 1-416-640-1917 (Toronto) or 1-877-289-8525
Toll-Free, passcode 21178013 followed by the number sign. This call will
be available for replay until Thursday, March 9 at 23:59 EST.
Oil and Gas Reserves
NAL's 2005 year-end reserves were evaluated by McDaniel &
Associates Consultants Ltd. ("McDaniels"), independent engineering
consultants in Calgary, in accordance with National Instrument ("NI")
51-101. At December 31, 2005, the Trust's proved reserves total 44.6
million barrels of oil equivalent(*) ("boe") (*) and proved plus
probable (P+P) reserves amount to 63.4 million boe.
NAL Oil & Gas Trust has a reserves committee, composed entirely
of independent directors, which is responsible for appointing the
Trust's independent engineering consultants and determining the scope of
the annual reserves review.
The acquisition of 70 percent of Addison Energy Inc. effective
February 10, 2005 added 29.1 million boe of P+P reserves to the Trust.
Subsequent activity on the Addison properties resulted in the
development of 1.1 million boe of P+P reserves. These reserves are
included within the acquisition totals in the accompanying
reconciliation table, and as such have not been added to the improved
recovery category.
Improved recovery on other NAL assets resulted in the addition of
3.3 million boe (P+P), over and above the volumes previously booked
as undeveloped. These represent incremental reserves associated with
development activities in NAL's assets, not including the Addison
properties. In addition, overall technical revisions contributed another
0.4 million boe of P+P reserves, resulting in total additions to the
P+P reserves of 3.7 million boe.
The following tables summarize NAL's estimated reserves volumes and
values using McDaniels' price forecasts as of January 1, 2006. Gross
reserves volumes are based on company working interests before deduction
of royalties payable, and exclude any wells or properties in which NAL
has only a royalty interest. Net reserves represent company working
interest reserves after deducting royalties payable, plus royalty
interest reserves.
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SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2005
FORECAST PRICES AND COSTS
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RESERVES
LIGHT AND NATURAL
MEDIUM OIL GAS
RESERVES CATEGORY Gross Net Gross Net
(Mbbl) (Mbbl) (MMcf) (MMcf)
PROVED
Developed Producing 18,908 16,319 107,587 90,273
Developed Non-Producing 176 151 2,341 1,894
Undeveloped 745 652 9,594 8,578
---------------------------------------
TOTAL PROVED 19,829 17,122 119,522 100,744
PROBABLE 8,626 7,482 47,045 39,402
---------------------------------------
TOTAL PROVED PLUS PROBABLE 28,455 24,604 166,567 140,146
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RESERVES
NATURAL GAS
LIQUIDS BOE (6:1)
RESERVES CATEGORY Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl)
PROVED
Developed Producing 4,650 3,446 41,489 34,811
Developed Non-Producing 71 52 636 519
Undeveloped 96 71 2,440 2,152
---------------------------------------
TOTAL PROVED 4,817 3,569 44,566 37,482
PROBABLE 2,409 1,762 18,876 15,811
---------------------------------------
TOTAL PROVED PLUS PROBABLE 7,226 5,331 63,442 53,293
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(*) 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 equivalent (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.
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NET PRESENT VALUES OF FUTURE NET REVENUE
FORECAST PRICES AND COSTS
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BEFORE INCOME TAXES, DISCOUNTED AT (percent/year)
RESERVES CATEGORY 0 % 5 % 10 % 15 %
(million $)(million $)(million $)(million $)
PROVED
Developed Producing 1,149 925 786 690
Developed Non-Producing 22 18 16 15
Undeveloped 34 24 16 10
--------------------------------------------
TOTAL PROVED 1,204 967 818 715
PROBABLE 540 344 245 186
--------------------------------------------
TOTAL PROVED PLUS PROBABLE 1,744 1,311 1,063 901
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The net present values shown include ARTC (Alberta Royalty Tax
Credit), and are reported before income taxes. It should not be assumed
that the estimated future net revenue is representative of the fair
market value of the properties of the Trust. There is no assurance that
such price and cost assumptions will be attained and variances could be
material.
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SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2005
FORECAST PRICES AND COSTS
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OIL
Edmonton Cromer NATURAL
Par Medium NATURAL GAS
WTI Price 40 29.3 GAS LIQUIDS INFLATION
Cushing degrees degrees AECO Spot EDMONTON RATES EXCHANGE
Oklahoma API API Price MIX Percent RATE
Year ($US/bbl)($Cdn/bbl)($Cdn/bbl)($Cdn/MMBtu)($Cdn/bbl) /Year ($US/Cdn)
2006 57.50 66.60 58.50 10.60 51.40 2.5 0.850
2007 55.40 64.20 56.30 9.54 48.90 2.5 0.850
2008 52.50 60.70 53.30 8.49 45.80 2.5 0.850
2009 49.50 57.20 50.20 7.38 42.60 2.5 0.850
2010 46.90 54.10 47.50 6.91 40.20 2.5 0.850
2011 48.10 55.50 48.70 7.12 41.30 2.5 0.850
There- +2.5% +2.5% +2.5% +2.5% +2.5%
after /year /year /year /year /year 2.5 0.850
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RECONCILIATION OF
COMPANY GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
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ASSOCIATED AND
LIGHT AND MEDIUM OIL NON-ASSOCIATED GAS
-------------------------------------------------------------------------
Proved Proved
Plus Plus
Proved Probable Proved Probable
FACTORS (Mbbl) (Mbbl) (MMcf) (MMcf)
December 31, 2004 17,129 24,877 52,682 68,703
Improved Recovery 557 1,746 4,139 9,143
Technical Revisions 2,142 1,126 (1,972) (5,394)
Acquisitions 3,432 4,137 81,773 111,243
Dispositions 0 0 (123) (151)
Production (3,431) (3,431) (16,977) (16,977)
December 31, 2005 19,829 28,455 119,522 166,567
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NATURAL GAS LIQUIDS TOTAL BOE
-------------------------------------------------------------------------
Proved Proved
Plus Plus
Proved Probable Proved Probable
FACTORS (Mbbl) (Mbbl) (Mboe) (Mboe)
December 31, 2004 892 1,237 26,801 37,565
Improved Recovery 16 43 1,263 3,313
Technical Revisions (276) 192 1,537 419
Acquisitions 4,878 6,450 21,939 29,128
Dispositions (12) (15) (33) (40)
Production (681) (681) (6,942) (6,942)
December 31, 2005 4,817 7,226 44,566 63,442
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Finding, Development and Acquisition Costs
The following values have been used in the determination of the Trust's
Finding, Development and Acquisition costs:
Capital
-------
$ Million
---------
2005 Capital Expenditures on
Acquired Properties 20.5
2005 Capital Expenditures on
Remaining Assets 54.2
Total 2005 Capital Expenditures 74.7(*)
(*) Includes $57.1 million for drilling, completion and production
equipment, $8.5 million for investment in plants and facilities, and
$9.1 million for land, seismic and capitalized general and
administrative costs.
$ Million
---------
2005 Acquisition Costs 384.5
2005 Disposition Proceeds 1.6
Net Acquisition and Disposition Costs 382.9
Proved P+P
$ Million $ Million
--------- ---------
Change in future development costs,
excluding Acquisitions 1.0 21.8
Change in future development costs,
including Acquisitions 32.6 64.1
Reserves Additions
-----------------
Proved P+P
Mboe Mboe
------ ----
Total Improved Recovery plus Technical
Revisions, excluding Acquisitions 3,391 3,511
Total Improved Recovery plus Technical
Revisions, including Acquisitions 2,800 3,732
(as provided in the reconciliation table above)
Net Acquisition and Disposition Reserves 21,906 29,088
1) Finding and Development (F&D) Costs, excluding effects of Acquisitions
and Dispositions:
Proved P+P
F&D F&D
$/boe $/boe
------ -----
(i) Before changes in future development
costs: 15.98 15.44
(ii) Including changes in future development
costs: 16.28 21.65
The values shown above are calculated using the following numbers:
(i) Capital = $54.2 million
Proved Reserves = 3,391 Mboe
P+P Reserves = 3,511 Mboe
(ii) Proved Capital = 54.2 + 1.0 = $55.2 million
Proved Reserves = 3,391 Mboe
P+P Capital = 54.2 + 21.8 = $76.0 million
P+P Reserves = 3,511 Mboe
2) Finding, Development and Acquisition (FD&A) Costs, including effects
of Acquisitions and Dispositions:
Proved P+P
FD&A FD&A
$/boe $/boe
------ -----
(i) Before changes in future development
costs: 18.52 13.94
(ii) Including changes in future development
costs: 19.84 15.90
The values shown above are calculated using the following numbers:
(i) Capital = 74.7 + 382.9 = $457.6 million
Proved Reserves = 2,800 + 21,906 =
24,706 Mboe
P+P Reserves = 3,732 + 29,088 = 32,820 Mboe
(ii) Proved Capital = 457.6 + 32.6 =
$490.2 million
Proved Reserves = 2,800 + 21,906 =
24,706 Mboe
P+P Capital = 457.6 + 64.1 = $521.7 million
P+P Reserves = 3,732 + 29,088 = 32,820 Mboe
It should be noted that the aggregate of the development costs
incurred in the most recent financial year and the change during that
year in estimated future development costs generally will not reflect
total finding and development costs related to reserve additions for
that year. NAL will provide greater detail regarding the calculation of
its 2005 FD&A costs and the three-year average, in its 2005 Annual
Information Form.
Reserve Life Index
Reserve Life Index ("RLI") is calculated by dividing reserves at
December 31, 2005 by expected annual production for 2006. In actual
fact, because of the nature of the natural decline in oil and gas
production, NAL anticipates that its production would last much longer
than indicated. RLI is useful in making comparisons between companies
but does not accurately represent the anticipated life of the Trust's
reserves.
NAL has issued a production guidance range of 19,200 - 19,800 boe
per day for 2006. Using the mid-point of that range - or 19,500 boe per
day - NAL's RLI at December 31, 2005 was 8.9 years for P+P reserves, up
from 8.0 years at year-end 2004.
Land and Seismic
At December 31, 2005 NAL owned an average 32.3 percent working
interest in 621,785 gross acres (200,820 net acres) of undeveloped land.
Included in these figures is a large block of non-operated lands in
Lake Erie, Ontario in which the Trust has an average 20.1 percent
working interest. Most of NAL's land is owned in partnership with
Manulife Financial, so in total NAL operates over 80 percent of its
production. Based on an internal estimate, NAL's undeveloped land and
seismic value is approximately $42.2 million.
Net Asset Value
Based on a 10% discount rate and McDaniel's forward prices and costs
estimates, NAL's net asset value was $910 million or $12.30 per unit at
December 31, 2005 compared to $424 million or $8.00 per unit at
December 31, 2004. Based on the constant price case, using year-end oil
and gas prices, NAL's net asset value was $1.1 billion or $15.39 per
unit compared to $422 million or $7.95 per unit a year earlier.
Net Asset Value at December 31, 2005 - Forecast Prices and Costs
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DISCOUNT RATE PER YEAR
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($000's, except per unit data) 5% 10% 15%
Proved plus probable reserves 1,310,694 1,062,520 901,397
Undeveloped land and seismic(*) 42,200 42,200 42,200
Working capital 22,168 22,168 22,168
Reclamation reserve 3,898 3,898 3,898
Long-term debt (220,519) (220,519) (220,519)
---------------------------------
Net asset value 1,158,441 910,267 749,144
Units outstanding (000) 73,977 73,977 73,977
NAV per unit $15.66 $12.30 $10.13
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(*) Internal estimate
Net Asset Value at December 31, 2004 - Forecast Prices and Costs
-------------------------------------------------------------------------
DISCOUNT RATE PER YEAR
-------------------------------------------------------------------------
($000's, except per unit data) 5% 10% 15%
Proved plus probable reserves 605,969 493,983 419,848
Undeveloped land and seismic(*) 23,900 23,900 23,900
Working capital (26,589) (26,589) (26,589)
Reclamation reserve 3,434 3,434 3,434
Long-term debt (70,275) (70,275) (70,275)
---------------------------------
Net asset value 536,439 424,453 350,318
Units outstanding (000) 53,064 53,064 53,064
NAV per unit $10.11 $8.00 $6.60
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(*) Internal estimate
Constant dollar values are calculated based on December 31, 2005
prices of US$61.04 per barrel for WTI crude oil, an Edmonton par price
of C$68.46 per barrel for Canadian crude oil, and an AECO Spot Price of
C$9.80 per million British Thermal Units for Canadian natural gas. The
comparable values for December 21, 2004 were US$43.45 per barrel for WTI
crude oil, C$46.51 per barrel for Canadian crude oil, and C$6.62 per
million British Thermal Units for Canadian natural gas.
Net Asset Value at December 31, 2005 - Constant Prices and Costs
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DISCOUNT RATE PER YEAR
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($000's, except per unit data) 5% 10% 15%
Proved plus probable reserves 1,626,755 1,290,508 1,073,270
Undeveloped land and seismic(*) 42,200 42,200 42,200
Working capital 22,168 22,168 22,168
Reclamation reserve 3,898 3,898 3,898
Long-term debt (220,519) (220,519) (220,519)
Net asset value 1,474,502 1,138,255 921,017
Units outstanding (000) 73,977 73,977 73,977
NAV per unit $19.93 $15.39 $12.45
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(*) Internal estimate
Net Asset Value at December 31, 2004 - Constant Prices and Costs
-------------------------------------------------------------------------
DISCOUNT RATE PER YEAR
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($000's, except per unit data) 5% 10% 15%
Proved plus probable reserves 614,114 491,560 411,969
Undeveloped land and seismic(*) 23,900 23,900 23,900
Working capital (26,589) (26,589) (26,589)
Reclamation reserve 3,434 3,434 3,434
Long-term debt (70,275) (70,275) (70,275)
Net asset value 544,584 422,030 342,439
Units outstanding (000) 53,064 53,064 53,064
NAV per unit $10.26 $7.95 $6.45
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(*) Internal estimate
Financial and Operating Highlights
(thousands of dollars, except per unit and boe data)
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Quarter Quarter 12 months 12 months
ended ended ended ended
December 31, December 31, December 31, December 31,
FINANCIAL 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross revenue,
net of royalties $94,856 $43,110 $311,103 $166,313
Net income 30,777 11,754 98,538 44,867
Funds from operations 65,837 28,846 221,649 114,184
Distributions declared 41,956 25,446 142,050 96,393
Funds from operations
per unit 0.90 0.54 3.17 2.20
Distributions
declared per unit 0.57 0.48 2.01 1.85
Payout ratio 64% 88% 64% 84%
Average number of
units outstanding 73,435,633 52,988,079 69,946,030 51,982,731
Total assets $813,954 $415,645 $813,954 $415,645
Long-term debt,
net of working
capital 198,351 98,864 198,351 96,864
Unitholders' equity 494,490 261,037 494,490 261,037
Costs per boe $9.41 $7.49 $8.02 $6.49
(6:1): Operating
General and
administrative 1.95 1.94 1.54 1.60
Management fees 2.27 0.86 1.43 1.44
OPERATING
Daily production
Oil (bbl) 9,755 8,273 9,399 8,231
Natural gas (Mcf) 52,340 25,145 46,512 25,707
Natural gas
liquids (bbl) 2,036 495 1,867 623
Oil equivalent
(boe - 6:1) 20,514 12,958 19,018 13,139
Average pricing,
net of
transportation
charges and hedging
Liquids:
WTI (US$/bbl) 60.02 48.27 56.56 41.40
NAL average
oil (Cdn$/bbl) 59.53 50.47 60.15 46.76
Natural gas
liquids
(Cdn$/bbl) 56.29 47.67 49.51 39.18
Natural gas:
AECO (Cdn$/Mcf) 11.43 7.07 8.77 6.79
Natural gas
Western Canada
(Cdn$/Mcf) 11.20 6.57 8.75 6.50
Natural gas Lake
Erie (Cdn$/Mcf) 14.36 7.82 11.06 8.10
NAL average
natural gas
(Cdn$/Mcf) 11.47 6.82 8.96 6.79
Oil equivalent
(Cdn$/boe- 6:1) 63.16 47.46 56.50 44.58
Average foreign
exchange rate
Cdn$/US$ 1.1732 1.2210 1.2114 1.3091
Operating netback
before hedging
losses ($/boe) 42.21 27.92 37.49 28.56
Hedging losses per boe (2.37) - (1.56) (1.00)
Operating netback
($/boe) 39.84 27.92 35.93 27.56
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Management's Discussion and Analysis
Please read Management's Discussion and Analysis (MD&A) in
conjunction with the unaudited interim consolidated financial statements
for the three months ended December 31, 2005 and the audited
consolidated financial statements for the years ended December 31, 2005
and December 31, 2004.
Operating netbacks, capital efficiency and funds from operations are
not recognized measures under Canadian generally accepted accounting
principles (GAAP). Management believes that in addition to net income,
operating netbacks, funds from operations, and funds from operations per
unit are useful supplemental measures as they provide an indication of
the results generated by the Trust's principal business activities prior
to the consideration of how those activities are financed or how the
results are taxed. Investors should be cautioned, however, 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 companies' and accordingly, they may not be comparable to measures
used by other companies. NAL calculates funds from operations as "funds
from operations" prior to the change in non-cash working capital
related to operating activities, with the per unit amount calculated
using the weighted average units outstanding for the period.
Acquisition of Addison Energy Inc.
Effective February 10, 2005 the Trust acquired all of the issued and
outstanding shares of Addison Energy Inc. ("Addison") for consideration
of $388.7 million. The allocation of the purchase price and
consideration paid was as follows:
Addison Energy Acquisition
-------------------------------------------
Net assets acquired ($000):
-------------------------------------------
Cash $1,527
Working capital 2,729
Asset retirement obligations (22,974)
Property, plant and equipment 407,460
---------
Total net assets acquired $388,742
Consideration
-------------------------------------------
Cash $386,461
Related fees and expenses 2,281
---------
Cost of acquisition $388,742
-------------------------------------------
The fair value of the property, plant and equipment and asset
retirement obligations reflects the Trust's 70 percent remaining
interest in the Addison properties following the disposal of a 30
percent interest to Manulife Financial Corporation ("MFC"). The Trust
received $165 million in cash from MFC, representing its 30 percent
share of the cost of Addison's properties, which has been offset against
the cost of the acquisition in the above purchase equation.
The 2005 operating results of the Trust include the operations of Addison from February 10, 2005.
Distributions to Unitholders
NAL declared cash distributions of $42 million ($0.57 per unit) in
the fourth quarter of 2005 as compared to $25 million ($0.48 per unit)
for the comparable period in 2004. Funds from operations for the three
months ended December 31, 2005 were $66 million ($0.90 per unit),
representing a payout ratio of 64 percent. The payout ratio of 64
percent represents a decrease of 27 percent from the 88 percent payout
ratio in the fourth quarter of 2004.
For the year ended December 31, 2005, NAL declared cash
distributions of $142 million ($2.01 per unit) as compared to $96
million ($1.85 per unit) for 2004. Funds from operations were $222
million ($3.17 per unit) representing a 64 percent payout ratio for
2005, a decrease of 24 percent from the 84 percent payout ratio in 2004.
The year over year increase in funds from operations is a result of a
45 percent increase in production, primarily due to the Addison
acquisition, and a 27 percent increase in commodity prices.
For the year ended December 31, 2005, distributions are 100 percent taxable.
The Trust increased monthly distributions to $0.19 per unit
effective with the distribution declared in October 2005, up from the
previous rate of $0.16 per unit.
The weighted average number of units outstanding during 2005
increased by 35 percent to 69.9 million from 52.0 million in 2004 as a
result of the public issue of 17 million units in January 2005 to fund a
portion of the Addison acquisition and strong unitholder participation
in the Trust's Distribution Reinvestment Plans.
Unitholders' Distributions
Distributions
-------------------------------------------------------------------------
Quarter Quarter 12 months 12 months
($000 except per ended ended ended ended
unit amounts) December 31, December 31, December 31, December 31,
(unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Funds from
operations $65,837 $28,846 $221,649 $114,184
Distributions
declared $41,956 $25,446 $142,050 $96,393
Funds from
operations per
unit(1) $0.90 $0.54 $3.17 $2.20
Distributions
declared per unit $0.57 $0.48 $2.01 $1.85
Weighted average
units outstanding 73,435,633 52,988,079 69,946,030 51,982,731
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding
Operating Highlights
Production
Average production increased by 58 percent to 20,514 boe/d in the
fourth quarter of 2005 from 12,958 boe/d in the fourth quarter of 2004.
This increase is comprised of a 108 percent increase in natural gas
production to 52,340 Mcf/d in the fourth quarter of 2005 from 25,145
Mcf/d in 2004, along with a 34 percent increase in oil and natural gas
liquids production to 11,791 bbl/d in the fourth quarter of 2005 up from
8,768 bbl/d in 2004.
Similar trends were noted for the year ended December 31, 2005 as
average production increased by 45 percent to 19,018 boe/d from 13,139
boe/d during 2004. The increase is largely attributable to an 81 percent
increase in natural gas production year over year to 46,512 Mcf/d in
2005 compared to 25,707 Mcf/d in 2004, along with a 27 percent increase
in oil and natural gas liquids production to 11,266 boe/d in 2005 from
8,854 boe/d in 2004.
The overall increase in production for the fourth quarter and the
year ended December 31, 2005 is attributable to the gas weighted Addison
acquisition completed in February 2005 and strong operating performance
and drilling results from all core areas.
As a result of the active and successful development program,
production in the fourth quarter of 2005 increased by 804 boe/d over the
third quarter of 2005. The Trust exited 2005 producing an average of
20,641 boe/d for the month of December 2005. This exit rate includes
approximately 3,200 boe/d of production added from the 2005 development
program.
Daily Production Volumes
-------------------------------------------------------------------------
3 months ended December 31 12 months ended December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Oil (bbl/d) 9,755 8,273 18 9,399 8,231 14
Natural gas (Mcf/d) 52,340 25,145 108 46,512 25,707 81
NGL's (bbl/d) 2,036 495 311 1,867 623 200
Oil equivalent
(boe/d) 20,514 12,958 58 19,018 13,139 45
-------------------------------------------------------------------------
As a result of the gas focused Addison acquisition, the Trust's
production weighting became more balanced. In the fourth quarter 2005,
oil and natural gas liquids production amounted to 57 percent of total
production with natural gas representing 43 percent. For the full year
2005, oil and natural gas liquids production amounted to 59 percent of
total production with natural gas representing 41 percent.
Production Weighting
-------------------------------------------------------------------------
3 months ended December 31 12 months ended December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Oil 48% 64% (25) 49% 63% (22)
Natural gas 43% 32% 34 41% 33% 24
NGLs 9% 4% 125 10% 4% 150
-------------------------------------------------------------------------
Development Activities
The Trust participated in the drilling of 57 (21.4 net) wells during
the fourth quarter with a success rate of 100 percent. The majority of
this activity occurred in our Southeast Saskatchewan and Gas Focus core
areas.
During the year, the Trust drilled 113 (74.2 net) operated wells
with an overall success rate of 99 percent. Of these wells, 39 (19.5
net) oil wells were drilled - primarily in our Southeast Saskatchewan
core area targeting the Alida, Frobisher and Midale formations - and 71
(53.3 net) gas wells were drilled in our Central Alberta and Gas Focus
core areas. The majority of the gas wells targeted shallow gas in the
Second White Specks, Edmonton Sands and Viking formations or coal bed
methane ("CBM") from the dry Horseshoe Canyon coals.
The Trust invested a record $74.7 million on capital developments
during 2005. This development increased average production in December
by approximately 3,200 boe/d and translates into a capital efficiency of
$23,500/boe/d.
Fourth Quarter Drilling Activity
-------------------------------------------------------------------------
Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
-------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
Operated
wells 16 8.33 13 8.04 2 1.00 0 0.00 31 17.37
Non-operated
wells 6 0.52 19 3.54 1 0.01 0 0.00 26 4.07
Total wells
drilled 22 8.85 32 11.58 3 1.01 0 0.00 57 21.44
-------------------------------------------------------------------------
2005 Drilling Activity
-------------------------------------------------------------------------
Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
-------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
Operated
wells 39 19.45 71 53.31 2 1.00 1 0.45 113 74.21
Non-operated
wells 23 1.64 55 11.45 7 0.26 3 0.60 88 13.95
Total wells
drilled 62 21.09 126 64.76 9 1.26 4 1.05 201 88.16
-------------------------------------------------------------------------
Southeast Saskatchewan Core Area
Active development of the Trust's oil assets in southeastern
Saskatchewan continued during the quarter by investing approximately $8
million to drill and tie-in a total of 19 (7.1 net) oil wells and three
(1.0 net) water injection wells.
A total of 63 (19.4 net) wells were drilled in southeast
Saskatchewan during 2005, with a success rate of 98 percent. These wells
added approximately 1,600 boe/d of net production during December.
Drilling activity during 2005 was higher than the previous year when 41
(14.9 net) wells were drilled. Drilling activity in 2006 is anticipated
to be consistent with 2005 levels.
During the fourth quarter, two (1.0 net) injection wells were
drilled at Elswick to expand the existing Midale waterflood in order to
improve recovery. Two (1.0 net) Midale horizontal oil wells were drilled
and brought on production at a net rate of 125 boe/d. At Star Valley,
successful development of the Alida formation continued with the
drilling of four (2.0 net) wells. Three (1.5 net) of these wells were
brought on production late in the quarter producing at a combined net
rate of 200 boe/d. At Weyburn, three (1.5 net) horizontal wells were
drilled targeting the Midale formation and one (0.5 net) vertical well
was drilled targeting Red River oil. All four Weyburn wells were brought
on production just prior to year-end. At Nottingham, three (0.66 net)
horizontal wells were drilled into the Alida formation and brought on
production early in the quarter producing at a combined net rate of 185
boe/d. At Wilmar, one (1.0 net) horizontal oil well was drilled into the
Frobisher formation and is producing at a rate of 150 boe/d.
Gas Focus Core Area
NAL's Gas Focus area is comprised of a majority of the Trust's
properties that exist outside NAL's two geographic core areas -
Southeast Saskatchewan and Central Alberta - and includes Garrington,
Pine Creek, Nevis/Lacombe, Brent/Hanna, Surmount/Hangingstone and Lake
Erie. Although geographically diverse, these properties are
strategically characterized by a concentrated land position, a high
proportion of natural gas production as a portion of the properties
product mix, as well as a gas bias in the future development potential.
Development continued during the quarter with the drilling of 16
(6.7 net) shallow gas wells, nine (3.9 net) CBM wells and the tie-in of
30 wells drilled during the previous quarter.
During 2005, a total of 110 (63.2 net) wells were drilled with a
success rate of 99 percent. These wells added approximately 1,200 boe/d
of net production to the Trust during December.
Coalbed Methane ("CBM")
At Clive and Lacombe, a five (3.2 net) well Horseshoe Canyon CBM
pilot program was initiated. Encouraging test results have helped
establish plans to drill an additional 33 (23.5 net) wells during 2006
with similar activity levels anticipated during 2007.
Also at Lacombe, the Trust farmed out over 20 sections of Mannville
CBM rights to a major CBM operator. As per the terms of the farmout, the
Trust retains the right to participate in the ongoing development of
these lands.
At Nevis, new processing and compression facilities were
commissioned during the quarter and 18 (9.4 net) CBM wells were tied-in.
Five (2.8 net) of these wells were also dually completed in the Belly
River formation. During December, net production from the coals and
Belly River totaled 1,700 Mcf/d and 1,000 Mcf/d, respectively.
Shallow Gas
At Brent/Hanna, three (2.5 net) operated wells and three (0.9 net)
non- operated wells were drilled during the quarter for Viking gas and
are awaiting tie-in. Fourteen (13.9 net) long reserve life Second White
Specks wells, drilled as part of a 31 well program during the third
quarter, were brought on production and are producing at a combined rate
of 800 Mcf/d.
Central Alberta Core Area
-------------------------
During the fourth quarter, eight (2.0 net) gas wells were drilled
primarily targeting the Edmonton Sands. Of these wells, three (1.6 net)
wells were brought on production at a combined net rate of 500 Mcf/d.
A total of 20 (4.2 net) were drilled in Central Alberta during 2005
with a 100 percent success rate. These wells added approximately 400
boe/d of net production to the Trust during December.
At Garrington, one (0.7 net) Elkton oil well was drilled and tied in
during the quarter. This well is capable of producing at net rates in
excess of 200 boe/d but will be rate restricted at 90 boe/d until EUB
approval is received (anticipated in June, 2006). The Trust plans to
drill approximately four high impact Elkton oil wells in the area during
2006.
Capital Expenditures
Exploitation and development expenditures in the fourth quarter of
2005 amounted to $27.7 million compared with the corresponding $18.2
million a year ago. For the year ended December 31, 2005 capital
expenditures totaled $74.7 million compared with $49.8 million in 2004.
In addition, effective February 10, 2005 NAL completed the corporate
acquisition of Addison Energy Inc. (resulting in the acquisition of oil
and gas properties in Alberta) for approximately $388.7 million. For
further details of the Addison transaction, see Note 3 to the financial
statements.
Exploitation and Development Expenditures
-------------------------------------------------------------------------
3 Months 12 Months
Ended December 31 Ended December 31
-------------------------------------------------------------------------
($000s) 2005 2004 2005 2004
Drilling, completion and
production equipment 20,718 15,432 57,1003 41,004
Plant and facilities 4,039 2,314 8,474 5,294
Seismic 1,072 211 2,691 871
Other(1) 1,899 226 6,393 2,673
Total capital expenditures 27,728 18,183 74,661 49,842
-------------------------------------------------------------------------
(1) Includes land purchases and capitalized G&A
Commodity Prices
NAL's Realized Prices(1)
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Oil ($/bbl) 62.16 50.47 23 62.33 48.35 29
Natural gas ($/Mcf) 11.91 6.82 75 9.16 6.79 35
NGLs ($/bbl) 56.29 47.67 18 49.51 39.18 26
Total ($/boe) 65.52 47.46 38 58.07 43.58 33
-------------------------------------------------------------------------
(1) The realized prices above are in Canadian dollars net of
transportation charges and prior to gains and losses on commodity
contracts.
Benchmark Pricing
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
WTI crude oil
(US$/bbl) 60.02 48.27 24 56.56 41.40 37
WTI crude oil
(Cdn$/bbl) 70.42 58.94 19 68.52 54.20 26
AECO natural gas
(Cdn$/Mcf) 11.43 7.07 62 8.77 6.79 29
Exchange rate
(US$/Cdn$) 1.1732 1.2210 4 1.2114 1.3091 7
-------------------------------------------------------------------------
Crude Oil and Natural Gas Liquids (NGLs)
----------------------------------------
NAL's average price for crude oil, net of transportation charges, in
the fourth quarter of 2005 was $62.16, up 23 percent from the same
period last year. The increase in crude oil prices was attributable to
the increase in benchmark WTI for the period of 19 percent.
For the full year 2005, NAL's average crude oil price per barrel,
after the effect of transportation costs, was $62.33, 29 percent higher
than the 2004 price of $48.35. This increase was attributable to WTI
price increases.
Year-over-year, the price per barrel of natural gas liquids rose by
18 percent to $56.29/bbl from a fourth quarter 2004 level of $47.67.
Natural gas liquids pricing for the twelve months ended December 31,
2005 was $49.51 per barrel, 26 percent higher than 2004. Pricing for
natural gas liquids generally tracks crude pricing which continues to be
strong, keeping natural gas liquids prices near record levels.
Natural Gas
-----------
For the quarter ended December 31, 2005, the average price for
natural gas was $11.91 per Mcf, up 75 percent from $6.82 per Mcf for the
comparable period in 2004, with the AECO reference price averaging
$11.43/Mcf in 2005 versus $7.07/Mcf for the comparable quarter last
year.
For the year ended December 31, 2005, the Trust received an average
gas price of $9.16/Mcf, an increase of 35 percent from the 2004 price of
$6.79/Mcf. Natural gas from Lake Erie production averaged $11.06/Mcf
compared to $8.10/Mcf in 2004, an increase of 37 percent. Lake Erie
production is premium priced due to its proximity to the Ontario and
Northeastern U.S. markets. With the Addison acquisition, Lake Erie
production accounted for 9 percent of the 2005 natural gas production as
compared to 18 percent in 2004. Overall, natural gas price increases
were attributable to rising benchmark AECO prices.
Risk Management
NAL periodically hedges its production to protect its cash flow from
the volatility of oil and natural gas commodity prices. During 2005,
fixed price hedging contracts for both oil and natural gas were put in
place, all of which expired by year-end. In total, the hedging loss for
the three months ended December 31, 2005 amounted to $4.5 million and,
for the year ended December 31, 2005, $10.9 million. This compares to a
hedging loss of $4.8 million for the year ended December 31, 2004.
During 2005, an average of 3,900 bbl/d of crude oil was hedged for
the period April 1, 2005 to December 31, 2005, which negatively affected
realized crude oil prices by $2.18/bbl as compared to $1.59/bbl in
2004. In addition, 17,928 Mcf/d were hedged for the period April 1, 2005
to October 31, 2005, which negatively affected natural gas realized
prices by $0.20/Mcf. No hedges for natural gas were in place during
2004.
The Trust has entered into certain financial WTI oil contracts as at
December 31, 2005 which are listed below. Settlements are made monthly
based on the average monthly WTI price. In general terms, the contracts
represent costless, three-way options which effectively provide the
Trust with protection up to an average of $8.66 per barrel if the WTI
price falls below the average hedge price of $48.67 per barrel and a
"top-up" payment if the WTI price falls between $48.67 and $57.33 to
bring the Trust's price up to $57.33 per barrel. There are no payments
either way if the average monthly WTI price falls between $57.33 and
$72.75. The Trust is capped at an average price of $72.75 per barrel and
is required to pay the difference if the WTI price is greater than
$72.75 per barrel.
Financial WTI oil contracts in place as at December 31, 2005:
-------------------------------------------------------------------------
Contract
Volume Sold Put Bought Put Sold Call
Term bbls/d $US/bbl $US/bbl $US/bbl
-------------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 52.00 57.00 72.50
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 57.00 72.50
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 58.50 72.50
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 57.50 74.00
Jan. 1 to
Dec. 31, 2006 3 way 600 48.00 57.00 72.50
----------------------------------------------
2006 weighted
average 1,800 48.67 57.33 72.75
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial AECO natural gas contracts in place as at December 31, 2005:
-------------------------------------------------------------------------
Contract
Volume Bought Put Sold Cal
Term GJ's/day $Cdn/GJ $Cdn/GJ
-------------------------------------------------------------------------
Jan. 1 to Dec. 31, 2006 Collar 2,000 9.50 14.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NAL has designated these derivatives as accounting hedges under the
Canadian Institute of Chartered Accountants (the "CICA") accounting guideline
AcG13 and, accordingly, has not recorded the fair value of these instruments
in the consolidated financial statements as at December 31, 2005. As at
December 31, 2005 the unrealized fair value of these hedges was a gain of
$36,000.
Subsequent to December 31, 2005, NAL entered into
additional oil contracts as follows:
-------------------------------------------------------------------------
Contract
Volume Sold Put Bought Put Sold Call
Term bbls/d $US/bbl $US/bbl $US/bbl
-------------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 60.00 72.50
Feb. 1 to
Dec. 31, 2006 3 way 300 48.00 60.00 72.50
Feb. 1 to
Dec. 31, 2006 3 way 300 48.00 60.00 74.00
----------------------------------------------
900 48.00 60.00 73.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Currently, the Trust has completed hedges for up to 30 percent of
estimated 2006 oil production, the maximum presently approved by the
Board of Directors. The Trust has similar limits on its gas hedging
program and will continue to monitor its position regarding further
natural gas hedges.
Revenue and Funds from Operations
Gross revenue from oil, natural gas and natural gas liquids sales
totaled $119 million for the three months ended December 31, 2005, a 111
percent increase over the same period last year. For the year ended
December 31, 2005, revenue increased 83 percent to $392 million from
$214 million in 2004.
Revenue increased in the fourth quarter of 2005 and the year ended
December 31, 2005 due to additional production volumes largely
attributable to the Addison acquisition and higher realized commodity
prices. Compared to the year ended December 31, 2004, production
increased 45% and commodity prices increased by 27%, for the year ended
December 31, 2005.
Funds from operations tracked revenues in 2005, up 128 percent over
last year's fourth quarter and up 94 percent over fiscal 2004.
Revenue
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Revenue(1) ($000's) 119,208 56,579 111 392,244 214,399 83
$/boe 63.16 47.46 33 56.51 44.58 27
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Oil and natural gas and liquid sales less transportation and hedging.
Funds from Operations
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Funds from operations
($000's) 65,837 28,846 128 221,649 114,184 94
$/boe 34.88 24.20 44 31.93 23.75 34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Income
NAL's net income for the fourth quarter of 2005 was $30.8 million or
$0.42 per unit, compared with net income of $11.8 million or $0.22 per
unit for the fourth quarter of 2004. For the year ended December 31,
2005 NAL's net income was $98.5 million or $1.41 per unit, as compared
with net income of $44.9 million or $0.86 per unit for fiscal 2004. The
increase in net income is due to increased production revenues,
partially offset by higher royalties, operating costs, administrative
expenses, interest charges and depletion expense.
Net Income
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Net income ($000's) 30,777 11,754 162 98,538 44,867 120
As % of revenue(1) 25.82 20.77 24 25.12 20.93 20
$/boe 16.31 9.86 65 14.20 9.33 52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Oil and natural gas and liquid sales less transportation and hedging
losses.
Royalty Expenses
Crown, freehold and overriding royalties net of Alberta Royalty Tax
Credit (ARTC) were $26 million and $87 million for the three and twelve
months ended December 31, 2005 respectively. Expressed as a percentage
of gross sales, before hedging and transportation costs, the net royalty
rate was 21.1 percent for the quarter and 21.5 percent for the year
ended 2005, down from 25.2 percent and 22.9 percent, respectively, for
the same periods last year, reflecting lower effective rates on sales
from the Addison properties. Included in 2005 royalty expense is a $3.1
million Saskatchewan Resource Surcharge relating to the period April
2005 to December 2005. Previously, trusts were exempt from paying this
surcharge. This surcharge is approximately $0.45/boe of total production
for the year. Royalties have increased on a boe basis due to the
Saskatchewan surcharge and increased royalty rates due to higher
commodity prices.
Royalty Expenses
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Net royalties
($000s) 26,248 14,363 83 87,188 50,621 72
As % of revenue(1) 21.1 25.2 (16) 21.5 22.9 (6)
$/boe 13.91 12.05 15 12.56 10.53 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Oil and natural gas and liquid sales before transportation and
hedging.
Operating Costs
For the three months ended December 31, 2005 operating costs
averaged $9.41 per boe, a 26 percent increase over the same period in
2004. A similar increase was experienced for the year ended December 31,
2005 with operating costs of $8.02 per boe compared to $6.49 for the
year ended December 31, 2004. The overall increase in operating costs in
fiscal 2005 was due to higher costs associated with the gas weighted
Addison properties acquired in the first quarter of 2005, as well as
inflationary pressures resulting from the increasing demand for
personnel, equipment and services in the highly competitive oil and gas
industry. The fourth quarter of 2005 also included adjustments to
certain costs accrued in prior months of the year.
Operating Costs
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Operating costs
($000s) 17,767 8,935 99 55,682 31,223 78
As % of revenue 14.9 15.7 (5) 14.2 14.5 (2)
$/boe 9.41 7.49 26 8.02 6.49 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Netbacks
In the fourth quarter of 2005, NAL's netback amounted to $42.21 per
boe, before hedging losses, compared with $27.92 for the corresponding
period in 2004, a 51 percent increase. The increase was primarily due to
higher commodity prices, offset slightly by higher royalties and
operating costs.
Similar trends were experienced for the year ended December 31, 2005
when operating netback, before hedging losses, was $37.49 per boe up 31
percent from $28.56 for the year ended December 31, 2004.
Operating Netbacks
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
($/boe) 2005 2004 % Change 2005 2004 % Change
Production Revenue,
net of transportation
costs 65.53 47.46 38 58.07 45.58 27
Royalties, net (13.91) (12.05) 15 (12.56) (10.53) 19
Operating expenses (9.41) (7.49) 26 (8.02) (6.49) 24
Operating netback,
before hedging 42.21 27.92 51 37.49 28.56 31
Hedging losses (2.37) - - (1.56) (1.00) 56
Operating netback,
after hedging 39.84 27.92 43 35.93 27.56 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
General & Administrative (G&A)
G&A expenses were $3.7 million for the three months ended
December 31, 2005, an increase of 59 percent compared to the same period
in 2004. In addition, during the current quarter, $1.1 million of
G&A costs relating to exploitation and development activities were
capitalized as compared to $0.3 million in the corresponding period of
2004.
For the full year 2005, G&A expenses increased by 39 percent to
$10.7 million from $7.7 million in 2004. Capitalized G&A increased
186 percent from $1.8 million to $5.2 million.
The increase in total G&A costs in 2005 was due to higher staff
levels as a result of the Addison acquisition and internal growth as
well as increased compensation rates necessary to continue to attract
and retain qualified personnel in a highly competitive market.
The increase in G&A capitalization rates in 2005 resulted from a
review of overall G&A expenses following the Addison acquisition.
General and Administrative Expenses
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
G & A expenses 3,677 2,314 59 10,710 7,697 39
As % of revenue 3.1 4.1 (24) 2.7 3.6 (25)
$/boe 1.95 1.94 0.5 1.54 1.60 (4)
Per Trust unit ($) 0.05 0.04 25 0.15 0.15 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Management Fees
The Trust is managed by NAL Resources Management Limited (the
"Manager"). The Manager is a wholly owned subsidiary of Manulife
Financial Corporation ("MFC") and manages, on their behalf, NAL
Resources Limited ("NAL Resources"), another wholly-owned subsidiary of
MFC. NAL Resources and the Trust maintain ownership interests in many of
the same oil and natural gas properties, in which NAL Resources is the
joint venture operator. As a result, a significant portion of the net
operating revenues and capital expenditures during the year is based on
joint venture amounts from NAL Resources. These transactions are in the
normal course of joint venture operations and are measured using the
fair value established through the original transactions with third
parties.
Total management fees paid to the Manager for the three months ended
December 31, 2005 were $4.3 million compared to $1 million for the
fourth quarter of 2004. The total management fee is comprised of a base
fee tied to operating cash flows and a performance fee tied to the Trust
market index. For the fourth quarter 2005, base fees were $2.1 million,
an increase of 110 percent over the $1 million base fees for the same
period in 2004, the increase being a reflection of increased production
revenues partially offset by increased operating costs.
In order to pay a performance fee the Trust's overall return
performance must exceed that of its peers based on the S&P/TSX
Capped Energy Trust Index (the "Index"). For the fourth quarter of 2005,
a performance fee of $2.1 million was paid; no performance fee was paid
for the corresponding period of 2004.
Total management fees for the year ended December 31, 2005 were $10
million, including a performance fee of $2.1 million, as compared to
total fees of $6.9 million, including a performance fee of $2.9 million
for fiscal 2004. The base management fees for 2005 were $1.13/boe
compared to $0.83/boe in 2004. During 2005, a $2.1 million performance
fee was paid based on the fourth quarter performance; no amount was
payable for the first three quarters of 2005. In 2004, a $2.9 million
performance fee was paid for the first three quarters.
Management Fees
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Base management
fees ($000s) 2,142 1,020 110 7,816 3,976 97
Performance fees 2,142 - - 2,142 2,956 (28)
Total management
fees 4,284 1,020 320 9,958 6,932 44
As % of revenue 3.6 1.8 100 2.5 3.2 (22)
$/boe 2.27 0.86 164 1.43 1.44 0
Per Trust unit ($) 0.06 0.02 200 0.14 0.13 0
-------------------------------------------------------------------------
On March 1, 2006 the Trust reached an agreement in principle
providing for the restructuring of the management contract with the
Manager. Under the new arrangement, the Trust will pay a one-time $30
million restructuring fee in exchange for the elimination of any further
base and performance management fees payable by the Trust, effective
January 1, 2006. The Trust will pay a monthly interim management fee of
$250,000 per month from January 1, 2006 to March 31, 2006 and $300,000
per month thereafter up to the date of closing, expected on May 31,
2006.
Interest
Interest expense for the quarter ended December 31, 2005 amounted to
$2.6 million, an increase of 165 percent from the same period last
year. Year- over-year interest charges increased by $6.3 million due to
higher bank debt following the February 10, 2005 Addison acquisition.
Interest Expense
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Interest ($000s) 2,651 1,001 165 10,372 4,015 158
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Depletion, Depreciation and Accretion (DDA)
In the fourth quarter of 2005, depletion on property, plant and
equipment and accretion on the asset retirement obligation increased by
88 percent over the comparable period due to the increase in production
and a 19 percent increase in the DDA rate per boe of production. This
higher DDA rate per boe is primarily due to the Addison acquisition,
which carried a higher cost per barrel of reserves as compared to
properties owned by the Trust prior to this acquisition. Similar trends
were noted for the year ended December 31, 2005.
Depletion and Accretion Expenses
-------------------------------------------------------------------------
3 months ended 12 months ended
December 31 December 31
-------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
Depletion and
accretion ($000s) 34,805 18,537 88 123,543 71,762 72
$/boe 18.44 15.55 19 17.80 14.92 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital Resources and Liquidity
The capital structure of the Trust is comprised of Trust units and debt.
As at December 31, 2005, NAL had 73,977,021 units outstanding,
20,912,881 units more than on December 31, 2004. The increase from
December 31, 2004 is attributable to 17 million units issued to fund the
February 2005 acquisition of Addison Energy Inc. and 3.9 million issued
under the DRIP program.
For the quarter ended December 31, 2005, the distribution
reinvestment and premium distribution reinvestment plans resulted in an
additional 1,129,572 units being issued at an average price of $15.73
for total proceeds of $17.8 million. For the year ended December 31,
2005, the plans resulted in an additional 3,912,888 units being issued
at an average price of $14.41 for total proceeds of $56.4 million.
Participation in these programs is currently approximately 43 percent.
The Trust continues to monitor participation in these plans in
conjunction with its capital requirements.
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 plan allows unitholders to exchange such units
for a cash payment from the Plan Broker equal to 102 percent of the
monthly distribution.
As at December 31, 2005 the Trust had debt of $198.4 million (net of
working capital) compared with $96.9 million at December 31, 2004 and
$249.7 million as at March 31, 2005 after the Addison acquisition. At
the end of 2005, the Trust had a net debt to equity ratio of 0.40 and a
net debt to twelve months trailing cash flow ratio of 0.88.
The Trust, through its subsidiary NAL Ventures Trust, maintains a
$300 million fully secured, extendible, revolving credit facility. The
facility consists of a $290 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. It will revolve until April 27, 2006 and is extendible at that
time for a further 364- day revolving period upon agreement between the
Trust and the bank syndicate. 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, the cash flow otherwise available to unitholders would
be used to repay the facility.
Total bank debt amounted to $220.5 million at December 31, 2005
compared with $93.7 million as at December 31, 2004 due to increased
borrowings to fund the Addison Energy Inc. acquisition in February 2005.
Of the debt outstanding at December 31, 2005, $219 million was
outstanding under the production facility and $1.5 million under the
working capital facility.
Capitalization
-------------------------------------------------------------------------
December 31, December 31, December 31,
2005 2004 2003
-------------------------------------------------------------------------
Trust unit equity ($000s) 494,490 261,037 284,626
Long-term debt ($000s) 220,519 93,700 103,500
Net debt(*) ($000s) 198,351 96,864 97,039
Net debt to equity 0.40 0.37 0.34
Net debt to trailing 12 month
cash flow 0.88 0.84 1.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Net debt is long-term debt net of working capital
Contractual Obligations
NAL has entered into several contract obligations as part of
conducting day-to day business. NAL has the following commitments for
the next five years:
Lease Obligations
-------------------------------------------------------------------------
($000) 2006 2007 2008 2009 2010
-------------------------------------------------------------------------
Office Lease(1) 2,843 2,460 - - -
Transportation 1,136 398 299 - -
Processing Agreement(2) 520 491 469 446 428
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager of which NAL is
allocated a pro rata share of the expense on a monthly basis.
Included in office lease is a $1 million commitment related to the
Addison Energy acquisition. The commitment started in February 2005
and extends 30 months. NAL has subsequently sublet the premise.
(2) Represents gas processing agreement under take or pay arrangement
associated with the Addison Energy acquisition.
(3) In the event, NAL's bank credit facility is not extended in April
2006, the bank debt totaling $220.5 million at December 31, 2005 will
be payable in four equal quarterly installments commencing April
2007.
Off-Balance Sheet Arrangements/Variable Interest Entities
NAL has no off-balance sheet arrangements or variable interest entities.
Quarterly Information
Quarterly Financial Results
-------------------------------------------------------------------------
2005
-------------------------------------------------------------------------
Financial Q4 Q3 Q2 Q1
Revenue, net of royalties
and transportation costs 94,856 84,833 70,797 60,617
Per unit 1.29 1.17 0.99 0.97
Funds from operations 65,837 62,442 49,881 43,489
Per unit 0.90 0.86 0.70 0.69
Distributions declared,
per unit 0.57 0.48 0.48 0.48
Net income 30,777 31,710 20,804 15,247
Per unit 0.42 0.44 0.29 0.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2004
-------------------------------------------------------------------------
Financial Q4 Q3 Q2 Q1
Revenue, net of royalties
and transportation costs 43,110 43,989 40,674 38,540
Per unit 0.81 0.84 0.79 0.76
Funds from operations 28,846 30,446 28,481 26,411
Per unit 0.54 0.58 0.55 0.52
Distributions declared,
per unit 0.48 0.47 0.45 0.45
Net income 11,754 13,279 10,871 8,963
Per unit 0.22 0.25 0.21 0.18
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Critical Accounting Estimates
The significant accounting policies used by NAL are disclosed in the
notes to NAL's December 31, 2005 audited consolidated financial
statements. Certain accounting policies require that management make
appropriate decisions when formulating estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and
expenses. The following discusses such accounting policies and is
included in Management's Discussion and Analysis to assist investors in
assessing the critical accounting policies and practices of NAL and the
likelihood of materially different results being reported. NAL's Manager
reviews the estimates regularly. The emergence of new information and
changed circumstances may result in actual results or changes to
estimated amounts that differ materially from current estimates.
The following assessment of significant accounting estimates is not
meant to be exhaustive. NAL might realize different results from the
application of new accounting standards published, from time to time, by
various regulatory bodies.
Proved Oil and Gas Reserves
---------------------------
Under National Instrument 51-101 ("NI 51-101"), "proved" reserves
are those reserves that can be estimated with a high degree of certainty
to be recoverable (it is possible that the actual remaining quantities
recovered will exceed the estimated proved reserves). In accordance with
this definition, the level of certainty targeted by the reporting
company should result in at least a 90 percent probability at a company
aggregate level that the quantities actually recovered will equal or
exceed the estimated reserves. There was no such consideration of
probability under previous reporting rules. In the case of "probable"
reserves, which are less certain to be recovered than proved reserves,
NI 51-101 states that it must be equally likely that the actual
remaining quantities recovered will be greater or less than the sum of
the estimated proved plus probable ("P+P") reserves. As for certainty,
in order to report reserves as P+P, the reporting company must believe
that there is at least 50 percent probability at a company aggregate
level that the quantities actually recovered will equal or exceed the
sum of the estimated P+P reserves. The implementation of NI 51-101 has
resulted in a more rigorous and uniform standardization of reserve
evaluation.
The oil and gas reserve estimates are made using all available
geological and reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions occur as a
result of changes in prices, costs, fiscal regimes, reservoir
performance or a change in NAL's plans. The effect of changes in proved
oil and gas reserves on the financial results and position of NAL is
described under the heading "Full Cost Accounting for Oil and Gas
Activities ("Ceiling Test")".
Depletion Expense
-----------------
NAL uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting,
all costs associated with exploration and development are capitalized
whether or not the activities funded were successful. The aggregate of
net capitalized costs and estimated future development costs is
amortized using the unit of production method based on estimated proved
oil and gas reserves.
An increase in estimated proved oil and gas reserves would result in
a corresponding reduction in depletion expense. A decrease in estimated
future development costs would result in a corresponding reduction in
depletion expense.
Impairment of Property, Plant & Equipment
-----------------------------------------
NAL is required to review the carrying value of all property, plant
and equipment, including the carrying value of oil and gas assets, for
potential impairment. Impairment is indicated if the carrying value of
the long-lived oil and gas asset is not recoverable by the future
undiscounted cash flows. If impairment is indicated, the amount by which
the carrying value exceeds the estimated fair value of the property,
plant and equipment is charged to earnings.
Fair Value of Derivative Instruments
------------------------------------
Periodically NAL utilizes financial derivatives to manage market
risk. The purpose of the hedge is to provide an element of stability to
NAL's cash flow in a volatile environment. NAL discloses the estimated
fair value of open hedging contracts as at the end of a reporting
period.
Asset Retirement Obligation
---------------------------
NAL adopted the CICA Handbook, section 3110 on asset retirement
obligations on January 1, 2004. The application of this standard
requires the recognition and measurement of liabilities associated with
capital assets. The standard recognizes a liability equal to the
discounted fair value of the obligation in the period in which the asset
is recorded with an equal offset to the carrying amount of the asset.
The liability then accretes to its fair value with the passage of time.
This standard requires management to estimate the timing and future
costs to settle liabilities.
Legal, Environmental Remediation and Other Contingent Matters
-------------------------------------------------------------
NAL is required to determine whether a loss is probable based on
judgment and interpretation of laws and regulations and whether the loss
can reasonably be estimated. When the loss is determined, it is charged
to earnings. NAL's management must continually monitor known and
potential contingent matters and make appropriate provisions by charges
to earnings when warranted by circumstance.
Income Tax Accounting
---------------------
The determination of NAL's income and other tax liabilities requires
interpretation of complex laws and regulations often involving multiple
jurisdictions. All tax filings are subject to audit and potential
reassessments after the lapse of considerable time. Accordingly, the
actual income tax liability may differ significantly from that estimated
and recorded by management.
Changes in Accounting Policies
------------------------------
There were no new accounting policies adopted during the twelve months ended December 31, 2005.
Dated March 1, 2006
Consolidated Balance Sheets
(thousands of dollars) (unaudited)
----------------------------
As at As at
December 31, December 31,
2005 2004
Assets
Current assets
Cash $1,124 $1,111
Accounts receivable and other 58,081 19,709
-----------------------------------------------------------
59,205 20,820
Reclamation reserve (Note 4) 3,898 3,434
Future income tax asset (Note 9) 2,136 4,676
Property, plant and equipment,
net (Note 5) 748,715 386,715
-----------------------------------------------------------
$813,954 $415,645
-----------------------------------------------------------
-----------------------------------------------------------
Liabilities
and
Unitholders'
Equity
Current liabilities
Accounts payable and accrued
liabilities $22,981 $15,494
Distributions payable to
Unitholders 14,056 8,490
Current portion of long-term
debt - 23,425
-----------------------------------------------------------
37,037 47,409
Long-term debt (Note 7) 220,519 70,275
Asset retirement obligations
(Note 6) 61,908 36,924
-----------------------------------------------------------
319,464 154,608
Unitholders' equity
Unitholders' capital (Note 8) 753,585 476,620
Accumulated income 273,796 175,258
Accumulated distributions
(Note 8) (532,891) (390,841)
-----------------------------------------------------------
494,490 261,037
-----------------------------------------------------------
$813,954 $415,645
-----------------------------------------------------------
-----------------------------------------------------------
Commitments (Note 12)
-----------------------------------------------------------
Subsequent event (Notes 1 and 11)
-----------------------------------------------------------
-----------------------------------------------------------
Units outstanding 73,977,021 53,064,140
-----------------------------------------------------------
-----------------------------------------------------------
See accompanying notes
Consolidated Statements of Income and Accumulated Income
(thousands of dollars, except per unit amounts) (unaudited)
-------------------------------------------------------
Quarter Quarter 12 months 12 months
ended ended ended ended
December 31, December 31, December 31, December 31,
2005 2004 2005 2004
-------------------------------------------------------------------------
Revenue
Oil, natural gas
and liquids sales $119,995 $56,962 $395,147 $215,988
Transportation costs (787) (383) (2,903) (1,589)
Royalty and other
income 1,896 894 6,047 2,535
Crown royalties,
net of ARTC (20,099) (11,225) (65,167) (39,787)
Freehold and
other royalties (6,149) (3,138) (22,021) (10,834)
-------------------------------------------------------------------------
94,856 43,110 311,103 166,313
-------------------------------------------------------------------------
Expenses
Operating 17,767 8,935 55,682 31,223
General and
administrative 3,677 2,314 10,710 7,697
Management fees
(Note 10) 4,284 1,020 9,958 6,932
Interest on long-
term debt 2,651 1,001 10,372 4,015
Depletion,
depreciation and
amortization 33,608 17,816 118,961 68,941
Accretion on asset
retirement
obligations 1,197 721 4,582 2,821
-------------------------------------------------------------------------
63,184 31,807 210,265 121,629
-------------------------------------------------------------------------
Income before taxes 31,672 11,303 100,838 44,684
Income and capital
taxes (recovery) 340 (207) 240 (564)
Future income tax
recovery (provision) (1,235) 658 (2,540) 747
-------------------------------------------------------------------------
Total income and
capital taxes
(Note 9) (895) 451 (2,300) 183
-------------------------------------------------------------------------
Net Income 30,777 11,754 98,538 44,867
Accumulated income,
beginning of period 243,019 163,504 175,258 130,391
-------------------------------------------------------------------------
Accumulated income,
end of period $273,796 $175,258 $273,796 $175,258
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust
unit $0.42 $0.22 $1.41 $0.86
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average
units outstanding 73,435,633 52,988,079 69,946,030 51,982,731
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Cash Flows
(thousands of dollars) (unaudited)
-------------------------------------------------------
Quarter Quarter 12 months 12 months
ended ended ended ended
December 31, December 31, December 31, December 31,
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating activities
Net income $30,777 $11,754 $98,538 $44,867
Items not involving
cash:
Depletion,
depreciation
and amortization 33,608 17,816 118,961 68,941
Accretion on asset
retirement
obligations 1,197 721 4,582 2,821
Future income
tax provision
(recovery) 1,235 (658) 2,540 (747)
Abandonment and
environmental
expenditures (980) (787) (2,972) (1,698)
-------------------------------------------------------------------------
Funds from operations 65,837 28,846 221,649 114,184
Decrease (increase)
in non-cash working
capital 6,626 5,165 (26,364) 8,562
-------------------------------------------------------------------------
72,463 34,011 195,285 122,746
-------------------------------------------------------------------------
Financing Activities
Distributions
to Unitholders (39,557) (25,421) (136,484) (95,488)
Issue of Trust units,
net of issue costs 17,690 2,015 276,964 27,937
Increase (decrease)
in long-term debt (18,281) 1,500 126,819 (9,800)
Decrease (increase)
in non-cash
working capital (3,133) (3,133)
-------------------------------------------------------------------------
(43,281) (21,906) 264,166 (77,351)
-------------------------------------------------------------------------
Investing Activities
Acquisition of Addison
Energy Inc. (Note 3) - - (387,215) -
Additions to property,
plant and equipment (27,078) (18,337) (74,663) (49,841)
Proceeds from
dispositions 1,564 3,858 1,564 4,637
Reclamation reserve (138) (28) (464) (349)
Decrease in non-cash
working capital (6,282) 3,297 1,340 695
-------------------------------------------------------------------------
(31,934) (11,210) (459,438) (44,858)
-------------------------------------------------------------------------
Increase (decrease)
in cash (2,752) 895 13 537
Cash, beginning
of period 3,876 216 1,111 574
-------------------------------------------------------------------------
Cash, end of period $1,124 $1,111 $1,124 $1,111
-------------------------------------------------------------------------
Supplementary
disclosure of cash
flow information:
Cash paid during
the period for:
Interest $2,621 $978 $10,287 $3,914
Taxes (recovery) (340) $207 (240) $564
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(The financial results for the three months ended December 31, 2005 have not been separately reviewed by the external auditors)
(Tabular amounts in thousands of dollars, except per unit amounts)
1. STRUCTURE OF THE TRUST
The Trust is an open-end investment trust formed under the laws
of the Province of Alberta. Operations commenced on May 9, 1996. The
principal undertakings of the Trust are to indirectly acquire and hold,
through its direct and indirect wholly owned subsidiaries, interests in
oil and natural gas properties and to distribute the net cash proceeds
to its Unitholders.
The Trust is managed by NAL Resources Management Limited (the
"Manager"). The Manager receives a base monthly management fee from the
Trust equal to 3.0% of net production revenue, defined as total revenues
received from the sales of petroleum substances and other income
sources, less operating costs and royalties. The Manager is also
entitled to a performance fee that is calculated quarterly based on the
Trust's total return compared to its peer group. The total return for
the Trust is calculated by dividing the quarter's closing unit price
less the quarter's opening unit price, plus cash distributions for the
quarter, by the quarter's opening unit price. This is compared to the
percentage increase in the S&P/TSX Capped Energy Trust Index. A
performance fee ranging from 0.5% to 3%, of the Trust's quarterly net
operating income, is then paid in cash for the Trust's return in excess
of the peer group. The Manager is also entitled to a recovery for
general and administrative costs incurred on behalf of the Trust. On
March 1, 2006 the Trust reached an agreement in principle providing for
the restructuring of the management contract with the Manager. Under the
new arrangement, the Trust will pay a one-time $30 million
restructuring fee in exchange for the elimination of any further base
and performance management fees payable by the Trust, effective January
1, 2006. The Trust will pay a monthly interim management fee of $250,000
per month from January 1, 2006 to March 31, 2006 and $300,000 per month
thereafter up to the date of closing, expected on May 31, 2006.
2. SUMMARY OF ACCOUNTING POLICIES
Basis of Presentation
The Trust's financial statements have been prepared in accordance
with Generally Accepted Accounting Principles ("GAAP") in Canada and
they include the accounts of the Trust and its subsidiaries, trusts and
partnerships, which are wholly owned. All inter-entity transactions and
balances have been eliminated.
The preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and the disclosure of
contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
period. Actual results could differ from those estimated. In
particular, the amounts recorded for depletion and depreciation of
property, plant and equipment and for asset retirement obligations are
based on estimates of reserves and future costs. The ceiling test
calculation is based on estimates of proved reserves, production rates,
oil and natural gas prices, future costs and other relevant assumptions.
By their nature, these estimates are subject to measurement uncertainty
and may impact the consolidated financial statements of future periods.
Property, Plant and Equipment
The Trust follows the full cost method of accounting for petroleum
and natural gas properties, whereby all costs of acquiring petroleum and
natural gas properties and related development costs are capitalized
and accumulated in one cost centre. Such costs include land acquisition,
geological and geophysical expenditures, costs of drilling both
productive and non-productive wells, related plant and production
equipment costs and related overhead charges.
Proceeds from the sale of oil and natural gas properties are applied
against capitalized costs, with no gain or loss recognized, unless such
sale would alter the depletion rate by 20% or more.
Depletion of oil and natural gas properties and depreciation of
equipment is calculated using the unit of production method based on
total proven reserves before royalties. Natural gas reserves are
converted to barrels of oil equivalent based on relative energy content
(6:1).
Oil and natural gas assets are evaluated in each reporting period to
determine that the carrying amount in a cost centre is recoverable and
does not exceed the fair value of the properties in the cost centre.
The carrying amount of property, plant and equipment is assessed to
be recoverable when the sum of the undiscounted cash flows expected from
the production of proved reserves exceeds the carrying amount.
When the carrying amount is not assessed to be recoverable, an
impairment loss is recognized to the extent that the carrying amount of
the cost centre exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves. The cash flows are
estimated using expected future commodity prices and costs and
discounted using a risk-free rate.
Asset Retirement Obligation
The Trust recognizes the fair value of an asset retirement
obligation in the period in which it is incurred, on a discounted basis,
with a corresponding increase to the carrying amount of property, plant
and equipment. The asset recorded is depleted on a unit of production
basis over the life of the reserves. The liability amount is increased
each reporting period due to the passage of time and the amount of
accretion is charged to income in the period. Revisions to the estimated
timing of cash flows or to the original estimated undiscounted cost
could also result in an increase or decrease to the obligation. Actual
costs incurred upon settlement of the retirement obligation are charged
against the obligation to the extent of the liability recorded.
Income Taxes
The Trust follows the liability method of accounting for income
taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to
differences between the amounts reported in the Trust's subsidiaries
financial statements and their respective tax bases, using substantially
enacted income tax rates. The effect of a change in income tax rates on
future income tax liabilities and assets is recognized in income in the
period that the change occurs. The Trust is a taxable entity under the
Canadian Income Tax Act and is taxable only on income that is not
distributed or distributable to Unitholders. The Trust meets the
criteria qualifying for income tax treatment permitting a tax deduction
for distributions paid to the unit holders in addition to other
deductions available in the Trust. In addition, the Trust is exempt from
future income taxes because it is contractually committed to distribute
all of its income to its
Unitholders. Ventures Trust, a subsidiary of the Trust, is also
exempt from future income taxes because it is contractually committed to
distribute all of its tax-exempt income to the Trust who ultimately
distributes the income to the Unitholders.
Joint Ventures
Substantially all of the development and production activities are
conducted jointly with others and, accordingly, these financial
statements reflect only the Trust's proportionate interest in such
activities.
Financial Instruments
The Trust uses, from time to time, derivative financial instruments
to manage exposure related to changes in oil and natural gas commodity
prices. They are not used for trading or speculative purposes.
The Trust formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective
and strategy for undertaking various hedge transactions.
This process includes linking all derivatives to specific assets and
liabilities on the balance sheet or to specific firm commitments or
anticipated transactions.
The Trust also formally assesses, both at the hedge's inception and
on an ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values
or cash flows of hedged items. For cash flow hedges effectiveness is
achieved if the changes in the cash flows of the derivative
substantially offset the changes in the cash flows of the hedged
position and the timing of the cash flows is similar.
Effectiveness for fair value hedges is achieved if the fair value of
the derivative substantially offsets changes in the fair value
attributable to the hedged item. In the event that a derivative does not
meet the designation or effectiveness criterion, the Trust applies the
fair value method of accounting by recording an asset or liability on
the consolidated balance sheet and recognizing changes in the fair value
of the instruments in the current period income statement.
If a derivative that qualifies as a hedge is settled early, the gain
or loss at settlement is deferred and recognized when the gain or loss
on the hedged transaction is recognized. Premiums paid or received with
respect to derivatives that are hedges are deferred and amortized to
income over the term of the hedge.
Realized gains or losses on changes in oil and natural gas commodity
prices are recognized in income in the same period and in the same
financial statement category as the income or expense arising from
corresponding commodity hedge contract.
Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title passes to purchaser.
3. CORPORATE ACQUISITION
Effective February 10, 2005 the Trust acquired all of the issued and
outstanding shares of Addison Energy Inc. ("Addison") for consideration
of $388.7 million. The allocation of the purchase price and
consideration paid was as follows:
---------------------------------------------------------------------
Net assets acquired:
---------------------------------------------------------------------
Cash $1,527
Working capital 2,729
Asset retirement obligations (22,974)
Property, plant and equipment 407,460
---------------------------------------------------------------------
Total net assets acquired $388,742
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration
---------------------------------------------------------------------
Cash $386,461
Related fees and expenses 2,281
---------------------------------------------------------------------
Cost of acquisition $388,742
---------------------------------------------------------------------
---------------------------------------------------------------------
The fair value of the property, plant and equipment and asset
retirement obligations reflects the Trust's 70 percent remaining
interest in the Addison properties following the disposal of a 30
percent interest to Manulife Financial Corporation ("MFC"). The Trust
received $165 million in cash from MFC, representing its 30 percent
share of the cost of the Addison properties, which has been offset
against the cost of the acquisition in the above purchase equation.
The consolidated financial statements incorporate the operations of Addison effective February 10, 2005.
4. RECLAMATION RESERVE
A reclamation reserve was established to assist in funding future
asset retirement obligations. The Board of Directors has approved
quarterly contributions, the amount of which may be adjusted by the
Trust from time to time.
---------------------------------------------------------------------
Reclamation Reserve 2005 2004
---------------------------------------------------------------------
Balance, beginning of year $3,434 $3,085
Contributions 322 269
Interest earned on fund 142 80
---------------------------------------------------------------------
Balance, end of year $3,898 $3,434
---------------------------------------------------------------------
---------------------------------------------------------------------
5. PROPERTY, PLANT AND EQUIPMENT ("PP&E")
---------------------------------------------------------------------
Net book value as at December 31 2005 2004
---------------------------------------------------------------------
Oil and natural gas properties, at cost $1,204,123 $685,737
Less: Accumulated depletion and
depreciation (455,408) (299,022)
---------------------------------------------------------------------
$748,715 $386,715
---------------------------------------------------------------------
---------------------------------------------------------------------
During 2005, the Trust capitalized $5,187,500 (2004 - $1,813,000) of
general and administrative costs that were directly related to
exploitation and development programs.
No property costs have been excluded from the depletion and depreciation calculation.
The Trust performed a ceiling test calculation at December 31, 2005
in accordance with CICA AcG16 to assess the recoverable value of
property, plant and equipment. The oil and gas future prices are based
on the January 1, 2006 commodity price forecast of our independent
reserve evaluators, adjusted for commodity differentials specific to the
Trust. The following table summarizes the benchmark prices used in the
ceiling test calculation. Based on these assumptions, the undiscounted
value of future net reserves from the
Trust's proved reserves exceeded the carrying value of property, plant and equipment as at December 31, 2005.
WTI Oil US$/Cdn$ WTI Oil AECO Gas
Year (US$/bbl) Exchange Rate (Cdn$/bbl) (Cdn$/GJ)
---------------------------------------------------------------------
2006 57.50 0.850 67.65 10.05
2007 55.40 0.850 65.18 9.05
2008 52.50 0.850 61.76 8.05
2009 49.50 0.850 58.24 7.00
2010 46.90 0.850 55.18 6.55
---------------------------------------------------------------------
Remainder(1) 2.5% 0.850 2.5% 2.5%
(1) Percentage change represents the change in each year after 2010
to the end of the reserve life.
6. 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 $60.3 million as at December 31, 2005 based
on a total undiscounted amount of cash flows required to settle its
asset retirement obligations of $221.8 million (2004 - $98.6 million).
These costs are expected to be made over the next 47 years with the
majority of the costs incurred between 2006 and 2033. NAL's
credit-adjusted risk-free rate of 8 percent (2004 - 8 percent) and an
inflation rate of 1.5 percent (2004 - 1.5 percent) were used to
calculate the present value of the asset retirement obligations.
The following table reconciles the Trust's asset retirement obligations.
---------------------------------------------------------------------
December 31, December 31,
2005 2004
---------------------------------------------------------------------
Balance, beginning of period $36,924 $34,914
Accretion expense 4,582 2,821
Liabilities incurred 23,374 887
Liabilities settled (2,972) (1,698)
---------------------------------------------------------------------
Balance, end of period $61,908 $36,924
---------------------------------------------------------------------
---------------------------------------------------------------------
7. LONG-TERM DEBT
---------------------------------------------------------------------
2005 2004
---------------------------------------------------------------------
Production loan facility $219,000 $93,700
Working capital facility 1,519 -
---------------------------------------------------------------------
Total debt outstanding 220,519 93,700
Current portion of debt - 23,425
---------------------------------------------------------------------
Long-term debt $220,519 $70,275
---------------------------------------------------------------------
---------------------------------------------------------------------
The Trust, through its subsidiary NAL Ventures Trust, maintains a
$300 million fully secured, extendible, revolving term credit facility
with a syndicate of Canadian chartered banks. This facility consists of a
$290 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 present and after acquired properties and assets of the
Trust and its subsidiary and affiliated entities. It will revolve until
April 27, 2006 and is extendible at that time 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 2006, 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 April 2007 with a final residual payment, if any, in April
2008. The term loan, if called, will be payable $164,250,000 in 2007 and
$56,269,000 in 2008.
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 US dollars by way of US base 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
US 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.
On December 31, 2005 the effective interest rate on amounts outstanding under the credit facility was 4.52 percent.
8. UNITHOLDERS' EQUITY
Unitholders' Equity
The Trust is authorized to issue 500 million Trust units of which 74
million units were issued and outstanding as at December 31, 2005
(December 31, 2004 - 53 million). Each unit is transferable, carries the
right to one vote and represents an equal undivided beneficial interest
in any distributions from the Trust and in the assets of the Trust in
the event of termination or winding up of the Trust. All trust units are
of the same class with equal rights and privileges.
Redemption
Unitholders may redeem their trust units for cash at any time, up to
a maximum value of $100,000 in any calendar month, by delivering their
unit certificates to the Trustee, accompanied by a properly completed
notice requesting redemption. The redemption amount per trust unit will
be the lesser of 95 percent of the market price of the units on the
principal market on which the units are quoted as trading during the
ten-trading day period commencing immediately after the date on which
the units are surrendered for redemption, and the closing market price
of the trust units or the principal market on which the units are quoted
for trading on the date that the trust units are tendered for
redemption.
Units Issued:
---------------------------------------------------------------------
2005 2004
--------------------------------------
Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning of
the year 53,064 $476,620 50,565 $448,683
Issued for cash 17,000 232,900 - -
Less: Issue expenses - (12,333) - -
Issued from Distribution
Reinvestment Plan 3,913 56,398 2,499 27,937
---------------------------------------------------------------------
Balance, end of the year 73,977 $753,585 53,064 $476,620
---------------------------------------------------------------------
---------------------------------------------------------------------
Distribution Reinvestment Plan
The Trust has in place a Distribution Reinvestment Plan ("DRIP") and
a Premium Distribution Reinvestment Plan ("Premium DRIP"). The
regular DRIP entitles Unitholders to reinvest cash distributions in
additional units of the Trust at 95% of the average market price with
no additional fees or commissions. The average market price is the
arithmetic average of the daily volume weighted average trading price
of the Trust units during a defined period before the distribution
payment date.
The Premium Distribution component of the Plan allows Unitholders to
exchange new Trust units, acquired by reinvesting their cash
distributions, for a cash payment from the Plan Broker equal to 102%
of the monthly distribution on the applicable distribution payment
date.
The Trust units issued under the Premium Distribution component of
the Plan at a 5% discount to the average market price will be
delivered to the Plan Broker in exchange for 102% of the cash
distribution payable on the participant's existing Trust units. At
certain times and at the discretion of management, these premium
distributions may be suspended.
Distributions
The Trust makes monthly distributions of its distributable cash to
unitholders on the fifteenth day, or if such day is not a business
day, the next business day. Cash distributions are calculated in
accordance with the Trust's Indenture. Distributions since the
inception of the Trust are as follows:
Other Return of
Income Capital Total
---------------------------------------------------------------------
Accumulated distributions
at December 31, 2003 $134,925 $159,523 $294,448
2004 distributions 60,318 36,075 96,393
---------------------------------------------------------------------
Accumulated distributions
at December 31, 2004 $195,243 $195,598 $390,841
2005 distributions 142,050 - 142,050
---------------------------------------------------------------------
Accumulated distributions
at December 31, 2005 $337,293 $195,598 $532,891
---------------------------------------------------------------------
---------------------------------------------------------------------
9. INCOME TAXES
The provision for income taxes in the financial statements differs
from the result that would have been obtained by applying the
combined federal and provincial tax rate to income before income
taxes as follows:
2005 2004
---------------------------------------------------------------------
Income before taxes $100,838 $44,684
Statutory income tax rate 39.0% 39.3%
---------------------------------------------------------------------
Expected income tax expense (recovery) 39,327 17,561
Increase (decrease) resulting from:
Non-deductible Crown charges 16,657 12,006
Resource allowance (17,260) (10,481)
Alberta Royalty Tax Credit (127) (149)
Valuation allowance 459 753
Net income of the Trust and other (37,019) (20,318)
Other 503 (119)
---------------------------------------------------------------------
Future income tax expense (recovery) 2,540 (747)
Capital taxes (240) 564
---------------------------------------------------------------------
Income and capital taxes 2,300 $(183)
---------------------------------------------------------------------
---------------------------------------------------------------------
The future income tax asset is comprised of:
2005 2004
---------------------------------------------------------------------
Property, plant and equipment $1,536 $282
Future tax liability resulting from
different year ends 532 431
Non-capital tax loss carry forward (2,440) (3,204)
Provision for site restoration (7,452) (8,728)
---------------------------------------------------------------------
(7,824) (11,219)
Valuation allowance 5,688 6,543
---------------------------------------------------------------------
---------------------------------------------------------------------
Future income tax asset ($2,136) ($4,676)
---------------------------------------------------------------------
---------------------------------------------------------------------
As at December 31, 2005, the Trust's subsidiaries have non-capital
losses totaling $6,700,000 available to reduce future taxable income,
expiring from time to time between 2009 and 2015.
The following tax pools are available to the Trust for future use as
deductions from taxable income:
---------------------------------------------------------------------
2005 2004
---------------------------------------------------------------------
Intangible resource pools $198,873 $240,301
Undepreciated capital cost 61,249 29,880
Unit issue costs 12,943 5,343
---------------------------------------------------------------------
Total tax pools $273,065 $275,524
---------------------------------------------------------------------
---------------------------------------------------------------------
The Trust meets the criteria qualifying it for income tax treatment
permitting a tax deduction for distributions paid to the unit holders
in addition to other deductions available in the Trust. At
December 31, 2005, the book amounts of the Trust's assets and
liabilities exceed the tax basis by $319.3 million.
10. RELATED PARTY TRANSACTIONS
NAL Resources Management Limited provides certain services pursuant
to a management agreement for which the Trust was charged $7,816,000
(2004 - $3,976,000) for management fees and $2,142,000 (2004 -
$2,956,000) for performance fees. In addition, the Trust was charged
$8,370,000 (2004 - $5,864,000) for reimbursement of general and
administrative expenses incurred by the Manager pursuant to the
management agreement. These transactions have been recorded at the
exchange amount. Reference is made to Note 3.
The Manager is a wholly owned subsidiary of Manulife Financial
Corporation ("MFC") and manages, on their behalf, NAL Resources
Limited ("NAL Resources"), another wholly-owned subsidiary of MFC.
NAL Resources and the Trust maintain ownership interests in many of
the same oil and natural gas properties, in which NAL Resources is
the joint venture operator. As a result, a significant portion of the
net operating revenues and capital expenditures during the year is
based on joint venture amounts from NAL Resources. These transactions
are in the normal course of joint venture operations and are measured
using the fair value established through the original transactions
with third parties.
The following amounts are due to and from related parties as at
December 31 and have been included in accounts receivable and
accounts payable and accrued liabilities on the balance sheet:
---------------------------------------------------------------------
2005 2004
---------------------------------------------------------------------
Due (to) from NAL Resources Limited $14,326 ($2,147)
---------------------------------------------------------------------
Due to NAL Resources Management Limited ($4,598) ($1,224)
---------------------------------------------------------------------
---------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Fair Values
The carrying value of the Trust's financial instruments, including
accounts receivable, reclamation reserve, long-term debt, and
accounts payable and accrued liabilities approximate their fair value
due to their short terms to maturity and variable interest rates.
Credit Risk Management
Accounts receivable includes amounts due from NAL Resources for oil,
natural gas and natural gas liquids sales. Oil and gas sales
marketing is conducted by the Manager on behalf of the Trust and NAL
Resources generally with large, creditworthy purchasers, for which
the Trust views the credit risk as low. The credit risk associated
with NAL Resources is also considered to be minimal as amounts owing
are from actual collections of oil and gas sales.
Interest Rate
The Trust is exposed to interest rate risk to the extent that bank
debt is at a floating interest rate.
Commodity Price Risk Management
As at December 31, 2005 the Trust had entered into the following
derivatives to protect its 2006 cash flow from the volatility of oil
and natural gas commodity prices:
Financial WTI oil contracts in place as at December 31, 2005:
---------------------------------------------------------------------
Volume Sold Put Bought Put Sold Call
Term Contract bbl/d $US/bbl $US/bbl $US/bbl
---------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 52.00 57.00 72.50
---------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 57.00 72.50
---------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 58.50 72.50
---------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 57.50 74.00
---------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 600 48.00 57.00 72.50
---------------------------------------------------------------------
2006 weighted
average 1,800 48.67 57.33 72.75
---------------------------------------------------------------------
Financial AECO natural gas contracts in place as at December 31,
2005:
---------------------------------------------------------------------
Term Contract Volume Bought Put Sold Call
GJ/d $Cdn/GJ $Cdn/GJ
---------------------------------------------------------------------
Jan. 1 to Dec. 31, 2006 Collar 2,000 9.50 14.40
---------------------------------------------------------------------
The estimated fair value of the above contracts, all of which qualify
for hedge accounting, was a gain of $36,000 as at December 31, 2005.
These instruments have no carrying value recorded in the financial
statements.
Subsequent to year-end, the Trust entered into further contracts as
follows:
---------------------------------------------------------------------
Volume Sold Put Bought Put Sold Call
Term Contract bbl/d $US/bbl $US/bbl $US/bbl
---------------------------------------------------------------------
Jan. 1 to
Dec. 31, 2006 3 way 300 48.00 60.00 72.50
---------------------------------------------------------------------
Feb. 1 to
Dec. 31, 2006 3 way 300 48.00 60.00 72.50
---------------------------------------------------------------------
Feb. 1 to
Dec. 31, 2006 3 way 300 48.00 60.00 74.00
---------------------------------------------------------------------
900 48.00 60.00 73.00
---------------------------------------------------------------------
12. COMMITMENTS
At December 31, 2005 the Trust had the following contractual
obligations and commitments:
($000s)
2006 2007 2008 2009 2010
---------------------------------------------------------------------
Office lease(1) 2,843 2,460 - - -
Transportation
agreement 1,136 398 299 - -
Processing
agreement(2) 520 491 469 446 428
---------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager of which NAL is
allocated a pro rata share of the expense on a monthly basis.
Included in office lease is a $1.0 million commitment related to
the Addison Energy acquisition. The commitment started in
February 2005 and extends 30 months. NAL has subsequently sublet
the premise.
(2) Represents gas processing agreement under take or pay arrangement
associated with Addison Energy acquisition.
13. COMPARATIVE FIGURES
Certain comparative figures have been re-classified to conform to
current-period presentation.
Trading Performance
-------------------------------------------------------------------------
For the Quarter Ended Full Year
-------------------------------------------------------------------------
31-Dec-05 30-Sep-05 31-Dec-04 30-Sep-04 2005 2004
-------------------------------------------------------------------------
PRICE
-------------------------------------------------------------------------
High $19.15 $17.80 $15.29 $14.2 $19.15 $15.29
-------------------------------------------------------------------------
Low $13.39 $14.31 $12.60 $11.68 $12.82 $9.79
-------------------------------------------------------------------------
Close $18.08 $15.95 $13.55 $14.29 $18.08 $13.55
-------------------------------------------------------------------------
Volume 16,922,700 18,992,928 15,265,465 9,359,852 72,097,477 47,130,324
-------------------------------------------------------------------------
Forward-Looking Statements
This disclosure contains certain forward-looking statements that
involve substantial known and unknown risks and uncertainties, many of
which are beyond NAL's control, including: the impact of general
economic conditions in Canada and in the United States, industry
conditions, changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced, increased competition, the lack of
availability of qualified personnel or management, fluctuations in
foreign exchange or interest rates, stock market volatility and market
valuations of companies with respect to announced transactions and the
final valuations thereof, and obtaining required approval of regulatory
authorities. NAL's actual results, performance or achievement could
differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurances can be given
that any of the events anticipated by the forward-looking statements
will transpire or occur, or if any of them do so, what benefits,
including the amount of proceeds, that NAL will derive therefrom.
NAL Oil & Gas Trust is an open-end investment trust founded in
1996 that generates distributions through the acquisition, development,
production and marketing of oil, natural gas and natural gas liquids.
The Trust owns high quality assets in Alberta, Saskatchewan and Ontario.
Trust units trade on the Toronto Stock Exchange under the symbol
"NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Gordon Currie
Manager, Investor Relations
(403) 294-3600 or Toll Free: 888-223-8792
Fax: (403) 515-3407
Email: Investor.Relations@nal.ca
Website: www.nal.ca