CALGARY--(CCNMatthews - March 2) - NAL Oil & Gas Trust (TSX: NAE.UN) ("NAL" or the "Trust") today announced its financial and operational results for the fourth quarter and year ended December 31, 2006. All amounts are in Canadian dollars unless otherwise stated.
HIGHLIGHTS
- In 2006, NAL delivered operating and financial performance that met or
exceeded expectations. Production volume was within guidance, cash
flow met expectations, netbacks were above industry average and NAL's
overall cost structure was lower than 2005 levels. NAL retained a
sound balance sheet, completed a restructuring of its management
contract and the capital spending program created positive momentum
going into 2007.
- Production averaged 19,444 barrels of oil equivalent per day in 2006,
up 2.2 percent from 19,018 in 2005 and within the range of guidance
(19,200 to 19,800) provided in January 2006. This production level
represents the highest annual rate in NAL's eleven-year history.
Production volume mix remained relatively constant at 48 percent crude
oil, 10 percent natural gas liquids and 42 percent natural gas.
- NAL benefited from a five percent increase in year-over-year oil
prices in 2006, but these higher oil prices were not sufficient to
offset a 23 percent decrease in natural gas prices. On a barrel of oil
equivalent basis, realized prices were seven percent lower at $53.98
per boe in 2006 compared to $58.07 per boe in 2005.
- Revenue and funds from operations were relatively unchanged in 2006
compared to 2005 as higher production volumes largely offset lower
commodity prices. On a per unit basis, funds from operations were
lower at $2.88 versus $3.17 due to an increase in the weighted average
number of units outstanding during the year. During 2006, the Trust
issued 2.4 million units under its Distribution Reinvestment Program
(DRIP), raising $41.1 million in new equity at an average price of
$17.25 per unit, and issued 1.6 million units to an affiliate of the
Manager at $18.84 per unit as part of the restructuring of the
management contract.
- Net income for full year 2006 was $60.2 million compared to $98.5
million a year earlier. Excluding a $27.2 million one-time charge
associated with the management contract restructuring, net income was
$87.4 million, down eleven percent from a year earlier.
- NAL's operating cost for the full year 2006 was $8.31 per boe and came
in at the low end of the 2006 guidance range due to active cost
management in a period of rising costs. Similarly, our G&A at $1.54
per boe was below guidance levels. In addition, as a result of
management contract restructuring, management fees fell from $1.43 per
boe in 2005 to $0.19 per boe in 2006 and there will be no management
fees payable in the future. Operating costs, G&A and management fees
totaled $10.04 per boe in aggregate in 2006, seven percent lower than
the $10.79 per boe incurred in 2005. NAL's operating netback was
$34.40 per boe, including a $0.48 per boe hedging gain.
- As to capital expenditures, the Trust spent $124 million in 2006.
Drilling, completion and production equipment totaled $88 million,
which contributed to NAL's positive production performance. The Trust
replaced 3,200 boe per day of production at $27,500 per flowing
barrel. In addition, NAL invested $25 million in plant, facilities,
seismic and core area land purchases to add future production and
reserves, the most significant being the Lacombe/Clive Horseshoe
Canyon coalbed methane ("CBM") project.
- NAL did not make a significant asset or corporate acquisition in 2006,
so its capital was focused on the conversion of existing reserves and
positioning for future growth. NAL's three-year average finding,
development and acquisition cost ("FD&A") per boe, which includes the
acquisition of Addison Energy Inc. in 2005, was $21.41 proved or
$18.59 proved plus probable.
- NAL ended the year with $223.1 million in net bank debt representing a
multiple of approximately one times debt-to-funds from operations.
NAL's solid balance sheet positions the Trust to take advantage of
acquisition opportunities as they arise.
- Regarding tax pools, NAL increased tax pool balances by 25 percent,
ending 2006 at $495 million vs. $395 million a year earlier.
- At the end of 2006, NAL added two experienced members to its senior
management team who are expected to contribute significantly to our
future plans. Marlon McDougall joined NAL on December 4, 2006 as Vice
President of Operations and Keith A. Steeves joined NAL on
December 11, 2006 as Vice President of Finance. Keith will assume the
CFO's responsibility at the end of March 2007 when Ross Liland retires
from NAL.
OUTLOOK
- Moving into 2007, NAL has strong momentum with new production being
tied-in as follow-on to 2006 capital spending. NAL's outlook for the
year remains consistent with its guidance announced in December 2006
and January 2007 with production and cost measures trending towards
the mid-range.
2007 Guidance
-----------------------------------------------------
Average total production (boe/d) 18,500 - 19,000
Capital expenditures $106 million
Operating costs ($/boe) 8.90 - 9.40
G&A ($/boe)(1) 1.75 - 1.95
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(1) Excluding unit-based compensation expense.
- As to our future direction, NAL will continue to build on its strong
historical performance and focus on creating sustainable value through
the efficient exploitation of its asset base supplemented by
acquisitions, which add value and deliver future potential. Andrew
Wiswell, President and CEO summarized the way forward:
"Our key priorities include delivering targeted production,
maintaining our very competitive cost structure, improving our capital
efficiency, and sustaining our industry-recognized safety and
environmental performance. To deliver these priorities and continue to
move towards a sustainable model, we will add opportunities through
the drill bit, partnering and acquisitions, set distributions which
are responsive to commodity prices, retain a balance sheet which
allows us to capture opportunities and build a higher tax pool base
which will serve our unitholders well in the future in any business
structure."
SENSITIVITY ANALYSIS
The estimated impact of changes to commodity prices, production levels,
exchange rates and interest rates on estimated 2007 funds from operations are
summarized below, excluding any effects of hedging.
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Funds From Operations
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Amount
Assumptions Change ($000s) Per Unit
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Commodity Prices
WTI oil (US$/bbl) $1.00 $2,900 $0.04
AECO natural gas (Cdn$/Mcf) $0.50 $7,300 $0.09
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Volume Changes
Oil 100 bbl/d $1,400 $0.02
Natural gas 1,000 Mcf/d $1,800 $0.02
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Exchange Rate
Cdn$/US$ $0.01 $1,600 $0.02
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Interest Rate
Bank prime lending rate 1.0% $2,500 $0.03
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At 8:30 a.m. MST (10:30 a.m. EST) on Friday, March 2, 2007 NAL will hold
a conference call to discuss its fourth quarter and year-end results.
Mr. Andrew Wiswell, President and CEO, will host the conference call with
other members of the Management Team. The call is open to analysts,
investors, and all interested parties. If you wish to participate, call
403-398-9531 within the Calgary area or 1-800-733-7571, toll-free across
North America. The conference will also be accessible by webcast at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID= [1]
1725680.
A recorded playback of the call will be available until March 9, 2007 by
dialing 416-640-1917 or 1-877-289-8525, reservation 21218454 followed by
the number sign.
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When converting natural gas to equivalent barrels of oil (boe) within
this report, NAL uses the widely recognized standard of 6 thousand cubic
feet (Mcf) of natural gas to one barrel of oil (bbl). However, boe's may
be misleading, particularly if used in isolation. A boe conversion ratio
of 6 Mcf : 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
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Three Months Year
Ended December 31 Ended December 31
-------------------------------------------
2006 2005 2006 2005
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FINANCIAL
Gross revenue, net of
royalties $75,694 $95,643 $310,752 $314,006
Net income (loss) 20,472 30,777 60,198(1) 98,538
Funds from operations 55,795 65,837 219,776 221,649
Distributions declared 39,663 41,956 169,589 142,050
Funds from operations
per unit 0.72 0.90 2.88 3.17
Distributions declared
per unit 0.51 0.57 2.22 2.01
Payout ratio 71% 64% 77% 64%
Average number of units
outstanding (000s) 77,697 73,436 76,350 69,946
Total assets $796,902 $834,883 $796,902 $834,883
Bank debt, net of working
capital 223,061 198,351 223,061 198,351
Unitholders' equity 456,500 494,490 456,500 494,490
Costs per boe ($/boe - 6:1):
Operating $7.13 $9.41 $8.31 $8.02
General and administrative 1.33 1.62 1.54 1.34
Unit-based incentive
compensation (0.07) 0.33 0.35 0.20
Management fees - 2.27 0.19 1.43
OPERATING
Daily production
Oil (bbl) 9,700 9,755 9,367 9,399
Natural gas (Mcf) 47,153 52,340 48,804 46,512
Natural gas liquids (bbl) 1,958 2,036 1,944 1,867
Oil equivalent (boe - 6:1) 19,517 20,514 19,444 19,018
Average pricing, net of
transportation charges
and before hedging gains
and losses
Liquids:
WTI (US$/bbl) 60.21 60.02 66.22 56.56
NAL average oil (Cdn$/bbl) 58.53 62.16 65.30 62.33
NAL natural gas liquids
(Cdn$/bbl) 43.24 56.29 48.70 49.51
Natural gas:
AECO (Cdn$/Mcf)
- daily spot 6.90 11.43 6.56 8.77
AECO (Cdn$/Mcf) - monthly 6.36 11.84 6.98 8.38
NAL natural gas Western
Canada (Cdn$/Mcf) 6.84 11.68 6.98 8.97
NAL natural gas Lake Erie
(Cdn$/Mcf) 8.16 14.36 8.09 11.06
NAL average natural gas
(Cdn$/Mcf) 6.96 11.91 7.03 9.16
NAL oil equivalent
(Cdn$/boe - 6:1) 49.77 65.52 53.98 58.07
Average foreign exchange
rate (Cdn$/US$) 1.139 1.173 1.134 1.211
Operating netback before
hedging gains (losses)
($/boe) 32.48 42.21 33.92 37.49
Hedging gains (losses)
($/boe) 1.00 (2.37) 0.48 (1.56)
Operating netback ($/boe) 33.48 39.84 34.40 35.93
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(1) Includes one-time $27.2 million non-cash management contract
restructuring charge.
OIL AND GAS RESERVES
NAL's 2006 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,
2006, the Trust's proved reserves total 40.8 million barrels of oil
equivalent("boe") and proved plus probable ("P+P") reserves amount to 58.2
million boe.
NAL has a reserves committee, composed entirely of independent directors,
which is responsible for appointing the Trust's independent engineering
consultants and determining the scope of the annual reserves review.
Some key points regarding NAL's 2006 reserves summary are:
- Overall technical revisions were highly positive for Proved reserves
(+2,588 Mboe) and essentially neutral for P+P reserves (-19 Mboe).
This demonstrates that our reserves bookings are consistent with
NI 51-101 guidelines, where the ultimate Proved reserves are a
conservative estimate, which should increase over time while the
ultimate P+P reserves represent the best estimate which, in aggregate,
should have an equal likelihood of being higher or lower than the
initial estimate.
- Additions for Improved Recovery amounted to 1,778 Mboe of P+P
reserves, representing new reserves added from drilling and other
development activities over and above the volumes that were previously
booked. The majority of the capital spending each year is directed
toward upgrading reserves from Probable to Proved or from Proved
Undeveloped to Proved Producing, while a smaller portion of the
capital spending targets new reserves additions.
- At December 31, 2006, over 94 percent of NAL's Proved reserves were in
the Proved Producing category. NAL takes a conservative approach in
booking undeveloped reserves in the Proved Undeveloped category.
- NAL continues to have a high quality asset base, with no heavy oil
reserves. No reserves write-downs have been required or are
anticipated as a result of lower commodity prices.
The following tables summarize NAL's estimated reserves volumes and values
using McDaniels' price forecasts as of January 1, 2007. Gross reserves volumes
are based on the Trust's working interests before deduction of royalties
payable, and exclude any wells or properties in which NAL has only a royalty
interest. Net reserves represent the Trust's working interest reserves after
deducting royalties payable, plus royalty interest reserves.
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SUMMARY OF OIL AND GAS RESERVES
as of December 31, 2006
FORECAST PRICES AND COSTS
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RESERVES
LIGHT AND NATURAL
MEDIUM OIL GAS
Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (MMcf) (MMcf)
PROVED
Developed Producing 17,734 15,483 99,925 84,485
Developed Non-Producing 145 129 5,811 5,118
Undeveloped 413 382 3,844 3,464
-------------------------------------------
TOTAL PROVED 18,291 15,994 109,580 93,067
PROBABLE 8,203 7,244 43,046 36,361
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TOTAL PROVED PLUS PROBABLE 26,494 23,238 152,626 129,428
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RESERVES
NATURAL GAS TOTAL
LIQUIDS BOE (6:1)
Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl)
PROVED
Developed Producing 4,137 3,099 38,525 32,663
Developed Non-Producing 84 66 1,197 1,048
Undeveloped 29 26 1,082 985
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TOTAL PROVED 4,250 3,191 40,804 34,696
PROBABLE 2,032 1,511 17,410 14,815
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TOTAL PROVED PLUS PROBABLE 6,282 4,702 58,214 49,511
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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 $)
PROVED
Developed Producing 1,118 882 736 636
Developed Non-Producing 34 27 23 20
Undeveloped 21 16 12 9
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TOTAL PROVED 1,173 925 771 665
PROBABLE 560 352 247 186
-------------------------------------------
TOTAL PROVED PLUS PROBABLE 1,733 1,277 1,018 851
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The net present values shown are reported before income taxes. It should
not be assumed that the estimated future net revenue is representative of
the fair market value of the properties of the Trust. There is no
assurance that such price and cost assumptions will be attained and
variances could be material.
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SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2006
FORECAST PRICES AND COSTS
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OIL
Edmonton Cromer Medium NATURAL GAS
WTI Cushing Par Price 29.3 degrees AECO Spot
Oklahoma 40 degrees API API Price
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu)
2007 62.50 70.80 62.20 7.22
2008 61.20 69.30 60.90 7.43
2009 59.80 67.70 59.40 7.80
2010 58.40 66.10 58.00 7.91
2011 56.80 64.20 56.40 8.12
2012 58.00 65.60 57.60 8.33
Thereafter(*) +2%/year +2%/year +2%/year +2%/year
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--------------------------------------------------------
NATURAL GAS INFLATION EXCHANGE
LIQUIDS RATES RATE
EDMONTON MIX
Year ($Cdn/bbl) Percent/Year ($US/Cdn)
2007 50.80 2.0 0.870
2008 50.10 2.0 0.870
2009 49.50 2.0 0.870
2010 48.60 2.0 0.870
2011 47.60 2.0 0.870
2012 48.70 2.0 0.870
Thereafter(*) +2%/year 2.0 0.870
--------------------------------------------------------
(*) Price escalation rates are approximate.
RECONCILIATION OF
COMPANY GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
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ASSOCIATED AND
LIGHT AND MEDIUM OIL NON-ASSOCIATED GAS
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Proved Proved
Plus Plus
Proved Probable Proved Probable
FACTORS (Mbbl) (Mbbl) (MMcf) (MMcf)
December 31, 2005 19,829 28,455 119,522 166,567
Improved Recovery 299 1,178 1,653 2,548
Technical Revisions 1,530 192 6,168 1,252
Acquisitions 123 174 50 73
Dispositions (71) (86) 0 0
Production (3,419) (3,419) (17,813) (17,813)
December 31, 2006 18,291 26,494 109,580 152,626
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NATURAL GAS LIQUIDS TOTAL BOE
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Proved Proved
Plus Plus
Proved Probable Proved Probable
FACTORS (Mbbl) (Mbbl) (Mboe) (Mboe)
December 31, 2005
4,817 7,226 44,566 63,442
Improved Recovery 105 175 680 1,778
Technical Revisions 30 (420) 2,588 (19)
Acquisitions 7 10 138 196
Dispositions 0 0 (71) (86)
Production (709) (709) (7,097) (7,097)
December 31, 2006 4,250 6,282 40,804 58,214
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2006
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Change in
Estimated
Actual Future
Spending Development
During 2006 Costs Total
------------- ----------- --------
Capital (M$) Proved 118,791 (22,092) 96,699
Proved + Probable 118,791 (16,852) 101,939
Improved Technical
Recovery Revisions Total
---------- ----------- --------
Reserves (Mboe) Proved 680 2,588 3,268
Proved + Probable 1,778 (19) 1,759
F&D ($/boe) Proved $29.59
Proved + Probable $57.95
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3-YEAR WEIGHTED AVERAGE
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Change in
Estimated
Actual Future
Spending Development
Over 3 Years Costs Total
-------------- ----------- --------
Capital (M$) Proved 221,973 (22,538) 199,435
Proved + Probable 221,973 5,912 227,885
Improved Technical
Recovery Revisions Total
---------- ----------- --------
Reserves (Mboe) Proved 3,155 5,220 8,375
Proved + Probable 6,982 55 7,037
F&D ($/boe) Proved $23.81
Proved + Probable $32.38
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2006
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Change in
Actual Estimated
Spending Future Total
During Development Acquis- Dispos- Including
2006 Costs itions itions A&D
--------- ----------- -------- --------- ---------
Capital (M$) Proved 118,791 (22,092) 3,111 (1,940) 97,870
Proved +
Probable 118,791 (16,852) 3,111 (1,940) 103,110
Total
Improved Technical Acquis- Dispos- Including
Recovery Revisions itions itions A&D
--------- ----------- -------- --------- ---------
Reserves Proved 680 2,588 138 (71) 3,335
(Mboe) Proved +
Probable 1,778 (19) 196 (86) 1,869
FD&A ($/boe) Proved $29.35
Proved +
Probable $55.17
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3-YEAR WEIGHTED AVERAGE
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Change in
Actual Estimated
Spending Future Total
Over Development Acquis- Dispos- Including
3 Years Costs itions itions A&D
--------- ----------- -------- --------- ---------
Capital (M$) Proved 242,434 9,082 388,456 (8,141) 631,831
Proved +
Probable 242,434 48,256 388,456 (8,141) 671,005
Total
Improved Technical Acquis- Dispos- Including
Recovery Revisions itions itions A&D
--------- ----------- -------- --------- ---------
Reserves Proved 3,155 4,629 22,077 (349) 29,512
(Mboe) Proved +
Probable 6,982 276 29,324 (486) 36,096
FD&A ($/boe) Proved $21.41
Proved +
Probable $18.59
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December 31, 2006 December 31, 2005
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Forecast Constant Forecast Constant
($000s, except per unit data) Prices(3) Prices(4) Prices Prices
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Proved plus probable reserves
(discounted at 10%) 1,017,713 897,171 1,062,520 1,290,508
Undeveloped land and
seismic(1) 47,800 47,800 42,200 42,200
Working capital (deficiency) (2,276) (2,276) 26,066 26,066
Long-term debt (221,790) (221,790) (220,519) (220,519)
Asset retirement
obligation(2) (34,191) (37,793) (31,059) (35,546)
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Net asset value 807,256 683,112 879,208 1,102,709
-------------------------------------------
Units outstanding (000s) 77,971 77,971 73,977 73,977
NAV per unit $10.35 $8.76 $11.88 $14.91
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(1) Internal estimate.
(2) The Asset Retirement Obligation ("ARO") is calculated based on the
same methodology that was used to calculate the ARO on NAL's year-end
financial statements, with the exception that future expected ARO
costs were discounted at 10 percent. The total discounted ARO of
$54.0 million and $50.7 million at the respective balance sheets was
reduced by $19.8 million and $19.6 million under the forecast price
cases and $16.2 million and $15.1 million under the constant price
cases, respectively, relating to well abandonment costs that were
incorporated in the Value of Proved Plus Probable reserves discounted
at 10 percent pursuant to the forecast and constant price cases
included in the Trust's oil and gas reserve evaluations.
(3) McDaniel's price forecasts as of January 1, 2007, reflecting WTI
US$62.50 and AECO Cdn$7.22 for 2007 trending to WTI US$56.80 and AECO
Cdn$8.12 in 2011, with a US$/Cdn$ exchange rate of $0.87 over the
five years.
(4) Based on December 31, 2006 closing prices as published by McDaniel &
Associates Consultants Ltd.
Fourth Quarter Drilling Activity
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Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
---------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated
wells 15 7.89 30 19.76 - - - - 45 27.65
Non-
operated
wells 3 0.40 1 0.31 - - - - 4 0.71
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Total
wells
drilled 18 8.29 31 20.07 - - - - 49 28.36
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Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
---------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
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Total
wells
drilled 71 27.7 110 57.21 7 2 3 0.64 191 87.55
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CAPITAL EXPENDITURES
Capital expenditures for the quarter ended December 31, 2006 totaled $34.8
million compared with $26.2 million in the quarter ended December 31, 2005.
For the year ended December 31, 2006 capital expenditures totaled $124.0
million as compared to $73.1 million in the same period in 2005.
Capital Expenditures ($000s)
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Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
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Drilling, completion and
production equipment 25,619 20,718 87,901 57,105
Plant and facilities 4,715 4,039 14,598 8,474
Seismic 404 1,072 2,628 2,691
Land 2,243 766 7,730 1,205
Property acquisitions
(dispositions) 40 (1,564) 1,171 (1,564)
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Total exploitation and
development 33,021 25,031 114,028 67,911
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Office equipment(1) 772 -- 4,080 --
Capitalized G&A 1,290 968 4,275 4,537
Capitalized unit-based
compensation (295) 165 1,659 651
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1,767 1,133 10,014 5,188
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Total capital expenditures 34,788 26,164 124,042 73,099
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(1) Includes $2.8 million in assets acquired as part of the management
agreement restructuring.
A record $87.9 million was spent in 2006 on drilling, completions and
tie-ins. Although industry costs for development activities were up
substantially in 2006, the Trust participated in a record 87.55 net wells (191
gross wells). The Trust also spent $14.6 million on plant and facilities in
2006, up from $8.5 million a year earlier. This increased level of spending
focused on new Lacombe compression facilities, as well as substantial upgrades
to water handling and storage facilities supporting our Saskatchewan
operations, all of which will support future production.
NAL made meaningful investments in land and seismic in 2006, focusing on
enhancing the Trust's core areas. Of the $7.7 million spent on land, major
expenditures in the Elswick area of Saskatchewan as well as in Hanna and
Garrington/Westward Ho in Alberta were made. Together with purchases in
Lacombe, Sylvan Lake, Huntoon, and Alida, these investments are focused on
drilling opportunities planned for 2007 and 2008.
PRODUCTION
Trust production averaged 19,517 boe/d for the three months ended December
31, 2006, five percent lower than the 20,514 boe/d for the comparable period
in 2005. For the year ended December 31, 2006, production averaged 19,444
boe/d, a two percent increase over 19,018 boe/d a year earlier.
Average Daily Production Volumes
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Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
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Oil (bbl/d) 9,700 9,755 9,367 9,399
Natural gas (Mcf/d) 47,153 52,340 48,804 46,512
NGL's (bbl/d) 1,958 2,036 1,944 1,867
Oil equivalent (boe/d) 19,517 20,514 19,444 19,018
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For the year ended December 31, 2006, the Trust's production weighting was
relatively unchanged from the comparable period in 2005 with oil and natural
gas liquids production representing 58 percent and natural gas 42 percent.
Production Weighting
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Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
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Oil 50% 48% 48% 49%
Natural gas 40% 43% 42% 41%
NGLs 10% 9% 10% 10%
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REVENUE AND FUNDS FROM OPERATIONS
Gross revenue from oil, natural gas and natural gas liquids sales, after
transportation costs and hedging gains, totaled $91.2 million for the three
months ended December 31, 2006, 24 percent lower than the fourth quarter of
2005.
Revenue decreased year-over-year due to lower production volumes and lower
natural gas prices. Compared to the fourth quarter of 2005, production in the
fourth quarter of 2006 decreased five percent and average commodity prices,
after hedging, decreased by 20 percent.
For the twelve-month period ended December 31, 2006 gross revenue totaled
$386.5 million, a decrease of one percent from the comparable period in 2005.
This decrease is attributable to a four percent decrease in NAL oil equivalent
pricing after hedging, offset by a two percent increase in production.
Funds from operations tracked revenues in the fourth quarter of 2006, down
15 percent in total from the fourth quarter 2005 and down 20 percent from
$0.90 to $0.72, on a per unit basis. For the year ended December 31, 2006,
total funds from operations were down one percent and down nine percent on a
per unit basis to $2.88 from $3.17 for 2005.
Revenue and Funds From Operations
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue(1) ($000s) 91,172 119,208 386,452 392,244
$/boe 50.78 63.16 54.45 56.51
Funds from operations(2)
($000s) 55,795 65,837 219,776 221,649
$/boe 31.07 34.88 30.97 31.93
$/unit 0.72 0.90 2.88 3.17
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(1) Oil, natural gas and liquids sales less transportation and after
hedging.
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
Average Pricing
(net of transportation charges)
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Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Liquids:
WTI (US$/bbl) 60.21 60.02 66.22 56.56
NAL average oil (Cdn$/bbl) 58.53 62.16 65.30 62.33
NAL natural gas liquids
(Cdn$/bbl) 43.24 56.29 48.70 49.51
Hedging gains (losses) 1.31 (2.63) 0.33 (2.18)
Natural Gas (Cdn$/Mcf):
AECO - daily spot 6.90 11.43 6.56 8.77
AECO - monthly 6.36 11.84 6.98 8.38
NAL Western Canada natural
gas (Cdn$/Mcf) 6.84 11.68 6.98 8.97
NAL Lake Erie natural gas
(Cdn$/Mcf) 8.16 14.36 8.09 11.06
NAL average natural gas 6.96 11.91 7.03 9.16
Hedging gains (losses) 0.14 (0.44) 0.13 (0.20)
NAL Oil Equivalent before
hedging (Cdn$/boe - 6:1) 49.77 65.52 53.98 58.07
Average Foreign Exchange Rate
(Cdn$/US$) 1.139 1.173 1.134 1.211
-------------------------------------------------------------------------
For 2007, NAL has the following hedges outstanding:
Hedging Summary
-------------------------------------------------------------------------
Crude Oil Natural Gas
-------------------------------------------------------------------------
Swap (bbls/d) 1,150 Swap (GJ/d) 6,630
$US/bbl $67.70 $Cdn/GJ $7.15
Collars (bbls/d) 1,148 Collars (GJ/d) 9,000
$US/bbl $64.68 - $73.78 $Cdn/GJ $6.61 - $8.48
Total (bbls/d) 2,298 Total (GJ/d) 15,630
-------------------------------------------------------------------------
The details of NAL's hedging position are set out in Note 12 to the
accompanying Consolidated Financial Statements.
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, 2006. As at
December 31, 2006 the unrealized fair value of these hedges was a gain of $4.5
million.
ROYALTY EXPENSES
Crown, freehold and overriding royalties, net of Alberta Royalty Tax
Credit ("ARTC"), were $18.3 million for the three months ended December 31,
2006. Expressed as a percentage of gross sales, before hedging and
transportation costs, the net royalty rate was 20.3 percent for the quarter
ended December 31, 2006, down slightly from 21.1 percent experienced in the
comparable period the previous year.
On a year-to-date basis, royalties were $83.3 million, down from $87.2
million in the comparable period of 2005. Expressed as a percentage of gross
sales the royalty rate is consistent year-over-year at 21.6 percent for 2006
as compared to 21.5 percent in the prior year.
Royalty Expenses
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Net royalties ($000s) 18,258 26,248 83,332 87,188
As % of revenue(1) 20.3 21.1 21.6 21.5
$/boe 10.17 13.91 11.74 12.56
-------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales before transportation and hedging.
OPERATING COSTS
For the quarter ended December 31, 2006, operating costs averaged $7.13
per boe, a 24 percent decrease from the $9.41 per boe for the quarter ended
December 31, 2005. The fourth quarter of 2005 included upward adjustments to
various costs that were accrued earlier in the year. Conversely, the fourth
quarter of 2006 includes several downward adjustments for activity from
earlier in 2006 that cost less than estimated. For the full year 2006,
operating costs averaged $8.31 per boe compared to $8.02 for 2005, an increase
of four percent. The Trust assets are characterized by high working interest
operated processing facilities and as such have a significant (80 percent
plus) fixed operating cost component. Although competitive industry conditions
had significant impact on the Trust's cost base in 2006, a continuous and
aggressive optimization program by our field operations staff yielded savings
of $1.2 million for the full year. The Trust continues to compare favorably to
trust industry averages for operating expenses.
Operating Costs
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating costs ($000s) 12,796 17,767 58,964 55,682
As % of revenue 14.0 14.9 15.3 14.2
$/boe 7.13 9.41 8.31 8.02
-------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended December 31, 2006, NAL's operating netback, before
hedging gains, was $32.48 per boe, a decrease of 23 percent from $42.21 for
the quarter ended December 31, 2005, primarily attributable to lower natural
gas prices.
For the twelve-month period ended December 31, 2006, the operating netback
before hedging was $33.92 per boe, a decrease of ten percent from the
comparable period of 2005, the decrease driven primarily by year-over-year
lower natural gas prices.
Operating Netback ($/boe)
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue(1) 49.78 65.53 53.97 58.07
Royalties, net (10.17) (13.91) (11.74) (12.56)
Operating expenses (7.13) (9.41) (8.31) (8.02)
-------------------------------------------
Operating netback, before
hedging 32.48 42.21 33.92 37.49
Hedging gains (losses) 1.00 (2.37) 0.48 (1.56)
-------------------------------------------
Operating netback, after
hedging 33.48 39.84 34.40 35.93
-------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales less transportation.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses include direct costs incurred
by the Trust plus the reimbursement of the Manager's G&A expenses incurred on
the Trust's behalf.
For the three months ended December 31, 2006, G&A expenses were $2.4
million, compared with $3.0 million in the comparable quarter in 2005. In
addition, $1.3 million of G&A costs relating to exploitation and development
activities were capitalized in the fourth quarter of 2006 compared with $1.0
million in the fourth quarter of 2005.
For the year ended December 31, 2006, total G&A has increased ten percent
to $15.2 million from $13.8 million. In 2006, $4.3 million of G&A costs
relating to exploitation and development activities were capitalized, compared
with $4.5 million in 2005. G&A expenses increased to $10.9 million in 2006
compared with $9.3 million in 2005.
The increase in total G&A costs in 2006 was primarily due to increased
compensation costs necessary to continue to attract and retain qualified
personnel in a highly competitive market, one time costs associated with the
special meeting to approve the restructuring of the management contract, and
costs associated with the simplification of the trust structure undertaken
during the year.
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
G&A expenses ($000s) 2,395 3,049 10,946 9,295
Capitalized G&A ($000s) 1,290 968 4,275 4,537
-------------------------------------------
Total G&A ($000s) 3,685 4,017 15,221 13,832
Expensed G&A costs:
As % of revenue 2.6 2.6 2.8 2.4
$/boe 1.33 1.62 1.54 1.34
Per Trust unit ($) 0.03 0.04 0.14 0.13
-------------------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
In January 2006, the Board of Directors approved a revised unit-based
incentive plan (the "Plan") for all employees of the Manager. Under the Plan,
employees receive cash compensation based upon the value and overall return of
a specified number of awarded notional Trust units. Distributions paid on the
Trust's outstanding units during the vesting period are assumed to be
reinvested in notional units on the date of distribution.
The first payment under the previous plan was made in December 2005, the
charge for which was accrued throughout the year and of which $1,415,000 was
charged to income and $651,000 capitalized in 2005. During the fourth quarter
of 2005, $628,000 was charged to income and $165,000 was capitalized. With the
expansion of the Plan and the introduction of the annual vesting provision for
the RTU's in 2006, the Trust has commenced to record its share of the value
associated with the notional units in its accounts over the vesting period.
The compensation charges relating to the units granted are recognized over
the vesting period based on the number of notional units outstanding, the
Trust's unit price and an expected performance multiplier. As a result, the
expense recorded in the accounts will fluctuate from period to period.
During the fourth quarter of 2006, the Trust recorded a reduction in unit-
based incentive compensation charges in the total amount of $426,000, of which
$131,000 was reflected in unit-based compensation expense and $295,000 was
deducted from capitalized unit-based compensation relating to exploitation and
development personnel. The reduction in unit-based compensation expense in the
fourth quarter is a reflection of the significant decrease in the Trust's unit
price following the October 31, 2006 announcement by the Federal Government of
their intention to tax income trusts.
On a year-to-date basis, the Trust has recorded $4.2 million of unit-
based incentive compensation charges in its accounts, of which $2.5 million
has been charged to income and $1.7 million has been capitalized. Of the $4.2
million, $2.2 million was paid in January 2007 and $1.0 million is expected to
be paid in December 2007. The balance represents the long-term portion of the
Trust's estimated liability for the unit-based incentive plan as at
December 31, 2006. This amount is payable in December 2008 and 2009.
Unit-Based Compensation
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) (131) 628 2,495 1,415
Capitalized ($000s) (295) 165 1,659 651
-------------------------------------------
Total unit-based compensation
($000s) (426) 793 4,154 2,066
Expensed unit-based
compensation:
As % of revenue (0.1) 0.5 0.6 0.4
$/boe (0.07) 0.33 0.35 0.20
Per trust unit ($) 0.00 0.01 0.03 0.02
-------------------------------------------------------------------------
MANAGEMENT CONTRACT AND 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 also 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
represent joint venture amounts from NAL Resources. These transactions are in
the normal course of joint venture operations and are based on the original
transactions with third parties.
The Manager provides certain services to the Trust pursuant to the
Management Contract for which, prior to January 1, 2006, the Trust was
required to pay a monthly base management fee equal to three percent of its
net production revenue and a quarterly performance fee based on the Trust's
overall return compared to the S&P/TSX Capped Energy Trust Index. Such fees
amounted to $4.3 million for the quarter ended December 31, 2005 and $10.0
million for the year ended December 31, 2005. In addition, the Trust paid $1.3
million (2005 - $1.9 million) for the reimbursement of G&A expenses incurred
by the Manager on behalf of the Trust pursuant to the Management Contract for
the fourth quarter of 2006, and $6.6 million (2005 - $7.0 million) for 2006.
The Trust also pays the Manager its share of unit-based incentive compensation
expense when cash compensation is paid to employees under the terms of the
Plan (2006 - $2.2 million; 2005 - $2.1 million).
On May 31, 2006 the Trust's unitholders approved the restructuring of the
Management Contract with the Manager. Under the restructuring, the Trust
agreed to pay a one-time $30 million restructuring fee in exchange for the
elimination of any further base and performance management fees payable by the
Trust and for the acquisition of a 50 percent ownership in the Manager's
administrative capital assets, effective January 1, 2006. In payment of the
Restructuring Fee, the Trust issued, to an affiliate of the Manager, 1,592,357
units of the Trust at a price of $18.84 per unit. The subscription price was
based on the weighted average trading price of the Trust units over the five
consecutive trading days ending on the third trading day preceding March 1,
2006, the date of the agreement.
Of the $30 million Restructuring Fee, $2.8 million has been allocated to
the administrative assets acquired and capitalized as Property, Plant and
Equipment. The balance of $27.2 million, representing the elimination of
future management and performance fees, has been recorded as a non-cash charge
to income. During 2006, the Trust paid an interim management fee of $250,000
per month in the first quarter and $300,000 per month in the second quarter up
to the closing of the restructuring transaction on May 31, 2006.
Management Fees
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Base management fees ($000s) - 2,142 1,350 7,816
Performance fees ($000s) - 2,142 -- 2,142
-------------------------------------------------------------------------
Total management fees - 4,284 1,350 9,958
As % of revenue - 3.6 0.4 2.5
$/boe - 2.27 0.19 1.43
Per trust unit ($) - 0.06 0.02 0.14
-------------------------------------------------------------------------
INTEREST
Interest expense includes charges on bank borrowings plus standby fees on
the unused portion of the bank credit facility. NAL's average outstanding bank
debt for the fourth quarter of 2006 was $213.9 million, as compared to $229.1
million for the fourth quarter of 2005. NAL's effective interest rate averaged
5.06 percent in 2006, compared with 4.54 percent in the fourth quarter of
2005.
For the year ended December 31, 2006 NAL's average outstanding debt was
$203.2 million, as compared to $233.7 million for the corresponding period in
2005. NAL's effective interest rate in 2006 averaged 4.83 percent compared
with 4.40 percent in 2005.
The lower outstanding bank debt during 2006 resulted in lower interest
charges for the year compared to fiscal 2005. Higher interest rates in 2006
resulted in higher interest charges in the fourth quarter compared with the
corresponding period in 2005.
Interest and Bank Debt ($000s)
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Interest on bank debt 2,759 2,651 9,963 10,372
Bank debt outstanding at
period end 220,785 220,519 220,785 220,519
Net bank debt outstanding at
period end(1) 223,061 198,351 223,061 198,351
Net bank debt-to-funds from
operations ratio 1.01 0.89 1.01 0.89
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
CASH FLOW NETBACK
For the quarter ended December 31, 2006, NAL's cash flow netback was
$30.68 per boe, a ten percent decrease from $34.21 for the comparable period
in 2005. The decrease is primarily due to lower operating netbacks in 2006
that are partially offset by the elimination of management fee charges for the
period, compared to a $2.27 per boe charge in the corresponding period of
2005.
For the year ended December 31, 2006, NAL's cash flow netback decreased
two percent to $30.92 compared to $31.47 in 2005. The decrease is primarily
attributable to lower operating netbacks offset by lower management fees in
2006 following the restructuring of the management agreement.
Cash Flow Netback ($/boe)
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating netback, after
hedging 33.48 39.84 34.40 35.93
Management fees -- (2.27) (0.19) (1.43)
G&A expenses (1.33) (1.62) (1.54) (1.34)
Unit-based incentive
compensation 0.07 (0.33) (0.35) (0.20)
Interest (1.54) (1.41) (1.40) (1.49)
-------------------------------------------
Cash flow netback 30.68 34.21 30.92 31.47
-------------------------------------------------------------------------
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION
(DDA)
Depletion of oil and natural gas properties, including the capitalized
portion of the asset retirement obligation, and depreciation of equipment is
provided for on a unit-of-production basis using estimated proved reserves
volumes.
For the quarter ended December 31, 2006, depletion on property, plant and
equipment and accretion on the asset retirement obligation increased by 6
percent over the comparable period in 2005 due to a 12 percent increase in the
DDA rate per boe of production partially offset by a five percent decrease in
production volumes.
For the year ended December 31, 2006 depletion and accretion increased by
12 percent over the comparable period due to a two percent increase in
production and a nine percent increase in the DDA rate per boe of production.
Depletion, Depreciation and Accretion Expenses
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Depletion and depreciation
($000s) 35,725 33,608 133,079 118,961
Accretion of asset retirement
obligation ($000s) 1,258 1,197 4,984 4,582
-------------------------------------------------------------------------
Total DDA ($000s) 36,983 34,805 138,063 123,543
DDA rate per boe ($) 20.60 18.44 19.45 17.80
-------------------------------------------------------------------------
TAXES
Taxes include provincial capital taxes relating to the Trust and its
subsidiary companies.
In the fourth quarter of 2006, NAL had a future income tax recovery of
$262,000 compared with a provision of $1.2 million in the corresponding period
of the prior year.
For the year, NAL had a future income tax recovery of $1.2 million in 2006
compared to a provision of $2.5 million in 2005.
The Trust is a taxable entity and files a trust income tax return
annually. The Trust's taxable income consists of royalty income, distributions
from a subsidiary trust and interest and dividends from other subsidiaries,
less deductions for the Trust's G&A expenses, resource allowance, Canadian Oil
and Gas Property Expense ("COGPE"), and trust unit issue costs. In addition,
Canadian Exploration Expense ("CEE"), Canadian Development Expense ("CDE") and
Undepreciated Capital Cost ("UCC") are incurred and deducted by the Trust's
subsidiaries. The Trust is taxable only on remaining income, if any, that is
not distributed to unitholders. The Trust does not expect to incur any cash
income taxes in 2007.
The following tax pools are available to the Trust and subsidiaries
(subject to assessment by income tax authorities) for future use as deductions
from taxable income:
--------------------------------------------------------
2006 2005
--------------------------------------------------------
Intangible resource pools $323,818 $268,575
Undepreciated capital cost 149,383 102,983
Unit issue costs 9,437 14,144
Non-capital losses 11,495 9,765
--------------------------------------------------------
Total tax pools $494,133 $395,467
--------------------------------------------------------
--------------------------------------------------------
On December 21, 2006, the Minister of Finance released for comment draft
legislation concerning the taxation of certain publicly traded trusts. The
legislation reflects proposals originally announced by the Minister on
October 31, 2006. Under the proposed legislation, distributions to unitholders
will not be deductible by publicly traded income trusts and, as a result, the
Trust will be taxed on its income similar to corporations. The proposed rules,
if passed into law, would be applicable commencing in 2011. However, if the
proposed legislation is implemented, the Trust would be required to recognize
in its accounts, in the period in which the change is substantially enacted,
future income taxes on temporary differences in the Trust.
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of Trust units and bank
debt.
As at December 31, 2006, NAL had 77,971,268 units outstanding, compared
with 73,977,021 units at December 31, 2005. The increase from December 31,
2005 is attributable to 2.4 million units issued under the distribution
reinvestment program ("DRIP") and 1.6 million units issued in connection with
the restructuring of the Management Agreement.
For the year ended December 31, 2006, the distribution reinvestment and
premium distribution reinvestment ("Premium DRIP") plans resulted in 2,401,890
units being issued at an average price of $17.25 per unit for total proceeds
of $41.4 million.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at 95
percent of the average market price with no additional fees or commissions.
The Premium DRIP allows unitholders to exchange such units for a cash payment,
from the plan broker, equal to 102 percent of the monthly distribution.
The combined participation in these programs has resulted in the
reinvestment of approximately 24.2 percent of monthly distributions over the
past year. On March 10, 2006, the Trust announced the suspension of the
Premium DRIP, which resulted in a significant reduction in the reinvestment
participation rate commencing with the distribution payable in April 2006. The
participation rate in the regular DRIP averaged 18.8 percent over the three
months ended December 31, 2006. The Trust continues to monitor the
participation in these plans in conjunction with its capital requirements.
As at December 31, 2006, the Trust had bank debt of $223.1 million (net of
working capital) compared with $198.4 million at December 31, 2005. At the end
of the fourth quarter, the Trust had a net bank debt-to-equity ratio of 0.49
and a net bank debt-to-twelve months trailing funds from operations ratio of
1.01.
The Trust maintains a $300 million fully secured, extendible, revolving
credit facility. The credit facility revolves until April 26, 2007, at which
time it is extendible for a further 364-day revolving period upon agreement
between the Trust and the bank syndicate. The facility consists of a $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. The purpose of the facility is to fund
property acquisitions and capital expenditures. Principal repayments to the
bank are not required at this time. Should principal repayments become
mandatory, and in the absence of refinancing arrangements, the Trust would be
required to repay the facility in four equal quarterly installments commencing
April 2008.
Total bank debt amounted to $220.8 million at December 31, 2006 compared
with $220.5 million as at December 31, 2005. Of the debt outstanding at
December 31, 2006, $219.0 million was outstanding under the production
facility and $1.8 million under the working capital facility.
Year-End Capitalization
-------------------------------------------------------------------------
2006 2005
-------------------------------------------------------------------------
Trust unit equity ($000s) 456,500 494,490
Bank debt ($000s) 220,785 220,519
Net bank debt ($000s)(1) 223,061 198,351
Net bank debt-to-equity 0.49 0.40
Net bank debt-to-trailing 12 months funds
from operations 1.01 0.89
Units outstanding (000s) 77,971 73,977
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
The Trust anticipates that, subject to fluctuations in commodity prices,
it will continue to have adequate liquidity to fund planned capital spending
during 2007 through a combination of funds from operations, funds received
from its distribution reinvestment program and bank borrowings.
ASSET RETIREMENT OBLIGATION
At December 31, 2006, the Trust reported an Asset Retirement Obligation
("ARO") balance of $65.6 million ($61.9 million at December 31, 2005) for
future abandonment and reclamation of the Trust's oil and gas properties and
facilities. The ARO balance was increased by accretion expense of $5.0 million
and liabilities incurred of $3.1 million in 2006 ($4.6 million and $23.4
million, respectively, in 2005) and reduced by $4.4 million for actual
abandonment and environmental expenditures in 2006 ($3.0 million in 2005). The
liabilities incurred in 2005 were primarily due to the liability associated
with the additional properties acquired with the acquisition of Addison Energy
Inc.
DISTRIBUTIONS TO UNITHOLDERS
The Trust sets distributions based upon commodity prices, financial market
conditions, internal capital investment opportunities and the resulting impact
on taxability and payout ratios. The Trust develops an annual forecast, which
is updated regularly by management. The Board sets distributions at a level it
believes will be sustainable for a period of time and formally reviews
distribution levels quarterly.
In November 2006, as a result of lower commodity prices, the Board of
Directors decided to reduce monthly distributions from $0.19 to $0.16 per
unit, reversing the $0.03 per unit distribution increase introduced in October
2005 in response to higher commodity prices. This reduced rate was implemented
effective with the distribution paid in December 2006. This reduction allows
the Trust to retain an incremental $2.3 million per month or $27.7 million on
an annual basis.
The lower distribution will allow the Trust to maintain an effective
capital expenditure budget and create additional tax pools for the Trust. This
action will also lower the payout ratio and retain the Trust's very
competitive debt level to position it to take advantage of opportunities to
add assets in the future.
For the three months ended December 31, 2006, funds from operations
amounted to $55.8 million compared with $65.8 million for the three months
ended December 31, 2005. NAL declared cash distributions of $39.7 million
($0.51 per unit) in the fourth quarter of 2006 as compared to $42.0 million
($0.57 per unit) in the fourth quarter of 2005. This represented a 71 percent
payout ratio in 2006, compared with the 64 percent payout ratio in the
comparable quarter in 2005. The payout ratio in the fourth quarter of 2006
decreased from the 81 percent experienced in the third quarter due to the
lower distribution rate in the fourth quarter.
The weighted average number of units outstanding during the fourth quarter
of 2006 increased by six percent to 77.7 million from 73.4 million in 2005.
For the year ended December 31, 2006 funds from operations were $219.8
million compared with $221.6 million for the comparable period in 2005. NAL
declared cash distributions of $169.6 million ($2.22 per unit) in this period
as compared to $142.1 million ($2.01 per unit) in 2005. This represented a 77
percent payout ratio for fiscal 2006 compared to 64 percent in 2005.
Distributions
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Funds from operations ($000s) 55,795 65,837 219,776 221,649
Distributions declared ($000s) 39,663 41,956 169,589 142,050
Funds from operations
per unit(1) 0.72 $0.90 2.88 $3.17
Distributions declared per unit 0.51 $0.57 2.22 $2.01
Weighted average units
outstanding ($000s) 77,697 73,436 76,350 69,946
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding.
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
NAL has entered into several contractual obligations as part of conducting
day-to-day business. NAL has the following commitments for the next five
years:
-------------------------------------------------------------------------
($000s) 2007 2008 2009 2010 2011
-------------------------------------------------------------------------
Office lease(1) 2,734 2,580 2,580 2,365
Transportation agreement 716 716 80 - -
Processing agreement(2) 491 469 446 428 414
Drilling rigs(3) 1,975 494 - - -
Retention bonus(4) 938 938 - - -
-------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager, of which the Trust is
allocated a pro rata share (currently approximately 53 percent) of
the expense on a monthly basis.
(2) Represents a gas processing agreement with a take or pay arrangement.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.
QUARTERLY INFORMATION
-------------------------------------------------------------------------
2006
-------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenue, net of royalties 75,694 75,798 77,988 81,272
Per unit 0.97 0.98 1.03 1.08
Funds from operations(1) 55,795 54,107 52,210 57,664
Per unit 0.72 0.70 0.69 0.77
Net income (loss)(2) 20,472 20,473 (5,357) 24,610
Per unit 0.26 0.27 (0.07) 0.33
Average oil equivalent
production (boe/d - 6:1) 19,517 19,079 19,012 20,181
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2005
-------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenue, net of royalties 95,643 85,613 71,482 61,268
Per unit 1.30 1.18 1.00 0.98
Funds from operations(1) 65,837 62,442 49,881 43,489
Per unit 0.90 0.86 0.70 0.69
Net income (loss) 30,777 31,710 20,804 15,247
Per unit 0.42 0.44 0.29 0.24
Average oil equivalent
production (boe/d - 6:1) 20,514 19,710 18,349 17,457
-------------------------------------------------------------------------
(1) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
(2) Includes non-cash management restructuring fee of $27.2 million in
Q2.
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (audited)
----------------------------
As at As at
December 31, December 31,
2006 2005
----------------------------
Assets
Current assets
Cash and cash equivalents $6,295 $1,124
Accounts receivable and other 44,467 79,010
-------------------------------------------------------------------------
50,762 80,134
Reclamation reserve (Note 5) - 3,898
Future income tax asset (Note 11) 3,345 2,136
Property, plant and equipment, net (Note 6) 742,795 748,715
-------------------------------------------------------------------------
$796,902 $834,883
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and
Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $40,563 $43,910
Distributions payable to unitholders 12,475 14,056
-------------------------------------------------------------------------
53,038 57,966
Bank debt (Note 8) 220,785 220,519
Unit-based incentive compensation (Note 9) 1,005 -
Asset retirement obligations (Note 7) 65,574 61,908
-------------------------------------------------------------------------
340,402 340,393
Unitholders' equity (Note 10)
Unitholders' capital 824,986 753,585
Deficit (368,486) (259,095)
-------------------------------------------------------------------------
456,500 494,490
-------------------------------------------------------------------------
$796,902 $834,883
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (Note 13)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Units outstanding (000s) 77,971 73,977
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005
------------------------------------------
Revenue
Oil, natural gas and liquids
sales(1) $91,792 $119,995 $388,999 $395,147
Royalty and other income 2,160 1,896 5,085 6,047
Crown royalties, net of ARTC (13,156) (20,099) (61,570) (65,167)
Freehold and other royalties (5,102) (6,149) (21,762) (22,021)
-------------------------------------------------------------------------
75,694 95,643 310,752 314,006
-------------------------------------------------------------------------
Expenses
Operating 12,796 17,767 58,964 55,682
Transportation costs 620 787 2,547 2,903
General and administrative 2,395 3,049 10,946 9,295
Unit-based incentive
compensation (Note 9) (131) 628 2,495 1,415
Management fees (Note 3) - 4,284 1,350 9,958
Restructuring fee (Note 3) - - 27,299 -
Interest on bank debt 2,759 2,651 9,963 10,372
Depletion, depreciation and
amortization 35,725 33,608 133,079 118,961
Accretion on asset retirement
obligations 1,258 1,197 4,984 4,582
-------------------------------------------------------------------------
55,422 63,971 251,627 213,168
-------------------------------------------------------------------------
Income before taxes 20,272 31,672 59,125 100,838
-------------------------------------------------------------------------
Income and capital taxes
(provision) recovery (62) 340 (136) 240
Future income tax recovery
(provision) 262 (1,235) 1,209 (2,540)
-------------------------------------------------------------------------
Total income and capital taxes
(Note 11) 200 (895) 1,073 (2,300)
-------------------------------------------------------------------------
Net income 20,472 30,777 60,198 98,538
Deficit, beginning of period (349,295) (247,915) (259,095) (215,583)
Distributions declared
(Note 10) (39,663) (41,957) (169,589) (142,050)
-------------------------------------------------------------------------
Deficit, end of period $(368,486) $(259,095) $(368,486) $(259,095)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust unit $0.26 $0.42 $0.79 $1.41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average units
outstanding (000s) 77,697 73,436 76,350 69,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) After hedging.
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
------------------------------------------
Three Months Ended Year Ended
December 31 December 31
------------------------------------------
2006 2005 2006 2005
------------------------------------------
Operating Activities
Net income $20,472 $30,777 $60,198 $98,538
Items not involving cash:
Depletion, depreciation and
amortization 35,725 33,608 133,079 118,961
Accretion on asset retirement
obligations 1,258 1,197 4,984 4,582
Future income tax provision
(recovery) (262) 1,235 (1,209) 2,540
Restructuring fee - - 27,159 -
Abandonment and environmental
expenditures (1,398) (980) (4,435) (2,972)
Decrease (increase) in non-cash
working capital (7,117) 6,626 18,669 (26,364)
-------------------------------------------------------------------------
48,678 72,463 238,445 195,285
-------------------------------------------------------------------------
Financing Activities
Distributions paid to
unitholders (41,899) (39,557) (171,170) (136,484)
Issue of Trust units, net of
issue costs 7,874 17,690 41,401 276,964
Increase (decrease) in bank
debt 12,592 (18,281) 266 126,819
Decrease (increase) in non-cash
working capital 186 (3,133) 2,241 (3,133)
-------------------------------------------------------------------------
(21,247) (43,281) (127,262) 264,166
-------------------------------------------------------------------------
Investing Activities
Acquisition of Addison Energy
Inc. - - - (387,215)
Additions to property, plant
and equipment (34,788) (25,514) (121,201) (73,099)
Reclamation reserve 4,294 (138) 3,898 (464)
Decrease (increase) in
non-cash working capital 2,169 (6,282) 11,291 1,340
-------------------------------------------------------------------------
(28,325) (31,934) (106,012) (459,438)
-------------------------------------------------------------------------
Increase (decrease) in cash (894) (2,752) 5,171 13
Cash and cash equivalents,
beginning of period 7,189 3,876 1,124 1,111
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $6,295 $1,124 $6,295 $1,124
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid during the period
for:
Interest $2,726 $2,621 $9,816 $10,287
Taxes (recovery) $62 $(340) $136 $(240)
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Year ended December 31, 2006
(Tabular amounts in thousands of dollars, except per unit
amounts)
The financial results for the three months ended December 31, 2006 have
not been separately reviewed by the external auditors.
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 is a wholly-owned subsidiary of Manulife
Financial Corporation ("MFC") and manages, on their behalf, NAL
Resources Limited ("NAL Resources"), another wholly-owned subsidiary
of MFC. NAL Resources and the Trust maintain ownership interests in
many of the same oil and natural gas properties in which NAL
Resources is the operator. As a result, a significant portion of the
net operating revenues and capital expenditures represent joint
operations amounts from NAL Resources. These transactions are in the
normal course of joint operations and are based on the original
transactions with third parties.
Effective May 31, 2006 the terms of the management contract were
restructured, resulting in the elimination of management fees and
performance fees while retaining the recovery of the general and
administrative costs incurred on behalf of the Trust, see Note 3.
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 amounts
recorded for unit-based compensation are based on estimates of unit
price and performance factors. 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 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
unitholders 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.
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.
Joint Operations
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.
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 the purchaser.
Unit-Based Incentive Compensation
The Manager has established a unit-based incentive compensation plan
(the "Plan") for all employees. Under the Plan, employees receive
cash compensation based upon the value and overall return of a
specified number of awarded notional Trust units on a fixed vesting
date. The notional unit grants are in the form of Restricted Trust
Units ("RTU's") and Performance Trust Units ("PTU's"). Distributions
paid on the Trust's outstanding units during the vesting period are
assumed to be reinvested in the awarded notional units on the date of
distribution. The compensation incorporates the Trust unit price and
the number of RTU's and PTU's outstanding at each period end. In
addition, for the PTU's, there is a performance multiplier which is
based on the Trust's performance relative to its peers and may range
from zero to two times the value of the notional units held at
vesting.
RTU's vest one third on November 30 in each of three years after
grant date. PTU's vest at the end of three years. Compensation
expense is recognized over the vesting period and is determined based
on the intrinsic value of the notional units at each period end and
an expected performance multiplier with a corresponding increase or
decrease in liabilities. Classification between accrued liabilities
and other long-term liabilities is dependent on the expected payout
date.
The Trust charges the accrued compensation amounts relating to head
office employees to general and administrative expenses, the amounts
relating to field staff to operating costs, and the amounts relating
to exploitation and development personnel to property, plant and
equipment.
The Trust has not incorporated an estimated forfeiture rate for
performance units that will not vest and accounts for actual
forfeitures as they occur.
Comparative Figures
Certain comparative figures have been reclassified to conform to
current period presentation.
3. RELATED PARTY TRANSACTIONS
The Manager provides certain services pursuant to the Management
Contract for which, prior to January 1, 2006, the Trust was required
to pay a monthly base management fee equal to three percent of its
net production revenue and a quarterly performance fee based on the
Trust's overall return compared to the S&P/TSX Capped Energy Trust
Index. Such fees amounted to $9,958,000 for the year ended
December 31, 2005.
On May 31, 2006 the Trust's unitholders approved the restructuring of
the Management Contract with the Manager. Under the restructuring,
the Trust agreed to pay a one-time $30 million restructuring fee in
exchange for the elimination of any further base and performance
management fees payable by the Trust and the acquisition of a 50
percent ownership in the Manager's administrative capital assets,
effective January 1, 2006. In payment of the Restructuring Fee, the
Trust issued, to an affiliate of the Manager. 1,592,357 units of the
Trust at a price of $18.84 per unit. The subscription price was based
on the weighted average trading price of the Trust units over the
five consecutive trading days ending on the third trading day
preceding March 1, 2006, the date of the agreement.
Of the $30 million Restructuring Fee, $2.8 million has been allocated
to the administrative assets acquired and capitalized as Property,
Plant and Equipment. The balance of $27.2 million, representing the
elimination of future management and performance fees, has been
recorded as a non-cash charge to income. During 2006, the Trust paid
an interim management fee of $1,350,000 up to the closing of the
restructuring transaction on May 31, 2006.
In addition, the Trust paid $6.6 million (2005 - $7.0 million) for
the reimbursement of G&A expenses incurred by the Manager on behalf
of the Trust pursuant to the Management Contract. The Trust also pays
the Manager its share of unit-based incentive compensation expense
when cash compensation is paid to employees under the terms of the
Plan (2006 - $2.2 million; 2005 - $2.1 million).
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:
---------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------
Due (to) from NAL Resources Limited $1,478 $14,326
Due to NAL Resources Management Limited $(3,718) $(4,598)
---------------------------------------------------------------------
4. 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.
5. RECLAMATION RESERVE
During 2006 certain amendments were made to a royalty agreement
involving the business of the Trust, which had provided for the
establishment of a reserve ("Reclamation Reserve") to assist in
funding future asset retirement obligations. Under the terms of the
amended royalty agreement, the requirement for the Reclamation
Reserve has been eliminated and, accordingly, the funds in the
reserve have been transferred to the general working capital of the
Trust. The Trust continues to pay ongoing abandonment and reclamation
expenditures from its cash flow from operating activities.
6. PROPERTY, PLANT AND EQUIPMENT ("PP&E")
---------------------------------------------------------------------
Net book value as at December 31: 2006 2005
---------------------------------------------------------------------
Oil and natural gas properties, at cost $1,293,854 $1,166,695
Less: Accumulated depletion and
depreciation (551,059) (417,980)
---------------------------------------------------------------------
$742,795 $748,715
---------------------------------------------------------------------
---------------------------------------------------------------------
During 2006, the Trust capitalized $4.3 million (2005 - $4.5 million)
of general and administrative costs and $1.7 million of unit-based
incentive compensation expense (2005 - $0.7 million) that were
directly related to exploitation and development programs.
No property costs have been excluded from the depletion and
depreciation calculation.
The Trust performed a ceiling test calculation at December 31, 2006
in accordance with CICA AcG16 to assess the recoverable value of
property, plant and equipment. The oil and gas future prices are
based on the January 1, 2007 commodity price forecast of our
independent reserve evaluators, adjusted for commodity differentials
specific to the Trust. The following table summarizes the benchmark
prices used in the ceiling test calculation. Based on these
assumptions, the undiscounted value of future net reserves from the
Trust's proved reserves exceeded the carrying value of property,
plant and equipment as at December 31, 2006.
US$/Cdn$
WTI Oil Exchange WTI Oil AECO Gas
Year (US$/bbl) Rate (Cdn$/bbl) (Cdn$/GJ)
---------------------------------------------------------------------
2007 62.50 0.870 71.84 6.85
2008 61.20 0.870 70.34 7.05
2009 59.80 0.870 68.74 7.40
2010 58.40 0.870 67.13 7.50
2011 56.80 0.870 65.29 7.70
---------------------------------------------------------------------
Remainder(1) 2% 0.870 2% 2%
1) Percentage change represents the change in each year after 2011 to
the end of the reserve life.
7. 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 $65.6 million
as at December 31, 2006 based on a total undiscounted amount of cash
flows required to settle its asset retirement obligations of
$165.2 million (2005 - $161.8 million). These costs are expected to
be made over the next 46 years with the majority of the costs
incurred between 2007 and 2033. NAL's credit-adjusted risk-free rate
of 8 percent (2005 - 8 percent) and an inflation rate of 2.0 percent
(2005 - 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.
---------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------
Balance, beginning of year $61,908 $36,924
Accretion expense 4,984 4,582
Liabilities incurred 3,117 23,374
Liabilities settled (4,435) (2,972)
---------------------------------------------------------------------
Balance, end of year $65,574 $61,908
---------------------------------------------------------------------
---------------------------------------------------------------------
8. BANK DEBT
---------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------
Production loan facility $219,000 $219,000
Working capital facility 1,785 1,519
---------------------------------------------------------------------
Total debt outstanding $220,785 $220,519
Current portion of debt - -
---------------------------------------------------------------------
Long-term debt $220,785 $220,519
---------------------------------------------------------------------
---------------------------------------------------------------------
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. The facility
was renewed in April 2006 and will revolve until April 26, 2007 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 2007, 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 2008 with a final residual payment, if any, in April
2009.
The Trust is restricted, under the credit facility, from making
distributions to its unitholders in excess of its consolidated
operating cash flow during the eighteen-month period preceding the
distribution date.
Amounts are advanced under the credit facility in Canadian dollars by
way of prime interest rate based loans and by issues of bankers'
acceptances and in U.S. dollars by way of U.S. based interest rate
and Libor based loans. The interest charged on advances is at the
prevailing interest rate for bankers' acceptances, Libor loans,
lenders' prime or U.S. base rates plus an applicable margin or
stamping fee. The applicable margin or stamping fee, if any, varies
based on the consolidated debt-to-cash flow ratio of the Trust.
On December 31, 2006 the effective interest rate on amounts
outstanding under the credit facility was 5.18 percent.
9. UNIT-BASED INCENTIVE COMPENSATION PLAN
In January 2006, the Board of Directors approved a revised unit-based
incentive plan (the "Plan") for all employees of the Manager. Under
the Plan, employees receive cash compensation based upon the value
and overall return of a specified number of awarded notional Trust
units.
The first payment under the previous plan was made in December 2005,
the charge for which was accrued throughout the year and of which
$1,415,000 was charged to income and $651,000 was capitalized in
2005. With the expansion of the Plan and the introduction of the
annual vesting provision of the awarded notional units in 2006, the
Trust has commenced to record its share of the value associated with
the notional units in its accounts over the vesting period.
During 2006, the Trust has accrued $4.2 million of unit-based
incentive compensation charges in its accounts, of which,
$2.5 million has been charged to income and $1.7 million has been
capitalized. Of the $4.2 million, $2.2 million was paid in January
2007 and $1.0 million is expected to be paid in December 2007. The
balance represents the long-term portion of the Trust's estimated
liability for the unit-based incentive plan as at December 31, 2006.
This amount is payable in December 2007 and 2008.
10. UNITHOLDERS' EQUITY
Unitholders' Equity
The Trust is authorized to issue 500 million Trust units of which
78 million units were issued and outstanding as at December 31, 2006
(December 31, 2005 - 74 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:
---------------------------------------------------------------------
2006 2005
-----------------------------------------
Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning of the
year 73,977 $753,585 53,064 $476,620
Issued under management
agreement restructuring
(Note 3) 1,592 30,000 - -
Issued for cash - - 17,000 232,900
Less issue expenses - (29) - (12,333)
Issued from Distribution
Reinvestment Plan 2,402 41,430 3,913 56,398
---------------------------------------------------------------------
Balance, end of the year 77,971 $824,986 73,977 $753,585
---------------------------------------------------------------------
---------------------------------------------------------------------
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, 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
2006 distributions 169,589 - 169,589
---------------------------------------------------------------------
Accumulated distributions
at December 31, 2006 $506,882 $195,598 $702,480
---------------------------------------------------------------------
---------------------------------------------------------------------
Deficit
The deficit is comprised of the following:
---------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------
Accumulated income $333,994 $273,796
Accumulated cash distributions (702,480) (532,891)
---------------------------------------------------------------------
Deficit, end of year $(368,486) $(259,095)
---------------------------------------------------------------------
---------------------------------------------------------------------
During 2006 presentation changes were made to combine the previously
reported accumulated income and accumulated cash distributions
figures on the balance sheet into a single deficit figure. The Trust
has historically paid cash distributions in excess of accumulated
income as cash distributions are based on cash flow generated in the
period whereas accumulated earnings are based on net income which
includes non-cash items such as depletion and depreciation,
unit-based compensation charges and future income tax provisions.
11. 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:
---------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------
Income before taxes $59,125 $100,838
Statutory income tax rate 39.0% 39.0%
---------------------------------------------------------------------
Expected income tax expense 23,059 39,327
Increase (decrease) resulting from:
Non-deductible Crown charges 8,471 16,657
Resource allowance (9,208) (17,260)
Alberta Royalty Tax Credit (39) (127)
Valuation allowance 200 459
Net income of the Trust (24,937) (37,019)
Other 1,045 503
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Current and future income tax expense (recovery) (1,409) 2,540
Capital taxes (recovery) 336 (240)
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Income and capital taxes (recovery) (1,073) 2,300
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The future income tax asset is comprised of:
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2006 2005
---------------------------------------------------------------------
Property, plant and equipment $6,794 $1,536
Future tax liability resulting from different
year ends - 532
Non-capital tax loss carry forward (3,197) (2,440)
Asset retirement obligation (7,889) (7,452)
Other (400) -
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(4,692) (7,824)
Valuation allowance 1,347 5,688
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Future income tax asset $(3,345) $(2,136)
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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, 2006, the book amounts of the Trust's assets and
liabilities exceed the tax basis by $192.2 million
(2005 - $319.3 million).
On December 21, 2006, the Minister of Finance released for comment
draft legislation concerning the taxation of certain publicly traded
trusts. The legislation reflects proposals originally announced by
the Minister on October 31, 2006. Under the proposed legislation,
distributions to unitholders will not be deductible by publicly
traded income trusts and, as a result, the Trust will be taxed on its
income similar to corporations. The proposed rules, if passed into
law, would be applicable commencing in 2011. However, if the proposed
legislation is implemented, the Trust would be required to recognize
in its accounts, in the period in which the change is substantially
enacted, future income taxes on temporary differences in the Trust.
12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Fair Values
The carrying value of the Trust's financial instruments, including
accounts receivable, bank 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, 2006 the Trust had entered into the following
derivatives to protect its 2007 cash flow from the volatility of oil
and natural gas commodity prices.
For 2007, NAL has the following WTI oil contracts in place:
-------------------------------------------------------------------------
Total Bought
Volume Volume Put Sold Call Swap
------ ------ ------ --------- ----
Days Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
COLLARS
181 2-way 300 54,300 70.00 85.85 -
181 2-way 300 54,300 72.00 88.10 -
365 2-way 500 182,500 62.00 68.25 -
365 2-way 200 73,000 64.00 71.00 -
184(1) 2-way 300 55,200 62.00 69.75 -
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Weighted
average Collars 1,148 419,300 64.68 73.78 -
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SWAPS
-------------------------------------------------------------------------
365 Swap 500 182,500 - - 65.05
365 Swap 500 182,500 - - 72.33
184(1) Swap 300 55,200 - - 61.07
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Weighted
average Swaps 1,150 420,200 - - 67.70
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For 2007, NAL has the following AECO natural gas contracts in place
-------------------------------------------------------------------------
Total Bought
Volume Volume Put Sold Call Swap
------ ------ ------- --------- ----
Days Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
-------------------------------------------------------------------------
COLLARS
365 2-way 3,000 1,095,000 6.00 8.10 -
365 2-way 1,000 365,000 6.50 8.85 -
365 2-way 1,000 365,000 7.00 8.70 -
365 2-way 1,000 365,000 6.75 8.60 -
365 2-way 2,000 730,000 7.00 8.70 -
365 2-way 1,000 365,000 7.25 8.51 -
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Weighted
average Collars 9,000 3,285,000 6.61 8.48 -
-------------------------------------------------------------------------
SWAPS
-------------------------------------------------------------------------
365 Swap 3,000 1,095,000 - - 6.77
365 Swap 1,000 365,000 - - 7.90
334(1) Swap 1,500 501,000 - - 7.20
306(1) Swap 1,500 459,000 - - 7.43
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Weighted
average Swaps 6,630 2,420,000 - - 7.15
-------------------------------------------------------------------------
(1) Entered into subsequent to year-end.
The estimated fair value of the above contracts excluding the
contracts entered into subsequent to year-end, all of which qualify
for hedge accounting, was a gain of $4,500,000 as at December 31,
2006. The fair value of these instruments is not recorded on the
Balance Sheet.
13. COMMITMENTS
At December 31, 2006 the Trust had the following contractual
obligations and commitments:
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($000s) 2007 2008 2009 2010 2011
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Office lease(1) 2,734 2,580 2,580 2,365 -
Transportation
agreement 716 716 80 - -
Processing
agreement(2) 491 469 446 428 414
Drilling rigs(3) 1,975 494 - - -
Retention bonus(4) 938 938 - - -
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(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager of which the Trust is
allocated a pro rata share (currently approximately 53 percent) of
the expense on a monthly basis.
(2) Represents gas processing agreement under take or pay arrangement.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
(4) Represents the Trust's share of expected future payments under a
staff retention program.
TRADING PERFORMANCE
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For the Quarter Ended
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31-Dec-06 30-Sep-06 31-Dec-05 30-Sep-05
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PRICE
-------------------------------------------------------------------------
High $18.74 $21.70 $19.15 $17.80
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Low $11.80 $16.14 $13.39 $14.31
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Close $12.31 $17.57 $18.08 $15.95
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Volume 27,691,472 12,786,792 16,922,700 18,992,928
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Full Year
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2006 2005
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PRICE
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High $21.70 $19.15
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Low $11.80 $12.82
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Close $12.31 $18.08
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Volume 65,412,678 72,097,477
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NAL Oil & Gas Trust is an open-end investment trust that generates
distributions through the acquisition, development, production and marketing
of oil, natural gas and natural gas liquids. The Trust owns high quality
assets in Alberta, Saskatchewan and Ontario. Trust units trade on the Toronto
Stock Exchange under the symbol "NAE.UN".
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: (888) 223-8792
Fax: (403) 515-3407
Email: Investor.Relations@nal.ca [2]
Website: www.nal.ca [3]
Links:
[1] http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=
[2] mailto:Investor.Relations@nal.ca
[3] http://www.nal.ca