CALGARY--(CCNMatthews - May 3) - NAL Oil
& Gas Trust (TSX:NAE.UN) (the "Trust" or "NAL") today announced its
financial and operational results for the first quarter ended March 31,
2006. All amounts are in Canadian dollars unless otherwise stated.
FIRST QUARTER HIGHLIGHTS
- NAL continued to deliver volume performance in Q1, 2006 with daily
production averaging 20,181 boe per day for the quarter, an increase
of 16 percent over the 17,457 boe per day in the same period of 2005.
- Capital expenditures of $20 million in the first quarter of 2006 were
in line with the budget as NAL accessed equipment and services and
executed its exploitation and development program as planned.
- Higher oil and gas prices realized by NAL in Q1, 2006 resulted in
average oil equivalent pricing increasing to $56.26 per boe
compared to $48.86 a year earlier. Production mix remained relatively
balanced at 57 percent crude oil and natural gas liquids and 43
percent natural gas.
- Funds from operations increased to $59.5 million ($0.80 per unit) in
the first quarter, 2006 compared to $43.9 million ($0.70 per unit) a
year earlier. This increase was largely driven by higher production
volumes and commodity prices. Distributions for the quarter increased
from $0.48 to $0.57 per unit and the payout ratio was consistent at 72
percent.
- NAL's strong operating netbacks continued at $35.71 per boe versus
$31.23 in the first quarter of 2005.
- Net debt continued to decline to $181.4 million at the end of first
quarter, 2006 compared with $249.7 million at the end of Q1, 2005 and
$198.4 million at year-end 2005. The Trust's net debt to cash flow
ratio continued to trend lower at 0.76 times trailing twelve months'
funds from operations. These lower debt levels allowed the Trust to
suspend its Premium DRIP program effective with the April, 2006
distribution.
- During the first quarter of 2005, the Trust restructured its
Management Contract with NAL Resources Management Limited, subject to
approval by the unitholders at the Annual and Special Meeting on May
31, 2006. Assuming approval of the new management agreement, the Trust
will have a long-term contract where base and performance fees will be
eliminated, governance will be enhanced and the Trust will have the
flexibility to terminate the Agreement on 90-days' notice to
facilitate future transactions. In exchange for these benefits, the
Trust will pay a one-time $30 million restructuring fee through the
issuance of 1,592,357 units at $18.84 per unit.
- Coincident with the restructuring of the Management Contract, NAL
announced new incentive plans which are more aligned with investor
performance measures and increased eligibility to all staff.
- As to NAL's outlook for 2006, plans remain on track and guidance
remains unchanged from levels previously announced on January 18,
2006. As budgeted, production is forecast to decline in Q2, 2006 due
to turnarounds and lower activity and will increase in Q3 and Q4 with
higher capital spending. The Trust's annual capital expenditure budget
remains at $95 million with spending increasing as we move through
2006 with Q3 and Q4 being the most active quarters.
- At 9:00 a.m. MDT on Wednesday, May 3, 2006 NAL will conduct a
conference call to discuss its first quarter results. Mr. Andrew
Wiswell, President and CEO, will host the conference call with other
members of the Management Team. The call is open to analysts,
investors, and all interested parties. If you wish to participate,
call 1-800-814-4857. Those who are unable to listen to the call live
may listen to a recording of it by calling 1-877-289-8525, reservation
No. 21185056. The recording will be available until May 10, 2006.
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NAL Oil & Gas Trust will hold its Annual and Special Meeting of
Unitholders on Wednesday, May 31, 2006 at 9:30 a.m. MDT in the
Metropolitan Ballroom of The Metropolitan Conference Centre,
333 - 4 Avenue SW, Calgary, Alberta.
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When converting natural gas to equivalent barrels of oil within this
report, NAL uses the widely recognized standard of 6 thousand cubic
feet (Mcf) to one barrel of oil (boe). However, boes 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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Quarter Quarter Quarter
Ended Ended Ended
March 31, March 31, December
2006 2005 31, 2005
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FINANCIAL
Gross revenue, net of royalties $80,604 $60,617 $94,856
Net income 24,610 15,247 30,777
Funds from operations 59,502 43,879 65,837
Distributions declared 42,597 31,027 41,956
Funds from operations per unit 0.80 0.70 0.90
Distributions declared per unit 0.57 0.48 0.57
Payout ratio 72% 71% 64%
Average number of units outstanding (000s) 74,544 62,671 73,436
Total assets $791,327 $830,463 $813,954
Bank debt, net of working capital 181,443 249,740 198,351
Unitholders' equity 497,310 472,759 494,490
Costs per boe (6:1): Operating $7.84 $6.67 $9.41
General and
administrative 1.36 1.26 1.62
Management fees 0.41 0.99 2.27
OPERATING
Daily production Oil (bbl) 9,552 9,206 9,755
Natural gas (Mcf) 51,937 41,575 52,340
Natural gas liquids
(bbl) 1,973 1,322 2,036
Oil equivalent
(boe - 6:1) 20,181 17,457 20,514
Average pricing, net of transportation
charges and hedging
Liquids:
WTI (US$/bbl) 63.48 49.90 60.02
NAL average oil (Cdn$/bbl) 61.00 55.59 59.53
NAL natural gas liquids (Cdn$/bbl) 52.53 40.29 56.29
Natural gas:
AECO (Cdn$/Mcf) - daily spot 7.59 6.69 11.43
AECO (Cdn$/Mcf) - monthly 9.28 6.71 11.86
NAL natural gas Western Canada
(Cdn$/Mcf) 8.59 6.76 11.20
NAL natural gas Lake Erie (Cdn$/Mcf) 9.40 8.50 14.36
NAL average natural gas (Cdn$/Mcf) 8.65 6.93 11.47
NAL oil equivalent (Cdn$/boe - 6:1) 56.26 48.86 63.16
Average foreign exchange rate (Cdn$/US$) 1.155 1.227 1.173
Operating netback before hedging gains
(losses) ($/boe) 35.57 31.23 42.21
Hedging gains (losses) per boe 0.14 - (2.37)
Operating netback ($/boe) 35.71 31.23 39.84
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MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in
conjunction with the Interim Consolidated Financial Statements for the
three months ended March 31, 2006 and the audited consolidated financial
statements and MD&A for the year ended December 31, 2005 of NAL Oil
& Gas Trust ("NAL" or the "Trust"). It also contains information
and opinions on the Trust's future outlook based on currently available
information. All amounts are reported in Canadian dollars, unless
otherwise stated. Where applicable, natural gas has been converted to
barrels of oil equivalent ("boe") based on a ratio of six thousand cubic
feet of natural gas to one barrel of oil. The boe rate is based on an
energy equivalent conversion method primarily applicable at the burner
tip and does not represent a value equivalent at the wellhead. Use of
boe in isolation may be misleading.
Operating netbacks and funds from operations are not recognized
measures under Canadian generally accepted accounting principles
("GAAP"). Management believes that in addition to net income, operating
netbacks, funds from operations and funds from operations per unit are
useful supplemental measures as they provide an indication of the
results generated by the Trust's principal business activities prior to
the consideration of how those activities are financed or how the
results are taxed. Investors should be cautioned, however, that these
measures should not be construed as an alternative to net income
determined in accordance with GAAP as an indication of NAL's
performance. NAL's method of calculating these measures may differ from
other income funds and companies and, accordingly, they may not be
comparable to measures used by other income funds and companies. NAL
calculates funds from operations prior to the change in non-cash working
capital related to operating activities, with the per unit amount
calculated using the weighted average units outstanding for the period.
FORWARD-LOOKING INFORMATION
This disclosure contains certain forward-looking statements that
involve substantial known and unknown risks and uncertainties, many of
which are beyond NAL's control, including: the impact of general
economic conditions in Canada and in the United States, industry
conditions, changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced, increased competition, the lack of
availability of qualified operating or management personnel,
fluctuations in commodity prices, foreign exchange or interest rates,
stock market volatility and fluctuations in market valuations of
companies with respect to announced transactions and the final
valuations thereof, and the ability to obtain required approvals from
regulatory authorities. NAL's actual results, performance or achievement
could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurances can be given
that any of the events anticipated by the forward-looking statements
will transpire or occur, or if any of them do so, what benefits,
including the amount of proceeds, that NAL will derive therefrom.
DEVELOPMENT ACTIVITIES
The Trust implemented its development plan as anticipated during the
first quarter and experienced few difficulties sourcing service
equipment and crews. Development was primarily focused in the Southeast
Saskatchewan core area where two operated drilling rigs were active.
Production during the quarter was in line with expectations at 20,181
boe/d.
The Trust participated in the drilling of 25 (6.8 net) wells during
the first quarter with a success rate of 100 percent. The majority of
this activity occurred in our Southeast Saskatchewan core area.
First Quarter Drilling Activity
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Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
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Gross Net Gross Net Gross Net Gross Net Gross Net
Operated wells 12 5.62 3 0.48 0 0.00 0 0.00 15 6.10
Non-operated wells 8 0.26 2 0.48 0 0.00 0 0.00 10 0.74
Total wells drilled 20 5.88 5 0.96 0 0.00 0 0.00 25 6.84
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Southeast Saskatchewan Core Area
--------------------------------
With two rigs running over the winter, development of the Trust's
oil assets in southeastern Saskatchewan continued during the quarter by
investing approximately $11 million to drill a total of 20 (5.8 net) oil
wells and upgrading production facilities.
During the quarter, three (1.3 net) horizontal wells were drilled at
Browning of which two (1.0 net) are producing at a net rate of 140
boe/d. At Steelman, four (1.90 net) horizontal wells were drilled and
tied in during the quarter, producing 140 boe/d net. At Huntoon, three
(1.4 net) horizontal wells were drilled but seasonal road bans delayed
completion activities on two (1.0 net) of these wells. One operated well
was drilled at each of Midale, Elswick, and Nottingham (1.33 net)
during the first quarter. Net production from these wells totals 70
boe/d. At Star Valley, one (0.5 net) well drilled the previous quarter
was tied-in and is producing 45 boe/d net to the Trust.
After break-up, the Trust will continue with the active development
of our high quality Southeast Saskatchewan oil assets. We will have two
drilling rigs running the majority of the year and expect to drill eight
(3.5 net) wells during the second quarter.
Gas Focus Core Area
-------------------
NAL's Gas Focus area is comprised of a majority of the Trust's
properties that exist outside NAL's two geographic core areas -
Southeast Saskatchewan and Central Alberta - and includes Nevis/Lacombe,
Brent/Hanna, Pine Creek, Surmount/Hangingstone and Lake Erie. Although
geographically diverse, these properties are strategically characterized
by a focused land position, a high proportion of current production and
future potential concentrated on natural gas.
Consistent with the Trust's plans, minimal drilling activity
occurred in these areas during the quarter with two (0.5 net)
non-operated gas wells being drilled. However, the Trust is actively
planning upcoming development projects at Hanna, Clive/Lacombe, and Lake
Erie.
At Hanna, a 20 (15 net) well development program targeting gas from
the Second White Specks is anticipated to start at the end of the second
quarter with production commencing during the fourth quarter. Also at
Hanna, a 46-square kilometer (18-square mile) 3D seismic program
is planned for the second quarter.
At Clive/Lacombe, a 32 (20 net) well program targeting gas from the
Horseshoe Canyon coals is underway. Facilities for this project have
been ordered and drilling is scheduled to commence by July 2006.
Production is anticipated to commence during the fourth quarter.
At Lake Erie, 25 (5 net) gas wells are scheduled to be drilled and
tied- in during this year's drilling season (June to September).
Central Alberta Core Area
-------------------------
Late in the first quarter, three (0.5 net) gas wells were drilled
targeting the Edmonton Sands. These wells are scheduled to be tied in
during the second quarter.
During the second quarter, the Trust plans on drilling eight (3.4
net) wells in the Sylvan Lake and Medicine River fields. This includes,
three (1.1 net) Edmonton Sands gas wells, two (1.7 net) Mannville wells,
and three (0.6 net) Jurassic oil wells. The Trust will also continue to
exploit the area's multi-zone potential by pursuing seven (3.1 net)
cost effective recompletions. These recompletions will primarily focus
on Mannville reservoirs.
CAPITAL EXPENDITURES
In line with NAL's 2006 budget, exploitation and development
expenditures for the quarter ended March 31, 2006 totaled $20.0 million
compared with $7.4 million in the quarter ended March 31, 2005.
The capital budget for full year 2006 remains at $95 million,
consistent with previous guidance. The Trust expects to drill 179 (72
net) wells during the year.
Exploitation and Development Expenditures ($000s)
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Drilling, completion and production
equipment 14,551 6,125 20,718
Plant and facilities 1,644 575 4,039
Seismic 728 46 1,072
Other(1) 3,089 679 1,899
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Total capital expenditures 20,012 7,425 27,728
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(1) Includes land purchases, capitalized G&A and capitalized unit-based
incentive compensation.
PRODUCTION
Average production for the three months ended March 31, 2006,
increased by 16 percent to 20,181 boe/d from 17,457 boe/d for the same
period in 2005. The increase reflects a 25 percent uplift in
year-over-year natural gas production during the first quarter of 2006,
along with a nine percent increase in oil and natural gas liquids
production.
The overall increase in production for the quarter ended March 31,
2006 is attributable to the gas-weighted acquisition of Addison Energy
Inc. completed in February 2005 and strong operating performance and
drilling results from all core areas.
The 2006 first quarter production of 20,181 boe/d compares with
20,514 boe/d in the fourth quarter of 2005. This natural decline was
anticipated due to the relatively low level of development in the first
quarter of 2006 versus the high level of capital development in the last
quarter of 2005.
The Trust maintains its previously announced production guidance of 19,200 to 19,800 boe/d for full year 2006.
Average Daily Production Volumes
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Oil (bbl/d) 9,552 9,206 9,755
Natural gas (Mcf/d) 51,937 41,575 52,340
NGL's (bbl/d) 1,973 1,322 2,036
Oil equivalent (boe/d) 20,181 17,457 20,514
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For the three months ended March 31, 2006, oil and natural gas liquids
production was 57 percent of total production with natural gas representing
the remaining 43 percent.
Production Weighting
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Oil 47% 53% 48%
Natural gas 43% 40% 43%
NGLs 10% 7% 9%
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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 $103.1 million for
the three months ended March 31, 2006, a 34 percent increase over the
first quarter of 2005.
Revenue increased year-over-year due to additional production
volumes largely attributable to the Addison acquisition and higher
realized commodity prices. Compared to the first quarter of 2005,
production increased 16 percent and average commodity prices increased
by 15 percent, for the first quarter of 2006.
Funds from operations tracked revenues in the first quarter of 2006, up 36 percent over the first quarter of 2005.
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Revenue(1) ($000s) 103,131 76,768 119,208
$/boe 56.78 48.86 63.16
Funds from operations(2) ($000s) 59,502 43,879 65,837
$/boe 32.76 27.93 34.88
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(1) Oil and natural gas and liquid sales less transportation and after
hedging.
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items, excluding unpaid unit-based incentive
compensation charges.
Average Pricing
(net of transportation charges and after hedging)
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Liquids:
WTI (US$/bbl) 63.48 49.90 60.02
NAL average oil (Cdn$/bbl) 61.00 55.59 59.53
NAL natural gas liquids (Cdn$/bbl) 52.53 40.29 56.29
Natural Gas:
AECO (Cdn$/Mcf) 7.59 6.69 11.43
NAL Western Canada natural gas (Cdn$/Mcf) 8.59 6.76 11.20
NAL Lake Erie natural gas (Cdn$/Mcf) 9.40 8.50 14.36
NAL average natural gas (Cdn$/Mcf) 8.65 6.93 11.47
NAL Oil Equivalent (Cdn$/boe - 6:1) 56.26 48.86 63.16
Average Foreign Exchange Rate (Cdn$/US$) 1.155 1.227 1.173
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OIL MARKETING
NAL sells its crude oil based on Refiners' posted prices at
Edmonton, Alberta, and Cromer, Manitoba, adjusted for transportation and
quality of each field battery. The Refiners' posted prices are
influenced by the West Texas Intermediate ("WTI") benchmark price,
transportation costs, exchange rates and the supply/demand situation of
particular crude oil quality streams during the year.
NAL's first quarter average crude oil price per barrel, net of
transportation costs, was $61.00, ten percent higher than the $55.59
received for the first quarter of 2005, largely attributable to
increases in WTI.
Natural gas liquids prices averaged $52.53 per barrel in the first
quarter, 30 percent higher than the first quarter of 2005. Pricing for
natural gas liquids is based upon crude pricing with some seasonality.
NATURAL GAS MARKETING
Approximately 73 percent of NAL's current gas production is sold
under marketing arrangements tied to the Alberta monthly or daily spot
price ("AECO"), with the remaining 27 percent tied to NYMEX or other
indexed referenced prices. Eight percent of the Trust's gas sales is
from its Lake Erie property and receives a higher price due to close
proximity to the Ontario and northeastern U.S. markets.
For the three months ended March 31, 2006, the Trust's total gas
sales averaged $8.65/Mcf, after $0.06/Mcf of hedging gains, an increase
of 25 percent from the 2005 first quarter price of $6.93/Mcf. The
quarter-over- quarter increase in gas prices was largely attributable to
the increased benchmark AECO prices. Natural gas sales from the Lake
Erie property averaged $9.40/Mcf in Q1 2006, compared to $8.50/Mcf in
2005, an increase of 11 percent.
HEDGING
NAL employs commodity hedging and is authorized by its Board to
hedge up to 30 percent of its production in any year to protect cash
flow and sustain its capital program and distributions. During the first
quarter of 2006, financial WTI oil contracts and AECO natural gas
contracts were in place.
For the oil contracts, settlements are made monthly based on the
average monthly WTI price. In general terms, the contracts represent
costless, three- way options which effectively provide the Trust with
protection up to an average of $9.78 per barrel if the WTI price falls
below the average hedge price of $48.44 per barrel and a "top-up"
payment if the WTI price falls between $48.44 and $58.22 to bring the
Trust's price up to $58.22 per barrel. There are no payments if the
average monthly WTI price falls between $58.22 and $72.83. The Trust's
oil price is capped at an average WTI price of $72.83 per barrel and is
required to pay the difference if the WTI price is greater than $72.83
per barrel.
During the first quarter 2006, an average of 2,493 bbl/d of crude
oil was hedged, with no effect on realized crude prices. In addition,
2,000 GJ/d of natural gas were hedged resulting in a realized gain of
$246,000 and increasing average natural gas prices for the quarter by
$0.06/Mcf. No hedges were in place for the first quarter of 2005.
Financial WTI Oil Contracts in Place as at March 31, 2006
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Contract
Volume Sold Put Bought Put Sold Call
-------- -------- ---------- ---------
Term Bbl/d US$/bbl US$/bbl US$/bbl
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Jan. 1 to Dec. 31, 2006 3-way 300 52.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 58.50 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.50 74.00
Jan. 1 to Dec. 31, 2006 3-way 600 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 74.00
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2006 weighted average 2,650 48.44 58.22 72.83
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Financial AECO Natural Gas Contracts in Place as at March 31, 2006
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Contract Volume Bought Put Sold Call
--------------- ---------- ---------
Term GJ's/day Cdn$/GJ Cdn$/GJ
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Jan. 1 to Dec. 31, 2006 Collar 2,000 9.50 14.40
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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 March
31, 2006. As at March 31, 2006 the unrealized fair value of these hedges
was a loss of $347,000.
Currently, the Trust has completed hedges for up to 30 percent of
estimated 2006 oil production, the maximum presently approved by the
Board of Directors. The Trust has similar limits on its gas hedging
program and will continue to monitor its position regarding further
natural gas hedges.
ROYALTY EXPENSES
Crown, freehold and overriding royalties, net of Alberta Royalty Tax
Credit (ARTC), were $24.1 million for the three months ended March 31,
2006. Expressed as a percentage of gross sales, before hedging and
transportation costs, the net royalty rate was 23.2 percent for the
quarter ended March 31, 2006, up from 22.3 percent for last year.
Included in the first quarter royalty expense is a $0.9 million
Saskatchewan Resource Surcharge relating to the period January 2006 to
March 2006. Prior to April 2005, trusts were exempt from this surcharge.
This surcharge is approximately 0.9% of revenue for the quarter.
Royalties have increased on a barrel of oil equivalent basis due to
higher commodity prices and the Saskatchewan surcharge.
Royalty Expenses
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
Net royalties ($000s) 24,056 17,227 26,248
As % of revenue(1) 23.2 22.3 21.1
$/boe 13.24 10.96 13.91
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(1) Oil and natural gas and liquid sales before transportation and
hedging.
OPERATING COSTS
For the quarter ended March 31, 2006, operating costs averaged $7.84
per boe, an 18 percent increase from the $6.67 for the quarter ended
March 31, 2005. The increase in operating costs in 2006 was due to
higher costs associated with the gas-weighted Addison properties
acquired in February 2005, as well as inflationary pressures resulting
from the increasing demand for personnel, equipment and services in the
highly competitive oil and gas industry.
Costs for the first quarter are in line with internal expectations
and are expected to trend upward during the second and third quarters
due to scheduled facility maintenance. Full year 2006 operating cost
guidance is unchanged at $8.30 - $8.70 per boe.
Operating Costs
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
Operating costs ($000s) 14,237 10,487 17,767
As % of revenue 13.8 13.7 14.9
$/boe 7.84 6.67 9.41
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OPERATING NETBACK
For the quarter ended March 31, 2006, NAL's operating netback,
before hedging gains, was $35.57 per boe, up 14 percent from $31.23 for
the quarter ended March 31, 2005. The increase was primarily due to
higher commodity prices, offset slightly by higher royalties and
operating costs.
Operating Netback ($/boe)
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Three months ended March 31, March 31, December
2006 2005 31, 2005
-------------------------------------------------------------------------
Production Revenue, net of transportation
costs 56.65 48.86 65.53
Royalties, net (13.24) (10.96) (13.91)
Operating expenses (7.84) (6.67) (9.41)
Operating netback, before hedging 35.57 31.23 42.21
Hedging gains (losses) 0.14 - (2.37)
Operating netback, after hedging 35.71 31.23 39.84
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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.
G&A expenses increased by 25 percent to $2.5 million for the
three months ended March 31, 2006 from $2.0 million for the three months
ended March 31, 2005. In addition, $0.9 million of G&A costs
relating to exploitation and development activities were capitalized,
compared with $0.3 million in the first quarter of 2005. The increase in
the capitalization rate in 2006 resulted from an overall review of
G&A expenses in the second half of 2005.
The increase in total G&A costs in 2006 was due to higher
staffing levels as a result of the Addison acquisition in February 2005
and an increased capital program as well as increased compensation
necessary to continue to attract and retain qualified personnel in a
highly competitive market.
General and Administrative Expenses
-------------------------------------------------------------------------
March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
G & A expenses ($000s) 2,464 1,976(1) 3,049(1)
As % of revenue 2.4 2.6 2.6
$/boe 1.36 1.26 1.62
Per Trust unit ($) 0.03 0.03 0.04
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(1) Restated from amounts previously reported to reflect the
reclassification of unit-based incentive compensation expense.
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.
The Plan will result in employees receiving cash compensation based
upon the value and overall return of a specified number of notional
Trust units. The Plan consists of Restricted Trust Units ("RTU's") and
Performance Trust Units ("PTU's"). 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. Distributions paid during the vesting period are assumed to be
reinvested in notional units on the date of distribution. Upon vesting,
the employee is entitled to a cash payout based on the unit price at
date of vesting of the units held. 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 market
value of the notional units held at vesting.
The first payment under the previous plan was made in December 2005,
the charge for which was accrued throughout the year and of which
$390,000 was charged to income in the first quarter of 2005. With the
expansion of the Plan and the introduction of the annual vesting
provision 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 the first quarter of 2006, the Trust accrued $3.6 million of
unit- based incentive compensation charges in its accounts of which,
$1.8 million has been charged to income and $1.8 million relating to
exploitation and development personnel has been capitalized in Property,
Plant and Equipment.
$2.3 million of the first quarter charge is expected to be paid in
December 2006 and has been included in current liabilities. The balance
represents the long-term portion of the Trust's estimated liability for
the unit-based incentive plan as at March 31, 2006. This amount is
payable in December 2007 and 2008.
The compensation changes relating to the units granted are
recognized over the vesting period based on the unit price, number of
RTU's and PTU's outstanding and the expected performance multiplier. As a
result, the expense recorded in the accounts will fluctuate over time.
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 manages, on their behalf, NAL
Resources Limited ("NAL Resources"), another wholly-owned subsidiary of
MFC. NAL Resources and the Trust maintain ownership interests in many of
the same oil and natural gas properties, in which NAL Resources is the
joint venture operator. As a result, a significant portion of the net
operating revenues and capital expenditures during the year is based on
joint venture amounts from NAL Resources. These transactions are in the
normal course of joint venture operations and are measured using the
fair value established through the original transactions with third
parties.
The Manager provides certain services pursuant to the Management
Contract for which, during the first quarter of 2006, the Trust paid
$750,000 for management fees in accordance with a proposed new
arrangement with the Manager described below. 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, which fees amounted to $1,554,000 for the
quarter ended March 31, 2005. In addition, the Trust paid $1.7 million
(2005 - $1.6 million) for the reimbursement of G&A expenses incurred
by the Manager on behalf of the Trust pursuant to the Management
Contract. The Trust will also pay the Manager its share of unit-based
incentive compensation expense when cash compensation is paid to
employees under the terms of the Plan.
On March 1, 2006 the Trust reached an agreement in principle
providing for the restructuring of the Management Contract with the
Manager. The restructuring transaction is subject to the approval of the
Trust's unitholders at the annual and special meeting scheduled for May
31, 2006 and certain regulatory and other third party approvals. Under
the new arrangement, the Trust will pay a one-time $30 million
restructuring fee in exchange for the elimination of any further base
and performance management fees payable by the Trust and the acquisition
of a 50 percent ownership in the Manager's administrative capital
assets, effective January 1, 2006. The Manager will then subscribe for
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 the date of the agreement.
In addition to the fees paid to date, the Trust will pay a monthly
interim management fee of $300,000 per month from April 1, 2006 up to
the date of closing expected on May 31, 2006. Upon approval of the
restructuring transaction on May 31, 2006, the second quarter results
will reflect the $30 million fee paid, with the portion representing the
capital assets acquired (currently estimated at approximately $3.0
million) capitalized as Property, Plant and Equipment, and the
remainder, representing the elimination of future management and
performance fees, recorded as a non-cash charge to income.
Management Fees
-------------------------------------------------------------------------
March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
Base management fees ($000s) 750 1,554 2,142
Performance fees ($000s) - - 2,142
Total management fees ($000s) 750 1,554 4,284
As % of revenue 0.7 2.0 3.6
$/boe 0.41 0.99 2.27
Per trust unit ($) 0.01 0.02 0.06
-------------------------------------------------------------------------
INTEREST
Interest expense includes amounts on borrowings plus standby fees on
the unused portion of the bank credit facility. NAL's average
outstanding bank debt for the first quarter 2006, was $207.0 million as
compared to $196.5 for the first quarter of 2005. NAL's effective
interest rate averaged 4.51 percent in 2006, compared with 4.27 percent
in the first quarter of 2005.
Interest expense for the year increased by $0.3 million to $2.4
million as compared to $2.1 million for the comparable period in 2005.
Interest and Bank Debt ($000s)
-------------------------------------------------------------------------
March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
Interest on bank debt 2,370 2,108 2,651
Bank debt outstanding at period end 198,093 259,600 220,519
Net bank debt outstanding at period
end(1) 181,443 249,740 198,351
Net bank debt-to-cash flow ratio 0.76 1.40 0.88
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
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 March 31, 2006, depletion on property, plant
and equipment and accretion on the asset retirement obligation increased
by 24 percent over the comparable period due to the increase in
production and an eight percent increase in the DDA rate per boe of
production. This higher DDA rate per boe is primarily due to the Addison
acquisition, acquired at a higher cost per barrel of reserves as
compared to properties owned by the Trust prior to this acquisition. In
addition, the higher asset retirement obligation recorded in 2005 has
resulted in higher accretion expense in 2006.
Depletion, Depreciation and Accretion Expenses
-------------------------------------------------------------------------
March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
Depletion and depreciation ($000s) 32,905 26,423 33,608
Accretion of asset retirement obligation
($000s) 1,239 1,023 1,197
-------------------------------------------------------------------------
Total DDA ($000s) 34,144 27,446 34,805
DDA rate per boe ($) 18.80 17.47 18.44
-------------------------------------------------------------------------
TAXES
Taxes include federal and provincial capital and income taxes
relating to the Trust and its subsidiary companies. In the first quarter
of 2006, NAL had future income tax expense of $0.05 million compared
with a provision of $1.3 million in the corresponding period of the
prior year.
The Trust is a taxable trust 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, and issue
costs. In addition, Canadian Exploration Expense and Canadian
Development Expense are deducted by the Trust's subsidiaries.
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of Trust units and bank debt.
As at March 31, 2006, NAL had 75,159,475 units outstanding, compared
with 73,977,041 units at December 31, 2005. The increase from December
31, 2005 is attributable to units issued under the distribution
reinvestment program.
For the quarter ended March 31, 2006, the distribution reinvestment
("DRIP") and premium distribution reinvestment ("Premium DRIP") plans
resulted in 1,182,434 units being issued at an average price of $17.60
per unit for total proceeds of $20.8 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 49 percent of monthly distributions over
the past quarter. On March 10, 2006, the Trust announced the suspension
of the Premium DRIP, which is expected to result in a significant
reduction in the reinvestment participation rate commencing with the
distribution payable in April 2006. The Trust monitors the participation
in these plans in conjunction with its capital requirements.
As at March 31, 2006 the Trust had bank debt of $181.4 million (net
of working capital) compared with $198.4 million at December 31, 2005
and $249.7 million as at March 31, 2005 after the Addison acquisition.
At the end of the first quarter, the Trust had a net bank debt to equity
ratio of 0.36 and a net bank debt to twelve months trailing cash flow
ratio of 0.76.
The Trust maintains a $300 million fully secured, extendible,
revolving credit facility. The credit facility has been recently renewed
and will revolve 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, a portion of the cash flow otherwise
available to unitholders would be used to repay the facility in four
equal quarterly installments commencing April 2008.
Total bank debt amounted to $198.1 million at March 31, 2006
compared with $220.5 million as at December 31, 2005. Of the debt
outstanding at March 31, 2006, $195.0 million was outstanding under the
production facility and $3.1 million under the working capital facility.
Capitalization
-------------------------------------------------------------------------
March 31, March 31, December
2006 2005 31, 2005
-------------------------------------------------------------------------
Trust unit equity ($000s) 497,310 472,759 494,490
Bank debt ($000s) 198,093 259,600 220,519
Net bank debt(1) ($000s) 181,443 249,740 198,351
Net bank debt to equity 0.36 0.53 0.40
Net bank debt to trailing 12-month cash flow 0.76 1.40 0.89
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
The Trust anticipates that it will continue to have adequate
liquidity to fund planned capital spending during 2006 through a
combination of funds from operations and funds received from its
distribution reinvestment programs and, if necessary, bank borrowings.
ASSET RETIREMENT OBLIGATION
At March 31, 2006, the Trust reported an Asset Retirement Obligation
("ARO") balance of $62.1 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 $1.2 million in the first quarter of 2006 ($1.0 million in
the first quarter of 2005) and reduced by $1.1 million for actual
abandonment and environmental expenditures incurred in the first quarter
of 2006 ($0.5 million in the first quarter of 2005).
DISTRIBUTIONS TO UNITHOLDERS
For the three months ended March 31, 2006, funds from operations
amounted to $59.5 million compared with $43.9 million for the three
months ended March 31, 2005. NAL declared cash distributions of $42.6
million ($0.57 per unit) in the first quarter as compared to $31.0
million ($0.48 per unit) in the first quarter of 2005, representing a 72
percent payout ratio for the quarter, compared with the 71 percent
payout ratio in the comparable quarter.
The weighted average number of units outstanding during the first
quarter of 2006 increased by 19 percent to 74.5 million from 62.7
million in 2005 as a result of the public issue of 17 million units in
January 2005, to fund a portion of the Addison acquisition, and strong
unitholder participation in the Trust's distribution reinvestment
programs.
UNITHOLDERS' DISTRIBUTIONS
Distributions
-------------------------------------------------------------------------
March 31, March 31, December
Three months ended 2006 2005 31, 2005
-------------------------------------------------------------------------
Funds from operations ($000s) 59,502 43,879 65,837
Distributions declared ($000s) 42,597 31,027 41,956
Funds from operations per unit(1) $0.80 0.70 $0.90
Distributions declared per unit $0.57 0.48 $0.57
Weighted average units outstanding (000s) 74,544 62,671 73,436
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding.
OFF-BALANCE SHEET ARRANGEMENTS/VARIABLE INTEREST ENTITIES
NAL has no off-balance sheet arrangements or variable interest entities.
CONTRACTUAL OBLIGATIONS
NAL has entered into several contract obligations as part of
conducting day-to-day business. NAL has the following commitments for
the next five years:
-------------------------------------------------------------------------
($000s) 2006 2007 2008 2009 2010
-------------------------------------------------------------------------
Office Lease(1) 2,132 2,460 - - -
Transportation 1,027 666 666 85 -
Processing Agreement(2) 389 491 469 446 428
Drilling rigs(3) 2,963 3,950 988 - -
-------------------------------------------------------------------------
(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 of the expense on a monthly basis.
Included in office lease is a $1 million commitment related to the
Addison acquisition. The commitment started in February 2005 and
extends 30 months. NAL has subsequently sublet the premises.
(2) Represents a gas processing agreement with a take or pay arrangement
associated with the Addison acquisition.
(3) Represents the full amount of the minimum payments required under
drilling rig contracts held by NAL Resources of which the Trust is
allocated a share of the expense on a monthly basis.
QUARTERLY INFORMATION
-------------------------------------------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
($000s, except
per unit and
production
amounts) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
-------------------------------------------------------------------------
Revenue, net of
royalties and
transportation
costs 80,604 94,856 84,833 70,797 60,617 43,110 43,989 40,674
Per unit 1.08 1.29 1.17 0.99 0.97 0.81 0.84 0.79
Funds from
operations 59,502 65,050 62,442 50,279 43,879 28,846 30,446 28,481
Per unit 0.80 0.89 0.86 0.71 0.70 0.54 0.58 0.55
-------------------------------------------------------------------------
Net income 24,610 30,777 31,710 20,804 15,247 11,754 13,279 10,871
Per unit 0.33 0.42 0.44 0.29 0.24 0.22 0.25 0.21
Average oil
equivalent
production
(boe/d - 6:1) 20,181 20,514 19,710 18,349 17,457 12,958 12,807 13,259
-------------------------------------------------------------------------
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has evaluated the effectiveness of the Trust's financial
reporting disclosure controls and procedures as at March 31, 2006, and
has concluded that such financial reporting disclosure controls and
procedures were effective as at that date.
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by NAL are disclosed in the
notes to NAL's December 31, 2005 audited consolidated financial
statements. Certain accounting policies require that management make
appropriate decisions when formulating estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and
expenses. The Manager reviews the estimates regularly. The emergence of
new information and changed circumstances may result in actual results
or changes to estimated amounts that differ materially from current
estimates. NAL might realize different results from the application of
new accounting standards published, from time to time, by various
regulatory bodies. An assessment of NAL's significant accounting
estimates is discussed in the MD&A filed with NAL's audited
consolidated financial statements for the year ended December 31, 2005.
Unit-Based Incentive Compensation Accounting Policy
---------------------------------------------------
In January 2006, the Board of Directors approved a revised
unit-based incentive plan (the "Plan") for all employees of the Manager.
The first payment under the previous plan was made in December 2005. No
charges related to the previous plan had been recorded in the accounts
of the Trust prior to 2005. With the expansion of the Plan and the
introduction of annual vesting provision 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 unit price, number of
RTU's and PTU's outstanding and the expected performance multiplier. As a
result, the expense recorded in the accounts will fluctuate over time.
The accounting policy for the Plan is more fully described in Note 1
to the accompanying consolidated financial statements for the three
months ended March 31, 2006.
Dated: May 2, 2006
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
-------------------------
As at As at
March 31, December 31,
2006 2005
(unaudited) (audited)
-------------------------
Assets
Current assets
Cash $708 $1,124
Accounts receivable and other 48,415 58,081
-------------------------------------------------------------------------
49,123 59,205
Reclamation reserve 3,995 3,898
Future income tax asset 2,083 2,136
Property, plant and equipment, net (Note 3) 736,126 748,715
-------------------------------------------------------------------------
$791,327 $813,954
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $18,193 $22,981
Distributions payable to unitholders 14,280 14,056
-------------------------------------------------------------------------
32,473 37,037
Bank debt (Note 4) 198,093 220,519
Unit-based incentive compensation (Note 5) 1,336 -
Asset retirement obligations (Note 6) 62,115 61,908
-------------------------------------------------------------------------
294,017 319,464
Unitholders' equity
Unitholders' capital (Note 7) 774,392 753,585
Accumulated income 298,406 273,796
Accumulated distributions (575,488) (532,891)
-------------------------------------------------------------------------
497,310 494,490
-------------------------------------------------------------------------
$791,327 $813,954
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (Note 9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Units outstanding (000s) 75,159 73,977
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME
(thousands of dollars, except per unit amounts) (unaudited)
------------------------
Three Three
months months
ended ended
March 31, March 31,
2006 2005
------------------------
Revenue
Oil, natural gas and liquids sales $103,799 $77,419
Transportation costs (668) (651)
Royalty and other income 1,529 1,076
Crown royalties, net of ARTC (18,164) (12,730)
Freehold and other royalties (5,892) (4,497)
-------------------------------------------------------------------------
80,604 60,617
-------------------------------------------------------------------------
Expenses
Operating 14,237 10,487
General and administrative 2,464 1,976
Unit-based incentive compensation (Note 5) 1,838 390
Management fees (Note 2) 750 1,554
Interest on bank debt 2,370 2,108
Depletion, depreciation and amortization 32,905 26,423
Accretion on asset retirement obligations 1,239 1,023
-------------------------------------------------------------------------
55,803 43,961
-------------------------------------------------------------------------
Income before taxes 24,801 16,656
Income and capital taxes (138) (81)
Future income tax provision (53) (1,328)
-------------------------------------------------------------------------
Total income and capital taxes (191) (1,409)
-------------------------------------------------------------------------
Net Income 24,610 15,247
Accumulated income, beginning of period 273,796 175,258
-------------------------------------------------------------------------
Accumulated income, end of period 298,406 $190,505
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust unit $0.33 $0.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average units outstanding (000s) 74,544 62,671
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
------------------------
Three Three
months months
ended ended
March 31, March 31,
2006 2005
------------------------
Operating Activities
Net income $24,610 $15,247
Items not involving cash:
Depletion, depreciation and amortization 32,905 26,423
Accretion on asset retirement obligations 1,239 1,023
Future income tax provision 53 1,328
Abandonment and environmental expenditures (1,143) (532)
Decrease (increase) in non-cash working capital 11,134 (7,262)
-------------------------------------------------------------------------
68,798 36,227
-------------------------------------------------------------------------
Financing Activities
Distributions to unitholders (42,372) (28,224)
Issue of Trust units, net of issue costs 20,807 227,501
Increase (decrease) in bank debt (22,426) 165,900
Decrease (increase) in non-cash working capital (318) 160
-------------------------------------------------------------------------
(44,309) 365,337
-------------------------------------------------------------------------
Investing Activities
Acquisition of Addison Energy Inc. - (383,157)
Additions to property, plant and equipment (20,012) (7,492)
Proceeds from dispositions 122 -
Reclamation reserve (96) (97)
Decrease (increase) in non-cash working capital (4,919) (9,671)
-------------------------------------------------------------------------
(24,905) (400,417)
-------------------------------------------------------------------------
Increase (decrease) in cash (416) 1,147
Cash, beginning of period 1,124 1,111
-------------------------------------------------------------------------
Cash, end of period $708 $2,258
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure of cash flow information:
Cash paid during the period for:
Interest $2,333 $2,096
Taxes (recovery) $138 $81
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2006
(Tabular amounts in thousands of dollars, except per unit amounts)
(unaudited)
1. SUMMARY OF ACCOUNTING POLICIES
Management prepared the interim consolidated financial statements of
NAL Oil & Gas Trust ("NAL" or the "Trust") in accordance with
accounting principles generally accepted in Canada and following the
same accounting policies and methods of computation as the
consolidated financial statements for the fiscal year ended
December 31, 2005, except for implementation of unit-based incentive
compensation. The following disclosure is incremental to the
disclosure included within the annual financial statements. Please
read the interim consolidated financial statements in conjunction
with the consolidated financial statements and notes thereto in NAL's
annual report for the year ended December 31, 2005.
Unit-Based Incentive Compensation
The Manager has established a unit-based incentive compensation plan
for employees, for which grants are in the form of Restricted Trust
Units ("RTU's") and Performance Trust Units ("PTU's"). As
participants in the plan receive a cash payment on a fixed vesting
date, compensation expense is determined based on the intrinsic value
of the units at each period end. The valuation incorporates the
period end trust unit price, number of RTU's and PTU's outstanding at
each period end, and certain management assumptions. PTU's vest at
the end of a three-year period. RTU's vest one third at the end of
each year for three years. Compensation expense is recognized over
the vesting period 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 amounts relating to head office employees to
general and administrative expenses, amounts relating to field staff
to operating costs, and 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, rather, the Trust accounts for
actual forfeitures as they occur.
2. 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 manages, on their behalf, NAL
Resources Limited ("NAL Resources"), another wholly-owned subsidiary
of MFC. NAL Resources and the Trust maintain ownership interests in
many of the same oil and natural gas properties, in which NAL
Resources is the joint venture operator. As a result, a significant
portion of the net operating revenues and capital expenditures during
the year is based on joint venture amounts from NAL Resources. These
transactions are in the normal course of joint venture operations and
are measured using the fair value established through the original
transactions with third parties.
The Manager provides certain services pursuant to the Management
Contract for which, during the first quarter of 2006, the Trust paid
$750,000 for management fees in accordance with a proposed new
arrangement with the Manager described below. 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, which fees amounted to $1,554,000
for the quarter ended March 31, 2005. In addition, the Trust paid
$1.7 million (2005 - $1.6 million) for the reimbursement of G&A
expenses incurred by the Manager on behalf of the Trust pursuant to
the Management Contract. The Trust will also pay the Manager its
share of unit-based incentive compensation expense when cash
compensation is paid to employees under the terms of the Plan.
On March 1, 2006 the Trust reached an agreement in principle
providing for the restructuring of the Management Contract with the
Manager. The restructuring transaction is subject to the approval of
the Trust's unitholders at the annual and special meeting scheduled
for May 31, 2006 and certain regulatory and other third party
approvals. Under the new arrangement, the Trust will pay a one-time
$30 million restructuring fee in exchange for the elimination of any
further base and performance management fees payable by the Trust and
the acquisition of a 50 percent ownership in the Manager's
administrative capital assets, effective January 1, 2006. The Manager
will then subscribe for 1,592,357 units of the Trust at a price of
$18.84 per unit.
In addition to the fees paid to date, the Trust will pay a monthly
interim management fee of $300,000 per month from April 1, 2006 up to
the date of closing of the restructuring transaction expected on
May 31, 2006.
3. PROPERTY, PLANT AND EQUIPMENT ("PP&E")
---------------------------------------------------------------------
Net book value as at: March 31, December 31,
2006 2005
---------------------------------------------------------------------
Oil and natural gas properties, at cost $1,224,124 $1,204,123
Less: Accumulated depletion and depreciation (487,998) (455,408)
---------------------------------------------------------------------
736,126 $748,715
---------------------------------------------------------------------
---------------------------------------------------------------------
During the three months ended March 31, 2006, the Trust capitalized
$0.9 million (2005 - $0.3 million) of general and administrative
costs and $1.7 million of unit-based incentive compensation expense
(2005 - $nil) that were directly related to exploitation and
development programs. (See Note 5).
No property costs have been excluded from the depletion and
depreciation calculation.
4. BANK DEBT
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.
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. base interest rate and
Libor based loans. The interest charged on advances is at the
prevailing interest rate for bankers' acceptances, Libor loans,
lenders' prime or 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 March 31, 2006 the effective interest rate on amounts outstanding
under the credit facility was 4.81 percent.
5. UNIT-BASED INCENTIVE COMPENSATION PLAN
In January 2006, the Board of Directors approved a revised unit-based
incentive compensation plan (the "Plan") for all employees of the
Manager. The Plan will result in employees receiving cash
compensation in relation to the value of a specified number of
notional units. The Plan consists of Restricted Trust Units ("RTU's")
and Performance Trust Units ("PTU's"). 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. Distributions paid during the vesting period
are assumed to be reinvested in notional units on the date of
distribution. Upon vesting the employee is entitled to a cash payout
based on the unit price at date of vesting of the units held. 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 market value of the notional units held at
date of vesting.
The first payment under the previous plan was made in December 2005,
the charge for which was accrued throughout the year and of which
$390,000 was charged to income in the first quarter of 2005. With
the expansion of the Plan and the introduction of the annual vesting
provision 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 the first quarter of 2006, the Trust accrued $3.6 million of
unit-based incentive compensation charges in its accounts, of which
$1.8 million has been charged to income and $1.8 million relating to
exploitation and development personnel has been capitalized in
Property, Plant and Equipment.
$2.3 million of the first quarter charge is expected to be paid in
December 2006 and has been included in current liabilities. The
balance represents the long-term portion of the Trust's estimated
liability for the unit-based incentive plan as at March 31, 2006.
This amount is payable in December 2007 and 2008.
The compensation changes relating to the units granted are recognized
over the vesting period based on the unit price, number of RTU's and
PTU's outstanding and the expected performance multiplier. As a
result, the expense recorded in the accounts will fluctuate over
time.
6. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligation was estimated by the
Manager based on the Trust's net ownership interests in oil and
natural gas assets including well sites, gathering systems and
processing facilities, estimated costs to remediate, reclaim and
abandon the wells and facilities and the estimated timing of the
costs to be incurred in future periods. NAL has estimated the net
present value of its asset retirement obligations to be $62.1 million
as at March 31, 2006 based on a total undiscounted amount of cash
flows required to settle its asset retirement obligations of
$157.4 million (2005 - $161.8 million). These costs are expected to
be incurred over the next 46 years with the majority of the costs
incurred between 2006 and 2033. NAL's credit-adjusted risk-free rate
of eight percent (2005 - eight percent) and an inflation rate of two
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.
---------------------------------------------------------------------
March 31, December
2006 31, 2005
---------------------------------------------------------------------
Balance, beginning of period $61,908 $36,924
Accretion expense 1,239 4,582
Liabilities incurred 111 23,374
Liabilities settled (1,143) (2,972)
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Balance, end of period $62,115 $61,908
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7. UNITHOLDERS' EQUITY
Units Issued:
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March 31, 2006 December 31, 2005
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Units Amount Units Amount
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Balance, beginning of
period 73,977 753,585 53,064 $476,620
Issued for cash - - 17,000 232,900
Less: Issue expenses - - - (12,333)
Issued from Distribution
Reinvestment Plan 1,182 20,807 3,913 56,398
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Balance, end of period 75,159 $774,392 73,977 $753,585
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8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As at March 31, 2006 the Trust had entered into the following
derivatives to protect its 2006 cash flow from the volatility of oil
and natural gas commodity prices:
Financial WTI oil contracts in place as at March 31, 2006:
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Volume Sold Put Bought Put Sold Call
Term Contract Bbl/d US$/bbl US$/bbl US$/bbl
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Jan. 1 to Dec. 31, 2006 3-way 300 52.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 58.50 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.50 74.00
Jan. 1 to Dec. 31, 2006 3-way 600 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 74.00
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2006 weighted average 2,650 48.44 58.22 72.83
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Financial AECO natural gas contracts in place as at March 31, 2006:
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Volume Bought Put Sold Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ
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Jan. 1 to Dec. 31, 2006 Collar 2,000 9.50 14.40
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The estimated fair value of the above contracts, all of which qualify
for hedge accounting, was a loss of $347,000 as at March 31, 2006.
These instruments have no carrying value recorded in the financial
statements.
9. COMMITMENTS
At December 31, 2005 the Trust had the following contractual
obligations and commitments:
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($000s) 2006 2007 2008 2009 2010
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Office lease(1) 2,132 2,460 - - -
Transportation agreement 1,027 666 666 85 -
Processing agreement(2) 389 491 469 446 428
Drilling rigs(3) 2,963 3,950 988 - -
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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 of the expense on a monthly basis.
Included in office lease is a $1.0 million commitment related to
the Addison Energy acquisition. The commitment started in
February 2005 and extends 30 months. NAL has subsequently sublet
the premises.
(2) Represents gas processing agreement under take or pay arrangement
associated with Addison Energy acquisition.
(3) Represents the full amount of the minimum payments required under
drilling rig contracts held by NAL Resources of which the Trust
is allocated a share of the expense on a monthly basis.
10. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform to
current period presentation.
TRADING PERFORMANCE
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For the Quarter Ended
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Price 31-Mar-06 31-Dec-05 31-Mar-05 31-Dec-04
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High $20.25 $19.15 $14.69 $15.29
Low $16.92 $13.39 $12.82 $12.60
Close $19.58 $18.08 $13.80 $13.55
Volume 13,614,737 16,922,700 23,391,175 15,265,465
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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".
Contact Information:
NAL Oil & Gas Trust
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: (888) 223-8792
Fax: (403) 515-3407
Email: Investor.Relations@nal.ca
Website: www.nal.ca