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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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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First Quarter Drilling Activity
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Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
------------------------------------------------------
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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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.
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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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$) 1.155 1.227 1.173
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Financial WTI Oil Contracts in Place as at March 31, 2006
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Contract
Volume Sold Put Bought Put Sold Call
-------- -------- ---------- ---------
Term Bbl/d US$/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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Royalty Expenses
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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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
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Operating costs ($000s) 14,237 10,487 17,767
As % of revenue 13.8 13.7 14.9
$/boe 7.84 6.67 9.41
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Operating Netback ($/boe)
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Three months ended March 31, March 31, December
2006 2005 31, 2005
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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
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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.
Management Fees
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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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
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Interest and Bank Debt ($000s)
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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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
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(1) Net bank debt is bank debt net of working capital.
Depletion, Depreciation and Accretion Expenses
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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Depletion and depreciation ($000s) 32,905 26,423 33,608
Accretion of asset retirement obligation
($000s) 1,239 1,023 1,197
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Total DDA ($000s) 34,144 27,446 34,805
DDA rate per boe ($) 18.80 17.47 18.44
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Capitalization
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March 31, March 31, December
2006 2005 31, 2005
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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
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(1) Net bank debt is bank debt net of working capital.
UNITHOLDERS' DISTRIBUTIONS
Distributions
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March 31, March 31, December
Three months ended 2006 2005 31, 2005
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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
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(1) Based on weighted average units outstanding.
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($000s) 2006 2007 2008 2009 2010
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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 - -
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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 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
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2006 2005 2004
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($000s, except
per unit and
production
amounts) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
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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
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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
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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
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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
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$791,327 $813,954
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Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $18,193 $22,981
Distributions payable to unitholders 14,280 14,056
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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
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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)
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497,310 494,490
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$791,327 $813,954
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Commitments (Note 9)
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Units outstanding (000s) 75,159 73,977
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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)
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80,604 60,617
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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
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55,803 43,961
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Income before taxes 24,801 16,656
Income and capital taxes (138) (81)
Future income tax provision (53) (1,328)
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Total income and capital taxes (191) (1,409)
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Net Income 24,610 15,247
Accumulated income, beginning of period 273,796 175,258
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Accumulated income, end of period 298,406 $190,505
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Net income per Trust unit $0.33 $0.24
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Weighted average units outstanding (000s) 74,544 62,671
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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)
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68,798 36,227
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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
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(44,309) 365,337
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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)
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(24,905) (400,417)
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Increase (decrease) in cash (416) 1,147
Cash, beginning of period 1,124 1,111
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Cash, end of period $708 $2,258
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Supplementary disclosure of cash flow information:
Cash paid during the period for:
Interest $2,333 $2,096
Taxes (recovery) $138 $81
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See accompanying notes
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")
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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
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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.
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March 31, December
2006 31, 2005
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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".
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