CALGARY--(CCNMatthews - Nov. 9) - NAL Oil & Gas Trust (TSX: NAE.UN) ("NAL" or the "Trust") today announced its financial and operational results for the third quarter ended September 30, 2006. All amounts are in Canadian dollars unless otherwise stated.
THIRD QUARTER HIGHLIGHTS
- Production volumes for the nine months ended September 30, 2006
averaged 19,420 boe/d, up five percent from 18,514 a year ago. For
the third quarter ended September 30, 2006 production averaged
19,079 boe/d, three percent lower than 19,710 boe/d a year earlier.
Unplanned outages at the non-operated Harmattan gas plant, drilling
results at Medicine River which were below expectations and delays in
bringing on new volumes at Garrington/Westward Ho contributed to the
slight decline. Production exit rates at September 30, 2006 were
strong at 19,600 boe/d with October actual average production
relatively consistent at 19,540 boe/d.
- WTI crude oil prices remained strong early in the third quarter
declining towards the end of the period. Natural gas prices continued
to trend lower while the Canadian dollar strengthened year-over-year.
Overall, NAL's realized price on a boe basis was Cdn$55.06 for the
third quarter, down eight percent compared to the previous year. Nine
months year-to-date, NAL's realized price was Cdn$55.70 per boe, up
three percent from Cdn$54.02 a year earlier.
- As a result of growing production and higher oil prices earlier in
2006, nine months' funds from operations reached $164 million
compared to $156 million a year earlier. On a per unit basis, nine
months' funds from operations was 4.4 percent lower at $2.16 versus
$2.26, as a result of additional units outstanding. For the third
quarter, funds from operations was $54 million compared to
$62 million a year earlier with per unit performance being $0.70
versus $0.86.
- The number of units outstanding at September 30, 2006 increased by
4.7 percent to 77.4 million from 73.9 million at December 31, 2005.
In June 2006, the Trust issued 1.6 million units to NAL Resources as
part of the restructuring of the management contract and the
elimination of the management fees going forward. For the January to
March 2006 period, the Trust issued 1.2 million units under the
Premium and regular DRIP programs and from April to September issued
0.7 million units from the regular DRIP. Ongoing participation in the
regular DRIP program during the third quarter averaged approximately
15 percent. These DRIP programs assist the Trust in funding its
capital expenditure programs and retain balance sheet flexibility.
- Net income for the nine months ended September 30, 2006 was
$39.7 million versus $67.8 million during the first nine months of
2005. This reduction was driven primarily by a $27.3 million one-time
charge related to the restructuring of the management contract during
the second quarter. Third quarter earnings were $20.5 million, down
35.4 percent from $31.7 million in the third quarter of 2005, as a
result of lower natural gas prices and higher operating and general
and administration costs.
- As to capital spending, NAL had an active third quarter participating
in 64 wells (28.95 net) during the period, spending $41.9 million
versus $28.8 million during the same three months last year. During
the first nine months, NAL drilled 130 wells (52.41 net) and spent
$89.4 million. The Board of Directors has authorized an increase in
the 2006 capital budget to $120 million from the original $95 million
forecast and the $103 to $108 million range announced in August 2006.
This higher level of spending is related to an increase in drilling
activity from 72 net wells to 86 net wells, the higher cost of
equipment and services, and more spending on land and seismic to
position future opportunities in our core areas. NAL is in the
process of developing its capital expenditures budget for 2007 and
will announce spending plans and activity levels early in the new
year. Preliminary estimates for 2007 capital expenditures are
projected to be in the $100 million to $110 million range.
- Net debt totaled $211.3 million as of September 30, 2006, relatively
consistent with $214.5 million a year earlier. NAL's current net debt
represents a multiple of 0.9 times trailing twelve-month cash flow
(funds from operations) of $229.8 million. NAL continues to have one
of the strongest balance sheets in the trust sector, allowing it to
maintain a high level of drilling activity during a period of lower
commodity prices and positioning the Trust to take advantage of
acquisition opportunities as they arise.
- NAL distributed nearly $130 million to its unitholders during the
first nine months of the year. Third quarter distributions totaled
$44.1 million or $0.57 per unit. Monthly distributions were increased
from $0.16 per unit to $0.19 in October 2005 on the strength of high
oil and gas prices. With oil prices declining in the third quarter
and natural gas prices remaining low, NAL's payout ratio increased to
79 percent for the nine months year-to-date and 81 percent for the
third quarter. As a result of lower commodity prices and increasing
payout ratios, the Board of Directors has decided to reduce
distributions from $0.19 to $0.16 per unit per month commencing with
the distribution to be paid in December 2006, reversing the $0.03 per
unit increase introduced in October 2005 in response to the higher
commodity prices experienced a year ago.
- NAL has been actively hedging both oil and gas prices to assist in
managing cash flow and supporting capital programs and distributions.
The Trust has currently hedged an average of 1,800 bbls/d for 2007
through a combination of collars with a weighted average floor price
of US$65.32 and a ceiling of US$75.18 and swaps at a weighted
average price of US$68.69. The Trust has also hedged a total of
9,000 GJ/d for next year through a combination of collars with a
weighted average floor price of Cdn$6.38 and a ceiling of Cdn$8.41
and a swap at a price of Cdn$6.77 per GJ. NAL's management is
authorized to hedge up to one-third of its annual net production.
- NAL is pleased to welcome Warren Thomson of Manulife Financial to its
board of directors, replacing Leo de Bever who resigned from Manulife
and the Board to pursue a career in Australia.
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2006
Nine-Month
2006 Full Year Actual
Guidance Results
As Issued Ending
January 18, September 30, Full Year
2006 2006 Estimate
-------------------------------------------------------------------------
Average total
production (boe/d) 19,200 - 19,800 19,420 19,300 - 19,600
Capital
expenditures ($MM) 95 89 120
Operating costs ($/boe) 8.30 - 8.70 8.71 8.50 - 8.70
G&A ($/boe)(1) 1.70 - 1.85 1.61 1.70 - 1.85
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(1) Excluding unit-based incentive compensation expense.
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
-------------------------------------------------------------------------
3 Months 3 Months 3 Months 9 Months 9 Months
Ended Ended Ended Ended Ended
September June September September September
30, 2006 30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
FINANCIAL
Gross revenue, net
of royalties and
transportation $ 75,175 $ 77,352 $ 84,833 $ 233,131 $ 216,247
Net income (loss) 20,473 (5,357)(1) 31,710 39,726 67,761
Funds from
operations 54,107 52,210 62,442 163,981 155,812
Distributions
declared 44,061 43,268 34,805 129,926 100,093
Funds from
operations
per unit 0.70 0.69 0.86 2.16 2.26
Distributions
declared per unit 0.57 0.57 0.48 1.71 1.44
Payout ratio 81% 83% 56% 79% 64%
Average number
of units
outstanding (000s) 77,247 75,869 72,345 75,897 68,770
Total assets $ 800,455 $ 788,519 $ 821,421 $ 800,455 $ 821,421
Bank debt, net of
working capital 211,276 186,333 214,508 211,276 214,508
Unitholders'
equity 467,817 484,734 487,979 467,817 487,979
Costs per boe
($/boe - 6:1):
Operating $ 8.70 $ 9.63 $ 8.55 $ 8.71 $ 7.50
General and
administrative 1.49 2.00 0.45 1.61 1.24
Unit-based
incentive
compensation 0.11 0.34 -- 0.50 0.15
Management fees -- 0.35 1.19 0.25 1.12
OPERATING
Daily production
Oil (bbl) 9,256 8,959 9,432 9,254 9,279
Natural gas (Mcf) 47,334 48,861 48,738 49,360 44,548
Natural gas
liquids (bbl) 1,934 1,910 2,155 1,939 1,810
Oil equivalent
(boe - 6:1) 19,079 19,012 19,710 19,420 18,514
Average pricing,
net of
transportation
charges and hedging
Liquids:
WTI (US$/bbl) 70.48 70.70 63.19 68.25 55.40
NAL average oil
(Cdn$/bbl) 71.22 71.35 67.28 67.68 60.37
NAL natural gas
liquids
(Cdn$/bbl) 50.17 49.86 51.94 50.56 46.95
Natural gas:
AECO (Cdn$/Mcf)
- daily spot 5.75 6.03 9.25 6.45 7.81
AECO (Cdn$/Mcf)
- monthly 6.03 6.28 8.19 7.18 7.24
NAL natural gas
Western Canada
(Cdn$/Mcf) 6.14 6.32 8.51 7.16 7.77
NAL natural gas
Lake Erie
(Cdn$/Mcf) 7.02 7.73 11.73 8.06 9.88
NAL average
natural gas
(Cdn$/Mcf) 6.22 6.45 8.81 7.24 7.97
NAL oil
equivalent
(Cdn$/boe - 6:1) 55.06 55.20 59.66 55.70 54.02
Average foreign
exchange rate
(Cdn$/US$) 1.1212 1.1220 1.2012 1.1327 1.2239
Operating netback
before hedging
gains (losses)
($/boe) 33.50 34.14 40.34 34.42 35.73
Hedging gains
(losses) ($/boe) 0.39 0.37 (3.05) 0.30 (1.27)
Operating netback
($/boe) 33.89 34.51 37.29 34.72 34.46
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(1) Net loss in Q2, 2006 attributable to non-cash restructuring fee of
$27.2 million.
Third Quarter Drilling Activity
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Crude Oil Natural Gas Service Wells
----------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------
Operated wells 16 6.67 27 17.32 3 1.50
Non-operated wells 2 0.20 14 2.87 0 0
-------------------------------------------------------------------------
Total wells drilled 18 6.87 41 20.19 3 1.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
---------------------------------------------------------
Dry & Abandoned Total
-------------------------------
Gross Net Gross Net
---------------------------------------------------------
Operated wells 1 0.19 47 25.68
Non-operated wells 1 0.20 17 3.27
---------------------------------------------------------
Total wells drilled 2 0.39 64 28.95
---------------------------------------------------------
---------------------------------------------------------
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Crude Oil Natural Gas Service Wells
----------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------
Year-to-date total
wells drilled 46 15.98 76 34.54 6 1.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
---------------------------------------------------------
Dry & Abandoned Total
-------------------------------
Gross Net Gross Net
---------------------------------------------------------
Year-to-date total
wells drilled 2 0.39 130 52.41
---------------------------------------------------------
---------------------------------------------------------
Capital Expenditures ($000s)
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Drilling, completion and
production equipment 32,697 20,900 61,752 36,249
Plant and facilities 5,792 3,093 9,883 4,435
Seismic 515 1,462 2,224 1,619
Land 60 2 5,469 439
Property acquisitions 1,286 -- 1,286 --
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Total exploitation and
development 40,350 25,457 80,614 42,742
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Office equipment 47 -- 3,308(1) --
Capitalized G&A 1,441 2,883 3,515 3,705
Capitalized unit-based
incentive compensation 31 486 1,954 486
-------------------------------------------------------------------------
1,519 3,369 8,777 4,191
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total capital expenditures 41,869 28,826 89,391 46,933
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes $2.8 million in assets acquired as part of the management
agreement restructuring.
Average Daily Production Volumes
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Oil (bbl/d) 9,256 9,432 9,254 9,279
Natural gas (Mcf/d) 47,334 48,738 49,360 44,548
NGL's (bbl/d) 1,934 2,155 1,939 1,810
Oil equivalent (boe/d) 19,079 19,710 19,420 18,514
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Production Weighting
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Oil 49% 48% 48% 50%
Natural gas 41% 41% 42% 40%
NGLs 10% 11% 10% 10%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Revenue(1) ($000s) 96,641 108,178 295,280 273,036
$/boe 55.06 59.66 55.70 54.02
Funds from
operations(2) ($000s) 54,107 62,442 163,981 155,812
$/boe 30.83 34.44 30.93 30.83
$/unit 0.70 0.86 2.16 2.26
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(1) Oil, natural gas and liquids sales less transportation and after
hedging.
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
Average Pricing
(net of transportation charges and after hedging)
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Liquids:
WTI (US$/bbl) 70.48 63.19 68.25 55.40
NAL average oil (Cdn$/bbl) 71.22 67.28 67.68 60.37
NAL natural gas liquids
(Cdn$/bbl) 50.17 51.94 50.56 46.95
Natural Gas (Cdn$/Mcf):
AECO 5.75 9.25 6.45 7.81
NAL Western Canada natural
gas (Cdn$/Mcf) 6.14 8.51 7.16 7.77
NAL Lake Erie natural gas
(Cdn$/Mcf) 7.02 11.73 8.06 9.88
NAL average natural gas 6.22 8.81 7.24 7.97
NAL Oil Equivalent
(Cdn$/boe - 6:1) 55.06 59.66 55.70 54.02
Average Foreign Exchange Rate
(Cdn$/US$) 1.1212 1.2012 1.1327 1.2239
-------------------------------------------------------------------------
Royalty Expenses
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Net royalties ($000s) 21,883 25,062 65,074 60,940
As % of revenue(1) 22.6 21.9 22.0 21.6
$/boe 12.47 13.82 12.27 12.06
-------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales before transportation and hedging.
Operating Costs
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Operating costs ($000s) 15,265 15,511 46,168 37,915
As % of revenue 15.8 14.3 15.6 13.9
$/boe 8.70 8.55 8.71 7.50
-------------------------------------------------------------------------
Operating Netback ($/boe)
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Production Revenue, net of
transportation costs 54.67 62.71 55.40 55.29
Royalties, net (12.47) (13.82) (12.27) (12.06)
Operating expenses (8.70) (8.55) (8.71) (7.50)
-------------------------------------------
Operating netback, before
hedging 33.50 40.34 34.42 35.73
Hedging gains (losses) 0.39 (3.05) 0.30 (1.27)
-------------------------------------------
Operating netback, after
hedging 33.89 37.29 34.72 34.46
-------------------------------------------------------------------------
General and Administrative Expenses
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
G&A expenses 2,623 817 8,551 6,245
Capitalized G&A 1,441 2,883 3,515 3,705
-------------------------------------------
Total G&A 4,064 3,700 12,066 9,950
Expensed G&A costs:
As % of revenue 2.7 0.8 2.9 2.3
$/boe 1.49 0.45 1.61 1.24
Per Trust unit ($) 0.03 0.01 0.11 0.09
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Unit-Based Compensation
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 193 - 2,626 788
Capitalized ($000s) 31 486 1,954 486
-------------------------------------------
Total unit-based
compensation ($000s) 224 486 4,580 1,274
Expensed unit-based compensation:
As % of revenue 0.2 - 0.9 0.3
$/boe 0.11 - 0.50 0.15
Per trust unit ($) 0.00 - 0.03 0.01
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Management Fees
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Base management fees ($000s) - 2,162 1,350 5,674
As % of revenue - 2.0 0.5 2.1
$/boe - 1.19 0.25 1.12
Per trust unit ($) - 0.03 0.02 0.08
-------------------------------------------------------------------------
Interest and Bank Debt ($000s)
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Interest on bank debt 2,496 2,823 7,204 7,721
Bank debt outstanding at
period end 208,193 238,800 208,193 238,800
Net bank debt outstanding at
period end(1) 211,276 214,508 211,276 214,508
Net bank debt-to-cash
flow ratio 0.92 1.02 0.92 1.02
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
Cash Flow Netback ($/boe)
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Operating netback, after
hedging 33.89 37.29 34.72 34.46
Management fees - (1.19) (0.25) (1.12)
G&A expenses (1.49) (0.45) (1.61) (1.24)
Unit-based incentive
compensation (0.11) - (0.50) (0.15)
Interest (1.42) (1.56) (1.36) (1.53)
-------------------------------------------
Cash flow netback 30.87 34.09 31.00 30.42
-------------------------------------------------------------------------
Depletion, Depreciation and Accretion Expenses
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Depletion and
depreciation ($000s) 33,213 30,663 97,354 85,353
Accretion of asset retirement
obligation ($000s) 1,247 1,184 3,726 3,385
-------------------------------------------------------------------------
Total DDA ($000s) 34,460 31,847 101,080 88,738
DDA rate per boe ($) 19.63 17.56 19.07 17.56
-------------------------------------------------------------------------
Capitalization
-------------------------------------------------------------------------
September December September
30, 2006 31, 2005 30, 2005
-------------------------------------------------------------------------
Trust unit equity ($000s) 467,817 494,490 487,979
Bank debt ($000s) 208,193 220,519 238,800
Net bank debt (1) ($000s) 211,276 198,351 214,508
Net bank debt-to-equity 0.45 0.40 0.49
Net bank debt-to-trailing 12-month
cash flow 0.92 0.89 1.02
Units outstanding (000s) 77,425 73,977 72,847
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
Distributions
-------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
-------------------------------------------------------------------------
Funds from operations ($000s) 54,107 62,442 163,981 155,812
Distributions declared ($000s) 44,061 34,805 129,926 100,093
Funds from operations
per unit(1) 0.70 0.86 2.16 2.26
Distributions declared per unit 0.57 0.48 1.71 1.44
Weighted average units
outstanding (000s) 77,247 72,345 75,897 68,770
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding.
-------------------------------------------------------------------------
($000s) 2006 2007 2008 2009 2010
-------------------------------------------------------------------------
Office lease(1) 724 2,734 2,580 2,580 2,365
Transportation agreement 325 645 645 83 -
Processing agreement(2) 130 491 469 446 428
Drilling rigs(3) 494 1,975 494 - -
-------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager of which the Trust is
allocated a pro rata share (currently approximately 54 percent) of
the expense on a monthly basis.
(2) Represents a gas processing agreement with a take or pay arrangement
associated with the Addison acquisition.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
QUARTERLY INFORMATION
-------------------------------------------------------------------------
2006 2005
-------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q3 Q2 Q1 Q4 Q3 Q2
-------------------------------------------------------------------------
Revenue, net of
royalties and
transportation costs 75,175 77,352 80,604 94,856 84,833 70,797
Per unit 0.97 1.02 1.08 1.29 1.17 0.99
Funds from operations(1) 54,107 52,210 57,664 65,837 62,442 49,881
Per unit 0.70 0.69 0.77 0.90 0.86 0.70
Net income (loss) 20,473 (5,357) 24,610 30,777 31,710 20,804
Per unit 0.27 (0.07) 0.33 0.42 0.44 0.29
Average oil equivalent
production
(boe/d - 6:1) 19,079 19,012 20,181 20,514 19,710 18,349
-------------------------------------------------------------------------
-----------------------------------------
2005 2004
-------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q1 Q4
-------------------------------------------------------------------------
Revenue, net of
royalties and
transportation costs 60,617 43,110
Per unit 0.97 0.81
Funds from operations(1) 43,489 28,846
Per unit 0.69 0.54
Net income (loss) 15,247 11,754
Per unit 0.24 0.22
Average oil equivalent
production
(boe/d - 6:1) 17,457 12,958
-------------------------------------------------------------------------
(1) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
----------------------
As at As at
September December
30, 2006 31, 2005
(unaudited) (audited)
----------------------
Assets
Current assets
Cash and cash equivalents $ 7,189 $ 1,124
Accounts receivable and other 44,221 79,010
Reclamation reserve (Note 7) 4,294 -
-------------------------------------------------------------------------
55,704 80,134
Reclamation reserve (Note 7) - 3,898
Future income tax asset 3,082 2,136
Property, plant and equipment, net (Note 3) 741,669 748,715
-------------------------------------------------------------------------
$ 800,455 $ 834,883
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 44,076 $ 43,910
Distributions payable to unitholders $ 14,711 14,056
-------------------------------------------------------------------------
58,787 57,966
Bank debt (Note 4) 208,193 220,519
Unit-based incentive compensation (Note 5) 2,007 -
Asset retirement obligations (Note 6) 63,651 61,908
-------------------------------------------------------------------------
332,638 340,393
Unitholders' equity
Unitholders' capital (Note 8) 817,112 753,585
Accumulated income 313,522 273,796
Accumulated distributions (662,817) (532,891)
-------------------------------------------------------------------------
467,817 494,490
-------------------------------------------------------------------------
$ 800,455 $ 834,883
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (Note 10)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Units outstanding (000s) 77,425 73,977
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME
(thousands of dollars, except per unit amounts) (unaudited)
--------------------------------------------
3 Months 3 Months 9 Months 9 Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
--------------------------------------------
Revenue
Oil, natural gas and
liquids sales(1) $ 97,264 $ 108,958 $ 297,207 $ 275,152
Royalty and other income 417 1,717 2,925 4,151
Crown royalties, net of ARTC (16,342) (18,496) (48,414) (45,068)
Freehold and other royalties (5,541) (6,566) (16,660) (15,872)
-------------------------------------------------------------------------
75,798 85,613 235,058 218,363
-------------------------------------------------------------------------
Expenses
Operating 15,265 15,511 46,168 37,915
Transportation costs 623 780 1,927 2,116
General and administrative 2,623 817 8,551 6,245
Unit-based incentive
compensation (Note 5) 193 - 2,626 788
Management fees (Note 2) - 2,162 1,350 5,674
Restructuring fee (Note 2) - - 27,299 -
Interest on bank debt 2,496 2,823 7,204 7,721
Depletion, depreciation
and amortization 33,213 30,663 97,354 85,353
Accretion on asset
retirement obligations 1,247 1,184 3,726 3,385
-------------------------------------------------------------------------
55,660 53,940 196,205 149,197
-------------------------------------------------------------------------
Income before taxes 20,138 31,673 38,853 69,166
-------------------------------------------------------------------------
Income and capital taxes 542 26 (74) (100)
Future income tax
recovery (provision) (207) 11 947 (1,305)
-------------------------------------------------------------------------
Total income and capital taxes 335 37 873 (1,405)
-------------------------------------------------------------------------
Net income 20,473 31,710 39,726 67,761
Accumulated income,
beginning of period 293,049 211,309 273,796 175,258
-------------------------------------------------------------------------
Accumulated income,
end of period $ 313,522 $ 243,019 $ 313,522 $ 243,019
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust unit $ 0.27 $ 0.44 $ 0.52 $ 0.99
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average units
outstanding (000s) 77,247 72,345 75,897 68,770
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) After hedging.
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
--------------------------------------------
3 Months 3 Months 9 Months 9 Months
Ended Ended Ended Ended
September September September September
30, 2006 30, 2005 30, 2006 30, 2005
--------------------------------------------
Operating Activities
Net income $ 20,473 $ 31,710 $ 39,726 $ 67,761
Items not involving cash:
Depletion, depreciation
and amortization 33,213 30,663 97,354 85,353
Accretion on asset
retirement obligations 1,247 1,184 3,726 3,385
Future income tax
provision (recovery) 207 (11) (947) 1,305
Restructuring fee - - 27,159 -
Abandonment and
environmental expenditures (1,033) (1,104) (3,037) (1,992)
Decrease (increase) in
non-cash working capital 6,642 (19,848) 25,786 (35,719)
-------------------------------------------------------------------------
60,749 42,594 189,767 120,093
-------------------------------------------------------------------------
Financing Activities
Distributions to unitholders (43,995) (34,635) (129,271) (96,927)
Issue of Trust units,
net of issue costs 6,671 15,876 33,527 259,274
Increase (decrease) in
bank debt 16,868 (11,300) (12,326) 145,100
Decrease (increase) in
non-cash working capital 1,311 - 2,055 -
-------------------------------------------------------------------------
(19,145) (30,059) (106,015) 307,447
-------------------------------------------------------------------------
Investing Activities
Acquisition of Addison
Energy Inc. - - - (384,994)
Additions to property,
plant and equipment (41,869) (28,961) (86,550) (47,077)
Proceeds from dispositions 14 - 137 -
Reclamation reserve (102) (72) (396) (326)
Decrease (increase) in
non-cash working capital (3,108) 13,232 9,122 7,622
-------------------------------------------------------------------------
(45,065) (15,801) (77,687) (424,775)
-------------------------------------------------------------------------
Increase (decrease) in cash (3,461) (3,266) 6,065 2,765
Cash, beginning of period 10,650 7,142 1,124 1,111
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 7,189 $ 3,876 $ 7,189 $ 3,876
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure
of cash flow information:
Cash paid during the
period for:
Interest $ 2,458 $ 2,799 $ 7,090 $ 7,666
Taxes $ (542) $ (26) $ 74 $ 100
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Nine months ended September 30, 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. RTU's vest one
third on November 30 in each of three years after grant date. PTU's
vest at the end of three years. Compensation expense is recognized
over the vesting period 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 and 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
represent joint venture amounts from NAL Resources. These
transactions are in the normal course of joint venture operations and
are based on the original transactions with third parties.
The Manager provides certain services pursuant to the Management
Contract for which, prior to January 1, 2006, the Trust was required
to pay a monthly base management fee equal to three percent of its
net production revenue and a quarterly performance fee based on the
Trust's overall return compared to the S&P/TSX Capped Energy Trust
Index. Such fees amounted to $2,162,000 for the quarter ended
September 30, 2005 and $5,674,000 for the nine months ended
September 30, 2005. In addition, the Trust paid $1.7 million (2005 -
$0.2 million) for the reimbursement of G&A expenses incurred by the
Manager on behalf of the Trust pursuant to the Management Contract
for the third quarter of 2006, and $5.3 million (2005 - $4.7 million)
year-to-date. The Trust also pays the Manager its share of unit-based
incentive compensation expense when cash compensation is paid to
employees under the terms of the Plan.
On May 31, 2006 the Trust's unitholders approved the restructuring of
the Management Contract with the Manager. Under the restructuring,
the Trust paid 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. Immediately following the payment of the
Restructuring Fee, an affiliate of the Manager subscribed 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 March 1, 2006, the date of the agreement.
Of the $30 million Restructuring Fee, $2.8 million has been allocated
to the administrative assets acquired and capitalized as Property,
Plant and Equipment. The balance of $27.2 million, representing the
elimination of future management and performance fees, has been
recorded as a non-cash charge to income. During 2006, the Trust paid
an interim management fee of $250,000 per month in the first quarter
and $300,000 per month in the second quarter, up to the closing of
the restructuring transaction on May 31, 2006.
3. PROPERTY, PLANT AND EQUIPMENT ("PP&E")
---------------------------------------------------------------------
September 30, December 31,
Net book value as at: 2006 2005
---------------------------------------------------------------------
Oil and natural gas properties, at cost $ 1,294,432 $ 1,204,123
Less: Accumulated depletion and depreciation (552,763) (455,408)
---------------------------------------------------------------------
$ 741,669 $ 748,715
---------------------------------------------------------------------
---------------------------------------------------------------------
During the nine months ended September 30, 2006, the Trust
capitalized $3.5 million (2005 - $3.7 million) of general and
administrative costs and $2.0 million of unit-based incentive
compensation expense (2005 - $0.5 million) 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.
Provided there is no default on the debt, the Trust is restricted,
under the credit facility, from making distributions to its
unitholders in excess of its consolidated operating cash flow during
the eighteen-month period preceding the distribution date.
Amounts are advanced under the credit facility in Canadian dollars by
way of prime interest rate based loans and by issues of bankers'
acceptances and in U.S. dollars by way of U.S. based interest rate
and Libor based loans. The interest charged on advances is at the
prevailing interest rate for bankers' acceptances, Libor loans,
lenders' prime or U.S. base rates plus an applicable margin or
stamping fee. The applicable margin or stamping fee, if any, varies
based on the consolidated debt-to-cash flow ratio of the Trust.
On September 30, 2006 the effective interest rate on amounts
outstanding under the credit facility was 5.11 percent.
5. 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
$788,000 was charged to income in the first nine months of 2005, with
no charge recorded in the third quarter of 2005. During the third
quarter of 2005, $486,000 was capitalized. 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 third quarter of 2006, the Trust accrued $224,000 of unit-
based incentive compensation charges in its accounts, of which
$193,000 has been charged to income and $31,000 relating to
exploitation and development personnel has been capitalized in
Property, Plant and Equipment.
On a year-to-date basis, the Trust has accrued $4.6 million of unit-
based incentive compensation charges in its accounts, of which,
$2.6 million has been charged to income and $2.0 million has been
capitalized. Of the $4.6 million accrued to date, $2.6 million 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
September 30, 2006. This amount is payable in December 2007 and 2008.
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.
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 $63.7 million
as at September 30, 2006 based on a total undiscounted amount of cash
flows required to settle its asset retirement obligations of
$160.3 million (2005 - $160.9 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.
---------------------------------------------------------------------
Nine Nine
Months Months Year
Ended Ended Ended
September September December
30, 2006 30, 2005 31, 2005
---------------------------------------------------------------------
Balance, beginning of period $ 61,908 $ 36,924 $ 36,924
Accretion expense 3,726 3,385 4,582
Liabilities incurred 1,054 23,133 23,374
Liabilities settled (3,037) (1,992) (2,972)
---------------------------------------------------------------------
Balance, end of period $ 63,651 $ 61,450 $ 61,908
---------------------------------------------------------------------
---------------------------------------------------------------------
7. RECLAMATION RESERVE
Certain amendments will be made to a royalty agreement involving the
business of the Trust, which had provided for the establishment of a
reserve ("Reclamation Reserve") to assist in funding future asset
retirement obligations. One of the amendments to be made to the
royalty agreement will provide for the elimination of the requirement
for the Reclamation Reserve. Accordingly, the balance in the reserve
has been reclassified to current assets in advance of the transfer of
funds to the general working capital of the Trust. The Trust
continues to pay ongoing abandonment and reclamation expenditures
from its cash flow from operating activities.
8. UNITHOLDERS' EQUITY
Units Issued:
---------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, 2006 December 31, 2005
--------------------------------------------
(000s) Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning
of period 73,977 $ 753,585 53,064 $ 476,620
Issued under management
agreement restructuring
(Note 2) 1,592 30,000 - -
Issued for cash - - 17,000 232,900
Less: Issue expenses - (29) - (12,333)
Issued from Distribution
Reinvestment Plan 1,856 33,556 3,913 56,398
---------------------------------------------------------------------
Balance, end of period 77,425 $ 817,112 73,977 $ 753,585
---------------------------------------------------------------------
---------------------------------------------------------------------
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As at September 30, 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.
NAL currently has the following WTI oil contracts in place for the
fourth quarter of 2006:
-------------------------------------------------------------------------
Total Bought Sold
Volume Volume Sold Put Put Call Swap
-------- -------- -------- -------- -------- --------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
COLLARS
92 3-way 300 27,600 52.00 57.00 72.50 -
92 3-way 300 27,600 48.00 57.00 72.50 -
92 3-way 300 27,600 48.00 58.50 72.50 -
92 3-way 300 27,600 48.00 57.50 74.00 -
92 3-way 600 55,200 48.00 57.00 72.50 -
92 3-way 300 27,600 48.00 60.00 72.50 -
92 3-way 300 27,600 48.00 60.00 72.50 -
92 3-way 300 27,600 48.00 60.00 74.00 -
92 2-way 300 27,600 - 68.00 80.90 -
92 2-way 300 27,600 - 70.00 84.85 -
92 2-way 300 27,600 - 72.00 87.35 -
61 2-way 500 30,500 - 62.00 68.25 -
-------------------------------------------------------------------------
Weighted
average Collars 3,932 361,700 - 61.23 75.10 -
-------------------------------------------------------------------------
SWAPS
-------------------------------------------------------------------------
61 Swap 500 30,500 - - - 65.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NAL currently has the following WTI oil contracts in place for
fiscal 2007:
-------------------------------------------------------------------------
Total Bought Sold
Volume Volume Sold Put Put Call Swap
-------- -------- -------- -------- -------- --------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
COLLARS
181 2-way 300 54,300 - 70.00 85.85 -
181 2-way 300 54,300 - 72.00 88.10 -
365 2-way 500 182,500 - 62.00 68.25 -
-------------------------------------------------------------------------
Weighted
average Collars 798 291,100 - 65.32 75.18 -
-------------------------------------------------------------------------
SWAPS
-------------------------------------------------------------------------
365 Swap 500 182,500 - - - 65.05
365 Swap 500 182,500 - - - 72.33
-------------------------------------------------------------------------
Weighted
average Swaps 1,000 365,000 - - - 68.69
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place
for the fourth quarter of 2006:
---------------------------------------------------------------------
Total Bought Sold
Volume Volume Put Call Swap
--------- --------- --------- --------- ---------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
COLLARS
92 2-way(1) 2,000 184,000 9.50 14.40 -
61 2-way(1) 3,000 183,000 6.00 8.10 -
61 2-way(1) 1,000 61,000 6.50 8.85 -
61 2-way(1) 1,000 61,000 7.00 8.70 -
---------------------------------------------------------------------
Weighted
average 5,315 489,000 7.50 10.64 -
---------------------------------------------------------------------
SWAPS
---------------------------------------------------------------------
61 Swap 3,000 183,000 - - 6.77
---------------------------------------------------------------------
---------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place
for fiscal 2007:
---------------------------------------------------------------------
Total Bought Sold
Volume Volume Put Call Swap
--------- --------- --------- --------- ---------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
COLLARS
365 2-way(1) 3,000 1,095,000 6.00 8.10 -
365 2-way(1) 1,000 365,000 6.50 8.85 -
365 2-way(1) 1,000 365,000 7.00 8.70 -
365 2-way(1) 1,000 365,000 6.75 8.60 -
---------------------------------------------------------------------
Weighted
average 6,000 2,190,000 6.38 8.41 -
---------------------------------------------------------------------
SWAPS
---------------------------------------------------------------------
365 Swap 3,000 1,095,000 - - 6.77
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Contracts entered into subsequent to quarter end.
The estimated fair value of the above contracts, all of which qualify
for hedge accounting, was a gain of $1,878,800 as at September 30,
2006. The fair value of these instruments is not recorded on the
Balance Sheet.
10. COMMITMENTS
At September 30, 2006 the Trust had the following contractual
obligations and commitments:
---------------------------------------------------------------------
($000s) 2006 2007 2008 2009 2010
---------------------------------------------------------------------
Office lease(1) 724 2,734 2,580 2,580 2,365
Transportation agreement 325 645 645 83 -
Processing agreement(2) 130 491 469 446 428
Drilling rigs(3) 494 1,975 494 - -
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager of which the Trust
is allocated a pro rata share (currently approximately
54 percent) of the expense on a monthly basis.
(2) Represents gas processing agreement under take or pay arrangement
associated with Addison Energy acquisition.
(3) Represents the Trust's share of the minimum payments required
under drilling rig contracts held by NAL Resources.
11. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform to
current period presentation.
TRADING PERFORMANCE
-------------------------------------------------------------------------
For the Quarter Ended
-------------------------------------------------------
Price 30-Sep-06 30-Jun-06 30-Sep-05 30-Jun-05
-------------------------------------------------------------------------
High $ 21.70 $ 20.67 $ 17.80 $ 14.98
Low $ 16.14 $ 18.26 $ 14.31 $ 13.13
Close $ 17.57 $ 20.00 $ 15.95 $ 14.25
Volume 12,786,792 11,319,677 18,992,928 12,790,674
-------------------------------------------------------------------------
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NAL Oil & Gas Trust is an open-end investment trust that generates
distributions through the acquisition, development, production and marketing
of oil, natural gas and natural gas liquids. The Trust owns high quality
assets in Alberta, Saskatchewan and Ontario. Trust units trade on the Toronto
Stock Exchange under the symbol "NAE.UN".
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: 888-223-8792
Fax: (403) 515-3407
Email: Investor.Relations@nal.ca
Website: www.nal.ca