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$6.77 per GJ. NAL's management is
authorized to hedge up to one-third of its annual net production.
- NAL is pleased to welcome Warren Thomson of Manulife Financial to its
board of directors, replacing Leo de Bever who resigned from Manulife
and the Board to pursue a career in Australia.
Commenting on the third quarter, President and Chief Executive
Officer, Andrew Wiswell said: "I am very pleased with our momentum
heading into the fourth quarter. Turnarounds extended until late in the
second quarter and delays and challenges resulted in performance below
plan early in the third quarter. The refocusing and additions to our
capital program demonstrated the quality of our asset base and the
strong execution by our operating teams got us back on track to deliver
production in the mid-range of guidance for full year 2006. We have
invested in facilities, land and seismic to position us to continue to
deliver in the future while retaining a strong balance sheet to continue
to pursue opportunities."
A summary of our performance compared to our January 18, 2006
guidance is outlined in the following table and demonstrates NAL is
clearly on track to meet its original 2006 production and cost targets.
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2006
Nine-Month
2006 Full Year Actual
Guidance Results
As Issued Ending
January 18, September 30, Full Year
2006 2006 Estimate
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Average total
production (boe/d) 19,200 - 19,800 19,420 19,300 - 19,600
Capital
expenditures ($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.
On October 31, 2006 the Federal Government announced proposed
changes to the taxation of income trusts. After a four-year exemption
period, all taxable distributions would be subject to a 31.5 percent tax
at the trust level and such payments to investors would be treated as a
taxable dividend. These provisions will see the total tax burden on
non-resident unitholders increase substantially from the current 15
percent withholding tax. NAL is currently evaluating the overall
implications of these changes and is focusing on continuing to deliver
strong performance from its business and operations.
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At 8:30 a.m. MST (10:30 a.m. EST) on Thursday, November 9, 2006 NAL
will hold a conference call to discuss its third 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
403-398- 9531 within the Calgary area or 1-866-250-4892, toll-free
across North America. The conference will also be accessible by webcast
at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=1634160.
A recorded playback of the call will be available until November 16,
2006 by dialing 416-640-1917 or 1-877-289-8525, reservation 21207156
followed by the number sign.
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When converting natural gas to equivalent barrels of oil (boe)
within this report, NAL uses the widely recognized standard of 6
thousand cubic feet (Mcf) of natural gas to one barrel of oil (bbl).
However, boe's may be misleading, particularly if used in isolation. A
boe conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
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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
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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.
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 and nine-month periods ended September 30, 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, cash flow 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, cash flow 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. Prior to the current quarter, funds from
operations was calculated prior to the change in non-cash working
capital related to operating activities but excluded unpaid unit-based
incentive compensation charges; prior quarters have been restated to
conform with the current period presentation.
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
Consistent with our plans, the Trust had an active development
program during the third quarter across all of its core areas. At the
end of the quarter, four drilling rigs were still active with three
additional rigs contracted to commence in the fourth quarter.
The Trust participated in the drilling of 64 (28.95 net) wells
during the third quarter with a success rate of 99 percent. During this
period, the Trust operated 47 (25.68 net) of the wells drilled.
Third Quarter Drilling Activity
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Crude Oil Natural Gas Service Wells
----------------------------------------------
Gross Net Gross Net Gross Net
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Operated wells 16 6.67 27 17.32 3 1.50
Non-operated wells 2 0.20 14 2.87 0 0
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Total wells drilled 18 6.87 41 20.19 3 1.50
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Dry & Abandoned Total
-------------------------------
Gross Net Gross Net
---------------------------------------------------------
Operated wells 1 0.19 47 25.68
Non-operated wells 1 0.20 17 3.27
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Total wells drilled 2 0.39 64 28.95
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Southeast Saskatchewan Core Area
--------------------------------
With two drilling rigs contracted exclusively for drilling in
Southeast Saskatchewan, this area had an active and successful third
quarter. A total of 19 (7.91 net) wells were drilled.
At Elswick, four (2.0 net) horizontal oil producers and three (1.5
net) vertical water injection wells were drilled during the quarter.
This integrated project, which includes an upgrade to fluid handling and
expansion of oil storage in the area, will continue in the fourth
quarter. At Nottingham, three (0.66 net) horizontal oil producers were
drilled while activity was also concentrated at Alida with six (2.7 net)
horizontal wells drilled during the quarter. In total, including single
wells drilled at Stoughton (0.5 net), Weyburn (0.5 net) and the
non-operated Midale Unit (0.0 net), new wells contributed approximately
650 boe/d of net production to the Trust as an exit rate at the end of
the quarter.
During the fourth quarter, the Trust will sustain its positive
momentum in Southeast Saskatchewan by drilling up to 10 (4.66 net)
relatively low-risk oil wells.
Central Alberta Core Area
-------------------------
Drilling during the third quarter consisted of 12 (3.44 net) wells
concentrated in the Sylvan Lake, Medicine River and Gilby areas and
focused mainly on shallow Edmonton Sands gas, deeper Upper Mannville gas
targets and non-operated Jurassic oil. All wells were cased, completed
and tested. Our Edmonton Sands program performed as expected but the
three (1.5 net) non-operated Medicine River Jurassic oil wells drilled
in the third quarter delivered marginal results. Several Upper Mannville
wells drilled during the quarter targeted Colony gas channels in which
NAL had earlier experienced some success. Upon testing, several of these
Colony zones were not productive but uphole potential is currently
being evaluated and may contribute some incremental production in the
future.
Also during the quarter, results of the Elkton drilling program in
the Garrington/Westward Ho area drilled in the second quarter were
finalized. One of these Elkton wells performed well while two wells had
disappointing oil tests, but had excellent tests uphole in the Mannville
gas, a secondary target. The additional evaluation and testing time,
together with a change in scope of plans to tie-in gas wells versus
planned oil producers, has delayed production from these wells until
later in 2006.
Drilling and recompletion activity in Central Alberta, for the
fourth quarter, will be selective and focused on retaining land tenure,
offset drilling and positioning for future land sales where economics
support these investments. At the end of the third quarter, production
behind pipe was approximately 250 boe/d. Partner and third party
capacity issues delayed approximately 100 boe/d, while 150 boe/d is
attributable to delayed production from our successful Edmonton Sands
program drilled during the second and third quarters with these wells
awaiting completions, acquisition of pipeline right-of-ways or tie-ins.
These wells are expected to be on-stream by year-end 2006.
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 percentage of current production and
future potential concentrated on natural gas.
At Hanna, the Trust completed its Second White Specks program during
the third quarter by drilling seven (6.33 net) wells. These wells
brought the total for the project to 17 wells, compared to 14 budgeted
for 2006, with three more wells planned for the fourth quarter. These
wells are anticipated to be tied-in during the fourth quarter when
pipeline right-of-ways are secured and construction is completed. At the
end of the third quarter, 200 boe/d of gas production is behind pipe in
the Hanna area as a result of the delay in the Second White Specks gas
program and the delay in tying-in a Banff producing well.
At Clive/Lacombe, 13 (8.4 net) wells were drilled out of a 30-well
program targeting gas from the Horseshoe Canyon coals. Facilities
construction, including compression, was completed during the quarter
but weather, surface land issues and regulatory delays delayed
production. Additional drilling is anticipated during the fourth quarter
together with completion, gathering pipelines and a new gas sales line
to Joffre. Production from this area is expected to commence late in the
fourth quarter.
At Lake Erie, 13 (2.61 net) gas wells were drilled during the third
quarter, thereby finishing the 25-well drilling program for the year. As
of the end of the third quarter, 11 of the 25 wells were tied-in and
producing, with seven more expected to be tied-in during the fourth
quarter. Three wells have been suspended pending future recompletion,
one well was abandoned, and three wells will be completed in the spring
of 2007 once weather permits the barges to get back on the lake.
For the nine months year-to-date, the Trust has drilled 130 gross wells (52.41 net) with an overall success rate of 99%.
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Crude Oil Natural Gas Service Wells
----------------------------------------------
Gross Net Gross Net Gross Net
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Year-to-date total
wells drilled 46 15.98 76 34.54 6 1.50
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Dry & Abandoned Total
-------------------------------
Gross Net Gross Net
---------------------------------------------------------
Year-to-date total
wells drilled 2 0.39 130 52.41
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CAPITAL EXPENDITURES
Capital expenditures for the quarter ended September 30, 2006
totaled $41.9 million compared with $28.8 million in the quarter ended
September 30, 2005. For the nine months ended September 30, 2006 capital
expenditures totaled $89.4 million as compared to $46.9 million in the
same period in 2005.
Capital Expenditures ($000s)
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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
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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
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1,519 3,369 8,777 4,191
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Total capital expenditures 41,869 28,826 89,391 46,933
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(1) Includes $2.8 million in assets acquired as part of the management
agreement restructuring.
The Board of Directors of the Trust has approved an updated capital
budget of $120 million for the full year 2006, an increase of $14
million from previous guidance of $103 to $108 million provided in our
August 8, 2006 press release. Included in the increase is approximately
$4 million attributable to higher costs to execute the Trust's planned
exploitation and development program, of which the Lacombe/Clive
Horseshoe Canyon coalbed methane project makes up the major portion;
$1.3 million on minor acquisitions; and up to $8 million allocated to
new higher return projects that will support production in the fourth
quarter of 2006 and the first quarter of 2007.
The Trust has budgeted $12 million of capital for plant and
facilities in 2006, of which $10 million has been spent year-to-date.
These expenditures include the completion of a major facility upgrade at
Elswick to expand tankage and improve fluid handling and throughput in
the Browning, Nottingham and Alida fields. In addition, a significant
portion of this capital was also earmarked for the installation of a
compressor and associated facilities for the Lacombe CBM project, which
is largely completed. The Trust increased its commitment to its core
areas by making major strategic land purchases in areas such as
Garrington, Hanna, Weyburn and Elswick, where it has strong positions.
Looking forward to the fourth quarter, capital expenditures will
target three areas of opportunity: focusing on the Lacombe/Clive coalbed
methane project by continuing to execute on the activities to commence
production from the project by year end 2006; addressing land tenure
issues by supporting gas projects that are earning wells, under offset
notice or are drilling into a land sale; and pursuing oil focused,
low-risk, short cycle time and payout opportunities in the Wilson Creek,
Alberta area as well as the Weyburn, Browning and Star Valley areas in
Southeast Saskatchewan.
As a result of a full management review of capital programs in
August 2006, several oil-weighted and liquids rich gas projects were
substituted for previously targeted gas projects. The new projects
provide a high near-term impact with low execution and tie-in risk. This
substitution for higher value projects, combined with the incremental
capital will result in the Trust drilling approximately 200 (86.5 net)
wells versus the 179 (72.5 net) wells originally planned.
PRODUCTION
The Trust averaged 19,079 boe/d for the three months ended September
30, 2006, three percent lower than the 19,710 boe/d for the comparable
period in 2005. For the nine months ended September 30, production
averaged 19,420 boe/d, a five percent increase over 18,514 boe/d a year
earlier. Production was approximately 465 boe/d lower than plan during
the third quarter due to disappointing drilling results from the
Medicine River area (150 boe/d), unplanned plant outages at the
non-operated Harmattan Plant (225 boe/d), and delay in bringing on its
Garrington/Westward Ho production (90 boe/d). We estimate approximately
600 boe/d was behind pipe at the end of the third quarter and is
expected to be brought on production during the fourth quarter. This
additional production and the Trust's focus on near-term oil
opportunities will increase production in the fourth quarter. We have
already seen a positive trend with an exit rate at September 30, 2006 of
19,600 boe/d with October's actual average production relatively
consistent at 19,540 boe/d. For the full year, the Trust is forecasting
an annual average in the mid-range of its original guidance of 19,200 to
19,800 boe/d.
Average Daily Production Volumes
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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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For the three months ended September 30, 2006, production weighting
was relatively unchanged from the comparable period in 2005 with oil and
natural gas liquids production representing 59 percent and natural gas
41 percent.
Production Weighting
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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%
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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 $96.6 million for
the three months ended September 30, 2006, 11 percent lower than the
third quarter of 2005.
Revenue decreased year-over-year due to lower production volumes and
lower natural gas prices. Compared to the third quarter of 2005,
production in the third quarter of 2006 decreased three percent and
average commodity prices decreased by eight percent.
For the nine-month period ended September 30, 2006 gross revenue
totaled $295.3 million, an increase of eight percent from the comparable
period in 2005. This increase is attributable to a five percent
increase in production from 18,514 to 19,420 boe/d and a three percent
increase in NAL oil equivalent pricing.
Funds from operations tracked revenues in the third quarter of 2006,
down 13 percent in total from the third quarter 2005 and down 19
percent from $0.86 to $0.70, on a per unit basis. For the nine months
ended September 30, 2006, total funds from operations were up five
percent and declined slightly on a per unit basis (from $2.26 to $2.16)
from the comparable period in 2005.
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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
-------------------------------------------------------------------------
OIL MARKETING
NAL sells its crude oil based on refiners' posted prices at
Edmonton, Alberta and Cromer, Manitoba adjusted for transportation and
quality of crude oil at 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 third quarter average crude oil price per barrel, net of
transportation costs, was $71.22, (including $0.01 of hedging losses) or
six percent higher than the $67.28 (including $4.97 of hedging losses)
for the third quarter of 2005. Excluding hedging gains and losses, NAL
realized an average price of $71.23 for third quarter of 2006, as
compared to $72.25 for the comparable quarter in 2005. This decrease of
one percent is attributable to a wider market differential between WTI
and Edmonton posted prices and a seven percent decrease in the Cdn$/US$
exchange rate, offset by a 12 percent increase in WTI. Compared to the
second quarter of 2006, NAL's average oil price remained relatively
consistent at $71.22 compared to $71.35.
For the nine months ended September 30, 2006, NAL's average oil
price was $67.68, 12 percent higher than the comparable period in 2005.
Excluding hedging gains and losses, the average price in 2006 is $67.69
as compared to $62.38 in 2005, an increase of nine percent. This
increase was attributable to a 23 percent increase in WTI, offset by a
seven percent decrease in the Cdn$/US$ exchange rate and a higher market
differential.
Natural gas liquids prices averaged $50.17 per barrel in the third
quarter, comparable with the $51.94 in the third quarter of 2005. For
the nine-month period ending September 30, natural gas liquids pricing
averaged $50.56, eight percent higher than the comparable period in
2005. Pricing for natural gas liquids is linked to crude oil pricing
with some seasonal impacts.
NATURAL GAS MARKETING
Approximately 92 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 eight percent tied to NYMEX or other
indexed referenced prices. Eight percent of the Trust's natural gas
sales is produced 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 September 30, 2006, the Trust's gas sales
averaged $6.22/Mcf (including $0.16/Mcf of hedging gains), a decrease
of 29 percent from the 2005 third quarter price of $8.81/Mcf (including a
hedging loss of $0.28/Mcf). Excluding hedging effects, NAL realized an
average natural gas price of $6.06 for the quarter, as compared to $9.09
for the comparable quarter in 2005, a decrease of 33%. The
quarter-over-quarter decrease in gas prices was attributable to the 38
percent decrease in the benchmark AECO price. Natural gas sales from the
Lake Erie property averaged $7.02/Mcf in the third quarter of 2006,
compared to $11.73/Mcf in 2005, a decrease of 40 percent.
For the nine months ended September 30, 2006, NAL averaged
$7.24/Mcf, after hedging gains of $0.12/Mcf, as compared to $7.97/Mcf in
the corresponding period of 2005, after a hedging loss of $0.10/Mcf.
Excluding hedging effects, NAL's average gas price was $7.12 as compared
to $8.07 in 2005, a decrease of 12 percent. The 12 percent decrease in
the year-to-date average gas price compares to a 17 percent decrease in
the AECO daily spot price, year-over-year. This lower decrease is due to
our Lake Erie gas production and marketing a portion of our gas on a
monthly basis. During the first nine months of 2006, the AECO monthly
price exceeded the daily spot price by an average of 11 percent, the
majority of the differential occurring in the first quarter.
RISK MANAGEMENT
NAL employs risk management practices to assist in managing cash
flows and support capital programs and distributions. NAL's management
is authorized to hedge up to one-third of its annual net production.
NAL's hedging programs tend to be scaled-in, 12 to 15 months forward,
and are normally executed through the last six months of the previous
year or early in the current year. During the third quarter of 2006, NAL
had several financial WTI oil contracts and AECO natural gas contracts
in place, which are described below.
For the oil contracts, settlements are made monthly based on the
average monthly WTI price. NAL has costless three-way options, costless
collar contracts and swaps in place to hedge oil production. Three-way
options 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 it is required to pay the difference
if the WTI price is greater than $72.83 per barrel.
During the third quarter of 2006, an average of 3,499 bbls/d of
crude oil was hedged, resulting in a realized loss of $12,000 and
lowering realized crude oil prices for the quarter by $0.01/bbl. In
addition, 2,000 GJ/d of natural gas were hedged resulting in a realized
gain of $696,000 and increasing average natural gas prices for the
quarter by $0.16/Mcf. Hedging contracts in place during the third
quarter of 2005 negatively affected realized crude oil prices by
$4.97/bbl and natural gas prices by $0.28/Mcf or $5.5 million in
aggregate.
For the nine-month period ended September 30, 2006 an average of
2,901 bbls/d of crude oil was hedged, resulting in the realized loss of
$12,000 in the third quarter. In addition, 2,000 GJ/d of natural gas
were hedged resulting in a realized gain of $1.6 million and increasing
natural gas prices for the period by $0.12/Mcf. Hedging contracts in
place for the corresponding period in 2005 negatively affected crude oil
prices by $2.01/bbl and natural gas price by $0.10/Mcf or $6.4 million
in aggregate.
For the fourth quarter 2006, NAL has hedged an average of 3,932
bbls/d through collars with a weighted average floor of US$61.23 WTI and
a ceiling of US$75.10 WTI, plus 332 bbls/d of swaps fixed at US$65.05
WTI. For 2007, NAL has an average of 798 bbls/d collared for the full
year with a weighted average floor of US$65.32 and a ceiling of
US$75.18, plus 1,000 bbls/d of swaps with an average price fixed at
US$68.69 WTI.
As to natural gas, for the fourth quarter of 2006, NAL has hedged an
average of 5,315 GJ/d through collars with a weighted average floor of
Cdn$7.50/GJ and a ceiling of Cdn$10.64/GJ, plus an average 1,989 GJ/d
swap fixed at Cdn$6.77/GJ. For 2007, NAL has 6,000 GJ/d collared for the
full year with a weighted average floor price of Cdn$6.38/GJ and a
ceiling of Cdn$8.41/GJ, plus a 3,000 GJ/d swap fixed at Cdn$6.77/GJ.
The details of NAL's hedging position are set out in Note 9 to the accompanying Consolidated Financial Statements.
NAL has designated these derivatives as accounting hedges under the
Canadian Institute of Chartered Accountants (the "CICA") accounting
guideline AcG13 and, accordingly, has not recorded the fair value of
these instruments in the consolidated financial statements as at
September 30, 2006. As at September 30, 2006 the unrealized fair value
of these hedges was a gain of $1,878,800.
ROYALTY EXPENSES
Crown, freehold and overriding royalties, net of Alberta Royalty Tax
Credit ("ARTC"), were $21.9 million for the three months ended
September 30, 2006. Expressed as a percentage of gross sales, before
hedging and transportation costs, the net royalty rate was 22.6 percent
for the quarter ended September 30, 2006, up slightly from 21.9 percent
experienced in the comparable period the previous year.
On a year-to-date basis, royalties were $65.1 million, up from $60.9
million in the comparable period of 2005. Expressed as a percentage of
gross sales the royalty rate is consistent year-over-year at 22.0
percent as compared to 21.6 percent in the prior year.
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
For the quarter ended September 30, 2006, operating costs averaged
$8.70 per boe, a two percent increase from the $8.55 for the quarter
ended September 30, 2005. On a year-to-date basis, operating costs
averaged $8.71 for the nine months ended September 30, 2006 compared to
$7.50 for 2005, an increase of 16 percent. The increase in operating
costs in 2006 was budgeted due to competitive industry conditions.
Operating costs per boe for the third quarter are down ten percent
from the second quarter of 2006, consistent with expectations. These
costs are expected to trend lower on a boe basis during the fourth
quarter. Full year 2006 operating costs are expected to range between
$8.50 and $8.70 per boe.
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
For the quarter ended September 30, 2006, NAL's operating netback,
before hedging gains, was $33.50 per boe, a decrease of 17 percent from
$40.34 for the quarter ended September 30, 2005, primarily attributable
to lower natural gas prices.
For the nine-month period ended September 30, 2006, operating
netback before hedging was $34.42 per barrel, a decrease of four percent
from the comparable period of 2005. This decrease was primarily driven
by higher royalties and operating costs.
Operating Netback ($/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
General and administrative ("G&A") expenses include direct costs
incurred by the Trust plus the reimbursement of the Manager's G&A
expenses incurred on the Trust's behalf.
For the three months ended September 30, 2006, G&A expenses were
$2.6 million, compared with $0.8 million in the comparable quarter in
2005. In addition, $1.4 million of G&A costs relating to
exploitation and development activities were capitalized in the third
quarter of 2006 compared with $2.9 million in the third quarter of 2005.
Quarter over quarter, this increase in G&A expenses and decrease in
capitalized G&A is a result of an increase in the capitalization
rate commencing in the third quarter of 2005 following an overall review
of G&A costs. The capitalized G&A for the quarter ended
September 30, 2005 includes a $1.8 million adjustment relating to
expenses incurred prior to June 30, 2005. Overall, on a year-over-year
basis, G&A costs are comparable at $4.1 million for the third
quarter of 2006 compared to $3.7 million for 2005.
For the nine months ended September 30, 2006, total G&A has
increased 21 percent to $12.1 million from $10.0 million. On a
year-to-date basis, $3.5 million of G&A costs relating to
exploitation and development activities were capitalized, compared with
$3.7 million in 2005. G&A expenses have increased to $8.6 million,
year-to-date, compared with $6.2 million in 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
as well as increased compensation necessary to continue to attract and
retain qualified personnel in a highly competitive market.
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
-------------------------------------------------------------------------
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 consistent with the higher capitalized
G&A expenses described above. With the expansion of the Plan and
the introduction of the annual vesting provision for the RTU's in 2006,
the Trust has commenced to record its share of the value associated with
the notional units in its accounts over the vesting period.
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.
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
-------------------------------------------------------------------------
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 to the Trust pursuant to the
Management Contract for which, prior to January 1, 2006, the Trust was
required to pay a monthly base management fee equal to three percent of
its net production revenue and a quarterly performance fee based on the
Trust's overall return compared to the S&P/TSX Capped Energy Trust
Index. Such fees amounted to $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 for 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.
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
Interest expense includes charges on bank borrowings plus standby
fees on the unused portion of the bank credit facility. NAL's average
outstanding bank debt for the third quarter of 2006 was $196.8 million,
as compared to $248.3 million for the third quarter of 2005. NAL's
effective interest rate averaged 4.96 percent in 2006, compared with
4.47 percent in the third quarter of 2005.
For the nine months ended September 30, 2006 NAL's average
outstanding debt was $199.6 million as compared to $206.5 million for
the corresponding period in 2005. NAL's effective interest rate in 2006
averaged 4.75 percent compared with 4.36 percent in 2005.
Interest expense for the three and nine-month periods ended
September 30, 2006 was lower than for the comparable periods in 2005,
primarily due to lower bank debt outstanding in 2006.
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
For the quarter ended September 30, 2006, NAL's cash flow netback
was $30.87 per boe, a nine percent decrease from $34.09 for the
comparable period in 2005. The decrease is primarily due to lower
operating netbacks and increased G&A expenses.
For the nine months ended September 30, 2006 cash flow netback
increased two percent to $31.00 compared to $30.42 in 2005. The increase
is primarily attributable to a decrease in management fees and interest
charges in 2006, offset by higher G&A and unit-based incentive
compensation expenses.
Cash Flow Netback ($/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 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 September 30, 2006, depletion on property,
plant and equipment and accretion on the asset retirement obligation
increased by eight percent over the comparable period in 2005 due to a
12 percent increase in the DDA rate per boe of production partially
offset by a three percent decrease in production volumes.
For the nine months ended September 30, 2006 depletion and accretion
increased by 14 percent over the comparable period due to a five
percent increase in production and a nine percent increase in the DDA
rate per boe of production.
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
-------------------------------------------------------------------------
TAXES
Taxes include provincial capital taxes relating to the Trust and its
subsidiary companies. In the third quarter of 2006, NAL had a future
income tax provision of $0.2 million compared with a recovery of $11,000
in the corresponding period of the prior year.
On a year-to-date basis, NAL had a future income tax recovery of $0.9 million compared to a provision of $1.3 million in 2005.
The Trust is a taxable entity and files a trust income tax return
annually. The Trust's taxable income consists of royalty income,
distributions from a subsidiary trust and interest and dividends from
other subsidiaries, less deductions for the Trust's G&A expenses,
resource allowance, Canadian Oil and Gas Property Expense ("COGPE"), and
issue costs. In addition, Canadian Exploration Expense ("CEE"),
Canadian Development Expense ("CDE") and Undepreciated Capital Cost
("UCC") are incurred and deducted by the Trust's subsidiaries. The Trust
is taxable only on remaining income, if any, that is not distributed to
unitholders. The Trust does not expect to incur any cash income taxes
in 2006.
As at September 30, 2006, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximate $460 million, of which approximately 48
percent represents COGPE and 28 percent UCC, with the remaining balance
represented by CEE, CDE, trust unit issue costs and non-capital loss
carry-forwards.
On October 31, 2006, the Federal Government announced proposed
changes to the taxation of income trusts. If enacted, the proposed
legislation will apply to existing trusts commencing in 2011 and will
generally result in taxation of distributions at the trust level at a
rate of 31.5 percent. NAL is currently assessing the potential
implications to the Trust and will continue to monitor developments in
this area.
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of Trust units and bank debt.
As at September 30, 2006, NAL had 77,425,163 units outstanding,
compared with 73,977,021 units at December 31, 2005. The increase from
December 31, 2005 is attributable to units issued under the distribution
reinvestment program ("DRIP") and units issued in connection with the
restructuring of the Management Agreement.
For the nine months ended September 30, 2006, the distribution
reinvestment and premium distribution reinvestment ("Premium DRIP")
plans resulted in 1,855,788 units being issued at an average price of
$18.08 per unit for total proceeds of $33.6 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 26 percent of monthly distributions over
the past nine months. On March 10, 2006, the Trust announced the
suspension of the Premium DRIP, which resulted in a significant
reduction in the reinvestment participation rate commencing with the
distribution payable in April 2006. The participation rate in the
regular DRIP averaged 15 percent over the three months ended September
30, 2006. The Trust continues to monitor the participation in these
plans in conjunction with its capital requirements.
As at September 30, 2006, the Trust had bank debt of $211.3 million
(net of working capital) compared with $198.4 million at December 31,
2005 and $214.5 million as at September 30, 2005. At the end of the
third quarter, the Trust had a net bank debt-to-equity ratio of 0.45 and
a net bank debt-to-twelve months trailing cash flow ratio of 0.92.
The Trust maintains a $300 million fully secured, extendible,
revolving credit facility. The credit facility has recently been 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 $208.2 million at September 30, 2006
compared with $220.5 million as at December 31, 2005. Of the debt
outstanding at September 30, 2006, $207.0 million was outstanding under
the production facility and $1.2 million under the working capital
facility.
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.
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 September 30, 2006, the Trust reported an Asset Retirement
Obligation ("ARO") balance of $63.7 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 $3.7 million in the first nine months of 2006 ($3.4
million in the first nine months of 2005) and reduced by $3.0 million
for actual abandonment and environmental expenditures incurred in the
first nine months of 2006 ($2.0 million in the first nine months of
2005).
DISTRIBUTIONS TO UNITHOLDERS
The Trust sets distributions based upon commodity prices, financial
market conditions, internal capital investment opportunities and the
resulting impact on taxability and payout ratios. The Trust develops an
annual forecast, which is updated regularly by management. The Board
sets distributions at a level it believes will be sustainable for a
period of time and formally reviews distribution levels quarterly.
During the third quarter, lower commodity prices have reduced funds
from operations and increased payout ratios and net debt levels for the
Trust. Commodity price outlooks remain relatively uncertain for the
fourth quarter and 2007, with oil and gas inventories relatively high.
As a result of these lower commodity prices, the Board of Directors
has decided to reduce monthly distributions from $0.19 to $0.16 per
unit, reversing the $0.03 per unit distribution increase introduced in
October 2005 in response to higher commodity prices experienced a year
ago. This reduced rate will take effect with the distribution to be paid
in December 2006 and will allow the Trust to retain an incremental $2.3
million per month or $27.7 million on an annual basis. It is essential
that NAL maintains its current momentum in its business and operations
and continues to invest meaningful capital to capture value-added
opportunities on its quality asset base.
The lower distribution will allow the Trust to maintain an effective
capital expenditure budget and create additional tax pools for the
Trust. This action will also lower the payout ratio and retain the
Trust's very competitive debt level to position it to take advantage of
opportunities to add assets in the future
For the three months ended September 30, 2006, funds from operations
amounted to $54.1 million compared with $62.4 million for the three
months ended September 30, 2005. NAL declared cash distributions of
$44.1 million ($0.57 per unit) in the third quarter as compared to $34.8
million ($0.48 per unit) in the third quarter of 2005, representing an
81 percent payout ratio for the quarter, compared with the 56 percent
payout ratio in the comparable quarter.
The weighted average number of units outstanding during the third
quarter of 2006 increased by seven percent to 77.2 million from 72.3
million in 2005 as a result of the issue of 1.6 million units in May
2006 to fund the Management Agreement restructuring transaction and
strong unitholder participation in the Trust's distribution reinvestment
programs.
For the nine months ended September 30, 2006 funds from operations
were $164.0 million compared with $155.8 million for the comparable
period in 2005. NAL declared cash distributions of $129.9 million ($1.71
per unit) in this period as compared to $100.1 million ($1.44 per unit)
in 2005, representing a 79 percent payout ratio for the nine months
compared to 64 percent in the comparable period.
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.
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
NAL has entered into several contractual obligations as part of
conducting day-to-day business. NAL has the following commitments for
the next five years:
-------------------------------------------------------------------------
($000s) 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.
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has evaluated the effectiveness of the Trust's financial
reporting disclosure controls and procedures as at September 30, 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 an 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 nine
months ended September 30, 2006.
FUTURE ACCOUNTING CHANGES
Financial Instruments, Other Comprehensive Income, Hedges
---------------------------------------------------------
The CICA issued new accounting standards effective for fiscal year
ends beginning on or after October 1, 2006. The standards address how
and at what amount financial assets, financial liabilities and
non-financial derivatives are to be recognized on the balance sheet and
how the gains and losses are to be presented. An additional financial
statement ("Other Comprehensive Income") will be required. The Trust has
not yet assessed the full impact of these standards on the consolidated
financial statements. However, the Trust anticipates adoption of the
new standards on January 1, 2007.
Dated: November 8, 2006
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 -
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Weighted
average Collars 798 291,100 - 65.32 75.18 -
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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"
Contact Information:
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