CALGARY, ALBERTA--(Marketwire - Nov. 7,
2007) - NAL (TSX:NAE.UN) today announced financial and operational
results that are on target with 2007 guidance on all key measures.
President and CEO Andrew Wiswell said, "We successfully closed the
acquisition of Seneca Energy Canada Inc. (Seneca) and integrated its
operations with NAL. Our 55 percent oil and liquids weighting, active
fourth quarter capital program, and comparatively strong financial
position all position NAL positively for a strong finish to 2007 and
positive momentum into 2008."
THIRD QUARTER HIGHLIGHTS
- Production volume for the third quarter averaged 20,182 barrels of
oil equivalent (boe) per day, an increase of six percent from 19,079 a
year earlier. These volumes included 4,346 boe/d from Seneca for the
month of September (1,450 boe/d for the third quarter) following the
closing of the transaction on August 31, 2007. In addition to these
volumes, NAL has 650 boe/d behind pipe which is scheduled to be tied-in
before year-end. Volumes are expected to continue to grow as we move
through the fourth quarter. Our full-year guidance remains 20,500 -
20,800 boe/d of production.
- Operating costs in the third quarter were $10.40 per boe, driven
primarily by a one-time prior period adjustment of $0.70 per boe in the
quarter. Year-to-date operating costs for the nine months ended
September 30, 2007 were $9.08 per boe and NAL's operating costs are
expected to be lower in the fourth quarter, which is consistent with
historical trends. NAL's guidance remains $8.90 - $9.10 per boe for full
year 2007.
- Total capital expenditures to date were $80.2 million and results
were on plan for the first nine months. An additional $35 - $40 million
will be spent in the fourth quarter for a total of $115 - 120 million in
2007. NAL is currently active with five operated drilling rigs as well
as three non-operated exploration wells, two at Monkman, B.C. and
another at Peppers/Pedley in West Central Alberta. Drilling and
evaluation of these wells should be completed in the fourth quarter,
2007 or early in 2008.
- The $246 million purchase of Seneca was financed primarily by
issuing $125 million in new equity and $100 million in convertible
debentures. At September 30, 2007, net debt totaled $364.9 million
representing a multiple of 1.3 times annualized nine-month cash flow
assuming conversion of the debentures, or 1.7 times when treating the
debentures as debt. NAL has one of the best balance sheets among
Canadian energy trusts, and also has approximately $125 million in
undrawn lines of credit which positions the Trust to make additional
acquisitions as opportunities arise.
- At current commodity prices, NAL's cash flow would not be
materially affected by recently announced revisions to Alberta's royalty
regime. Approximately 44 percent of our production is located in B.C.,
Saskatchewan or Ontario, and most of our wells in Alberta are lower
productivity wells. Based upon October 2007 annualized production,
overall royalty expense would increase less than one percent. We will
continue to evaluate these changes and their implications for future
capital expenditures as the detailed implementation programs are
announced.
At 3:00 pm MST (5:00 pm EST) on Wednesday, November 7, 2007 NAL will
conduct 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 will be open to analysts,
investors and all interested parties. If you wish to participate, call
1-866-542-4238 toll free across North America. A recorded playback of
the call will be available until November 14, 2007 by dialing
1-416-695-5800 or 1-800-408-3053 and entering pass code 3240129#.
The conference call will also be accessible by webcast at http://events.onlinebroadcasting.com/nal/110707/index.php
Notes:
All amounts are in Canadian dollars unless otherwise stated.
When converting natural gas to equivalent barrels of oil within this
report, NAL uses the widely recognized standard of 6 thousand cubic
feet (Mcf) to one barrel of oil (boe). However, boe's may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 Mcf : 1
bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency
at the wellhead.
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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FINANCIAL
Gross revenue, net of royalties $78,573 $75,798 $233,072 $235,058
Net income 7,801 20,473 45,901 39,726(1)
Distributions declared 39,778 44,061 115,261 129,926
Distributions declared per unit 0.48 0.57 1.44 1.71
Cash flow from operating activities 61,266 60,749 170,253 189,767
Payout ratio based on cash flow 65% 73% 68% 68%
Cash flow per unit 0.74 0.79 2.13 2.50
Funds from operations(2) 50,817 54,107 159,208 163,981
Payout ratio based on funds
from operations 78% 81% 72% 79%
Funds from operations per unit 0.61 0.70 1.99 2.16
Average number of units
outstanding (000s) 82,815 77,247 79,982 75,897
Total debt, net of working
capital (3) 364,912 211,276 364,912 211,276
Capital expenditures 34,256 41,869 80,240 89,391
Costs per boe (6:1):
Operating $10.40 $8.70 $9.08 $8.71
General and administrative,
excluding special retention bonus 1.31 1.49 1.76 1.61
General and administrative special
retention bonus 0.06 - 0.17 -
Unit-based incentive compensation 0.22 0.11 0.20 0.50
Management fees - - - 0.25
OPERATING
Daily production
Oil (bbl) 9,193 9,256 9,195 9,254
Natural gas (Mcf) 54,073 47,334 49,601 49,360
Natural gas liquids (bbl) 1,977 1,934 2,057 1,939
Oil equivalent (boe - 6:1) 20,182 19,079 19,519 19,420
Average pricing, net of
transportation charges and before
hedging gains and losses
Liquids:
WTI (US$/bbl) 75.39 70.48 66.19 68.25
NAL average oil (Cdn$/bbl) 74.37 71.23 67.74 67.69
NAL natural gas liquids (Cdn$/bbl) 51.02 50.17 48.18 50.56
NAL average oil and natural gas
liquids (Cdn$/bbl) 70.24 67.59 64.16 64.72
Natural gas:
AECO (Cdn$/Mcf) - daily spot 5.14 5.75 6.54 6.45
AECO (Cdn$/Mcf) - monthly 5.61 6.03 6.81 7.18
NAL natural gas Western Canada
(Cdn$/Mcf) 5.30 5.97 6.63 7.03
NAL natural gas Lake Erie
(Cdn$/Mcf) 6.67 7.02 8.73 8.06
NAL average natural gas (Cdn$/Mcf) 5.40 6.06 6.79 7.12
NAL oil equivalent before hedging
gains (losses) (Cdn$/boe - 6:1) 53.35 54.67 54.23 55.40
Average foreign exchange rate
(Cdn$/US$) 1.0448 1.1212 1.1048 1.1327
Operating netback before hedging
gains (losses) ($/boe) 31.19 33.50 33.30 34.42
Hedging gains (losses) per boe (0.03) 0.39 0.58 0.30
Operating netback ($/boe) 31.16 33.89 33.88 34.72
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(1) Includes one time $27.2 million non-cash management contract
restructuring charge.
(2) See reconciliation of cash flow from operating activities to funds from
operations in the non-GAAP financial measures section
(3) Excludes derivative contracts and future income tax asset
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, 2007 and the audited
Consolidated Financial Statements and MD&A for the year ended
December 31, 2006 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.
NON-GAAP FINANCIAL MEASURES
Throughout this discussion and analysis, Management uses the terms
funds from operations, funds from operations per unit, payout ratio, net
debt to trailing 12 month cash flow, operating netback and cash flow
netback. They are considered useful supplemental measures, as they
provide an indication of the results generated by the Trust's principal
business activities. Management uses the terms to facilitate the
understanding of the results of operations and financial position. These
terms do not have any standardized meaning as prescribed by Canadian
Generally Accepted Accounting Principles ("GAAP"). Investors should be
cautioned 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.
Funds from operations is calculated as cash flow from operating
activities before changes in non-cash working capital. Funds from
operations does not represent operating cash flows or operating profits
for the period and should not be viewed as an alternative to cash flow
from operating activities calculated in accordance with GAAP. Funds from
operations is considered by management to be a more meaningful key
performance indicator of NAL's ability to generate cash to finance
operations and to pay monthly distributions. Funds from operations per
unit is calculated using the weighted average units outstanding for the
period.
Payout ratio is calculated as distributions declared for a period as
a percentage of either cash flow from operating activities or funds
from operations, both measures are stated.
Net debt to trailing 12 months cash flow is calculated as net debt
as a proportion of funds from operations for the previous 12 months.
The following table reconciles cash flows from operating activities to funds
from operations:
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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Cash flow from operating activities 61,266 60,749 170,253 189,767
Add back charge in non-cash working
capital (10,449) (6,642) (11,045) (25,786)
Funds from operations 50,817 54,107 159,208 163,981
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FORWARD-LOOKING INFORMATION
This discussion and analysis contains forward-looking information as
to the Trust's internal projections, expectations or beliefs relating
to future events or future performance. Forward looking information is
typically identified by words such as "anticipate", "continue",
"estimate", "expect", "forecast", "may", "will", "could", "plan",
"intend", "should", "believe", "outlook", "potential", "target", and
similar words suggesting future events or future performance.
In particular, this MD&A contains forward-looking information
pertaining to the following, without limitation; the amount and timing
of cash flows of distributions to unitholders, 2007 production, future
tax treatment of the Trust; future structure of the Trust and its
subsidiaries; the Trust's tax pools; future oil and gas prices; the
amount of future asset retirement obligations; future liquidity and
future financial capacity; future results from operations; cost
estimates and royalty rates; drilling plans; tie in of wells; future
development, exploration, and acquisition and development activities and
related expenditures.
Although NAL believes that the expectations reflected in the
forward-looking information contained in the MD&A, and the
assumptions on which such forward-looking information are made, are
reasonable, readers are cautioned not to place undue reliance on such
forward looking statements as there can be no assurance that the plans,
intentions or expectations upon which the forward-looking information
are based will occur. Such information involves known and unknown risks,
uncertainties and other factors that may cause actual results or events
to differ materially from those anticipated and which may cause NAL's
actual performance and financial results in future periods to differ
materially from any estimates or projections of future performance.
These risk and uncertainties include, without limitation; changes in
commodity prices; unanticipated operating results or production
declines; the impact of weather conditions on seasonal demand and
ability to execute the capital program; risks inherent in oil and gas
operations; imprecision of reserve estimates; limited, unfavorable or no
access to capital markets; the impact of competitors; the lack of
availability of qualified operating or management personnel; ability to
obtain industry partner and other third party consents and approvals,
when required; failure to realize the anticipated benefits of
acquisitions; general economic conditions in Canada, the United States
and globally; fluctuations in foreign exchange or interest rates;
changes in government regulation of the oil and gas industry, including
environmental regulation; changes in the royalty rates, particularly in
light of the Alberta governments review; changes in tax laws; impact of
the new SIFT legislation following the October 31, 2006 announcement by
the Federal government; stock market volatility and market valuations;
OPEC's ability to control production and balance global supply and
demand for crude oil at desired price levels; political uncertainty,
including the risk of hostilities in the petroleum producing regions of
the world; and other risk factors discussed in other public filings of
the Trust including the Annual information Form and MD&A for the
year ended December 31, 2006.
NAL cautions that the foregoing list of factors that may affect
future results is not exhaustive. The forward looking information
contained in the MD&A is made as of the date of this MD&A, and
the Trust does not assume any obligation to publicly update or revise it
to reflect new events or circumstances except as required by law. The
forward looking information contained in the MD&A is expressly
qualified by this cautionary statement.
ACQUISITION OF SENECA ENERGY CANADA INC. ("Seneca")
NAL successfully closed the acquisition of Seneca on August 31, 2007
for a price of $245.1 million plus costs of $0.9 million. The
acquisition added 10.3 million boe proved plus probable reserves and
production averaging 4, 400 boe/d from September 2007 to year end 2007.
This production is weighted 85 percent to natural gas. The transaction
also added 157,287 acres of net undeveloped land and growth
opportunities to the Trust.
The net cash consideration was financed by the issuance of 10.2
million units at a price of $12.20 per unit for proceeds of $125 million
($118.8 million net of issue costs), $100 million in 6.75% convertible
extendible unsecured subordinated debentures ($96 million net of issue
costs), and $31.2 million of bank debt.
DEVELOPMENT ACTIVITIES
The Trust participated in drilling 32 (15.5 net) commercial wells
during the third quarter, with a success rate of 100 percent. At the end
of the quarter, six rigs were drilling and we are expecting to finish
2007 with four to five rigs working.
Third Quarter Drilling Activity
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Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
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Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 20 8.7 8 6.0 0 0 0 0 28 14.7
Non-operated wells 2 0.5 2 0.3 0 0 0 0 4 0.8
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Total wells drilled 22 9.2 10 6.3 0 0 0 0 32 15.5
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YTD Drilling Activity
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Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
----------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 44 20.6 15 10.7 2 1 0 0 61 32.3
Non-operated wells 8 1.0 10 1.1 0 0 0 0 18 2.1
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Total wells drilled 52 21.6 25 11.8 2 1 0 0 79 34.4
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Southeast Saskatchewan
There were 18 (6.7 net) successful horizontal oil wells drilled
during the quarter. Of significance was the 5-11 Bakken well that had a
post stimulation initial production rate of 500 bbls/d (125 bbl/d net).
NAL was also successful in acquiring 6,000 hectares of trend acreage
that the Trust will begin to evaluate in 2008.
A significant turnaround was successfully completed at the
Nottingham gas plant which included upgrading the control system for
future expansion. Preliminary engineering has been completed on a plant
expansion which NAL is considering for 2008. This expansion would
capture the opportunity to process additional third party and owned gas
that will be developed and tied in over the next year.
All wells drilled during the quarter were tied-in and producing at
quarter-end. Three contracted rigs will be drilling continuously across
all of our Saskatchewan operating areas for the remainder of the year.
Gas Focus Areas (Nevis, Lacombe, Hanna, Pine Creek, Drumheller)
There were 10 (6.8 net) successful gas wells drilled during the
quarter in these areas. Five wells were CBM drills on expiring lands
adjacent to our infrastructure in Lacombe, Clive and Hanna. The
remaining wells were part of an ongoing successful Mannville development
in the Hanna and Pine Creek areas.
Wet ground conditions experienced in the second quarter continued
into July which delayed drilling programs. Consequently, there is 250
boe/d net to the Trust behind pipe that will be brought on stream in the
fourth quarter. A budgeted turnaround at NAL's Brent gas plant in July
resulted in a loss of 150 boe/d net for the month and an unscheduled
third party turnaround in September resulted in a loss of 85 boe/d net
for the month.
With the acquisition of Seneca, three significant opportunities (two
in Monkman and one in Peppers) were added to our 2007 drilling program.
All three of these wells were still drilling at the end of the third
quarter and are expected to be rig released during the fourth quarter.
Testing of these wells will likely occur late in the fourth quarter with
the subsequent tie in of any successful wells in the first quarter of
2008. Recompletion work and two drills on Seneca lands around Drumheller
will round out the activity in the area for the fourth quarter.
Central Alberta - (Sylvan Lake, Medicine River, Garrington, Westward Ho)
There were four (1.8 net) successful Mannville gas wells drilled
during the quarter and a recompletion program (seven wells in the third
quarter) is ongoing for Cardium oil across the area. The new well at
8-18 Caroline tested at rates of 3.5 mmcf/d (1.25 mmcf/d net) while two
Cardium recompletions had initial production rates of 125 bbls/d (80
bbls/d net).
As with our gas focused areas in Alberta, wet conditions delayed
surface access in July and as a result there is 400 boe/d net to the
Trust behind pipe that will be brought on stream in the fourth quarter.
CAPITAL EXPENDITURES
Capital expenditures for the quarter ended September 30, 2007 were
consistent with expectations and totaled $34.3 million, compared with
$41.9 million in the quarter ended September 30, 2006. For the nine
months ended September 30, 2007 capital expenditures were on plan and
totaled $80.2 million as compared to $89.4 million in the same period in
2006. Results from the capital program are at or above plan year to
date.
Capital Expenditures ($000s)
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Drilling, completion and production
equipment $26,507 $32,697 $64,356 $61,752
Plant and facilities 2,285 5,792 6,680 9,883
Seismic 32 515 559 2,224
Land 2,672 60 2,762 5,469
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Total exploitation and development 31,496 39,064 74,357 79,328
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Office equipment 231 47 505 3,308(1)
Capitalized G&A 1,051 1,441 3,487 3,515
Capitalized unit-based compensation 274 31 445 1,954
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Total other capital 1,556 1,519 4,437 8,777
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Property acquisitions (dispositions),
net 1,204 1,286 1,446 1,286
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Total capital expenditures and
property acquisitions $34,256 $41,869 $80,240 $89,391
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(1) Includes $2.8 million in assets acquired as part of management agreement
restructuring
NAL's capital spending outlook for the full year 2007 has been
increased from $101 million to $115 - 120 million as a result of adding
the opportunities on the Seneca lands. The remaining capital of $35 - 40
million will be primarily spent on exploration and development activity
in our core areas.
PRODUCTION
Third quarter 2007 production of 20,182 boe/d (18,765 boe/d
excluding Seneca) exceeded production in the comparable period of 2006
by six percent. The third quarter of 2007 includes Seneca production for
the month of September. The average production for September was 23,222
boe/d, which includes 4,346 boe/d related to Seneca.
For the nine months ended September 30, 2007, production at 19,519
boe/d (19,042 boe/d excluding Seneca) exceeded production in the
comparable period of 2006 of 19,420 boe/d. To date, NAL has not
experienced any shut-in due to Enbridge capacity constraints although
trucking volume has increased.
Production volumes (excluding Seneca) were lower in the third
quarter as compared to the first and second quarters of 2007 but in line
with expectations due to forecasted turnarounds and wet lease
conditions carried over from June. An active capital program in the
fourth quarter, recent positive drilling results and the ability to tie
in 650 boe/d of behind pipe volumes are expected to deliver our full
year guidance of 20,500 boe/d to 20,800 boe/d. Specifically, we are
forecasting the fourth quarter to average 23,300 - 23,500 boe/d with an
exit rate of approximately 23,700 boe/d.
Average Daily Production Volumes
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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Oil (bbl/d) 9,193 9,256 9,195 9,254
Natural gas (Mcf/d) 54,073 47,334 49,601 49,360
NGL's (bbl/d) 1,977 1,934 2,057 1,939
Oil equivalent (boe/d) 20,182 19,079 19,519 19,420
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Oil and natural gas liquids totaled 55 percent of production in the third
quarter with natural gas increasing to 45 percent due to the Seneca
acquisition.
Production Weighting
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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Oil 45% 49% 47% 48%
Natural gas 45% 41% 42% 42%
NGLs 10% 10% 11% 10%
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REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs, totaled $99.1 million for the three months
ended September 30, 2007, a three percent increase over the third
quarter of 2006. The increase is attributable to a six percent increase
in production, offset by a two percent decrease in average price per
boe. Compared to the third quarter of 2006, average commodity prices
decreased by two percent for the third quarter of 2007 due to lower
natural gas realized prices, which were partially offset by higher crude
and NGL realized prices.
For the nine month period ended September 30, 2007, revenue after
transportation costs totaled $289.0 million, a decrease of two percent
from the comparable period in 2006. The decrease is attributable to a
two percent decrease in average commodity prices driven by lower natural
gas realized prices.
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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Revenue (1) ($000s) 99,076 95,957 288,996 293,703
$/boe 53.36 54.67 54.23 55.40
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(1) Oil, natural gas and liquid sales less transportation prior to
royalties, and excluding gain/loss on derivative contracts (see Risk
Management).
OIL MARKETING
NAL sells its crude oil based on refiners' posted prices at
Edmonton, Alberta, and Cromer, Manitoba, adjusted for transportation and
the quality of each field battery. The refiners' posted prices are
influenced by the West Texas Intermediate ("WTI") benchmark price,
transportation costs, exchange rates and the supply/demand situation of
particular crude oil quality streams during the year.
NAL's third quarter average Canadian crude oil price per barrel, net
of transportation costs, was $74.37, as compared to $71.23 for the
comparable quarter of 2006. The increase in realized price quarter over
quarter of four percent, or $3.14 per barrel, was primarily driven by a
seven percent increase in WTI (US$/bbl), over the comparable period
(US$75.39 versus US$70.48). In addition, NAL's crude differentials
compared to WTI priced in Canadian dollars increased realized prices,
but were offset by a strengthening Canadian dollar.
For the third quarter of 2007, NAL's realized oil price was 94
percent of WTI in Canadian dollars, an increase of four percent from the
90 percent for the corresponding period in 2006. The increase in the
third quarter of 2007 resulted from a narrower differential occurring
between WTI and Edmonton and Cromer posted prices, due to greater demand
for light crude in Western Canada during that time frame.
For the nine months ended September 30, 2007, NAL's average oil
price was $67.74 per barrel, comparable with the corresponding period in
2006. The realized price remained constant due to differentials
improving from 88 percent in 2006 to 93 percent in 2007, offset by a
three percent decrease in WTI (US$/bbl) and a two percent unfavorable
exchange rate change.
Natural gas liquids prices averaged $51.02 per barrel in the third
quarter of 2007, comparable with the third quarter of 2006. For the nine
month period ending September 30, 2007, natural gas liquids pricing
averaged $48.18, five percent lower than the comparable period in 2006.
NATURAL GAS MARKETING
Approximately 93 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 seven percent tied to NYMEX or other
indexed referenced prices. Seven percent of the Trust's gas sales are
from its Lake Erie property and receives a higher price due to the
proximity to the Ontario and northeastern U.S. markets.
For the three months ended September 30, 2007, the Trust's gas sales
averaged $5.40/Mcf, compared to $6.06/Mcf for the comparable quarter in
2006, a decrease of 11 percent. The quarter-over-quarter decrease in
gas prices was attributable to an 11 percent decrease in the benchmark
AECO prices. Natural gas sales from the Lake Erie property averaged
$6.67/Mcf in the third quarter of 2007, compared to $7.02/Mcf in 2006, a
decrease of five percent.
For the nine months ended September 30, 2007, NAL averaged
$6.79/Mcf, a five percent decrease from the $7.12/Mcf realized in the
comparable period of 2006. The decrease in realized price, despite the
AECO spot increasing by one percent, is attributable to marketing a
portion of gas based on the monthly AECO price, which decreased five
percent year over year. During the nine months ended September 30, 2007,
the spread between the spot and monthly AECO prices was $0.27/Mcf
compared to $0.73/Mcf for the comparable period in 2006.
Average Pricing
(net of transportation charges)
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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Liquids
WTI (US$/bbl) 75.39 70.48 66.19 68.25
NAL average oil (Cdn$/bbl) 74.37 71.23 67.74 67.69
NAL natural gas liquids (Cdn$/bbl) 51.02 50.17 48.18 50.56
Natural Gas (Cdn$/Mcf)
AECO - daily spot 5.14 5.75 6.54 6.45
AECO - monthly 5.61 6.03 6.81 7.18
NAL Western Canada natural gas 5.30 5.97 6.63 7.03
NAL Lake Erie natural gas 6.67 7.02 8.08 8.06
NAL average natural gas 5.40 6.06 6.79 7.12
NAL Oil Equivalent before hedging
(Cdn$/boe - 6:1) 53.35 54.67 54.23 55.40
Average Foreign Exchange Rate
(Cdn$/US$) 1.0448 1.1212 1.1048 1.1327
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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 50 percent of its annual net of royalty
production. NAL's risk management programs are scaled in over time using
a combination of swaps and collars. During the first nine months of
2007, NAL had several financial WTI oil contracts and AECO natural gas
contracts in place.
The following is a summary of the realized gains and losses on risk
management contracts for the quarter and year to date:
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Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
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Average crude volumes hedged (bbl/d) 3,833 3,499 2,816 2,901
Crude oil realized gain (loss)
($000's) $(2,314) $ (12) $ 623 $ (12)
Gain (loss) per bbl hedged $ (6.56) $ (0.04) $ 0.81 $ (0.02)
Average natural gas volumes hedged
(GJ/d) 16,000 2,000 15,505 2,000
Natural gas realized gain ($000's) $ 2,267 $ 696 $ 2,452 $ 1,589
Gain per GJ hedged $ 1.54 $ 3.78 $ 0.58 $ 2.91
Average BOE hedged (boe/d) 6,362 3,815 5,266 3,217
Total realized gain (loss) ($000's) $ (47) $ 684 $ 3,075 $ 1,577
Gain (loss) per boe hedged $ (0.08) $ 1.95 $ 2.14 $ 1.80
Gain (loss) per boe $ (0.03) $ 0.39 $ 0.58 $ 0.30
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The Trust has recorded the fair value of risk management contracts
on the balance sheet effective January 1, 2007 in accordance with new
accounting standards, issued by the Canadian Institute of Chartered
Accountants ("CICA"), addressing financial instruments and hedges. These
standards require all derivative instruments to be recorded on the
balance sheet at fair value, with changes in the fair value recognized
in net income unless specific hedge criteria are met. The Trust has not
designated any of its derivative contracts as effective accounting
hedges, even though the Trust considers all commodity contracts to be
effective economic hedges. Therefore, changes in the fair value of the
derivative contracts are recognized in net income for the period.
The gain on derivative contracts presented in the income statement
includes realized gains and losses, unrealized gains and losses since
January 1, 2007, and a reclassification from other comprehensive income.
The realized gain/loss represents actual cash settlements or receipts
under the respective contracts. The unrealized gain/loss represents the
change in the fair value of the contracts during the period. The
reclassification from other comprehensive income represents the
amortization of the fair value of the contracts on transition to the new
accounting standards, over the term of the contracts. On January 1,
2007, the fair value of the outstanding contracts of $4.5 million was
recorded as an asset with the offset being recorded in accumulated other
comprehensive income, a component of unitholders equity. The amount
recorded in accumulated other comprehensive income will be reclassified
to net income over the term of the derivative contracts, of which $0.9
million was reclassified in the third quarter of 2007 and $3.6 million
year to date.
Fair value is calculated at a point in time based on an
approximation of the amounts that would be received or paid to settle
these instruments, with reference to forward prices and market
valuations provided by third party sources. Accordingly, the magnitude
of the unrealized gain or loss will continue to fluctuate with changes
in commodity prices.
The fair value of the derivatives at September 30, 2007 was a
liability of $1.4 million. The fair value of $1.4 million at September
30, 2007 was comprised of a $5.8 million asset on gas contracts offset
by a $7.2 million liability on oil contracts.
Third quarter income of 2007 includes a $1.5 million unrealized loss
on derivatives resulting from the change in the fair value of the
derivative contracts during the quarter from an asset of $137,000 at
June 30, 2007 to a liability of $1.4 million at September 30, 2007. The
$1.5 million unrealized loss in income was comprised of a $3.1 million
unrealized gain on natural gas contracts, offset by a $4.6 million
unrealized loss on crude oil contracts. The unrealized loss in the third
quarter income is primarily attributable to stronger crude oil forward
prices compared to June 30, 2007 and an increase in derivative
instruments held.
For the nine months ended September 30, 2007, income includes a $5.9
million unrealized loss resulting from the change in the fair value of
the derivative contracts during the nine months. The unrealized loss was
comprised of a $9.9 million loss on oil contracts, offset by a $4.0
million gain on gas contracts.
The gain/loss on derivative contracts for the quarter is as follows:
Gain (loss) on Derivative Contracts ($000's)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Unrealized gain (loss)
Crude oil contracts (4,580) - (9,920) -
Natural gas contracts 3,072 - 4,028 -
----------------------------------------------------------------------------
Unrealized loss (1,508) - (5,892) -
Realized gain (loss) (47) 684 3,075 1,577
Reclassification from other
comprehensive income 874 - 3,647 -
----------------------------------------------------------------------------
Gain (loss) on derivative contracts (681) 684 830 1,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Risk Management Contracts Summary
For the remainder of 2007, NAL has the following risk management contracts
outstanding:
----------------------------------------------------------------------------
CRUDE OIL NATURAL GAS
----------------------------------------------------------------------------
Swap (bbls) 171,700 Swap (GJ) 1,010,000
Swap (bbl/d) 1,866 Swap (GJ/d) 10,978
$US/bbl $67.92 $Cdn/GJ $7.28
Collars (bbls) 193,200 Collars (GJ) 828,000
Collars (bbl/d) 2,100 Collars (GJ/d) 9,000
$US/bbl $63.95 - $70.07 $Cdn/GJ $6.61 - $8.48
Total (bbls) 364,900 Total (GJ) 1,838,000
Total (bbl/d) 3,966 Total (GJ/d) 19,978
----------------------------------------------------------------------------
For 2008, NAL has the following risk management contracts outstanding:
----------------------------------------------------------------------------
CRUDE OIL NATURAL GAS
----------------------------------------------------------------------------
Swap (bbls) 374,500 Swap (GJ) 2,514,500
Swap (bbl/d) 1,023 Swap (GJ/d) 6,870
$US/bbl $77.76 $Cdn/GJ $7.52
Collars (bbls) 383,000 Collars (GJ) 455,000
Collars (bbl/d) 1,046 Collars (GJ/d) 1,243
$US/bbl $71.65 - $79.30 $Cdn/GJ $8.32 - $10.09
Total (bbls) 757,500 Total (GJ) 2,969,500
Total (bbl/d) 2,070 Total (GJ/d) 8,113
----------------------------------------------------------------------------
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $21.8 million for the
three months ended September 30, 2007. Expressed as a percentage of
gross sales, before gain/loss on derivative contracts and transportation
costs, the net royalty rate was consistent with budget at 21.9 percent,
down from 22.6 percent for the same period last year.
On a year-to-date basis, royalties were $63.1 million, down from
$65.1 million in the comparable period of 2006. Expressed as a
percentage of gross sales, the royalty rate is consistent year-over-year
at 21.7 percent as compared to 22.0 percent in the prior year.
On October 25, 2007, Premier Stelmach announced the new royalty
regime for Alberta, effective January 2009. This new framework will
affect NAL in that conventional oil and gas royalties will now be on a
sliding scale that is determined by commodity price and productivity.
Natural gas royalties will increase from a cap of 35 percent to 50
percent, with rate caps at $16.59/GJ. Crude oil royalty rates will
increase from the current maximum of 35 percent to 50 percent, with rate
caps raised to $120/bbl.
The Trust has assessed the impact of these new royalties on its
production and the impact is considered modest given the low level of
crude oil production in Alberta and a significant weighting towards low
producing gas wells. For the nine months ended September 30, 2007, 24
percent of crude oil and 84 percent of natural gas production is from
Alberta.
Royalty Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net royalties ($000s) 21,849 21,883 63,126 65,074
As % of revenue(1) 21.9 22.6 21.7 22.0
$/boe 11.77 12.47 11.85 12.27
----------------------------------------------------------------------------
(1) Oil and natural gas and liquid sales before transportation and gains/
losses on derivative contracts.
OPERATING COSTS
For the quarter ended September 30, 2007, total operating costs were
higher compared to the similar period a year earlier. On a unit of
production basis, operating costs averaged $10.40/boe compared to
$8.70/boe for the quarter ended September 30, 2006. On a year-to-date
basis, operating costs are consistent with guidance at $9.08/boe
compared with $8.71/boe for 2006.
NAL owns and operates facilities associated with a large percentage
of its production, which results in 60 - 70 percent of operating costs
being fixed. This high percentage of fixed costs creates a similar
operating cost profile year over year independent of volume. Costs are
traditionally lower in the first four months of the year and rise
significantly May through September, reflecting high maintenance and
turnaround activity, and then decline through the fourth quarter. The
current full year guidance range ($8.90 - $9.10/boe) was established
with this historical profile and NAL expected costs to be $9.80/boe in
the third quarter due to turn around activities at the Nottingham and
Brent gas plants, as well as overhauls at various field compression
sites.
A one time prior period accounting adjustment of $1.3 million
($0.70/boe for Q3, $0.17/boe for full year 2007) from a third party
processor during the month of August was the main driver in higher than
expected operating costs for the quarter. Consistent with historical
trends, NAL's operating costs are forecast to be lower in the fourth
quarter (excluding Seneca).
The Trust assumed full responsibility for the Seneca properties in
September and has since undertaken significant operating cost related
projects some of which had been deferred during the sale process. These
activities include turnarounds, pipeline replacements, pump changes and
corrosion inhibition programs, which will translate into higher
operating costs for the fourth quarter. In 2008, the Trust expects cost
savings through the integration and synergy of operations with NAL's
current assets and manpower in the Drumheller area.
Near term expectations for higher costs from the Seneca properties
are forecast to be offset by lower overall costs on the Trust base
volumes for the fourth quarter. As a result, full year guidance remains
unchanged at $8.90 - $9.10/boe.
Operating Costs
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating costs ($000s) 19,301 15,265 48,379 46,168
As % of revenue 19.5 15.9 16.7 15.7
$/boe 10.40 8.70 9.08 8.71
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended September 30, 2007, NAL's operating netback,
before realized gains on derivative contracts, was $31.19 per boe, a
decrease of seven percent from $33.50 for the quarter ended September
30, 2006. The decrease was due to lower revenue and higher operating
costs, offset by a decrease in royalties.
Similar trends are noted for the nine month period ended September
30, 2007, with operating netback before hedging at $33.30 per boe, a
decrease of three percent from $34.42 per boe for the comparable period
in 2006.
Operating Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue(1) 53.36 54.67 54.23 55.40
Royalties, net (11.77) (12.47) (11.85) (12.27)
Operating expenses (10.40) (8.70) (9.08) (8.71)
----------------------------------------------------------------------------
Operating netback, before hedging 31.19 33.50 33.30 34.42
Realized gains (losses) on derivative
contracts (0.03) 0.39 0.58 0.30
----------------------------------------------------------------------------
Operating netback, after hedging 31.16 33.89 33.88 34.72
----------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales less transportation
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses include direct costs
incurred by the Trust plus the reimbursement of the Manager's G&A
expenses incurred on the Trust's behalf.
For the three months ended September 30, 2007, G&A expenses were
$2.5 million, compared with $2.6 million in the comparable quarter in
2006. In addition, $1.1 million of G&A costs relating to
exploitation and development activities were capitalized in the third
quarter of 2007, compared with $1.4 million in the third quarter of
2006.
For the nine months ended September 30, 2007, G&A expenses
increased 21 percent to $10.3 million from $8.6 million. In addition, on
a year-to-date basis $3.5 million of G&A costs relating to
exploration and development activities were capitalized, consistent with
2006.
Total G&A increased $1.7 million from $12.1 million to $13.8
million in the first nine months of 2007 due to increased compensation
costs associated with hiring, compensating and retaining staff. Included
in G&A expenses in 2007 is a retention bonus of $0.9 million
associated with an employee retention program established at year end
2006. This represents a $0.17 per boe charge in the first nine months of
2007. Due to the program paying out in two equal installments, at June
30, 2007 and June 30, 2008, the expense for the second half of 2007 is
substantially less than the first six months, resulting in an expected
average of $0.13 per boe for full year 2007. G&A excluding the
retention bonus and unit-based compensation plan is $1.76 per boe for
the first nine months of 2007, consistent with our full year guidance at
$1.75 - $1.95 per boe.
General and Administrative Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
G&A expenses ($000s)
G&A 2,445 2,623 9,420 8,551
Retention bonus 104 - 888 -
----------------------------------------------------------------------------
Expensed G&A 2,549 2,623 10,308 8,551
Capitalized G&A ($000s) 1,051 1,441 3,487 3,515
----------------------------------------------------------------------------
Total G&A ($000s) 3,600 4,064 13,795 12,066
Expensed G&A costs:
G&A, excluding retention bonus ($/boe) 1.31 1.49 1.76 1.61
Retention bonus ($/boe) 0.06 - 0.17 -
----------------------------------------------------------------------------
Total G&A expenses ($/boe) 1.37 1.49 1.93 1.61
As % of revenue 2.6 2.7 3.6 2.9
Per Trust unit ($) 0.03 0.03 0.13 0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
The employees of the Manager are all members of a unit-based
incentive plan (the "Plan"). The Plan results 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 ("RTUs") and Performance Trust Units ("PTUs"). RTUs vest one third
on November 30 in each of three years after grant date. PTUs 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, the PTUs
have 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.
During the third quarter of 2007, the Trust accrued $0.7 million of
unit-based incentive compensation charges as compared to $0.2 million in
the comparable quarter of 2006.
On a year-to-date basis, the Trust has accrued $1.5 million compared
to $4.6 million in the comparable period in 2006. The reduction in
unit-based compensation in 2007 is a reflection of a decrease in the
unit price and a decrease in the performance factors attached to the
PTUs. These reductions have resulted in the reversal of amounts accrued
prior to December 31, 2006 for units vesting in 2007 and 2008.
This calculation is made at the end of each quarter based on the
quarter ending unit price and performance factors. The compensation
charges relating to the units granted are recognized over the vesting
period based on the unit price, number of RTUs and PTUs outstanding, and
the expected performance multiplier. As a result, the expense recorded
in the accounts will fluctuate over time.
At September 30, 2007, the Trust has recorded a liability for
unit-based incentive compensation in the amount of $3.5 million, of
which $1.3 million is expected to be paid in December 2007. The
remaining balance represents the long-term portion of the Trust's
estimated liability for the unit-based incentive plan as at September
30, 2007. This amount is payable in December 2008 and December 2009.
Unit-Based Compensation
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 408 193 1,072 2,626
Capitalized ($000s) 274 31 445 1,954
----------------------------------------------------------------------------
Total unit-based compensation ($000s) 682 224 1,517 4,580
Expensed unit-based compensation:
As % of revenue 0.4 0.2 0.4 0.9
$/boe 0.22 0.11 0.20 0.50
Per Trust unit ($) 0.00 0.00 0.01 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 operator. As a result, a significant portion of the net operating
revenues and capital expenditures during the year is based on joint
amounts from NAL Resources. These transactions are in the normal course
of joint operations and are measured using the fair value established
through the original transactions with third parties.
The Manager provides certain services pursuant to a Management
Contract. During the nine months ended September 30, 2006, the Trust
paid $1.4 million for management fees. The management contract was
restructured effective May 31, 2006, after which no further management
fees are payable.
The Trust paid $2.4 million (2006 - $1.7 million) for the
reimbursement of G&A expenses incurred by the Manager on behalf of
the Trust pursuant to the Management Contract during the third quarter
and $8.4 million (2006 - $5.3 million) year to date. The increase in
charges from the Manager is due to increased compensation charges, see
General and Administrative Expenses. 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 a year
to date basis, $2.2 million was paid in the first quarter of 2007
relating to notional units that vested November 30, 2006.
INTEREST
Interest on bank debt includes charges on borrowings plus standby
fees on the unused portion of the bank credit facility. NAL's average
outstanding bank debt for the third quarter of 2007 was $246.8 million,
compared to $196.8 million for the third quarter of 2006. NAL's
effective interest rate averaged 5.46 percent in 2007, compared with
4.96 percent in the third quarter of 2006. NAL's interest is at floating
rate. The increase in the rate from the third quarter of 2006 is
attributable to rate increases in the market.
For the nine months ended September 30, 2007 NAL's average debt was
$234.9 million, compared to $199.6 million for the corresponding period
in 2006. NAL's effective interest rate in 2007 averaged 5.29 percent
compared with 4.75 percent in 2006 due to rate increases in the market.
Interest on bank debt for the third quarter increased to $3.5
million compared to $2.5 million for the comparable period in 2006, due
to higher interest rates and increased average debt levels in 2007. A
similar trend is noted for the nine months ended September 30, 2007.
Interest on convertible debentures represents interest charges since
the issuance of the debentures on August 28, 2007 at 6.75% of $629,000
and accretion of the debt discount of $158,000.
Interest and Debt ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest on bank debt 3,540 2,496 9,536 7,204
Interest on convertible debentures 787 - 787 -
----------------------------------------------------------------------------
Total interest 4,327 2,496 10,323 7,204
Bank debt outstanding at period end 256,485 208,193 256,485 208,193
Convertible debentures 90,399 - 90,399 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CASH FLOW NETBACK
For the quarter ended September 30, 2007, NAL's cash flow netback
was $27.24 per boe, a 12 percent decrease from $30.87 for the comparable
period in 2006. The decrease is attributable to an eight percent
decrease in operating netback, after hedging, and higher interest
charges.
A similar trend is noted for the nine months ended September 30,
2007 as the cash flow netback decreased to $29.81 per boe from $31.00 in
2006.
Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating netback, after hedging 31.16 33.89 33.88 34.72
Management fees - - - (0.25)
G&A expenses, excluding retention bonus (1.31) (1.49) (1.76) (1.61)
Retention bonus (0.06) - (0.17) -
Unit-based incentive compensation (0.22) (0.11) (0.20) (0.50)
Interest and fees on bank debt (1.91) (1.42) (1.79) (1.36)
Interest on convertible debentures (0.42) - (0.15) -
----------------------------------------------------------------------------
Cash flow netback 27.24 30.87 29.81 31.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital excluding derivative
contracts.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATIONS (DDA)
Depletion of oil and natural gas properties, including the
capitalized portion of the asset retirement obligation, and depreciation
of equipment are provided for on a unit-of-production basis using
estimated proved reserves volumes.
For the quarter ended September 30, 2007, depletion on property,
plant and equipment and accretion on the asset retirement obligation
increased by 29 percent over the comparable period in 2006 due to a six
percent increase in production, the inclusion of property, plant and
equipment from the Seneca acquisition since September 1, 2007 and a ten
percent increase in the DDA rate per boe of production for existing
trust properties. As part of the Seneca acquisition, the Trust acquired
undeveloped land with a fair value of $28 million. These costs have been
excluded from the depletion calculation for the three months ended
September 30, 2007.
Similar trends are noted for the nine months ended September 30, 2007.
The DDA rate will fluctuate period over period depending on the
amount and type of capital expenditures and the amount of reserves
added.
Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 43,254 33,213 112,504 97,354
Accretion of asset retirement
obligation 1,370 1,247 3,969 3,726
Total DDA ($000s) 44,624 34,460 116,473 101,080
DDA rate per boe ($) 24.03 19.63 21.86 19.07
----------------------------------------------------------------------------
TAXES
Taxes include federal and provincial capital and income taxes relating to the Trust and its subsidiary companies.
In the third quarter of 2007, NAL had a future income tax reduction
of $1.1 million compared with $0.2 million provision in the
corresponding period of the prior year.
For the nine months ended September 30, 2007, NAL had a future
income tax reduction of $1.3 million compared to $0.9 million in 2006.
The Trust is a taxable trust and files a trust income tax return
annually. The Trust's taxable income consists of royalty income,
distributions from a subsidiary trust and interest and dividends from
other subsidiaries, less deductions for the Trust's G&A expenses,
Canadian Oil and Gas Property Expense, and issue costs. In addition,
Canadian Exploration Expense ("CEE"), Canadian Development Expense
("CDE") and Undepreciated Capital Cost ("UCC") are incurred and are
deducted by the Trust's subsidiaries. The Trust is taxable only on
remaining income, if any, that is not distributed to unitholders. The
Trust does not expect to incur any cash income taxes in 2007.
As at September 30, 2007, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximate $664.8 million, of which approximately 46
percent represents COGPE and 29 percent UCC, with the remaining balance
represented by CEE, CDE, trust unit issue costs and non-capital loss
carry forwards.
On June 12, 2007, Bill C52, released by the Department of Finance on
December 21, 2006 to implement its October 31, 2006 announcement of the
changes to taxability of Income Trusts, received third reading in the
House of Commons. Under this legislation, distributions to unitholders
will not be deductible by publicly traded income trusts and, as a
result, the Trust will be taxed on its income similar to corporations.
As a result of passing third reading, these measures are now considered
substantially enacted for purposes of Canadian generally accepted
accounting principles. Accordingly, the Trust measured, in the second
quarter of 2007, future income tax assets and liabilities associated
with this new tax. In addition, the Trust re-measured future income tax
assets and liabilities associated with this new tax in the third quarter
of 2007, following the acquisition of Seneca. There is no impact on the
future tax recognized in the financial statements, resulting from the
implementation of this tax legislation as it is expected that all
existing taxable temporary differences will reverse prior to January 1,
2011, the date the taxation changes take effect. Accordingly, all
taxable temporary differences have been recognized at a zero taxation
rate. The scheduling of the reversal of temporary differences is based
on management's best estimates and current assumptions, which may
change.
NET INCOME
Net income is a measure impacted by both cash and non-cash items.
The largest non-cash items impacting the Trust's net income are
depletion, accretion, unrealized gain or loss on derivative contracts
and future income taxes.
Net income for the third quarter of 2007 was $7.8 million compared
to $20.5 million for the comparable period in 2006. The decrease in net
income of $12.7 million is primarily due to a $10 million increase in
depletion, increased operating costs of $4.0 million and increased
interest expense of $1.8 million, partially offset by higher revenues,
net of royalties, of $2.8 million and lower taxes.
Net income for the nine months ended September 30, 2007 of $45.9
million was $6.2 million higher than the same period in 2006. In 2006,
net income includes a non-cash expense of $27.3 million relating to the
restructuring of the management contract. Excluding this amount net
income decreased period over period by $21.1 million, due to a $15
million increase in depletion, increased interest expense of $3.1
million, a $2 million decrease in revenues, net of royalties, and a $2.2
million increase in operating costs, offset by a $1.4 million decrease
in management fees.
Net Income
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net income 7,801 20,473 45,901 39,726
----------------------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of Trust units, bank debt, and convertible debentures.
As at September 30, 2007, NAL had 89,885,824 units outstanding,
compared with 77,971,268 units at December 31, 2006. The increase from
December 31, 2006 is attributable to 10,246,000 units issued on close of
the equity offering on August 31, 2007, and units issued under the
distribution reinvestment program.
Under the equity offering, 10.2 million units were issued at a price
of $12.20 per unit for net proceeds, after issue costs, of $118.8
million.
For the nine months ended September 30, 2007, the distribution
reinvestment ("DRIP") plan resulted in 1,668,561 units being issued at
an average price of $11.83 per unit, for total proceeds of $19.7
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 distribution reinvestment ("Premium DRIP") plan
allows unitholders to exchange such units for a cash payment from the
Plan Broker equal to 102 percent of the monthly distribution.
The Premium DRIP program has been suspended since March 10, 2006.
The participation rate in the regular DRIP averaged 17 percent over
the past nine months, consistent with recent experience. The Trust
continues to monitor the participation in this plan in conjunction with
its capital requirements.
As at September 30, 2007 the Trust had total debt of $364.9 million,
including convertible debentures of $90.4 million and a working capital
deficit of $18.0 million (excluding derivative contracts). Excluding
the convertible debentures, net debt is $274.5 million, compared with
$223.1 million at December 31, 2006, and $211.3 million as at September
30, 2006.
At the end of the third quarter, the Trust had a net debt to equity
ratio of 0.69 compared to 0.49 at December 31, 2006. In addition, at the
end of the third quarter, the Trust had a net debt (excluding
convertible debentures) to twelve months trailing cash flow of 1.28 and a
total net debt to trailing cash flow of 1.70.
In conjunction with the acquisition of Seneca, the Trust increased
its credit facility from $325 million to $400 million. The credit
facility is fully secured, extendible, and revolving and will revolve
until April 30, 2008, 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 $390 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 May 2009.
Bank debt amounted to $256.5 million at September 30, 2007 compared
with $220.8 million as at December 31, 2006. Of the debt outstanding at
September 30, 2007, $256.5 million was outstanding under the production
facility and zero under the working capital facility.
Bank debt increased from $220.8 million as at December 31, 2006 to
$256.5 million as at September 30, 2007 mainly due to $31.2 million
required for the acquisition of Seneca.
On August 28, 2007, in connection with the acquisition of Seneca,
the Trust issued $100 million principal amount of 6.75% convertible
extendible unsecured subordinated debentures. Interest on these
debentures is paid semi-annually in arrears, on February 28 and August
31, and the debentures are convertible at the option of the holder, at
any time, into fully paid trust units at a conversion price of $14.00
per trust unit. The debentures mature on August 31, 2012 at which time
they are due and payable. The debentures are redeemable by the Trust at a
price of $1,050 per debenture on or after September 1, 2010 and on or
before August 31, 2011, and at a price of $1,025 per debenture on or
after September 1, 2011 and on or before August 31, 2012. On redemption
or maturity the Trust may opt to satisfy its obligation to repay the
principal by issuing trust units.
The convertible debentures are classified as debt on the balance
sheet with a portion of the proceeds allocated to equity, representing
the value of the conversion feature. As the debentures are converted to
trust units, a portion of the debt and equity amounts will be
transferred to Unitholders' Capital. The debt component of the
convertible debentures is carried net of issue costs of $4 million. The
debt balance, net of issue costs, accretes over time to the principal
amount owing on maturity. The accretion of the debt discount and the
interest paid to debenture holders are expensed each period as part of
the caption interest and accretion on convertible debentures in the
consolidated statements of income.
The Trust recognized $158,000 of accretion of the debt discount in the third quarter of 2007.
As at November 7, 2007 the Trust has 90,088,068 units and $100 million in convertible debentures outstanding.
Capitalization
----------------------------------------------------------------------------
Sept. 30, 2007 Dec. 31, 2006 Sept. 30, 2006
----------------------------------------------------------------------------
Trust unit equity ($000s) 531,706 456,500 467,817
Bank debt ($000s) 256,485 220,785 208,193
Working capital(1) ($000s) 18,028 2,276 3,083
----------------------------------------------------------------------------
Net debt excluding convertible
debentures 274,513 223,061 211,276
Convertible debentures ($000s) 90,399 - -
----------------------------------------------------------------------------
Net debt 364,912 223,061 211,276
Net debt to equity 0.69 0.49 0.45
Net debt excluding convertible
debentures to trailing 12-month
cash flow (2) 1.28 1.01 0.92
Net debt to trailing 12-month
cash flow (2) 1.70 1.01 0.92
Units outstanding (000s) 89,886 77,971 77,425
----------------------------------------------------------------------------
(1) Working capital excludes derivative contracts and future income tax
asset.
(2) Calculated as net debt divided by funds from operations for the previous
12 months.
Subject to fluctuations in commodity prices, the Trust anticipates
that it will continue to maintain adequate liquidity to fund planned
capital spending during 2007 through a contribution of funds from
operations, funds received from its distribution reinvestment program
and bank borrowings.
ASSET RETIREMENT OBLIGATION
At September 30, 2007, the Trust reported an Asset Retirement
Obligation ("ARO") balance of $75.6 million ($65.6 million at December
31, 2006) for future abandonment and reclamation of the Trust's oil and
gas properties and facilities. The ARO balance was increased by $10.4
million due to the Seneca acquisition, $4.0 million from accretion
expense in the first nine months of 2007 ($3.7 million in the first nine
months of 2006) and reduced by $4.2 million for actual abandonment and
environmental expenditures incurred in the first nine months of 2007
($3.0 million in the first nine months of 2006).
DISTRIBUTIONS TO UNITHOLDERS
For the three months ended September 30, 2007 the Trust distributed
65% of its cash flow from operating activities and 68% year to date, as
compared to 71% in 2006 and 73% in 2005. The Trust has distributed in
excess of its net income each period, due to the non-cash charges
included in net income. Cash flow from operations usually exceeds net
income as net income includes non-cash charges such as depletion,
depreciation, accretion, future income tax expense and unrealized gains
and losses on derivative contracts.
The Trust bases its distributions on the cash flow of the Trust,
commodity prices, financial market conditions, internal capital
investment opportunities and the resulting impact on taxability. 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.
Given that distributions exceed net income, the excess could be
considered to be an economic return of capital to the unitholders. The
Trust's business model is such that it distributes a certain proportion
of its cash flow whilst retaining cash to execute planned capital
programs. As a result of the depleting nature of oil and gas assets some
capital expenditure is required in order to minimize production
declines as well as to invest in facilities and infrastructure. NAL's
2007 capital program is not projected to fully replace production. When
the Trust sets distribution levels depletion expense is not considered
to be indicative of a measure for maintaining productive capacity, and
therefore net income is not considered a driver of distribution levels.
The Trust grows its productive capacity and sustains its cash flow
through acquisition. NAL's productive capacity and future cash flow will
be dependent on its ability to acquire assets and find reserves at
appropriate economics. Acquisitions are financed through equity, debt or
a combination of the two.
Generally, the capital expenditures of the Trust and the
distributions in any given period exceed the cash flow from operating
activities. The shortfall is financed from proceeds from the
distribution reinvestment plan and debt. Over the medium term,
fluctuations in commodity prices, other market factors, or development
opportunities may make it necessary to fund the excess, of distributions
and capital expenditures over cash, from the credit facility. The
credit facility and other sources of cash are expected to be sufficient
to meet NAL's near term capital requirements, sustain distributions and
provide for the resources to pursue potential growth opportunities.
NAL intends to continue to make cash distributions to unitholders.
However, these cash distributions cannot be guaranteed. The intent is to
continue to distribute a certain proportion of cash flow from operating
activities, the level of distributions being dependent on the drivers
of cash flow, namely production and commodity prices. The implication of
this policy is that the Trust is likely to continue to distribute in
excess of its net income for any given period. The future sustainability
of this distribution policy will be dependent upon maintaining
productive capacity through both capital expenditures and acquisitions. A
significant decrease in commodity prices could impact cash from
operating activities, access to credit facilities and the Trust's
ability to fund operations and maintain distributions.
Distributions
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Nine
months months
ended ended
Sept. 30 Sept. 30 Year ended
2007 2007 2006 2005
----------------------------------------------------------------------------
Cash flow from operating activities 61,266 170,253 238,445 195,285
Net income 7,801 45,901 60,198 98,538
Actual cash distributions paid
or payable 39,778 115,261 169,589 142,050
Excess (shortfall) of cash flow from
operating activities over cash
distribution paid 21,488 54,992 68,856 53,235
Percentage of cash flow from
operations distributed 65% 68% 71% 73%
Excess (shortfall) of net income
over cash distributions paid (31,977) (69,360) (109,391) (43,512)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As stated in the non-GAAP measures section of the MD&A, NAL uses
funds from operations as a key performance indicator to measure the
ability of the Trust to generate cash from operations and to pay monthly
distributions.
For the three months ended September 30, 2007, funds from operations
amounted to $50.8 million compared with $54.1 million for the three
months ended September 30, 2006. The decrease is due to increased
operating costs and higher interest charges in 2007. On a per unit basis
funds from operations decreased 13 percent from $0.70 in 2006 to $0.61
due to the increase in units from the equity offering associated with
the acquisition of Seneca.
For the nine months ended September 30, 2007, funds from operations
decreased three percent, and eight percent on a per unit basis from
$2.16 to $1.99, from the comparable period in 2006. The decrease of
three percent is primarily due to lower revenues with a decrease on a
per unit basis due to the equity offering and units issued under the
DRIP.
Funds from Operations
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Funds from operations 50,817 54,107 159,208 163,981
Funds from operations per unit 0.61 0.70 1.99 2.16
Payout ratio based on funds from
operations 78% 81% 72% 79%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
NAL has entered into several contractual obligations as part of
conducting day-to-day business. NAL has the following commitments for
the next five years:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($000s) 2007 2008 2009 2010 2011
----------------------------------------------------------------------------
Office Lease (1) 697 3,206 3,206 2,939 -
Transportation 456 1,007 908 84 -
Processing Agreement (2) 123 469 446 428 414
Drilling rigs (3) 494 494 - - -
Retention bonus (4) - 644 - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including office
space acquired with the Seneca acquisition, 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.
(3) Represents the Trust's share of minimum payments required under drilling
rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.
QUARTERLY INFORMATION
2007 2006 2005
----------------------------------------------------------------------------
($000s, except
per unit and
production
amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Revenue, net of
royalties 78,573 83,268 71,231 75,694 75,798 77,988 81,272 95,643
Per unit 0.95 1.06 0.91 0.97 0.98 1.03 1.08 1.30
Cash flow from
operating
activities 61,266 56,021 52,966 48,678 60,749 60,221 68,798 72,463
Per unit 0.74 0.71 0.68 0.63 0.79 0.79 0.92 0.99
Net income 7,801 21,390 16,710 20,472 20,473 (5,357)(1) 24,610 30,777
Per unit 0.09 0.27 0.21 0.26 0.27 (0.07) 0.33 0.42
Average oil
equivalent
production
(boe/d - 6:1) 20,182 18,946 19,422 19,517 19,079 19,012 20,181 20,514
----------------------------------------------------------------------------
(1) Includes non-cash management restructuring fee of $27.2 million.
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has evaluated the effectiveness of the Trust's financial
reporting disclosure controls and procedures as at September 30, 2007,
and has concluded that such financial reporting disclosure controls and
procedures were effective as at that date.
CHANGES TO INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes to the Trust's internal control over financial
reporting since December 31, 2006 that have materially affected, or are
reasonably likely to materially affect, the Trust's internal control
over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by NAL are disclosed in the
notes to NAL's December 31, 2006 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, 2006.
NEW ACCOUNTING POLICIES
Effective January 1, 2007 the Trust implemented the provisions of
CICA Handbook Section 3855 "Financial Instruments - recognition and
measurement", Section 3861 "Financial Instruments - disclosure and
presentation", Section 3865 "Hedges", Section 1530 "Comprehensive
Income", and certain provisions of Section 3251 "Equity".
These standards address the recognition and measurement of financial
assets, financial liabilities and non-financial derivatives. Financial
instruments are classified into one of four categories, each category
determines how an instrument is measured and when and where gains and
losses are recognized. Instruments are either measured at fair value or
amortized cost, which is determined using the effective interest method.
The hedging standard provides guidance on when and how hedge accounting
may be performed and section 1530 provides standards on the reporting
and display of comprehensive income and its components.
These standards have been applied by the Trust, on a prospective
basis, in accordance with the relevant transitional provisions. For full
details on the implications to the Trust of these standards, see Note 2
to the interim consolidated financial statements.
FUTURE ACCOUNTING CHANGES
The CICA issued new accounting standards; Section 1535 "Capital
Disclosures", Section 3862 "Financial Instruments", and Section 3863
"Financial Instruments - Disclosures". These standards will be effective
January 1, 2008.
Section 1535 "Capital Disclosures" establishes standards for
disclosing information about an entity's capital and how it is managed.
The Section specifies disclosure about objectives, policies and
processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance.
Section 3862 and 3863, establish standards to revise and enhance
disclosure on financial instruments. These standards require entities to
provide disclosure in their financial statements that enable users to
evaluate the significance of financial instruments to the entity's
financial position and performance, and the nature and extent of risks
arising from financial instruments and how the entity manages those
risks. The standards establish presentation guidelines for financial
instruments and non-financial derivatives and deals with the
classification of financial instruments from the perspective of the
issuer, between liabilities and equity, the classification of related
interest, dividends, losses and gains, and the circumstances in which
financial assets and liabilities are offset.
The Trust has not yet assessed the impact of these standards on its financial statements.
Dated: November 7, 2007
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 6,092 $ 6,295
Accounts receivable and other 52,613 44,467
Derivative contracts (Note 4) 3,394 -
Future income tax asset 1,344
----------------------------------------------------------------------------
63,443 50,762
Derivative contracts (Note 4) 2,437 -
Future income tax asset 3,089 3,345
Property, plant and equipment, net (Notes 2
and 3) 971,439 742,795
----------------------------------------------------------------------------
$ 1,040,408 $ 796,902
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 62,351 $ 40,563
Distributions payable to unitholders 14,382 12,475
Derivative contracts (Note 4) 6,650 -
----------------------------------------------------------------------------
83,383 53,038
Derivative contracts (Note 4) 552 -
Convertible debentures (Note 6) 90,399 -
Bank debt (Note 5) 256,485 220,785
Unit-based incentive compensation (Note 7) 2,234 1,005
Asset retirement obligations (Note 8) 75,649 65,574
----------------------------------------------------------------------------
508,702 340,402
Unitholders' equity
Unitholders' capital (Note 9) 963,180 824,986
Equity component of convertible debentures
(Note 6) 5,759 -
Deficit (437,846) (368,486)
Accumulated other comprehensive income 613 -
----------------------------------------------------------------------------
Deficit and accumulated other
comprehensive income (437,233) (368,486)
----------------------------------------------------------------------------
Unitholders' equity 531,706 456,500
----------------------------------------------------------------------------
Liabilities and unitholders' equity $ 1,040,408 $ 796,902
----------------------------------------------------------------------------
Commitments (Note 10)
Units outstanding (000s) 89,886 77,971
----------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue
Oil, natural gas and liquids
sales $ 99,767 $ 96,580 $ 290,878 $ 295,630
Crown royalties (15,874) (16,342) (45,660) (48,414)
Freehold and other royalties (5,975) (5,541) (17,466) (16,660)
----------------------------------------------------------------------------
77,918 74,697 227,752 230,556
Gain (loss) on derivative
contracts (Note 4):
Realized gain (loss) (47) 684 3,075 1,577
Unrealized loss (1,508) - (5,892) -
Reclassification from other
comprehensive income 874 - 3,647 -
----------------------------------------------------------------------------
(681) 684 830 1,577
Royalty and other income 1,336 417 4,490 2,925
----------------------------------------------------------------------------
78,573 75,798 233,072 235,058
----------------------------------------------------------------------------
Expenses
Operating 19,301 15,265 48,379 46,168
Transportation 691 623 1,882 1,927
General and administrative 2,549 2,623 10,308 8,551
Unit-based incentive
compensation (Note 7) 408 193 1,072 2,626
Management fees - - - 1,350
Restructuring fee - - - 27,299
Interest on bank debt 3,540 2,496 9,536 7,204
Interest and accretion on
convertible debentures 787 - 787 -
Depletion, depreciation and
amortization 43,254 33,213 112,504 97,354
Accretion on asset
retirement obligations 1,370 1,247 3,969 3,726
----------------------------------------------------------------------------
71,900 55,660 188,437 196,205
----------------------------------------------------------------------------
Income before taxes 6,673 20,138 44,635 38,853
Income and capital taxes
(provision) 25 542 (83) (74)
Future income tax reduction
(provision) 1,103 (207) 1,349 947
----------------------------------------------------------------------------
Total income and capital
taxes 1,128 335 1,266 873
----------------------------------------------------------------------------
Net income 7,801 20,473 45,901 39,726
Other comprehensive income:
Reclassification to net
income, net of tax (Notes
4 and 9) (613) - (2,559) -
----------------------------------------------------------------------------
Comprehensive Income 7,188 20,473 43,342 39,726
----------------------------------------------------------------------------
Deficit, beginning of period (405,869) (325,707) (368,486) (259,095)
Net income 7,801 20,473 45,901 39,726
Distributions declared (39,778) (44,061) (115,261) (129,926)
----------------------------------------------------------------------------
Deficit, end of period $ (437,846) $ (349,295) $ (437,846) $ (349,295)
----------------------------------------------------------------------------
Net income per Trust unit -
basic and diluted (Note 9) $ 0.09 $ 0.27 $ 0.57 $ 0.52
----------------------------------------------------------------------------
Weighted average units
outstanding (000s) 82,815 77,247 79,982 75,897
----------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net income $ 7,801 $ 20,473 $ 45,901 $ 39,726
Items not involving cash:
Depletion, depreciation and
amortization 43,254 33,213 112,504 97,354
Accretion on asset
retirement obligations 1,370 1,247 3,969 3,726
Unrealized loss on
derivative contracts 1,508 - 5,892 -
Reclassification from other
comprehensive income (874) - (3,647) -
Future income tax provision
(reduction) (1,103) 207 (1,349) (947)
Non-cash accretion expense
on convertible debentures 158 - 158 -
Restructuring fee - - - 27,159
Abandonment and
environmental expenditures (1,297) (1,033) (4,220) (3,037)
Change in non-cash working
capital 10,449 6,642 11,045 25,786
----------------------------------------------------------------------------
61,266 60,749 170,253 189,767
----------------------------------------------------------------------------
Financing Activities
Distributions to unitholders (38,050) (43,995) (113,355) (129,271)
Issue of Trust units, net of
issue costs 125,029 6,671 138,194 33,527
Increase (decrease) in bank
debt 22,968 16,868 35,700 (12,326)
Issue of convertible
debentures 96,000 - 96,000 -
Change in non-cash working
capital - 1,311 915 2,055
----------------------------------------------------------------------------
205,947 (19,145) 157,454 (106,015)
----------------------------------------------------------------------------
Investing Activities
Acquisition of Seneca Energy
Canada Inc. (Note 2) (246,728) - (246,728) -
Additions to property, plant
and equipment (33,052) (40,569) (78,794) (85,127)
Property acquisitions (1,204) (1,300) (1,472) (1,423)
Proceeds from dispositions - 14 26 137
Reclamation reserve - (102) - (396)
Change in non-cash working
capital 14,794 (3,108) (942) 9,122
----------------------------------------------------------------------------
(266,190) (45,065) (327,910) (77,687)
----------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents 1,023 (3,461) (203) 6,065
Cash and cash equivalents,
beginning of period 5,069 10,650 6,295 1,124
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 6,092 $ 7,189 $ 6,092 $ 7,189
----------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid (received) during
the period for:
Interest $ 4,816 $ 2,458 $ 12,136 $ 7,090
Taxes $ (25) $ (542) $ 83 $ 74
----------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Nine months ended September 30, 2007
(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, 2006, except
for the implementation of new standards addressing financial
instruments, hedging and comprehensive income as described below. 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, 2006.
Financial Instruments, Hedges, Comprehensive Income
Effective January 1, 2007 the Trust implemented the provisions of
CICA Handbook Section 3855 "Financial Instruments - recognition and
measurement", Section 3861 "Financial Instruments - disclosure and
presentation", Section 3865 "Hedges", Section 1530 "Comprehensive
Income" and certain provisions of Section 3251 "Equity".
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial derivatives.
Financial instruments are classified into one of four categories, each
category determines how an instrument is measured and when and where
gains and losses are recognized. Instruments are either measured at fair
value or amortized cost, which is determined using the effective
interest method. Section 3865 provides guidance on when and how hedge
accounting may be used. Section 1530 provides standards on the reporting
and display of comprehensive income and its components. Other
comprehensive income comprises revenues, expenses, gains and losses not
included in net income. Section 3251 provides guidance on the
presentation and disclosure of the components of equity, including
accumulated other comprehensive income.
These standards have been applied on a prospective basis, in accordance with the relevant transitional provisions.
The Trust has entered into certain derivative contracts in order to
reduce its exposure to market risks from fluctuations in commodity
prices. These instruments are not used for trading or speculative
purposes. In accordance with Section 3855, all derivative instruments
are recorded on the balance sheet at fair value, with changes in the
fair value recognized in net income, unless specific hedge criteria are
met.
The Trust has not designated its derivative contracts as effective
accounting hedges under Section 3865, even though the Trust considers
all commodity contracts to be effective economic hedges. Therefore,
changes in the fair value of the derivative instruments are recognized
in net income for the period. Proceeds and costs realized from holding
the derivative contracts are recognized in net income at the time each
transaction under a contract is settled.
On January 1, 2007, the Trust had derivative contracts in place with
a fair value of $4.5 million. The transitional provisions of the new
standards allow for NAL's derivatives to be recorded as an asset on
January 1, 2007 with the offset being recorded in accumulated other
comprehensive income ("AOCI"), a component of unitholders' equity. The
amount recorded in AOCI will be reclassified to net income over the
remaining term of the derivatives.
Accordingly, on January 1, 2007, the fair value of the derivatives
of $4.5 million was recorded as an asset on the balance sheet with a
corresponding increase in AOCI.
The fair value of these derivative instruments is based on an
approximation of the amounts that would be received or paid to settle
these instruments at the end of the period, with reference to forward
prices and market valuations provided by third party sources.
Transaction costs are frequently attributed to the issue of a
financial asset or liability. Section 3855 requires that such
transaction costs incurred related to held for trading financial
instruments be expensed immediately. For other financial instruments, an
entity can adopt an accounting policy of either expensing transaction
costs as they occur or adding such transaction costs to the fair value
of the financial instrument. The Trust has chosen a policy of adding
transaction costs to the fair value initially recognized for financial
assets and liabilities. In accordance with this policy convertible
debentures are presented net of issue costs of $4 million.
In accordance with Section 3855, bank debt is presented net of
deferred interest payments, with interest recognized in net income on an
effective interest basis. Previously, interest was recognized on a
straightline basis with the deferred amount included in accounts
receivable. There was no impact at January 1, 2007 resulting from this
change.
2. ACQUISITION
On August 31, 2007 the Trust acquired all the issued and outstanding
shares of Seneca Energy Canada Inc. ("Seneca"), which has interests in
oil and natural gas properties and undeveloped land in East Central
Alberta, Northeast British Columbia and Saskatchewan. The results of
operations from these properties have been included in the consolidated
financial statements commencing September 1, 2007. The transaction was
accounted for using the purchase method of accounting with the fair
values assigned to net assets and consideration paid as follows:
Net assets acquired:
----------------------------------------------------------------------------
Working capital deficiency (including bank indebtedness of $718) (4,571)
Property, plant and equipment 260,937
Asset retirement obligations (10,356)
----------------------------------------------------------------------------
246,010
----------------------------------------------------------------------------
Consideration:
----------------------------------------------------------------------------
Cash 245,110
Acquisition costs 900
----------------------------------------------------------------------------
246,010
----------------------------------------------------------------------------
The above amounts are estimates made by management based on
currently available information. Amendments may be made to the purchase
allocation as cost estimates and balances are finalized.
3. PROPERTY, PLANT AND EQUIPMENT
----------------------------------------------------------------------------
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Oil and natural gas properties, at
cost $1,635,002 $1,293,854
Less: Accumulated depletion and
depreciation (663,563) (551,059)
----------------------------------------------------------------------------
$971,439 $742,795
----------------------------------------------------------------------------
Costs associated with undeveloped land of $28 million (2006 - $nil)
have been excluded from the depletion calculation for the nine months
ended September 30, 2007.
Future development costs for proved reserves of $37.4 million (2006 -
$49.3 million) have been included in the depletion calculation.
During 2007, the Trust capitalized $3.5 million (2006 - $4.3
million) of general and administrative costs and $0.4 million (2006 -
$1.7 million) of unit based incentive compensation that were directly
related to exploitation and development programs.
4. DERIVATIVE CONTRACTS AND RISK MANAGEMENT
Commodity Price Risk Management
NAL employs risk management practices to assist in managing cash
flows and support capital programs and distributions. NAL's management
is authorized to hedge up to 50% of its annual net production. NAL's
risk management programs tend to be scaled-in over time using a
combination of swaps and collars.
As at September 30, 2007, the Trust had entered into the following
derivatives to protect its cash flow from the volatility of oil and
natural gas commodity prices.
For the balance of 2007, NAL has the following WTI oil contracts in place:
Total Bought Sold
Volume Volume Put Call Swap
----------------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
Oct-Dec 2-way 500 46,000 62.00 68.25 -
Oct-Dec 2-way 200 18,400 64.00 71.00 -
Oct-Dec 2-way 300 27,600 62.00 69.75 -
Oct-Dec 2-way 200 18,400 63.00 68.50 -
Oct-Dec 2-way 200 18,400 62.50 69.50 -
Oct-Dec 2-way 200 18,400 64.00 70.45 -
Oct-Dec 2-way 100 9,200 66.00 72.25 -
Oct-Dec 2-way 100 9,200 67.00 71.75 -
Oct-Dec 2-way 100 9,200 68.00 71.50 -
Oct-Dec 2-way 100 9,200 68.00 72.00 -
Oct-Dec 2-way 100 9,200 71.00 74.50 -
----------------------------------------------------------------------------
Weighted Average Collars 193,200 63.95 70.07 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
Oct-Dec Swap 100 9,200 - - 69.10
Oct-Dec Swap 500 46,000 - - 65.05
Oct-Dec Swap 500 46,000 - - 72.33
Oct-Dec Swap 300 27,600 - - 61.07
Oct-Dec Swap 100 9,200 - - 69.00
Oct-Dec Swap 100 9,200 - - 69.30
Oct-Dec Swap 100 9,200 - - 70.14
Oct-Dec Swap 100 9,200 - - 72.80
Nov-Dec Swap 100 6,100 - - 71.00
----------------------------------------------------------------------------
Weighted Average Swaps 171,700 - - 67.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the balance of 2007, NAL has the following AECO natural gas contracts in
place:
Total Bought Sold
Volume Volume Put Call Swap
----------------------------------------------------------------------------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
Oct-Dec 2-way 3,000 276,000 6.00 8.10 -
Oct-Dec 2-way 1,000 92,000 6.50 8.85 -
Oct-Dec 2-way 1,000 92,000 7.00 8.70 -
Oct-Dec 2-way 1,000 92,000 6.75 8.60 -
Oct-Dec 2-way 2,000 184,000 7.00 8.70 -
Oct-Dec 2-way 1,000 92,000 7.25 8.51 -
----------------------------------------------------------------------------
Weighted Average Collars 828,000 6.61 8.48 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
Oct-Dec Swap 3,000 276,000 - - 6.77
Oct-Dec Swap 1,000 92,000 - - 7.90
Oct-Dec Swap 1,500 138,000 - - 7.20
Oct-Dec Swap 1,500 138,000 - - 7.43
Nov-Dec Swap 2,000 122,000 - - 7.26
Nov-Dec Swap 2,000 122,000 - - 7.60
Nov-Dec Swap 2,000 122,000 - - 7.40
----------------------------------------------------------------------------
Weighted Average Swaps 1,010,000 - - 7.28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL currently has the following WTI oil contracts in place for fiscal 2008:
Total Bought Sold
Volume Volume Put Call Swap
----------------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
January-June 2-way 200 36,400 64.00 72.26 -
January-March 2-way 100 9,100 66.00 71.90 -
January-June 2-way 200 36,400 68.50 73.00 -
January-June 2-way 100 18,200 70.00 76.25 -
April-June 2-way 100 9,100 69.00 74.25 -
January-March 2-way 100 9,100 68.00 73.60 -
January-March 2-way 100 9,100 68.00 74.35 -
January-June 2-way 100 18,200 69.00 74.00 -
January-June 2-way 100 18,200 70.00 75.05 -
January-June 2-way 100 18,200 70.00 75.00 -
January-December 2-way 100 36,600 70.50 75.50 -
January-June 2-way 100 18,200 71.00 78.50 -
January-June 2-way 100 18,200 72.00 78.00 -
January-June 2-way 100 18,200 73.00 79.00 -
January-June 2-way 100 18,200 75.00 81.00 -
January-December 2-way 100 36,600 76.00 87.00 -
July-December 2-way 100 18,400 75.00 85.50 -
January-December 2-way 100 36,600 83.00 100.00 -
----------------------------------------------------------------------------
Weighted Average Collars 383,000 71.65 79.30 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
January-March Swap 100 9,100 - - 69.35
January-March Swap 100 9,100 - - 71.30
January-June Swap 100 18,200 - - 73.47
January-June Swap 100 18,200 - - 72.50
April-June Swap 100 9,100 - - 71.90
January-December Swap 100 36,600 - - 71.00
January-December Swap 100 36,600 - - 73.25
January-December Swap 100 36,600 - - 73.50
January-June Swap 100 18,200 - - 76.30
January-June Swap 100 18,200 - - 78.00
January-December Swap 100 36,600 - - 79.10
January-December Swap 100 36,600 - - 80.75
January-December Swap 100 36,600 - - 83.00
January-December Swap 100 36,600 - - 87.10
January-June Swap 100 18,200 - - 92.00
----------------------------------------------------------------------------
Weighted Average Swaps 374,500 - - 77.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place for
fiscal 2008:
Total Bought Sold
Volume Volume Put Call Swap
----------------------------------------------------------------------------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
January-March 2-way 2,000 182,000 8.40 10.25 -
January-March 2-way 1,000 91,000 8.40 10.15 -
January-March 2-way 1,000 91,000 8.40 10.40 -
January-March 2-way 1,000 91,000 8.00 9.40 -
----------------------------------------------------------------------------
Weighted Average Swaps 455,000 8.32 10.09 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
January-March Swap 1,000 91,000 - - 8.90
January-March Swap 1,500 136,500 - - 7.20
January-March Swap 1,000 91,000 - - 9.13
January-December Swap 2,000 732,000 - - 7.26
January-December Swap 2,000 732,000 - - 7.60
January-December Swap 2,000 732,000 - - 7.40
----------------------------------------------------------------------------
Weighted Average Swaps 2,514,500 - - 7.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair Values
The carrying amount of the Trust's financial instruments, including
accounts receivable, accounts payable and accrued liabilities and
distributions payable, approximate their fair value due to their short
term to maturity.
The Trust's bank debt and cash equivalents bear interest at a
floating market rate and, accordingly, the fair market value
approximates the carrying amount.
The fair value of the Trust's convertible debentures at September 30, 2007 was $97.5 million.
Derivative contracts are recorded at fair value on the balance sheet
as current or long-term, assets or liabilities, based on their fair
values on a contract by contract basis.
----------------------------------------------------------------------------
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Current unrealized gain on derivative
contracts $ 3,394 $ -
Current unrealized loss on derivative
contracts (6,650) -
Long-term unrealized gain on
derivative contracts 2,437 -
Long-term unrealized loss on
derivative contracts (552) -
----------------------------------------------------------------------------
Net unrealized loss on derivative
contracts $(1,371) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On transition to Section 3865 on January 1, 2007, the fair value of
the outstanding contracts of $4.5 million was recorded in accumulated
other comprehensive income, with related tax of $1.3 million, and will
be transferred to net income over the term of the respective contracts.
During the first nine months of 2007, $3.6 million has been reclassified
to net income and is included in the gain (loss) on derivative
contracts.
As at September 30, 2007, the total fair value of derivative
contracts was a liability of $1.4 million. The change in the fair value
for the nine months of $5.9 million has been recognized as an unrealized
loss in the income statement.
The following table reconciles the movement in the fair value of the Trust's
derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Unrealized gain, beginning of period $ 137 $ - $ - $ -
Unrealized gain on adoption of new
accounting standards (Note 1) - - 4,521 -
Unrealized loss, end of period (1,371) - (1,371) -
----------------------------------------------------------------------------
Unrealized loss (1,508) - (5,892) -
Realized gain (loss) in the period (47) 684 3,075 1,577
Reclassification from other
comprehensive income 874 - 3,647 -
----------------------------------------------------------------------------
Gain (loss) on derivative contracts $ (681) $ 684 $ 830 $ 1,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. BANK DEBT
In conjunction with the acquisition of Seneca, the Trust, through
its subsidiary NAL Ventures Trust, increased its credit facility to $400
million from $325 million. The facility is fully secured, extendible,
and is a revolving term credit facility with a syndicate of Canadian
chartered banks. This facility consists of a $390 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 will
revolve until April 30, 2008 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
2008, 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 May 2009 with a final residual payment
in May 2010.
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. based 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, 2007, the effective interest rate on amounts outstanding under the credit facility was 5.78 percent.
6. CONVERTIBLE DEBENTURES
On August 28, 2007 the Trust issued $100 million principal amount of
6.75% convertible extendible unsecured subordinated debentures, at a
price of $1,000 per debenture. Interest on these debentures is paid
semi-annually in arrears, on February 28 and August 31, and the
debentures are convertible at the option of the holder at anytime into
trust units at a conversion price of $14.00 per unit. The debentures
mature on August 31, 2012 at which time they are due and payable. The
debentures are redeemable by the Trust at a price of $1,050 per
debenture on or after September 1, 2010 and on or before August 31,
2011, and at a price of $1,025 per debenture on or after September 1,
2011 and on or before August 31, 2012. On redemption or maturity the
Trust may opt to satisfy its obligation to repay the principal by
issuing trust units.
The debentures are classified as debt on the balance sheet with a
portion of the proceeds allocated to equity, representing the value of
the conversion feature. As the debentures are converted to trust units, a
portion of the debt and equity amounts will be transferred to
Unitholders' capital. The debt component of the convertible debentures
is carried net of issue costs of $4 million. The debt balance, net of
issue costs, accretes over time to the principal amount owing on
maturity. The accretion of the debt discount and the interest paid to
debenture holders are expensed each period as part of the caption
interest and accretion on convertible debentures in the consolidated
statements of income.
The following table reconciles the principal amount, debt component and
equity component of the convertible debentures.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Principal amount Debt component of Equity component
of debentures debentures of debentures
----------------------------------------------------------------------------
August 28, 2007
issuance $100,000 $94,241 $5,759
Issue costs - (4,000) -
----------------------------------------------------------------------------
100,000 90,241 5,759
Accretion - 158 -
----------------------------------------------------------------------------
Balance, September 30,
2007 $100,000 $90,399 $5,759
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. UNIT-BASED INCENTIVE COMPENSATION
The Trust recorded a total compensation expense of $1.5 million in
the first nine months of 2007 of which $1.1 was recorded as an expense
and $0.4 as property, plant and equipment ($2.5 million as an expense
and $1.7 million as property, plant and equipment for full year 2006).
The compensation expense was based on the September 30, 2007 unit price
of $12.22 ($12.95 in 2006), accrued distributions, performance factors,
and the number of units vesting on maturity.
The following table reconciles the change in total accrued unit-based
incentive compensation relating to the plan:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Year ended
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 4,153 $ -
Increase in liability 1,518 4,153
Cash payout, relating to units vested
November 30, 2006 (2,184) -
----------------------------------------------------------------------------
Balance, end of period $ 3,487 $ 4,153
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current portion of liability(1) 1,253 3,148
----------------------------------------------------------------------------
Long-term liability 2,234 1,005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.
8. 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 $75.6 million as at September 30, 2007,
based on a total undiscounted amount of cash flows required to settle
its asset retirement obligations of $190.4 million (December 31, 2006 -
$165.2 million). These costs are expected to be incurred over the next
46 years with the majority of the costs incurred between 2007 and 2033.
NAL's credit-adjusted risk-free rate of eight percent (2006 - eight
percent) and an inflation rate of two percent (2006 - two percent) were
used to calculate the present value of the asset retirement obligations.
The following table reconciles the Trust's asset retirement obligations.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Year ended
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of period $65,574 $61,908
Accretion expense 3,969 4,984
Revisions to estimates (738) 39
Liabilities incurred 708 3,078
Liabilities acquired (Note 2) 10,356 -
Liabilities settled (4,220) (4,435)
----------------------------------------------------------------------------
Balance, end of period $75,649 $65,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. UNITHOLDERS' EQUITY
Units Issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Year ended
September 30, December 31,
2007 2006
----------------------------------------------------------------------------
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of period 77,971 $824,986 73,977 $753,585
Issued for cash 10,246 125,001 - -
Issued under management agreement
restructuring - - 1,592 30,000
Less: Issue expenses - (6,553) - (29)
Issued from Distribution Reinvestment
Plan 1,669 19,746 2,402 41,430
----------------------------------------------------------------------------
Balance, end of period 89,886 $963,180 77,971 $824,986
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated Other Comprehensive Income:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Year ended
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of period $ - -
Fair value of derivative instruments
on transition to new accounting
standards, net of tax of $1,349
(Note 1) 3,172 -
Reclassification to net income in
period, net of tax of $1,088 (Note 1) (2,559) -
----------------------------------------------------------------------------
Balance, end of period $ 613 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Distributions
The Trust is required to make a distribution of distributable cash
flow each calendar month, pursuant to the Trust Indenture. The
distributable cash flow is defined as cash flow of the Trust less a
discretionary amount, which the Trustee, upon recommendations of the
Manager, considers it necessary to retain.
Per Unit Information
Basic net income per trust unit is calculated using the weighted
average number of trust units outstanding. The calculation of diluted
net income per trust unit excludes the convertible debentures as the
units potentially issuable on the conversion of the convertible
debentures are anti-dilutive for the three and nine months ended
September 30, 2007. Total weighted average trust units issuable on
conversion of the convertible debentures and excluded from the diluted
net income per trust unit calculation for the three and nine months
ended September 30, 2007 were 2,639,752 and 889,587 respectively. As at
September 30, 2007, the total convertible debentures outstanding were
immediately convertible to 7,142,857 trust units.
10. COMMITMENTS
At September 30, 2007 the Trust had the following contractual obligations
and commitments:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($000s) 2007 2008 2009 2010 2011
----------------------------------------------------------------------------
Office Lease (1) 697 3,206 3,206 2,939 -
Transportation 456 1,007 908 84 -
Processing Agreement (2) 123 469 446 428 414
Drilling rigs (3) 494 494 - - -
Retention bonus (4) - 644 - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including office
space acquired with the Seneca acquisition, both base rent and operating
costs, held by the Manager, of which the Trust is allocated a pro rata
share (currently approximately 54 percent) of the expense on a monthly
basis.
(2) Represents a gas processing agreement with a take or pay arrangement.
(3) Represents the Trust's share of minimum payments required under drilling
rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.
TRADING PERFORMANCE
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the Quarter Ended
----------------------------------------------------------------------------
Price ($) 30-Sept-07 30-Jun-07 30-Sept-06 30-Jun-06
----------------------------------------------------------------------------
High 13.65 13.80 21.70 20.67
Low 11.52 11.45 16.14 18.26
Close 12.22 12.57 17.57 20.00
Volume 17,663,336 15,594,573 12,786,792 11,319,677
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL Oil & Gas Trust is an open-end investment trust that
generates distributions through the acquisition, development, production
and marketing of oil, natural gas and natural gas liquids. The Trust
owns high quality assets in Alberta, Saskatchewan and Ontario. Trust
units trade on the Toronto Stock Exchange under the symbol "NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: 1-888-223-8792
(403) 515-3407 (FAX)
Email: investor.relations@nal.ca
Website: www.nal.ca