CALGARY--(CCNMatthews - Nov. 5) -
/T/
Third Quarter Highlights
- Third quarter results benefited from the continued strength of oil
prices. NAL realized an average price of $52.48/barrel (bbl) during
the period, up 38% from the $38.00/bbl a year ago
- Gross revenue, net of royalties, totaled $44.0 million, 32% higher
than in 2003, mainly because of increased production and continued
high commodity prices
- Funds available for distribution were $30.3 million or $0.58 per
Trust unit, compared with $23.2 million or $0.55 per Trust unit for
the prior-year period
- Distributions declared totaled $0.47 per Trust unit, providing an
annualized cash-on-cash yield of 13% based on a quarter-end closing
price of $14.29 per Trust unit
- The Trust outperformed its peer group in the third quarter of 2004 by
delivering a total return to its Unitholders of 25.8% compared to a
15.2% total return provided by the S&P/TSX Capped Energy Trust Index
(*) 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 equivalent (boe). However, boes may be
misleading, particularly if used in isolation. A boe conversion ratio of
6 mcf: 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
/T/
President's Message
At the end of the second quarter, all hedging agreements NAL had entered into at
the beginning of the year expired. Given the Trust's strong balance sheet - our
trailing net debt to cash flow ratio stood at a modest 0.8 times -, and a
favorable outlook for oil and gas prices, NAL decided not to enter into any new
forward sales agreements for either oil or natural gas. As 67% of NAL's production
consists of light, sweet crude, our Unitholders benefited from the surge in oil
prices seen during the quarter: the benchmark West Texas Intermediate (WTI) price
per barrel of oil rose 27%, from US$38.74 to US$49.64. The lift in oil prices
benefited NAL's unit price as it climbed from $11.73 on June 30 to $14.29 on
September 30. Distributions declared during the quarter of $0.47, combined with the
$2.56 increase in our unit price, resulted in a total return of 26% for the third
quarter alone. From the beginning of 2004 to September 30, NAL has delivered a
total return of 45%. For the third consecutive quarter, NAL Oil & Gas Trust
outperformed the Capped Energy Trust Index by a significant margin.
At its regularly scheduled meeting in August, the Board of Directors decided to
increase monthly distributions from $0.15 to $0.16 per unit starting with the
September distribution. NAL believes it will be able to sustain this level of
distribution payments for the foreseeable future. We will, however, continue to
announce the level of our distributions every month.
Recent reports indicate that NAL's foreign ownership stands at around 16%, well
below the 50% threshold that would threaten our mutual fund trust status in Canada.
While NAL has been very successful in arresting natural declines and maintaining
production essentially level for the past five quarters, production decreased by
approximately three percent in the third quarter over the prior quarter. The main
reason for this decline in output was a previously planned blow-down of the Nisku
(D3) reservoir at Joffre as well as natural declines in other properties.
Additionally, unseasonably wet weather in Alberta and Saskatchewan throughout the
reporting period hampered drilling and development efforts and resulted in delaying
these activities.
Nonetheless, NAL was active on a number of fronts and in the third quarter, $16.4
million were spent on capital expenditures compared with $7.0 million in the second
quarter:
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- In central Alberta, 58 shallow gas wells (55.10 net) were
successfully drilled in the Brent/Hanna area. Weather permitting, the
majority of these wells are scheduled to be on production in the
fourth quarter.
- We continued drilling on the southeast Saskatchewan lands acquired
during the summer of 2003 by drilling twelve wells (4.3 net) of which
three (1.5 net) are on production and seven (1.63 net) wells are
awaiting tie-in.
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The first nine months of 2004 saw NAL successfully raise $25.9 million through the
premium component of NAL's DRIP by issuing an additional 2.3 million units. The
proceeds were used to fund NAL's capital program and reduce current debt levels.
Beginning with the October 15 distribution payment, the premium component of NAL's
DRIP has been suspended; however, management reserves the right to restart the
premium DRIP as the need may arise.
Traditionally among the lowest-cost operators in its peer group, NAL saw operating
costs rise from $5.79/boe in the second quarter to $6.98/boe in the third quarter,
mainly because of a large number of workovers we carried out and lower production
volumes. We expect production costs to return to lower levels in the fourth
quarter.
Donald P. Driscoll
President and Chief Executive Officer
/T/
Financial and Operating Highlights
(thousands of dollars, except per unit and boe data)
-------------------------------------------------------------------------
FINANCIAL Quarter Quarter Quarter 9 months 9 months
ended ended ended ended ended
September June September September September
30, 2004 30, 2004 30, 2003 30, 2004 30, 2003
Gross revenue, net
of royalties $ 43,989 $ 40,674 $33,378 $ 123,203 $ 94,178
Net income 13,279 10,871 8,701 33,113 45,991
Funds available for
distribution
before: 30,346 28,387 23,176 85,017 67,123
Funds applied to
debt and capital (5,606) (5,086) (2,318) (14,070) (12,811)
------------------------------------------------------
Distributions
declared 24,740 23,301 20,858 70,947 54,312
Distributions
declared per unit 0.47 0.45 0.45 1.37 1.33
Debt repayment and
capital per unit 0.11 0.10 0.06 0.27 0.33
Total assets $ 421,493 $ 423,901 454,576 $ 421,493 454,576
Long-term debt,
net of working
capital 87,772 86,767 92,831 87,772 92,831
Unitholders' equity 272,714 274,238 303,881 272,714 303,881
Costs per boe (6:1):
Operating 6.98 5.79 6.02 6.16 5.64
General and
administrative 1.57 1.48 1.34 1.49 1.31
Management fees 1.77 1.63 0.80 1.63 1.17
OPERATING
Daily production
Oil (bbl) 8,145 8,205 6,023 8,217 4,966
Natural gas (mcf) 24,572 26,254 26,907 25,895 27,421
Natural gas
liquids (bbl) 567 678 756 666 799
Oil equivalent
(boe - 6:1) 12,807 13,259 11,264 13,199 10,335
Average pricing, net
of transportation
charges
Liquids:
WTI (US$/bbl) 43.85 38.33 30.20 39.13 30.99
NAL average oil
(Cdn$/bbl) 52.48 43.48 38.00 45.37 40.41
Natural gas
liquids
(Cdn$/bbl) 41.05 34.44 29.24 36.79 31.99
Natural gas:
AECO (Cdn$/mcf) 6.67 6.80 5.86 6.69 6.98
Natural gas
Western Canada
(Cdn$/mcf) 6.31 6.81 6.12 6.51 6.96
Natural gas Lake
Erie (Cdn$/mcf) 7.76 8.50 7.11 8.22 8.73
NAL average
natural gas
(Cdn$/mcf) 6.60 7.12 6.31 6.82 7.29
Oil equivalent
(Cdn$/boe- 6:1) 47.82 43.15 37.68 43.63 41.45
Average foreign
exchange rate
Cdn$/US$ 1.3074 1.3597 1.3801 1.3281 1.4292
Operating netback
($/boe) 29.78 27.48 26.13 27.44 27.54
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/T/
Management's Discussion and Analysis
------------------------------------
Please read Management's Discussion and Analysis (MD&A) in conjunction with the
unaudited interim consolidated financial statements for the three and nine months
ended September 30, 2004 and the audited consolidated financial statements and MD&A
for the year ended December 31, 2003.
Operating netbacks and cash flow from operations are not recognized measures under
Canadian generally accepted accounting principles (GAAP). Management believes that
in addition to net income, operating netbacks and cash flow are useful supplemental
measures as they provide an indication of the results generated by the Trust's
principal business activities prior to the consideration of how those activities
are financed or how the results are taxed. Investors should be cautioned, however,
that these measures should not be construed as an alternative to net income
determined in accordance with GAAP as an indication of NAL's performance. NAL's
method of calculating these measures may differ from other companies' and
accordingly, they may not be comparable to measures used by other companies. NAL
calculates cash flow from operations as "funds from operations" prior to the change
in non-cash working capital related to operating activities.
Distributions to Unitholders
Funds available for distribution in the third quarter amounted to $30.3 million or
$0.58 per unit, compared with $23.2 million or $0.55 per unit for the same three-
month period in 2003. A 27% rise in oil equivalent pricing combined with a 14%
uplift in production accounted for the year-over-year increase. Compared with the
second quarter of 2004, funds available for distribution were up 7% or $0.03 per
unit due in large part to stronger oil pricing. Year-to-date funds available for
distribution were $85.0 million or $1.65 per unit, up 27% over the equivalent
period in 2003 but down $0.05 on a per unit basis as a result of more units
outstanding.
The Trust increased distributions to $0.16 per unit effective with the September
15, 2004 payment, following 18 consecutive months of distributing $0.15 per unit.
It is anticipated that the current level of distributions will be sustained for the
foreseeable future.
/T/
Unitholders' Distributions
(thousands of dollars, except per unit amounts) (unaudited)
--------------------------------------------------------
Quarter Quarter 9 months 9 months
ended ended ended ended
September 30, September 30, September 30, September 30,
2004 2003 2004 2003
--------------------------------------------------------
Funds from
operations $ 30,809 $ 23,615 $ 86,249 $ 68,004
Deduct:
Contributions
to reclamation
reserve (100) (87) (321) (297)
Actual abandonment
costs (363) (352) (911) (584)
-------------------------------------------------------------------------
Funds available
for distribution
before: $ 30,346 $ 23,176 $ 85,017 $ 67,123
Funds applied
to debt
repayment and
capital (5,606) (2,318) (14,070) (12,811)
-------------------------------------------------------------------------
Distributions
declared $ 24,740 $ 20,858 $ 70,947 $ 54,312
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Distributable
income per unit
(1) $ 0.58 $ 0.55 $ 1.65 $ 1.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Distributions
declared per
unit $ 0.47 $ 0.45 $ 1.37 $ 1.33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average
units outstanding 52,494,452 42,092,878 51,645,169 39,390,417
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding
/T/
Production
----------
During the third quarter, the Trust's output averaged 12,807 boed, up from 11,264
boed recorded in the third quarter of 2003 but down three percent from 13,259 boed
in the second quarter of 2004. The decrease in production over the prior quarter
can be attributed to the planned blow-down of the Nisku (D3) reservoir at Joffre
along with natural production declines at other properties. During the quarter,
adverse weather conditions in southeast Saskatchewan and central Alberta continued
to affect development drilling and tie-in activities, delaying the production
uplift from new wells that was expected to offset natural declines during the
quarter. Year-to-date production was 20% higher than in 2003 due largely to the
August 2003 southeast Saskatchewan acquisition.
/T/
Daily Production Volumes
------------------------
---------------------------------------------------
3 months ended 9 months ended
September 30 September 30
---------------------------------------------------
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Oil (bbl/d) 8,145 6,023 35% 8,217 4,966 65%
---------------------------------------------------
Natural gas (mcf/d) 24,572 26,907 (9%) 25,895 27,421 (6%)
---------------------------------------------------
NGL (bbl/d) 567 756 (25%) 666 799 (17%)
---------------------------------------------------
Oil equivalent (boe/d) 12,807 11,264 14% 13,199 10,335 28%
---------------------------------------------------
/T/
Commodity Prices
Crude Oil and Natural Gas Liquids (NGLs)
----------------------------------------
Throughout the third quarter, world oil prices in U.S. dollar terms remained
strong. WTI benchmark crude averaged US$43.85/bbl during this period, up 45% from
US$30.20 a year ago and 14.4% higher at US$38.33 than in the second quarter of
2004. In the first nine months of 2004, WTI averaged US$39.13, 26% higher than
during the first three quarters of 2003. NAL's third quarter crude price per
barrel, after the effect of transportation costs, averaged $52.48, up 38% from the
prior-year period and 21% over the previous quarter's average of $43.48. NAL's 2004
nine month average after the effect of hedging and transportation costs was $45.37,
12% higher than the 2003 price of $40.41. A seven percent increase in the Canadian
dollar mitigated the rise in year-over-year oil pricing. The pricing contracts in
place in the first half of 2004 negatively affected NAL's year-to-date oil price by
$2.13 per barrel. There were no oil-related hedging contracts in place during the
third quarter of 2004.
Year-over-year, the price per barrel of NGLs rose by 40% to $41.05 per barrel from
a third quarter 2003 level of $29.24. Compared to the previous quarter, the NGL
price was up 19%. NGL pricing for the nine months ended September 30, 2004 was
$36.79 per barrel, 15% higher than the same period in 2003. Demand for NGLs
generally tracks crude pricing which continues to be strong, keeping NGL prices
near record levels.
Natural Gas
-----------
Western Canadian average natural gas prices were 14% higher, with the AECO
reference price averaging $6.67/mcf in the third quarter of 2004, compared with
$5.86/mcf in the comparable period of 2003. Over the prior quarter, third quarter
2004 natural gas prices dropped a modest 2%; the AECO monthly index price averaged
$6.80/mcf in the second quarter of 2004. When comparing year-to-date pricing
levels, 2004 AECO pricing was down 4% from 2003.
Natural gas from our Lake Erie production was sold at $7.76/mcf in the third
quarter, up from $7.11/mcf a year ago but down 9% from the second quarter of 2004.
Year-to-date, Lake Erie's price totaled $8.22/mcf, a 6% decrease over 2003. Lake
Erie's gas represents 18% of NAL's total year-to-date natural gas production and is
premium priced because it is close to both the Ontario and northeastern U.S.
markets.
Overall, NAL received an average third quarter natural gas price, net of
transportation costs, of $6.60/mcf, up from the $6.31/mcf reported in the same
period last year but down 7% from the prior quarter.
Risk Management
In the first six months of 2004 NAL entered into certain fixed price contracts for
both oil and natural gas as a measure to support cash flow and protect
distributions. These contracts ended on June 30, 2004 allowing NAL to benefit from
record high crude oil prices. The realized payments from the sales contracts in
place through June 30, 2004 amounted to approximately $4.8 million. As at September
30, 2004 NAL has no outstanding pricing contracts.
Revenue and Cash Flow from Operations
Gross revenue, net of transportation charges, from oil, natural gas and natural gas
liquids sales totaled $56.3 million in the three months ended September 30, 2004, a
44% increase over the same period last year. A 14% rise in quarterly production
stemming from the August 2003 southeast Saskatchewan acquisition and a 27% increase
in oil equivalent pricing were the major contributing factors. Year-to-date
revenues totaled $157.8 million, 35% higher than the corresponding period last
year. The increase is attributable to a 28% growth in production volumes and a 5%
rise in oil equivalent pricing, mitigated somewhat by a stronger Canadian dollar.
Corresponding cash flows were up 30% over last year's third quarter and 2004 year-
to-date cash flows eclipsed 2003 totals by 27%.
Net Income
Net income for the three months ended September 30, 2004 was $13.3 million, $4.6
million higher than the $8.7 million recorded in the third quarter of 2003. Higher
commodity prices and production, mitigated somewhat by higher depletion and
operating costs, were the major contributing factors for the increase in net
income. Year-to-date net income was $33.1 million compared with $46.0 million in
the comparable period of 2003. Included in the 2003 results is a $15.0 million non-
cash income tax recovery. After removing the impact of the tax recovery in 2003,
income for the nine months ended September 30, 2004 was up by $2.2 million over
last year. Stronger crude oil pricing and higher production, offset by higher
depletion charges, were the key factors in the increased year-over-year pre-tax
earnings.
Royalties
Crown, freehold and overriding royalties net of Alberta Royalty Tax Credit (ARTC)
came to $13.0 million and $36.3 million for the three and nine months ended
September 30, 2004 respectively. Expressed as a percentage of gross sales, before
hedging and transportation costs, the net royalty rate was 23.0% for the quarter
and 22.2% on a year-to-date basis, up from 14.9% and 20.0% for the same respective
periods last year. The year-over-year increase in royalty rates occurred primarily
in response to higher commodity prices, as royalty rates are tied to prices. A one-
time positive credit recorded in the third quarter of 2003 related to certain
prior-year adjustments also contributed to this increase.
/T/
---------------------------------------------------
3 months ended 9 months ended
September 30 September 30
---------------------------------------------------
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Net royalties ($000s) 13,030 5,729 127% 36,258 23,344 55%
---------------------------------------------------
As % of revenue 23.0 14.9 54% 22.2 20.0 11%
---------------------------------------------------
$/boe 11.06 5.53 100% 10.03 8.27 21%
---------------------------------------------------
/T/
Operating Costs
Production expenses per boe for the third quarter of 2004 were up 16% over the
third quarter of 2003, averaging $6.98 compared with $6.02. Lower production
volumes in the third quarter of 2004, combined with a higher level of turnaround
activity, led to the increase. Operating costs on a per boe basis for the nine
months ended September 30, 2004 increased 9% over 2003. The higher-cost southeast
Saskatchewan assets, acquired in August 2003, have led to an overall increase in
operating costs. In addition, the strong demand for services and equipment because
of high industry activity levels continued to exert upward pressure on field
operating costs.
/T/
---------------------------------------------------
3 months ended 9 months ended
September 30 September 30
---------------------------------------------------
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Operating costs ($000s) 8,224 6,243 32% 22,288 15,926 40%
---------------------------------------------------
As % of revenue 14.6 16.0 (9%) 14.1 13.6 4%
---------------------------------------------------
$/boe 6.98 6.02 16% 6.16 5.64 9%
---------------------------------------------------
/T/
Operating Netback
NAL's operating netback for the third quarter was $29.78 per boe, up 14% from the
$26.13 recorded in the same period a year ago. Record high crude oil pricing led to
a 30% increase in pre-hedged oil equivalent pricing. This increase was somewhat
tempered by the higher royalties. When comparing year-to-date operating
netbacks, the $27.44/boe recorded in 2004 was essentially unchanged from last year.
The benefit of higher crude prices was mitigated by hedging contracts in the first
six months of 2004. The end result is an increase in oil equivalent pricing of ten
percent, offset by higher royalty and operating costs.
/T/
$/boe
---------------------------------------------------
3 months ended 9 months ended
September 30 September 30
---------------------------------------------------
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Revenue, net of
transportation costs 47.82 36.77 30% 44.96 41.02 10%
---------------------------------------------------
Hedging effect - 0.91 - (1.33) 0.43 (409%)
---------------------------------------------------
Royalties, net (11.06) (5.53) 100% (10.03) (8.27) 21%
---------------------------------------------------
Operating expenses (6.98) (6.02) 16% (6.16) (5.64) 9%
---------------------------------------------------
Operating netback 29.78 26.13 14% 27.44 27.54 0%
---------------------------------------------------
/T/
General & Administrative (G&A)
G&A costs for the three and nine months ended September 30, 2004 averaged $1.57 and
$1.49 per boe respectively, up from $1.34 and $1.31 per boe recorded in the same
respective periods last year. The higher G&A costs per boe reflect the increased
costs resulting from greater regulatory and public company compliance requirements
and increased charges related to the ongoing evaluation of potential acquisition
opportunities. Also contributing to increased G&A costs are higher costs for
consulting and other services that are in great demand in the current economic
environment.
/T/
---------------------------------------------------
3 months ended 9 months ended
September 30 September 30
---------------------------------------------------
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
G&A costs ($000s) 1,845 1,391 33% 5,383 3,687 46%
---------------------------------------------------
As % of revenue 3.3 3.6 (8%) 3.4 3.2 6%
---------------------------------------------------
$/boe 1.57 1.34 17% 1.49 1.31 14%
---------------------------------------------------
Per Trust unit ($) 0.04 0.03 33% 0.10 0.09 11%
---------------------------------------------------
/T/
Management Fees
Base management fees for the three and nine months ended September 30, 2004
amounted to $1.0 million and $3.0 million respectively, up from $0.8 million and
$2.4 million in the comparable periods last year. These base management fees will
fluctuate with net production revenues, which were higher when comparing year-over-
year results.
A performance fee of $1.1 million was recorded based on the Trust's third quarter
performance, which was significantly higher than that of its peers based on the
S&P/TSX Capped Energy Trust Index (the "Index"). NAL's total return for the three
months ended September 30, 2004 was 25.8% compared with a 15.2% return for the
Index. There was no performance fee awarded in the third quarter of 2003. Year-to-
date NAL has maximized the performance bonus payable to the Manager in each of the
first three quarters of 2004. Total performance fees paid for the nine months ended
September 30, 2004 amounted to $2.9 million, up from $0.9 million recorded in the
same period last year. Total management fees for the three and nine months ended
September 30, 2004 were $2.1 million and $5.9 million respectively, up from $0.8
million and $3.3 million in the same periods last year.
/T/
---------------------------------------------------
3 months ended 9 months ended
September 30 September 30
---------------------------------------------------
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Management fees ($000s) 2,082 827 152% 5,912 3,298 79%
---------------------------------------------------
As % of revenue 3.7 2.1 76% 3.7 2.8 32%
---------------------------------------------------
$/boe 1.77 0.80 121% 1.63 1.17 39%
---------------------------------------------------
Per Trust unit ($) 0.04 0.02 100% 0.11 0.08 38%
---------------------------------------------------
/T/
Interest
Interest expense for the quarter ended September 30, 2004 was $0.9 million. Year-
over-year third quarter interest charges decreased by $0.2 million due to a lower
average debt load. Year-to-date interest charges totaled $3.0 million, up from $2.8
million in the same period last year as the August 2003 southeast Saskatchewan
acquisition was partially financed with debt.
Depletion, Depreciation and Accretion (DDA)
In the third quarter of 2004, depletion on property, plant and equipment and
accretion on the asset retirement obligation increased over the comparable period
in 2003, primarily because of higher production volumes. Third quarter depletion
and accretion charges amounted to $17.6 million in 2004 compared with $14.1 million
for 2003. Per boe, DDA rose 10% to $14.92 in the third quarter from $13.61 a year
ago. Year-to-date depletion and accretion was $53.2 million or $14.72 per boe
compared to $37.0 million or $13.13 per boe.
With the adoption of CICA Handbook section 3110 on asset retirement obligations,
the petroleum and natural gas assets are increased as reflected in note 1 to our
interim financial statements. The asset retirement cost included in petroleum and
natural gas assets is depleted on a unit of production basis over the life of the
reserves and the asset retirement obligations are accreted to their fair value with
accretion expense recognized for each reporting period. As a result, expenses
related to asset retirement obligations are disclosed in both depletion and
depreciation and as accretion expense, while under the old method the entire
expense was recognized as a component of depletion and depreciation. Accretion
expense for the nine months totaled $2.1 million and $0.7 million for the three
months ended September 30th, 2004. This is up from $1.5 million and $0.5 million
for the comparative periods in the prior year.
Capital Resources and Liquidity
The capital structure of the Trust is comprised of Trust units and debt.
As at September 30, 2004, NAL had 52,912,513 units outstanding -- 2,348,010 units
more than on December 31, 2003, reflecting the additional units issued through the
Trust's Distribution Reinvestment Plan (DRIP). As at November 5, 2004 there were
52,960,039 units outstanding. The DRIP generated net proceeds of $9.9 million in
the third quarter and $25.9 million for the nine months ended September 30, 2004.
The proceeds were used to fund existing capital programs and to reduce debt.
Beginning with the October 15 distribution payment, the premium component of NAL's
DRIP has been suspended until further notice as capital requirements have been met.
NAL Energy Inc. maintains a $140 million, fully secured, extendible revolving term
bank credit facility. The purpose of the facility is primarily to provide loans to
entities within the NAL Oil & Gas Trust group to fund their property acquisitions
and capital expenditures. Principal repayments to the bank are not required at this
time. Should principal repayments become mandatory, the cash flows otherwise
available to Unitholders would be used to repay the credit facility.
/T/
($000s) September 30, December 31, September 30,
2004 2003 2003
------------------------------------------
Trust unit equity 272,714 284,626 303,881
Long-term debt 92,200 103,500 99,000
Debt to equity 0.34 0.36 0.33
Net debt(*) 87,772 97,039 92,831
Net debt to trailing 12 month
cash flow 0.79 1.05 1.08
------------------------------------------
(*) Net debt is long-term debt net of working capital
/T/
Contractual Obligations
NAL enters into many contract obligations as part of conducting day-to-day
business. NAL has the following long-term commitments for the years indicated:
/T/
($000s)
-------------------------------------------------------------------------
2004 2005 2006 2007 2008
-------------------------------------------------------------------------
Office lease (1) 1,262 1,265 1,290 1,182 -
-------------------------------------------------------------------------
Transportation Agreement 502 669 284 - -
-------------------------------------------------------------------------
(1) Represents the full amount of the office lease, both base rent and
operating costs, held by the Manager of which NAL is allocated a pro rata
share of the expense on a monthly basis.
/T/
Off-Balance Sheet Arrangements/Variable Interest Entities
NAL has no off-balance sheet arrangements or variable interest entities.
Capital Expenditures
Capital expenditures in the third quarter of 2004 amounted to $16.4 million
compared with $9.6 million a year ago. In the third quarter, NAL spent $11.2
million on development drilling, $4.5 million on facilities and equipment, and $0.7
million on geological and geophysical and other corporate assets. Year-to-date
capital expenditures totaled $30.6 million up from $20.3 million recorded in 2003.
In addition, in the nine months ended September 30, 2004 NAL spent $1.0 million on
the purchase of minor land interests compared to $1.7 million in 2003. The third
quarter of 2003 saw NAL purchase assets in southeast Saskatchewan for $136.2
million after purchase-price adjustments.
Development Activities
During the third quarter, the Trust participated in a total of 86 wells (62.43 net)
with a 94% success rate (97% net).
In central Alberta, 58 shallow gas wells (55.10 net) were successfully drilled in
the Brent/Hanna area. The majority of these wells are scheduled to be completed and
tied in to the NAL operated Brent Gas Plant in the fourth quarter. At Medicine
River, 5 wells (1.17 net) were drilled, with one oil well (0.33 net) on production
and two oil (0.45 net) and two gas (0.39 net) wells awaiting tie-in.
In southeast Saskatchewan a total of 12 wells (4.13 net) were drilled during the
third quarter. At Elswick, four (1.13 net) oil wells and two injection wells (0.25
net) are awaiting tie-in. At Stoughton, one oil well (0.50 net) is on production
and one oil well is awaiting tie-in. At Browning, one oil well (0.50 net) is on
production and one well (0.5 net) was drilled and abandoned. In addition, one well
(0.50 net) is on production at Midale and one well (0.50 net) was drilled and
abandoned at Bryant.
At Lake Erie, six gas wells (1.17 net) are online, one gas well (0.20 net) is being
tied in, and three gas wells (0.59 net) were drilled and abandoned.
/T/
Quarterly Information
-------------------------------------------------------------------------
2004 2003 2002
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Financial
-------------------------------------------------------------------------
Revenue,
net of
royal-
ties 43,989 40,674 38,540 37,697 33,378 28,615 32,185 26,367
-------------------------------------------------------------------------
Per unit 0.84 0.79 0.76 0.75 0.79 0.75 0.85 0.76
-------------------------------------------------------------------------
Funds flow
from
operat-
ions 30,809 28,789 26,651 24,413 23,615 19,844 24,546 18,350
-------------------------------------------------------------------------
Per unit 0.59 0.56 0.52 0.48 0.56 0.52 0.65 0.53
-------------------------------------------------------------------------
Net
income 13,279 10,871 8,963 3,252 8,701 24,381 12,909 5,992
-------------------------------------------------------------------------
Per unit 0.25 0.21 0.18 0.06 0.21 0.64 0.34 0.17
-------------------------------------------------------------------------
/T/
Critical Accounting Estimates
The significant accounting policies used by NAL are disclosed in the notes to NAL's
December 31, 2003 audited 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 following discusses such accounting policies and is included in
Management's Discussion and Analysis to assist investors in assessing the critical
accounting policies and practices of NAL, and the likelihood of materially
different results being reported. NAL's management reviews its 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.
The following assessment of significant accounting policies is not meant to be
exhaustive. NAL might realize different results from the application of new
accounting standards published, from time to time, by various regulatory bodies.
Proved Oil and Gas Reserves
---------------------------
Under National Instrument 51-101 (NI 51-101), "proved" reserves are those reserves
that can be estimated with a high degree of certainty to be recoverable (it is
likely that the actual remaining quantities recovered will exceed the estimated
proved reserves). In accordance with this definition, the level of certainty
targeted by the reporting company should result in at least a 90% probability at a
company aggregate level that the quantities actually recovered will equal or exceed
the estimated reserves. There was no such consideration of probability under
previous reporting rules. In the case of "probable" reserves, which are less
certain to be recovered than proved reserves, NI 51-101 states that it must be
equally likely that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable ("P+P") reserves. As for
certainty, in order to report reserves as P+P, the reporting company must believe
that there is at least 50% probability at a company aggregate level that the
quantities actually recovered will equal or exceed the sum of the estimated P+P
reserves. The implementation of NI 51-101 has resulted in a more rigorous and
uniform standardization of reserve evaluation.
The oil and gas reserve estimates are made using all available geological and
reservoir data as well as historical production data. Estimates are reviewed and
revised as appropriate. Revisions occur as a result of changes in prices, costs,
fiscal regimes, reservoir performance or a change in NAL's plans. The effect of
changes in proved oil and gas reserves on the financial results and position of NAL
is described under the heading "Full Cost Accounting for Oil and Gas Activities
(Ceiling Test)".
Depletion Expense
-----------------
NAL uses the full cost method of accounting for exploration and development
activities. In accordance with this method of accounting, all costs associated with
exploration and development are capitalized whether or not the activities funded
were successful. The aggregate of net capitalized costs and estimated future
development costs, less estimated salvage values, is amortized using the unit of
production method based on estimated proved oil and gas reserves.
An increase in estimated proved oil and gas reserves would result in a
corresponding reduction in depletion expense. A decrease in estimated future
development costs would result in a corresponding reduction in depletion expense.
Withheld Costs
--------------
Certain costs related to unproved properties may be excluded from costs subject to
depletion until proved reserves have been determined or their value is impaired.
These properties are reviewed quarterly and any impairment is transferred to the
costs being depleted.
Impairment of Property, Plant & Equipment
-----------------------------------------
NAL is required to review the carrying value of all property, plant and equipment,
including the carrying value of oil and gas assets, for potential impairment.
Impairment is indicated if the carrying value of the long-lived oil and gas asset
is not recoverable by the future undiscounted cash flows. If impairment is
indicated, the amount by which the carrying value exceeds the estimated fair value
of the property, plant and equipment is charged to earnings.
Fair Value of Derivative Instruments
------------------------------------
Periodically NAL utilizes financial derivatives to manage market risk. The purpose
of the hedge is to provide an element of stability to NAL's cash flow in a volatile
environment. NAL discloses the estimated fair value of open hedging contracts as at
the end of a reporting period.
Provision for Site Restoration
------------------------------
NAL adopted the CICA Handbook, section 3110 on asset retirement obligations on
January 1, 2004. The application of this standard requires the recognition and
measurement of liabilities associated with capital assets. The standard recognizes
a liability equal to the discounted fair value of the obligation in the period in
which the asset is recorded with an equal offset to the carrying amount of the
asset. The liability then accretes to its fair value with the passage of time. This
standard requires management to estimate the timing and future costs to settle
liabilities.
Legal, Environmental Remediation and Other Contingent Matters
-------------------------------------------------------------
NAL is required to determine whether a loss is probable based on judgment and
interpretation of laws and regulations and whether the loss can reasonably be
estimated. When the loss is determined, it is charged to earnings. NAL's management
must continually monitor known and potential contingent matters and make
appropriate provisions by charges to earnings when warranted by circumstance.
Income Tax Accounting
---------------------
The determination of NAL's income and other tax liabilities requires interpretation
of complex laws and regulations often involving multiple jurisdictions. All tax
filings are subject to audit and potential reassessments after the lapse of
considerable time. Accordingly, the actual income tax liability may differ
significantly from that estimated and recorded by management.
Dated November 5, 2004
/T/
Consolidated Balance Sheets
(thousands of dollars)
---------------------------
As at As at
September 30, December 31,
2004 2003
(unaudited) (audited)
(Restated
- Note 1)
Assets
Current assets
Cash and cash equivalents $ 216 $ 574
Accounts receivable and other 23,514 21,583
-----------------------------------------------------------------------
23,730 22,157
Reclamation reserve 3,406 3,085
Future income tax asset 4,018 3,929
Property, plant and equipment, net (Note 2) 390,339 409,565
-----------------------------------------------------------------------
$ 421,493 $ 438,736
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Liabilities and
Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 10,836 $ 8,111
Distributions payable to Unitholders 8,466 7,585
-----------------------------------------------------------------------
19,302 15,696
Long-term debt (Note 4) 92,200 103,500
Asset retirement obligations (Note 3) 37,277 34,914
-----------------------------------------------------------------------
148,779 154,110
-----------------------------------------------------------------------
Unitholders' equity (Note 5) 272,714 284,626
-----------------------------------------------------------------------
$ 421,493 $ 438,736
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Units outstanding 52,912,513 50,564,503
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Income and Unitholders' Equity
(thousands of dollars, except per unit amounts) (unaudited)
-------------------------------------------------------
Quarter Quarter 9 months 9 months
ended ended ended ended
September 30, September 30, September 30, September 30,
2004 2003 2004 2003
(Restated (Restated
- Note 1) - Note 1)
-------------------------------------------------------------------------
Revenue
Oil, natural gas
and liquids sales $ 56,724 $ 39,393 $ 158,871 $ 117,997
Transportation
costs (384) (347) (1,051) (1,035)
Royalty and other
income 679 61 1,641 560
Crown royalties,
net of ARTC (10,197) (4,145) (28,562) (18,674)
Freehold and other
royalties (2,833) (1,584) (7,696) (4,670)
-------------------------------------------------------------------------
43,989 33,378 123,203 94,178
-------------------------------------------------------------------------
Expenses
Operating 8,224 6,243 22,288 15,926
General and
administrative 1,845 1,391 5,383 3,687
Management fees 2,082 827 5,912 3,298
Interest on
long-term debt 932 1,138 3,014 2,796
Depletion,
depreciation and
amortization 16,875 13,579 51,125 35,592
Accretion on asset
retirement
obligations 701 528 2,100 1,456
-------------------------------------------------------------------------
30,659 23,706 89,822 62,755
-------------------------------------------------------------------------
Income before taxes 13,330 9,672 33,381 31,423
Income and capital
taxes (97) (164) (357) (467)
Future income tax
recovery (provision) 46 (807) 89 15,035
-------------------------------------------------------------------------
Net income $ 13,279 $ 8,701 $ 33,113 $ 45,991
Unitholders' equity,
beginning of period 274,238 204,024 288,590 200,536
Retroactive effect
of change in
accounting policy
(Note 1) - (4,764) (3,964) (5,112)
----------- ----------- -----------
Unitholders' equity,
beginning of period
as restated - 199,260 284,626 195,424
Issue of Trust units,
net of issue costs 9,937 116,778 25,922 116,778
Distributions
declared for the
period (24,740) (20,858) (70,947) (54,312)
-------------------------------------------------------------------------
Unitholders' equity,
end of period $ 272,714 $ 303,881 $ 272,714 $ 303,881
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per
Trust unit $ 0.25 $ 0.21 $ 0.64 $ 1.17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average
units outstanding 52,494,452 42,092,878 51,645,169 39,390,417
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Cash Flows
(thousands of dollars) (unaudited)
--------------------------------------------------------
Quarter Quarter 9 months 9 months
ended ended ended ended
September 30, September 30, September 30, September 30,
2004 2003 2004 2003
(Restated (Restated
- Note 1) - Note 1)
-------------------------------------------------------------------------
Operating activities
Net income $ 13,279 $ 8,701 $ 33,113 $ 45,991
Items not involving
cash:
Depletion,
depreciation and
amortization 16,875 13,579 51,125 35,592
Accretion on
asset retirement
obligations 701 528 2,100 1,456
Future income
tax provision
(recovery) (46) 807 (89) (15,035)
-------------------------------------------------------------------------
Funds from
operations 30,809 23,615 86,249 68,004
Remediation
expenditures (363) (352) (911) (584)
Decrease (increase)
in non-cash working
capital 139 (8,531) 3,396 (8,706)
-------------------------------------------------------------------------
30,585 14,732 88,734 58,714
Financing Activities
Distributions to
Unitholders (24,084) (18,983) (70,066) (51,676)
Issue of Trust units,
net of issue costs 9,937 116,778 25,922 116,778
Advances from
(repayment of)
long-term debt (5,300) 28,800 (11,300) 34,100
Decrease in non-cash
working capital - - - -
-------------------------------------------------------------------------
(19,447) 126,595 (55,444) 99,202
-------------------------------------------------------------------------
Investing Activities
Acquisition of
property, plant and
equipment (181) (136,240) (1,014) (140,156)
Investment in
property, plant and
equipment (16,367) (9,557) (30,645) (20,292)
Proceeds from
dispositions - 9 934 153
Reclamation reserve (100) (87) (321) (297)
Decrease (increase)
in non-cash working
capital 4,623 3,749 (2,602) 2,680
-------------------------------------------------------------------------
(12,025) (142,126) (33,648) (157,912)
-------------------------------------------------------------------------
Increase (decrease)
in cash and cash
equivalents (887) (799) (358) 4
Cash and cash
equivalents,
beginning of period 1,103 1,798 574 995
-------------------------------------------------------------------------
Cash and cash
equivalents, end of
period $ 216 $ 999 $ 216 $ 999
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary
disclosure of cash
flow information:
Cash paid during
the period for:
Interest $ 909 $ 1,109 $ 2,936 $ 2,741
Taxes $ 97 $ 164 $ 357 $ 467
-------------------------------------------------------------------------
See accompanying notes
Notes to Interim Consolidated Financial Statements
Three and nine months ended September 30, 2004
(Unaudited) (Tabular amounts in thousands of dollars, except per unit
amounts)
Management prepared the interim consolidated financial statements of
NAL Oil and Gas Trust (NAL) 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, 2003 except 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, 2003.
1. CHANGES IN SIGNIFICANT ACCOUNTING POLICY
----------------------------------------
Asset Retirement Obligations
----------------------------
NAL has adopted the asset retirement obligation method of recording
the future cost associated with removal, site restoration and asset
retirement costs. The fair value of the liability for NAL's asset
retirement obligation is recorded in the period in which it is
incurred, discounted to its present value using NAL's credit-adjusted
risk-free interest rate and the corresponding amount recognized by
increasing the carrying amount of property, plant and equipment. The
asset recorded is depleted on a unit of production basis over the life
of the reserves. The liability amount is increased each reporting
period due to the passage of time and the amount of accretion is
charged to earnings in the period. Revisions to the estimated timing
of cash flows or to the original estimated undiscounted cost could
also result in an increase or decrease to the obligation. Actual costs
incurred upon settlement of the retirement obligation are charged
against the obligation to the extent of the liability recorded.
Previously, NAL recognized a provision for estimated future removal
and site restoration costs calculated on the unit-of-production method
over the remaining life of the proved reserves.
The effect of this change in accounting policy has been recorded
retroactively with restatement of prior periods. The effect of the
adoption is presented below as increases (decreases):
----------------------------------------------------------------------
December 31, December 31,
Balance Sheets 2003 2002
Asset retirement costs included in property,
plant and equipment $ 16,097 $ 8,338
Asset retirement obligations 34,914 24,424
Provision for future site restoration (12,398) (9,298)
Future income tax asset 2,455 1,676
Retained earnings (3,964) (5,112)
----------------------------------------------------------------------
----------------------------------------------------------------------
Statements of Income 3 months 9 months
ended ended Year ended
September September December
2003 2003 2003
----------------------------------------------------------------------
Accretion on asset retirement
obligations ($527) ($1,456) ($2,107)
Depletion and depreciation on asset
retirement costs (375) (1,117) (1,825)
Amortization of estimated future
removal and site restoration
liability 1,178 2,807 4,301
Future income taxes 195 585 779
----------------------------------------------------------------------
Net income impact 471 819 1,148
Net income per Trust unit 0.01 0.02 0.03
----------------------------------------------------------------------
----------------------------------------------------------------------
2. PROPERTY, PLANT AND EQUIPMENT
------------------------------
Net book value as at:
September 30, December 31,
2004 2003
----------------------------------------------------------------------
Oil and natural gas properties, at cost $ 671,544 $ 639,645
Less: Accumulated depletion and depreciation (281,205) (230,080)
----------------------------------------------------------------------
$ 390,339 $ 409,565
----------------------------------------------------------------------
----------------------------------------------------------------------
3. ASSET RETIREMENT OBLIGATIONS
----------------------------
NAL's asset retirement obligations result from net ownership interests
in oil and natural gas assets including well sites, gathering systems
and processing facilities. NAL estimates the total undiscounted amount
of cash flows required to settle its asset retirement obligations is
approximately $97.6 million that will be incurred between 2004 and
2052. The majority of the costs will be incurred between 2004 and
2020. A credit-adjusted risk-free rate of eight percent was used to
calculate the fair value of the asset retirement obligations.
A reconciliation of the asset retirement obligations is provided
below:
----------------------------------------------------------------------
September 30, December 31, September 30,
2004 2003 2003
----------------------------------------------------------------------
Balance, beginning of period $ 34,914 $ 24,424 $ 24,424
Accretion expense 2,100 2,107 1,456
Liabilities incurred 1,174 9,584 9,584
Liabilities settled (911) (1,201) (584)
----------------------------------------------------------------------
Balance, end of period $ 37,277 $ 34,914 $ 34,880
----------------------------------------------------------------------
----------------------------------------------------------------------
4. LONG-TERM DEBT
--------------
The Trust has a revolving credit facility of $140 million. The credit
facility is fully secured by a floating debenture over the Trust's
assets, and a general assignment of book debts. Amounts advanced under
the credit facility bear interest at the bank's prime rate or at
Bankers' Acceptance rates plus a stamping fee charge.
The credit facility will revolve until April 29, 2005, whereupon it
may be renewed for a further 364 days, upon agreement between the
Trust and the bank, or converted into a term facility with amounts
outstanding under the facility repayable in eight quarterly
installments. The Trust can post, at its option, security suitable to
the bank in lieu of the first year's payment.
5. TRUST UNITS
-----------
Issued at:
September 30, 2004 December 31, 2003
------------------------------------------
Units Amount Units Amount
----------------------------------------------------------------------
Balance, beginning of period 50,565 $ 448,683 38,017 $ 331,666
Issued for cash - - 12,500 123,125
Less: issue expenses - - - (6,578)
Issued from Distribution
Reinvestment Plan 2,348 25,922 48 470
----------------------------------------------------------------------
----------------------------------------------------------------------
Balance, end of period 52,913 $ 474,605 50,565 $ 448,683
----------------------------------------------------------------------
----------------------------------------------------------------------
6. FINANCIAL INSTRUMENTS
---------------------
The Trust does not have any derivative or hedging agreements in place
as at September 30, 2004. The Trust made net settlement payments of
$4.8 million for the nine months ended September 30, 2004
(2003 - received $0.3 million).
7. COMPARATIVE FIGURES
-------------------
Certain comparative figures have been re-classified to conform with
current-period presentation.
/T/
Forward-Looking Statements
This disclosure contains certain forward-looking statements that involve
substantial known and unknown risks and uncertainties, many of which are beyond
NAL's control, including: the impact of general economic conditions in Canada and
in the United States, industry conditions, changes in laws and regulations
including the adoption of new environmental laws and regulations and changes in how
they are interpreted and enforced, increased competition, the lack of availability
of qualified personnel or management, fluctuations in foreign exchange or interest
rates, stock market volatility and market valuations of companies with respect to
announced transactions and the final valuations thereof, and obtaining required
approval of regulatory authorities. NAL's actual results, performance or
achievement could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurances can be given that any of
the events anticipated by the forward-looking statements will transpire or occur,
or if any of them do so, what benefits, including the amount of proceeds, that NAL
will derive there from.
/T/
Trading Performance
TSX: NAE.UN
For the
quarter
ended 30-Sep-04 30-Jun-04 31-Mar-04 31-Dec-03 30-Sep-03
-----------------------------------------------------------
PRICE
High $14.29 $12.05 $11.47 $10.98 $10.22
Low $11.68 $11.05 $9.79 $9.46 $9.35
Close $14.29 $11.73 $11.47 $10.94 $9.74
-----------------------------------------------------------
Volume 9,359,852 11,283,206 11,221,801 15,926,969 12,825,681
-----------------------------------------------------------
/T/
NAL Oil & Gas Trust Paul Belliveau Vice President Finance & Chief Financial Officer (403) 294-3600 or Toll Free: 888-223-8792 Fax: (403) 294-3699 or NAL Oil & Gas Trust Anne-Marie Buchmuller Manager, Investor Relations (403) 294-3600 or Toll Free: 888-223-8792 Fax: (403) 294-3699 Email: Investor.Relations@nal.ca Website: www.nal.ca