CALGARY--(CCNMatthews - March 2) -
/T/
Highlights
- Gross revenue, net of royalties, totaled $43.1 million, 14% higher
than in 2003, mainly because of continued high commodity prices
- Funds available for distribution in the quarter were $28.8 million or
$0.54 per Trust unit, compared with $23.7 million or $0.47 per Trust
unit for the prior-year period
- Distributions declared totaled $0.48 per Trust unit, providing an
annualized cash-on-cash yield of 14% based on a quarter-end closing
price of $13.55 per Trust unit
- Fourth quarter results benefited from the continued strength of oil
prices. NAL realized an average price of $50.47/barrel ("bbl") during
the period, up 36% from the $37.22/bbl recorded a year ago
- Production for the full year 2004 averaged 13,139 barrels of oil
equivalent per day(*) ("boed"), up 16% from the prior year
- Funds available for distribution during the year amounted to
$113.8 million or $2.19 per Trust unit, compared with $90.8 million
or $2.15 per Trust unit for the prior year.
On February 10, 2005, NAL completed the acquisition of Addison Energy
Inc. (the "Acquisition") and the concurrent sale of a 30% undivided
interest in the Addison properties. Current production from the Trust's
70% interest in the Addison properties amounts to approximately
7,700 boed.
(*) 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
NAL had a very successful year in 2004 and provided Unitholders with a total
return of 41%; the Trust outperformed its peer group average in three of the
four quarters.
Commodity prices remained very strong throughout the year, in particular the
West Texas Intermediate ("WTI") oil price, which was 33% higher in 2004 than in
the prior year. NAL's production, weighted 67% towards oil and natural gas
liquids ("NGLs"), remained completely unhedged during the second half of the
year. As a result, Unitholders received the full benefit from the positive oil
price environment: NAL's average Canadian dollar realization for a barrel of oil
exceeded $50.00 in both the third and fourth quarters of 2004. Although natural
gas prices were slightly lower than in 2003, they were still quite robust and
averaged $6.79/thousand cubic feet ("Mcf") for the year.
Commodity prices remain quite strong and the outlook is positive. The Trust has
no forward sales contracts in place, which allows our Unitholders to continue to
reap the rewards of the strong crude prices. However, we are closely monitoring
the situation and will put hedges in place as we deem appropriate.
NAL's success as a field operator continued in 2004. Our development program
successfully offset natural declines and helped maintain our production levels
essentially flat year over year at approximately 13,000 boed. We were
particularly active in our largest core area, southeast Saskatchewan, where we
drilled a total of 41 wells (15.84 net). Production in our Alida field -
discovered in 1955 - peaked in the summer of 2004, 48 years after its discovery.
Other successes occurred in the Steelman, Elswick and Browning areas. Steelman
and Elswick formed part of our 2003 acquisition, and Browning was acquired a
year earlier through the acquisition of Landex Energy. Numerous opportunities
remain in this area and we expect 2005 to be another active year. We also
focused on our Brent/Hanna fields in southeastern Alberta where we continued an
extensive drilling program into the Second White Specks formation. A total of 58
wells were drilled here with a 100% success rate. Fifty-four of these shallow
gas wells were tied in late in the fourth quarter, and the remaining four wells
are expected to come onstream during the first quarter of 2005. The natural gas
produced in this area is processed at the local NAL-owned gas plant, which is
running at capacity.
During the fourth quarter of 2004, the Trust participated in a total of 27 wells
(11.27 net) and saw a 100% success rate. On the southeast Saskatchewan lands
acquired in August 2003, 12 horizontal oil wells (4.42 net) were drilled, and
the results of this program continue to meet or exceed management's
expectations.
In February 2005, we undertook the largest acquisition in our history when we
acquired Addison Energy Inc. NAL partnered with Manulife Financial Corporation
("MFC") to successfully carry out the Acquisition. NAL paid $550 million for all
of the outstanding shares of Addison; however, the concurrent sale of a 30%
undivided interest in the Addison properties to a wholly-owned subsidiary of MFC
made for a net consideration for the Trust of $385 million. This transaction is
another excellent example of the strategic advantage the Trust enjoys as a
result of its relationship with MFC.
In order to finance the Acquisition, NAL issued 17,000,000 Trust units at $13.70
each, which resulted in net proceeds to the Trust of $221 million. The balance
of the purchase price was financed by bank debt as we increased our existing
credit facility by $160 million to $300 million. Subsequent to the Acquisition,
the market capitalization of the Trust exceeded $1 billion for the first time in
its history.
Current production from the Trust's 70% interest in the Addison properties is
approximately 7,700 boed, mostly (62%) consisting of natural gas. This natural
gas generally has high heat content, which commands a premium price. The new
assets have a long reserve life index ("RLI") at 10.6 years on a proved plus
probable basis and will contribute to an increase in the Trust's overall RLI.
Following the Acquisition, the Trust's production portfolio consists of
approximately 57% oil and NGLs and 43% natural gas. The acquired properties are
for the most part in close proximity to NAL's core central Alberta operations,
an area our technical team is very familiar with and where we have high working
interest ownership. We have identified numerous development opportunities
throughout the properties. Additionally, there are coalbed methane prospects in
the Nevis/Lacombe area of Central Alberta, which we will pursue throughout 2005
and beyond.
The income trust sector has become a significant component of the Canadian
equity market. Standard and Poors and the Toronto Stock Exchange have recognized
this fact and will include a number of income trusts in the S&P/TSX Composite
Index (the "Index"). This change is expected to occur later in the year and we
anticipate NAL to be included in the Index, given our market capitalization of
$1 billion. As well, Alberta has now introduced legislation that eliminates the
risk of any liability for income trust Unitholders. In another development
affecting the trust sector, the Federal Government has delayed discussion on
legislating a cap on foreign ownership. At year-end 2004, approximately 16% of
NAL's Unitholders were non-resident Canadians.
Finally, after leading NAL for 15 years as President and CEO, I have advised the
Board of Directors that I will be retiring some time this year. An executive
search is underway, and once the new President and CEO has been identified and a
proper transition has taken place, I will retire from NAL's management and from
the Trust's Board of Directors. I have thoroughly enjoyed the opportunity to
lead our Trust and am proud of the many, many achievements NAL has made since we
started out in 1990 as NAL Resources Management Limited. At the time, we had
production of about 300 boed; we established NAL Oil & Gas Trust in May 1996.
Today, total production of the Trust and Manulife Financial's oil and gas
interests - both managed by NAL Resources Management Limited - amounts to
approximately 40,000 boed.
I would like to take this opportunity to thank NAL's hard-working, success-
driven team as well as our directors who have made sure Unitholders' interests
always came first. They all made my task easier, and I will miss them.
/T/
Donald P. Driscoll
President and Chief Executive Officer
March 2, 2005
Financial and Operating Highlights
(thousands of dollars, except per unit and boe data)
-------------------------------------------------------------------------
Quarter Quarter Quarter 12 months 12 months
ended ended ended ended ended
December September December December December
31, 2004 30, 2004 31, 2003 31, 2004 31, 2003
FINANCIAL
Gross revenue,
net of royalties $43,110 $43,989 $37,698 $166,313 $131,876
Net income 11,754 13,279 2,679 44,867 48,670
Funds from
Operations 29,633 38,809 24,414 115,882 92,418
Deduct:
Contributions to
reclamation reserve (28) (100) (137) (349) (434)
Actual abandonment
and environmental
costs (787) (363) (617) (1,698) (1,201)
------------------------------------------------------
Funds available
for distribution
before: 28,818 30,346 23,660 113,835 90,783
Funds applied to
debt and capital (3,372) (5,606) (913) (17,442) (13,724)
------------------------------------------------------
Distributions
declared 25,446 24,740 22,747 96,393 77,059
Distributions
declared per unit $0.48 $0.47 $0.45 1.85 $1.78
Debt repayment and
capital per unit 0.06 0.11 0.02 0.34 0.33
Total assets $415,645 $421,493 $438,736 $415,645 $438,736
Long-term debt,
net of working
capital 96,864 87,772 97,039 96,864 97,039
Unitholders'
equity 261,037 272,714 284,626 261,037 284,626
Costs per boe (6:1):
Operating $7.49 $6.98 $6.99 $6.49 $6.07
General and
administrative 1.94 1.57 1.46 1.60 1.35
Management fees 0.86 1.77 0.75 1.44 1.04
OPERATING
Daily production
Oil (bbl) 8,273 8,145 8,597 8,231 5,881
Natural gas (Mcf) 25,145 24,572 28,541 25,707 27,703
Natural gas
liquids (bbl) 495 567 765 623 790
Oil equivalent
(boe - 6:1) 12,958 12,807 14,118 13,139 11,289
Average pricing,
net of transport-
ation charges and
hedging
Liquids:
WTI (US$/bbl) 48.27 43.85 31.18 41.40 31.04
NAL average oil
(Cdn$/bbl) 50.47 52.48 37.22 46.76 39.18
Natural gas
liquids
(Cdn$/bbl) 47.67 41.05 32.24 39.18 31.71
Natural gas:
AECO (Cdn$/Mcf) 7.07 6.67 5.59 6.79 6.70
Natural gas
Western Canada
(Cdn$/Mcf) 6.57 6.31 5.64 6.50 6.51
Natural gas
Lake Erie
(Cdn$/Mcf) 7.82 7.76 7.00 8.10 8.34
NAL average
natural gas
(Cdn$/Mcf) 6.82 6.60 5.98 6.79 6.94
Oil equivalent
(Cdn$/boe- 6:1) 47.46 47.82 36.36 44.58 39.84
Average foreign
exchange rate
Cdn$/US$ 1.2210 1.3074 1.3158 1.3091 1.4010
Operating netback
($/boe) 27.92 29.78 21.77 27.56 25.71
-------------------------------------------------------------------------
/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 months ended
December 31, 2004 and the audited consolidated financial statements for the
twelve months ended December 31, 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 fourth quarter amounted to $28.8 million
or $0.54 per unit, compared with $23.7 million or $0.47 per unit for the same
three-month period in 2003. The year-over-year increase was the result of a 31%
rise in oil equivalent pricing. Year-to-date funds available for distribution
were $113.8 million ($2.19 per unit), up 25% from the $90.8 million ($2.15 per
unit) reported for the equivalent period in 2003. In addition to stronger crude
prices, 2004 benefited from a full year of production from the August 2003
southeast Saskatchewan acquisition.
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. The $0.16 monthly distribution will remain in effect for the second
quarter of 2005, barring any major fluctuations in commodity prices and the U.S.
dollar exchange rate.
/T/
Unitholders' Distributions
(thousands of dollars, except per unit amounts) (unaudited)
----------------------------------------------
Quarter Quarter 12 months 12 months
ended ended ended ended
December December December December
31, 2004 31, 2003 31, 2004 31, 2003
Funds from operations $29,633 $24,414 $115,882 $92,418
Deduct:
Contributions to
reclamation reserve (28) (137) (349) (434)
Actual abandonment and
environmental costs (787) (617) (1,698) (1,201)
-------------------------------------------------------------------------
Funds available for
distribution before: 28,818 23,660 113,835 90,783
Funds applied to debt
repayment and capital (3,372) (913) (17,442) (13,724)
-------------------------------------------------------------------------
Distributions declared $25,446 $22,747 $96,393 $77,059
-------------------------------------------------------------------------
Distributable income per
unit(1) $0.54 $0.47 $2.19 $2.15
-------------------------------------------------------------------------
Distributions declared
per unit $0.48 $0.45 $1.85 $1.78
-------------------------------------------------------------------------
Weighted average units
outstanding 52,988,079 50,541,808 51,982,731 42,201,179
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding
/T/
Production
During the fourth quarter, the Trust's output averaged 12,958 boed, down eight
percent from 14,118 boed recorded in the fourth quarter of 2003 and essentially
unchanged from the third quarter of 2004. The year-over-year decrease in
production can be attributed to the depletion of the Nisku (D3) reservoir at
Joffre along with natural production declines at other properties. Total 2004
production was 16% higher than in 2003 due largely to the August 2003 southeast
Saskatchewan acquisition.
Late in the fourth quarter, the Trust tied in 54 (net) of the 58 (net) Second
White Specks shallow gas wells drilled in the Brent/Hanna area during the
previous quarter. Fourth quarter production additions in our southeast
Saskatchewan core area were offset by high initial declines from horizontal oil
wells drilled earlier in the year at Alida. In the meantime, these Alida wells
have stabilized as anticipated.
/T/
Daily Production Volumes
3 months ended 12 months ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
------------------------------------------------
Oil (bbl/d) 8,273 8,597 (4%) 8,231 5,881 40%
Natural gas (Mcf/d) 25,145 28,541 (12%) 25,707 27,703 (7%)
NGL (bbl/d) 495 765 (35%) 623 790 (21%)
Oil equivalent (boe/d) 12,958 14,118 (8%) 13,139 11,289 16%
/T/
Commodity Prices
Crude Oil and Natural Gas Liquids (NGLs)
Throughout the fourth quarter, world oil prices in U.S. dollar terms remained
strong. WTI benchmark crude averaged US$48.27/bbl during this period, up 55%
from US$31.18 a year ago and 10% higher than the third quarter of 2004. Calendar
2004 saw WTI average US$41.40/bbl, 33% higher than in 2003. NAL's fourth quarter
crude price per barrel, after the effect of transportation costs, averaged
$50.47, up 36% from the prior-year period. Although the WTI reference price was
up 10% in the fourth quarter over the previous quarter, NAL's crude price
realization was down four percent as it was adversely affected by a stronger
Canadian dollar and weaker crude differentials. An influx of heavy sour crude in
the fourth quarter put downward price pressure on NAL's predominantly light sour
crude production.
NAL's 2004 average crude oil price per barrel after the effect of hedging and
transportation costs was $46.76, 19% higher than the 2003 price of $39.18. A
seven percent increase in the value of 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 oil price by $1.59 per barrel. There were no oil-
related hedging contracts in place during the fourth quarter of 2004.
Year-over-year, the price per barrel of NGLs rose by 48% to $47.67/bbl from a
fourth quarter 2003 level of $32.24. Compared to the previous quarter, the NGL
price was up 16%. NGL pricing for the twelve months ended December 31, 2004 was
$39.18 per barrel, 24% 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 26% higher in the fourth
quarter of 2004 over the comparable period of 2003, with the AECO reference
price averaging $7.07/Mcf versus $5.59/Mcf for the comparable quarter last year.
Over the prior quarter, fourth quarter 2004 natural gas prices rose six percent
as the AECO monthly index price averaged $6.67/Mcf in the third quarter of 2004.
When comparing year-to-date pricing levels, 2004 AECO pricing was up a modest
one percent from 2003.
Natural gas from our Lake Erie production was sold at $7.82/Mcf in the fourth
quarter, up from $7.00/Mcf a year ago and essentially unchanged from the third
quarter of 2004. Year-to-date, Lake Erie's price totaled $8.10/Mcf, a three
percent decrease over 2003. Lake Erie's gas represents approximately 18% of
NAL's total natural gas production and is premium priced because it is close to
the Ontario and northeastern U.S. markets.
Overall, NAL received an average natural gas price, net of transportation costs
for the three and twelve months ended December 31, 2004, of $6.82/Mcf and
$6.79/Mcf, respectively, compared with $5.98/Mcf and $6.94/Mcf reported in the
same periods last year.
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. The realized payments by NAL from these sales contracts reduced
2004 revenue by $4.8 million. As at December 31, 2004 NAL has no outstanding
pricing contracts.
Revenue and Cash Flow from Operations
Gross revenue, net of transportation charges and hedging, from oil, natural gas
and natural gas liquids sales totaled $56.6 million in the three months ended
December 31, 2004, a 20% increase over the same period last year. The primary
reason for the year-over year increase was a 31% improvement in oil equivalent
pricing, offset somewhat by an eight percent reduction in production. Revenues
for the year ended December 31, 2004 totaled $214.4 million, 31% higher than the
corresponding period last year. The increase is attributable to a 16% growth in
production volumes stemming from the August 2003 southeast Saskatchewan property
acquisition and a 12% rise in oil equivalent pricing. Corresponding cash flows
tracked revenues, up 21% over last year's fourth quarter and up 25% when
comparing year-to-date totals.
Net Income
Net income for the three months ended December 31, 2004 was $11.8 million, $9.1
million higher than the $2.7 million recorded in the fourth quarter of 2003. A
36% higher oil price received by NAL in 2004, combined with a $2.9 million
future income tax provision recorded in the fourth quarter of 2003, were the
major contributing factors for the increase in net income. 2004 net income was
$44.9 million, compared with $48.7 million recorded in 2003. Included in the
2003 results is a $12.2 million non-cash income tax recovery. After removing the
impact of taxes, income for the year ended December 31, 2004 was up by $7.6
million over last year. Stronger crude oil pricing and higher production, offset
by higher depletion charges and a stronger Canadian dollar, 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 $14.4 million and $50.6 million for the three and twelve months
ended December 31, 2004 respectively. Expressed as a percentage of gross sales,
before hedging and transportation costs, the net royalty rate was 25.2% for the
quarter and 22.9% for the year ended 2004, up from 21.1% and 20.3%,
respectively, 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 2003, related to certain prior-year adjustments, also
contributed to this increase.
/T/
3 months ended 12 months ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
------------------------------------------------
Net royalties ($000s) 14,363 9,866 46% 50,621 33,210 52%
As % of revenue 25.2 21.1 19% 22.9 20.3 13%
$/boe 12.05 7.60 59% 10.53 8.06 31%
/T/
Operating Costs
Production expenses per boe for the fourth quarter of 2004 were up seven percent
over the fourth quarter of 2003, averaging $7.49 compared with $6.99. An eight
percent quarter-over-quarter decrease in production volumes, combined with
certain one-time costs, led to the increase. Operating costs on a per boe basis
for the year ended December 31, 2004 increased a similar seven percent 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 12 months ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
------------------------------------------------
Operating costs ($000s) 8,935 9,075 (2%) 31,223 25,001 25%
As % of revenue 15.7 19.1 (18%) 14.5 15.1 (4%)
$/boe 7.49 6.99 7% 6.49 6.07 7%
/T/
Operating Netback
NAL's operating netback for the fourth quarter was $27.92 per boe, up 28% from
the $21.77 recorded in the same period a year ago. Record high crude oil pricing
led to a 33% increase in pre-hedged oil equivalent pricing. This increase was
somewhat tempered by higher royalty payments and weaker crude oil differentials.
Operating netbacks for 2004 totaled $27.56 per boe, seven percent higher than
the $25.71 recorded in 2003. The benefit of higher crude prices was mitigated by
hedging contracts in the first six months of 2004 and a Canadian dollar that was
seven percent stronger in 2004 as compared to 2003. The end result is an
increase in oil equivalent pricing of 16%, offset somewhat by higher royalty and
operating costs.
/T/
3 months ended 12 months ended
December 31 December 31
% %
($/boe) 2004 2003 Change 2004 2003 Change
-------------------------------------------------------------------------
Revenue, net of
transportation costs 47.46 35.73 33% 45.58 39.35 16%
Hedging effect - 0.63 - (1.00) 0.49 -
Royalties, net (12.05) (7.60) 59% (10.53) (8.06) 31%
Operating expenses (7.49) (6.99) 7% (6.49) (6.07) 7%
Operating netback 27.92 21.77 28% 27.56 25.71 7%
/T/
General & Administrative (G&A)
G&A costs for the three and twelve months ended December 31, 2004 averaged $1.94
and $1.60 per boe respectively, up from $1.46 and $1.35 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 the increased G&A
expenses are higher salary costs and escalating fees for consulting and other
services that are in great demand in the current economic environment.
/T/
3 months ended 12 months ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
------------------------------------------------
G&A costs ($000s) 2,314 1,896 22% 7,697 5,583 38%
As % of revenue 4.1 4.0 3% 3.6 3.4 6%
$/boe 1.94 1.46 33% 1.60 1.35 19%
Per Trust unit ($) 0.04 0.04 0% 0.15 0.13 15%
/T/
Management Fees
Base monthly management fees for the three and twelve months ended December 31,
2004 amounted to $1.0 million and $4.0 million, respectively, up from $0.8
million and $3.3 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.
The Trust's fourth quarter performance as compared to the S&P/TSX Capped Energy
Trust Index was lower than that of its peers and as a result, the Trust recorded
no performance fee in the fourth quarter of 2004. There was a $0.2 million
performance fee awarded in the fourth quarter of 2003. In 2004 NAL paid a
maximum performance bonus to the Manager in three of four quarters. Total
performance fees paid during the year amounted to $2.9 million, up from $1.0
million recorded in 2003. Total management fees for the three and twelve months
ended December 31, 2004 were $1.0 million and $6.9 million compared with $1.0
million and $4.3 million, respectively, in the same periods last year.
/T/
3 months ended 12 months ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
------------------------------------------------
Management fees ($000s) 1,020 970 5% 6,932 4,268 62%
As % of revenue 1.8 2.0 (10%) 3.2 2.6 23%
$/boe 0.86 0.75 15% 1.44 1.04 38%
Per Trust unit ($) 0.02 0.02 0% 0.13 0.10 30%
/T/
Interest
Interest expense for the quarter ended December 31, 2004 was $1.0 million. Year-
over-year fourth quarter interest charges decreased by $0.2 million due to a
lower average debt load. Interest charges for 2004 totaled $4.0 million,
unchanged from 2003. A higher average debt level in 2004 was offset by lower
interest rates during the year.
Depletion, Depreciation and Accretion (DDA)
In the fourth quarter of 2004, depletion on property, plant and equipment and
accretion on the asset retirement obligation totaled $18.5 million, down
slightly over the comparable period in 2003. Depletion per boe rose seven
percent to $14.94 in the fourth quarter from $14.02 a year ago. In 2004,
depletion and accretion was $71.8 million compared to $55.9 million recorded
last year. Year-over-year depletion rates per boe increased 10% from a 2003
level of $13.06 to $14.33 in 2004. Higher production volumes during 2004 as well
as revisions to reserves resulting from NI 51-101 have increased the total
amount of DD&A expense.
With the adoption of CICA Handbook section 3110 on asset retirement obligations,
the petroleum and natural gas assets are increased as reflected in Note 4 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 twelve months totaled $2.8 million and $0.7 million for the
three months ended December 31, 2004. This is up from $2.1 million and $0.6
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 December 31, 2004, NAL had 53,064,140 units outstanding - 2,499,637 units
more than on December 31, 2003, reflecting the additional units issued through
the Trust's Distribution Reinvestment Plan (DRIP). As at March 2, 2005 there
were 70,203,019 units outstanding. The increase from December 31, 2004 is almost
entirely attributable to the 17 million units issued to fund the February 2005
acquisition of Addison Energy Inc. The DRIP generated net proceeds of $2.0
million in the fourth quarter and $27.9 million for the year ended December 31,
2004. The proceeds were used to fund existing capital programs and to reduce
debt.
NAL Energy Inc. maintains a $300 million ($140 million prior to February 10,
2005), 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/
December 31, December 31, December 31,
2004 2003 2002
-------------------------------------------------------------------------
Trust unit equity ($000s) 261,037 284,626 195,424
Long-term debt ($000s) 93,700 103,500 64,900
Debt to equity 0.36 0.36 0.33
Net debt(*) ($000s) 96,864 97,039 62,125
Net debt to trailing 12 month
cash flow 0.84 1.05 1.15
-----------------------------------------------------
(*) 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)
2005 2006 2007 2008 2009
Office lease(1) 2,105 2,238 1,765 - -
Transportation Agreement(2) 1,315 284 - - -
(1) Represents the full amount of office lease commitments, 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.
Included in office lease is a $2.1 million commitment related to the
Addison Energy acquisition. The commitment starts in February 2005
and extends 30 months. NAL has subsequently sublet the premise.
(2) Includes transportation commitments associated with the Addison
Energy acquisition.
/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 fourth quarter of 2004 amounted to $18.3 million
compared with $7.9 million a year ago. In the fourth quarter, NAL spent $10.3
million on development drilling, $7.4 million on facilities and equipment, and
$0.6 million on geological and geophysical and other corporate assets. In the
fourth quarter of 2004 NAL disposed of a minor property interest in southeast
Saskatchewan for proceeds of $3.7 million. Year-to-date capital expenditures
totaled $49.0 million, up from $28.2 million recorded in 2003. In addition, NAL
spent $0.9 million on the purchase of minor land interests in 2004, compared
with $1.9 million last year. 2003 saw NAL purchase assets in southeast
Saskatchewan for $136.7 million after purchase- price adjustments.
Development Activities
During the fourth quarter, the Trust participated in a total of 27 wells (11.27
net) with a 100% success rate.
In southeast Saskatchewan, a total of 17 wells (6.82 net) were drilled during
the third quarter. At Star Valley, five (2.10 net) oil wells are on production.
At Steelman, one oil well (0.31 net) is on production and two (0.62 net)
injection wells were drilled to improve oil recovery from adjacent wells. At
Alida, two (0.90 net) oil wells are on production and one oil well (1.0 net) is
on production at Browning. At Elswick, one (0.39 net) oil well is on production
and one oil well (0.50 net) is awaiting tie-in.
In central Alberta, 10 wells (4.45 net) were successfully drilled during the
quarter. A six-well Edmonton Sands program was drilled in the Medicine River
area, with two gas wells (0.75 net) producing, and four (1.08) gas wells
awaiting tie-in. At Brent, four wells (2.62 net) were drilled, with one (1.0
net) producing gas and two (1.62 net) awaiting tie-in.
In the fourth quarter, no drilling activities took place in Lake Erie as the 20-
well program for the year had been completed early in the third quarter.
/T/
Quarterly Information
2004 2003
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------
Financial
Revenue, net of
royalties 43,110 43,989 40,674 38,540 37,698 33,378 28,615 32,185
Per unit 0.81 0.84 0.79 0.76 0.75 0.79 0.75 0.85
Funds flow from
operations 29,633 30,809 28,789 26,651 24,414 23,615 19,844 24,545
Per unit 0.56 0.59 0.56 0.52 0.48 0.56 0.52 0.65
Net income 11,754 13,279 10,871 8,963 2,679 8,701 24,381 12,909
Per unit 0.22 0.25 0.21 0.18 0.05 0.21 0.64 0.34
/T/
Critical Accounting Estimates
The significant accounting policies used by NAL are disclosed in the notes to
NAL's December 31, 2004 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.
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.
Asset Retirement Obligation
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. Any changes to the amount or timing of
future liabilities or the related inflation rate and discount factor may affect
the carrying value of the asset and associated liability and accretion expense.
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 March 2, 2005
/T/
Consolidated Balance Sheets
(thousands of dollars) (audited)
-------------------------
As at As at
December 31, December 31,
2004 2003
(Restated
- Note 4)
Assets
Current assets
Cash and cash equivalents $ 1,111 $ 574
Accounts receivable and other 19,709 21,583
-----------------------------------------------------------------------
20,820 22,157
Reclamation reserve (Note 5) 3,434 3,085
Future income tax asset (Note 13) 4,676 3,929
Property, plant and equipment, net (Note 6) 386,715 409,565
-----------------------------------------------------------------------
$ 415,645 $ 438,736
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Liabilities and
Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 15,494 $ 8,111
Distributions payable to Unitholders 8,490 7,585
Current portion of long-term debt 23,425
-----------------------------------------------------------------------
47,409 15,696
Long-term debt (Note 8) 70,275 103,500
Asset retirement obligations (Note 7) 36,924 34,914
-----------------------------------------------------------------------
154,608 154,110
Unitholders' equity
Unitholders' capital (Note 9) 476,620 448,683
Accumulated income 175,258 130,391
Accumulated distributions (Note 10) (390,841) (294,448)
-----------------------------------------------------------------------
261,037 284,626
-----------------------------------------------------------------------
$ 415,645 $ 438,736
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Commitments (Note 14)
-----------------------------------------------------------------------
Subsequent event (Note 15)
-----------------------------------------------------------------------
Units outstanding 53,064,140 50,564,503
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Income and Accumulated Income
(thousands of dollars, except per unit amounts)
---------------------------------------------------
Quarter Quarter 12 months 12 months
ended ended ended ended
December 31, December 31, December 31, December 31,
2004 2003 2004 2003
(unaudited) (Restated (audited) (Restated
- Note 4) - Note 4)
(unaudited) (audited)
-------------------------------------------------------------------------
Revenue
Oil, natural gas
and liquids sales $ 56,962 $ 47,588 $ 215,988 $ 165,598
Transportation costs (383) (368) (1,589) (1,416)
Royalty and other
income 894 344 2,535 904
Crown royalties,
net of ARTC (11,225) (7,917) (39,787) (26,591)
Freehold and other
royalties (3,138) (1,949) (10,834) (6,619)
-------------------------------------------------------------------------
43,110 37,698 166,313 131,876
-------------------------------------------------------------------------
Expenses
Operating 8,935 9,075 31,223 25,001
General and
administrative 2,314 1,896 7,697 5,583
Management fees
(Note 11) 1,020 970 6,932 4,268
Interest on long-
term debt 1,001 1,219 4,015 4,015
Depletion, depreciation
and amortization 17,816 18,214 68,941 53,806
Accretion on asset
retirement obligations 721 651 2,821 2,107
-------------------------------------------------------------------------
31,807 32,025 121,629 94,780
-------------------------------------------------------------------------
Income before taxes 11,303 5,673 44,684 37,096
Income and capital
taxes (207) (124) (564) (591)
Future income tax
recovery (provision)
(Note 13) 658 (2,870) 747 12,165
-------------------------------------------------------------------------
Total income and
capital taxes 451 (2,994) 183 11,574
-------------------------------------------------------------------------
Net income $ 11,754 $ 2,679 $ 44,867 $ 48,670
Accumulated income,
beginning of period
as previously reported - 131,431 134,355 86,259
Retroactive effect of
change in accounting
policy (Note 4) - (3,719) (3,964) (4,538)
-------------------------------------------------------------------------
Accumulated income,
beginning of period,
as restated 163,504 127,712 130,391 81,721
-------------------------------------------------------------------------
Accumulated income,
end of period $ 175,258 $ 130,391 $ 175,258 $ 130,391
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust
unit $0.22 $0.05 $0.86 $1.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average units
outstanding 52,988,079 50,541,808 51,982,731 42,201,179
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Cash Flows
(thousands of dollars)
---------------------------------------------------
Quarter Quarter 12 months 12 months
ended ended ended ended
December 31, December 31, December 31, December 31,
2004 2003 2004 2003
(unaudited) (Restated (audited) (Restated
- Note 4) - Note 4)
(unaudited) (audited)
-------------------------------------------------------------------------
Operating activities
Net income $ 11,754 $ 2,679 $ 44,867 $ 48,670
Items not involving
cash:
Depletion,
depreciation
and amortization 17,816 18,214 68,941 53,806
Accretion on asset
retirement
obligations 721 651 2,821 2,107
Future income tax
provision (recovery) (658) 2,870 (747) (12,165)
-------------------------------------------------------------------------
Funds from operations 29,633 24,414 115,882 92,418
Abandonment and
environmental
expenditures (787) (617) (1,698) (1,201)
Decrease (increase)
in non-cash working
capital 5,165 (4,572) 8,562 (13,278)
-------------------------------------------------------------------------
34,011 19,225 122,746 77,939
-------------------------------------------------------------------------
Financing Activities
Distributions to
Unitholders (25,421) (22,741) (95,488) (74,417)
Issue of Trust units,
net of issue costs 2,015 239 27,937 117,017
Advances from (repayment
of) long-term debt 1,500 4,500 (9,800) 38,600
-------------------------------------------------------------------------
(21,906) (18,002) (77,351) 81,200
-------------------------------------------------------------------------
Investing Activities
Acquisition of
property, plant
and equipment - (674) (859) (140,830)
Investment in property,
plant and equipment (18,337) (7,906) (48,982) (28,198)
Proceeds from
dispositions 3,858 3,220 4,637 3,373
Reclamation reserve (28) (137) (349) (434)
Decrease in non-cash
working capital 3,297 3,849 695 6,529
-------------------------------------------------------------------------
(11,210) (1,648) (44,858) (159,560)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Increase (decrease)
in cash and cash
equivalents 895 (425) 537 (421)
Cash and cash
equivalents,
beginning of period 216 999 574 995
-------------------------------------------------------------------------
Cash and cash
equivalents,
end of period $ 1,111 $ 574 $ 1,111 $ 574
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure
of cash flow information:
Cash paid during
the period for:
Interest $ 978 $ 1,188 $ 3,914 $ 3,929
Taxes $ 207 $ 124 $ 564 $ 591
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of dollars, except per unit amounts)
1. BASIS OF PRESENTATION
NAL Oil & Gas Trust's ("NAL" or the "Trust") financial statements
include the accounts of the Trust and its wholly owned subsidiaries
and partnerships and have been prepared in accordance with Canadian
generally accepted accounting principles. All inter-entity
transactions and balances have been eliminated.
2. STRUCTURE OF THE TRUST
The Trust is an open-end investment trust formed under the laws of
the Province of Alberta. Operations commenced on May 9, 1996. The
principal undertaking of the Trust is to indirectly acquire and hold,
through it's direct and indirect wholly owned subsidiaries interests
in oil and natural gas properties and the distribution of net cash
proceeds to its Unitholders.
The Trust is managed by NAL Resources Management Limited (the
"Manager"). The Manager receives a monthly management fee from the
Trust equal to 3.0% of net operating income, defined as total
revenues received from the sales of petroleum substances and other
income sources, less operating costs and royalties. The Manager is
also entitled to a performance fee that is calculated quarterly based
on the Trust's total return compared to its peer group. The total
return for the Trust is calculated by dividing the quarter's closing
unit price less the quarter's opening unit price, plus cash
distributions for the quarter, by the quarter's opening unit price.
This is compared to the percentage increase in the S&P/TSX Capped
Energy Trust Index. A performance fee ranging from 0.5% to 3%, of the
Trust's quarterly net operating income, is then paid in cash for the
Trust's return in excess of the peer group. The Manager is also
entitled to a recovery for general and administrative costs incurred
on behalf of the Trust.
3. SUMMARY OF ACCOUNTING POLICIES
Property, Plant and Equipment
The Trust follows the full cost method of accounting for oil and
natural gas properties whereby all acquisition and development costs
are capitalized. Such costs include land acquisition, geological and
geophysical and drilling costs for productive and non-productive
wells. General and administrative costs charged by the Manager
directly related to development activities are capitalized.
Depletion of oil and natural gas properties and depreciation of
equipment is calculated using the unit of production method based on
total proven reserves before royalties as estimated by independent
engineers. Natural gas reserves are converted to barrels of oil
equivalent based on relative energy content. Proceeds from the sale
of oil and natural gas properties are applied against capitalized
costs, with no gain or loss recognized, unless such sale would alter
the depletion and depreciation rate by 20% or more.
Oil and natural gas assets are evaluated in each reporting period to
determine that the carrying amount in a cost centre is recoverable
and does not exceed the fair value of the properties in the cost
centre.
The carrying amounts are assessed to be recoverable when the sum of
the undiscounted cash flows expected from the production of proved
reserves exceeds the carrying amount of the cost centre. When the
carrying amount is not assessed to be recoverable, an impairment loss
is recognized to the extent that the carrying amount of the cost
centre exceeds the sum of the discounted cash flows expected from the
production of proved and probable reserves. The cash flows are
estimated using expected future product prices and costs and
discounted using a risk-free rate.
Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and all investments
that are highly liquid in nature and generally have a maturity date
of three months or less.
Asset Retirement Obligation
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 income 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.
Measurement Uncertainty
The amounts recorded for depletion, depreciation and amortization of
property, plant and equipment and the provision for asset retirement
obligations are based on estimates of proved reserves and future
costs. The ceiling test is also based on estimates of proved
reserves, production rates, oil and natural gas prices, future costs
and other relevant assumptions. Though considered reasonable by the
Manager, these estimates are subject to measurement uncertainty, the
impact of which on future financial statements could be material.
Income Taxes
The Trust is a taxable entity under the Canadian Income Tax Act and
is taxable only on income that is not distributed to Unitholders. The
tax deductions received by the Trust for the distributions to
Unitholders represent an exemption from taxation equivalent to the
Trust's earnings. In addition, the Trust is exempt from future income
taxes because it is contractually committed to distribute all of its
income to its Unitholders. Ventures Trust, a subsidiary of the Trust,
is also exempt from future income taxes because it is contractually
committed to distribute all of its tax- exempt income to the Trust
who ultimately distributes the income to the Unitholders.
The Trust's subsidiaries follow the liability method of accounting
for income taxes. Under this method, income tax liabilities and
assets are recognized for the estimated tax consequences attributable
to differences between the amounts reported in the financial
statements and their respective tax bases, using substantially
enacted income tax rates. The effect of a change in income tax rates
on future income tax liabilities and assets is recognized in income
in the period that the change occurs.
Joint Ventures
Substantially all of the development and production activities are
conducted jointly with others and, accordingly, these financial
statements reflect only the Trust's proportionate interest in such
activities.
Financial Instruments
The Trust uses, from time to time, derivative financial instruments
to manage exposure related to changes in oil and natural gas
commodity prices. They are not used for trading or speculative
purposes.
The Trust formally documents all relationships between hedging
instruments and hedged items, as well as its risk management
objective and strategy for undertaking various hedge transactions.
This process includes linking all derivatives to specific assets and
liabilities on the balance sheet or to specific firm commitments or
anticipated transactions.
The Trust also formally assesses, both at the hedge's inception and
on an ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair
values or cash flows of hedged items. For cash flow hedges,
effectiveness is achieved if the changes in the cash flows of the
derivative substantially offset the changes in the cash flows of the
hedged position and the timing of the cash flows is similar.
Effectiveness for fair value hedges is achieved if the fair value of
the derivative substantially offsets changes in the fair value
attributable to the hedged item. In the event that a derivative does
not meet the designation or effectiveness criterion, the gain or loss
on the derivative is recognized in income. If a derivative that
qualifies as a hedge is settled early, the gain or loss at settlement
is deferred and recognized when the gain or loss on the hedged
transaction is recognized. Premiums paid or received with respect to
derivatives that are hedges are deferred and amortized to income over
the term of the hedge.
Realized gains or losses on changes in oil and natural gas commodity
prices are recognized in income in the same period and in the same
financial statement category as the income or expense arising from
corresponding commodity swap contracts (see Note 12).
Revenue Recognition
Oil, natural gas and liquids sales are recognized when title and
risks pass to the purchaser.
4. CHANGES IN ACCOUNTING POLICY
Asset Retirement Obligation
Effective January 1, 2004, NAL adopted the asset retirement
obligation method of recording the future cost associated with
removal, site restoration and asset retirement costs as outlined
in Note 3. 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 2,250
Accumulated income (3,964) (4,538)
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------
3 months
ended Year ended
December 31, December 31,
Statements of Income 2003 2003
---------------------------------------------------------------------
Accretion on asset retirement obligations ($651) ($2,107)
Depletion and depreciation on
asset retirement costs (708) (1,825)
Amortization of estimated future removal
and site restoration liability 1,494 4,301
Future income taxes (380) 205
---------------------------------------------------------------------
Net income impact (245) 574
Net income per Trust unit 0.00 0.01
---------------------------------------------------------------------
---------------------------------------------------------------------
Hedging
Effective January 1, 2004, NAL adopted the hedging policy guideline
as outlined in Note 3. There was no effect on prior-period net
income.
5. RECLAMATION RESERVE
The Trust has established a reclamation reserve to assist in funding
its future asset retirement obligations. During 2004, $349,000
(2003-$434,000) was deposited to this reserve. The quarterly deposit
amount may be adjusted by the Trust from time to time based on its
assessment of its share of expected future asset retirement costs.
The reserve is managed by an arms length investment firm and all
interest earned on the reserve is reinvested in the reserve on an
ongoing basis.
6. PROPERTY, PLANT AND EQUIPMENT ("PP&E")
Net book value as at December 31:
2004 2003
(Restated
- Note 4)
---------------------------------------------------------------------
Oil and natural gas properties, at cost $ 685,737 $ 639,646
Less: Accumulated depletion and depreciation (299,022) (230,081)
---------------------------------------------------------------------
$ 386,715 $ 409,565
---------------------------------------------------------------------
---------------------------------------------------------------------
During 2004, the Trust capitalized $1,813,000 (2003-$1,405,000) of
general and administrative costs that were directly related to
exploitation and development programs.
On August 28, 2003 the Trust bought properties in the Steelman and
Weyburn areas of southeast Saskatchewan for $136.7 million after
purchase price adjustments. The acquisition was initially financed
with debt drawn on the Trust's credit facility.
The Trust performed a ceiling test calculation at December 31, 2004
to assess the recoverable value of PP&E. Based on the calculation,
the present value of future net revenues from the Trust's proved
reserves exceeded the carrying value of the Trust's PP&E at
December 31, 2004. The benchmark prices used in the calculation are
as follows:
US$/Cdn$
WTI Oil Exchange WTI Oil AECO Gas
Year (US$/bbl) Rate (Cdn$/bbl) (Cdn$/GJ)
---------------------------------------------------------------------
2005 42.59 0.832 51.19 6.18
2006 40.42 0.835 48.41 6.15
2007 39.10 0.837 46.71 5.77
2008 38.03 0.837 45.44 5.48
2009 37.32 0.836 44.64 5.18
2010 36.89 0.835 44.18 5.01
---------------------------------------------------------------------
Remainder(1) 2.0% 0.835 2.0% 2.0%
---------------------------------------------------------------------
(1) Percentage change represents the change in each year after 2010
to the end of the reserve life.
7. 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 are approximately $98.6 million. The majority
of the costs will be incurred between 2005 and 2033. 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:
---------------------------------------------------------------------
December 31, December 31,
2004 2003
---------------------------------------------------------------------
Balance, beginning of period $ 34,914 $ 24,424
Accretion expense 2,821 2,107
Liabilities incurred 887 9,584
Liabilities settled (1,698) (1,201)
---------------------------------------------------------------------
Balance, end of period $ 36,924 $ 34,914
---------------------------------------------------------------------
---------------------------------------------------------------------
8. LONG-TERM DEBT
The Trust has a revolving credit facility of $140 million
($300 million after the February 10, 2005 purchase of Addison Energy
Inc.). The credit facility is fully secured by a floating debenture
over the Trust's and its subsidiaries' 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. In the event that the credit facility is not
extended at the end of the 364-day period, it converts into a term
facility, repayable in eight equal instalments.
The effective interest rate on the outstanding amounts at
December 31, 2004, was approximately four percent.
9. TRUST UNITS
Authorized:
500,000,000 Trust units
Issued as at December 31:
2004 2003
---------------------------------------------------
Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning
of the year 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 2,499 27,937 48 470
---------------------------------------------------------------------
Balance, end of year 53,064 $ 476,620 50,565 $ 448,683
---------------------------------------------------------------------
---------------------------------------------------------------------
Distribution Reinvestment Plan
The Distribution Reinvestment Plan ("DRIP") entitles Unitholders to
reinvest cash distribution in additional units of the Trust.
Unitholders may reinvest their cash distributions in additional Trust
units at 95% of the average market price. Essentially, average
market price means the arithmetic average of the daily volume
weighted average trading price of the Trust units during a defined
period before the distribution payment date.
The Premium Distribution component of the Plan allows Unitholders to
exchange new Trust units, acquired by reinvesting their cash
distributions, for a cash payment equal to 102% of a given monthly
distribution on the applicable distribution payment date.
The Trust units issued under the Premium Distribution component of
the Plan at a 5% discount to the average market price will be
delivered to the Plan Broker in exchange for 102% of the cash
distribution payable on the participant's existing Trust units. At
certain times and at the discretion of management, these premium
distributions may be pro-rated.
10. DISTRIBUTIONS
Distributions since the inception of the Trust are as follows:
Other Return of
Income Capital Total
---------------------------------------------------------------------
Cumulative distributions at
December 31, 2002 $ 100,248 $ 117,141 $ 217,389
2003 distributions 34,677 42,382 77,059
---------------------------------------------------------------------
Cumulative distributions at
December 31, 2003 $ 134,925 $ 159,523 $ 294,448
2004 distributions 60,318 36,075 96,393
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Cumulative distributions at
December 31, 2004 $ 195,243 $ 195,598 $ 390,841
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11. RELATED PARTY TRANSACTIONS
The Manager provides services pertaining to the significant
operating, financing and investing activities of the Trust pursuant
to a management agreement. During 2004, the Manager charged the Trust
$3,976,000 (2003-$3,251,000) for base monthly management fees and
$2,956,000 (2003 - $1,017,000) in performance fees. In 2004 the
Manager charged the Trust $5,864,000 (2003-$3,340,000) for general
and administrative costs.
The Manager is a wholly-owned subsidiary of Manulife Financial
Corporation ("MFC") and manages, on their behalf, NAL Resources
Limited ("NAL Resources"), another wholly-owned subsidiary of MFC.
NAL Resources and the Trust maintain ownership interests in many of
the same oil and natural gas properties, in which NAL Resources is
the joint venture operator. As a result, a significant portion of the
net operating revenues and capital expenditures during the year are
based on joint venture amounts from NAL Resources. These transactions
are in the normal course of joint venture operations and are measured
using the fair value established through the original transactions
with third parties.
The following amounts are due to and from related parties as at
December 31:
2004 2003
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Due to NAL Resources Limited $ 2,147 $ 5,216
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Due to NAL Resources Management Limited $ 1,224 $ 1,014
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12. FINANCIAL INSTRUMENTS
Commodity Price Risk Management
The Trust, from time to time, implements a price risk management
program whereby the commodity price associated with a portion of its
future production is fixed. The Trust sells forward a portion of its
future production through a combination of fixed price sales
contracts with customers and commodity swap agreements with financial
counter parties. The forward and futures contracts are subject to
market risk from fluctuating commodity prices and exchange rates;
however, gains or losses on the contracts are offset by changes in
the value of the Trust's production.
The Trust does not have any derivative or hedging agreements in place
as at December 31, 2004. The Trust made net settlement payments of
approximately $4,797,000 million (2003 - received $2,031,000 million)
for the year ended December 31, 2004, which have been included in
oil, natural gas and liquids sales revenue.
Credit Risk Management
Accounts receivable includes amounts due from NAL Resources for oil,
natural gas and natural gas liquids sales. Oil and gas sales
marketing is conducted by the Manager on behalf of the Trust and
NAL Resources generally with large, creditworthy purchasers, for
which the Trust views the credit risk as low. The credit risk
associated with NAL Resources is also considered to be minimal as
amounts owing are from actual collections of oil and gas sales.
Interest Rate
The Trust is exposed to interest rate risk to the extent that bank
debt is at a floating rate of interest.
Fair Values
The carrying value of the Trust's financial instruments, including
accounts receivable, long-term debt, and accounts payable and accrued
liabilities approximate their fair value due to their short terms to
maturity and variable interest rates.
13. INCOME TAXES
Trust:
Taxable income for the Trust for 2004 was $60,318,000 (2003-
$34,677,000). Taxable income consists of income from the royalty,
distributions from Ventures Trust and interest and dividends from
subsidiaries less deductions for the Trust's general and
administrative costs, resource allowance, Canadian Oil and Gas
Property Expense (COGPE) and issue costs. Any losses arising from the
calculation of taxable income are carried forward and are deductible
against future taxable income for a period of seven years. The Trust
and Ventures Trust have the following tax balances available to be
claimed against future income for tax purposes:
2004 2003
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COGPE $ 221,845 $ 238,152
CDE 18,191 4,487
CEE 265 4,633
UCC 29,880 35,367
Unamortized issue costs 5,343 7,996
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---------------------------------------------------------------------
Trust's Subsidiaries:
The provision for income taxes in the financial statements differs
from the result that would have been obtained by applying the
combined federal and provincial tax rate to the Trust's income before
income taxes. This difference results from the following items:
2004 2003
(Restated
- Note 4)
---------------------------------------------------------------------
Income before taxes $ 44,684 $ 37,096
Less non-taxable earnings of the Trust (53,100) (35,575)
---------------------------------------------------------------------
Taxable earnings (loss) (8,416) 1,521
Combined federal and provincial tax rate 39.3% 41.5%
Computed income tax expense (recovery) (3,309) 631
Increase (decrease) in income taxes
resulting from:
Non-deductible Crown charges 2,431 726
Resource allowance (456) (2,210)
Alberta Royalty Tax Credit (50) (203)
Valuation allowance 753 2,509
Rate Reduction (116) (916)
Future income tax reduction from restructuring - (12,702)
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Future income taxes (747) (12,165)
Capital taxes 564 591
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Income and Capital taxes ($183) ($11,574)
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---------------------------------------------------------------------
The components of Energy and the Trust's subsidiaries' future income
tax liability are as follows at December 31:
2004 2003
(Restated
- Note 4)
---------------------------------------------------------------------
Oil and natural gas properties $ 282 ($654)
Future tax liability resulting from
different year ends 431 133
Non-capital tax loss carry forward (3,204) (835)
Provision for site restoration (8,728) (8,363)
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(11,219) (9,719)
Valuation allowance 6,543 5,790
---------------------------------------------------------------------
($4,676) ($3,929)
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As at December 31, 2004, the Trust's subsidiaries have non-capital
losses of $8,316,000 that may be carried forward to reduce future
taxable income. These losses start to expire in 2010.
14. COMMITMENTS
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:
($000s) 2005 2006 2007 2008 2009
Office lease(1) 2,105 2,238 1,765 - -
Transportation
Agreement(2) 669 284 - - -
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(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager of which NAL is
allocated a pro rata share of the expense on a monthly basis.
Included in office lease is a $2.1 million commitment related to
the Addison Energy acquisition. The commitment starts in February
2005 and extends 30 months. NAL has subsequently sublet the
premise.
(2) Includes transportation commitments associated with the Addison
Energy acquisition.
15. SUBSEQUENT EVENT
On February 10, 2005 the Trust acquired all of the issued and
outstanding shares of Addison Energy Inc. ("Addison"), a wholly-owned
subsidiary of a private U.S. company, for $550 million. On the same
date, the Trust also sold to a wholly-owned subsidiary of MFC an
undivided 30% interest in the Addison properties for $165 million
immediately upon closing of the share purchase. The net purchase
price to the Trust of $385 million was funded with the proceeds of a
concurrent bought-deal equity financing consisting of 17 million
units at $13.70 per unit for gross proceeds of $232.9 million and an
increase in the Trust's revolving credit facility to $300 million.
16. COMPARATIVE FIGURES
Certain comparative figures have been re-classified to conform with
current-period presentation.
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.
Trading Performance
TSX: NAE.UN
For the
Quarter
ended Full Year
31-Dec-04 30-Sep-04 31-Dec-03 30-Sep-03 2004 2003
PRICE
High $15.29 $14.29 $10.98 $10.22 $15.29 $10.98
Low $12.60 $11.68 $9.46 $9.35 $9.79 $8.46
Close $13.55 $14.29 $10.94 $9.74 $13.55 $10.94
Volume 15,265,465 9,359,852 15,926,969 12,825,681 47,130,324 38,611,262
/T/
Paul Belliveau Vice President Finance & Chief Financial Officer (403) 294-3600 or Toll Free: 1-888-223-8792 (403) 294-3699 (FAX) or Anne-Marie Buchmuller Manager, Investor Relations (403) 294-3600 or Toll Free: 1-888-223-8792 (403) 294-3699 (FAX) Email: Investor.Relations@nal.ca Website: www.nal.ca