ARC Energy Trust announces 2006 fourth quarter and year-end financial results

CALGARY, Feb. 22 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC"
or "the Trust") released today its 2006 fourth quarter and year-end financial
results.

<<
Three Months Ended Twelve Months Ended
December 31 December 31
2006 2005 2006 2005
-------------------------------------------------------------------------
FINANCIAL
($CDN millions, except per
unit and per boe amounts)
Revenue before royalties 292.5 365.3 1,230.5 1,165.2
Per unit(1) 1.42 1.89 6.02 6.10
Per boe 49.95 67.16 53.46 56.75
Cash flow(2) 174.4 207.6 760.6 639.5
Per unit(1) 0.85 1.07 3.72 3.35
Per boe 29.80 38.17 33.05 31.15
Net income 56.6 130.5 460.1 356.9
Per unit(3) 0.28 0.68 2.28 1.90
Cash distributions 122.3 115.7 484.2 376.6
Per unit(1) 0.60 0.60 2.40 1.99
Payout ratio(4) 70% 56% 64% 59%
Net debt outstanding(5) 739.1 578.1 739.1 578.1
Total capital expenditures
and net acquisitions(8) 214.9 553.6 496.3 865.1
OPERATING
Production
Crude oil (bbl/d) 29,605 25,534 29,042 23,282
Natural gas (mmcf/d) 179.5 177.9 179.1 173.8
Natural gas liquids (bbl/d) 4,144 3,943 4,170 4,005
Total (boe per day) 63,663 59,120 63,056 56,254
Average prices
Crude oil ($/bbl) 58.26 62.12 65.26 61.11
Natural gas ($/mcf) 6.99 12.05 6.97 8.96
Natural gas liquids ($/bbl) 46.51 56.43 52.63 49.91
Oil equivalent ($/boe)(6) 49.95 67.16 53.46 56.75
Operating netback ($/boe)
Commodity and other
revenue (before hedging) 49.95 67.16 53.46 56.75
Transportation costs (0.64) (0.65) (0.63) (0.70)
Royalties (8.80) (13.51) (9.66) (11.46)
Operating costs (9.13) (7.16) (8.49) (6.93)
Netback (before hedging) 31.37 45.84 34.68 37.66
-------------------------------------------------------------------------
TRUST UNITS
(thousands)
Units outstanding,
end of period 204,289 202,039 204,289 202,039
Units issuable for
exchangeable shares 2,884 2,934 2,884 2,934
Total units outstanding
and issuable for exchangeable
shares, end of period 207,173 204,973 207,173 204,973
Weighted average units(7) 203,580 190,510 201,554 188,237
-------------------------------------------------------------------------
TRUST UNIT TRADING STATISTICS
($CDN, except volumes) based
on intra-day trading
High 29.22 27.58 30.74 27.58
Low 19.20 20.45 19.20 16.55
Close 22.30 26.49 22.30 26.49
Average daily volume (thousands) 1,125 653 706 656
-------------------------------------------------------------------------
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(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average units plus units issuable for exchangeable
shares.
(2) Management uses cash flow to analyze operating performance and
leverage. Cash flow as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Cash flow as presented is not intended to represent
operating cash flow or operating profits for the period nor should it
be viewed as an alternative to cash flow from operating activities,
net earnings or other measures of financial performance calculated in
accordance with Canadian GAAP. All references to cash flow throughout
this report are based on cash flow from operating activities before
changes in non-cash working capital and expenditures on site
restoration and reclamation.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average units (excluding units issuable
for exchangeable shares).
(4) Cash distributions divided by cash flow from operations. This ratio
would have increased to 71 per cent and 65 per cent, respectively,
for the three and twelve months ended December 31, 2006 if the
exchangeable shares had been converted to trust units at the
beginning of the period.
(5) Net debt excludes unrealized commodity and foreign exchange contracts
asset and liability.
(6) Includes other revenue.
(7) Excludes trust units issuable for outstanding exchangeable shares at
period end.
(8) Includes total consideration for the corporate acquisition including
fees but prior to working capital, asset retirement obligation and
future income tax liability assumed on acquisition.

ACCOMPLISHMENTS / FINANCIAL UPDATE
----------------------------------

- Production averaged 63,056 boe per day in 2006, the highest in the
Trust's history and 12 per cent higher than the 56,254 boe per day
achieved in 2005. Fourth quarter production reached 63,663 in 2006,
an eight per cent increase over the same period in 2005. The increase
in annual and fourth quarter production is due primarily to the
Redwater and NPCU acquisitions which occurred late in 2005 and several
minor acquisitions that closed in 2006. Natural production declines
were replaced through a successful and active drilling program.
Production per unit increased by seven per cent to 0.31 boe per day
per thousand units in 2006, from 0.29 boe per day per thousand units
in 2005.

- ARC realized record cash flow from operations of $760.6 million
($3.72 per unit) in 2006 compared to $639.5 million ($3.35 per unit)
in 2005. The 19 per cent increase in 2006 cash flow was due to
increased production volumes, cash hedging gains, slightly higher oil
prices that offset the impact of lower natural gas prices and higher
operating costs. Fourth quarter cash flow decreased by 16 percent from
$207.6 million ($1.07 per unit) in 2005 to $174.4 million ($0.85 per
unit) in 2006. The decrease in fourth quarter cash flow was largely
attributed to a 42 per cent decrease in ARC's realized gas price
compared to the fourth quarter of 2005.

- The Trust posted record net income, before future income taxes and
non-controlling interest, of $379.6 million in 2006 compared to $364.1
million in 2005. Strong oil prices on average during 2006, combined
with record production volume, resulted in revenue of $1.2 billion,
the highest since inception of the Trust. Fourth quarter net income
before future income tax and non-controlling interest decreased from
$152.2 million in 2005 to $61.2 million in 2006. In addition to lower
commodity prices, foreign exchange losses, higher depletion expense
and a decrease in non-cash gains on commodity and foreign currency
contracts contributed to the decrease in net income for the fourth
quarter of 2006.

- The Trust declared record cash distributions of $484.2 million in 2006
($2.40 per unit), resulting in a full year payout ratio of 64 per
cent. The remaining 36 per cent of 2006 cash flow ($276.4 million) was
used to fund 72 per cent of ARC's capital development program and to
contribute $13.2 million, inclusive of interest income, to the
reclamation funds. Fourth quarter distributions were $122.3 million
($0.60 per unit) in 2006 compared to $115.7 million ($0.60 per unit)
in 2005 resulting in a payout ratio of 70 percent in 2006 compared to
56 percent in the fourth quarter of 2005.

- In 2006, the Trust completed its most extensive drilling program to
date with 294 gross wells (219 net wells) drilled on operated
properties with a 99 per cent success rate. The most significant
activity was focused in southeastern Alberta as the Trust drilled 125
net shallow gas wells. In addition, the Trust was active in northern
and central Alberta 2006, with the drilling of 61 net wells. In the
fourth quarter of 2006 ARC drilled 59 gross wells (45 net wells) with
a 100 per cent success rate.

- The Trust replaced 96 per cent of its annual production through a
combination of its $364.5 million 2006 capital development program and
by making oil and natural gas property acquisitions. The Trust added
16.3 mmboe of reserves from its 2006 capital development program and
an additional 5.8 mmboe of reserves were added through $132 million of
net acquisitions. Fourth quarter capital spending increased to $121.9
million compared to $87.8 million in the same period of 2005.

- At year end 2006 the Trust's proved plus probable reserves stood at
286.1 mmboe, compared to 287 at year end 2005. The Trust's reserve
life index is 12.4 years and reserves per unit remained constant
relative to 2005 at 1.4 boe per unit.

- Oil prices were at historically high levels throughout much of the
year while natural gas prices weakened significantly early in 2006.
The price of oil reached a high of US$77.03 per barrel in July before
tumbling to a low of US$55.81 per barrel in November. The AECO natural
gas monthly index opened the year at $12.11 per mcf and declined to a
low of $4.45 per mcf in October. The Trust's product mix being almost
equally weighted to oil and natural gas served to mitigate the impact
of the significant decline in natural gas prices in 2006 relative to
2005 levels. In addition, the Trust realized a cash gain of $29.3
million on its hedging program in 2006 entirely due to natural gas
hedges. Fourth quarter realized prices decreased significantly from
2005 and in particular natural gas prices.

- The Trust realized an operating netback, before hedging, of $34.68 per
boe in 2006 ($31.37 per boe in Q4 2006) compared to $37.66 per boe in
2005 ($45.84 per boe in Q4 2005). The lower netback per boe was
primarily due to the significant reduction in natural gas prices in
2006 and increased operating costs. Operating costs increased to $8.49
per boe in 2006 ($9.13 per boe in Q4 2006) compared to $6.93 per boe
in 2005 ($7.16 per boe in Q4 2005), due to the higher cost Redwater
and NPCU properties and overall industry operating cost increases.

- The Trust achieved a recycle ratio of 1.6 in 2006, a significant
accomplishment in light of unprecedented industry activity and
continual cost increases throughout 2006. The lower recycle ratio is
due to higher finding, development and acquisition costs, which were
partly due to a significant investment in undeveloped land with no
associated reserves. Net undeveloped land increased to 529,000 acres
at year-end 2006, an increase of 43,000 acres from 2005. The Trust's
three year average recycle ratio was 2.1 demonstrating a successful
long-term capital development program and high quality of the Trust's
assets.

- The Trust continues to maintain low debt levels as indicated by a net
debt to 2006 cash flow from operations of 1.0 and net debt to total
capitalization as at December 31, 2006 of 14 per cent. In addition,
the Trust maintains a reclamation fund balance to provide for future
abandonment and reclamation of its wells and facilities. The fund
balance was $30.9 million at December 31, 2006 and represents one of
the largest reclamation funds in the oil and gas sector.

- On October 31, 2006, the Federal Government announced tax proposals
pertaining to taxation of distributions paid by publicly traded income
trusts ("the proposed Trust taxation"). Currently, the Trust does not
pay tax on distributions as tax is paid by the unitholders. The
proposals would result in a two-tiered tax structure whereby
distributions would be subject to a 31.5 per cent tax at the Trust
level commencing in 2011 and then unitholders would be subject to tax
on the distribution as if it were a taxable dividend paid by a taxable
Canadian corporation. The Tax announcement had a significant impact on
the Canadian equity markets with a significant devaluation of trust
unit prices. Despite the devaluation of the trust unit price following
the taxation announcement, the Trust's core business remains
unchanged. The Trust is currently assessing the draft legislation and
alternatives with respect to the future structure of the Trust.

- Subsequent to year-end, options on ARC Energy Trust units began
trading on the Montreal Stock Exchange. The options will enable
investors to buy and sell "calls" and "puts" on ARC's Trust units.
>>

MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------

This management's discussion and analysis ("MD&A") is dated February 20,
2007 and should be read in conjunction with the audited consolidated financial
statements for the year ended December 31, 2006 and the audited consolidated
financial statements and MD&A for the year ended December 31, 2005 and MD&A
for the quarters ended March 31, 2006, June 30, 2006 and September 30, 2006.

Non-GAAP Measures
Management uses cash flow, cash flow from operations and cash flow from
operations per unit derived from cash flow from operating activities (before
changes in non-cash working capital and expenditures on site reclamation and
restoration) to analyze operating performance and leverage. Cash flow as
presented does not have any standardized meaning prescribed by Canadian
generally accepted accounting principles, ("GAAP") and therefore it may not be
comparable with the calculation of similar measures for other entities. Cash
flow as presented is not intended to represent operating cash flow or
operating profits for the period nor should it be viewed as an alternative to
cash flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian GAAP.
The following table reconciles the cash flow from operating activities to
cash flow from operations which is used frequently in this MD&A:

<<
-------------------------------------------------------------------------
($ millions) 2006 2005
-------------------------------------------------------------------------
Cash flow from operating activities 734.0 616.7
Changes in non-cash working capital 16.0 17.9
Expenditures on site reclamation and restoration 10.6 4.9
-------------------------------------------------------------------------
Cash flow from operations 760.6 639.5
-------------------------------------------------------------------------
>>

Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as operating netbacks ("netbacks"), total capitalization,
finding, development and acquisition costs, recycle ratio, reserve life index,
reserves per unit and production per unit to analyze financial and operating
performance. Management feels that these KPI's and benchmarks are a key
measure of profitability and overall sustainability for the Trust. These KPI's
and benchmarks as presented do not have any standardized meaning prescribed by
Canadian GAAP and therefore may not be comparable with the calculation of
similar measures for other entities.

Fourth Quarter Financial and Operational Results
The Trust had an active fourth quarter with the closing of $93 million of
acquisitions and $121.9 million spent on capital development activities which
contributed to quarterly average production of 63,663 boe per day. The Trust
had a payout ratio of 70 per cent and funded $48.8 million of its fourth
quarter capital development program with cash flow. The fourth quarter was an
active one for the Trust with the drilling of 59 gross wells on operated
properties and new production coming on-stream.
Late in the fourth quarter, natural gas prices started to recover to
levels not seen since the first quarter of 2006, however, oil prices declined.
Due to increasing electricity prices, the Trust's fourth quarter operating
costs were higher than previous quarters of 2006. Electricity prices declined
to be in line with historical levels late in the quarter.
The Government's proposed Trust taxation announcement on October 31, 2006
was an unforeseen event in the fourth quarter of 2006 and it had a significant
impact throughout the trust sector. With the government announcement, there
was a significant devaluation in trust unit prices and a mass "sell off" of
trust units whereby the Trust incurred an approximate 20 per cent decrease in
the trust unit price and a resulting negative total return to unitholders in
the fourth quarter and 2006 as a whole. Despite this event, ARC's core
business is unchanged and the Trust's financial results are strong as
indicated by record levels of production, revenue, capital spending, net
income, cash flow, and distributions to unitholders in 2006.

Refer to "Quarterly Historical Review" in this MD&A for key quarterly
financial and operational results.

<<
- The Trust's fourth quarter production was 63,663 boe per day, an
increase of eight per cent from the fourth quarter of 2005 due to
acquisitions in late 2005 and during 2006.

- Cash flow decreased to $174.4 million ($0.85 per unit) from $207.6
million ($1.07 per unit) in the fourth quarter of 2005. Despite eight
per cent higher volumes in the fourth quarter of 2006, significantly
lower commodity prices and higher operating costs were the key
contributors to the lower cash flow. Fourth quarter cash hedging gains
of $9.8 million partially offset the lower commodity prices (cash
hedging losses were $26.5 million in the fourth quarter of 2005).

- Net income decreased to $56.6 million ($0.28 per unit) from $130.4
million ($0.68 per unit) in the fourth quarter of 2005. In addition to
the cash flow items listed above, 2006 net income decreased due to a
$19.8 million increase in foreign exchange losses, a $22.5 million
increase in depletion, a $24.2 million decrease in non-cash gains on
commodity and foreign currency contracts offset by a $16.1 million
decrease in future income tax expense and an $8.3 million decrease in
the non-cash portion of G&A as compared to 2005.

- The Trust maintained fourth quarter distributions at $0.20 per unit
per month and paid out $122.3 million for a payout ratio of 70 per
cent (56 per cent in the fourth quarter of 2005). The remaining $52.1
million of fourth quarter cash flow was used to fund $48.8 million (40
per cent) of the capital expenditure program and contribute $3.4
million to the Trust's reclamation funds, including interest.

- Both oil and natural gas prices recovered slightly late in the fourth
quarter, however the total realized price for the quarter was 26 per
cent lower than in 2005 due primarily to significantly lower natural
gas prices and a stronger Canadian dollar which resulted in lower
Canadian denominated commodity prices. The WTI oil price averaged US
$60.22 per barrel in the fourth quarter, effectively unchanged from US
$60.05 barrel in 2005. The stronger Canadian dollar resulted in a
lower Canadian denominated oil price of $68.60 per barrel relative to
$70.45 per barrel in 2005. The AECO monthly natural gas price was
$6.36 per mcf, a 46 per cent decrease compared to the fourth quarter
of 2005. The total realized price was $49.94 per boe, a 26 per cent
decrease compared to $67.16 per boe in the fourth quarter of 2005.

- The fourth quarter netback before hedging decreased to $31.37 per boe
compared to $45.84 per boe in 2005 due to a 26 per cent decrease in
the realized price per boe. In addition, operating costs increased to
$9.13 per boe in 2006 due to the higher cost Redwater and NPCU
properties acquired in late 2005. Alberta electricity prices were
significantly higher in the fourth quarter of 2006 relative to 2005
and service and labour costs increased throughout the industry in 2006
relative to 2005 levels.

- The Trust spent $121.9 million on capital development activities and
undeveloped land in the fourth quarter compared to $87.8 million in
2005. The Trust had a very active fourth quarter with the drilling of
59 gross wells (45 net wells) on operated properties with a 100 per
cent success rate. The Trust expanded its inventory of undeveloped
land acreage with the purchase of $11.9 million of land in the fourth
quarter. The land acquired was in core areas where the Trust has
identified strategic development opportunities.

- Net debt levels increased to $739.1 million in the fourth quarter as a
result of $93 million of acquisitions and debt funded capital
expenditures of $44.4 million. A devaluation of the Canadian dollar
relative to the U.S. dollar also impacted the Trust's net debt levels
as 71 percent of the Trust's debt is denominated in U.S. dollars. With
the higher debt levels, interest expense increased to $8.7 million
($1.48 per boe) in the fourth quarter compared to $6 million ($1.11
per boe) in 2005.

- Cash G&A expenses increased to $1.74 per boe from $1.39 per boe in the
fourth quarter of 2005. The increased G&A expenses were due to higher
compensation costs in 2006. In addition, the Trust made a $0.7 million
cash payout under the Whole Unit Plan for units vesting in the fourth
quarter while no units vested in the fourth quarter of 2005. Non-cash
G&A per boe decreased significantly in the fourth quarter of 2006,
with a recovery of $0.02 per boe compared to an expense of $1.43 per
boe in 2005 due to the devaluation of the trust unit price following
the proposed Trust taxation announcement on October 31, 2006, which
resulted in a lower value of the Whole Unit Plan and resultant non-
cash expense. In addition, the Trust recorded lower non-cash rights
expense in the fourth quarter of 2006 due to majority of the rights
having vested and thus been fully expensed early in 2006.

-------------------------------------------------------------------------
Fourth Quarter Financial and
Operational Highlights
(CDN$ millions except per unit
and per cent) Q4 2006 Q4 2005 % Change
-------------------------------------------------------------------------
Production (boe/d) 63,663 59,120 8
Cash flow from operations 174.4 207.6 (16)
Per unit $ 0.85 $ 1.07 (21)
Cash distributions 122.3 115.7 6
Per unit $ 0.60 $ 0.60 -
Payout ratio (per cent) 70 56 26
Net income 56.6 130.4 (57)
Per unit $ 0.28 $ 0.68 (59)
-------------------------------------------------------------------------
Prices
WTI (US$/bbl) 60.22 60.05 -
USD/CAD exchange rate 0.87 0.85 3
Realized oil price (CDN $/bbl) 58.26 62.12 (6)
AECO gas monthly index (CDN $/mcf) 6.36 11.68 (46)
Realized gas price (CDN $/mcf) 6.99 12.05 (42)
-------------------------------------------------------------------------
Operating netback ($/boe)
Revenue, before hedging 49.94 67.16 (26)
Royalties (8.80) (13.51) (35)
Transportation (0.64) (0.65) (1)
Operating costs (9.13) (7.16) 28
Netback (before hedging) 31.37 45.84 (32)
Cash hedging gain (loss) 1.68 (4.86) (135)
Netback (after hedging) $ 33.05 $ 40.98 (20)
-------------------------------------------------------------------------
Capital expenditures 121.9 87.8 39
Capital funded with cash flow (per cent) 40 106
-------------------------------------------------------------------------

2006 Annual Financial and Operational Results

Following is a discussion of ARC's 2006 annual financial and operating
results.

Financial Highlights

-------------------------------------------------------------------------
(CDN $ millions, except per unit
and volume data) 2006 2005 % Change
-------------------------------------------------------------------------
Cash flow from operations 760.6 639.5 19
Cash flow from operations per unit(1) 3.72 3.35 11
Net income before future income tax
and non-controlling interest 379.6 364.1 4
Net income 460.1 356.9 29
Net income per unit(2) 2.28 1.90 20
Distributions per unit(3) 2.40 1.99 21
Payout ratio per cent(4) 64 59 8
Average daily production (boe/d)(5) 63,056 56,254 12
-------------------------------------------------------------------------
(1) Per unit amounts are based on weighted average units plus units
issuable for exhangeable shares at year-end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units excluding trust units issuable for
exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Based on cash distributions divided by cash flow from operations.
(5) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf:1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of boe in isolation may be
misleading.
>>

Net Income
Net income in 2006 was $460.1 million ($2.28 per unit), an increase of
$103 million from $356.9 million ($1.90 per unit) in 2005 as a result of
higher production volumes, strong oil prices throughout 2006 and total hedging
gains on the commodity hedging program of $24.7 million compared to losses of
$87.6 million in 2005. A significant future income tax recovery of
$87.1 million in 2006, attributed to the reduction in legislated future
corporate income tax rates, also resulted in higher net income in 2006
relative to 2005.

Cash Flow from Operations
Cash flow from operations increased by 19 per cent in 2006 to
$761 million from $640 million in 2005. The increase in 2006 cash flow was the
result of a 12 per cent increase in production volumes, partially offset by
lower natural gas prices. Cash flow was further increased by cash hedging
gains of $29.3 million in 2006 compared to a cash hedging loss of
$87.6 million in 2005. A change in the Trust's product mix and the acquisition
of properties with lower effective royalty rates resulted in lower royalty
expense in 2006. The increases in 2006 cash flow were somewhat offset by
higher operating costs, higher cash G&A expenses and higher interest expense
attributed to increased debt levels. Per unit cash flow from operations
increased 11 per cent to $3.72 per unit from $3.35 per unit in 2005.

Following is a summary of variances in cash flow from operations from
2005 to 2006:

<<
-------------------------------------------------------------------------
($ per
trust (%
($ millions) unit) variance)
-------------------------------------------------------------------------
2005 Cash flow from
Operations 639.5 3.35
-------------------------------------------------------------------------
Volume variance $ 140.9 $ 0.74 % 22
Price variance (75.6) (0.40) (12)
Cash gains on commodity
and foreign currency
contracts(1) 116.8 0.61 18
Royalties 13.0 0.07 2
Expenses:
Transportation (0.2) (0.00) -
Operating(2) (54.0) (0.28) (8)
Cash G&A (8.9) (0.05) (1)
Interest (14.8) (0.08) (2)
Taxes 3.6 0.02 1
Realized foreign
exchange gain 0.3 0.00 -
Weighted average
trust units (0.26)
-------------------------------------------------------------------------
2006 Cash flow
from Operations $ 760.6 $ 3.72 % 19
-------------------------------------------------------------------------
(1) Represents cash losses on commodity and foreign currency contracts
including cash settlements on termination of commodity and foreign
currency contracts.
(2) Excludes non-cash portion of LTIP expense recorded in operating
costs.
>>

Production
Production volume averaged 63,056 boe per day in 2006 compared to 56,254
boe per day in 2005. The Redwater and North Pembina Cardium Unit ("NPCU")
acquisitions contributed approximately 5,500 boe per day (net) in 2006 that
includes 580 boe per day (net) of incremental production on wells reactivated
during the year. With the acquisition of producing properties in Manitoba, an
incremental 785 boe per day of production came on-stream in the fourth quarter
of 2006.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During 2006, the Trust drilled 294 gross wells
(219 net wells) on operated properties; 72 gross oil wells and 222 gross
natural gas wells with a 99 per cent success rate.
The Trust expects that 2007 full year production will be approximately
63,000 boe per day and that 275 gross wells (225 net wells) will be drilled by
ARC on operated properties with participation in an additional 150 gross wells
to be drilled on the Trust's non-operated properties. The Trust estimates that
the 2007 drilling program will add 11,000 boe per day of production which will
offset production declines at existing properties.

<<
-------------------------------------------------------------------------
Production 2006 2005 % Change
-------------------------------------------------------------------------
Crude oil (bbl/d) 27,674 22,032 26
Heavy oil (bbl/d) 1,368 1,250 9
Natural gas (mcf/d) 179,067 173,800 3
NGL (bbl/d) 4,170 4,005 4
-------------------------------------------------------------------------
Total production (boe/d)(1) 63,056 56,254 12
% Natural gas production 47 51
% Crude oil and liquids production 53 49
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>

Oil production increased by 25 per cent to 29,042 boe per day in 2006
from 23,282 boe per day in 2005. The increase in oil production was largely
attributed to the Redwater and NPCU acquisitions late in 2005. The Trust's
weighting of oil and liquids production increased to 53 per cent in 2006 from
49 per cent in 2005 as the new volumes from Redwater and NPCU were primarily
liquids.
Natural gas production increased to 179.1 mmcf per day in 2006, a three
per cent increase from the 173.8 mmcf per day produced in 2005. The majority
of this increase was as a result of ARC's active 2006 internal drilling
program particularly in northern and central Alberta. In addition, the Trust
drilled 125 net operated natural gas wells in southeastern Alberta and
southwestern Saskatchewan during 2006, the majority of which were drilled in
the third quarter and came on production during the fourth quarter.
The following table summarizes the Trust's production by core area:

<<
-------------------------------------------------------------------------
2006
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 8,206 1,553 31.3 1,433
Northern AB & BC 18,897 6,194 67.6 1,452
Pembina & Redwater 13,950 9,453 20.0 1,157
S.E. AB & S.W. Sask. 10,743 1,071 58.0 9
S.E. Sask. 11,260 10,771 2.2 119
-------------------------------------------------------------------------
Total 63,056 29,042 179.1 4,170
-------------------------------------------------------------------------

-------------------------------------------------------------------------
2005
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 8,041 1,364 30.2 1,641
Northern AB & BC 18,286 6,026 65.3 1,381
Pembina & Redwater 7,953 4,166 17.7 832
S.E. AB & S.W. Sask. 11,298 1,499 58.7 15
S.E. Sask. 10,676 10,227 1.9 136
-------------------------------------------------------------------------
Total 56,254 23,282 173.8 4,005
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, S.E. is southeast, S.W. is southwest.

Commodity Prices Prior to Hedging

-------------------------------------------------------------------------
Average Benchmark prices 2006 2005 % Change
-------------------------------------------------------------------------
AECO gas ($/mcf)(1) 6.98 8.45 (17)
WTI oil (US$/bbl)(2) 66.25 56.61 17
USD/CAD foreign exchange rate 0.88 0.83 6
WTI oil (CDN $/bbl) 75.00 68.52 9
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Oil prices reached historic highs in 2006 peaking at US$77.03 per barrel
averaging US$66.25 per barrel for the full year of 2006. The strength of the
Canadian dollar served to partially offset the impact of higher U.S.
denominated oil prices. The Trust's oil production consists predominantly of
light and medium crude oil while heavy oil accounts for less than three per
cent of the Trust's liquids production. Overall the price of WTI oil in
Canadian dollars increased by nine per cent over the prior year to $75.00
versus $68.52 in 2005.
Alberta AECO Hub natural gas prices, which are commonly used as an
industry reference, averaged $6.98 per mcf in 2006 compared to $8.45 per mcf
in 2005. Natural gas prices started the year at an historic high point of
$12.11 per mcf but declined dramatically throughout the second and third
quarters. ARC's realized gas price, before hedging, decreased by 22 per cent
to $6.97 per mcf compared to $8.96 per mcf in 2005. ARC's realized gas price
is based on prices received at the various markets in which the Trust sells
its natural gas. ARC's natural gas sales portfolio consists of gas sales
priced at the AECO monthly index, the AECO daily spot market, eastern and
mid-west United States markets and a portion to aggregators.
Prior to hedging activities, ARC's total realized commodity price was
$53.33 per boe in 2006, a six per cent decrease from the $56.54 per boe
received prior to hedging in 2005.
The following is a summary of realized prices:

<<
-------------------------------------------------------------------------
ARC Realized Prices Prior to Hedging 2006 2005 % Change
-------------------------------------------------------------------------
Oil ($/bbl) 65.26 61.11 7
Natural gas ($/mcf) 6.97 8.96 (22)
NGL ($/bbl) 52.63 49.92 5
-------------------------------------------------------------------------
Total commodity revenue before
hedging ($/boe) 53.33 56.54 (6)
Other revenue ($/boe) 0.13 0.21 (38)
Total revenue before hedging ($/boe) 53.46 56.75 (6)
-------------------------------------------------------------------------
>>

Revenue
Revenue increased to a historical high of $1.2 billion in 2006. The
increase in revenue was attributable to higher volumes and higher oil prices
which were partially offset by lower natural gas prices.
A breakdown of revenue is as follows:

<<
-------------------------------------------------------------------------
Revenue
($ millions) 2006 2005 % Change
-------------------------------------------------------------------------
Oil revenue 691.8 519.3 33
Natural gas revenue 455.7 568.7 (20)
NGL revenue 80.1 73.0 10
-------------------------------------------------------------------------
Total commodity revenue 1,227.6 1,161.0 6
Other revenue 2.9 4.2 (31)
Total revenue 1,230.5 1,165.2 6
-------------------------------------------------------------------------
>>

Risk Management and Hedging Activities

The Trust continues to maintain a strong hedging mandate with an emphasis
on protecting cash flow and distributions to unitholders.
The Trust's risk management activities are conducted by an internal Risk
Management Committee, based upon guidelines approved by the Board and the
following mandate:

<<
- protect unitholder return on investment;
- provide protection for minimum monthly cash distributions to
unitholders;
- employ a portfolio approach to risk management by entering into a
number of small positions that build upon each other;
- participate in commodity price upturns to the greatest extent possible
while limiting exposure to price downturns; and,
- ensure profitability of specific oil and gas properties that are more
sensitive to changes in market conditions.

To satisfy this mandate, the board of directors has approved that up to
three per cent of forecast revenues may be spent on option premiums on a
go-forward basis to achieve price protection and satisfy the risk management
mandate while limiting the risk exposure of hedged positions.
In 2006 ARC implemented the following strategies to protect distributions
and provide upside commodity price participation to the unitholder:

- Protected power consumption with electricity swaps;
- Protected natural gas prices with an energy equivalent swap to crude
oil;
- Protected the 2005 Redwater acquisitions volume with US$55 floors via
a 3-way collar;
- Protected price conversion of US$ denominated WTI crude oil with
foreign exchange swaps;
- Protected on average 44 per cent of natural gas production and 35 per
cent of crude oil production for the year;
- Protected as much as 62 per cent of natural gas production volumes
during the most vulnerable fall months;
- Protected natural gas and crude oil production with a portfolio of
floor and ceiling option contracts.
>>

ARC uses a combination of puts and call options otherwise known as floors
and ceilings to protect budgeted commodity prices. A floor or put option
ensures a minimum selling price and a ceiling or call option establishes a
maximum selling price. ARC employs a strategy of buying floors and offsetting
the cost of those floors by selling ceilings at higher prices or selling
additional floors at lower prices. The net cost or premiums associated with
the protection that is put in place is viewed as an insurance premium to
ensure cash flow and stability of distributions, while maintaining strong
upside price participation.
By implementing these strategies ARC realized total cash hedging gains of
$29.3 million in 2006 as illustrated in detail in the "Gain or Loss on
Commodity and Foreign Currency Contracts" section of this MD&A. In addition,
cash hedging gains of $3.4 million on electricity hedges have been recorded as
a reduction of 2006 operating costs.
On a forward-looking basis ARC continues to put layers of protection in
place on both crude oil and natural gas. ARC has protection on approximately
40 per cent of oil production and 25 per cent of natural gas production for
2007 as shown in the following table which represents ARC's positions in place
as at January 31, 2007.

<<
-------------------------------------------------------------------------
2007 Hedge Positions
as at January 31, 2007(1)(2)
Q1 Q2
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 89.05 7,500 89.05 7,500
Bought Put 63.42 13,656 63.46 13,000
Sold Put 50.02 10,000 50.02 13,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 10.89 93,566 8.39 113,028
Bought Put 7.97 93,566 7.05 113,028
Sold Put 5.50 10,000 5.15 50,000
-------------------------------------------------------------------------
FX CAD/USD $M/month CAD/USD $M/month
-------------------------------------------------------------------------
Bought Put 1.1321 2.4 1.1321 2.4
Sold Put 1.0990 2.0 1.0990 2.0
Swap 1.1387 16.6 1.1387 16.6
-------------------------------------------------------------------------

-------------------------------------------------------------------------
2007 Hedge Positions
as at January 31, 2007(1)(2)
Q3 Q4
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 87.65 7,500 87.65 7,500
Bought Put 61.67 12,000 61.67 12,000
Sold Put 48.13 12,000 48.13 12,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.89 50,000 10.58 30,839
Bought Put 7.15 50,000 7.62 30,839
Sold Put 5.15 50,000 5.15 16,848
-------------------------------------------------------------------------
FX CAD/USD $M/month CAD/USD $M/month
-------------------------------------------------------------------------
Bought Put 1.1321 2.4 1.1321 2.4
Sold Put 1.0990 2.0 1.0990 2.0
Swap 1.1387 16.6 1.1387 16.6
-------------------------------------------------------------------------
(1) Note that the prices and volumes noted above represents averages for
several contracts and the average price for the portfolio of options
listed above does not have the same payoff profile as the individual
option contracts. Viewing the average price of a group of options is
purely for indicative purposes. The natural gas price shown
translates all NYMEX positions to an AECO equivalent price. In
addition to positions shown here, ARC has entered into additional
basis positions.
(2) Please refer to the Trust's website at www.arcenergytrust.com under
"Hedging Program" within the "Investor Relations" section for details
on the Trust's hedging positions as of January 31, 2007.
>>

The above table should be interpreted as follows using the 2007 Q1 Crude
Oil Hedges as an example. For oil, the Trust has hedged 13,656 barrels per day
at a minimum average price of US$63.42 and participates in prices up to a
maximum average of US$89.05 on 7,500 barrels per day with no limit on the
remaining 6,156 barrels per day hedged. Finally, ARC's average protected price
of $63.42 reduces penny for penny at an average price below $50.02 on 10,000
barrels per day.
During 2006 ARC entered into "basis" natural gas contracts to lock in the
difference between the Henry Hub index and the AECO monthly index. This set of
transactions diversifies ARC's price exposure from the AECO basin to the
broader North American market, thus reducing ARC's sensitivity to regional
market events. Basis swaps are negotiated in terms of a fixed price in
US$ per mmbtu that is deducted from the NYMEX natural gas price. For the
period January 1, 2007 through March 2007, the Trust locked in the basis at
US$1.31 per mmbtu on an average volume of 40,000 mcf per day and ARC has an
average basis price of US$1.08 per mmbtu on an average volume of 50 mmcf per
day of natural gas for the period of April 2007 through October 2010.
In addition to these positions the Trust has fixed the price of
electricity for a portion of its power consumption at average prices between
$59.33 and $64.63 through 2010 to mitigate the risk associated with
fluctuating electricity prices which have a large impact on operating costs. A
significant portion of the Trust's power usage is subject to the deregulated
Alberta Power Pool price which was extremely volatile during 2006 and ranged
from a record high monthly average price of $174.09 mw/h to a low of $42.87
mw/h. The electricity hedge represents approximately 69 per cent of the
Trust's Alberta power consumption at operated properties.
The Trust considers its risk management contracts to be effective
economic hedges as they meet the objectives of the Trust's risk management
mandate. In order to mitigate credit risk, the Trust executes commodity and
foreign currency hedging risk management with financially sound, credit worthy
counterparties. All contracts require approval of the Trust's Risk Management
Committee prior to execution. Deferred premiums payable will be recorded as a
realized cash hedging loss when payment is made in a future period. These
premiums may be partially offset if ARC sells any short-term options. The
Trust's oil contracts are based on the WTI index and the majority of the
Trust's natural gas contracts are based on the AECO monthly index.
For a complete summary of the Trust's oil, natural gas and foreign
exchange hedges, please refer to "Hedging Program" under the "Investor
Relations" section of the Trust's website at www.arcenergytrust.com.

Gain or Loss on Commodity and Foreign Currency Contracts
Gain or loss on commodity and foreign currency contracts comprise
realized and unrealized gains or losses on commodity and foreign currency
contracts that do not meet the accounting definition of the requirements of an
effective hedge, even though the Trust considers all commodity and foreign
currency contracts to be effective economic hedges. Accordingly, gains and
losses on such contracts are shown as a separate category in the statement of
income.
The Trust recorded a realized cash gain on commodity and foreign currency
contracts of $29.3 million in 2006 as compared to a loss of $87.6 million
recorded in 2005. The majority of the 2006 cash gains were attributed to the
natural gas hedges whereby the Trust utilized a variety of contracts to lock
in the minimum price on natural gas. As gas prices declined subsequent to the
first quarter, the Trust realized significant gains on the contracts.
The following is a summary of the total gain (loss) on commodity and
foreign currency contracts for 2006:

<<
-------------------------------------------------------------------------
Commodity and
foreign currency
contracts
Crude Oil Natural Foreign 2006 2005
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash
gain (loss) on
contracts(1) (7.7) 29.7 7.3 29.3 (87.6)
Unrealized gain
(loss) on
contracts(2) 6.2 (4.1) (6.7) (4.6) -
-------------------------------------------------------------------------
Total gain (loss)
on commodity
and foreign
currency
contracts (1.5) 25.6 0.6 24.7 (87.6)
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
>>

Operating Netbacks
The Trust's operating netback, after realized hedging gains or losses,
increased eight per cent to $35.95 per boe in 2006 compared to $33.40 per boe
in 2005. The increase in netbacks in 2006 is primarily due to higher oil
prices in 2006, a decrease in royalties, and cash hedging gains of $1.27 per
boe compared to losses of $4.26 per boe in 2005. A decline in natural gas
prices and higher operating costs partially offset the higher revenue and
lower royalties.

The components of operating netbacks are shown below:

<<
-------------------------------------------------------------------------
Crude Heavy 2006 2005
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 66.16 46.90 6.97 52.63 53.33 56.54
Other revenue - - - - 0.13 0.21
Total revenue 66.16 46.90 6.97 52.63 53.46 56.75
Royalties (10.80) (4.86) (1.37) (14.08) (9.66) (11.46)
Transportation (0.14) (0.86) (0.19) - (0.63) (0.70)
Operating
costs(1) (11.51) (10.63) (0.96) (7.49) (8.49) (6.93)
-------------------------------------------------------------------------
Netback prior
to hedging 43.71 30.55 4.45 31.06 34.68 37.66
Realized gain
(loss) on
commodity and
foreign
currency
contracts (0.05) - 0.45 - 1.27 (4.26)
-------------------------------------------------------------------------
Netback after
hedging 43.66 30.55 4.90 31.06 35.95 33.40
-------------------------------------------------------------------------
(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
>>

Royalties decreased to $9.66 per boe in 2006 compared to $11.46 per boe
in 2005. Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs decreased to 18 per cent compared to 20 per cent in 2005.
The decrease in royalties is due to a lower effective royalty rate in 2006 as
a result of the increased oil weighting of the Trust's production following
the 2005 acquisitions and royalty concessions received on certain British
Columbia natural gas properties. In addition, the Redwater and NPCU properties
acquired in 2005 carried a significantly lower effective royalty rate than the
Trust's existing properties due to the royalty structure of the properties.
Operating costs increased to $8.49 per boe compared to $6.93 per boe in
2005. The acquisition of the Redwater and NPCU properties, with operating
costs of approximately $22 per boe in 2006, contributed to a large portion of
the 23 per cent increase in operating costs. However, the Redwater and NPCU
properties also contribute high netbacks of $40.60 per boe and $40.19 per boe,
respectively, due to the premium oil quality and low royalty regime. Despite
reductions in natural gas prices during 2006, the industry was still
experiencing increasing costs for services, supplies, materials, electricity
and labour throughout 2006. In particular, areas in northern Alberta
experienced significant cost increases for services, materials and labour. In
addition, the cost of electricity in Alberta was extremely volatile during the
second half of 2006 with daily average prices ranging from $16.49 mw/h to
$576.10 mw/h. Approximately 69 per cent of the Trust's electricity usage on
Alberta operated properties was hedged at approximately $63 mw/h whereby the
Trust was partially protected from the increases in electricity costs. The
electricity hedge resulted in a $0.15 per boe reduction in operating costs in
2006.
Transportation costs decreased 10 per cent to $0.63 per boe in 2006
compared to $0.70 per boe in 2005. This is a result of the increased
percentage of oil in the Trust's production mix as oil generally has a lower
transportation cost than natural gas as a majority of the Trust's oil
production is sold at the plantgate.
In 2007 it is expected that operating costs will increase by
approximately five per cent to $8.95 per boe primarily due to costs associated
with our newly acquired properties and the additional 11,000 boe per day of
2007 development production volumes. The Trust expects that the industry cost
pressures will ease slightly in 2007 due to the moderation in industry
activity levels experienced late in 2006.

General and Administrative Expenses and Trust Unit Incentive Compensation
Cash G&A net of overhead recoveries on operated properties increased 32
per cent to $36.3 million in 2006 from $27.4 million in 2005. Increases in
cash G&A expenses for 2006 were due to increased staff levels, higher
compensation costs and the nature of ARC's long-term incentive program. As a
result of the unprecedented levels of activity for ARC and for the industry as
a whole, the costs associated with hiring, compensating and retaining
employees and consultants have risen. The increase in G&A costs was partially
offset by higher overhead recoveries attributed to high levels of capital and
operating activity throughout 2006 and as a result of incremental overhead
charged on new and existing operated properties. On a per boe basis, cash G&A
costs increased 18 per cent to $1.58 per boe from $1.34 per boe as a result of
higher cash G&A costs partially offset by increased production volume.
The Trust paid out $5.2 million under the whole unit plan in 2006
compared to $1.6 million in 2005 ($3.5 million and $1.1 million of the payouts
were allocated to G&A in 2006 and 2005, respectively, and the remainder to
operating costs and capital projects). The higher cash payment in 2006 is
attributed to a higher unit price upon vesting in April and October of each
year, higher distributions and having two years of awards vesting in 2006
compared to one year of awards in 2005. The next cash payment under the Whole
Unit Plan is scheduled to occur in April 2007.

The following is a breakdown of G&A and trust unit incentive compensation
expense:

<<
-------------------------------------------------------------------------
G&A and Trust Unit Incentive
Compensation Expense
($ millions except per boe) 2006 2005 % Change
-------------------------------------------------------------------------
G&A expenses 45.8 35.0 31
Operating recoveries (12.9) (8.7) 48
-------------------------------------------------------------------------
Cash G&A expenses before Whole Unit Plan 32.9 26.3 25
Cash Expense - Whole Unit Plan 3.5 1.1 218
-------------------------------------------------------------------------
Cash G&A expenses including Whole Unit Plan 36.4 27.4 32
-------------------------------------------------------------------------
Accrued compensation - Rights Plan 2.5 6.5 (62)
Accrued compensation - Whole Unit Plan 8.2 8.8 (7)
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 47.1 42.7 10
-------------------------------------------------------------------------
Cash G&A expenses per boe 1.58 1.34 18
Total G&A and trust unit incentive
compensation expense per boe 2.05 2.08 (1)
-------------------------------------------------------------------------
>>

A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $10.7 million ($0.47 per boe) was recorded in 2006
compared to $15.3 million ($0.74 per boe) in 2005. This non-cash amount
relates to estimated costs of the Trust Unit Incentive Rights Plan ("Rights
Plan") and the Whole Trust Unit Incentive Plan ("Whole Unit Plan") to
December 31, 2006. Despite a higher number of units outstanding under the plan
in 2006, there was a decrease in the value of the Whole Unit Plan and a
reduction in the non-cash expense due to the decline in trust unit prices
following the Federal Government's proposed Trust taxation announcement in the
fourth quarter of 2006.

Rights Plan
The Rights Plan provides employees, officers and independent directors
the right to purchase units at a specified price. The rights have a five year
term and vest equally over three years. The exercise price of the rights is
adjusted downwards from time to time by the amount that distributions to
unitholders, in any calendar quarter exceeds 2.5 per cent of the Trust's net
book value of property, plant and equipment. The rights plan was replaced by a
Whole Unit Plan during 2004 after which no further rights under the rights
plan were issued. During 2006, one million rights were exercised or cancelled
and 0.4 million rights remained outstanding as at December 31, 2006. Of the
remaining rights outstanding, 6,000 will vest in March 2007 and compensation
expense will be recorded until that time. All other rights were fully vested
and expensed as of December 31, 2006.
The decrease in compensation expense for the rights plan in 2006 is due
to the majority of rights having vested early in 2006 and compensation expense
is only recorded up to vesting date.

Whole Trust Unit Incentive Plan ("Whole Unit Plan")
In March 2004, the Board of Directors approved a new Whole Unit Plan to
replace the Rights Plan for new awards granted subsequent to the first quarter
of 2004. The new Whole Unit Plan results in employees, officers and directors
(the "plan participants") receiving cash compensation in relation to the value
of a specified number of underlying units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
Upon vesting, the plan participant is entitled to receive a cash payment
based on the fair value of the underlying trust units plus accrued
distributions. The cash compensation issued upon vesting of the PTUs is
dependent upon the performance of the Trust compared to its peers and
indicated by the performance multiplier. The performance multiplier is based
on the percentile rank of the Trust's total unitholder return compared to its
peers. Total return is calculated as the sum of the change in the market price
of the units in the period plus the amount of distributions in the period. The
performance multiplier ranges from zero, if ARC's performance ranks in the
bottom quartile, to two for top quartile performance.
The following table shows the changes during the year of RTUs and PTUs
outstanding:

<<
-------------------------------------------------------------------------
Whole Unit Plan Total
(units in thousands and $ millions Number of Number of RTUs and
except per unit) RTUs PTUs PTUs
-------------------------------------------------------------------------
Balance, beginning of period 479 391 870
Granted in the period 373 303 676
Vested in the period (180) - (180)
Forfeited in the period (24) (11) (35)
-------------------------------------------------------------------------
Balance, end of period(1) 648 683 1,331
-------------------------------------------------------------------------
Estimated distributions to
vesting date(2) 168 222 390
Estimated units upon vesting after
distributions 816 905 1,721
Performance multiplier(3) - 2.0
-------------------------------------------------------------------------
Estimated total units upon vesting 816 1,810 2,626
-------------------------------------------------------------------------
Trust unit price at December 31, 2006 $ 22.30 $ 22.30 $ 22.30
Estimated total value upon vesting $ 18.2 $ 40.4 $ 58.6
-------------------------------------------------------------------------
(1) Based on underlying units before performance multiplier and accrued
distributions.
(2) Represents estimated additional units to be issued equivalent to
estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and approximated 2.0
at December 31, 2006. The performance multiplier is assessed each
period end based on actual results of the Trust relative to its
peers.
>>

The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the unit price, the number of PTUs to be issued on vesting, and distributions.
Therefore, the expense recorded in the statement of income fluctuates over
time.
As at December 31, 2006, the PTUs outstanding were assessed to have a
percentile rank equal or greater than 75 and thus were valued with a
performance multiplier of 2.0. Below is a summary of the range of future
expected payments under the Whole Unit Plan based on variability of the
performance multiplier:

<<
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
December 31, 2006 Performance multiplier
(units thousands and $ millions -------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 816 816 816
PTUs - 905 1,810
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total units(1) 816 1,721 2,626
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Trust unit price(2) 22.30 22.30 22.30
Trust unit distributions per month(2) 0.20 0.20 0.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting 18.2 38.8 58.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Officers 2.1 11.6 20.9
Directors 1.4 1.4 1.4
Staff 14.7 25.8 36.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total payments under Whole Unit Plan(3) 18.2 38.8 58.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 7.8 11.2 14.6
2008 6.7 14.9 23.1
2009 3.7 12.7 20.9
-------------------------------------------------------------------------
(1) Includes additional estimated units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumed
future trust unit price of $22.30 per trust unit and distributions of
$0.20 per unit per month based on current levels.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in April
and October of each year and at that time is reflected as a reduction
of cash flow from operations.
>>

Due to the variability in the future payments under the plan, the Trust
estimates that $18.2 million to $58.6 million will be paid out from 2007
through 2009 based on the current trust unit price, distribution levels and a
performance multiplier ranging from zero to two.

Interest Expense
Interest expense increased to $31.8 million in 2006 from $16.9 million in
2005 due to an increase in short-term interest rates, and higher debt balances
as a result of the Trust's acquisitions activity which was funded $125 million
with debt. As at December 31, 2006, the Trust had $687.1 million of debt
outstanding, of which $261 million was fixed at a weighted average rate of
5.056 per cent and $426.1 million was floating at current market rates plus a
credit spread of 65 basis points. Seventy-one percent of the Trust's debt is
denominated in U.S. dollars.
The following is a summary of the debt balance and interest expense for
2006 and 2005:

<<
-------------------------------------------------------------------------
Interest Expense
($ millions) 2006 2005 % Change
-------------------------------------------------------------------------
Year end debt balance(1) 687.1 526.6 30
Fixed rate debt 261.0 268.2 (3)
Floating rate debt 426.1 258.4 65
-------------------------------------------------------------------------
Interest expense before interest
rate swaps(2) 31.4 17.4 80
Loss (gain) on interest rate hedge 0.4 (0.5) 180
-------------------------------------------------------------------------
Net interest expense 31.8 16.9 88
-------------------------------------------------------------------------
(1) Includes both long-term and current portions of debt.
(2) The interest rate swap was designated as an effective hedge for
accounting purposes whereby actual realized gains and losses are
netted against interest expense.
>>

Foreign Exchange Gains and Losses
The Trust recorded a loss of $4.2 million ($0.18 per boe) on foreign
exchange transactions compared to a gain of $6.4 million ($0.31 per boe) in
2005. These amounts include both realized and unrealized foreign exchange
gains and losses. Unrealized foreign exchange gains and losses are due to
revaluation of U.S. denominated debt balances. The volatility of the Canadian
dollar during the reporting period has a direct impact on the unrealized
component of the foreign exchange gain or loss. The unrealized gain/loss
impacts net income but does not impact cash flow as it is a non-cash amount.
Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements.
Included in the 2006 realized foreign exchange gain was a gain of $2.6
million realized upon repayment of US$6 million of debt in 2006. The debt was
issued in 2002 when the USD/CAD foreign exchange rate was approximately 0.64
and strengthened considerably to 0.88 on repayment in 2006. The 2006
unrealized foreign exchange loss of $7.2 million was due to the revaluation of
U.S. denominated debt balances associated with the weakening of the Canadian
dollar relative to the U.S. dollar in 2006.

Taxes
In 2006, a future income tax recovery of $87.1 million was included in
income compared to a $1.6 million expense in 2005. The significant increase in
the future income tax recovery in 2006 was due to the legislated reduction in
the future corporate income tax rates in the second quarter of 2006 whereby
the Trust's expected future income tax rate decreased to 29.4 per cent from
33.7 per cent prior to the rate reductions.
Acquisitions completed in 2006 resulted in the Trust recording a future
income tax liability of $5.4 million due to the difference between the tax
basis and the fair value assigned to the acquired assets. The amount of tax
pools versus asset value is one of the parameters that impacts the Trust's
acquisition bid levels.
At December 31, 2006 the Trust's subsidiaries had tax pools of
approximately $1 billion. The tax pools consist of $903 million of tangible
and intangible capital assets, $18.2 million of non-capital loss carryforwards
which expire at various periods to 2026, and $110 million for other tax pools.
In addition to the above tax basis for the Trust's subsidiaries, the Trust
itself had an approximate tax basis of $545.1 million as at December 31, 2006.
On October 31, 2006, the Federal Government announced the Trust taxation.
Currently, distributions paid to unitholders, other than returns of capital,
are claimed as a deduction by the Trust in arriving at taxable income whereby
tax is eliminated at the Trust level and is paid by the unitholders. The
proposals would result in a two-tiered tax structure whereby distributions
would first be subject to a 31.5 per cent tax at the Trust level commencing in
2011, and then unitholders would be subject to tax on the distribution as if
it were a taxable dividend paid by a taxable Canadian corporation. If enacted,
the proposals would apply to the Trust effective January 1, 2011. The Trust is
currently assessing various alternatives with respect to the potential
implications of the tax proposals, however until the legislation is enacted in
final form, the Trust will not arrive at a final conclusion with respect to
future Trust structure and implications to the Trust. As the tax proposals had
not yet been substantively enacted as of December 31, 2006, the consolidated
financial statements do not reflect the impact of the proposed taxation.
The corporate income tax rate applicable to 2006 is 34.5 per cent,
however ARC does not anticipate any material cash income taxes will be paid
for fiscal 2006. Due to the Trust's structure, currently, both income tax and
future tax liabilities are passed on to the unitholders by means of royalty
payments made between ARC Resources and the Trust.
Capital taxes were eliminated effective January 1, 2006 pursuant to the
Federal Government budget of May 2, 2006.

Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate increased to
$15.64 per boe in 2006 from $12.88 per boe in 2005. The higher DD&A rate is
due to the Redwater and NPCU acquisitions in the fourth quarter of 2005 for
which the Trust recorded a higher proportionate cost per barrel of proved
reserves of the acquired operations compared to the existing ARC properties.
In addition, the Trust completed net acquisitions in 2006 for $131.8 million
plus an additional $5.4 future income tax liability recorded on acquisition,
both acquisitions were at a higher proportionate cost per barrel of proved
reserves than existing ARC properties. Accretion expense was also higher in
2006 as a result of the higher asset retirement obligation recorded late in
2005 primarily attributed to the acquired Redwater and NPCU properties.

<<
A breakdown of the DD&A rate is a follows:
-------------------------------------------------------------------------
DD&A Rate
($ millions except per boe amounts) 2006 2005 % Change
-------------------------------------------------------------------------
Depletion of oil & gas assets(1) 348.9 259.3 35
Accretion of asset retirement obligation(2) 11.1 5.2 113
-------------------------------------------------------------------------
Total DD&A 360.0 264.5 36
DD&A rate per boe 15.64 12.88 21
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
("PP&E") balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>

The costs subject to depletion included $61.3 million relating to the
capitalized portion of the asset retirement obligation as at December 31, 2006
($61.9 million as at December 31, 2005), net of accumulated depletion.

Goodwill
The goodwill balance of $157.6 million arose as a result of the
acquisition of Star in 2003. The goodwill balance was determined based on the
excess of total consideration paid plus the future income tax liability less
the fair value of the assets for accounting purposes acquired in the
transaction.
Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such an
impairment exists, it would be charged to income in the period in which the
impairment occurs. The Trust has determined that there was no goodwill
impairment as of December 31, 2006.

Capital Expenditures and Net Acquisitions
Total capital expenditures, excluding acquisitions and dispositions,
totaled $364.5 million in 2006 compared to $268.8 million in 2005. This amount
was incurred on drilling and completions, geological, geophysical and
facilities expenditures, and the purchase of undeveloped acreage. The
significant increase in 2006 capital expenditures is reflective of the Trust's
higher production, larger asset base and the higher cost to replace production
as well as increased spending on undeveloped land.
In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $115.2 million in 2006. The most
significant property acquisition was the purchase of Manitoba properties
accounting for 785 boe per day of oil production and 3.4 mmboe of proved plus
probable reserves for cash consideration of $74 million. The Trust also
completed one minor corporate acquisition for consideration of $16.6 million
in 2006.
During the year, the Trust drilled 294 gross wells (219 net wells) on
operated properties; consisting of 72 gross oil wells and 222 gross natural
gas wells most of which were shallow gas wells with a success rate of 99 per
cent. In addition, the Trust participated in 443 gross wells (40 net wells)
drilled by other operators.
Proved plus probable oil and gas reserves were effectively maintained at
286.1 mmboe at year end 2006 as a result of the Trust's 2006 capital
expenditure program and property and corporate acquisitions.
A breakdown of capital expenditures and net acquisitions is shown below:

<<
-------------------------------------------------------------------------
Capital Expenditures
($ millions) 2006 2005 % Change
-------------------------------------------------------------------------
Geological and geophysical 11.4 9.2 24
Drilling and completions 240.5 191.8 25
Plant and facilities 77.6 55.0 41
Undeveloped land 32.4 9.1 256
Other capital 2.6 3.7 (30)
-------------------------------------------------------------------------
Total capital expenditures 364.5 268.8 36
-------------------------------------------------------------------------
Producing property acquisitions(1) 124.0 111.3 11
Producing property dispositions(1) (8.8) (20.0) (57)
Corporate acquisitions(2) 16.6 505.0 (967)
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 496.3 865.1 (426)
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
(2) Represents total consideration for the transactions, including fees
but is prior to the related future income tax liability, asset
retirement obligation and working capital assumed on acquisition.
>>

Approximately 72 per cent of the $364.5 million capital program was
financed with cash flow from operations in 2006 compared to 95 per cent in
2005. Property and corporate acquisitions were financed through a combination
of debt and proceeds from the 2006 distribution reinvestment program and
employee rights plan.

<<
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
2006
-------------------------------------------------------------------------
Development Net Total
Capital Acquisitions Expenditures
-------------------------------------------------------------------------
Expenditures 364.5 131.8 496.3
-------------------------------------------------------------------------
Per cent funded by:
Cash flow 72% - 53%
Proceeds from DRIP and
Rights Plan 28% 5% 22%
Proceeds from equity offering - - -
Debt - 95% 25%
-------------------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
2005
-------------------------------------------------------------------------
Development Net Total
Capital Acquisitions Expenditures
-------------------------------------------------------------------------
Expenditures 268.8 596.3 865.1
-------------------------------------------------------------------------
Per cent funded by:
Cash flow 95% - 30%
Proceeds from DRIP and
Rights Plan 5% 9% 8%
Proceeds from equity offering - 40% 28%
Debt - 51% 34%
-------------------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------------------
>>

ARC expects to undertake significant development activities again in 2007
resulting in a $360 million capital budget. The Trust plans to drill 275 gross
wells (225 net wells) on operated properties in 2007, allocate $6.5 million to
Enhanced Oil Recovery initiatives such as carbon dioxide ("CO(2)") injection,
continue to research Natural Gas from Coal ("NGC") opportunities and develop
the recently acquired Manitoba properties.

Long-Term Investment
During the second quarter of 2006, the Trust made a $20 million
investment in the shares of a private company that is involved in the
acquisition of oil sands leases with development potential. At year end, the
Trust holds less than a two per cent interest in the company and has the
intent of holding the shares for investment purposes.
The investment in the shares of the private company has been considered
to be a related party transaction due to common directorships of the Trust,
the private company and the manager of a private equity fund that holds shares
in the private company. In addition, certain directors and officers of the
Trust have minor direct and indirect shareholdings in the private company. All
of the interested directors declared their interest and the investment was
approved unanimously by the directors of the Trust not including the
interested directors. The $20 million investment was part of a $325 million
private placement of the private company.

Asset Retirement Obligation and Reclamation Fund
At December 31, 2006, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $177.3 million ($165.1 million at December 31, 2005) for
future abandonment and reclamation of the Trust's properties. The ARO
increased slightly in 2006 as a result of wells drilled in the year and
property and corporate acquisitions completed in 2006. The ARO further
increased by $11.1 million for accretion expense in 2006 ($5.2 million in
2005) and was reduced by $10.6 million ($4.9 million in 2005) for actual
abandonment expenditures incurred in 2005. The Trust did not record a gain or
loss on actual abandonment expenditures incurred as the costs closely
approximated the liability value included in the ARO.
As a result of the Redwater acquisition in December 2005, the Trust set
up a new restricted reclamation fund (the "Redwater Fund") in 2006 to fund
future abandonment obligations attributed to the Redwater properties. The
Trust makes annual contributions to the Redwater fund and may utilize the
funds only for abandonment activities for the Redwater property. With the
addition of the Redwater Fund, the Trust now maintains two reclamation funds
which together held $30.9 million of money market instruments at December 31,
2006. Future contributions for the two funds will vary over time in order to
provide for the total estimated future abandonment and reclamation costs that
are to be incurred upon abandonment of the Trust's properties. The Trust
currently estimates that $230 million will be contributed to the funds over
the next 50 years to provide for future abandonment and reclamation costs.
In total, ARC contributed $12.1 million cash to its reclamation funds in
2006 ($6 million in 2005) and earned interest of $1 million ($0.8 million in
2005) on the fund balances. The increase in funding is attributed to the
Redwater fund. The fund balances were reduced by $5.7 million for cash-funded
abandonment expenditures 2006 ($4.6 million in 2005).

A breakdown of the Trust's capital structure is as follows as at
December 31, 2006 and 2005:

<<
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per unit and per cent amounts) 2006 2005
-------------------------------------------------------------------------
Revolving credit facilities 426.1 258.5
Senior secured notes 261.0 268.2
Working capital deficit excluding short-term debt(1) 52.0 51.4
-------------------------------------------------------------------------
Net debt obligations 739.1 578.1
Units outstanding and issuable for exchangeable
shares (thousands) 207.2 202.0
Market price per unit at end of year 22.30 26.49
Market value of units and exchangeable shares 4,620.0 5,352.0
Total capitalization(2) 5,359.1 5,930.1
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 13.8% 9.7%
Net debt obligations 739.1 578.1
Cash flow from operations 760.6 639.5
Net debt to cash flow 1.0 0.9
-------------------------------------------------------------------------
(1) The working capital deficit excludes the balances for commodity and
foreign currency contracts.
(2) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
>>

The increase in net debt to total capitalization in 2006 is attributed to
the devaluation of the trust unit price following the Federal Government's
proposed Trust taxation announcement and an increase in debt. Prior to the
announcement, the trust unit price was $27.56 per unit and total
capitalization approximated $6.3 billion. The devaluation of the unit price
resulted in an approximate 20 per cent decline in market capitalization
resulting in a higher net debt to total capitalization ratio.
The Federal Government's proposed Trust taxation announcement also caused
increased market uncertainty pertaining to the future of the trust sector.
This market uncertainty is diminishing over time, however it is our assessment
that the Trust's ability to raise equity by issuing new trust units in the
market has been diminished. The Government released guidelines regarding trust
growth that limits expansion via acquisitions in 2007 to 40 per cent of the
Trust's market capitalization as at October 31, 2006. We believe the 40 per
cent limit is in excess of what the Trust could raise in the equity markets on
a prudent basis. Management's assessment is that the Trust's ability to raise
new equity would be dependent on financial market conditions at the time and
the nature of the use of proceeds.
The Trust has a syndicated three year revolving credit facility allowing
for maximum borrowing of up to $572 million. The debt is secured by all the
Trust's oil and gas properties and has the following major covenants:

<<
-------------------------------------------------------------------------
Covenant Position as at December 31, 2006
-------------------------------------------------------------------------
Long-term debt and letters of Long-term debt and letters of credit
credit not to exceed three times of 0.9 times annualized net income
annualized net income before before non-cash items
non-cash items and interest expense and interest expense
-------------------------------------------------------------------------
Long-term debt, letters of credit Long-term debt, letters of credit
and subordinated debt not to exceed and subordinated debt of 0.9 times
four times annualized net income annualized net income before
before non-cash items and interest non-cash items and interest expense
expense
-------------------------------------------------------------------------
Long-term debt and letters of Long-term debt and letters of credit
credit not to exceed 50 per cent of 26.8 per cent of the sum of
of the sum of the book value of unitholders' equity, long-term debt,
unitholders' equity, long-term letters of credit, and subordinated
debt, letters of credit,and debt
subordinated debt
-------------------------------------------------------------------------
>>

As indicated by the above covenants, the Trust has additional potential
borrowing capacity above the $572 credit facility, however the Trust's
objective is to limit debt to under 2.0 times cash flow from operations and
20 per cent of total capitalization.
In the event that the Trust enters into a material acquisition whereby
the purchase price exceeds 10 per cent of the book value of the Trust's
assets, the ratios in the first two covenants above are increased to 3.5 and
5.5 times, respectively. The Trust had $4.7 million of letters of credit
outstanding at December 31, 2006 and no subordinated debt. As at December 31,
2006, the Trust was in compliance with all covenants.
In addition to the $572 million credit facility, the Trust has issued
senior secured notes which do not reduce the available borrowings under the
credit facility.
Net debt obligations increased by $161 million in 2006 to $739.1 million
as a result of significant capital and acquisition activity in the year that
resulted in a working capital deficit and the majority of acquisitions having
been funded with debt. The Trust funded 72 per cent of its 2006 capital
development program of $364.5 million with cash flow and the remaining
$101.2 million was funded with proceeds from the DRIP and employee rights
plan. The Trust funded $125 million of the 2006 acquisitions with debt and the
remaining $6.8 million was funded with proceeds from the DRIP and Employee
Rights program.
The Trust intends to finance its $360 million 2007 capital program with
cash flow and the proceeds of the distribution reinvestment program with any
remainder being financed with debt.

Unitholders' Equity
At December 31, 2006, there were 207.2 million units issued and issuable
for exchangeable shares, an increase of 5.2 million units from December 31,
2005. The increase in number of units outstanding is mainly attributable to
the 3.9 million units issued pursuant to the DRIP during 2006 at an average
price of $24.67 per unit.
The Trust had 0.4 million rights outstanding as of December 31, 2006
under an employee plan where further rights issuances were discontinued in
2004. The rights have a five-year term and vest equally over three years from
the date of grant. The majority of rights vested on May 6, 2006. The remaining
rights may be purchased at an average adjusted exercise price of $9.47 per
unit as at December 31, 2006. All but 6,000 of the rights were fully vested at
December 31, 2006 and the remainder will vest on March 22, 2007. The
contractual life of the rights varies by series but all will expire on or
before March 22, 2009.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees
may elect to have units purchased for them on the market with the cash
received upon vesting.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire units from treasury under the DRIP may do so at a five per
cent discount to the prevailing market price with no additional fees or
commissions. During the 2006, the Trust raised proceeds of $96.1 million and
issued 3.9 million trust units pursuant to the DRIP.

Cash Distributions
ARC declared cash distributions of $484.2 million ($2.40 per unit),
representing 64 per cent of 2006 cash flow from operations compared to cash
distributions of $376.6 million ($1.99 per unit), representing 59 per cent of
cash flow from operations in 2005. The remaining 36 per cent of 2006 cash flow
($276.4 million) was used to fund 72 per cent of ARC's 2006 capital
expenditures and make contributions, including interest, to the reclamation
fund ($13.2 million).
Monthly cash distributions for 2006 were $0.20 per unit. Revisions, if
any, to the monthly distribution are normally announced on a quarterly basis
in the context of prevailing and anticipated commodity prices at that time.
The following items may be deducted from cash flow to arrive at cash
distributions to unitholders:

<<
- An annual contribution to the reclamation funds and interest earned on
the fund balances. The reclamation funds are segregated bank accounts
or subsidiary trusts and the balances will be drawn on in future
periods as the Trust incurs abandonment and reclamation costs over the
life of its properties. The contribution level is reviewed annually
based on a detailed assessment of the Trust's total future abandonment
obligation, an estimated return based on current interest rates and a
future funding period approximating 50 years. The funding amount is
approved by the Health, Safety and Environment committee. As future
abandonment and reclamation obligations will be settled with
reclamation fund balances over the life of the properties, the Trust
does not anticipate any separate deductions from cash flow for
abandonment and reclamation costs. The annual contribution was $12.1
million in 2006 or two per cent of cash flow and will vary in future
periods depending on acquisition and capital development activity and
abandonment cost estimates to reclaim the Trust's oil and natural gas
properties. The most significant annual contributions to the
reclamation funds are expected to occur in years 2007 through 2015.
The 2007 contribution is currently estimated to be $12 million.

- The portion of capital expenditures that are funded with cash flow.
The Trust's distribution policy guideline is to withhold at least
20 per cent of cash flow to fund a portion of capital expenditures.
In 2006, the Trust withheld 34 per cent of 2006 cash flow to fund
72 per cent of the capital program excluding acquisitions. The
objective of the Trust's capital expenditure program is to replace
natural production declines resulting in stable production. This level
of capital expenditures may not replace the Trust's reserves produced
out during the period, but rather bring non-producing reserves on
stream.

- Debt principal repayments to the extent that required principal
repayment cannot be refinanced by other means. The Trust's current
debt level is well within the covenants specified in the debt
agreements and, accordingly, there are no current mandatory
requirements for repayment. Refer to the "Capital Structure and
Liquidity" section of this MD&A for a detailed review of the debt
covenants.

- Income taxes that are not passed on to unitholders. The Trust has a
liability for future income taxes due to the excess of book value over
the tax basis of the assets of the Trust and its corporate
subsidiaries. The Trust currently minimizes or eliminates cash income
taxes in corporate subsidiaries by maximizing deductions, however in
future periods there may be cash income taxes if deductions are not
sufficient to eliminate taxable income and if proposed changes in
Trust taxation are enacted. Taxability of the Trust is currently
passed on to unitholders in the form of taxable distributions whereby
corporate income taxes are eliminated at the Trust level. If the
proposed Trust taxation legislation is enacted, the Trust anticipates
that the resulting tax commencing in 2011 at the Trust level would
decrease cash flow and thus reduce cash distributions to unitholders.

- Working capital requirements as determined by the Trust. Certain
working capital amounts may be deducted from cash flow, however such
amounts would be minimal and the Trust does not anticipate any such
deductions in the foreseeable future.

- The Trust has certain obligations for future payments relative to
employee long-term incentive compensation. Presently, the Trust
estimates that $18.2 million to $58.6 million will be paid out
pursuant to such commitments in 2007 through 2009 subject to vesting
provisions and future performance of the Trust. These amounts will
reduce cash flow and in turn cash distributions in future periods.

Cash flow and cash distributions in total and per unit were as follows:

-------------------------------------------------------------------------
Cash flow and ($ million) ($ per unit)
distributions ---------------------------------------------------
($ millions and % %
$ per unit) 2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
Cash flow from
operations 760.6 639.5 19 3.72 3.35 11
Reclamation fund
contributions(1) (13.2) (6.8) 94 (0.06) (0.04) 50
Capital expenditures
funded with
cash flow (263.2) (256.1) 3 (1.28) (1.34) (4)
Other(2) - - 0.02 0.02 -
-------------------------------------------------------------------------
Cash distributions 484.2 376.6 29 2.40 1.99 21
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to cash distributions paid being
based on actual units at each distribution date whereas per unit cash
flow, reclamation fund contributions and capital expenditures funded
with cash flow are based on weighted average trust units in the year
plus units issuable for exchangeable shares at year end.
>>

The Trust continually assesses distribution levels, in light of commodity
prices and production volumes, to ensure that distributions are in line with
the long-term strategy and objectives of the Trust as per the following
guidelines:

<<
- To maintain a level of distributions that, in the opinion of
Management and the Board of Directors, are sustainable for a minimum
period of six months. The Trust's objective is to normalize the effect
of volatility of commodity prices rather than to pass on that
volatility to unitholders in the form of fluctuating monthly
distributions.

- To ensure that the Trust's payout ratio does not exceed 80 per cent on
an annual basis. The Trust believes that a portion of cash flow should
be reinvested in capital development activities in order to offset, in
part, the natural production declines of the Trust's assets over the
long-term. The use of cash flow to fund capital development activities
reduces the requirements of the Trust to use debt and equity to
finance these expenditures. In 2006 the Trust funded 72 per cent of
capital development activities with 34 per cent of cash flow. The
actual amount of cash flow withheld to fund the Trust's capital
expenditure program is dependent on the commodity price environment
and is at the discretion of the Board of Directors.
>>

In order to set distributions to meet the above noted objectives, the
Trust maintains an annual cash flow forecast that incorporates actual results
of the Trust and market conditions. An annual distribution is determined based
on the Trust's objectives of a maximum annual payout ratio of 80 percent, a
minimum of 20 per cent of annual cash flow to fund capital expenditures, and a
minimum annual contribution to the reclamation funds. As market conditions
change, the forecast is updated to assess whether there should be a change in
distribution levels. A change to distributions is proposed only if there is a
reasonable probability that the revised distribution may be maintained for a
minimum six-month period. If distribution levels remain the same, the
difference in cash flow between estimated and actual results is reflected in
the level of cash funded capital expenditures.
The actual amount of future monthly cash distributions are proposed by
management and are subject to the approval and discretion of the Board of
Directors. The Board reviews future cash distributions in conjunction with
their review of quarterly financial and operating results.
Monthly cash distributions for the first quarter of 2007 have been set at
$0.20 per unit subject to monthly review based on commodity price
fluctuations. Revisions, if any, to the monthly distribution are normally
announced on a quarterly basis in the context of prevailing and anticipated
commodity prices at that time.

Historical Cash Distributions by Calendar Year

The following table presents cash distributions paid and payable for each
calendar period.

<<
-------------------------------------------------------------------------
Taxable Return of
Calendar Year Distributions Portion Capital
-------------------------------------------------------------------------
2007 YTD(2) 0.20 0.20(2) 0.00(2)
2006(1) 2.60 2.55(3) 0.05(3)
2005 1.94 1.90 0.04
2004 1.80 1.69 0.11
2003 1.78 1.51 0.27
2002 1.58 1.07 0.51
2001 2.41 1.64 0.77
2000 1.86 0.84 1.02
1999 1.25 0.26 0.99
1998 1.20 0.12 1.08
1997 1.40 0.31 1.09
1996 0.81 - 0.81
-------------------------------------------------------------------------
Cumulative $ 18.83 $ 12.09 $ 6.74
-------------------------------------------------------------------------
(1) Based on cash distributions paid and payable in 2006.
(2) Based on cash distributions declared at January 31, 2007 and
estimated taxable portion of 2007 distributions of 98 per cent.
(3) Based on taxable portion of 2006 distributions of 98 per cent.

2006 Monthly Cash Distributions

Actual cash distributions paid and payable in 2006 along with relevant
payment dates were as follows:

-------------------------------------------------------------------------
Ex-distribution Distribution Total
date Record date payment date distribution
-------------------------------------------------------------------------
December 28, 2005 December 31, 2005 January 16, 2006 0.20
January 27, 2006 January 31, 2006 February 15, 2006 0.20
February 24, 2006 February 28, 2006 March 15, 2006 0.20
March 29, 2006 March 31, 2006 April 17, 2006 0.20
April 26, 2006 April 30, 2006 May 15, 2006 0.20
May 29, 2006 May 31, 2006 June 15, 2006 0.20
June 28, 2006 June 30, 2006 July 17, 2006 0.20
July 27, 2006 July 31, 2006 August 15, 2006 0.20
August 29, 2006 August 31, 2006 September 15, 2006 0.20
September 27, 2006 September 30, 2006 October 16, 2006 0.20
October 27, 2006 October 31, 2006 November 15, 2006 0.20
November 28, 2006 November 30, 2006 December 15, 2006 0.20
December 27, 2006 December 31, 2006 January 15, 2007 0.20
-------------------------------------------------------------------------
Total 2006 2.60
-------------------------------------------------------------------------
>>

Please refer to the Trust's website at www.arcenergytrust.com for details
on distributions dates for 2007.

Taxation of Cash Distributions
Cash distributions comprise a return of capital portion (tax deferred)
and a return on capital portion (taxable). The return of capital component
reduces the cost basis of the units held. For 2006, cash distributions paid in
the calendar year will be 98 per cent return on capital (taxable) and two per
cent return of capital (tax deferred).For a more detailed breakdown, please
visit our website at www.arcenergytrust.com.
The proposed Trust taxation announced by the Federal Government on
October 31, 2006 and subsequent draft legislation would result in income taxes
being imposed at the Trust level on distributions paid to unitholders
effective January 1, 2011. The Trust is currently assessing the proposals and
the potential implications to the Trust in future periods.

Deficit
During the second quarter, presentation changes were made to combine the
previously reported accumulated earnings and accumulated cash distribution
figures on the balance sheet into a single deficit balance. The Trust has
historically paid cash distributions in excess of accumulated earnings as cash
distributions are based on cash flow generated in the current period, while
accumulated earnings are based on cash flow generated in the current period
less a depletion and depreciation expense recorded on the original property,
plant, and equipment investment. Numbers presented for comparative purposes
have been restated to reflect this change in presentation.

Contractual Obligations and Commitments
The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, and lease
rental obligations. These obligations are of a recurring and consistent nature
and impact cash flow in an ongoing manner. The Trust also has contractual
obligations and commitments that are of a less routine nature as disclosed in
the following table.

<<
-------------------------------------------------------------------------
Commitments Payments due by period
-----------------------------------------------
($ millions) 2007 2008-2009 2010-1011 Thereafter Total
-------------------------------------------------------------------------
Debt repayments 8.0 451.2 53.1 174.8 687.1
Interest
payments(1) 11.3 21.5 18.1 20.8 71.7
Reclamation
fund
contributions(2) 6.0 11.1 9.5 76.2 102.8
Purchase
commitments 12.6 8.4 3.4 6.8 31.2
Operating leases 5.3 9.9 5.0 - 20.2
Derivative
contract
premiums(3) 12.4 3.3 - - 15.7
Retention
bonuses 1.0 - - - 1.0
-------------------------------------------------------------------------
Total
contractual
obligations 56.6 505.4 89.1 278.6 929.7
-------------------------------------------------------------------------
(1) Fixed interest payments on the Senior Secured Notes.
(2) Contribution commitments to a restricted reclamation fund associated
with the Redwater property acquired in 2005.
(3) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
>>

The above noted derivative contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has commitments related to its risk management program. As
the premiums are part of the underlying derivative contract, they have been
recorded at fair market value at December 31, 2006 on the balance sheet as
part of commodity and foreign currency contracts.
The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2007 capital budget has
been approved by the Board at $360 million. This commitment has not been
disclosed in the commitment table as it is of a routine nature and is part of
normal course of operations for active oil and gas companies and trusts.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the following table does not include any
commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.

Off Balance Sheet Arrangements
The Trust has certain lease agreements which aggregate to less that
$1 million and were entered into in the normal course of operations. All
leases have been treated as operating leases whereby the lease payments are
included in operating expenses or G&A expenses depending on the nature of the
lease. No asset or liability value has been assigned to these leases in the
balance sheet as of December 31, 2006.
The Trust's long-term electricity hedge and interest rate hedges have not
been recorded as an asset or liability on the balance sheet as they qualify as
effective accounting hedges.
The Trust entered into agreements to pay premiums pursuant to certain
crude oil derivative put contracts. Premiums of $15.7 million will be paid in
2007 through 2009 for the put contracts in place at December 31, 2006. As the
premiums are part of the underlying derivative contract, they have been
recorded at fair market value at December 31, 2006 on the balance sheet.

Critical Accounting Estimates
The Trust has continuously evolved and documented its management and
internal reporting systems to provide assurance that accurate, timely internal
and external information is gathered and disseminated.

The Trust's financial and operating results incorporate certain estimates
including:

<<
- estimated revenues, royalties and operating costs on production as at
a specific reporting date but for which actual revenues and costs have
not yet been received;
- estimated capital expenditures on projects that are in progress;
- estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves that the Trust expects to recover in
the future;
- estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and foreign
exchange rates;
- estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
- estimated future recoverable value of property, plant and equipment
and goodwill.
>>

The Trust has hired individuals and consultants who have the skills
required to make such estimates and ensures that individuals or departments
with the most knowledge of the activity are responsible for the estimates.
Further, past estimates are reviewed and compared to actual results, and
actual results are compared to budgets in order to make more informed
decisions on future estimates.
The ARC leadership team's mandate includes ongoing development of
procedures, standards and systems to allow ARC staff to make the best
decisions possible and ensuring those decisions are in compliance with the
Trust's environmental, health and safety policies.

Internal Controls Update
On July 31, 2002, the United States Congress enacted the Sarbanes-Oxley
Act ("SOX"). SOX applies to all companies registered with the Securities and
Exchange Commission ("SEC"). Although ARC is not listed on a US stock
exchange, the Trust is registered with the SEC as a result of having acquired
Startech Energy Inc. in 2001 and therefore was required to comply with section
404 of the SOX legislation as at December 31, 2006 and each year thereafter.
There are various components to the SOX legislation, however the most
comprehensive is Section 404 "Internal Controls Over Financial Reporting".
Section 404 requires that management undertake the following:

<<
- identify and document internal controls that impact financial
reporting;
- assess the effectiveness of those internal controls;
- remediate any deficiencies in internal controls and/or implement any
required controls that are not already in place;
- test the internal controls to ensure that they are operating
effectively; and
- issue a report, to be signed by the Chief Operating Officer and the
Chief Financial Officer, on management's assessment of the
effectiveness of internal controls and communicate any material
weaknesses.
>>

Internal control over financial reporting is a process designed to
provide reasonable assurance that all assets are safeguarded, transactions are
appropriately authorized and to facilitate the preparation of relevant,
reliable and timely information. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements.
Management has assessed the effectiveness of the company's internal control
over financial reporting based on the framework in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO) and concluded that the company's internal
control over financial reporting was effective as of December 31, 2006.
Management's assessment of the effectiveness of the company's internal control
over financial reporting as of December 31, 2006 has been audited by Deloitte
& Touche LLP, as reflected in their report for 2006.
As of December 31, 2006, an internal evaluation was carried out of the
effectiveness of the Trust's disclosure controls and procedures as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934, also known as
SOX 302.
Based on that evaluation, the President and Chief Executive Officer and
Chief Financial Officer concluded that the disclosure controls and procedures
are effective to ensure that the information required to be disclosed in the
reports that the Trust files or submits under the Exchange Act is recorded,
processed, summarized and reported, within the time periods specified in the
rules and forms of the SEC. Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that the
information required to be disclosed by the Trust in the reports that it files
or submits under the Exchange Act is accumulated and communicated to the
Trust's management, including the senior executive and financial officers, as
appropriate to allow timely decisions regarding the required disclosure.
In addition to SOX, ARC is required to comply with Multilateral
Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim
Filings", otherwise referred to as Canadian SOX ("C-Sox"). The Canadian
requirements closely parallel the SEC's certification rules, however,
currently there is no requirement to have the external auditor opine on the
Trust's internal controls or management's assessment thereof. ARC has complied
with this legislation by filing bare interim certificates and a full annual
certificate with no modifications in conjunction with the December 31, 2006
year end. The 2006 certificate requires that the Trust disclose in the annual
MD&A any changes in the Trust's internal control over financial reporting that
occurred during the period that has materially affected, or is reasonably
likely to materially affect the Trust's internal control over financial
reporting. The Trust confirms that no such changes were made to the internal
controls over financial reporting during 2006.

Financial Reporting Update
During 2006, the Trust commenced a review of the new CICA Handbook
section 3855 "Financial Instruments - Recognition and Measurement", section
1530 "Comprehensive Income" and section 3865 "Hedges" that deal with the
recognition and measurement of financial instruments at fair value and
comprehensive income. The new standards are intended to harmonize Canadian
standards with United States and international accounting standards. The new
standards are effective for annual and interim periods in fiscal years
beginning on or after October 1, 2006. These new standards will impact the
Trust in 2007 and are currently being reviewed to assess their impact.

Objectives and 2007 Outlook

Sustainability
It is the Trust's objective to provide superior and sustainable long-term
returns to unitholders by focusing on the key strategic objectives of the
business plan. The Trust acquires, develops and optimizes oil and natural gas
properties in predominantly mature areas to generate a cash flow stream. Due
to natural production declines, the Trust must continually develop its
reserves and/or acquire new reserves in an effort to maintain reserves,
production and cash flow levels on which distributions are paid. The trust
facilitates this by withholding a portion of cash flow to fund a portion of
ongoing capital development activities and maintaining moderate debt levels;
this is evidenced by the Trust's low payout ratio. Oil and gas royalty trusts
hold assets that are depleting and unitholders should expect production,
revenue, cash flow and distributions to decline over the long-term if reserves
cannot be economically replaced. The Trust has an inventory of internal
development prospects that will enable the Trust to maintain production and
reserves for a minimum period of two years. The Trust anticipates employing a
conservative payout policy to provide for cash funding of a portion of ongoing
capital development programs and maintaining low debt levels to facilitate
further growth. The Trust measures its sustainability and success in terms of
per unit cash distributions, production, reserves, and cash flow in addition
to the ability to maintain low debt levels and the annual replacement of
reserves.
Following is a summary of the historical debt-adjusted production and
reserves per unit and reserve life index on which the Trust assesses
performance and sustainability:

<<
-------------------------------------------------------------------------
5 Year
Per trust unit ratios 2006 2005 2004 2003 2002 Total
-------------------------------------------------------------------------
Production per unit(1):
Unadjusted 0.31 0.29 0.31 0.35 0.35 -
Debt-adjusted(3) 0.27 0.26 0.28 0.31 0.29 -
Normalized(4) 0.31 0.31 0.33 0.38 0.33 -
------------------------------------------------------------------------
Reserves per unit(2):
Unadjusted 1.38 1.42 1.29 1.37 1.47 -
Debt-adjusted(3) 1.19 1.28 1.20 1.25 1.19 -
Normalized(4) 1.38 1.49 1.39 1.44 1.38 -
-------------------------------------------------------------------------
Reserve life index(5) 12.4 12.9 12.2 12.4 11.8 -
Cash flow per unit $ 3.72 $ 3.35 $ 2.41 $ 2.56 $ 1.87 $13.91
Cash distributions
per unit $ 2.40 $ 1.99 $ 1.80 $ 1.80 $ 1.56 $ 9.55
Payout ratio per cent(6) 64 59 74 71 82 70
Per cent of cash flow
retained 36 41 26 29 18 30
-------------------------------------------------------------------------

(1) Represents daily average production per thousand units. Calculated
based on annual daily average production divided by weighted average
trust units including trust units issuable for exchangeable shares.
(2) Calculated based on proved plus probable reserves divided by period
end trust units including trust units issuable for exchangeable
shares.
(3) Debt-adjusted indicates that all years as presented have been
adjusted to reflect a nil net debt to capitalization. It is assumed
that additional trust units were issued at a period end price for the
reserves per unit calculation and at an annual average price for the
production per unit calculation in order to reduce the net debt
balance to zero in each year. The debt-adjusted amounts are presented
to enable comparability of annual per unit values.
(4) Normalized indicates that all years as presented have been adjusted
to reflect a net debt to capitalization of 14 per cent as per
December 31, 2006. It is assumed that additional trust units were
issued (or repurchased) at a period end price for the reserves per
unit calculation and at an annual average price for the production
per unit calculation in order to reduce the net debt balance to
14 per cent of total capitalization each year. The normalized amounts
are presented to enable comparability of annual per unit values.
(5) Calculated based on proved plus probable reserves divided by annual
2007 production estimate of 63,000 boe per day for 2006 RLI.
(6) Calculated as cash distributions divided by cash flow from
operations.
>>

During the 2002 to 2006 time period the trust's normalized production per
unit has decreased only slightly from 0.33 to 0.31 boe of daily average
production per thousand trust units and normalized reserves per unit have
remained constant during this time at 1.38 boe of proved plus probable
reserves per trust unit. The maintenance of production and reserves per unit
occurred even with the payout of $1.7 billion of cash distributions ($9.55 per
trust unit and 70 per cent of cash flow) during the 2002 through 2006 time
period. This indicates that the Trust has continually grown production levels
to offset natural production declines and developed and grown its reserve
base. The normalized production per unit is a key measure as it indicates the
ability to generate cash flow from core operations which in turn impacts the
level of cash that may be distributed to unitholders. The Trust expects to
replace production in 2007 from internal development opportunities.
To compare the Trust's results with oil and gas companies that retain all
of their cash flow to grow production and reserves, the Trust looks at
normalized and distribution-adjusted production and reserves per unit which
calculates the total reserves and production per initial investment with the
assumption that distributions are reinvested through the DRIP plan.
Consequently, the reserves and production per initial investment increase over
time as the investor's number of trust units increase with distribution
reinvestment. The Trust's normalized daily average production per initial
investment has increased from 0.33 boe per thousand trust units in 2002 to
0.56 in 2006, while normalized reserves per initial investment have increased
from 1.53 boe at January 1, 2002 to 2.50 boe at December 31, 2006. The
increase is attributed to the DRIP factor whereby one trust unit purchased on
January 1, 2002 would have grown to 1.81 trust units on December 31, 2006. A
unitholder can replicate this by participating in the DRIP so that the number
of units they own increases over time.
The Trust's reserve life index ("RLI") increased to 12.4 years in 2006
from 11.8 years in 2002. The RLI is a measure of the remaining average life of
the reserves based on a current production estimate for 2007 of 63,000 boe per
day. The Trust's high RLI is indicative of the high quality of assets and long
reserve life of the properties. The acquisition of the Redwater and NPCU
properties in 2005 resulted in an increase in the RLI due to the long reserve
life of the properties. A high RLI is key for a royalty trust as it is
indicates the potential sustainability of production levels and cash flow over
a longer period of time.
The Trust's distribution policy centres around the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The low payout ratio is indicative of the Trust's
commitment to fund ongoing development activities with cash flow to enable
long-term sustainability. A high payout ratio indicates that ongoing capital
development activities must be either debt or equity financed. The Trust's
payout ratio has declined over time as the Trust has addressed the issue of
long-term sustainability while setting distribution levels.
An additional measure of sustainability is the comparison of net income
to cash distributions. Net income incorporates all costs including depletion
expense and other non-cash expenses whereas cash flow from operations measures
the cash generated in a given period before the cost of the associated
reserves. Therefore, net income may be more representative of the
profitability of the entity and thus a relevant measure against which to
measure cash distributions to illustrate sustainability. As net income is
sensitive to fluctuations in commodity prices, it is expected that there will
be deviations between annual net income and cash distributions. The following
table illustrates the annual excess or shortfall of cash distributions to net
income as a measure of long-term sustainability.

<<
-------------------------------------------------------------------------
Net income and cash
distributions
($ millions except 5 Year
per cent) 2006 2005 2004 2003 2002 Total
-------------------------------------------------------------------------
Net income 460.1 356.9 241.7 284.6 70.0 1,431.3
Cash distributions 484.2 376.6 330.0 279.3 183.6 1,653.7
-------------------------------------------------------------------------
Excess (shortfall) (24.1) (19.7) (88.3) 5.3 (113.6) (222.4)
Excess (shortfall)
as per cent of
net income (5%) (6%) (37%) 2% (62%) (16%)
Payout per cent 64% 59% 74% 71% 82% 70%
-------------------------------------------------------------------------
>>

During 2002 through 2004, there was significant volatility in commodity
prices and it was management's decision to maintain distributions at a
consistent level during that time as it was perceived that the decline in
commodity prices was temporary. Management's decision to lower payout ratios
over time is illustrated in the table as cash distributions more closely
approximate net income in 2005 and 2006.

Returns to Unitholders and Proposed Federal Legislation to Tax Income
Trusts
The Trust has provided unitholders with the following one, three and five
year returns, including reinvestment of distributions:

<<
-------------------------------------------------------------------------
Total Returns Three Five
($ per unit except for per cent) One Year Year Year
-------------------------------------------------------------------------
Distributions per unit $ 2.40 $ 6.19 $ 9.55
Capital appreciation per unit $ (4.19) $ 7.56 $ 10.20
Total return per unit $ (1.79) $ 13.75 $ 19.75
Annualized total return per unit % (8.0) % 26.7 % 26.5
-------------------------------------------------------------------------
>>

To the end of 2006, the Trust has provided cumulative cash distributions
of $18.63 per unit and capital appreciation of $12.30 per unit for a total
return of $30.93 per unit (23.8 per cent annualized total return) for
unitholders who invested in the Trust at inception in 1996. The Trust has
announced 2007 cash distributions of $0.20 per unit per month through March
2007.
During 2006, the announcement and subsequent introduction of proposed
legislation regarding taxation of Trusts resulted in a significant decline in
trust unit prices throughout the industry. Consequently, many trusts have
reported a negative total return to unitholders in 2006 as a result of the
decline in trust unit prices immediately following the announcement. ARC's
return to unitholders was negative eight per cent in 2006 as a result of a 20
per cent decline in the trust unit price following the Federal Government
announcement on October 31, 2006. The Trust had reached a historic high unit
price of $30.74 in August 2006. Annual distributions to unitholders of $2.40
per trust unit are our highest to date.
Despite the devaluation of the trust unit price following the proposed
Trust taxation announcement, the Trust's business remains unchanged and the
Trust is still a prospering and sustainable entity with no change to the core
operations. Subsequent to the announcement, the Trust has been actively
researching alternatives regarding the structure and business strategy leading
up to the implementation of the proposed tax in 2011. Under the current
proposed legislation, the most viable option appears to be conversion to a
corporate entity no earlier than January 1, 2011 due to the punitive financial
impact that the taxation would have on the trust structure. However, given
that the legislation has not been officially enacted, the Trust has not made
any conclusive decisions with respect to the strategy over the next four years
as we feel it is prudent to await the final legislation and fully research all
alternatives before making a final decision. The Trust is working closely with
legal and business advisors as to the potential future structure and direction
of the Trust in an effort to maximize the value to unitholders, and to choose
a direction which is in the best interest of its unitholders.
ARC plans to proceed with its full $360 million capital expenditure
budget for 2007 which consists of a robust drilling and development program on
its diverse asset base. The 2007 capital budget is being deployed on well
tie-ins and other facility related costs, a balanced drilling program of low
and moderate risk wells and the acquisition of undeveloped land. The Trust
continues to focus on major properties with significant upside, with the
objective to replace production declines through internal development
opportunities. The 2007 capital expenditure budget anticipates the drilling of
225 net operated wells and the addition of 11,000 boe per day of new
production from the capital development program to replace declines at
existing properties. The 2007 capital budget also allows for a portion of
spending to further research and pursue Enhanced Recovery Initiatives such as
CO(2) injection and NGC development. Despite the Trust's active fourth
quarter, there was a general slow down in activity levels for the industry
late in 2006. The Trust expects that with the lower activity levels and
decreased demand for industry services that costs will moderate slightly in
2007. Current low debt levels and a strong working capital position provide
the Trust with the financial flexibility to fund the 2007 capital expenditure
program.
The Trust continually looks to execute minor property acquisitions and
dispositions in order to enhance and streamline the Trust's portfolio of oil
and natural gas assets. The Trust continually reviews potential acquisitions
of both conventional oil and natural gas reserves and in the broader energy
industry. The Federal Government issued guidance with respect to limitations
on future growth of the Trust in conjunction with the proposed Trust taxation
anouncement. The Trust does not anticipate that the guidelines will impair the
Trust's ability to annually replace or grow reserves in the next four years as
the guidelines allow sufficient growth targets. Key attributes of the future
growth constraints are as follows:

<<
- Trusts may grow in size by 100 per cent cumulatively for the period
2007 through 2010 as measured by the value of equity based on the
October 31, 2006 market capitalization. The cumulative limit starts at
40 per cent in 2007 and increases by 20 per cent per year in 2008
through 2010.

- Merger of two Trusts will not be impacted by the growth limitations.

- The growth limits are not impacted by non-convertible debt-financed
growth but rather focus solely on the issuance of equity to facilitate
growth.
>>

The Trust will continue to assess accretive acquisition opportunities.
Acquisitions are evaluated internally and acquisitions in excess of
$25 million are subject to Board approval.

Accomplishment of 2006 Objectives
The key future objectives of the Trust's business plan, as identified
below, are reviewed annually by the Board. The Trust was successful in meeting
all of its objectives in 2006 as individually addressed below. They continue
to be key objectives for 2007.

<<
- Annual reserves replacement - The Trust's proved plus probable
reserves were effectively maintained as December 31, 2006 reserves of
286.1 Mmboe were within one per cent of the 287 Mmboe recorded as at
December 31, 2005. The reserves were maintained through a combination
of the $364.5 million 2006 capital development program and corporate
and property acquisitions (net of dispositions) of $131.8 million.

- Ensuring acquisitions are strategic and enhance unitholder returns -
The Trust added producing properties in Manitoba to its asset base in
2006 and also increased its land ownership in certain core areas in
2006 in an effort to increase its inventory of future development
opportunities. In addition, the Redwater property acquired in 2005
provided many opportunities to ARC due to the optimization potential
of this long-life, light oil property. Since acquisition, ARC has
reactivated 95 gross wells (62 net wells) at Redwater and NPCU and
increased production by approximately 580 boe per day net. ARC
believes that long-life, light oil properties will provide future
opportunities to enhance unitholder value through the application of
tertiary recovery methods.

- Controlling costs - Due to the diligence of field and office operating
staff, the Trust's base operating costs per boe, before the impact of
higher cost acquisitions, increased by approximately five per cent
over 2005 costs. Cash G&A costs in 2006 increased 18 per cent to $1.58
per boe from $1.34 per boe in 2005 as a result of both increased staff
counts following acquisitions and increased compensation costs due to
the extremely competitive marketplace for experienced staff with oil
and gas expertise. The Trust believes the $1.58 per boe cash G&A costs
will be better than average for mid-sized oil and gas producers in
2006. The Trust's three year average FD&A costs of $15.59 per boe
prior to incorporating future development costs "FDC" and $18.99 per
boe with FDC are expected to approximate the industry average. The
increase in FD&A costs in 2006 is considered an anomaly partly due to
the large investment in strategic undeveloped land with no associated
reserves. The land acquisitions provide future development
opportunities and are expected to yield reserves in future periods as
development occurs.

- Conservative utilization of debt - The Trust's net debt levels were
under 14 per cent of total capitalization and debt to 2006 cash flow
was slightly less than 1.0 times for the year ended 2006. With the
Federal Government's proposed Trust taxation announcement, the Trust's
market capitalization fell by approximately 20 per cent to $4.5
billion whereby the net debt to total capitalization increased
accordingly. The Trust's debt levels are still considered to be one of
the lowest in the Trust sector.

- Continuously developing the expertise of our staff and seeking to hire
and retain the best in the industry - The Trust runs an active
training and development program for its employees and encourages
personal development. The Trust continues to assess compensation
levels in the industry to ensure that the Trust's compensation is
competitive so as to attract and retain the best employees. The
Trust's long-term incentive plan's payouts are directly tied to the
Trust's performance providing alignment between employees and
investors.

- Building relationships and conducting business in a way that is viewed
as fair and equitable - ARC employees, leadership team and directors
work hard to build the ARC "franchise value" through honest,
transparent dealings with our business partners. "Treating all people
with respect" is a key message inside and outside the organization.
This basic business fundamental allows us to build enduring
relationships with joint venture partners, land owners, investors,
banks and lending institutions, governments and the investment
community.

- Promoting the use of proven and effective technologies - The Trust
continues to research new technologies in an effort to conduct its
operations in the most efficient and cost effective manner. The Trust
has committed a portion of its 2007 capital expenditure budget towards
continued research into tertiary recovery methods.

- Being an industry leader in health, safety and environmental
performance - The Trust's primary focus continues to be on operating
in a safe, reliable and responsible fashion. The Trust is committed to
the platinum level of CAPP Stewardship reporting and continues to
achieve reductions in greenhouse gas emissions under the Canada
Climate Change VCR initiative. The Trust's commitment to pursue
additional CO(2) injection opportunities is expected to have the two-
fold benefit of enhanced recovery of reserves and the capture and
containment of CO(2) emissions which will benefit the environment. The
Trust's commitment to safety is evidenced by zero lost time incidents
reported for employees and contract employees of the Trust in 2006.

- Continuing to actively support local initiatives in the communities in
which we live and work - The Trust is very actively involved in
charitable and philanthropic causes both in Calgary and in the rural
communities in which it operates. ARC continued to be a strong
supporter of the United Way, Alberta Cancer Foundation, Alberta
Children's Hospital and many community organizations in rural centres.
In addition to the $1.3 million of cash donations made to charitable
organizations in 2006 the Trust also provided business expertise,
employee volunteers and tangible assets as needed.

2006 Review and 2007 Guidance
Following is a summary of the Trust's 2007 Guidance issued by way of news
release on November 2, 2006 and a review of 2006 actual results compared to
2006 Guidance:

-------------------------------------------------------------------------
2006 Actual 2007
Guidance 2006 % Change Guidance
-------------------------------------------------------------------------
Production (boe/d) 63,000 63,056 63,000
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 8.40 8.49 1 8.95
Transportation 0.70 0.63 (10) 0.70
G&A expenses - cash 1.65 1.58 4 2.25
G&A expenses - stock
compensation plans 0.60 0.47 (22) 0.20
Interest 1.35 1.38 2 1.50
Taxes 0.02 0.01 (50) 0.00
Capital expenditures ($ millions) 370 365 (1) 360
Weighted average trust units
and units issuable (millions) 205 207 1 208
-------------------------------------------------------------------------

Actual 2006 results were in line with 2006 guidance with only minor
exceptions as follows:

- Operating costs were slightly higher than guidance due to increased
Alberta electricity rates in the fourth quarter of 2006.

- Transportation costs were lower than guidance due to lower than
anticipated transportation costs in the fourth quarter on trucked
volumes.

- Cash G&A expenses were lower than guidance due to higher operating
recoveries attributed to high levels of capital and operating activity
in the fourth quarter.

- Non-cash G&A expenses were lower than guidance due to the decline in
the value of the Trust's whole unit plan following the Federal
Government's proposed Trust taxation announcement on October 31, 2006.
As the value of the whole unit plan is dependent upon the trust unit
price, there was a considerable decrease in the fourth quarter non-
cash whole unit plan expense.

- Interest expense was slightly higher than guidance due to increased
debt levels in the fourth quarter resulting from high capital and
acquisition activity which was partially funded with debt.

- Weighted average trust units were slightly higher than guidance due to
the large number of units issued pursuant to the DRIP in the fourth
quarter.
>>

There have been no revisions to the 2007 Guidance estimates as originally
published on November 2, 2006.

2007 Cash Flow Sensitivity
Below is a table that illustrates sensitivities to pre-hedged cash flow
with operational changes and changes to the business environment:

<<
-------------------------------------------------------------------------
Impact on Annual
Cash Flow
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 59.00 $ 1.00 $ 0.05
Natural gas price (CDN $AECO/mcf)(1) $ 7.25 $ 0.10 $ 0.03
USD/CAD exchange rate 0.88 $ 0.01 $ 0.06
Interest rate on debt 5.2% % 1.0 $ 0.03
Operational
Liquids production volume (bbl/d) 32,200 % 1.0 $ 0.02
Gas production volumes (mmcf/d) 185.0 % 1.0 $ 0.02
Operating expenses per boe $ 8.95 % 1.0 $ 0.01
Cash G&A expenses per boe $ 2.25 % 10.0 $ 0.02
-------------------------------------------------------------------------
(1) Analysis does not include the effect of hedging contracts.
>>

Forward-Looking Statement
This discussion and analysis contains forward-looking statements as to
the Trusts internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions. These
statements represent management's expectations or beliefs concerning, among
other things, future operating results and various components thereof or the
economic performance of ARC Energy Trust ("ARC" or "the Trust"). The
projections, estimates and beliefs contained in such forward-looking
statements are based on management's assumptions relating to the production
performance of ARC's oil and gas assets, the cost and competition for services
throughout the oil and gas industry in 2007 and the continuation of the
current regulatory and tax regime in Canada, and necessarily involve known and
unknown risks and uncertainties, including the business risks discussed in
this MD&A, which may cause actual performance and financial results in future
periods to differ materially from any projections of future performance or
results expressed or implied by such forward-looking statements. Accordingly,
readers are cautioned that events or circumstances could cause results to
differ materially from those predicted. The Trust does not undertake to update
any forward looking information in this document whether as to new
information, future events or otherwise.

Additional Information
Additional information relating to ARC can be found on SEDAR at
www.sedar.com.

<<
ANNUAL HISTORICAL REVIEW
-------------------------------------------------------------------------
For the year ended December 31
(CDN $ millions, except
per unit amounts) 2006 2005 2004 2003 2002
-------------------------------------------------------------------------
FINANCIAL
Revenue before
royalties 1,230.5 1,165.2 901.8 743.2 444.8
Per unit(1) 6.02 6.10 4.85 4.80 3.72
Cash flow 760.6 639.5 448.0 396.2 224.0
Per unit - basic(1) 3.72 3.35 2.41 2.56 1.87
Per unit - diluted 3.71 3.32 2.38 2.48 1.86
Net income 460.1 356.9 241.7 284.6 70.0
Per unit - basic(2) 2.28 1.90 1.32 1.88 0.60
Per unit - diluted 2.27 1.88 1.31 1.82 0.59
Cash distributions 484.2 376.6 330.0 279.3 183.6
Per unit(3) 2.40 1.99 1.80 1.80 1.56
Total assets 3,479.0 3,251.2 2,305.0 2,281.8 1,467.9
Total liabilities 1,550.6 1,415.5 755.7 730.0 599.3
Net debt outstanding(4) 739.1 578.1 264.8 262.1 347.8
Weighted average units
(millions)(5) 204.4 191.2 186.1 154.7 119.6
Units outstanding and
issuable at period
end (millions)(5) 207.2 202.0 188.8 182.8 126.4
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 11.4 9.2 5.4 5.7 2.0
Land 32.4 9.1 4.1 4.0 -
Drilling and completions 240.5 191.8 140.4 106.2 70.0
Plant and facilities 77.6 55.0 41.1 36.5 14.4
Other capital 2.6 3.7 2.8 3.4 1.9
Total capital
expenditures 364.5 268.8 193.8 155.8 88.3
Property acquisitions
(dispositions), net 115.2 91.3 (58.2) (161.6) 119.1
Corporate
acquisitions(6) 16.6 505.0 72.0 721.6 -
Total capital
expenditures and net
acquisitions 496.3 865.1 207.6 715.8 207.4
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,042 23,282 22,961 22,886 20,655
Natural gas (mmcf/d) 179.1 173.8 178.3 164.2 109.8
Natural gas liquids
(bbl/d) 4,170 4,005 4,191 4,086 3,479
Total
(boe per day 6:1) 63,056 56,254 56,870 54,335 42,425
Average prices
Crude oil ($/bbl) 65.26 61.11 47.03 36.90 31.63
Natural gas ($/mcf) 6.97 8.96 6.78 6.40 4.41
Natural gas liquids
($/bbl) 52.63 49.92 39.04 32.19 24.01
Oil equivalent ($/boe) 53.33 56.54 43.13 37.29 28.73
-------------------------------------------------------------------------
RESERVES(7)
(company interest)
Proved plus probable
reserves
Crude oil and NGL
(mbbl) 162,193 163,385 123,226 129,663 117,241
Natural gas (bcf) 743.6 741.7 724.5 720.2 408.8
Total (mboe) 286,125 286,997 243,974 249,704 185,371
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading)
Unit prices
High 30.74 27.58 17.98 14.87 13.44
Low 19.20 16.55 13.50 10.89 11.04
Close 22.30 26.49 17.90 14.74 11.90
Average daily volume
(thousands) 706 656 420 430 305
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average units plus units issuable for exchangeable
shares.
(2) Net income in the basic per trust unit calculation has been reduced
by interest on the convertible debentures in 2003 and is based on net
income after non-controlling interest divided by weighted average
units (excluding units issuable for exchangeable shares) for the
years 2003-2006.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Net debt excludes unrealized commodity and foreign exchange contracts
asset and liability.
(5) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio
(6) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.
(7) Established reserves for 2002.

QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(CDN $ millions, except per
unit amounts) 2006
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 292.5 312.3 306.7 318.9
Per unit(1) 1.42 1.52 1.51 1.58
Cash flow 174.4 200.3 194.7 191.2
Per unit - basic(1) 0.85 0.98 0.96 0.94
Per unit - diluted 0.84 0.97 0.95 0.94
Net income 56.6 116.9 182.5 104.1
Per unit - basic(2) 0.28 0.58 0.91 0.52
Per unit - diluted 0.28 0.58 0.91 0.52
Cash distributions 122.3 121.4 120.6 119.9
Per unit(3) 0.60 0.60 0.60 0.60
Total assets 3,479.0 3,335.8 3,277.8 3,279.7
Total liabilities 1,550.6 1,371.3 1,339.9 1,434.1
Net debt outstanding(4) 739.1 579.7 567.4 598.9
Weighted average units(5) 206.5 205.1 203.7 202.5
Units outstanding and
issuable(5) 207.2 205.7 204.4 203.1
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.7 2.2 2.8 2.7
Land 11.8 1.4 14.3 4.9
Drilling and completions 79.1 76.2 29.8 55.4
Plant and facilities 26.5 24.6 10.9 15.6
Other capital 0.8 0.5 0.8 0.5
Total capital expenditures 121.9 104.9 58.6 79.1
Property acquisitions
(dispositions) net 76.4 8.4 2.8 27.6
Corporate acquisitions(6) 16.6 - - -
Total capital expenditures
and net acquisitions 214.9 113.3 61.4 106.7
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,605 29,108 27,805 29,651
Natural gas (mmcf/d) 179.5 173.4 178.5 185.0
Natural gas liquids (bbl/d) 4,144 4,166 4,247 4,120
Total (boe per day 6:1) 63,663 62,178 61,803 64,600
Average prices
Crude oil ($/bbl) 58.26 71.84 71.86 59.53
Natural gas ($/mcf) 6.99 6.10 6.35 8.40
Natural gas liquids ($/bbl) 46.51 56.60 54.44 52.91
Oil equivalent ($/boe) 49.94 54.59 54.54 54.86
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 29.22 30.74 28.61 27.51
Low 19.20 25.25 24.35 25.09
Close 22.30 27.21 28.00 27.36
Average daily volume
(thousands) 1,125 614 548 546
-------------------------------------------------------------------------

-------------------------------------------------------------------------
(CDN $ millions, except per
unit amounts) 2005
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 365.3 310.2 251.6 238.1
Per unit(1) 1.89 1.62 1.32 1.26
Cash flow 207.6 168.1 121.8 142.0
Per unit - basic(1) 1.07 0.88 0.64 0.75
Per unit - diluted 1.07 0.87 0.63 0.74
Net income 130.4 114.6 73.2 38.6
Per unit - basic(2) 0.68 0.61 0.39 0.21
Per unit - diluted 0.68 0.59 0.39 0.20
Cash distributions 115.7 92.6 84.5 83.9
Per unit(3) 0.60 0.49 0.45 0.45
Total assets 3,251.2 2,483.5 2,427.5 2,303.9
Total liabilities 1,415.5 912.2 895.2 785.8
Net debt outstanding(4) 578.1 357.6 366.2 254.3
Weighted average units(5) 193.4 191.7 190.3 189.2
Units outstanding and
issuable(5) 202.0 192.1 191.3 189.6
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.0 2.3 2.7 1.3
Land 5.5 2.0 0.8 0.8
Drilling and completions 60.3 63.6 32.7 35.2
Plant and facilities 17.0 14.8 8.7 14.5
Other capital 2.0 0.3 0.6 0.7
Total capital expenditures 87.8 83.0 45.5 52.5
Property acquisitions
(dispositions) net 3.0 5.9 78.7 3.7
Corporate acquisitions(6) 462.8 - 42.2 -
Total capital expenditures
and net acquisitions 553.6 88.9 166.4 56.2
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 25,534 23,513 22,046 21,993
Natural gas (mmcf/d) 177.9 168.2 173.1 176.1
Natural gas liquids (bbl/d) 3,943 4,047 3,962 4,072
Total (boe per day 6:1) 59,120 55,592 54,860 55,410
Average prices
Crude oil ($/bbl) 62.12 69.37 58.37 53.63
Natural gas ($/mcf) 12.05 9.08 7.42 7.20
Natural gas liquids ($/bbl) 57.14 50.43 46.13 46.57
Oil equivalent ($/boe) 67.16 60.66 50.40 47.74
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 27.58 24.20 20.30 20.40
Low 20.45 19.94 16.88 16.55
Close 26.49 24.10 19.94 18.15
Average daily volume
(thousands) 653 599 605 895
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average units plus units issuable for exchangeable
shares.
(2) Net income per unit is based on net income after non-controlling
interest divided by weighted average units (excluding units issuable
for exchangeable shares).
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Net debt excludes unrealized commodity and foreign exchange contracts
asset and liability.
(5) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(6) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.

CONSOLIDATED BALANCE SHEETS
As at December 31 (unaudited)

(CDN$ millions) 2006 2005
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 2.8 $ -
Accounts receivable 129.8 123.0
Prepaid expenses 18.4 14.0
Commodity and foreign currency
contracts (Note 11) 25.7 3.1
-------------------------------------------------------------------------
176.7 140.1
Reclamation funds (Note 4) 30.9 23.5
Property, plant and equipment (Note 5) 3,093.8 2,930.0
Long-term investment (Note 6) 20.0 -
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,479.0 $ 3,251.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 7) $ 162.1 $ 148.6
Cash distributions payable 40.9 39.8
Commodity and foreign currency contracts
(Note 11) 34.4 7.2
-------------------------------------------------------------------------
237.4 195.6
Long-term debt (Note 8) 687.1 526.6
Other long-term liabilities (Note 9) 14.6 12.4
Asset retirement obligations (Note 10) 177.3 165.1
Future income taxes (Note 13) 434.2 515.9
-------------------------------------------------------------------------
Total liabilities 1,550.6 1,415.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 21)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 14) 40.0 37.5

UNITHOLDERS' EQUITY
Unitholders' capital (Note 15) 2,349.2 2,230.8
Contributed surplus (Note 18) 2.4 6.4
Deficit (Note 16) (463.2) (439.1)
-------------------------------------------------------------------------
Total unitholders' equity 1,888.4 1,798.1
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,479.0 $ 3,251.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
For the three and twelve months ended December 31 (unaudited)

Three months ended Twelve months ended
($CDN millions, except December 31 December 31
per unit amounts) 2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues
Oil, natural gas and
natural gas liquids $ 292.5 $ 365.3 $ 1,230.5 $ 1,165.2
Royalties (51.5) (73.5) (222.3) (235.3)
-------------------------------------------------------------------------
241.0 291.8 1,008.2 929.9
Gain (loss) on commodity
and foreign currency
contracts (Note 11)
Realized 9.8 (26.4) 29.3 (87.6)
Unrealized 3.9 28.1 (4.6) -
-------------------------------------------------------------------------
254.7 293.5 1,032.9 842.3
-------------------------------------------------------------------------
Expenses

Transportation 3.8 3.5 14.5 14.3
Operating 53.5 38.9 195.4 142.2
General and administrative 10.1 15.4 47.1 42.8
Interest on long-term debt
(Note 8) 8.7 6.0 31.8 16.9
Depletion, depreciation and
accretion (Notes 5 and 10) 96.2 73.7 360.0 264.5
Loss (gain) on foreign
exchange (Note 12) 21.2 1.4 4.2 (6.4)
-------------------------------------------------------------------------
193.5 138.9 653.0 474.3
-------------------------------------------------------------------------
Income before taxes 61.2 154.6 379.9 368.0
Capital and other taxes - (2.3) (0.3) (3.9)
Future income tax (expense)
recovery (Note 13) (3.7) (19.8) 87.1 (1.6)
-------------------------------------------------------------------------
Net income before
non-controlling interest 57.5 132.5 466.7 362.5
Non-controlling interest
(Note 14) (0.9) (2.0) (6.6) (5.6)
-------------------------------------------------------------------------
Net income $ 56.6 $ 130.5 $ 460.1 $ 356.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of period $ (397.5) $ (453.9) $ (439.1) $ (419.4)
Distributions paid or
declared (Note 17) (122.3) (115.7) (484.2) (376.6)
-------------------------------------------------------------------------
Deficit, end of period
(Note 16) $ (463.2) $ (439.1) $ (463.2) $ (439.1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 20)
Basic $ 0.28 $ 0.68 $ 2.28 $ 1.90
Diluted $ 0.27 $ 0.67 $ 2.27 $ 1.88
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and twelve months ended December 31 (unaudited)

Three months ended Twelve months ended
December 31 December 31
($CDN millions) 2006 2005 2006 2005
-------------------------------------------------------------------------

CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 56.6 $ 130.5 $ 460.1 $ 356.9
Add items not involving cash:
Non-controlling interest
(Note 14) 0.9 2.0 6.6 5.6
Future income tax expense
(recovery) (Note 13) 3.7 19.8 (87.1) 1.6
Depletion, depreciation and
accretion (Notes 5 and 10) 96.2 73.7 360.0 264.5
Non-cash (gain) loss on
commodity and foreign
currency contracts (Note 11) (3.9) (28.1) 4.6 -
Non-cash loss (gain) on
foreign exchange (Note 12) 21.0 1.5 4.5 (6.3)
Non-cash trust unit
incentive compensation
(Notes 18 and 19) (0.1) 8.2 11.9 17.2
Expenditures on site
restoration and
reclamation (Note 10) (4.0) (1.8) (10.6) (4.9)
Change in non-cash working
capital (11.1) 41.5 (16.0) (17.9)
-------------------------------------------------------------------------
159.3 247.3 734.0 616.7
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING
ACTIVITIES
Issuance of long-term debt
under revolving credit
facilities, net 167.1 155.0 162.7 258.2
Issuance of senior secured
notes - 86.8 - 86.8
Repayment of senior secured
notes (6.8) (32.5) (6.8) (32.5)
Issue of trust units 2.2 242.7 14.4 259.7
Trust unit issue costs (0.2) (12.2) (0.2) (12.2)
Cash distributions paid,
net of distribution
reinvestment (Note 17) (95.7) (92.7) (389.6) (318.3)
Payment of retention
bonuses (Note 9) - - (1.0) (1.0)
Change in non-cash
working capital (2.7) (2.0) - (0.2)
-------------------------------------------------------------------------
63.9 345.1 (220.5) 240.5
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING
ACTIVITIES
Corporate acquisition, net
of cash received (Note 3) (16.6) (462.8) (16.6) (505.0)
Acquisition of petroleum
and natural gas properties (76.6) (3.1) (117.4) (93.8)
Proceeds on disposition of
petroleum and natural gas
properties - (17.5) 2.1 2.5
Capital expenditures (121.8) (77.3) (362.7) (257.9)
Long-term investment (Note 6) - - (20.0) -
Net reclamation fund
contributions (Note 4) (1.9) (0.2) (7.4) (2.2)
Changes in non-cash
working capital (3.9) (53.7) 11.3 (5.2)
-------------------------------------------------------------------------
(220.8) (597.1) (510.7) (861.6)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 2.4 (4.7) 2.8 (4.4)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 0.4 4.7 - 4.4
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 2.8 $ - $ 2.8 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006 and 2005 (unaudited)
(all tabular amounts in CDN$ millions, except per unit and volume
amounts)

1. STRUCTURE OF THE TRUST

ARC Energy Trust (the "Trust") was formed on May 7, 1996 pursuant to
a Trust indenture (the "Trust Indenture") that has been amended from
time to time, most recently on May 15, 2006. Computershare Trust
Company of Canada was appointed as Trustee under the Trust Indenture.
The beneficiaries of the Trust are the holders of the trust units.

The Trust was created for the purposes of issuing trust units to the
public and investing the funds so raised to purchase a royalty in the
properties of ARC Resources Ltd. ("ARC Resources") and ARC Sask
Energy Trust ("ARC Sask"). The Trust Indenture was amended on June 7,
1999 to convert the Trust from a closed-end to an open-ended
investment Trust. The current business of the Trust includes the
investment in all types of energy business-related assets including,
but not limited to, petroleum and natural gas-related assets,
gathering, processing and transportation assets. The operations of
the Trust consist of the acquisition, development, exploitation and
disposition of these assets and the distribution of the net cash
proceeds from these activities to the unitholders.

2. SUMMARY OF ACCOUNTING POLICIES

The consolidated financial statements have been prepared by
management following Canadian generally accepted accounting
principles ("GAAP"). The preparation of financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingencies
at the date of the financial statements, and revenues and expenses
during the reporting year. Actual results could differ from those
estimated.

In particular, the amounts recorded for depletion, depreciation and
accretion of the petroleum and natural gas properties and for asset
retirement obligations are based on estimates of reserves and future
costs. By their nature, these estimates, and those related to future
cash flows used to assess impairment, are subject to measurement
uncertainty and the impact on the financial statements of future
periods could be material.

Principles of Consolidation
The consolidated financial statements include the accounts of the
Trust and its subsidiaries. Any reference to "the Trust" throughout
these consolidated financial statements refers to the Trust and its
subsidiaries. All inter-entity transactions have been eliminated.

Revenue Recognition
Revenue associated with the sale of crude oil, natural gas, and
natural gas liquids ("NGLs") owned by the Trust are recognized when
title passes from the Trust to its customers.

Transportation
Costs paid by the Trust for the transportation of natural gas, crude
oil and NGLs from the wellhead to the point of title transfer are
recognized when the transportation is provided.

Joint Venture
The Trust conducts many of its oil and gas production activities
through joint ventures and the financial statements reflect only the
Trust's proportionate interest in such activities.

Depletion and Depreciation
Depletion of petroleum and natural gas properties and depreciation of
production equipment are calculated on the unit-of-production basis
based on:

(a) total estimated proved reserves calculated in accordance with
National Instrument 51-101, Standards of Disclosure for Oil and
Gas Activities;
(b) total capitalized costs, excluding undeveloped lands, plus
estimated future development costs of proved undeveloped
reserves, including future estimated asset retirement costs; and
(c) relative volumes of petroleum and natural gas reserves and
production, before royalties, converted at the energy equivalent
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil.

Unit Based Compensation
The Trust established a Trust Unit Incentive Rights Plan (the "Rights
Plan") for employees, independent directors and long-term consultants
who otherwise meet the definition of an employee of the Trust. The
exercise price of the rights granted under the Plan may be reduced in
future periods in accordance with the terms of the Plan. The Trust
accounts for the rights using the fair value method, whereby the fair
value of rights is determined on the date on which fair value can
initially be determined. The fair value is then recorded as
compensation expense over the period that the rights vest, with a
corresponding increase to contributed surplus. When rights are
exercised, the proceeds, together with the amount recorded in
contributed surplus, are recorded to unitholders' capital.

Whole Trust Unit Incentive Plan Compensation
The Trust has established a Whole Trust Unit Incentive Plan (the
"Whole Unit Plan") for employees, independent directors and long-term
consultants who otherwise meet the definition of an employee of the
Trust. Compensation expense associated with the Whole Unit Plan is
granted in the form of Restricted Trust Units ("RTUs") and
Performance Trust Units ("PTUs") and is determined based on the
intrinsic value of the Whole Trust Units at each period end. The
intrinsic valuation method is used as participants of the Whole Unit
Plan receive a cash payment on a fixed vesting date. This valuation
incorporates the period end Trust unit price, the number of RTUs and
PTUs outstanding at each period end, and certain management
estimates. As a result, large fluctuations, even recoveries, in
compensation expense may occur due to changes in the underlying Trust
unit price. In addition, compensation expense is amortized and
recognized in earnings over the vesting period of the Whole Unit Plan
with a corresponding increase or decrease in liabilities.
Classification between accrued liabilities and other long-term
liabilities is dependent on the expected payout date.

The Trust charges amounts relating to head office employees to
general and administrative expense, amounts relating to field
employees to operating expense and amounts relating to geologists and
geophysicists to property, plant and equipment.

The Trust has not incorporated an estimated forfeiture rate for RTUs
and PTUs that will not vest. Rather, the Trust accounts for actual
forfeitures as they occur.

Cash and Cash Equivalents
Cash and cash equivalents include short-term investments, such as
money market deposits or similar type instruments, with an original
maturity of three months or less when purchased.

Reclamation Funds
Reclamation funds hold investment grade assets which are carried at
cost and are subject to impairment in the event of a non-temporary
decline in market value.

Long-Term Investment
Investments are recorded and carried at cost and are subject to
impairment in the event of a non-temporary decline in market value.

Property, Plant and Equipment ("PP&E")
The Trust follows the full cost method of accounting. All costs of
exploring, developing and acquiring petroleum and natural gas
properties, including asset retirement costs, are capitalized and
accumulated in one cost centre as all operations are in Canada.
Maintenance and repairs are charged against income, and renewals and
enhancements that extend the economic life of the PP&E are
capitalized. Gains and losses are not recognized upon disposition of
petroleum and natural gas properties unless such a disposition would
alter the rate of depletion by 20 per cent or more.

Impairment
The Trust places a limit on the aggregate carrying value of PP&E,
which may be amortized against revenues of future periods.

Impairment is recognized if the carrying amount of the PP&E exceeds
the sum of the undiscounted cash flows expected to result from the
Trust's proved reserves. Cash flows are calculated based on third
party quoted forward prices, adjusted for the Trust's contract prices
and quality differentials.

Upon recognition of impairment, the Trust would then measure the
amount of impairment by comparing the carrying amounts of the PP&E to
an amount equal to the estimated net present value of future cash
flows from proved plus risked probable reserves. The Trust's risk-
free interest rate is used to arrive at the net present value of the
future cash flows. Any excess carrying value above the net present
value of the Trust's future cash flows would be recorded as a
permanent impairment and charged against net income.

The cost of unproved properties is excluded from the impairment test
described above and subject to a separate impairment test. In the
case of impairment, the book value of the impaired properties are
moved to the petroleum and natural gas depletable base.

Goodwill
The Trust must record goodwill relating to a corporate acquisition
when the total purchase price exceeds the fair value for accounting
purposes of the net identifiable assets and liabilities of the
acquired company. The goodwill balance is assessed for impairment
annually at year-end or as events occur that could result in an
impairment. Impairment is recognized based on the fair value of the
reporting entity (consolidated Trust) compared to the book value of
the reporting entity. If the fair value of the consolidated Trust is
less than the book value, impairment is measured by allocating the
fair value of the consolidated Trust to the identifiable assets and
liabilities as if the Trust had been acquired in a business
combination for a purchase price equal to its fair value. The excess
of the fair value of the consolidated trust over the amounts assigned
to the identifiable assets and liabilities is the fair value of the
goodwill. Any excess of the book value of goodwill over this implied
fair value of goodwill is the impairment amount. Impairment is
charged to earnings in the period in which it occurs.

Goodwill is stated at cost less impairment and is not amortized.

Asset Retirement Obligations
The Trust recognizes the fair value of an Asset Retirement Obligation
("ARO") in the period in which it is incurred when a reasonable
estimate of the fair value can be made. On a periodic basis,
management will review these estimates and changes, if any, to the
estimate will be applied on a prospective basis. The fair value of
the estimated ARO is recorded as a long-term liability, with a
corresponding increase in the carrying amount of the related asset.
The capitalized amount 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 would also result in an increase or decrease to the
ARO. Actual costs incurred upon settlement of the ARO are charged
against the ARO to the extent of the liability recorded. Any
difference between the actual costs incurred upon settlement of the
ARO and the recorded liability is recognized as a gain or loss in the
Trust's earnings in the period in which the settlement occurs.

Income Taxes
The Trust follows 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
of the Trust's corporate subsidiaries and their respective tax base,
using substantively enacted future income tax rates. The effect of a
change in income tax rates on future tax liabilities and assets is
recognized in income in the period in which the change occurs.
Temporary differences arising on acquisitions result in future income
tax assets and liabilities.

The Trust is a taxable entity under the Income Tax Act (Canada) and
is taxable only on income that is not distributed or distributable to
the unitholders. As the Trust distributes all of its taxable income
to the unitholders and meets the requirements of the Income Tax Act
(Canada) applicable to the Trust, no provision for income taxes has
been made in the Trust.

Basic and Diluted per Trust Unit Calculations
Basic net income per unit is computed by dividing the net income by
the weighted average number of trust units outstanding during the
period. Diluted net income per unit amounts are calculated based on
net income before non-controlling interest divided by dilutive trust
units. Dilutive trust units are arrived at by taking weighted average
trust units and trust units issuable on conversion of exchangeable
shares, and giving effect to the potential dilution that would occur
if rights were exercised at the beginning of the period. The treasury
stock method assumes that proceeds received from the exercise of in-
the-money rights and any unrecognized trust unit incentive
compensation are used to repurchase units at the average market
price.

Derivative Financial Instruments
The Trust is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the
normal course of operations. A variety of derivative instruments are
used by the Trust to reduce its exposure to fluctuations in commodity
prices, foreign exchange rates, and interest rates. The fair values
of these derivative instruments are based on an estimate of the
amounts that would have been received or paid to settle these
instruments prior to maturity. The Trust considers all of these
transactions to be effective economic hedges, however, the majority
of the Trust's contracts do not qualify or have not been designated
as effective hedges for accounting purposes.

For derivative instruments that do qualify as effective accounting
hedges, policies and procedures are in place to ensure that the
required documentation and approvals are in place. This documentation
specifically ties the derivative financial instrument to their use,
and in the case of commodities, to the mitigation of market price
risk associated with cash flows expected to be generated. When
applicable, the Trust also identifies all relationships between
hedging instruments and hedged items, as well as its risk management
objective and the strategy for undertaking hedge transactions. This
would include linking the particular derivative to specific assets
and liabilities on the consolidated balance sheet or to specific firm
commitments or forecasted transactions. Where specific hedges are
executed, the Trust assesses, both at the inception of the hedge and
on an ongoing basis, whether the derivative used in the particular
hedging transaction is effective in offsetting changes in fair value
or cash flows of the hedged item.

Realized and unrealized gains and losses associated with hedging
instruments that have been terminated or cease to be effective prior
to maturity, are deferred on the consolidated balance sheet and
recognized in income in the period in which the underlying hedged
transaction is recognized.

For transactions that do not qualify for hedge accounting, the Trust
applies the fair value method of accounting by recording an asset or
liability on the consolidated balance sheet and recognizing changes
in the fair value of the instruments in the statement of income for
the current period.

Foreign Currency Translation
Monetary assets and liabilities denominated in a foreign currency are
translated at the rate of exchange in effect at the consolidated
balance sheet date. Revenues and expenses are translated at the
period average rates of exchange. Translation gains and losses are
included in income in the period in which they arise.

Non-Controlling Interest
The Trust must record non-controlling interest when exchangeable
shares issued by a subsidiary of the Trust are transferable to third
parties. Non-controlling interest on the consolidated balance sheet
is recognized based on the fair value of the exchangeable shares upon
issuance plus the accumulated earnings attributable to the non-
controlling interest. Net income is reduced for the portion of
earnings attributable to the non-controlling interest. As the
exchangeable shares are converted to trust units, the non-controlling
interest on the consolidated balance sheet is reduced by the
cumulative book value of the exchangeable shares and Unitholders'
capital is increased by the corresponding amount.

3. CORPORATE ACQUISITIONS

On December 6, 2006 the Trust completed a minor corporate acquisition
for net cash consideration of $16.6 million. There was no goodwill
recognized with this acquisition. Substantially all of the
consideration was applied against property, plant and equipment, with
a nominal amount applied against working capital items.

The following acquisitions were completed in 2005:

REDWATER AND NORTH PEMBINA CARDIUM UNIT

On December 16, 2005, the Trust acquired all of the issued and
outstanding shares of three legal entities, 3115151 Nova Scotia
Company, 3115152 Nova Scotia Company and 3115153 Nova Scotia Company
which together hold the Redwater and North Pembina Cardium Unit
assets (collectively "Redwater and NPCU") for total consideration of
$462.8 million. The allocation of the purchase price and
consideration paid were as follows:

Net Assets Acquired
---------------------------------------------------------------------
Working capital deficit $ (0.6)
Property, plant and equipment 729.5
Asset retirement obligations (70.7)
Future income taxes (195.4)
---------------------------------------------------------------------
Total net assets acquired $ 462.8
---------------------------------------------------------------------
---------------------------------------------------------------------

Consideration Paid
---------------------------------------------------------------------
Cash consideration and fees paid $ 462.8
---------------------------------------------------------------------
Total consideration paid $ 462.8
---------------------------------------------------------------------
---------------------------------------------------------------------

The acquisition of Redwater and NPCU has been accounted for as an
asset acquisition pursuant to both management's view of the
transaction and EIC-124.

In addition to consideration paid, the Trust committed to making
contributions to a restricted reclamation fund as detailed in
Note 21.

The future income tax liability on acquisition was based on the
difference between the fair value of the acquired net assets of
$463.4 million and the associated tax basis of $93.3 million.

These consolidated financial statements incorporate the operations of
Redwater and NPCU from December 16, 2005.

ROMULUS EXPLORATION INC.

On June 30, 2005, the Trust acquired all of the issued and
outstanding shares of Romulus Exploration Inc. ("Romulus") for total
consideration of $42.2 million. The allocation of the purchase price
and consideration paid were as follows:

Net Assets Acquired
---------------------------------------------------------------------
Working capital deficit $ (1.4)
Property, plant and equipment 62.5
Asset retirement obligations (0.4)
Future income taxes (18.5)
---------------------------------------------------------------------
Total net assets acquired $ 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------

Consideration Paid
---------------------------------------------------------------------
Cash and fees paid $ 42.2
---------------------------------------------------------------------
Total consideration paid $ 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------

The acquisition of Romulus has been accounted for as an asset
acquisition pursuant to both management's view of the transaction and
EIC-124.

The future income tax liability on acquisition was based on the
difference between the fair value of the acquired net assets of
$44 million and the associated tax basis of $9 million.

These consolidated financial statements incorporate the operations of
Romulus from June 30, 2005.

4. RECLAMATION FUNDS

2006 2005
---------------------------------------------------------------------
Unrestricted Restricted Unrestricted Restricted
---------------------------------------------------------------------
Balance,
beginning
of year $ 23.5 $ - $ 21.3 $ -
Contributions 6.0 6.1 6.0 -
Reimbursed
expenditures(1) (5.7) - (4.6) -
Interest earned
on funds 1.0 - 0.8 -
---------------------------------------------------------------------
Balance, end
of year $ 24.8 $ 6.1 $ 23.5 $ -
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.

An unrestricted reclamation fund was established to fund future asset
retirement obligation costs. In addition, the Trust has created a
restricted reclamation fund associated with the Redwater property
acquired in 2005. Contributions to the restricted and unrestricted
reclamation funds and interest earned on the balances have been
deducted from the cash distributions to the unitholders. The Board of
Directors of ARC Resources has approved voluntary contributions to
the unrestricted reclamation fund over a 20-year period that
currently results in minimum annual contributions of $6 million
($6 million in 2005) based upon properties owned as at December 31,
2006. Contributions to the restricted reclamation fund will vary
over time and have been disclosed in Note 21. Contributions for both
funds are continually reassessed to ensure that the funds are
sufficient to finance the majority of future abandonment obligations.
Interest earned on the funds are retained within the funds.

5. PROPERTY, PLANT AND EQUIPMENT

2006 2005
---------------------------------------------------------------------
Property, plant and equipment, at cost $ 4,655.3 $ 4,142.0
Accumulated depletion and depreciation (1,561.5) (1,212.0)
---------------------------------------------------------------------
Property, plant and equipment, net $ 3,093.8 $ 2,930.0
---------------------------------------------------------------------
---------------------------------------------------------------------

The calculation of 2006 depletion and depreciation included an
estimated $547 million ($488 million in 2005) for future development
costs associated with proved undeveloped reserves and excluded $108.9
million ($58.9 million in 2005) for the book value of unproved
properties.

The Trust performed a ceiling test calculation at December 31, 2006
to assess the recoverable value of property plant and equipment
(PP&E). Based on the calculation, the present value of future net
revenues from the Trust's proved plus probable reserves exceeded the
carrying value of the Trust's PP&E at December 31, 2006. The
benchmark prices used in the calculation were as follows:

WTI Oil AECO Gas USD/CAD
Year ($US/bbl) (CDN$/mmbtu) Exchange Rates
---------------------------------------------------------------------
2007 62.00 7.20 0.87
2008 60.00 7.45 0.87
2009 58.00 7.75 0.87
2010 57.00 7.80 0.87
2011 57.00 7.85 0.87
2012 57.50 8.15 0.87
2013 58.50 8.30 0.87
2014 59.75 8.50 0.87
2015 61.00 8.70 0.87
2016 62.25 8.90 0.87
2017 63.50 9.10 0.87
---------------------------------------------------------------------
Remainder(1) 2.0% 2.0% 0.87
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Percentage change represents the change in each year after 2017
to the end of the reserve life.

6. LONG-TERM INVESTMENT

During the year the Trust entered into an equity investment in a
private oil sands company in the amount of $20 million. The
investment in the shares of the private company has been considered
to be a related party transaction due to common directorships of the
Trust, the private company and the manager of a private equity fund
that holds shares in the private company. The $20 million investment
was part of a $325 million private placement of the private company.
In addition, certain directors and officers of the Trust have minor
direct and indirect shareholdings in the private company.

7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

2006 2005
---------------------------------------------------------------------
Trades payable $ 39.0 $ 33.0
Accrued liabilities 108.8 109.2
Current portion of accrued long-term
incentive compensation 11.5 3.6
Interest payable 1.8 1.8
Retention bonuses 1.0 1.0
---------------------------------------------------------------------
Total accounts payable and accrued
liabilities $ 162.1 $ 148.6
---------------------------------------------------------------------
---------------------------------------------------------------------

The current portion of accrued long-term incentive compensation
represents the current portion of the Trust's estimated liability for
the Whole Unit Plan as at December 31, 2006 (see Note 19). This
amount is payable in 2007.

8. LONG-TERM DEBT

2006 2005
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility $ 425.0 $ 254.6
Working capital facility 1.1 3.8
Senior secured notes
5.42% USD Note 87.4 87.4
4.94% USD Note 28.0 35.0
4.62% USD Note 72.8 72.9
5.10% USD Note 72.8 72.9
---------------------------------------------------------------------
Total long-term debt outstanding $ 687.1 $ 526.6
---------------------------------------------------------------------
---------------------------------------------------------------------

Revolving Credit Facilities
During 2006, the Trust entered into a $572 million secured, annually
extendible, financial covenant-based three year syndicated credit
facility that expires in March 2009 and a $25 million demand working
capital facility. The revolving credit facility is extendible
annually, security is in the form of floating charges on all lands
and assignments and negative pledges on specific petroleum and
natural gas properties.

Borrowings under the facility bear interest at bank prime (6.0 per
cent and 5.0 per cent at December 31, 2006 and December 31, 2005,
respectively) or, at the Trust's option, Canadian or U.S. dollar
bankers' acceptances plus a stamping fee. The lenders review the
credit facility each year and determine whether they will extend the
revolving periods for another year. In the event that the credit
facility is not extended at anytime before the maturity date, the
loan balance will become repayable on the maturity date. The maturity
date of the current credit facility is March 24, 2009.

The working capital facility allows for maximum borrowings of $25
million and is due and payable immediately upon demand by the bank.
The facility is secured and is subject to the same covenants as the
syndicated credit facility.

Various borrowing options exist under the revolving credit facility
including prime rate advances, bankers' acceptances and LIBOR based
loans denominated in either Canadian or U.S. dollars. All drawings
under the facility are subject to stamping fees that vary between 65
bps and 115 bps depending on certain consolidated financial ratios.

5.42 Per Cent and 4.94 Per Cent Senior Secured USD Notes
These senior secured notes were issued in two separate issues
pursuant to an Uncommitted Master Shelf Agreement. The US$24 million
Senior secured notes were issued in 2002, bear interest at 4.94 per
cent, have a remaining final term of 3.8 years (remaining average
term of 2.3 years) and require equal principal payments of US$6
million over a four year period commencing in 2007. The US$75 million
Senior secured notes were issued in 2005, bear interest at 5.42 per
cent, have a remaining final term of 11 years (remaining weighted
average term of 7.6 years) and require equal principal repayments
over an eight year period commencing in 2010.

4.62 Per Cent and 5.10 Per Cent Senior Secured USD Notes
These notes were issued on April 27, 2004 via a private placement in
two tranches of US$62.5 million each. The first tranche of US$62.5
million bears interest at 4.62 per cent and has a remaining final
term of 7.3 years (remaining weighted average term of 4.9 years) and
require equal principal repayments over a 6 year period commencing
2009. Immediately following the issuance, the Trust entered into
interest rate swap contracts which effectively changed the interest
rate from fixed to floating (see Note 11). The second tranche of US
$62.5 million bears interest at 5.10 per cent and has a remaining
final term of 9.3 years (remaining weighted average term of 7.4
years). Repayments of the notes will occur over a five year period
commencing in 2012.

Debt Covenants
The following are the significant financial covenants governing the
revolving credit facilities:

- Long-term debt and letters of credit not to exceed three times
annualized net income before non-cash items and interest
expense;
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times annualized net income before non-cash items
and interest expense; and
- Long-term debt and letters of credit not to exceed 50 per cent
of unitholders' equity and long-term debt, letters of credit,
and subordinated debt.

In the event that the Trust enters into a material acquisition
whereby the purchase price exceeds 10 per cent of the book value of
the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times, respectively. As at December 31,
2006, the Trust had $4.7 million in letters of credit ($4.4 million
in 2005), no subordinated debt, and was in compliance with all
covenants.

The payment of principal and interest are allowable deductions in the
calculation of cash available for distribution to unitholders and
rank ahead of cash distributions payable to unitholders. Should the
properties securing this debt generate insufficient revenue to repay
the outstanding balances, the unitholders have no direct liability.

During 2006, the weighted-average effective interest rate under the
credit facility was 5.3 per cent (3.3 per cent in 2005).

Amounts due under the working capital facility and the senior secured
notes in the next 12 months have not been included in current
liabilities as management has the ability and intent to refinance
this amount through the syndicated credit facility.

Interest paid during the period did not differ significantly from
interest expense.

9. OTHER LONG-TERM LIABILITIES

2006 2005
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 14.6 $ 11.4
Retention bonuses - 1.0
---------------------------------------------------------------------
Total other long-term liabilities $ 14.6 $ 12.4
---------------------------------------------------------------------
---------------------------------------------------------------------

The accrued long-term incentive compensation represents the long-term
portion of the Trust's estimated liability for the Whole Unit Plan as
at December 31, 2006 (see Note 19). This amount is payable in 2008
through 2009.

The retention bonuses arose upon internalization of the management
contract in 2002. The final retention payment will occur in August
2007 and therefore is classified as a current liability as at
December 31, 2006.

10. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations were estimated by
management based on the Trust's net ownership interest in all wells
and facilities, estimated costs to reclaim and abandon the wells and
facilities and the estimated timing of the costs to be incurred in
future periods. The Trust has estimated the net present value of its
total asset retirement obligations to be $177.3 million as at
December 31, 2006 ($165.1 million in 2005) based on a total future
undiscounted liability of $1,042.6 million ($603.4 million in 2005).
These payments are expected to be made over the next 61 years with
the bulk of payments being made in years 2017 to 2021 and 2057 to
2067. The Trust's weighted average credit adjusted risk free rate of
6.5 per cent (5.6 per cent in 2005) and an inflation rate of 2.0 per
cent (2.0 per cent in 2005) were used to calculate the present value
of the asset retirement obligations. During the year, no gains or
losses were recognized on settlements of asset retirement
obligations.

The following table reconciles the Trust's asset retirement
obligations:

2006 2005
---------------------------------------------------------------------
Balance, beginning of year $ 165.1 $ 73.0
Increase in liabilities relating to
corporate acquisitions 4.9 71.1
Increase in liabilities relating to
development activities 2.8 5.1
Increase in liabilities relating to
change in estimate 4.0 15.6
Settlement of liabilities during the year (10.6) (4.9)
Accretion expense 11.1 5.2
---------------------------------------------------------------------
Balance, end of year $ 177.3 $ 165.1
---------------------------------------------------------------------
---------------------------------------------------------------------

11. FINANCIAL INSTRUMENTS

The Trust is exposed to a number of financial risks that are part of
its normal course of business. The Trust has a risk management
program in place that includes financial instruments as disclosed in
this note. The objective of the risk management program is to
mitigate the Trust's exposure to the following financial risks:

Credit Risk
Most of the Trust's accounts receivable relate to oil and natural
gas sales and are exposed to typical industry credit risks. The
Trust manages this credit risk by entering into sales contracts
with only highly rated entities and reviewing its exposure to
individual entities on a regular basis. With respect to
counterparties to financial instruments the Trust partially
mitigates associated credit risk by limiting transactions to
counterparties with investment grade credit ratings.

Volatility of Oil and Natural Gas Prices
The Trust's operational results and financial condition, and
therefore the amount of distributions paid to unitholders are
dependent on the prices received for oil and natural gas
production. Oil and gas prices have fluctuated widely during
recent years and are determined by economic and in the case of oil
prices, political factors. Supply and demand factors, including
weather and general economic conditions as well as conditions in
other oil and natural gas regions impact prices. Any movement in
oil and natural gas prices could have an effect on the Trust's
financial condition and therefore on the distributions to
unitholders. ARC may manage the risk associated with changes in
commodity prices by entering into oil or natural gas price
derivative contracts. To the extent that ARC engages in risk
management activities related to commodity prices, it will be
subject to credit risks associated with counterparties with which
it contracts.

Variations in Interest Rates and Foreign Exchange Rates
Increases in interest rates could result in a significant increase
in the amount the Trust pays to service variable interest debt,
resulting in a decrease in distributions to unitholders. World oil
prices are quoted in U.S. dollars and the price received by
Canadian producers is therefore affected by the Canadian/U.S.
dollar exchange rate that may fluctuate over time. Variations in
the exchange rate of the Canadian dollar could have significant
positive or negative impact on future distributions. ARC has
initiated certain derivative contracts to attempt to mitigate
these risks. To the extent that ARC engages in risk management
activities related to foreign exchange rates, it will be subject
to credit risk associated with counterparties with which it
contracts. The increase in the exchange rate for the Canadian
dollar and future Canadian/U.S. exchange rates will impact future
distributions and the future value of the Trust's reserves as
determined by independent evaluators.

Financial Instruments
Financial instruments of the Trust carried on the consolidated
balance sheet consist mainly of cash and cash equivalents, accounts
receivable, reclamation funds, current liabilities, other long-term
liabilities, commodity and foreign currency contracts and long-term
debt. Except as noted below, as at December 31, 2006 and 2005, there
were no significant differences between the carrying value of these
financial instruments and their estimated fair value due to their
short-term nature.

The fair value of the US$224 million fixed rate senior secured notes
approximated CDN$257 million as at December 31, 2006 and will vary
with changes in interest rates (2005 - US$230 million outstanding
approximated CDN$269 million).

Derivative Contracts
Following is a summary of all derivative contracts in place as at
December 31, 2006 in order to mitigate the risks discussed above:

Financial WTI Crude Oil Contracts
Bought Sold
Volume Put Sold Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Jan 07 - Feb 07 Bought Put 1,000 62.50 - -
Jan 07 - Jun 07 Put Spread 1,000 75.00 62.70 -
Jan 07 - Jun 07 Put Spread 1,000 75.00 65.00 -
Jan 07 - Dec 07 Put Spread 1,000 75.00 60.00 -
Jan 07 - Dec 07 3 - Way Collar 2,500 65.00 52.50 80.00
Jan 07 - Dec 07 Put Spread 2,500 65.00 52.50 -
Jan 07 - Dec 09 3 - Way Collar 5,000 55.00 40.00 90.00
Jul 07 - Dec 07 Put Spread 1,000 65.00 55.00 -
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial AECO Natural Gas Contracts
Bought
Volume Put Sold Put Sold Call
Term Contract GJ/d CDN$/GJ CDN$/GJ CDN$/GJ
---------------------------------------------------------------------
Jan 07 - Mar 07 Collar 10,000 7.25 - 9.00
Jan 07 - Mar 07 Collar 10,000 7.50 - 9.50
Jan 07 - Mar 07 Collar 10,000 8.00 - 12.00
Jan 07 - Mar 07 Collar 20,000 8.50 - 12.35
Jan 07 - Mar 07 3 - Way Collar 10,000 8.00 5.50 11.90
Apr 07 - Oct 07 3 - Way Collar 10,000 7.25 5.25 9.00
Apr 07 - Oct 07 3 - Way Collar 10,000 7.50 5.50 9.50
Apr 07 - Oct 07 3 - Way Collar 30,000 7.00 5.00 8.65
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial NYMEX Natural Gas Contracts
Bought
Volume Put Sold Put Sold Call
Term Contract mmbtu/d US$/mmbtu US$/mmbtu US$/mmbtu
---------------------------------------------------------------------
Jan 07 - Mar 07 Collar 5,000 8.50 - 10.25
Jan 07 - Mar 07 Collar 10,000 8.25 - 10.00
Jan 07 - Mar 07 Collar 10,000 10.00 - 13.65
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial Natural Gas AECO (monthly) to NYMEX (last 3 day)
Basis Contracts

Volume Basis Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
Jan 07 - Mar 07 Swap 40,000 (1.3125)
Apr 07 - Oct 08 Swap 50,000 (1.1160)
Nov 08 - Oct 10 Swap 50,000 (1.0430)
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial Foreign Exchange Contracts(1)

Volume Bought
MM Swap Swap Put Sold Put
Term Contract US$ CDN$/US$ US$/CDN$ CDN$/US$ CDN$/US$
---------------------------------------------------------------------
USD Sales
Contracts
Jan 07 - Dec 07 Swap 192 1.1379 0.8788 - -

USD Option
Contracts
Jan 07 - Dec 07 Put
Spread 12 - - 1.125 1.100
Jan 07 - Dec 07 Put
Spread 12 - - 1.128 1.098
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Contracted volume is a total notional volume for the entire term.

Financial Electricity Contracts(2)

Volume Swap
Term Contract MWh CDN$/MWh
---------------------------------------------------------------------
Jan 07 - Dec 07 Swap 20.0 64.63
Jan 08 - Dec 08 Swap 15.0 60.17
Jan 09 - Dec 09 Swap 15.0 59.33
Jan 10 - Dec 10 Swap 5.0 63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Contracted volume is based on a 24/7 term.

Financial Interest Rate Contracts(3)
Fixed Spread
Principal Annual on 3 Mo.
Term Contract MM USD Rate (%) LIBOR
---------------------------------------------------------------------
Jan 07 - Apr 14 Swap 30.5 4.62 38.5 bps
Jan 07 - Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------
(3) Starting in 2009, the notional amount of the contracts decreases
annually until 2014. The Trust pays the floating interest rate
based on the three month LIBOR plus a spread and receives the
fixed interest rate.

The Trust has designated its fixed price electricity and interest
rate swap contracts as effective accounting hedges as at January 1,
2004. A realized gain of $3.4 million ($0.3 million gain in 2005) on
the electricity contract has been included in operating costs. The
fair value unrealized gain on the electricity contract of $7 million
has not been recorded on the consolidated balance sheet at
December 31, 2006 ($0.2 million loss in 2005). A realized loss of
$0.4 million for the year on the interest rate swap contracts has
been included in interest expense ($0.5 million gain in 2005). The
fair value unrealized loss on the two interest rate swap contracts of
$1.8 million has not been recorded on the consolidated balance sheet
at December 31, 2006 ($1 million loss in 2005).

None of the Trust's commodity and foreign currency contracts have
been designated as effective accounting hedges. Accordingly, all
commodity and foreign currency contracts have been accounted as
assets and liabilities in the consolidated balance sheet based on
their fair values.

The following table reconciles the movement in the fair value of the
Trust's financial commodity and foreign currency contracts that have
not been designated as effective accounting hedges:

2006 2005
---------------------------------------------------------------------
Fair value, beginning of year(1) $ (4.1) $ (4.1)
Fair value, end of year (8.7) (4.1)
---------------------------------------------------------------------
Change in fair value of contracts in
the year(1) (4.6) -
Realized gains (losses) in the year 29.3 (87.6)
---------------------------------------------------------------------
Gain (loss) on commodity and foreign
currency contracts(1) $ 24.7 $ (87.6)
---------------------------------------------------------------------
---------------------------------------------------------------------

Commodity and foreign currency contracts
asset $ 25.7 $ 3.1
Commodity and foreign currency contracts
liability $ (34.4) $ (7.2)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Excludes the fixed price electricity contract and interest rate
swap contracts that were accounted for as effective accounting
hedges.

The Trust recorded a net gain on commodity and foreign currency
contracts of $24.7 million in the statement of income for 2006
($87.6 million loss in 2005). This amount includes the realized and
unrealized gains and losses on derivative contracts that do not
qualify as effective accounting hedges. During the year, $4.6 million
in unrealized losses ($ nil in 2005) and $29.3 million in realized
cash gains ($87.6 million loss in 2005) on contracts was recognized
during the year.

12. GAIN (LOSS) ON FOREIGN EXCHANGE

The following is a summary of the total gain (loss) US$ denominated
transactions:

2006 2005
---------------------------------------------------------------------
Unrealized (loss) on US$ denominated debt $ (7.1) $ (4.2)
Realized gain on US$ denominated debt
repayments 2.6 10.5
---------------------------------------------------------------------
Total non-cash (loss) gain on US$
denominated transactions (4.5) 6.3
Realized cash gain on US$ denominated
transactions 0.3 0.1
---------------------------------------------------------------------
Total foreign exchange (loss) gain $ (4.2) $ 6.4
---------------------------------------------------------------------
---------------------------------------------------------------------

13. INCOME TAXES

The tax provision differs from the amount computed by applying the
combined Canadian federal and provincial statutory income tax rates
to income before future income tax recovery as follows:

2006 2005
---------------------------------------------------------------------
Income before future income tax expense
and recovery $ 379.6 $ 364.1
Canadian statutory rate 34.5% 37.6%
---------------------------------------------------------------------
Expected income tax expense at
statutory rates 130.9 137.0
Effect on income tax of:
Net income of the Trust (138.0) (111.7)
Effect of change in corporate tax rate (62.2) (4.9)
Resource allowance (10.7) (20.0)
Change in estimated pool balances (10.0) -
Unrealized loss (gain) on foreign exchange 1.2 (1.6)
Non-deductible crown charges 1.2 1.3
Other non-deductible items 0.5 1.5
---------------------------------------------------------------------
Future income tax (recovery) expense $ (87.1) $ 1.6
---------------------------------------------------------------------
---------------------------------------------------------------------

The net future income tax liability is comprised of the following:

2006 2005
---------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 509.8 $ 569.8
Long-term debt 4.0 -
Future tax assets:
Non-capital losses (5.3) (1.5)
Asset retirement obligations (52.1) (45.7)
Accrued long-term incentive compensation (7.7) -
Commodity and foreign currency contracts (2.5) (1.4)
Attributed Canadian royalty income (10.4) (5.3)
Cumulative eligible capital and deductible
share issue costs (1.6) -
---------------------------------------------------------------------
Net future income tax liability $ 434.2 $ 515.9
---------------------------------------------------------------------
---------------------------------------------------------------------

The petroleum and natural gas properties and facilities owned by the
Trust's subsidiaries have an approximate tax basis of $1,031 million
($788.4 million in 2005) available for future use as deductions from
taxable income. Included in this tax basis are estimated non-capital
loss carry forwards of $18.2 million ($13.1 million in 2005) that
expire in the years 2008 through 2026. The following is a summary of
the estimated Trust's subsidiaries' tax basis:

2006 2005
---------------------------------------------------------------------
Canadian oil and gas property expenses $ 200.1 $ 88.6
Canadian development expenses 285.9 201.3
Canadian exploration expenses 27.7 22.7
Undepreciated capital cost 389.0 352.2
Non-capital losses 18.2 13.1
Provincial tax pools 104.5 104.5
Other 5.6 6.0
---------------------------------------------------------------------
Estimated tax basis $ 1,031.0 $ 788.4
---------------------------------------------------------------------
---------------------------------------------------------------------

In addition to the above tax basis for the Trust's subsidiaries, the
Trust itself has an approximate tax basis of $545.1 million as at
December 31, 2006 ($555.4 million in 2005).

On October 31, 2006, the Federal Government announced a proposed
Trust taxation pertaining to taxation of distributions paid by
publicly traded income Trusts. Currently, distributions paid to
unitholders, other than returns of capital, are claimed as a
deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and is paid by the unitholders. The
proposals would result in a two-tiered tax structure whereby
distributions would first be subject to a 31.5 per cent tax at the
Trust level commencing in 2011 and then investors would be subject to
tax on the distribution as if it were a taxable dividend paid by a
taxable Canadian corporation. If enacted, the proposals would apply
to the Trust effective January 1, 2011. The Trust is currently
assessing various alternatives with respect to the potential
implications of the tax proposals; however, until the legislation is
enacted in final form, the Trust will not arrive at a final
conclusion with respect to future Trust structure and implications to
the Trust. As the tax proposals had not yet been substantively
enacted as of December 31, 2006, the consolidated financial
statements do not reflect the impact of the proposed taxation.

No current income taxes were paid or payable in 2006.

14. EXCHANGEABLE SHARES

The ARC Resources exchangeable shares ("ARL Exchangeable Shares")
were issued on January 31, 2001 at $11.36 per exchangeable share as
partial consideration for the Startech Energy Inc. acquisition. The
issue price of the exchangeable shares was determined based on the
weighted average trading price of Trust units preceding the date of
announcement of the acquisition. The ARL Exchangeable Shares had an
exchange ratio of 1:1 at the time of issuance.

The Trust is authorized to issue an unlimited number of ARL
Exchangeable Shares which can be converted (at the option of the
holder) into Trust units at any time. The number of Trust units
issuable upon conversion is based upon the exchange ratio in effect
at the conversion date. The exchange ratio is calculated monthly
based on the cash distribution paid divided by the ten day weighted
average unit price preceding the record date and multiplied by the
opening exchange ratio. The exchangeable shares are not eligible for
distributions and, in the event that they are not converted, any
outstanding shares are redeemable by the Trust for Trust units on
August 28, 2012. The ARL Exchangeable Shares are publicly traded.

ARL EXCHANGEABLE SHARES (thousands) 2006 2005
---------------------------------------------------------------------
Balance, beginning of year 1,595 1,784
Exchanged for Trust units (162) (189)
---------------------------------------------------------------------
Balance, end of year 1,433 1,595
Exchange ratio, end of year 2.01251 1.83996
---------------------------------------------------------------------
Trust units issuable upon conversion,
end of year 2,884 2,935
---------------------------------------------------------------------
---------------------------------------------------------------------

The non-controlling interest on the consolidated balance sheet
consists of the fair value of the exchangeable shares upon issuance
plus the accumulated earnings attributable to the non-controlling
interest. The net income attributable to the non-controlling interest
on the consolidated statement of income represents the cumulative
share of net income attributable to the non-controlling interest
based on the Trust units issuable for exchangeable shares in
proportion to total Trust units issued and issuable at each period
end.

Following is a summary of the non-controlling interest for 2006 and
2005:

2006 2005
---------------------------------------------------------------------
Non-controlling interest, beginning of year $ 37.5 $ 35.9
Reduction of book value for conversion to
Trust units (4.1) (4.0)
Current year net income attributable to
non-controlling interest 6.6 5.6
---------------------------------------------------------------------
Non-controlling interest, end of year $ 40.0 $ 37.5
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 27.3 $ 20.7
---------------------------------------------------------------------
---------------------------------------------------------------------

15. UNITHOLDERS' CAPITAL

The Trust is authorized to issue 650 million Trust units of which
204.3 million units were issued and outstanding as at December 31,
2006 (199.1 million as at December 31, 2005).

The Trust has in place a Distribution Reinvestment and Optional Cash
Payment Program ("DRIP") in conjunction with the Trusts' transfer
agent to provide the option for unitholders to reinvest cash
distributions into additional Trust units issued from treasury at a
five per cent discount to the prevailing market price with no
additional fees or commissions.

The Trust is an open ended mutual fund under which unitholders have
the right to request redemption directly from the Trust. Units
tendered by holders are subject to redemption under certain terms and
conditions including the determination of the redemption price at the
lower of the closing market price on the date units are tendered or
90 per cent of the weighted average trading price for the 10 day
trading period commencing on the tender date. Cash payments for units
tendered for redemption are limited to $100,000 per month with
redemption requests in excess of this amount eligible to receive a
note from ARC Resources Ltd. accruing interest at 4.5 per cent and
repayable within 20 years.

2006 2005
---------------------------------------------------------------------
Number Number
of Trust of Trust
Units Units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning
of year 199,104 2,230.8 185,822 1,926.4
Issued for cash 1 - 9,000 239.8
Issued on conversion of
ARL exchangeable shares
(Note 14) 310 4.1 333 4.0
Issued on exercise of
employee rights
(Note 18) 978 18.4 1,500 24.0
Distribution reinvestment
program 3,896 96.1 2,449 48.8
Trust unit issue costs - (0.2) - (12.2)
---------------------------------------------------------------------
Balance, end of year 204,289 2,349.2 199,104 2,230.8
---------------------------------------------------------------------
---------------------------------------------------------------------

16. DEFICIT

The deficit balance is composed of the following items:

2006 2005
---------------------------------------------------------------------
Accumulated earnings $ 1,695.8 $ 1,235.7
Accumulated cash distributions (2,159.0) (1,674.8)
---------------------------------------------------------------------
Deficit $ (463.2) $ (439.1)
---------------------------------------------------------------------
---------------------------------------------------------------------

During the year, presentation changes were made to combine the
previously reported Accumulated Earnings and Accumulated Cash
Distribution figures on the balance sheet into a single Deficit
balance. The Trust has historically paid cash distributions in excess
of accumulated earnings as cash distributions are based on cash flow
generated in the current period while accumulated earnings are based
on cash flow generated in the current period less a depletion,
depreciation, and accretion expense recorded on the original
property, plant, and equipment investment and other non-cash charges.

17. RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS

Cash distributions are calculated in accordance with the Trust
Indenture. To arrive at cash distributions, cash flow from operating
activities adjusted for changes in non-cash working capital and
expenditures on site restoration and reclamation, is reduced by
reclamation funds contributions including interest earned on the fund
and a portion of capital expenditures. The portion of cash flow
withheld to fund capital expenditures is at the discretion of the
Board of Directors.

2006 2005
---------------------------------------------------------------------
Cash flow from operating activities $ 734.0 $ 616.7
Change in non-cash working capital 16.0 17.9
Expenditures on site reclamation and
restoration 10.6 4.9
---------------------------------------------------------------------
Cash flow from operating activities after
the above adjustments 760.6 639.5
Deduct:
Cash withheld to fund current period
capital expenditures (263.2) (256.1)
Reclamation fund contributions and
interest earned on fund balances (13.2) (6.8)
---------------------------------------------------------------------
Cash distributions(1) 484.2 376.6
Accumulated cash distributions,
beginning of year 1,674.8 1,298.2
---------------------------------------------------------------------
Accumulated cash distributions,
end of year $ 2,159.0 $ 1,674.8
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash distributions per unit(2) $ 2.40 $ 1.99
Accumulated cash distributions per
unit, beginning of year 16.23 14.24
---------------------------------------------------------------------
Accumulated cash distributions per
unit, end of year $ 18.63 $ 16.23
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Cash distributions include non-cash amounts of $94.6 million
($58.3 million in 2005). These amounts relate to the distribution
reinvestment program.
(2) Cash distributions per trust unit reflect the sum of the per
trust unit amounts declared monthly to unitholders.

18. TRUST UNIT INCENTIVE RIGHTS PLAN

The Trust Unit Incentive Rights Plan (the "Rights Plan") was
established in 1999 and authorized the Trust to grant up to 8,000,000
rights to its employees, independent directors and long-term
consultants to purchase Trust units, of which 7,866,088 were granted
to December 31, 2006. The initial exercise price of rights granted
under the Rights Plan could not be less than the market price of the
trust units as at the date of grant and the maximum term of each
right was not to exceed ten years. In general, the rights have a five
year term and vest equally over three years commencing on the first
anniversary date of the grant. In addition, the exercise price of the
rights is to be adjusted downwards from time to time by the amount,
if any, that distributions to unitholders in any calendar quarter
exceeds 2.5 per cent (ten per cent annually) of the Trust's net book
value of property, plant and equipment (the "Excess Distribution"),
as determined by the Trust.

During the 2006 and 2005, the Trust did not grant any rights as the
Rights Plan was replaced with a Whole Unit Plan during 2004 (see Note
19). The existing Rights Plan will be in place until the remaining
0.4 million rights outstanding as at December 31, 2006 are exercised
or cancelled.

A summary of the changes in rights outstanding under the Rights Plan
is as follows:

Weighted Weighted
Number Average Number Average
of Rights Exercise of Rights Exercise
(thousands) Price ($) (thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of year 1,349 10.22 3,009 10.92
Granted - - - -
Exercised (978) 12.19 (1,500) 11.60
Cancelled (2) 10.07 (160) 10.99
---------------------------------------------------------------------
Balance before reduction
of exercise price 369 10.40 1,349 11.10
Reduction of exercise
price (1) - (0.93) - (0.88)
---------------------------------------------------------------------
Balance, end of year 369 9.47 1,349 10.22
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held at
the original grant price or a reduced exercise price.

A summary of the plan as at December 31, 2006 is as follows:

Exercise Number Number of
Price At Adjusted of Rights Remaining Rights
Grant Exercise Outstanding Contractual Life Exercisable
Date ($) Price ($) (thousands) of Rights (years) (thousands)
---------------------------------------------------------------------
12.58 9.11 32 0.4 32
12.29 9.40 328 1.4 328
15.42 13.27 9 2.2 3
---------------------------------------------------------------------
12.40 9.47 369 1.3 363
---------------------------------------------------------------------
---------------------------------------------------------------------

The Trust recorded compensation expense of $2.5 million for the year
($6.5 million in 2005) for the cost associated with the rights. Of
the 3,013,569 rights issued on or after January 1, 2003 that were
subject to recording compensation expense, 357,999 rights have been
cancelled and 2,318,222 rights have been exercised to December 31,
2006.

The Trust used the Black-Scholes option-pricing model to calculate
the estimated fair value of the outstanding rights issued on or after
January 1, 2003. Subsequent to the initial valuation, the Trust used
a binomial lattice model and observed immaterial valuation
differences. The following assumptions were used to arrive at the
estimate of fair value as at December 31, 2004:

---------------------------------------------------------------------
2004
---------------------------------------------------------------------
Expected annual right's exercise price reduction 0.72
Expected volatility 13.2%
Risk-free interest rate 3.7%
Expected life of option (years) 1.1
Expected forfeitures 0%
---------------------------------------------------------------------

Prior to 2004, the Trust recorded compensation expense on its Rights
Plan using the intrinsic method. In 2004, the Trust adopted the fair
value method. Use of the fair value prior to 2004 would have resulted
in an immaterial impact to the Trust.

The following table reconciles the movement in the contributed
surplus balance for 2006 and 2005:

---------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------
Balance, beginning of year $ 6.4 $ 6.5
Compensation expense 2.5 6.5
Net benefit on rights exercised(1) (6.5) (6.6)
---------------------------------------------------------------------
Balance, end of year $ 2.4 $ 6.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to unitholders' capital.

19. WHOLE TRUST UNIT INCENTIVE PLAN

In March 2004, the Board of Directors, upon recommendation of the
Compensation Committee, approved a new Whole Trust Unit Incentive
Plan (the "Whole Unit Plan") to replace the existing Trust Unit
Incentive Rights Plan for new awards granted subsequent to March 31,
2004. The new Whole Unit Plan will result in employees, officers and
directors (the "plan participants") receiving cash compensation in
relation to the value of a specified number of underlying notional
trust units. The Whole Unit Plan consists of Restricted Trust Units
("RTUs") for which the number of trust units is fixed and will vest
over a period of three years and Performance Trust Units ("PTUs") for
which the number of trust units is variable and will vest at the end
of three years.

Upon vesting, the plan participant receives a cash payment based on
the fair value of the underlying trust units plus notional accrued
distributions. The cash compensation issued upon vesting of the PTUs
is dependent upon the future performance of the Trust compared to its
peers based on a performance multiplier. The performance multiplier
is based on the percentile rank of the Trust's Total Unitholder
Return. The cash compensation issued upon vesting of the PTUs may
range from zero to two times the value of the PTUs originally
granted.

The fair value associated with the RTUs and PTUs is expensed in the
statement of income over the vesting period. As the value of the RTUs
and PTUs is dependent upon the trust unit price, the expense recorded
in the statement of income may fluctuate over time.

The Trust recorded compensation expense of $8.2 million and $1.1
million to general and administrative and operating expenses,
respectively, and capitalized $1.8 million to property, plant and
equipment in the twelve months ended December 31, 2006 for the
estimated cost of the plan ($8.8 million, $1.9 million, and $1.4
million for the twelve months ended December 31, 2005). The
compensation expense was based on the December 31, 2006 unit price of
$22.30 ($26.49 in 2005), accrued distributions, a performance
multiplier ranging from 1.9 to 2.0 for the various series (2.0 in
2005), and the number of units to be issued on maturity.

The following table summarizes the RTU and PTU movement for the
twelve months ended December 31, 2006 and 2005:

2006 2005
---------------------------------------------------------------------
Number of Number of Number of Number of
RTUs PTUs RTUs PTUs
(thousands) (thousands) (thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning
of year 479 391 224 128
Vested (180) - (78) -
Granted 373 303 367 305
Forfeited (24) (11) (34) (42)
---------------------------------------------------------------------
Balance, end of year 648 683 479 391
---------------------------------------------------------------------
---------------------------------------------------------------------

The following table reconciles the change in total accrued
compensation liability relating to the Whole Unit Plan:

2006 2005
---------------------------------------------------------------------
Balance, beginning of year $ 15.0 $ 2.9
Change in liabilities in the year
General and administrative expense 8.2 8.8
Operating expense 1.1 1.9
Property, plant and equipment 1.8 1.4
---------------------------------------------------------------------
Balance, end of year $ 26.1 $ 15.0
---------------------------------------------------------------------
Current portion of liability (Note 7) 11.5 3.6
---------------------------------------------------------------------
Long-term liability $ 14.6 $ 11.4
---------------------------------------------------------------------
---------------------------------------------------------------------

During the year $5.2 million in cash payments were made to employees
relating to the Whole Unit Plan ($1.6 million in 2005).

20. BASIC AND DILUTED PER TRUST UNIT CALCULATIONS

Net income per Trust unit has been determined based on the following:

Three months ended Twelve months ended
December 31 December 31
(thousands) 2006 2005 2006 2005
---------------------------------------------------------------------
Weighted average
trust units(1) 203,580 190,510 201,554 188,237
Trust units issuable on
conversion of exchangeable
shares(2) 2,884 2,935 2,884 2,935
Dilutive impact of rights(3) 323 925 711 1,372
Dilutive trust units and
exchangeable shares 206,787 194,370 205,149 192,544
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average Trust units exclude trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the period end exchange ratio.
(3) All outstanding rights were dilutive and therefore have been
included in the diluted unit calculation for both 2006 and 2005.

Basic net income per unit has been calculated based on net income
after non-controlling interest divided by weighted average trust
units. Diluted net income per unit has been calculated based on net
income before non-controlling interest divided by dilutive trust
units.

21. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at December 31, 2006:

---------------------------------------------------------------------
Payments Due By Period
---------------------------------------------------------------------
2008- 2010-
2007 2009 2011 Thereafter Total
---------------------------------------------------------------------
Debt repayments(1) 8.0 451.2 53.1 174.8 687.1
Interest payments(2) 11.3 21.5 18.1 20.8 71.7
Reclamation fund
contributions(3) 6.0 11.1 9.5 76.2 102.8
Purchase commitments 12.6 8.4 3.4 6.8 31.2
Operating leases 5.3 9.9 5.0 - 20.2
Derivative contract
premiums(4) 12.4 3.3 - - 15.7
Retention bonuses 1.0 - - - 1.0
---------------------------------------------------------------------
Total contractual
obligations 56.6 505.4 89.1 278.6 929.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property acquired in 2005.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.

The above noted derivative contract premiums are part of the Trust's
commitments related to its risk management program. In addition to
the above premiums, the Trust has commitments related to its risk
management program (see Note 11). As the premiums are part of the
underlying derivative contract, they have been recorded at fair
market value at December 31, 2006 on the balance sheet as part of
commodity and foreign currency contracts.

The Trust enters into commitments for capital expenditures in advance
of the expenditures being made. At a given point in time, it is
estimated that the Trust has committed to capital expenditures equal
to approximately one quarter of its capital budget by means of giving
the necessary authorizations to incur the capital in a future period.
The Trust's 2007 capital budget has been approved by the Board at
$360 million. This commitment has not been disclosed in the
commitment table as it is of a routine nature and is part of normal
course of operations for active oil and gas companies and trusts.

The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending
litigation will not have a material adverse impact on the Trust's
financial position or results of operations and therefore the
following table does not include any commitments for outstanding
litigation and claims.

The Trust has certain sales contracts with aggregators whereby the
price received by the Trust is dependent upon the contracts entered
into by the aggregator. This commitment has not been disclosed in the
commitment table as it is of a routine nature and is part of normal
course of operations.
>>

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5.4 billion. The
Trust currently has an interest in oil and gas production of approximately
63,000 barrels of oil equivalent per day from six core areas in western
Canada. The royalty trust structure allows net cash flow to be distributed to
unitholders in a tax efficient manner. ARC Energy Trust trades on the TSX
under the symbol AET.UN.

ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 2007 and beyond; the
sources, deployment and allocation of expected capital in 2007; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,
President and Chief Executive Officer