EXHIBIT 99.3
                                                                  ------------



        MANAGEMENT'S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005



<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's  discussion and analysis  ("MD&A")  should be read in conjunction
with the audited consolidated financial statements for the year ended December
31, 2005 and the audited  consolidated  financial  statements and MD&A for the
year ended  December 31, 2004 and MD&A for the three  quarters ended March 31,
2005, June 30, 2005 and September 30, 2005.

This MD&A is dated February 8, 2006.

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:


-------------------------------------------------------------------------------

 ($ thousands)                                                2005        2004
-------------------------------------------------------------------------------

Cash flow from operating activities                        616,711     446,418
  Changes in non-cash working capital                       17,919      (1,617)
  Expenditures on site reclamation and restoration           4,881       3,232

Cash flow from operations                                  639,511     448,033
-------------------------------------------------------------------------------


Management  uses certain key  performance  indicators  ("KPI's")  and industry
benchmarks such as operating netbacks  ("netbacks"),  total capitalization and
finding,  development and acquisition costs to analyze financial and operating
performance.  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.

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 2006 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.


                                     -1-
<PAGE>

HIGHLIGHTS

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------
(Cdn$ millions, except per unit and volume data)              2005       2004     % Change
-------------------------------------------------------------------------------------------
<S>                                                          <C>        <C>             <C>
Cash flow from operations                                    639.5      448.0           43
Cash flow from operations per unit (1)                        3.35       2.41           39
Net income                                                   356.9      241.7           48
Distributions per unit (4)                                    1.99       1.80           11
Payout ratio per cent (2)                                       59         74          (20)
-------------------------------------------------------------------------------------------
Total daily production (boe/d) (3)                           6,254      6,870           (1)
-------------------------------------------------------------------------------------------
</TABLE>

(1)  Per unit amounts are based on weighted  average units plus units issuable
     for exhangeable shares at year end.
(2)  Based on cash distributions divided by cash flow from operations.
(3)  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.
(4)  Based on  number of trust  units  outstanding  at each cash  distribution
     date.

CASH FLOW FROM OPERATIONS

Cash flow from  operations  increased  by 43 per cent in 2005 to $640  million
from $448 million in 2004.  This  increase was  primarily the result of higher
commodity prices. The cash flow from operations per unit increased 39 per cent
to $3.35  per unit  from  $2.41  per unit in 2004.  The 2005  cash  flow  from
operations  included a cash loss of $87.6  million on  commodity  and  foreign
currency  contracts  while 2004 cash flow  included a loss of $86.9 million on
commodity and foreign currency contracts.

The following table  summarizes the variances in cash flow from operations and
in cash flow from  operations  per unit  between  2004 and 2005.  It shows the
variance is due mainly to increased commodity pricing,  with some of the price
increase being paid out in increased royalties and a small decrease in revenue
because of the one per cent decrease in the volumes produced.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
                                                           ($ millions)  ($ per trust unit)   (% variance)
----------------------------------------------------------------------------------------------------------
<C>                                                           <C>                <C>
2004 CASH FLOW FROM OPERATIONS                                $  448.0           $   2.41
----------------------------------------------------------------------------------------------------------

Volume variance                                                  (12.2)             (0.07)            (3)
Price variance                                                   275.6               1.48             62
Cash losses on commodity and foreign currency contracts (1)       (0.6)             --                --
Royalties                                                        (58.3)             (0.31)           (13)
Expenses:
   Transportation                                                  0.5              --                --
   Operating                                                      (2.5)             (0.01)            (1)
   Cash G&A                                                       (6.0)             (0.03)            (1)
   Interest                                                       (3.6)             (0.02)            (1)
   Taxes                                                          (1.0)             (0.01)            --
   Realized foreign exchange gain                                 (2.2)             (0.01)            --
Other                                                              1.8               0.01             --
Weighted average trust units                                        --              (0.09)            (4)

2005 CASH FLOW FROM OPERATIONS                                $  639.5           $   3.35             39
----------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Represents  cash  losses on  commodity  and  foreign  currency  contracts
     including  cash  settlements  on  termination  of  commodity  and foreign
     currency contracts.

                                     -2-
<PAGE>

PRODUCTION

Production  volumes averaged 56,254 boe per day in 2005 compared to 56,870 boe
per day in 2004.  Production  from the Redwater and North Pembina Cardium Unit
("NPCU") acquisitions were included starting on December 16, 2005 (these areas
contributed  5,460  boe per day for the last 16 days of  December  2005).  The
Trust exited 2005 with average daily  production  for the month of December in
excess of 61,000 boe per day.

The Trust expects 2006 production to average 61,000 boe per day, an eight per
cent increase over 2005.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
PRODUCTION                                                                               2005             2004          % Change
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>              <C>                    <C>
Crude oil (bbl/d)                                                                      23,282           22,961                 1
Natural gas (mcf/d)                                                                   173,800          178,309                (3)
NGL (bbl/d)                                                                             4,005            4,191                (4)

Total production (boe/d) (1)                                                           56,254           56,870                (1)
---------------------------------------------------------------------------------------------------------------------------------
% Natural gas production                                                                   51               52
% Crude oil and liquids production                                                         49               48
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Reported  production  for a period may  include  minor  adjustments  from
     previous production periods.

The following table summarizes the Trust's production by core area:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
                                                           2005                                         2004
---------------------------------------------------------------------------------------------------------------------------------
                                          TOTAL         OIL      GAS (2)        NGL       Total        Oil        Gas        NGL
CORE AREA (1)                           (boe/d)      (bbl/d)    (mmcf/d)   (bbl/d)      (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
---------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>          <C>          <C>       <C>         <C>        <C>         <C>       <C>
Central AB                                8,041        1,364        30.2      1,641       9,295      2,003       32.6      1,856
Northern AB & BC                         18,286        6,026        65.3      1,381      19,026      5,733       71.1      1,441
Pembina & Redwater                        7,953        4,166        17.7        832       7,433      3,742       17.5        772
S.E. AB & S.W. Sask.                     11,298        1,499        58.7         15      10,871      1,658       55.2         14
S.E. Sask.                               10,676       10,227         1.9        136      10,245      9,825        1.9        108
---------------------------------------------------------------------------------------------------------------------------------
TOTAL                                    56,254       23,282       173.8      4,005      56,870     22,961      178.3      4,191
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Provincial  references:  AB is Alberta, BC is British Columbia,  Sask. is
     Saskatchewan,  S.E. is southeast,  S.W. is southwest. (2) Rounding of the
     gas conversion at 6:1 mmcf can result in totals not summing exactly.

<TABLE>
<CAPTION>
COMMODITY PRICES

---------------------------------------------------------------------------------------------------------------------------------
BENCHMARK PRICES                                                                         2005             2004          % Change
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>              <C>                 <C>
AECO gas ($/mcf) (1)                                                                     8.45             6.79                24
WTI oil (US$/bbl) (2)                                                                   56.61            41.43                37
US$/Cdn$ foreign exchange rate                                                           0.83             0.77                 8
WTI oil (Cdn$/bbl)                                                                      68.52            53.81                27
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Represents the AECO monthly posting.
(2)  WTI represents West Texas Intermediate posting as denominated in US$.

Oil and gas  prices  reached  historic  highs in  2005.  The  strength  of the
Canadian dollar served to partially offset the impact of higher US denominated
oil prices.  The Trust's oil production  consists  predominantly  of light and
medium  crude oil while heavy oil  accounts for less than five per cent of the
Trust's liquids  production.  Overall the price of WTI oil in Canadian dollars
increased by 27 per cent over the prior year to $68.52 versus $53.81 in 2004.

                                     -3-
<PAGE>

Alberta AECO Hub natural gas prices,  which are  commonly  used as an industry
reference,  averaged  $8.45 per mcf in 2005 compared to $6.79 per mcf in 2004.
ARC's realized gas price,  before  hedging,  increased by 32 per cent to $8.96
per mcf compared to $6.78 per mcf in 2004.  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  realized  $56.54 per boe in 2005, a 31 per
cent increase over the $43.13 per boe received prior to hedging in 2004.

The following is a summary of realized prices :

<TABLE>
<CAPTION>
ARC REALIZED PRICES
---------------------------------------------------------------------------------------------------------------------------------
                                                                                         2005             2004          % Change
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>              <C>                  <C>
Oil ($/bbl)                                                                             61.11            47.03                30
Natural gas ($/mcf)                                                                      8.96             6.78                32
NGL ($/bbl)                                                                             49.92            39.04                28
---------------------------------------------------------------------------------------------------------------------------------

Total commodity revenue before hedging ($/boe)                                          56.54            43.13                31
Other revenue ($/boe)                                                                    0.21             0.19                11

TOTAL REVENUE BEFORE HEDGING ($/boe)                                                    56.75            43.32                31
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>


REVENUE

Revenue increased to $1.2 billion in 2005, an increase of 29 per cent compared
to 2004 revenue of $902 million.  Significantly higher commodity prices caused
this higher revenue.

A breakdown of revenue is as follows:

<TABLE>
<CAPTION>
REVENUE
----------------------------------------------------------------------------------------------------------------------------------
($ thousands)                                                                            2005             2004          % Change
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>              <C>                    <C>
Oil revenue                                                                           519,272          395,203                31
Natural gas revenue                                                                   568,710          442,537                29
NGL revenue                                                                            72,973           59,886                22
----------------------------------------------------------------------------------------------------------------------------------

Total commodity revenue                                                             1,160,955          897,626                29
Other revenue                                                                           4,242            4,156                 2

TOTAL REVENUE                                                                       1,165,197          901,782                29
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


RISK MANAGEMENT

The Trust's risk  management  activities  are  conducted  by an internal  Risk
Management  Committee,  based upon guidelines  approved by the Board. The Risk
Management Committee has the following mandate:

   o protect unitholder return on investment;

   o provide for minimum monthly cash distributions to unitholders;

   o employ a portfolio approach to risk management by entering into a number
     of small positions that build upon each other;

   o participate in commodity price upturns to the greatest extent possible
     while limiting exposure to price downturns; and,

   o ensure profitability of specific oil and gas properties that are more
     sensitive to changes in market conditions.

The  Trust  realized  cash  hedging  losses  of  $87.6  million  for the  year
attributed primarily to capped contracts that expired on December 31, 2005. At
the date of this  MD&A the  Trust  had  upside  participation  for 2006 on all
produced volumes with the exception of those noted below,  with downside price
protection on 39 per cent of liquids production and 14 per cent of natural gas
production (26 per cent of produced boes).

                                     -4-
<PAGE>

The Trust continues to execute a risk management  strategy  focused on put and
put spread  structures to manage  commodity  prices and continues to use fixed
rate  swaps to manage  foreign  exchange  and  interest  rate  exposures.  The
purchase of a put involves paying a premium to limit the exposure to downturns
in commodity prices while  participating in commodity price  appreciation.  At
year end the Trust had bought puts with an average floor on oil  production of
US$52.68  per bbl and  Cdn$8.16  per GJ on natural gas. The Trust also entered
into sold put  transactions  that offset the cost of the bought put  premiums.
The $12.4  million  cost of the put  premiums  has been  incurred to protect a
portion of 2006 revenue.

In addition to the above  contracts,  the Trust  entered into  long-term  risk
management  structures to lock in returns on production  acquired  through the
Redwater and NPCU  acquisitions  announced in December 2005. ARC has protected
5,000  barrels  per day  through  2009 with a  three-way  collar by  partially
financing  the purchase of a US$55 floor with a sold US$40 put and US$90 call.
ARC  felt it  prudent  to sell the  out-of-the-money  put and call in order to
reduce  the  cost of the  US$55  floor  and  minimize  its  long-term  premium
commitments.  As a result,  ARC has US$55 price  protection (down to US$40) on
the acquired volumes costing an average of $1.9 million per year through 2009.
If oil trades  above US$90 in any one month,  ARC will be limited to US$90 for
that month,  if WTI falls below US$40,  ARC  receives  market price plus US$15
under the  three-way  collar.  For a complete  summary of the  Trust's oil and
natural gas hedges,  please  refer to "Hedging  Program"  under the  "Investor
Relations" section of the Trust's website at www.arcenergytrust.com.

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.


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 expense in the statement of income.

The Trust recorded a realized loss on commodity and foreign currency contracts
of $87.6  million in 2005,  which is virtually  the same amount as realized in
2004.

The  following  is a summary  of the gain  (loss)  on  commodity  and  foreign
currency contracts for 2005:

<TABLE>
<CAPTION>
COMMODITY AND FOREIGN CURRENCY CONTRACTS
---------------------------------------------------------------------------------------------------
                                CRUDE OIL &       NATURAL       FOREIGN         2005          2004
($ thousands)                       LIQUIDS           GAS      CURRENCY        TOTAL         Total
---------------------------------------------------------------------------------------------------
<S>                                 <C>           <C>             <C>        <C>           <C>
Realized cash (loss) gain
   on contracts (1)                 (75,816)      (12,491)          749      (87,558)      (86,909)
Non-cash gain on contracts               --            --            --           --         4,883
Non-cash amortization of
   opening deferred hedge loss           --            --            --           --       (14,575)
Unrealized (loss) gain on
   contracts, change in
   fair value (2)                    16,465       (17,531)        1,066           --        10,533
---------------------------------------------------------------------------------------------------

TOTAL GAIN (LOSS) ON
   COMMODITY AND FOREIGN
   CURRENCY CONTRACTS               (59,351)      (30,022)        1,815      (87,558)      (86,068)
---------------------------------------------------------------------------------------------------
</TABLE>
(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.


                                     -5-
<PAGE>

OPERATING NETBACKS

The Trust's operating netback, prior to realized hedging losses,  increased 37
per cent to $37.66 per boe in 2005  compared  to $27.39  per boe in 2004.  The
increase in netbacks in 2005 is due to higher commodity prices.

The netback was reduced by realized  losses on commodity and foreign  currency
contracts  of $4.26 per boe for 2005,  very similar to losses of $3.94 per boe
in 2004.

<TABLE>
<CAPTION>
The components of operating netbacks are shown below:

---------------------------------------------------------------------------------------
                                                                       2005       2004
                                        Oil       Gas        NGL      TOTAL      Total
NETBACK                              ($/bbl)   ($/mcf)    ($/bbl)    ($/boe)    ($/boe)
---------------------------------------------------------------------------------------
<S>                                   <C>        <C>       <C>        <C>        <C>
Weighted average sales price          61.11      8.96      49.91      56.54      43.13
Other revenue                            --        --         --       0.21       0.19
---------------------------------------------------------------------------------------

Total revenue                         61.11      8.96      49.91      56.75      43.32
Royalties                            (11.58)    (1.85)    (13.18)    (11.46)     (8.51)
Transportation                        (0.13)    (0.21)        --      (0.70)     (0.71)
Operating costs (1)                   (8.62)    (0.98)     (4.69)     (6.93)     (6.71)
---------------------------------------------------------------------------------------

Netback prior to hedging              40.78      5.92      32.04      37.66      27.39
Realized loss on commodity and
   foreign currency contracts         (8.83)    (0.20)        --      (4.26)     (3.94)
---------------------------------------------------------------------------------------

Netback after hedging                 31.95      5.72      32.04      33.40      23.45
---------------------------------------------------------------------------------------
</TABLE>

(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, natural gas and natural gas liquids production.

Royalties  increased  to $11.46 per boe in 2005  compared  to $8.51 per boe in
2004,  up 35 per cent as a result of higher  commodity  prices.  Royalties are
calculated   and  paid  based  on   commodity   revenue   net  of   associated
transportation  costs  and  before  any  commodity  hedging  gains or  losses.
Royalties   as  a  percentage   of   pre-hedged   commodity   revenue  net  of
transportation costs remained unchanged at approximately 20 per cent.

Operating costs, net of processing income,  remained relatively  consistent at
$142.2 million in 2005 compared to $139.7 million in 2004. Operating costs per
boe  increased  three per cent to $6.93 per boe in 2005  compared to $6.71 per
boe  in  2004.   The  higher  costs  of  services   throughout  the  industry,
particularly  for service rigs,  trucking costs and mechanical  services,  has
caused the increase in operating costs.

In 2006 it is expected that base  operating  costs (before  Redwater and NPCU)
will  increase  over 10 per cent to $7.70 per boe.  With the  addition  of the
higher  cost  Redwater  and  NPCU  properties  it is  estimated  that  average
operating costs will increase to $8.65 per boe in 2006.


GENERAL AND ADMINISTRATIVE EXPENSES AND TRUST UNIT INCENTIVE COMPENSATION

Cash general and administrative  expenses ("G&A"),  net of overhead recoveries
on operated  properties,  increased to $27.4  million  ($1.34 per boe) in 2005
from $21.4 million ($1.03 per boe) in 2004.  Increases in cash G&A expenses in
total  and per boe were the  result  of the  increasing  costs to  manage  the
business  associated with increased  staff levels and increased  compensation.
Due to  unprecedented  levels of  activity  for ARC and for the  industry as a
whole in 2005, the costs  associated with hiring,  compensating  and retaining
employees and consultants has risen. It is essential for the Trust to maintain
competitive  compensation  levels to ensure  that we  continue  to attract and
retain the most qualified individuals.


                                     -6-
<PAGE>

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

G&A AND TRUST UNIT INCENTIVE COMPENSATION EXPENSE
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------
($ thousands except per boe)                                 2005       2004   % Change
----------------------------------------------------------------------------------------
<S>                                                        <C>        <C>            <C>
G&A expenses                                               35,044     30,733         14
Whole Unit Plan compensation expense (1)                    1,062         --        100
Operating recoveries                                       (8,659)    (9,307)        (7)
----------------------------------------------------------------------------------------

Cash G&A expenses                                          27,447     21,426         28
Accrued compensation - Rights Plan                          6,525      5,171         26
Accrued compensation - Whole Unit Plan                      8,774      2,915        201
----------------------------------------------------------------------------------------

Total G&A and trust unit incentive compensation expense    42,746     29,512         45

Cash G&A expenses per boe                                    1.34       1.03         30
Total G&A and trust unit incentive
   compensation expense per boe                              2.08       1.42         46
----------------------------------------------------------------------------------------
</TABLE>

(1)  Plan started in 2004 with the first cash payment made in April 2005.

A non-cash trust unit incentive  compensation expense ("non-cash  compensation
expense") of $15.3  million  ($0.74 per boe) was recorded in 2005  compared to
$8.1  million  ($0.39  per boe) in  2004.  This  non-cash  amount  relates  to
estimated  costs of the Trust Unit Incentive  Rights Plan ("Rights  Plan") and
the Whole Trust Unit  Incentive  Plan to December  31, 2005 and  reflects  the
strong market performance of ARC's units during the year.


RIGHTS PLAN

The Rights Plan provided  employees,  officers and  independent  directors the
right to purchase  units at a specified  price.  In general,  the rights had a
five year term and vested 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. The number of rights  outstanding  declined
by 1.7 million in the year from exercises or cancellations, to end the year at
1.3 million outstanding.

For the year ended December 31, 2005, the compensation  expense for the rights
plan  based on the fair  value  calculation  resulted  in an  expense  of $6.5
million compared to $5.2 million in 2004.


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. The PTU grant is adjusted by a
performance multiplier.  The performance multiplier is based on the percentile
rank of the Trust's total unitholder return,  which is the sum of the increase
in market price of the units over the period plus the amount of  distributions
over the period,  compared to its peers. The performance  multiplier can range
from zero to two.

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.


                                     -7-
<PAGE>

The  following  table  shows  the  changes  during  the  year of RTUs and PTUs
outstanding:

--------------------------------------------------------------------------------

(in thousands of units)                         number of RTUs   number of PTUs
--------------------------------------------------------------------------------

Balance, beginning of year                                 225              128
  Vested                                                   (79)              --
  Granted                                                  367              305
  Forfeited                                                (34)             (42)
--------------------------------------------------------------------------------

Balance, end of year                                       479              391
--------------------------------------------------------------------------------


Under the Whole Unit Plan $13.6  million  was paid or accrued  during the year
versus $2.9 million in 2004.  The large  increase in the accrued  value of the
RTUs and PTUs  outstanding is attributed to the  considerable  increase in the
Trust's  unit  value  in the  market,  and  the  increase  in the  performance
multiplier on the PTUs to two reflecting  ARC's top quartile  returns compared
to other midsized oil and gas producers.

The Trust expects 2006 G&A costs,  excluding  non-cash G&A associated with the
Trust's Rights Plan and Whole Unit Plan, to be approximately $1.70 per boe. In
addition,  the Trust expects 2006 non-cash G&A of approximately  $0.65 per boe
for the non-cash trust unit incentive compensation expense associated with the
Rights  Plan and Whole Unit  Plan.  The  increasing  G&A costs in 2006 are the
result of higher  compensation  levels  associated  with hiring and  retaining
qualified employees and consultants in a competitive environment.


INTEREST EXPENSE

Interest  expense  increased  to $16.9  million in 2005 from $13.3  million in
2004.  The increase is attributed to increased  interest rates and to a higher
average  debt  balance in 2005  compared  to 2004 as a result of  acquisitions
funded by debt.  Also  during  the year the  Trust  paid out an 8.05 per cent,
US$21 million note and refinanced it at a lower interest rate. The amount paid
to settle the note early was  Cdn$1.3  million  and was  included  as interest
expense.

The following is a summary of the debt balance and interest expense:

INTEREST EXPENSE
--------------------------------------------------------------------------------
($ thousands)                                        2005       2004   % Change
--------------------------------------------------------------------------------
Year end debt balance (1)                         526,636    220,549        139
   Fixed rate debt                                268,156    220,259
   Floating rate debt                             258,480        290
--------------------------------------------------------------------------------

Interest expense before interest rate swaps (2)    17,420     14,675         19
Gain on interest rate hedge                          (474)    (1,355)

Net interest expense                               16,946     13,320         27
--------------------------------------------------------------------------------

(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 gain of $6.4 million ($0.31 per boe) on foreign  exchange
transactions  compared  to a gain of $20.7  million  ($1.00  per boe) in 2004.
These amounts include both realized and unrealized  foreign exchange gains and
losses. Unrealized foreign exchange gains and losses are due to revaluation of
US 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 US  denominated  transactions  such as
interest payments, debt repayments and hedging settlements.


                                     -8-
<PAGE>

TAXES

Capital  taxes paid or payable by ARC,  based on debt and equity levels at the
end of the year,  amounted to $3.9 million in 2005 compared to $2.8 million in
2004.  The increase in 2005 capital taxes was attributed to the higher taxable
capital base as a result of asset acquisitions, partially offset by a decrease
in the capital tax rate, as well as a $0.9 million reassessment on prior years
tax return  filings by Star Oil & Gas Ltd.  ("Star"),  which ARC  purchased in
2003.

Corporate  acquisitions  completed in 2005  resulted in the Trust  recording a
future income tax liability of $213.8  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.

In the  Trust's  structure,  payments  are made  between  ARC  Resources  Ltd.
("ARL"),  the operating  subsidiary of the Trust, and the Trust,  transferring
both income and future tax liability to the unitholders.  At the current time,
ARC does not anticipate any cash taxes will be paid by ARL.


DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION

The depletion,  depreciation  and accretion  ("DD&A") rate increased to $12.88
per boe in 2005 from  $11.51 per boe in 2004.  The higher  DD&A rate is due to
the Redwater and NPCU property  acquisition  in the fourth quarter of 2005 for
which the Trust  recorded  a higher  proportionate  cost per  barrel of proved
reserves of the acquired  properties  compared to the existing ARC properties.
In  addition,  the higher  asset  retirement  obligation  recorded in 2005 has
resulted in higher accretion expense in 2005.

A breakdown of the DD&A rate is a follows:

DD&A RATE
------------------------------------------------------------------------------
($ thousands except per boe amounts)                 2005      2004  % Change
------------------------------------------------------------------------------
Depletion of oil & gas assets (1)                 259,308   235,094        10
Accretion of asset retirement obligation (2)        5,207     4,580        14
------------------------------------------------------------------------------

Total DD&A                                        264,515   239,674        10
DD&A rate per boe                                   12.88     11.51        12
------------------------------------------------------------------------------

(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  $61.9  million  relating  to the
capitalized portion of the asset retirement obligation as at December 31, 2005
($42.3 million as at December 31, 2004), 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, 2005.


CAPITAL EXPENDITURES AND NET ACQUISITIONS

Total capital expenditures,  excluding acquisitions and dispositions,  totaled
$268.8  million in 2005  compared to $193.8  million in 2004.  This amount was
incurred on drilling and completions,  geological,  geophysical and facilities
expenditures,  as ARC  continues  to develop its asset base.  The  significant
increase  in 2005  capital  expenditures  is due to the  costs of the  capital
development program needed to replace production in the year.

During the year, the Trust drilled 250 gross wells (220 net wells) on operated
properties;  consisting  of 68 gross oil wells and 180 gross natural gas wells
most of which were  shallow gas wells,  and two dry holes for a total  success
rate of 99 per cent in 2005. In addition,  the Trust participated in 402 gross
wells drilled by other operators.

In addition  to capital  expenditures  on  development  activities,  the Trust
completed net property  acquisitions of $91.3 million in 2005.  Major property
acquisitions were in the following areas:  Berrymoor and Buck Creek in Alberta
and Weirhill and Steelman in Saskatchewan.


                                     -9-
<PAGE>

The Trust also completed a number of corporate  acquisitions including Romulus
Exploration  Inc.  in June 2005 for total  consideration  of $42  million  and
companies  holding the Redwater and NPCU properties in December 2005 for total
consideration of $463 million.

Capital expenditures on development activities and acquisitions resulted in an
increase in proved plus  probable oil and gas reserves  from 244 mmboe at year
end 2004 to 287 mmboe at year end 2005.

Approximately  95 per cent of the $269  million  capital  program was financed
from cash flow from  operations  in 2005 versus 57 per cent in 2004.  Property
and corporate  acquisitions  were financed  through a combination  of debt and
equity.

A breakdown of capital expenditures and net acquisitions is shown below:

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES
-----------------------------------------------------------------------------------------------------------
($ thousands)                                                                 2005        2004    % Change
-----------------------------------------------------------------------------------------------------------
<S>                                                                          <C>         <C>            <C>
Geological and geophysical                                                   9,219       5,388          71
Drilling and completions                                                   200,873     144,487          39
Plant and facilities                                                        55,032      41,089          34
Other capital                                                                3,710       2,820          32

Total capital expenditures                                                 268,834     193,784          39
-----------------------------------------------------------------------------------------------------------
Producing property acquisitions (1)                                        111,324        (529)
Producing property dispositions (1)                                        (20,038)    (57,691)
Corporate acquisitions (2)                                                 504,996      72,009

Total capital expenditures and net acquisitions                            865,116     207,573         318
-----------------------------------------------------------------------------------------------------------
Total capital expenditures and net acquisitions financed with cash flow    256,104     110,846
Total capital expenditures and net acquisitions financed with debt         609,012      96,727
-----------------------------------------------------------------------------------------------------------
</TABLE>

(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.

ARC expects to  undertake  significant  development  activities  again in 2006
resulting in a $340 million capital budget.  New activities  include  spending
$25 million on a commercial  scale  Natural Gas from Coal ("NGC")  project and
incurring  a $17  million  increase  in capital  allocated  to  moderate  risk
exploration.


ASSET RETIREMENT OBLIGATION AND RECLAMATION FUND

At December 31, 2005,  the Trust has recorded an Asset  Retirement  Obligation
("ARO") of $165.1  million  ($73  million  at  December  31,  2004) for future
abandonment  and reclamation of the Trust's  properties.  The ARO increased by
$76.2  million  during 2005 as a result of additional  liabilities  associated
with the  acquisitions  of Redwater and NPCU,  and the wells  drilled in 2005.
Also the ARO  increased  because the  inflation  factor used to calculate  the
future  retirement  obligation was increased from 1.5 per cent to two per cent
in 2005.  The ARO further  increased by $5.2 million for accretion  expense in
2005 ($4.6  million in 2004) and was reduced by $4.9 million  ($3.2 million in
2004) 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.

ARC contributed $6 million cash to its reclamation fund in 2005 ($6 million in
2004) and earned  interest of $0.8 million  ($1.2 million in 2004) on the fund
balance.  The  fund  balance  was  reduced  by $4.6  million  for  cash-funded
abandonment  expenditures in 2005 ($3.1 million in 2004). This fund,  invested
in money market instruments,  is established to provide for future abandonment
and  reclamation  liabilities.  Future  contributions  are  currently  set  at
approximately  $6 million  per year over 20 years in order to provide  for the
total  estimated  future  abandonment  and  reclamation  costs  that are to be
incurred over the next 61 years. In addition, as a result of the Redwater/NPCU
acquisition  the  Trust  has  committed  to  additional  yearly  contributions
starting at $6.1 million per year  (resulting in a total 2006  contribution of
$12.1 million). Currently, the fund balance stands at $23.5 million.


                                     -10-
<PAGE>

CAPITAL STRUCTURE

A breakdown of the Trust's capital structure is as follows:

<TABLE>
<CAPTION>
CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY
-----------------------------------------------------------------------------------------------
($ thousands except per unit and per cent amounts)                           2005         2004
-----------------------------------------------------------------------------------------------
<S>                                                                       <C>              <C>
Revolving credit facilities                                               258,480          290
Senior secured notes                                                      268,156      220,259
Working capital deficit excluding short-term debt (1)                      51,450       44,293
-----------------------------------------------------------------------------------------------

Net debt obligations                                                      578,086      264,842
Units outstanding and issuable for exchangeable shares (thousands)        202,039      188,804
Market price per unit at end of year                                        26.49        17.90
Market value of units and exchangeable shares                           5,352,013    3,379,592
Total capitalization (2)                                                5,930,099    3,644,434
-----------------------------------------------------------------------------------------------

Net debt as a percentage of total capitalization                             9.7%         7.3%
Net debt obligations                                                      578,086      264,842
Cash flow from operations                                                 639,511      448,033
Net debt to cash flow                                                         0.9          0.6
-----------------------------------------------------------------------------------------------
</TABLE>

(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.

On December 15, 2005 the Trust repaid the remaining US$21 million  outstanding
on its 8.05 per cent senior secured notes  originally  issued in November 2000
pursuant  to an  Uncommitted  Master  Shelf  Agreement.  The Trust paid US$1.1
million  in order to  retire  this note  based  upon the  discounted  value of
interest  payable at the 8.05 per cent rate and current market interest rates.
Concurrent  with the  repayment,  US$75  million of senior  secured notes were
issued under an Amended  Uncommitted Master Shelf Agreement.  This note pays a
quarterly  coupon  of 5.42 per cent per  annum and  requires  equal  principal
payments of US$9,375,000 over an eight year period commencing in 2010.

In  conjunction  with the December  acquisition  of Redwater and the NPCU, the
Trust increased its syndicated credit facility to $700 million and its working
capital  facility to $25 million  resulting in a total  borrowing base of $950
million.  The increase in the  borrowing  base did not impact any key terms in
the credit  facility  such as security or  covenants.  The next annual  credit
review  will occur  during  the first  quarter of 2006 at which time the Trust
will  reduce  its  available  credit  facilities  to  reduce  fees  on  credit
facilities it does not expect to utilize in the near future.

The Trust  intends to finance its $340 million 2006 capital  program with cash
flow  and the  proceeds  of the  distribution  reinvestment  program  with any
remainder being financed with debt.


                                     -11-
<PAGE>

UNITHOLDERS' EQUITY

At December  31,  2005,  there were 199.1  million  trust units issued and 2.9
million units issuable for exchangeable shares, a seven per cent increase from
the  185.8  million  units  issued  and  three  million  units   issuable  for
exchangeable shares at December 31, 2004.

The  increase  in the  number  of units  outstanding  is  attributable  to the
following:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
                                                                 Average Price       Proceeds   # of Units
                                                                    (per unit)   ($ millions)   (millions)
----------------------------------------------------------------------------------------------------------
<S>                                                                <C>                 <C>         <C>
Units Issued at December 31, 2004                                          --            --        185.8
  December 2005 equity offering                                    $    26.65          239.9         9.0
  Units issued from treasury pursuant to DRIP program              $    19.92           48.8         2.5
  Units issued on exercise of employee rights                      $    16.03           24.1         1.5
  Units issued pursuant to exchange of ARL exchangeable shares     $    11.04            4.0         0.3
----------------------------------------------------------------------------------------------------------

UNITS ISSUED AT DECEMBER 31, 2005                                                                  199.1
----------------------------------------------------------------------------------------------------------
</TABLE>

The Trust issued nine million units at $26.65 in December 2005 for proceeds of
$239.9  million  less  underwriter's  fees of $12 million for net  proceeds of
$227.9  million.  Proceeds from the offering were used to partially repay debt
associated with the Redwater and NPCU acquisitions.

The Trust made its final issuance of rights under the Rights Plan during 2004.
There will be no future  issuances  of rights as the rights plan was  replaced
with a new Whole Unit Plan in 2004. The existing  rights plan will be in place
until the remaining 1.3 million rights outstanding as of December 31, 2005 are
exercised or cancelled. These rights have an adjusted exercise price of $10.22
and have an  average  remaining  contractual  life of 3.3 years and  expire at
various  dates to March 22, 2009.  Of the rights  outstanding  at December 31,
2005, a total of 0.6 million were exercisable at that time.

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.


CASH DISTRIBUTIONS

ARC declared cash distributions of $377 million ($1.99 per unit), representing
59 per cent of 2005 cash flow from operations  compared to cash  distributions
of $330 million ($1.80 per unit),  representing  74 per cent of cash flow from
operations in 2004. The remaining 41 per cent of 2005 cash flow ($263 million)
was used to fund 95 per  cent of  ARC's  2005  capital  expenditures  and make
contributions, including interest, to the reclamation fund ($6.8 million). 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.

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

<TABLE>
<CAPTION>
CASH FLOW AND DISTRIBUTIONS                             ($ millions)                 ($ per unit)
--------------------------------------------------------------------------------------------------------
                                                2005     2004    % Change       2005    2004   % Change
--------------------------------------------------------------------------------------------------------
<S>                                            <C>      <C>            <C>      <C>     <C>          <C>
Cash flow from operations                      639.5    448.0          43       3.35    2.41         39
Reclamation fund contributions (1)              (6.8)    (7.2)         (6)     (0.04)  (0.04)        --
Capital expenditures funded with cash flow    (256.1)  (110.8)        131      (1.34)  (0.60)       123
Other (2)                                         --       --          --       0.02    0.03        (33)
--------------------------------------------------------------------------------------------------------

Cash distributions                             376.6    330.0          14       1.99    1.80         11
--------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Includes  interest income earned on the reclamation  fund balance that is
     retained in the reclamation fund.
(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.


                                     -12-
<PAGE>

Monthly  cash  distributions  for the first  quarter  of 2006 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

<TABLE>
<CAPTION>
The following table presents cash distributions paid in each calendar period.

-------------------------------------------------------------------------------------------------
                                                                    Taxable         Return of
Calendar Year                                 Distributions (1)     Portion           Capital
-------------------------------------------------------------------------------------------------
<S>                                            <C>                     <C>               <C>
2006 YTD (2)                                   0.40                    0.39 (2)          0.01 (2)
2005                                           1.94                    1.90 (3)          0.04 (3)
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                                 $  16.43                $   9.73           $  6.70
-------------------------------------------------------------------------------------------------
</TABLE>

(1)  Based on cash distributions paid in the calendar year.
(2)  Based on cash distributions paid in 2006 up to and including February 15,
     2006 and estimated taxable portion of 2006 distributions of 98 per cent.
(3)  Based on taxable portion of 2005 distributions of 98 per cent.


2005 MONTHLY CASH DISTRIBUTIONS

<TABLE>
<CAPTION>
Actual  cash  distributions  paid along  with  relevant  payment  dates are as
follows:

-----------------------------------------------------------------------------------------------------------
                                               Distribution               Total      Taxable     Return of
Ex-Distribution Date    Record Date            Payment Date        Distribution      Portion       Capital
-----------------------------------------------------------------------------------------------------------
<S>                     <C>                    <C>                         <C>        <C>           <C>
December 29, 2004       December 31, 2004      January 17, 2005            0.15       0.1470        0.0030
January 27, 2005        January 31, 2005       February 15, 2005           0.15       0.1470        0.0030
February 24, 2005       February 28, 2005      March 15, 2005              0.15       0.1470        0.0030
March 29, 2005          March 31, 2005         April 15, 2005              0.15       0.1470        0.0030
April 27, 2005          April 30, 2005         May 16, 2005                0.15       0.1470        0.0030
May 27, 2005            May 31, 2005           June 15, 2005               0.15       0.1470        0.0030
June 28, 2005           June 30, 2005          July 15, 2005               0.15       0.1470        0.0030
July 27, 2005           July 31, 2005          August 15, 2005             0.15       0.1470        0.0030
August 28, 2005         August 31, 2005        September 15, 2005          0.17       0.1666        0.0034
September 28, 2005      September 30, 2005     October 17, 2005            0.17       0.1666        0.0034
October 27, 2005        October 31, 2005       November 15, 2005           0.20       0.1960        0.0040
November 28, 2005       November 30, 2005      December 15, 2005           0.20       0.1960        0.0040

TOTAL 2005                                                                 1.94       1.9012        0.0388
-----------------------------------------------------------------------------------------------------------
</TABLE>

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 a more detailed breakdown,  please visit
our website at www.arcenergytrust.com.


                                     -13-
<PAGE>

For 2005,  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).
The  increase in the taxable  portion of  distributions  to 98 per cent is the
result of increasing  commodity prices and in turn increasing cash flow of the
Trust.

The  exchangeable  shares of ARL, a  corporate  subsidiary  of the Trust,  may
provide  a more  tax-effective  basis for  investment  in the  Trust.  The ARL
exchangeable  shares  are  traded on the TSX under  the  symbol  "ARX" and are
convertible  into units, at the option of the  shareholder,  based on the then
current exchange ratio.  Exchangeable shareholders are not eligible to receive
monthly cash distributions,  however the exchange ratio increases on a monthly
basis by an amount equal to the current month's unit  distribution  multiplied
by the then current  exchange ratio and divided by the 10 day weighted average
trading  price of the units at the end of each month.  The gain  realized as a
result  of the  monthly  increase  in the  exchange  ratio is  taxed,  in most
circumstances,  as a capital gain rather than income and is therefore  subject
to a lower  effective  tax rate.  Tax on the  exchangeable  shares is deferred
until the exchangeable share is sold or converted into a unit.


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.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                    Payments Due by Period
($ millions)                           2006     2007-2008    2009-2010    Thereafter      Total
-----------------------------------------------------------------------------------------------
<S>                                    <C>          <C>           <C>          <C>        <C>
Debt repayments                          --         279.4         49.2         198.0      526.6
Reclamation fund contributions (1)      6.1          11.8         10.2          80.9      109.0
Purchase commitments                    2.4           3.4          3.2           8.0       17.0
Operating leases                        4.1           8.1          7.3            --       19.5
Derivative contract premiums (2)       12.4            --           --            --       12.4
Retention bonuses                       1.0           1.0           --            --        2.0

TOTAL CONTRACTUAL OBLIGATIONS          26.0         303.7         69.9         286.9      686.5
-----------------------------------------------------------------------------------------------
</TABLE>
(1)  Contribution commitments to a restricted reclamation fund associated with
     the Redwater property acquired in the Redwater and NPCU acquisition
(2)  Fixed  premiums  to be  paid  in  future  periods  on  certain  commodity
     derivative contracts.

The Trust enters into  commitments for capital  expenditures in advance of the
expenditures  being made. At any given point in time, it is estimated that the
Trust  has  committed  to   approximately   $40  to  $60  million  of  capital
expenditures  by means of giving  the  necessary  authorizations  to incur the
capital in a future  period.  This  commitment  has not been  disclosed in the
above referenced  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 has  certain  sales  contracts  with  aggregators  whereby the price
received by the Trust is  dependent  upon the  contracts  entered  into by the
aggregator.

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.


OFF BALANCE SHEET ARRANGEMENTS

The Trust has certain  lease  agreements  that are entered  into in the normal
course of operations.  All leases are 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,  2005.  The  total
obligation for future lease  payments under all operating  leases is disclosed
in the "Commitments and Contingencies" section of this MD&A.

The Trust entered into  agreements  to pay premiums  pursuant to certain crude
oil derivative put contracts.  Premiums of approximately $12.4 million will be
paid in 2006 for the put  contracts  in place at year end. As the premiums are
part of the underlying  derivative  contract,  they have been recorded at fair
market value at December 31, 2005 on the balance sheet.  The total  obligation
for  future   premium   payments  is   disclosed  in  the   "Commitments   and
Contingencies" section of this MD&A.


                                     -14-
<PAGE>

FINANCIAL REPORTING UPDATE

The following new standard has been reviewed by the Trust during 2005:

     Financial  Instruments  -  Recognition  and  Measurement - On January 27,
     2005,  the  Accounting  Standard's  Board  ("AcSB")  issued CICA Handbook
     section 3855 "Financial Instruments - Recognition and Measurement",  CICA
     Handbook  section 1530  "Comprehensive  Income" and CICA Handbook section
     3865 "Hedges" that deal with the recognition and measurement of financial
     instruments 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 future  periods  and the
     resulting impact will be assessed at that time.


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:

     a)  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;

     b)  estimated capital expenditures on projects that are in progress;

     c)  estimated  depletion,  depreciation  and accretion  that are based on
         estimates of oil and gas reserves  that the Trust  expects to recover
         in the future;

     d)  estimated  fair values of  derivative  contracts  that are subject to
         fluctuation  depending  upon  the  underlying  commodity  prices  and
         foreign exchange rates;

     e)  estimated value of asset  retirement  obligations  that are dependent
         upon estimates of future costs and timing of expenditures; and

     f)  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  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.


FINANCIAL REPORTING AND 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 is required to comply with certain
portions  of the SOX  legislation.  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:

     o   identify  and  document   internal  controls  that  impact  financial
         reporting;

     o   assess the effectiveness of those internal controls;

     o   remediate any deficiencies in internal  controls and/or implement any
         required controls that are not already in place;

     o   test  the  internal  controls  to  ensure  that  they  are  operating
         effectively; and

     o   issue a  report,  to be signed  by the CEO and CFO,  on  management's
         assessment of the  effectiveness of internal controls and communicate
         any material weaknesses.

ARC is currently required to comply with section 404 of the SOX legislation on
December 31, 2006. In conjunction with the 2006 year end audit, ARC's external
auditors will audit the Trust's internal controls and will issue two opinions,
one on the auditor's assessment of the effectiveness of internal controls over
financial   reporting  and  one  on  the  auditor's  opinion  on  management's
assessment of the internal controls over financial reporting.

The  Trust  currently  has a  comprehensive  plan  and  a  dedicated  team  of
individuals  in place to  execute  the plan of  meeting  the SOX  Section  404
compliance date.


                                     -15-

<PAGE>

As of  December  31,  2005,  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.  Based on that
evaluation,  the President  and Chief  Executive  Officer and Chief  Financial
Officer  concluded that the design and operation of these disclosure  controls
and procedures were effective to ensure that material  information relating to
the Trust is made known to  management  on a timely  basis and is  included in
this  report.  No changes were made to our  internal  control  over  financial
reporting  during the year  ended  December  31,  2005,  that have  materially
affected,  or are reasonably likely to materially affect, our internal control
over financial reporting.

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").  ARC is currently  complying
with this  legislation by filing bare interim and annual  certificates.  It is
expected  that ARC  will be  required  to file a full  annual  certificate  in
conjunction  with the December  31, 2006 year end.  The Canadian  requirements
closely parallel the SEC's certification rules, however, currently there is no
requirement  to  have  external  auditor's  opinion  on the  Trust's  internal
controls or management's assessment thereof.


OBJECTIVES AND 2006 OUTLOOK

It  is  the  Trust's  objective  to  provide  superior  long-term  returns  to
unitholders by focusing on the key strategic  objectives of the business plan.
The Trust has provided unitholders with the following one, three and five year
returns (assuming the reinvestment of distributions):

<TABLE>
<CAPTION>
TOTAL RETURNS
--------------------------------------------------------------------------------------------
($ per unit except for per cent)                         One Year   Three Year    Five Year
--------------------------------------------------------------------------------------------
<S>                                                   <C>           <C>           <C>
Distributions per unit                                $      1.99   $     5.59    $    9.46
Capital appreciation per unit                                8.59        14.59        15.19
--------------------------------------------------------------------------------------------

Total return per unit                                 $     10.58   $    20.18    $   24.65
Annualized total return per unit                            62.4%        46.5%        38.8%
--------------------------------------------------------------------------------------------
</TABLE>

To the end of 2005, the Trust has provided  cumulative cash  distributions  of
$16.23 per unit and capital appreciation of $16.49 per unit for a total return
of $32.72 per unit (27.9 per cent annualized total return) for unitholders who
invested in the Trust at inception in 1996.

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 2005 as individually  addressed  below.  They continue to be
key objectives for 2006.

     o   ANNUAL  RESERVES  REPLACEMENT  - The Trust  increased its proved plus
         probable  reserves  from 244  mmboe at year end 2004 to 287  mmboe at
         year  end  2005  through  a  combination  of the  reserves  additions
         associated  with the Trust's $269  million  2005  capital  budget and
         reserves  purchased in corporate  and property  acquisitions  (net of
         dispositions) for $598 million.

     o   ENSURING  ACQUISITIONS ARE STRATEGIC AND ENHANCE UNITHOLDER RETURNS -
         The Trust added significant  assets in its core Pembina and southeast
         Saskatchewan  areas in 2005.  In  addition,  the Trust added  another
         long-life,  light oil property to its portfolio with the  acquisition
         of a controlling  interest in the Redwater  field.  ARC believes that
         long-life,  light oil properties will provide future opportunities to
         enhance unitholder value through the application of tertiary recovery
         methods.

     o   CONTROLLING  COSTS  - Due  to  the  diligence  of  field  and  office
         operating  staff,  the  Trust's  operating  costs  per  boe  in  2005
         increased less than three per cent over 2004 costs. Cash G&A costs in
         2005  increased  30 per cent to $1.34  per boe from  $1.03 per boe in
         2004  as a  result  of  both  increased  staff  count  and  increased
         compensation costs due to the extremely  competitive  marketplace for
         experienced staff with oil and gas expertise.  The Trust believes the
         $1.34  per boe  cash G&A  costs  will be  "middle  of the  pack"  for
         mid-sized oil and gas producers,  representing an appropriate balance
         of the Trust's  objective to develop and retain the best staff in the
         industry,  discussed  below,  and the  desire to keep costs as low as
         possible.  The Trust's  three year  average FD&A costs of $11 per boe
         prior to incorporating  future development costs "FDC" and $13.50 per
         boe with FDC, ARC believes  will be better than the industry  average
         and demonstrates ARC's effective use of retained cash.

     o   CONSERVATIVE UTILIZATION OF DEBT - The Trust's debt levels were under
         10 per cent of total  capitalization  and debt to 2005  cash flow was
         0.7 times for the year ended 2005 taking into  account full year cash
         flow on properties acquired later in the year.

     o   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.  Since  ARC's 62 per cent total  return in 2005 was one of
         the top returns in our sector, total non-cash long-term  compensation
         expense increased to $0.74 per boe in 2005.


                                     -16-

<PAGE>

     o   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.

     o   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.  With the
         Trust's purchase of Redwater and additional interest in Pembina,  the
         Trust will be increasing its research into tertiary recovery methods.

     o   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.

     o   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.

Following  is a summary of the  Trust's  2006  Guidance  issued by way of news
release on December 6, 2005:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                             2005 Revised                                      2006
                                                 Guidance    Actual 2005    % Change       GUIDANCE
----------------------------------------------------------------------------------------------------
<S>                                                <C>            <C>       <C>            <C>
PRODUCTION (boe/d)                                 56,000         56,254          --         61,000
----------------------------------------------------------------------------------------------------

EXPENSES ($/boe):
   Operating costs                                   7.00           6.93          (1)          8.65
   Transportation                                    0.70           0.70          --           0.70
   G&A expenses - cash                               1.25           1.34           7           1.70
   G&A expenses - stock compensation plans           0.60           0.74          23           0.65
   Interest                                          0.75           0.83          11           1.40
   Taxes                                             0.15           0.19          --           0.15

CAPITAL EXPENDITURES ($ millions)                     270            269          --            340
----------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE TRUST UNITS
   AND UNITS ISSUABLE (millions)                    191.3          191.2           --         205.5
----------------------------------------------------------------------------------------------------
</TABLE>

Actual 2005 results were in line with 2005  guidance  except for G&A expenses,
which were higher because of increased staff  compensation  costs and expected
payments under the Long-term Employee Incentive Plan. Interest costs increased
because of acquisitions,  which were made during the year and partially funded
by debt.


                                     -17-
<PAGE>

2006 CASH FLOW AND HEDGING SENSITIVITY

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

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
                                                                                Impact On Annual
                                                                                    Cash Flow
BUSINESS ENVIRONMENT                                         Assumption       Change          $/Unit
-----------------------------------------------------------------------------------------------------
<S>                                                      <C>              <C>           <C>
Oil price (US$WTI/bbl) (1)                               $        55.00   $     1.00    $       0.05
Natural gas price (Cdn$AECO/mcf) (1)                     $        10.55   $     0.10    $       0.03
CAD/USD exchange rate                                    $         0.87   $     0.01    $       0.06
Interest rate on debt                                              4.1%         1.0%    $       0.03
-----------------------------------------------------------------------------------------------------

OPERATIONAL
Liquids production volume (bbl/d)                                31,000         1.0%    $       0.02
Gas production volumes (mmcf/d)                                   181.0         1.0%    $       0.02
Operating expenses per boe                               $         8.60         1.0%    $       0.01
Cash G&A expenses per boe                                $         1.70        10.0%    $       0.02
-----------------------------------------------------------------------------------------------------
</TABLE>

(1)  Analysis does not include the effect of derivative contracts.


ASSESSMENT OF BUSINESS RISKS

The ARC  management  team is focused on long-term  strategic  planning and has
identified the key risks,  uncertainties and opportunities associated with the
Trust's business that can impact the financial results as follows:

VOLATILITY OF OIL AND NATURAL GAS PRICES

The Trust's  operational  results and financial  condition,  and therefore the
amount of  distributions  paid to the  unitholders  will be  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 the holders of trust units. ARC may manage
the risk associated  with changes in commodity  prices by entering into oil or
natural gas price derivative contracts. If ARC engages in activities to manage
its  commodity  price  exposure,  the Trust may forego the  benefits  it would
otherwise  experience  if  commodity  prices were to  increase.  In  addition,
commodity  derivative  contracts activities could expose ARC to losses. 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

Variations  in interest  rates could result in a  significant  increase in the
amount  the  Trust  pays  to  service   debt,   resulting  in  a  decrease  in
distributions  to  unitholders.  World oil prices are quoted in US dollars and
the  price  received  by  Canadian  producers  is  therefore  affected  by the
Canadian/US  dollar  exchange  rate that may  fluctuate  over time. A material
increase in the value of the Canadian dollar may negatively impact the Trust's
net production revenue. In addition, the exchange rate for the Canadian dollar
versus  the US dollar  has  increased  significantly  over the last 12 months,
resulting  in the  receipt  by the  Trust of fewer  Canadian  dollars  for its
production,  which may affect 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/US  exchange  rates may impact future  distributions  and the
future value of the Trust's reserves as determined by independent evaluators.

RESERVES ESTIMATES

The reserves and recovery information  contained in ARC's independent reserves
evaluation is only an estimate.  The actual  production and ultimate  reserves
from the properties may be greater or less than the estimates  prepared by the
independent reserves evaluator. The reserves report was prepared using certain
commodity  price  assumptions  that are described in the notes to the reserves
tables. If lower prices for crude oil, natural gas liquids and natural gas are
realized by the Trust and  substituted for the price  assumptions  utilized in
those reserves  reports,  the present value of estimated future net cash flows
for the  Trust's  reserves  would  be  reduced  and  the  reduction  could  be
significant, particularly based on the constant price case assumptions.

DEPLETION OF RESERVES AND MAINTENANCE OF DISTRIBUTION

ARC's future oil and natural gas reserves and  production,  and  therefore its
cash  flows,  will be highly  dependent  on ARC's  success in  exploiting  its
reserves base and acquiring  additional  reserves.  Without reserves additions
through  acquisition  or  development  activities,  the


                                     -18-
<PAGE>

Trust's  reserves and production will decline over time as the oil and natural
gas reserves are produced out.

There  can be no  assurance  that  the  Trust  will  make  sufficient  capital
expenditures to maintain  production at current levels;  nor as a consequence,
that the amount of distributions by the Trust to unitholders can be maintained
at current levels.

To the extent that  external  sources of capital,  including  the  issuance of
additional  trust units become limited or  unavailable,  ARC's ability to make
the necessary  capital  investments  to maintain or expand its oil and natural
gas reserves could be impaired. To the extent that ARC is required to use cash
flow to finance capital  expenditures or property  acquisitions,  the level of
distributions could be reduced.

There  can be no  assurance  that  ARC will be  successful  in  developing  or
acquiring  additional  reserves  on terms  that  meet the  Trust's  investment
objectives.

ACQUISITIONS

The price paid for reserves  acquisitions is based on engineering and economic
estimates of the reserves made by  independent  engineers  modified to reflect
the  technical  views of  management.  These  assessments  include a number of
material   assumptions   regarding   such   factors  as   recoverability   and
marketability  of oil,  natural gas,  natural gas liquids and sulphur,  future
prices of oil,  natural  gas,  natural gas  liquids and sulphur and  operating
costs,  future capital  expenditures and royalties and other government levies
that will be imposed over the producing  life of the  reserves.  Many of these
factors are subject to change and are beyond the control of the  operators  of
the working interests, management and the Trust. In particular, changes in the
prices of and markets for oil,  natural  gas,  natural gas liquids and sulphur
from those  anticipated at the time of making such assessments will affect the
amount  of  future  distributions  and as such  the  value  of the  units.  In
addition,  all such estimates  involve a measure of geological and engineering
uncertainty that could result in lower production and reserves than attributed
to the working  interests.  Actual  reserves could vary  materially from these
estimates.  Consequently,  the reserves  acquired  may be less than  expected,
which could adversely impact cash flows and distributions to unitholders.


OPERATIONAL AND RESERVE RISKS RELATING TO THE ACQUISITION OF ASSETS

Risk  factors  set  forth in this MD&A  relating  to the oil and  natural  gas
business and the operations and reserves of the Trust apply equally in respect
of the  acquisitions  that the Trust  makes over time.  Reserve  and  recovery
information  contained  in this MD&A in  respect  of  acquisitions  is only an
estimate  and  the  actual  production  from  and  ultimate  reserves  of  the
acquisitions,  particularly the NPCU and Redwater properties may be greater or
less than the  estimates  contained  in such  reports.  There are  significant
environmental  reclamation  liabilities  attributable to the NPCU and Redwater
properties.

COMPETITION

There  is  strong  competition  relating  to all  aspects  of the  oil and gas
industry.  There  are  numerous  trusts in the oil and gas  industry  that are
competing  for the  acquisition  of  properties  with longer life reserves and
properties with  exploitation  and development  opportunities.  As a result of
such increasing competition,  it will be more difficult to acquire reserves on
beneficial  terms. ARC competes for reserve  acquisitions and skilled industry
personnel with a substantial  number of other oil and gas  companies,  many of
which have significantly greater financial and other resources than the Trust.

NATURE OF UNITS

Units will have no value when the oil and gas reserves from the properties can
no longer be economically produced and, as a result, cash distributions do not
represent a "yield" in the  traditional  sense as they represent both a return
of capital and a return on investment.

The units do not represent a traditional investment in the oil and natural gas
sector and should not be viewed by investors as shares in a  corporation.  The
units  represent  a  fractional  interest  in the Trust.  As holders of units,
unitholders  will not have  the  statutory  rights  normally  associated  with
ownership  of shares of a  corporation.  The  Trust's  sole assets will be the
royalty  interests  in the  properties.  The price per unit is a  function  of
anticipated  distributable  income,  the properties  acquired by ARC and ARC's
ability to effect long-term growth in the value of the Trust. The market price
of the units will be  sensitive to a variety of market  conditions  including,
but not  limited  to,  interest  rates and the ability of the Trust to acquire
suitable  oil and natural gas  properties.  Changes in market  conditions  may
adversely affect the trading price of the units.

The net asset value,  utilizing assumptions by independent  engineers,  of the
assets of the Trust  will  vary from time to time  dependent  upon a number of
factors  beyond the control of management,  including oil and gas prices.  The
trading prices of the units from time to time are also  determined by a number
of factors that are beyond the control of management  and such trading  prices
may be greater than the net asset value of the Trust's assets.

ENVIRONMENTAL CONCERNS

The oil and  natural  gas  industry  is  subject to  environmental  regulation
pursuant  to  local,  provincial  and  federal  legislation.  A breach of such
legislation  may result in the  imposition  of fines or  issuance  of clean up
orders in respect of ARC or its working  interests.  Such  legislation  may be
changed to impose higher standards and potentially more costly  obligations on
ARC.  Although  ARC has  established  a  reclamation  fund for the  purpose of
funding  its  currently   estimated  future   environmental   and  reclamation
obligations based on its current knowledge, there can be no assurance that the
Trust will be able to satisfy its actual future  environmental and reclamation
obligations. Additionally, the


                                     -19-
<PAGE>

potential  impact on the Trust's  operations and business of the December 1997
Kyoto Protocol, which has been ratified by Canada, with respect to instituting
reductions  of  greenhouse  gases,  is  difficult  to quantify at this time as
specific measures for meeting Canada's commitments have not been developed.

CHANGES IN LEGISLATION

Income tax laws, or other laws or government  incentive  programs  relating to
the oil and gas  industry,  such as the  treatment  of mutual  fund trusts and
resource  taxation,  may in the future be changed or  interpreted  in a manner
that adversely affects the Trust and its unitholders.  Tax authorities  having
jurisdiction over the Trust or the unitholders may disagree with how the Trust
calculates  its  income  for  tax  purposes  or  could  change  administrative
practices to the detriment of the Trust or the  detriment of its  unitholders.
ARC intends that the Trust will continue to qualify as a mutual fund trust for
purposes of the Tax Act. The Trust may not, however, always be able to satisfy
any future  requirements  for the  maintenance  of mutual  fund trust  status.
Should the status of the Trust as a mutual fund trust be lost or  successfully
challenged by a relevant tax authority, certain adverse consequences may arise
for the Trust and its unitholders.

OPERATIONAL MATTERS

The operation of oil and gas wells  involves a number of operating and natural
hazards that may result in blowouts, environmental damage and other unexpected
or dangerous conditions  resulting in damage to operating  subsidiaries of the
Trust and possible  liability to third  parties.  ARC will maintain  liability
insurance,  where available,  in amounts  consistent with industry  standards.
Business interruption insurance may also be purchased for selected facilities,
to the extent that such  insurance  is  available.  ARC may become  liable for
damages  arising from such events  against  which it cannot  insure or against
which it may  elect  not to  insure  because  of high  premium  costs or other
reasons.  Costs  incurred to repair such damage or pay such  liabilities  will
reduce distributable cash.

Continuing  production  from a property,  and to some extent the  marketing of
production  therefrom,  are largely dependent upon the ability of the operator
of the property.  Operating costs on most  properties have increased  steadily
over recent years. To the extent the operator fails to perform these functions
properly,  revenue may be reduced.  Payments from  production  generally  flow
through the  operator and there is a risk of delay and  additional  expense in
receiving  such  revenues  if  the  operator   becomes   insolvent.   Although
satisfactory title reviews are generally conducted in accordance with industry
standards, such reviews do not guarantee or certify that a defect in the chain
of title may not arise to defeat the claim of the Trust to certain properties.
A reduction of the distributions could result in such circumstances.

NON-RESIDENT OWNERSHIP OF TRUST UNITS

In order for the Trust to maintain its status as a mutual fund trust under the
Tax Act, the Trust intends to comply with the  requirements of the Tax Act for
"mutual fund trusts" at all relevant  times.  In this regard,  the Trust shall
among  other  things,  monitor  the  ownership  of the units to carry out such
intentions. The Trust Indenture provides that if at any time the Trust becomes
aware  that the  beneficial  owners of 50 per cent or more of the  units  then
outstanding are or may be  non-residents or that such a situation is imminent,
the Trust  shall  take such  action as it is able and as may be  necessary  to
carry out the foregoing intention.

DEBT SERVICE AND ADDITIONAL FINANCING

Amounts  paid in  respect  of  interest  and  principal  on debt  will  reduce
distributions. Variations in interest rates and scheduled principal repayments
could result in  significant  changes in the amount  required to be applied to
debt  service  before  payment  of  distributions.  Certain  covenants  of the
agreements  with ARC's  lenders  may also limit  distributions.  Although  ARC
believes the credit  facilities  will be sufficient for the Trust's  immediate
requirements,  there can be no assurance  that the amount will be adequate for
the future financial obligations of the Trust or that additional funds will be
able to be obtained.

The lenders  will be provided  with  security  over  substantially  all of the
assets of ARC.  If ARC  becomes  unable  to pay its debt  service  charges  or
otherwise  commits  an event of  default  such as  bankruptcy,  the lender may
foreclose on or sell the working interests.

In the normal course of making capital  investments to maintain and expand the
oil and gas reserves of the Trust,  additional  units are issued from treasury
that may result in a decline in  production  per unit and  reserves  per unit.
Additionally,  from time to time the Trust issues units from treasury in order
to reduce debt and maintain a more optimal capital structure.  Conversely,  to
the extent  that  external  sources of  capital,  including  the  issuance  of
additional units,  become limited or unavailable,  the Trust's ability to make
the  necessary  capital  investments  to  maintain  or expand  its oil and gas
reserves will be impaired. To the extent that ARC is required to use cash flow
to finance capital expenditures or property acquisitions,  to pay debt service
charges or to reduce debt, the level of distributable income will be reduced.

EXPANSION OF OPERATIONS

The operations and expertise of management of the Trust are currently  focused
on conventional oil and gas production and development in the western Canadian
sedimentary basin. In the future, the Trust may acquire oil and gas properties
outside this geographic area. In addition,  the Trust Indenture does not limit
the activities of the Trust to oil and gas production and development, and the
Trust could acquire other energy related  assets,  such as oil and natural gas
processing  plants or  pipelines,  or an  interest  in an oil  sands  project.
Expansion of our activities into new areas may present new additional risks or
alternatively,  significantly  increase  the  exposure  to one or  more of the
present risk  factors,  which may result in future  operational  and financial
conditions of the Trust being adversely affected.


                                     -20-
<PAGE>

ADDITIONAL INFORMATION

Additional information relating to ARC can be found on SEDAR at WWW.SEDAR.COM.

<TABLE>
<CAPTION>
ANNUAL HISTORICAL REVIEW

------------------------------------------------------------------------------------------------------------
For the year ended December 31
(Cdn$ thousands, except per unit amounts)        2005         2004          2003          2002         2001
------------------------------------------------------------------------------------------------------------
<S>                                         <C>            <C>           <C>           <C>          <C>
FINANCIAL
Revenue before royalties                    1,165,197      901,782       743,182       444,835      515,596
   Per unit (1)                                  6.10         4.85          4.80          3.72         5.00
Cash flow                                     639,511      448,033       396,180       223,969      260,270
   Per unit - basic (1)                          3.35         2.41          2.56          1.87         2.53
   Per unit - diluted                            3.32         2.38          2.48          1.86         2.54
Net income                                    356,935      241,690       284,559        69,981      130,993
   Per unit - basic (5)                          1.90         1.32          1.88          0.60         1.30
   Per unit - diluted                            1.88         1.31          1.82          0.59         1.32
Cash distributions                            376,566      329,977       279,328       183,617      234,053
   Per unit (2)                                  1.99         1.80          1.80          1.56         2.31
Total assets                                3,251,161    2,304,998     2,281,775     1,467,918    1,380,004
Total liabilities                           1,415,519      755,650       730,039       599,252      563,882
Net debt outstanding (4)                      578,086      264,842       262,071       347,795      288,684
Weighted
   average units (thousands) (3)              191,172      186,105       154,695       119,613      103,062
Units outstanding and issuable
   at period end (thousands) (3)              202,039      188,804       182,777       126,444      111,692
------------------------------------------------------------------------------------------------------------

CAPITAL EXPENDITURES
Geological and geophysical                      9,219        5,388         5,671         1,966        2,215
Drilling and completions                      200,873      144,487       110,277        70,074       73,147
Plant and facilities                           55,032       41,089        36,457        14,357       22,970
Other capital                                   3,710        2,820         3,359         1,881        3,886
Total capital expenditures                    268,834      193,784       155,764        88,278      102,218
Property acquisitions
   (dispositions), net                         91,286      (58,219)     (161,609)      119,113       12,911
Corporate acquisitions (6)                    504,996       72,009       721,590            --      509,748
Total capital expenditures
   and net acquisitions                       865,116      207,574       715,745       207,391      624,877
------------------------------------------------------------------------------------------------------------

OPERATING
Production
   Crude oil (bbl/d)                           23,282       22,961        22,886        20,655       20,408
   Natural gas (mmcf/d)                         173.8        178.3         164.2         109.8        115.2
   Natural gas liquids (bbl/d)                  4,005        4,191         4,086         3,479        3,511
   Total (boe per day 6:1)                     56,254       56,870        54,335        42,425       43,111
Average prices
   Crude oil ($/bbl)                            61.11        47.03         36.90         31.63        31.70
   Natural gas ($/mcf)                           8.96         6.78          6.40          4.41         5.72
   Natural gas liquids ($/bbl)                  49.92        39.04         32.19         24.01        31.03
   Oil equivalent ($/boe)                       56.54        43.13         37.29         28.73        32.76
------------------------------------------------------------------------------------------------------------

RESERVES (7)
(company interest)
Proved plus probable reserves
   Crude oil and NGL (mbbl)                   163,385      123,226       129,663       117,241      114,243
   Natural gas (bcf)                            741.7        724.5         720.2         408.8        385.5
   Total (mboe)                               286,997      243,974       249,704       185,371      178,496
------------------------------------------------------------------------------------------------------------
</TABLE>

                                     -21-

<PAGE>

<TABLE>
<CAPTION>
TRUST UNIT TRADING
(based on intra-day trading)
<S>                                             <C>          <C>           <C>           <C>          <C>
Unit prices
   High                                         27.58        17.98         14.87         13.44        13.54
   Low                                          16.55        13.50         10.89         11.04        10.25
   Close                                        26.49        17.90         14.74         11.90        12.10
Average daily volume (thousands)                  656          420           430           305          414
------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Based  on  weighted   average   trust  units  plus  units   issuable  for
     exchangeable shares.
(2)  Based on  number of trust  units  outstanding  at each cash  distribution
     date.
(3)  Includes trust units issuable for outstanding  exchangeable  shares based
     on the period end exchange ratio.
(4)  Total current and long-term debt net of working capital.
(5)  Net income in the basic per trust unit  calculation  has been  reduced by
     interest on the convertible debentures.
(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 and 2001.




                                     -22-
<PAGE>

<TABLE>
<CAPTION>
QUARTERLY REVIEW

---------------------------------------------------------------------------------------------------------------------------------
(Cdn$ thousands, except per unit amounts)                    2005                                      2004
---------------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>        <C>        <C>        <C>        <C>        <C>        <C>         <C>
FINANCIAL                                       Q4         Q3         Q2         Q1         Q4         Q3         Q2          Q1
Revenue before royalties                   365,298    310,249    251,596    238,054    232,112    230,769    233,307     205,594
   Per unit (1)                               1.89       1.62       1.32       1.26       1.23       1.23       1.26        1.12
Cash flow                                  207,621    168,117    121,808    141,965    106,935    110,835    122,249     108,014
   Per unit - basic (1)                       1.07       0.88       0.64       0.75       0.57       0.59       0.66        0.59
   Per unit - diluted                         1.07       0.87       0.63       0.74       0.56       0.59       0.65        0.58
Net income                                 130,474    114,600     73,215     38,646    112,995     38,897     50,338      39,460
   Per unit - basic (5)                       0.68       0.61       0.39       0.21       0.61       0.21       0.28        0.22
   Per unit - diluted                         0.68       0.59       0.38       0.20       0.60       0.21       0.27        0.22
Cash distributions                         115,671     92,559     84,468     83,867     83,531     83,178     82,053      81,215
   Per unit (2)                               0.60       0.49       0.45       0.45       0.45       0.45       0.45        0.45
Total assets                             3,251,161  2,483,540  2,427,463  2,303,948  2,304,998  2,316,297  2,309,599   2,278,608
Total liabilities                        1,415,519    912,160    895,179    785,776    755,650    804,603    768,073     752,166
Net debt outstanding (4)                   578,086    357,560    366,216    254,252    264,842    220,500    220,074     284,001
Weighted average units (thousands) (3)     193,445    191,709    190,315    189,210    188,521    187,629    184,998     183,314
Units outstanding and issuable at
   period end (thousands) (3)              202,039    192,089    191,329    189,609    188,804    188,185    187,296     183,980
---------------------------------------------------------------------------------------------------------------------------------

CAPITAL EXPENDITURES
Geological and geophysical                   3,040      2,258      2,659      1,262        867        828      1,373       2,320
Drilling and completions                    65,690     65,676     33,465     36,042     39,125     42,553     24,867      37,942
Plant and facilities                        17,031     14,803      8,703     14,495      6,183     11,668      7,282      15,956
Other capital                                2,020        317        652        721      1,480        394        605         341
Total capital expenditures                  87,781     83,054     45,479     52,520     47,655     55,443     34,127      56,559
Property acquisitions
   (dispositions), net                       3,037      5,860     78,721      3,668     (1,036)    (5,345)   (53,412)      1,574
Corporate acquisitions (6)                 462,814         --     42,182         --     41,449         --     30,560          --
Total capital expenditures
   and  net acquisitions                   553,632     88,914    166,382     56,188     88,068     50,098     11,275      58,133
---------------------------------------------------------------------------------------------------------------------------------

OPERATING
Production
   Crude oil (bbl/d)                        25,534     23,513     22,046     21,993     22,969     22,496     22,720      23,663
   Natural gas (mmcf/d)                      177.9      168.2      173.1      176.1      174.7      177.4      186.7       174.5
   Natural gas liquids (bbl/d)               3,943      4,047      3,962      4,072      4,097      4,034      4,313       4,323
   Total (boe per day 6:1)                  59,120     55,592     54,860     55,410     56,179     56,096     58,147      57,075
Average prices
   Crude oil ($/bbl)                         62.12      69.37      58.37      53.63      49.48      51.00      47.43       40.41
   Natural gas ($/mcf)                       12.05       9.08       7.42       7.20       6.82       6.65       6.99        6.64
   Natural gas liquids ($/bbl)               57.14      50.43      46.13      46.57      43.72      42.30      38.22       32.30
   Oil equivalent ($/boe)                    67.16      60.66      50.40      47.74      44.62      44.54      43.82       39.58
---------------------------------------------------------------------------------------------------------------------------------

TRUST UNIT TRADING
(BASED ON INTRA-DAY TRADING)
Unit prices
   High                                      27.58      24.20      20.30      20.40      17.98      17.38      15.74       15.74
   Low                                       20.45      19.94      16.88      16.55      14.80      15.02      14.28       13.50
   Close                                     26.49      24.10      19.94      18.15      17.90      16.85      15.35       15.64
Average daily volume (thousands)               653        599        605        895        456        384        337         502
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Based  on  weighted   average   trust  units  plus  units   issuable  for
     exchangeable shares.
(2)  Based on  number of trust  units  outstanding  at each cash  distribution
     date.
(3)  Includes trust units issuable for outstanding  exchangeable  shares based
     on the period end exchange ratio.


                                     -23-
<PAGE>

(4)  Total current and long-term debt net of working capital.
(5)  Net income in the basic per trust unit  calculation  has been  reduced by
     interest on the convertible debentures.
(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 and 2001.



                                     -24-