EXHIBIT 99.1
                                                                   ------------





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                                ARC ENERGY TRUST



                          2006 ANNUAL INFORMATION FORM



                                 MARCH 22, 2007






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<PAGE>

                                TABLE OF CONTENTS

                                                                           PAGE

GLOSSARY OF TERMS.............................................................1
SPECIAL NOTES TO READER.......................................................2
ARC ENERGY TRUST..............................................................4
   General....................................................................4
   General Development of Our Business........................................4
OUR BUSINESS..................................................................6
   Overview...................................................................6
   Proposed Federal Tax Changes...............................................6
   Our Organizational Structure...............................................7
   Management Policies........................................................8
   Cash Distributions and Distribution Policy.................................8
   Capital Expenditures.......................................................8
   Potential Acquisitions.....................................................9
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................9
   Disclosure of Reserves Data................................................9
   Reserves Data (Constant Prices and Costs).................................10
   Reserves Data (Forecast Prices and Costs).................................12
   Definitions and Notes to Reserves Data Tables:............................13
   Reconciliations of Changes in Reserves and Future Net Revenue.............18
   Additional Information Relating to Reserves Data..........................19
   Other Oil and Gas Information.............................................20
   Marketing Arrangements....................................................28
   Acquisitions and Dispositions.............................................28
SHARE CAPITAL OF ARC RESOURCES...............................................28
   Common Shares.............................................................28
   Exchangeable Shares.......................................................29
   Second Preferred Shares...................................................30
OTHER INFORMATION RELATING TO OUR BUSINESS...................................30
   Borrowing.................................................................30
   Restriction On Resale Agreements..........................................31
   Retention Payments........................................................31
OUR INFORMATION..............................................................31
   Trust Units...............................................................31
   Special Voting Unit.......................................................32
   the Trust Indenture.......................................................32
   Trustee...................................................................32
   Future Offerings..........................................................33
   Meetings and Voting.......................................................33
   Our Management............................................................33
   Arc Financial Advisory Agreement..........................................34
   Limitation On Non-resident Ownership......................................34
   Right of Redemption.......................................................34
   Termination of the Trust..................................................35
   Reporting to Unitholders..................................................35
   Distribution Reinvestment and Optional Trust Unit Purchase Plan...........35

<PAGE>
                                      ii


CORPORATE GOVERNANCE.........................................................35
   General...................................................................35
   Trust Indenture...........................................................35
   Decision Making...........................................................36
   Board of Directors of Arc Resources.......................................36
AUDIT COMMITTEE DISCLOSURES..................................................40
   Members of the Audit Committee............................................40
   Principal Accountant Fees and Services....................................41
CONFLICTS OF INTEREST........................................................42
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................42
DISTRIBUTIONS TO UNITHOLDERS.................................................42
PRICE RANGE AND TRADING VOLUME OF TRUST UNITS AND EXCHANGEABLE SHARES........43
INDUSTRY REGULATIONS.........................................................44
   Pricing and Marketing - Oil and Natural Gas...............................44
   Pipeline Capacity.........................................................45
   the North American Free Trade Agreement...................................45
   Provincial Royalties and Incentives.......................................45
   Land Tenure...............................................................49
   Environmental Regulation..................................................49
RISK FACTORS.................................................................50
   Volatility of Oil and Natural Gas Prices..................................50
   Proposed Federal Tax Changes..............................................50
   Operational Matters.......................................................52
   Reserves Estimates........................................................52
   Variations in Interest Rates and Foreign Exchange Rates...................53
   Purchase of Properties....................................................53
   Enhanced Oil Recovery.....................................................53
   Changes in Legislation....................................................54
   Maintenance of Distributions..............................................55
   Expansion of Operations...................................................55
   Non-resident Ownership of Trust Units.....................................55
   Environmental Concerns....................................................55
   Kyoto Protocol............................................................56
   Additional Financing......................................................56
   Competition...............................................................57
   Accounting Write-downs as a Result of Gaap................................57
   Debt Service..............................................................57
   Delay in Cash Distributions...............................................58
   Reliance On Management....................................................58
   Depletion of Reserves.....................................................58
   Net Asset Value...........................................................59
   Return of Capital.........................................................59
   Nature of Trust Units.....................................................59
   Unitholder Limited Liability..............................................59
   Title to Properties.......................................................60

<PAGE>
                                      iii


TRANSFER AGENTS AND REGISTRARS...............................................60
MATERIAL CONTRACTS...........................................................60
INTEREST OF EXPERTS..........................................................61
ADDITIONAL INFORMATION.......................................................61

APPENDIX A   -    REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
                  EVALUATOR
APPENDIX B   -    REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
                  INFORMATION
APPENDIX C   -    MANDATE OF THE AUDIT COMMITTEE

<PAGE>

<TABLE>
<CAPTION>
ABBREVIATIONS AND CONVERSIONS
<S>        <C>                                                     <C>         <C>
bbl        Barrel                                                  Mcf         one thousand cubic feet
bbl/d      barrels per day                                         Mcfpd       one thousand cubic feet per day
Bcf        billion cubic feet                                      MMBTU       one million British Thermal Units
boe        barrels of oil equivalent converting 6 Mcf of           MMcf        one million cubic feet
           natural gas or one barrel of natural gas liquids
           to one barrel of oil equivalent
                                                                   MMcfpd      one million cubic feet per day
                                                                   $MM         one million dollars
boe/d      barrels of oil equivalent per day                       MMbbl       one million barrels
Mbbl       one thousand barrels                                    NGLs        natural gas liquids
mboe       one thousand barrels of oil equivalent
</TABLE>

We have adopted the standard of 6Mcf:1boe when converting  natural gas to boes.
Boes may be  misleading,  particularly  if used in isolation.  A boe conversion
ratio of 6 Mcf per barrel is based on an energy  equivalency  conversion method
primarily  applicable  at the  burner  tip  and  does  not  represent  a  value
equivalency at the wellhead.

The following table sets forth certain  standard  conversions  between Standard
Imperial Units and the International System of Units (or metric units).

    TO CONVERT FROM            TO                     MULTIPLY BY
    ---------------            --                     -----------
    cubic metres               cubic feet             35.315
    bbls                       cubic metres           0.159
    cubic metres               bbls                   6.290
    Feet                       metres                 0.305
    Metres                     feet                   3.281
    Miles                      kilometres             1.609
    Kilometres                 miles                  0.621
    Acres                      hectares               0.4047
    Hectares                   acres                  2.471

All dollar  amounts set forth in this Annual  Information  Form are in Canadian
dollars, except where otherwise indicated.



<PAGE>

                               GLOSSARY OF TERMS

In this Annual Information Form,  capitalized terms shall have the meanings set
forth below:

ACQUISITION  means the acquisition by ARC Resources and its affiliates of three
unlimited liability corporations which together held the Acquisition Assets;

ACQUISITION ASSETS means certain properties  comprising a 45.57 percent working
interest  in the North  Pembina  Cardium  Unit #1 in Alberta  and the  vendors'
working interests in the Redwater area of Alberta;

ARC,  WE,  US,  OUR or TRUST  means ARC  Energy  Trust  and all its  controlled
entities as a consolidated body;

ARC RESOURCES means ARC Resources Ltd.;

ARC SASK. means ARC (Sask.) Energy Trust, an Alberta trust;

ARC SUBCO means  1285637  Alberta  Ltd.,  or such other  corporation  as may be
substituted for ARC Subco;

ARML means ARC  Resources  Management  Ltd. a  corporation  that,  prior to its
acquisition by ARC Resources in connection with an internalization transaction,
was responsible for our management;

EXCHANGEABLE  SHARES means the  exchangeable  shares of ARC Resources  that are
exchangeable for Trust Units;

EXCHANGE  RATIO  means  the  ratio  at which  the  Exchangeable  Shares  may be
exchanged for Trust Units;

GLJ means GLJ Petroleum Consultants Ltd.,  independent petroleum consultants of
Calgary, Alberta;

GLJ REPORT means the report  prepared by GLJ dated February 12, 2007 evaluating
the  crude  oil,   natural  gas,  natural  gas  liquids  and  sulphur  reserves
attributable to the properties at December 31, 2006;

LONG TERM NOTES means the unsecured long term notes issued by ARC Resources and
ARC Sask.  to the Trust from time to time  bearing  interest at rates per annum
ranging from 12 per cent to 13 per cent payable  monthly with maturity dates of
15 years from the date of issuance;

ROYALTIES means,  collectively,  the royalties payable by ARC Resources and ARC
Sask. to the Trust pursuant to the royalty  agreements  which equal 99 per cent
of royalty income;

TAX ACT means the Income Tax Act (Canada);

TRUST INDENTURE means the trust indenture between  Computershare  Trust Company
of Canada,  as trustee,  and ARC Resources  Ltd., as amended and restated as of
May 15, 2006;

TRUST  UNITS  means the units of the  Trust,  each unit  representing  an equal
undivided beneficial interest in the Trust; and

UNITHOLDERS means holders of Trust Units of the Trust.

Certain other terms used in this Annual Information Form but not defined herein
are defined in NI 51-101 and, unless the context otherwise requires, shall have
the same meanings herein as in NI 51-101.

<PAGE>
                                       2


                             SPECIAL NOTES TO READER

REGARDING FORWARD LOOKING STATEMENTS

Certain  statements  contained in this Annual  Information Form, and in certain
documents   incorporated  by  reference  into  this  Annual  Information  Form,
constitute forward-looking statements. These statements relate to future events
or our future  performance.  All statements other than statements of historical
fact may be forward-looking  statements.  Forward-looking statements are often,
but not always,  identified  by the use of words such as "seek",  "anticipate",
"budget", "plan", "continue",  "estimate", "expect", "forecast", "may", "will",
"project",  "predict",  "potential",  "targeting",  "intend", "could", "might",
"should", "believe" and similar expressions. These statements involve known and
unknown risks, uncertainties and other factors that may cause actual results or
events to differ  materially  from those  anticipated  in such  forward-looking
statements.  We believe the  expectations  reflected  in those  forward-looking
statements are reasonable but no assurance can be given that these expectations
will prove to be correct and such  forward-looking  statements  included in, or
incorporated  by reference  into,  this Annual  Information  Form should not be
unduly relied upon.  These  statements speak only as of the date of this Annual
Information  Form or as of the date specified in the documents  incorporated by
reference into this Annual Information Form, as the case may be.

In particular,  this Annual Information Form, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:

     o   the performance characteristics of our oil and natural gas properties;

     o   oil and natural gas production levels;

     o   the size of the oil and natural gas reserves;

     o   projections  of market prices and costs and the related  sensitivities
         of distributions;

     o   supply and demand for oil and natural gas;

     o   expectations regarding the ability to raise capital and to continually
         add to reserves through acquisitions and development;

     o   treatment under governmental regulatory regimes and tax laws; and

     o   capital expenditures programs.

The actual results could differ  materially  from those results  anticipated in
these  forward-looking  statements  as a result of the risk  factors  set forth
below and elsewhere in this Annual Information Form:

     o   volatility in market prices for oil and natural gas;

     o   liabilities inherent in oil and natural gas operations;

     o   uncertainties associated with estimating oil and natural gas reserves;

     o   competition  for,  among  other  things,   capital,   acquisitions  of
         reserves, undeveloped lands and skilled personnel;

     o   incorrect  assessments  of  the  value,  or  failure  to  realize  the
         anticipated benefits of acquisitions, of acquisitions;

     o   geological, technical, drilling and processing problems;

     o   changes in income tax laws or changes in tax or environmental laws and
         incentive  programs  or royalty  regimes  relating  to the oil and gas
         industry and income trusts; and

     o   the other factors discussed under "RISK FACTORS".

The actual results could differ  materially  from those results  anticipated in
these forward-looking statements, which are based on assumptions,  including as
to the market  prices for oil and natural gas; the  continued  availability  of
capital, acquisitions of reserves, undeveloped lands and skilled personnel; the

<PAGE>
                                       3


continuation  of the current tax and  regulatory  regime and other  assumptions
contained in this Annual Information Form.

Statements   relating  to   "reserves"   or   "resources"   are  deemed  to  be
forward-looking  statements,  as they involve the implied assessment,  based on
certain  estimates and assumptions,  that the resources and reserves  described
can be profitably produced in the future.

Readers are cautioned that the foregoing  lists of factors are not  exhaustive.
The  forward-looking  statements  contained in this Annual Information Form and
the documents  incorporated by reference herein are expressly qualified by this
cautionary statement.  We do not undertake any obligation to publicly update or
revise any forward-looking  statements except as required by securities laws or
regulations.

DESCRIPTION OF CASH FLOW

This Annual  Information Form refers to cash flow and cash flow from operations
derived from cash flow from operating  activities  (before  changes in non-cash
working capital and  expenditures on site  reclamation and  restoration).  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.

For more information,  see "Management's  Discussion and Analysis" for the year
ended  December 31, 2006,  which  includes a  reconciliation  of "cash flow" or
"cash flow from  operations"  to cash flow from  operating  activities  (before
changes in non-cash  working capital and  expenditures on site  reclamation and
restoration), and which has been filed on SEDAR at WWW.SEDAR.COM.

ACCESS TO DOCUMENTS

Any  document  referred to in this Annual  Information  and  described as being
filed on SEDAR at WWW.SEDAR.COM (including those documents referred to as being
incorporated by reference in this Annual Information Form) may be obtained free
of charge from us at 2100, 440 - 2nd Avenue S.W., Calgary, Alberta, T2P 5E9.

<PAGE>
                                       4


                                ARC ENERGY TRUST

GENERAL

We are an open-end  investment  trust  created on May 7, 1996 under the laws of
the Province of Alberta  pursuant to the Trust Indenture.  Computershare  Trust
Company of Canada has been appointed as trustee under the Trust Indenture.  The
beneficiaries  of the Trust are holders of the Trust Units.  The  principal and
head  office of the  Trustee  is located  at Suite  600,  530 8th  Avenue  SW.,
Calgary,  Alberta,  T2P 3S8. The Trust  Indenture has been amended from time to
time, the latest amendments being approved at the annual and special meeting of
Unitholders held May 15, 2006.

The principal offices of the Trust and ARC Resources are located at 2100, 440 -
2nd Avenue S.W., Calgary, Alberta, T2P 5E9 and its registered office is located
at 1400, 350 - 4th Avenue S.W., Calgary, Alberta, T2P 3N9.

The  following  are the  name,  the  percentage  of voting  securities  and the
jurisdiction  governing  our material  subsidiaries,  partnerships  and trusts,
either direct or indirect, as at the date hereof:

<TABLE>
<CAPTION>
                                  PERCENTAGE OF VOTING                        JURISDICTION OF
                                       SECURITIES                              INCORPORATION/
                                (DIRECTLY OR INDIRECTLY)   NATURE OF ENTITY      FORMATION
                                ------------------------   ----------------      ---------
<S>                                       <C>                <C>                  <C>
ARC Resources Ltd.                        100%               Corporation          Alberta
Orion Energy Trust                        100%                  Trust             Alberta
ARC (Sask.) Energy Trust                  100%                  Trust             Alberta
</TABLE>

GENERAL DEVELOPMENT OF OUR BUSINESS

The following equity offering was completed over the last three financial years.

<TABLE>
<CAPTION>
                PROSPECTUS     TRUST UNITS     ISSUE
CLOSING DATE       DATE           ISSUED         PRICE    GROSS PROCEEDS          USE OF PROCEEDS
------------       ----           ------         -----    --------------    -------------------------------
<C>               <C>            <C>             <C>        <C>             <C>
23-Dec-05         16-Dec-05      9,000,000       $26.65     $239,850,000    Repay outstanding indebtedness,
                                                                            including  the  indebtedness
                                                                            incurred in connection with
                                                                            the Acquisition
</TABLE>

A description  of the general  development  of our business over the last three
financial years follows.

On June 8,  2004,  we  acquired  the  remaining  30 per cent  ownership  of the
Cranberry  Slave  Point D Pool in the  Prestville  area  in  northern  Alberta,
through the  purchase of United  Prestville  Ltd. We paid for this  acquisition
with the issuance of 2,032,358  Trust Units at a price of $15.01 per Trust Unit
to the owners of United Prestville Ltd.

On December 31, 2004, we acquired all of the issued and  outstanding  shares of
four legal entities - Harrington Oil & Gas Ltd.,  Bibler Oil & Gas Ltd.,  Lesco
Oil & Gas Ltd., and Bibco Oil & Gas Ltd. for approximately  $41.4 million.  All
of the assets  acquired  are  long-life  shallow  gas  assets in our  southwest
Saskatchewan/southeast  Alberta core area, with almost 60 per cent of the value
attributed to properties operated by us.

On June 30,  2005,  we  acquired  all of the issued and  outstanding  shares of
Romulus  Exploration  Inc. for total  consideration  of $42.2 million.  The key
property in this  acquisition is directly  adjacent to ARC's Weir Hill property
in Southeast Saskatchewan.

<PAGE>
                                       5


On December  16,  2005,  we acquired  the  Acquisition  Assets for an aggregate
purchase  price  of  approximately  $462.8  million.  In  conjunction  with the
Acquisition,  ARC Resources  agreed to form a reclamation  trust in relation to
the Redwater properties pursuant to which ARC Resources agreed to contribute to
such trust certain minimum amounts,  totaling approximately $110 million over a
50 year period,  to fund future  environmental  and reclamation  obligations in
respect  of the  Redwater  properties,  or to expend  certain  minimum  amounts
towards  discharging  these  obligations.  The amount  will be  contributed  or
expenditures  incurred over such period with minimum  annual  contributions  or
expenditures  over each of the initial five years of  approximately  $6 million
and declining thereafter.  Concurrently,  we increased our credit facility from
$620  million  to $950  million  in  order  to pay for the  Acquisition  and on
December 23, 2005 decreased our  indebtedness by the net proceeds from the sale
of 9,000,000 Trust Units at a price of $26.65 per Trust Unit.

We completed property acquisitions,  net of dispositions,  of $115.2 million in
2006. We also completed one corporate  acquisition for total  consideration  of
$16.6 million resulting in total acquisitions,  net of dispositions,  of $131.8
million in the year.



<PAGE>
                                       6


                                  OUR BUSINESS

OVERVIEW

Our principal undertaking is to receive Royalties and other income on petroleum
and  natural  gas  properties  and  related  assets  and to  acquire  and  hold
securities of subsidiaries,  trusts and partnerships. Our subsidiaries,  trusts
and   partnerships  are  entitled  to  carry  on  the  business  of  acquiring,
developing,  exploiting and disposing of all types of energy  business  related
assets,   including  petroleum  and  natural  gas  related  assets,  oil  sands
interests,  electricity  or power  generating  assets and pipeline,  gathering,
processing and  transportation  assets. We issue Trust Units and may also issue
securities  of ARC  Resources  or an  affiliate  of  ARC  Resources  which  are
exchangeable for Trust Units and confer voting rights in us.

Our principal investments are the Royalties granted by ARC Resources and by ARC
Sask.,  the  common  shares  of ARC  Resources  and the Long  Term  Notes.  The
Royalties  consist  of a 99 per cent  share  of  royalty  income  on all of the
properties held by ARC Resources and ARC Sask.  Royalty income is generally all
production  revenue less all  operating  and capital costs and all debt service
charges including principal repayments.  On each monthly distribution date, ARC
Resources  and ARC Sask.  pay the Trust 99 per cent of  royalty  income and ARC
Resources and ARC Sask. pays interest on outstanding Long Term Notes. The Trust
will  make cash  distributions  of such  funds,  subject  only to the  required
deductions and its expenses.  Such cash  distributions may be wholly or in part
taxable. See "Distributions to Unitholders".

We are structured  with the objective of having income tax incurred only in the
hands of Unitholders. Income distributed to Unitholders consists essentially of
operating  cash flow  generated  by our oil and  natural gas  properties.  More
specifically,  internally  generated cash flow, with the exception of cash flow
used  for  capital  expenditures,   reclamation  fund  contributions,  interest
expense,  debt  repayments,  income  taxes not  passed on to  Unitholders,  and
working capital  requirements,  such as long-term  incentive  compensation,  is
effectively returned to Unitholders.

As an open-ended  investment,  trust  Unitholders  have a right to redeem their
Trust  Units.  As with most other  open-ended  funds,  it is  anticipated  that
trading  on the TSX and not the  right  of  retraction  would  continue  as the
primary  mechanism for Unitholders to sell their Trust Units. For more detailed
information regarding the right of redemption,  see "Our Information - Right of
Redemption".

As at December 31,  2006,  we had  approximately  451  employees  and full time
consultants.

PROPOSED FEDERAL TAX CHANGES

On October  31, 2006 the  Federal  Minister of Finance  proposed to apply a tax
commencing  on January 1, 2011 at the trust level on  distributions  of certain
income from publicly  traded  mutual fund trusts at rates of tax  comparable to
the  combined   federal  and  provincial   corporate  tax  and  to  treat  such
distributions as dividends to the Unitholders (the "October 31 Proposals").  On
December 21, 2006 the Federal Minister of Finance released draft legislation to
implement the October 31, 2006 Proposals pursuant to which,  commencing January
1, 2011 (provided ARC only experiences "normal growth" and no "undue expansion"
before then)  certain  distributions  from us which would have  otherwise  been
taxed as ordinary  income  generally  will be  characterized  as  dividends  in
addition  to  being  subject  to tax at  corporate  rates at the  Trust  level.
Assuming the October 31 Proposals  are  ultimately  enacted in their form,  the
implementation  of such legislation  would be expected to result in adverse tax
consequences  to  us  and  certain  Unitholders  (including  most  particularly
Unitholders  that are tax deferred or  non-residents  of Canada) and may impact
cash distributions from us.

<PAGE>
                                       7


Management  believes  that the October 31 Proposals may reduce the value of the
Trust  Units,  which would be  expected to increase  the cost to ARC of raising
capital in the public capital markets. In addition management believes that the
October 31 Proposals are expected to place ARC and other Canadian energy trusts
at a potential  disadvantage relative to industry  competitors,  including U.S.
master  limited  partnerships,  which will continue to not be subject to entity
level  taxation.  The October 31 Proposals  are also expected to make the Trust
Units less attractive as an acquisition  currency.  As a result,  it may become
more difficult for us to compete effectively for acquisition opportunities.  We
are currently  investigating  alternatives  for the mitigation of the effect of
the October 31 Proposals but there can be no assurance  that we will be able to
successfully  reorganize our legal and tax structure to substantially  mitigate
the expected impact of the October 31 Proposals.

The Government of Canada confirmed its intention to proceed with the October 31
Proposals in its budget speech of March 19, 2007.

There  can be no  assurance  that  this  legislation  will come into law in its
present form or at all or that different or materially  different laws relating
to the  existence  of or  taxation  of income and  royalty  trusts  will not be
enacted  in the  future.  For more  information,  see "Risk  Factors - Proposed
Federal Tax Changes" and "Risk Factors - Changes in Legislation".

OUR ORGANIZATIONAL STRUCTURE

Our structure and the cash flows from our material  subsidiaries  and trusts to
Unitholders are set forth below:

                   [GRAPHIC OMITTED -- ORGANIZATIONAL CHART]


<PAGE>
                                       8


Notes:
(1)  ARC Resources is the holder of  substantially  all  properties  and assets
     other than the  properties and assets  located in  Saskatchewan  which are
     held by ARC  (Sask.).  Properties  in  British  Columbia  are  held by ARC
     Petroleum Inc. as trustee and agent of ARC Resources.
(2)  ARC Resources had a total of 1,433,000  Exchangeable Shares outstanding as
     at December 31, 2006 that were  exchangeable for  approximately  2,884,000
     Trust Units.

MANAGEMENT POLICIES

All our  activities are directed  towards  maximizing  distributable  income to
Unitholders  while at the same time striving for long-term  growth in the value
of our assets.  These two objectives are  fundamental to our operations and are
balanced to maximize benefit to Unitholders.  We direct our efforts to increase
the value of our  assets  through  the  acquisition  of  producing  oil and gas
properties.  We acquire  producing  properties  and  primarily  participate  in
development activities that are generally considered to be of a low risk nature
in the oil and gas industry.  Also, a small  percentage of each year's  capital
budget will be devoted to moderate risk  development and lower risk exploration
opportunities on our properties.

CASH DISTRIBUTIONS AND DISTRIBUTION POLICY

Cash  distributions are made on the 15th day (or if such date is not a business
day, on the next  business day)  following  the end of each  calendar  month to
Unitholders of record on the last business day of each such calendar month.

The Board of  Directors  of ARC  Resources  on behalf of the Trust  reviews the
distribution  policy from time to time. The actual amount distributed is at the
discretion  of the Board of Directors  and is  principally  dependent  upon the
commodity  price  environment  and the amount of cash flow withheld to fund the
Trust's capital  expenditure program and the annual contribution to the Trust's
reclamation  fund.  In times of high  commodity  prices,  we withhold a greater
percentage  of cash  flow so that  more of the  capital  program  can be funded
internally.

Although our  distributions  are made on a monthly basis, we normally  announce
distribution  levels on a quarterly  basis.  As we strive for  stability in our
distributions,  any changes  which may occur due to varying  market  conditions
will be made with a view to maintaining the new level of  distributions  for at
least six months.

CAPITAL EXPENDITURES

We may acquire  additional  properties and related tangible  equipment and fund
such  acquisitions from production  revenues,  the net proceeds of any issue of
additional  Trust Units or from the proceeds of  disposition  of the  Royalties
sold  along with  properties,  or from  borrowings,  farmouts  or with  working
capital.  We may  sell any of our  interests  in  properties  and  release  the
Royalties from such properties in  consideration of the allocation of a portion
of the proceeds to the Trust,  provided  that the sale is approved by a special
resolution of Unitholders  in the event the interests in the  properties  being
sold constitute  greater than 25 per cent of the asset value of all properties.
In  connection  with  the  sale of any  interests  in the  properties,  we will
determine  whether  the net  proceeds  of the  sale  should  be  reinvested  in
additional properties, used to repay borrowings or make capital expenditures in
ARC Resources or ARC Sask. or be distributed to Unitholders.

We may approve future capital  expenditures  or farmouts under the terms of the
royalty  agreements.   Future  capital  expenditures  on  the  properties  will
generally  be of the type that are  intended to maintain or improve  production
from the  properties.  We may  finance  capital  expenditures  from  production
revenues,  the  proceeds  of the issue of  additional  Trust  Units or from the
proceeds  of  disposition   of  the  Royalties  sold  along  with   properties,
borrowings, farmouts or with working capital.

<PAGE>
                                       9


POTENTIAL ACQUISITIONS

We continue to evaluate  potential  acquisitions  of all types of petroleum and
natural gas and other energy-related  assets as part of our ongoing acquisition
program.  We are  normally  in the  process  of  evaluating  several  potential
acquisitions at any one time which  individually or together could be material.
We cannot predict  whether any current or future  opportunities  will result in
one or more acquisitions.

          STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas  information  is set forth
below (the  "Statement").  The effective  date of the Statement is December 31,
2006 and the preparation  date of the Statement is January 23, 2007. The Report
of Management  and Directors on Oil and Gas Disclosure on Form 51-101F3 and the
Report on Reserves  Data by GLJ on Form  51-102F2 are attached as  Appendices A
and B to this Annual Information Form.

DISCLOSURE OF RESERVES DATA

The reserves  data set forth below is based upon an  evaluation  by GLJ with an
effective date of December 31, 2006  contained in the GLJ Report dated February
12,  2007.  The  reserves  data  summarizes  our oil,  liquids  and natural gas
reserves  and the net present  values of future net revenue for these  reserves
using  constant  prices  and  costs and  forecast  prices  and  costs  prior to
provision for income taxes, interest,  general and administrative expenses, the
impact of any hedging  activities  or the  liability  associated  with  certain
abandonment and well, pipeline and facilities  reclamation costs which were not
deducted by GLJ in  estimating  future net revenue.  The reserves data conforms
with the requirements of NI 51-101.  We engaged GLJ to provide an evaluation of
proved and proved plus probable  reserves.  See also  "Definitions and Notes to
Reserves Data Tables" below.

All of our  reserves  are in Canada  and,  specifically,  in the  provinces  of
Alberta, British Columbia, Saskatchewan and Manitoba.

IT SHOULD NOT BE ASSUMED THAT THE ESTIMATES OF FUTURE NET REVENUES PRESENTED IN
THE TABLES BELOW  REPRESENT THE FAIR MARKET VALUE OF THE RESERVES.  THERE IS NO
ASSURANCE THAT THE CONSTANT  PRICES AND COSTS  ASSUMPTIONS  AND FORECAST PRICES
AND COSTS  ASSUMPTIONS  WILL BE ATTAINED AND VARIANCES  COULD BE MATERIAL.  THE
RECOVERY AND RESERVES  ESTIMATES OF CRUDE OIL,  NATURAL GAS LIQUIDS AND NATURAL
GAS RESERVES  PROVIDED HEREIN ARE ESTIMATES ONLY AND THERE IS NO GUARANTEE THAT
THE ESTIMATED  RESERVES WILL BE  RECOVERED.  ACTUAL CRUDE OIL,  NATURAL GAS AND
NATURAL  GAS LIQUID  RESERVES  MAY BE GREATER  THAN OR LESS THAN THE  ESTIMATES
PROVIDED  HEREIN.  FOR MORE  INFORMATION  AS TO THE RISKS  INVOLVED,  SEE "RISK
FACTORS - RESERVES ESTIMATES" AND "RISK FACTORS - VOLATILITY OF OIL AND NATURAL
GAS PRICES".


<PAGE>
                                      10


RESERVES DATA (CONSTANT PRICES AND COSTS)

<TABLE>
<CAPTION>
                         SUMMARY OF OIL AND GAS RESERVES
                  AND NET PRESENT VALUES OF FUTURE NET REVENUE
                             as of December 31, 2006
                            CONSTANT PRICES AND COSTS

                                                           RESERVES
                                   ------------------------------------------------------
                                     LIGHT AND MEDIUM OIL                  HEAVY OIL
                                     --------------------                  ---------
                                    Gross             Net           Gross            Net
RESERVES CATEGORY                   (Mbbl)          (Mbbl)          (Mbbl)         (Mbbl)
-----------------                   ------          ------          ------         ------
<S>                                <C>              <C>             <C>            <C>
PROVED
     Developed Producing           100,204          90,219          2,517          2,553
     Developed Non-Producing         1,234           1,096             23             23
     Undeveloped                    11,912          10,418              0              0
                                   -------         -------          -----          -----
TOTAL PROVED                       113,350         101,733          2,541          2,575

PROBABLE                            30,703          27,093            849            819
                                   -------         -------          -----          -----
TOTAL PROVED PLUS PROBABLE         144,053         128,826          3,389          3,394
                                   =======         =======          =====          =====

<CAPTION>
                                                        RESERVES
                                   ----------------------------------------------------
                                         NATURAL GAS              NATURAL GAS LIQUIDS
                                         -----------              -------------------
                                    Gross            Net          Gross          Net
RESERVES CATEGORY                   (MMcf)         (MMcf)         (Mbbl)        (Mbbl)
-----------------                   ------         ------         ------        ------
<S>                                <C>            <C>             <C>           <C>
PROVED
     Developed Producing           436,870        371,691          9,441         6,806
     Developed Non-Producing        18,044         13,986            310           215
     Undeveloped                   121,318         97,230          1,818         1,275
                                   -------        -------         ------        ------
TOTAL PROVED                       576,232        482,907         11,569         8,295

PROBABLE                           146,134        121,276          2,956         2,167
                                   -------        -------         ------        ------
TOTAL PROVED PLUS PROBABLE         722,367        604,183         14,525        10,463
                                   =======        =======         ======        ======
</TABLE>

                                     RESERVES
           ---------------------------------------------------------
                                       TOTAL
           ---------------------------------------------------------
                                               Gross            Net
           RESERVES CATEGORY                   (mboe)         (mboe)
           -----------------                   ------         ------

           PROVED
                Developed Producing           184,973        161,526
                Developed Non-Producing         4,575          3,665
                Undeveloped                    33,950         27,898
                                              -------        -------
           TOTAL PROVED                       223,498        193,088

           PROBABLE                            58,864         50,292
                                              -------        -------
           TOTAL PROVED PLUS PROBABLE         282,362        243,380
                                              =======        =======

<PAGE>
                                      11


                                                  NET PRESENT VALUES OF
                                                   FUTURE NET REVENUE
                                                  ---------------------
                                                   BEFORE INCOME TAXES
                                                  DISCOUNTED AT (%/year)
                                                  ---------------------
                                                   0%                10%
RESERVES CATEGORY                                (MM$)              (MM$)
-----------------                                -----              -----

PROVED
   Developed Producing                           4,779              2,687
   Developed Non-Producing                         116                 68
   Undeveloped                                     614                242
                                                 -----              -----
TOTAL PROVED                                     5,508              2,996

PROBABLE                                         1,536                496
                                                 -----              -----
TOTAL PROVED PLUS PROBABLE                       7,044              3,492
                                                 =====              =====

<TABLE>
<CAPTION>
                                       TOTAL FUTURE NET REVENUE
                                            (UNDISCOUNTED)
                                        as of December 31, 2006
                                       CONSTANT PRICES AND COSTS
                                                                                               FUTURE NET                FUTURE NET
                                                                                  WELL          REVENUE                   REVENUE
                                              OPERATING      DEVELOPMENT      ABANDONMENT        BEFORE     INCOME         AFTER
    RESERVES       REVENUE     ROYALTIES        COSTS           COSTS            COSTS        INCOME TAXES    TAXES     INCOME TAXES
    CATEGORY        (MM$)        (MM$)          (MM$)           (MM$)            (MM$)           (MM$)        (MM$)        (MM$)
    --------        -----        -----          -----           -----            -----           -----        -----        -----
<S>                 <C>           <C>             <C>            <C>              <C>         <C>               <C>         <C>
Proved Reserves     11,303        1,665           3,470          517              144         5,508             0           5,508

Proved Plus         14,263        2,147           4,198          723              151         7,044             0           7,044
Probable
Reserves
</TABLE>

<TABLE>
<CAPTION>
                               FUTURE NET REVENUE
                               BY PRODUCTION GROUP
                             as of December 31, 2006
                            CONSTANT PRICES AND COSTS
                                                                         FUTURE NET REVENUE BEFORE
                                                                        INCOME TAXES (discounted at
                                                                                 10%/year)
   RESERVES CATEGORY                      PRODUCTION GROUP                           (MM$)
   -----------------                      ----------------              ---------------------------
<S>                                 <C>                                 <C>
Proved Reserves                     Light and Medium Crude Oil                      2006
                                    Heavy Oil                                         44
                                    Natural Gas                                      946

Proved Plus Probable Reserves       Light and Medium Crude Oil                     2,351
                                    Heavy Oil                                         55
                                    Natural Gas                                    1,086
</TABLE>

<PAGE>

                                      12

RESERVES DATA (FORECAST PRICES AND COSTS)

<TABLE>
<CAPTION>
                         SUMMARY OF OIL AND GAS RESERVES
                  AND NET PRESENT VALUES OF FUTURE NET REVENUE
                             as of December 31, 2006
                            FORECAST PRICES AND COSTS

                                                        RESERVES
                                    ----------------------------------------------------
                                    LIGHT AND MEDIUM OIL               HEAVY OIL
                                    --------------------               ---------
                                    Gross           Net          Gross          Net
RESERVES CATEGORY                   (Mbbl)         (Mbbl)         (Mbbl)        (Mbbl)
-----------------                   ------         ------         ------        ------
<S>                                   <C>             <C>           <C>            <C>
PROVED
     Developed Producing               99,418          89,460       2,503          2,540
     Developed Non-Producing            1,369           1,226          14             13
     Undeveloped                       11,861          10,393           0              0
                                      -------         -------       -----          -----
TOTAL PROVED                          112,647         101,079       2,517          2,554

PROBABLE                               30,936          27,324         844            815
                                      -------         -------       -----          -----
TOTAL PROVED PLUS PROBABLE            143,583         128,402       3,361          3,369
                                      =======         =======       =====          =====

<CAPTION>
                                                        RESERVES
                                    ----------------------------------------------------
                                         NATURAL GAS              NATURAL GAS LIQUIDS
                                         -----------              -------------------
                                    Gross            Net          Gross          Net
RESERVES CATEGORY                   (MMcf)         (MMcf)         (Mbbl)        (Mbbl)
-----------------                   ------         ------         ------        ------
<S>                                   <C>             <C>           <C>        <C>
PROVED
     Developed Producing              441,588         376,123        9,440     6,811
     Developed Non-Producing           18,060          13,996          313       218
     Undeveloped                      121,976          97,800        1,827     1,282
                                      -------         -------       ------    ------
TOTAL PROVED                          581,624         487,919       11,580     8,310

PROBABLE                              147,577         122,539        2,957     2,170
                                      -------         -------       ------    ------
TOTAL PROVED PLUS PROBABLE            729,201         610,458       14,537    10,480
                                      =======         =======       ======    ======
</TABLE>

                                                     RESERVES
                                              ----------------------
                                                      TOTAL
                                              ----------------------
                                              Gross            Net
          RESERVES CATEGORY                   (mboe)         (mboe)
          -----------------                   ------         ------

          PROVED
               Developed Producing            184,959        161,498
               Developed Non-Producing          4,706          3,790
               Undeveloped                     34,017        193,262
                                              -------        -------
          TOTAL PROVED                        223,682        193,262

          PROBABLE                             59,332         50,732
                                              -------        -------
          TOTAL PROVED PLUS PROBABLE          283,015        243,994
                                              =======        =======

<PAGE>
                                      13


<TABLE>
<CAPTION>
                                                          NET PRESENT VALUES OF FUTURE NET REVENUE
                                                         BEFORE INCOME TAXES DISCOUNTED AT (%/year)
                                             --------------------------------------------------------------------
                                              0%             5%             10%            15%             20%
RESERVES CATEGORY                            (MM$)          (MM$)           (MM$)          (MM$)           (MM$)
-----------------                            -----          -----           -----          -----           -----
<S>                                           <C>            <C>             <C>            <C>             <C>
PROVED
   Developed Producing                        5,609          3,900           3,037          2,517           2,169
   Developed Non-Producing                      152            107              82             67              57
   Undeveloped                                  841            509             332            224             153
                                              -----          -----           -----          -----           -----
TOTAL PROVED                                  6,603          4,516           3,451          2,809           2,379

PROBABLE                                      2,112          1,018             605            407             295
                                              -----          -----           -----          -----           -----
TOTAL PROVED PLUS PROBABLE                    8,715          5,534           4,056          3,215           2,674
                                              =====          =====           =====          =====           =====
</TABLE>

<TABLE>
<CAPTION>
                                       TOTAL FUTURE NET REVENUE
                                            (UNDISCOUNTED)
                                         as December 31, 2006
                                       FORECAST PRICES AND COSTS
                                                                                               FUTURE NET                FUTURE NET
                                                                                  WELL          REVENUE                   REVENUE
                                               OPERATING     DEVELOPMENT      ABANDONMENT        BEFORE     INCOME         AFTER
    RESERVES       REVENUE      ROYALTIES        COSTS          COSTS            COSTS        INCOME TAXES    TAXES     INCOME TAXES
    CATEGORY        (MM$)         (MM$)          (MM$)          (MM$)            (MM$)           (MM$)        (MM$)        (MM$)
    --------        -----         -----          -----          -----            -----           -----        -----        -----
<S>                 <C>             <C>           <C>           <C>               <C>             <C>           <C>         <C>
Proved Reserves     13,936          2,026         4,543         549               215             6,603         0           6,603

Proved Plus         18,164          2,676         5,761         769               243             8,715         0           8,715
Probable
Reserves
</TABLE>

<TABLE>
<CAPTION>
                                          FUTURE NET REVENUE
                                          BY PRODUCTION GROUP
                                        as of December 31, 2006
                                       FORECAST PRICES AND COSTS
                                                                               FUTURE NET REVENUE BEFORE
                                                                              INCOME TAXES (discounted at
                                                                                       10%/year)
        RESERVES CATEGORY                           PRODUCTION GROUP                     (MM$)
        -----------------                           ----------------          ---------------------------
<S>                                 <C>                                                  <C>
Proved Reserves                     Light and Medium Crude Oil                           2,058
                                    Heavy Oil                                               44
                                    Natural Gas                                          1,350

Proved Plus Probable Reserves       Light and Medium Crude Oil                           2,430
                                    Heavy Oil                                               55
                                    Natural Gas                                          1,571
</TABLE>


DEFINITIONS AND NOTES TO RESERVES DATA TABLES:

In the tables set forth above in "Disclosure of Reserves Data" and elsewhere in
this Annual  Information  Form the  following  definitions  and other notes are
applicable:

1.   "GROSS" means:

     (a)   in relation to our interest in production and reserves, our interest
           (operating  and  non-operating)  before  deduction of royalties  and
           without including any royalty interest of us;

     (b)   in relation to wells,  the total number of wells in which we have an
           interest; and

<PAGE>
                                      14


     (c)   in relation to properties,  the total area of properties in which we
           have an interest.

2.   "NET" means:

     (a)   in relation to our interest in production and reserves, our interest
           (operating   and   non-operating)   after   deduction  of  royalties
           obligations, plus our royalty interest in production or reserves;

     (b)   in relation to wells,  the number of wells  obtained by  aggregating
           our working interest in each of our gross wells; and

     (c)   in relation to our  interest in a property,  the total area in which
           we have an interest multiplied by the working interest we owned.

3.   Columns may not add due to rounding.

4.   The crude oil,  natural gas liquids  and  natural gas  reserves  estimates
     presented in the GLJ Report are based on the  definitions  and  guidelines
     contained in the Canadian Oil and Gas Evaluation Handbook (COGE Handbook).
     A summary of those definitions are set forth below:

     RESERVES CATEGORIES

     Reserves are  estimated  remaining  quantities  of oil and natural gas and
     related substances anticipated to be recoverable from known accumulations,
     from a given date  forward,  based on  analysis of  drilling,  geological,
     geophysical and engineering data; the use of established  technology;  and
     specified economic conditions.

     Reserves are  classified  according to the degree of certainty  associated
     with the estimates.

     (a)   PROVED RESERVES are those reserves that can be estimated with a high
           degree of certainty to be recoverable.  It is likely that the actual
           remaining  quantities  recovered  will exceed the  estimated  proved
           reserves.

     (b)   PROBABLE  RESERVES  are  those  additional  reserves  that  are less
           certain to be recovered than proved  reserves.  It is equally likely
           that the actual  remaining  quantities  recovered will be greater or
           less than the sum of the estimated proved plus probable reserves.

     Other  criteria that must also be met for the  categorization  of reserves
     are provided in the COGE Handbook.

     Each of the reserves  categories (proved and probable) may be divided into
     developed and undeveloped categories:

     (c)   DEVELOPED  RESERVES  are  those  reserves  that are  expected  to be
           recovered  from  existing  wells  and  installed  facilities  or, if
           facilities  have  not  been  installed,  that  would  involve  a low
           expenditure  (for  example,  when compared to the cost of drilling a
           well) to put the reserves on production.  The developed category may
           be subdivided into producing and non-producing.

           (i)   DEVELOPED  PRODUCING  RESERVES  are  those  reserves  that are
                 expected to be recovered from completion intervals open at the
                 time  of  the  estimate.   These  reserves  may  be  currently
                 producing or, if shut-in,  they must have  previously  been on

<PAGE>
                                      15


                 production,  and the date of resumption of production  must be
                 known with reasonable certainty.

           (ii)  DEVELOPED  NON-PRODUCING  RESERVES  are  those  reserves  that
                 either have not been on production, or have previously been on
                 production,  but are shut-in,  and the date of  resumption  of
                 production is unknown.

     (d)   UNDEVELOPED  RESERVES  are those  reserves  expected to be recovered
           from  known  accumulations  where  a  significant  expenditure  (for
           example,  when  compared to the cost of drilling a well) is required
           to render  them  capable  of  production.  They must  fully meet the
           requirements of the reserves  classification  (proved,  probable) to
           which they are assigned.

     In multi-well  pools it may be appropriate to allocate total pool reserves
     between the  developed  and  undeveloped  categories  or to subdivide  the
     developed reserves for the pool between developed  producing and developed
     non-producing.   This  allocation  should  be  based  on  the  estimator's
     assessment as to the reserves that will be recovered from specific  wells,
     facilities  and  completion  intervals  in the pool and  their  respective
     development and production status.

     LEVELS OF CERTAINTY FOR REPORTED RESERVES

     The qualitative  certainty levels referred to in the definitions above are
     applicable to  individual  reserves  entities  (which refers to the lowest
     level  at which  reserves  calculations  are  performed)  and to  reported
     reserves  (which  refers to the  highest  level sum of  individual  entity
     estimates for which  reserves are  presented).  Reported  reserves  should
     target the following  levels of certainty under a specific set of economic
     conditions:

     (a)   at least a 90 per cent  probability  that  the  quantities  actually
           recovered will equal or exceed the estimated proved reserves; and

     (b)   at least a 50 per cent  probability  that  the  quantities  actually
           recovered will equal or exceed the sum of the estimated  proved plus
           probable reserves.

     A  qualitative  measure of the  certainty  levels  pertaining to estimates
     prepared  for the various  reserves  categories  is desirable to provide a
     clearer understanding of the associated risks and uncertainties.  However,
     the majority of reserves  estimates will be prepared  using  deterministic
     methods that do not provide a mathematically  derived quantitative measure
     of  probability.  In  principle,  there  should be no  difference  between
     estimates prepared using probabilistic or deterministic methods.

     Additional  clarification  of certainty  levels  associated  with reserves
     estimates and the effect of aggregation is provided in the COGE Handbook.

5.   FORECAST PRICES AND COSTS

     These  are  prices  and costs  that are  generally  acceptable  as being a
     reasonable  outlook of the  future.  To the extent that there are fixed or
     presently  determinable  future  prices  or costs to which we are  legally
     bound by a contractual or other  obligation to supply a physical  product,
     including those for an extension period of a contract that is likely to be
     extended,  those prices or costs shall be  incorporated  into the forecast
     prices.

<PAGE>
                                      16


     The  forecast  cost and price  assumptions  include  increases in wellhead
     selling  prices and take into  account  inflation  with  respect to future
     operating  and  capital  costs.  Crude oil,  natural  gas and  natural gas
     liquids benchmark reference pricing, as at January 1, 2007,  inflation and
     exchange rates utilized in the GLJ Report were as follows:

<TABLE>
<CAPTION>
                                        SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
                                                   as of December 31, 2006
                                                  FORECAST PRICES AND COSTS


                                OIL                                         EDMONTON LIQUIDS PRICES
             ---------------------------------------------              ---------------------------------
                          Edmonton
                            Par      Hardisty   Cromer      NATURAL
                WTI        Price      Heavy     Medium        GAS
              Cushing    40(degree) 12(degree) 29.3(degree) AECO Gas                            Pentanes   INFLATION   EXCHANGE
             Oklahoma       API        API        API         Price       Propane    Butane       Plus      RATES(1)    RATE(2)
   Year      ($US/bbl)   ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/MMbtu) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/bbl)    %/Year    ($US/$Cdn)
   ----      ---------   ---------- ---------- ----------  ------------ ---------- ---------- ------------   ------    ----------
<S>             <C>       <C>        <C>        <C>          <C>         <C>         <C>        <C>          <C>         <C>
Forecast
2007            62.00      70.25      39.25       61.25        7.20          45.00     56.25      71.75       2.0         0.870
2008            60.00      68.00      40.00       59.25        7.45          43.50     50.25      69.25       2.0         0.870
2009            58.00      65.75      39.75       57.25        7.75          42.00     48.75      67.00       2.0         0.870
2010            57.00      64.50      39.75       56.00        7.80          41.25     47.75      65.75       2.0         0.870
2011            57.00      64.50      40.25       56.00        7.85          41.25     47.75      65.75       2.0         0.870
2012            57.50      65.00      41.50       56.50        8.15          41.50     48.00      66.25       2.0         0.870
2013            58.50      66.25      42.50       57.75        8.30          42.50     49.00      67.50       2.0         0.870
2014            59.75      67.75      43.50       59.00        8.50          43.25     50.25      69.00       2.0         0.870
2015            61.00      69.00      44.25       60.00        8.70          44.25     51.00      70.50       2.0         0.870
2016            62.25      70.50      45.25       61.25        8.90          45.00     52.25      72.00       2.0         0.870
2017            63.50      71.75      46.00       62.50        9.10          46.00     53.00      73.25       2.0         0.870
Thereafter      (3)        (3)        (3)         (3)         (3)            (3)       (3)        (3)         2.0         0.870
</TABLE>
Notes:
(1)  Inflation rates for forecasting prices and costs.
(2)  Exchange  rates used to generate the  benchmark  reference  prices in this
     table.
(3)  Prices escalate 2.0 per cent per year from 2018.

     Weighted  average  actual prices  realized for the year ended December 31,
     2006,  were  $6.97/Mcf  for natural gas,  $66.16/bbl  for light and medium
     crude oil,  $46.90/bbl  for heavy crude oil and $52.63/bbl for natural gas
     liquids.  Only a minor amount of our production is  characterized as heavy
     oil

6.   CONSTANT PRICES AND COSTS

     These  are  actual  prices  and  costs  as at the  effective  date  of the
     estimation, held constant throughout the estimated lives of the properties
     to which the  estimate  applies.  To the extent  that,  there are fixed or
     presently  determinable  future  prices  or costs to which we are  legally
     bound by a contractual or other  obligation to supply a physical  product,
     including those for an extension period of a contract that is likely to be
     extended,  those prices or costs shall be incorporated  into the price for
     future years.

     The constant crude oil and natural gas benchmark reference pricing and the
     exchange rate utilized in the GLJ Report were as follows:

<PAGE>
                                      17


                         SUMMARY OF PRICING ASSUMPTIONS
                             as of December 31, 2006
                            CONSTANT PRICES AND COSTS

<TABLE>
<CAPTION>
                      OIL                                           EDMONTON LIQUIDS PRICES
   ---------------------------------------------              ---------------------------------
                Edmonton
                  Par                  Cromer       NATURAL
      WTI        Price     LLB Crude   Medium         GAS
    Cushing    40(degree)   Oil at   29.3(degree)   AECO Gas                          Pentanes    EXCHANGE
   Oklahoma       API      Hardesty       API         Price     Propane    Butane       Plus       RATE(1)
   ($US/bbl)   ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/MMbtu) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/bbl)    %/Year
   ---------   ---------- ---------- ----------  ------------ ---------- ----------  ----------    ------
  <S>          <C>        <C>        <C>         <C>          <C>        <C>         <C>           <C>
  60.85           67.58     47.62      59.47          6.07       43.25      54.06       71.55      0.8581
</TABLE>
Note:
(1)  The exchange rate used to generate the benchmark  reference prices in this
     table.

7.   FUTURE DEVELOPMENT COSTS

     The  following  table  sets  forth   development  costs  deducted  in  the
     estimation  of  our  future  net  revenue  attributable  to  the  reserves
     categories noted below.

<TABLE>
<CAPTION>
                                                                                           Constant Prices and
                                                 Forecast Prices and Costs                    Costs
                                          ----------------------------------------    ---------------------
                                          Proved Reserves     Proved Plus Probable
                   Year                        (MM$)              Reserves (MM$)      Proved Reserves (MM$)
                   ----                        -----              --------------      ---------------------
     <S>                                       <C>                <C>                 <C>

     2007                                      225.3                 251.7                          225.4
     2008                                      124.6                 173.1                          122.2
     2009                                       64.0                 104.8                           61.6
     2010                                       30.6                  68.9                           28.9
     2011                                       11.1                  34.1                           10.3
     Total: Undiscounted                       549.0                 769.5                          516.6
     Total:  Discounted at 10%/year            429.0                 587.6                          418.9
</TABLE>

     We  expect  to fund  the  development  costs  of the  reserves  through  a
     combination  of cash flow withheld from  distributions,  debt, the sale of
     existing assets and the issuance of Trust Units.

     There can be no  guarantee  that funds will be  available  or that we will
     allocate  funding to develop  all of the  reserves  attributed  in the GLJ
     Report.  Failure to develop those reserves would have a negative impact on
     future cash flow.

     The  interest or other costs of external  funding are not  included in the
     reserves and future net revenue  estimates  and would reduce  reserves and
     future net  revenue to some  degree  depending  upon the  funding  sources
     utilized.  We do not anticipate that interest or other funding costs would
     make development of any property uneconomic.

8.   Estimated  future well  abandonment  costs related to reserves  wells have
     been taken into account by GLJ in  determining  the  aggregate  future net
     revenue therefrom.

9.   Both the  constant  and forecast  price and cost  assumptions  assumed the
     continuance of current laws and regulations.

10.  All factual  data  supplied to GLJ was accepted as  represented.  No field
     inspection was conducted.

11.  THE  ESTIMATES OF FUTURE NET REVENUE  PRESENTED IN THE TABLES ABOVE DO NOT
     REPRESENT FAIR MARKET VALUE.

<PAGE>
                                      18


RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

  The following table sets forth the reconciliation of our net reserves as at
December 31, 2006, using forecast price and cost estimates derived from the GLJ
Report. Net reserves as at December 31, 2006 and as at December 31, 2005 include
working interest reserves plus royalties receivable less royalties payable.

<TABLE>
<CAPTION>
                                                           RECONCILIATION OF
                                                             NET RESERVES
                                                       BY PRINCIPAL PRODUCT TYPE
                                                       FORECAST PRICES AND COSTS

                             LIGHT AND MEDIUM OIL                 HEAVY OIL                      NATURAL GAS
                        -----------------------------   ----------------------------    -----------------------------
                                               Net                            Net                              Net
                                              Proved                         Proved                           Proved
                           Net      Net        Plus        Net     Net        Plus        Net       Net        Plus
                        Proved   Probable    Probable   Proved  Probable    Probable    Proved   Probable    Probable
       Factors          (Mbbl)    (Mbbl)      (Mbbl)    (Mbbl)   (Mbbl)      (Mbbl)     (MMcf)    (MMcf)      (MMcf)
       -------          ------    ------      ------    ------   ------      ------     ------    ------      ------
<S>                     <C>        <C>        <C>       <C>        <C>        <C>      <C>         <C>       <C>
December 31, 2005      101,674     26,139    127,813    2,758      699        3,458        489.5      119.5      609.0

 Extensions                181        366        547       28       54           82          8.5        2.9       11.4
 Improved Recovery(1)    2,321      2,525      4,845       29       12           40         24.1       (1.5)      22.6
 Technical Revisions     1,489     (1,798)      (309)      73       28          101         10.7       (2.2)       8.5
 Discoveries                 8          3         11        0        0            0          0.3        0.1        0.5
 Acquisitions            3,153      1,070      4,223        0        0            0          4.9        4.0        8.9
 Dispositions             (332)      (309)      (641)       0        0            0         (1.3)      (1.5)      (2.9)
 Economic Factors        1,256       (672)       584      115       23          138          4.3        1.2        5.5
 Production             (8,671)         0     (8,671)    (450)       0         (450)       (53.1)       0        (53.1)

December 31, 2006      101,079     27,324    128,402    2,554      816        3,369        487.9       12.5      610.4
</TABLE>

<TABLE>
<CAPTION>
                             NATURAL GAS LIQUIDS                    TOTAL
                        -----------------------------   ----------------------------
                                               Net                            Net
                                              Proved                         Proved
                          Net      Net        Plus        Net     Net        Plus
                        Proved   Probable    Probable   Proved  Probable    Probable
       Factors          (Mbbl)    (Mbbl)      (Mbbl)    (mboe)   (mboe)      (mboe)
       -------          ------    ------      ------    ------   ------      ------
<S>                     <C>         <C>       <C>       <C>       <C>        <C>
December 31, 2005        8,621      2,092     10,713    194,637    48,845     243,482

 Extensions                 88         21        109     1,706        928       2,634
 Improved Recovery(1)      466         81        547     6,835      2,365       9,200
 Technical Revisions       155       (106)        49     3,507     (2,242)      1,265
 Discoveries                10          4         14        75         32         107
 Acquisitions               80         93        173     4,051      1,828       5,879
 Dispositions              (11)       (13)       (24)     (568)      (572)     (1,140)
 Economic Factors           27         (3)        24     2,108       (451)      1,657
 Production             (1,125)         0     (1,125)   (19,089)        -     (19,089)

December 31, 2006        8,310      2,170     10,480    193,262    50,732     243,994
</TABLE>
Note:
(1)  Improved recovery  includes infill drilling  additions of 1,301 Mbbl light
     and medium  oil, 0 Mbbl heavy oil,  23.5 Bcf natural gas and 455 Mbbl NGLs
     total proved; and 2,432 Mbbl light and medium oil, 29 Mbbl heavy oil, 21.8
     Bcf natural gas and 533 Mbbl NGLs total proved plus probable.

<PAGE>
                                      19


<TABLE>
<CAPTION>
                          RECONCILIATION OF CHANGES IN
                    NET PRESENT VALUES OF FUTURE NET REVENUE
                                DISCOUNTED AT 10%
                              TOTAL PROVED RESERVES
                            CONSTANT PRICES AND COSTS

                                                                               Before and After
                                                                                   Tax 2006
PERIOD AND FACTOR                                                                    (M$)
-----------------                                                              ----------------
<S>                                                                                <C>
Estimated Net Present Value at January 1, 2006                                      4,302,000
     Oil and gas sales during the period net of production costs and                 (827,600)
royalties(1)
     Changes due to prices, production costs and royalties related to              (1,115,100)
     forecast production(2)
     Development costs during the period(3)                                           318,800
     Changes in forecast development costs(4)                                        (377,800)
     Changes resulting from extensions and improved recovery(5)                       141,900
     Changes resulting from discoveries(5)                                              1,600
     Changes resulting from acquisitions of reserves(5)                                81,000
     Changes resulting from dispositions of reserves(5)                               (11,275)
     Accretion of discount(6)                                                         430,200
     Net change in income taxes(7)                                                          0
     Changes resulting from technical reserves revisions                               64,700
     All other changes(8)                                                             (12,500)

Estimated Net Present Value at End of Period                                        2,996,000
</TABLE>
Notes:
(1)  Actual  revenues  received  (net of the  realized  cash  gain  on  hedging
     contracts of $29.3 MM) but before  income  taxes,  excluding  interest and
     general and administrative expenses.
(2)  The impact of changes in prices and other  economic  factors on future net
     revenue.
(3)  Actual capital expenditures  relating to the exploration,  development and
     production of oil and gas reserves.
(4)  The change in forecast  development costs for the properties  evaluated at
     the beginning of the period.
(5)  End of period net present value of the related reserves. Improved Recovery
     included Infill Drilling.
(6)  Estimated as 10 per cent of the beginning of period net present value.
(7)  As a royalty trust, the Trust's income tax liability is transferred to the
     its Unitholders.
(8)  Includes the effect of 2006 base cash flow being different from previously
     forecast.

ADDITIONAL INFORMATION RELATING TO RESERVES DATA


PROVED AND PROBABLE UNDEVELOPED RESERVES

Undeveloped  reserves are  attributed by GLJ in accordance  with  standards and
procedures  contained in the COGE  Handbook.  Proved  undeveloped  reserves are
those  reserves  that can be estimated  with a high degree of certainty and are
expected  to  be  recovered  from  known   accumulations  where  a  significant
expenditure  is  required  to  render  them  capable  of  production.  Probable
undeveloped  reserves are those  reserves that are less certain to be recovered
than proved reserves and are expected to be recovered from known  accumulations
where  a  significant  expenditure  is  required  to  render  them  capable  of
production.

In some cases it will take us longer than two years to develop these  reserves.
We plan to develop  the  majority  of the proved  undeveloped  reserves  in the
reserves  evaluation  over the next four years and plan to develop the probable
undeveloped reserves over the next five years.

We manage development activities to ensure facilities and gathering systems are
properly utilized over the facility life which means scheduling  capital over a
longer  period.  We develop  assets in a  methodical  fashion to reduce risk by
technically  assessing  the  results  of one  annual  drilling  program  before
embarking on another drilling program.

<PAGE>
                                      20


SIGNIFICANT FACTORS OR UNCERTAINTIES

We have a significant  amount of proved  undeveloped  reserves  assigned to the
Dawson gas field in  northeast  British  Columbia  and the  Hatton/Horsham  gas
fields in southwest  Saskatchewan.  Sophisticated  and expensive  technology is
required for the Dawson wells to produce.  At the current  prices,  these wells
are economic;  however, should gas prices fall materially, the wells may not be
economic to drill. Similarly,  the low rate gas wells in southwest Saskatchewan
may also be uneconomic in a low price environment.

OTHER OIL AND GAS INFORMATION

Our  portfolio of properties as at December 31, 2006 includes both unitized and
non-unitized oil and natural gas production. In general, the properties contain
long life, low decline rate reserves and include interests in several major oil
and gas fields.

PRINCIPAL PROPERTIES

The following is a description  of our principal oil and natural gas properties
as at December  31,  2006.  Reserves  amounts are stated at December  31, 2006,
based on escalated  cost and price  assumptions  as evaluated in the GLJ Report
prepared  by GLJ  (see  "Statement  of  Reserves  Data  and  Other  Oil and Gas
Information").  Information  in respect of gross and net acres and well  counts
are as at December 31, 2006,  and  information  in respect of production is for
the year ended December 31, 2006 except where indicated  otherwise.  Due to the
fact  that we  have  been  active  at  acquiring  additional  interests  in our
principal properties,  the working interest share and interest in gross and net
acres and wells as at December  31,  2006 may not  directly  correspond  to the
stated  production for the year which only includes  production  since the date
the  interests  were  acquired by us. The  estimates of reserves and future net
revenue for individual  properties may not reflect the same confidence level as
estimates  of reserves  and future net revenue for all  properties,  due to the
effects of aggregation.

All of the  properties  described  below are  located in the  Western  Canadian
Sedimentary  Basin and  within the  Canadian  provinces  of  British  Columbia,
Alberta or Saskatchewan.  The properties represent 52 per cent of the total net
proved plus probable  reserves as assigned by GLJ in the GLJ Report.  There are
no other  properties which  individually  account for more than 4.2 per cent of
the total net proved  plus  probable  reserves  as  assigned  by GLJ in the GLJ
Report. There are no material properties to which reserves have been attributed
which are capable of  producing  but which are not  producing  and there are no
material  statutory  or  mandatory  relinquishments,  surrenders,  back-ins  or
changes in ownership provisions.


<PAGE>
21


                           Net Reserves and Net Production
                     --------------------------------------------
                                                      Proved plus
                        2006                            Probable
                     Production         Proved          Reserves
                       (boe/d)      Reserves (mboe)      (mboe)
                       -------      ---------------      ------
Redwater               3,484           19,698           23,592
Ante Creek             3,304           15,056           19,342
Dawson                 2,670           13,646           18,356
Jenner                 2,622           11,296           14,030
Lougheed               2,353            5,510            6,903
Hatton                 2,347            8,431            9,692
Weyburn Unit           1,808            8,836           13,284
Pouce Coupe            1,604            3,047            3,574
NPCU No. 1             1,522           12,091           13,875
Prestville             1,455            3,238            4,214

REDWATER

The Redwater  property is located in central  Alberta.  We are the operator and
own an average  land  interest of 89 per cent.  Oil and  solution  gas are both
processed at an operated central facility. During 2006, net production from the
area averaged 3,484 boe/d of oil,  natural gas and natural gas liquids from 378
net wells.  During  2006,  2 new wells were  drilled.  GLJ  assigned net proved
reserves of 19,698 mboe and net proved plus probable reserves of 23,592 mboe of
oil, natural gas and natural gas liquids to this area, or 9.7 per cent of total
net proved plus probable reserves.

ANTE CREEK

The Ante Creek  property is located in northwest  Alberta.  We are the operator
and own an average land  interest of 97 per cent.  Oil  production is processed
through two operated  facilities  while the gas is routed through a third party
plant.  During 2006, net production  from the area averaged 3,304 boe/d of oil,
natural gas and natural gas liquids  from 147 net wells.  During  2006,  14 new
wells were  drilled.  GLJ assigned  net proved  reserves of 15,056 mboe and net
proved plus  probable  reserves of 19,342 mboe of oil,  natural gas and natural
gas  liquids to this area,  or 7.9 per cent of total net proved  plus  probable
reserves.

DAWSON

The Dawson  property  is  located in  northeast  British  Columbia.  We are the
operator  and own an average land  interest of 89 per cent.  We operate a large
area compression  facility where the natural gas and liquids are then sent to a
third party operated facility for sweetening.  During 2006, net production from
the area  averaged  2,670 boe/d of natural gas and natural gas liquids  from 62
net wells.  During  2006,  10 new wells were  drilled.  GLJ assigned net proved
reserves of 13,646 mboe and net proved plus probable reserves of 18,356 mboe of
natural gas and natural gas liquids to this area,  or 7.5 per cent of total net
proved plus probable reserves.

JENNER

The Jenner property is located in southeast Alberta.  There is a combination of
operated and non operated acreage with an average land interest of 87 per cent.
We operate all four major gas  compression  and  dehydration  facilities in the
area. During 2006, net production from the area averaged 2,622 boe/d of natural
gas from 758 net wells.  During 2006, 58 new wells were  drilled.  GLJ assigned
net proved  reserves of 11,296 mboe and net proved  plus  probable  reserves of
14,030  mboe of natural  gas to this area,  or 5.8 per cent of total net proved
plus probable reserves.

<PAGE>
                                      22


LOUGHEED

The Lougheed property is located in southeast Saskatchewan. We are the operator
and own an average land  interest of 78 per cent.  Production  is handled by an
operated  battery and gas plant.  During  2006,  net  production  from the area
averaged 2,353 boe/d of oil and natural gas liquids from 114 net wells.  During
2006,  six new wells were  drilled.  GLJ assigned net proved  reserves of 5,510
mboe and net proved plus probable reserves of 6,903 mboe of oil and natural gas
liquids  to this  area,  or 2.8 per  cent of total  net  proved  plus  probable
reserves.

HATTON

The  Hatton  property  is  located  in  southwest  Saskatchewan.   There  is  a
combination of operated and non operated  acreage with an average land interest
of  44  per  cent.  The  operated   production  flows  through  three  operated
compression and dehydration  facilities  where our working interest ranges from
50 to 100 per cent.  During 2006, net  production  from the area averaged 2,347
boe/d of  natural  gas from 420 net  wells.  During  2006,  19 new  wells  were
drilled.  GLJ  assigned  net proved  reserves of 8,431 mboe and net proved plus
probable reserves of 9,692 mboe of natural gas to this area, or 4.0 per cent of
total net proved plus probable reserves.

WEYBURN UNIT

The  Weyburn  unit is located in  southeast  Saskatchewan.  EnCana  Corporation
operates the unit and we have a working  interest of 6.95 per cent. The unit is
currently  undergoing a CO2 flood for enhanced  oil  recovery.  During 2006 net
production from the unit averaged 1,808 boe/d of oil from 50 net wells.  During
2006, 39 new wells were drilled. GLJ assigned net proved reserves of 8,836 mboe
and net proved  plus  probable  reserves  of 13,284 mboe of oil and natural gas
liquids  to this  unit,  or 5.4 per  cent of total  net  proved  plus  probable
reserves.

POUCE COUPE

The Pouce Coupe property is located in northwest  Alberta.  We are the operator
and own an average  land  interest of 76 per cent.  The sweet gas is  processed
through  an  operated  gas  plant  and the  sour  gas  flows  to a third  party
processing  plant.  During 2006,  net  production  from the area averaged 1,604
boe/d of oil,  natural gas and natural  gas liquids  from 40 net wells.  During
2006,  two new wells were  drilled.  GLJ assigned net proved  reserves of 3,047
mboe and net proved plus  probable  reserves of 3,574 mboe of oil,  natural gas
and natural gas liquids to this area,  or 1.5 per cent of total net proved plus
probable reserves.

NPCU NO. 1

The North Pembina Cardium Unit No. 1 is located in central Alberta.  We are the
operator and own a 45.57 per cent interest in the unit. Production is processed
through two operated oil  treatment  facilities  and one operated  solution gas
plant.  During 2006, net production  from the unit averaged 1,522 boe/d of oil,
natural gas and natural gas liquids from 167 net wells.  During 2006, three new
wells were  drilled.  GLJ assigned  net proved  reserves of 12,091 mboe and net
proved plus  probable  reserves of 13,875 mboe of oil,  natural gas and natural
gas  liquids to this unit,  or 5.7 per cent of total net proved  plus  probable
reserves.

PRESTVILLE

The Prestville  property is located in northwest  Alberta.  We are the operator
and own a 100 per cent working  interest in  production  and  reserves.  Oil is
processed at an operated  battery while the solution gas flows to a third party
processor.  During 2006, net  production  from the area averaged 1,455 boe/d of

<PAGE>
                                      23


oil,  natural gas and natural gas liquids from 11 net wells.  During 2006,  two
new wells were drilled.  GLJ assigned net proved reserves of 3,238 mboe and net
proved plus probable reserves of 4,214 mboe of oil, natural gas and natural gas
liquids  to this  area,  or 1.7 per  cent of total  net  proved  plus  probable
reserves.

OIL AND GAS WELLS

The following table sets forth the number and status of wells in which we had a
working interest as at December 31, 2006.

<TABLE>
<CAPTION>
                                     Oil Wells                                Natural Gas Wells
                      -----------------------------------------    ---------------------------------------
                           Producing            Non-Producing            Producing           Non-Producing
                           ---------            -------------            ---------           -------------
                       Gross       Net        Gross        Net       Gross        Net      Gross       Net
                       -----       ---        -----        ---       -----        ---      -----       ---
<S>                    <C>       <C>         <C>           <C>      <C>        <C>         <C>         <C>
Alberta                4,037     1,503       1,073         155       3,981      1,731        203        45
British Columbia         126         3          24           -         234         68         41        14
Saskatchewan           1,956       696         283          83       5,110        740         64        30
Manitoba                 552       120          18           3           -          -          -         -
                       -----     -----       -----         ---       -----      -----        ---        --
Total                  6,671     2,322       1,398         241       9,325      2,539        308        89
                       =====     =====       =====         ===       =====      =====        ===        ==
</TABLE>

PROPERTIES WITH NO ATTRIBUTABLE RESERVES

The following table sets out our  undeveloped  land holdings as at December 31,
2006.

                                            Undeveloped Acres
                                          ---------------------
                                          Gross           Net
                                        ---------       -------

          Alberta                         670,910       284,423
          British Columbia                132,617        81,732
          Manitoba                          1,120           796
          Northwest Territories           276,262        27,881
          Saskatchewan                    279,014       126,421
                                        ---------       -------
          Total                         1,359,922       521,253
                                        =========       =======

We currently have no material work  commitments on these lands.  We expect that
approximately  68,000 net acres of our undeveloped land holdings will expire by
December 31, 2007.


FORWARD CONTRACTS

We are exposed to market risks resulting from fluctuations in commodity prices,
foreign exchange rates and interest rates in the normal course of operations. A
variety  of  derivative   instruments  are  used  to  reduce  our  exposure  to
fluctuations in commodity prices, foreign exchange rates and interest rates. We
are  exposed to losses in the event of default by the  counterparties  to these
derivative  instruments.  We manage this risk by  diversifying  our  derivative
portfolio among a number of financially sound  counterparties.  For information
in relation to marketing  arrangements,  see "Other Oil and Gas  Information  -
Marketing Arrangements".

We have a hedging  program  under which  financial  and physical  hedges can be
entered  into in respect of  commodity  prices and  foreign  currency  exchange
rates.  The program  permits hedging of up to 70 per cent of our forecasted oil
and  natural  gas  liquids  production  for up to 24 months . With  respect  to
natural gas  hedging,  the program  permits the hedging of up to 70 per cent of
our forecasted natural gas production for up to 24 months and up to 35 per cent
of forecasted  natural gas production for the 36 month period thereafter (years
three to five in the future).  The above limits are  restricted to a maximum of
55 per cent on a boe basis  for up to 24 months  and up to 15 per cent on a boe
basis for the 36 month period  thereafter  (years three to five in the future).
The program  allows the sale of upside  participation  only to the extent of 25

<PAGE>
                                      24


per cent of volumes beyond a three month period at a price which is 20 per cent
above the futures price and 50 per cent of volumes  within a three month period
at a price which is 10 per cent above the future price.

A summary of financial and physical  contracts in respect of hedging activities
can be found in Note 11  "Financial  Instruments"  to our audited  consolidated
financial statements for the year ended December 31, 2006 and under the heading
"Risk  Management  and Hedging" in our  management  discussion and analysis and
results of  operations  for the year ended  December  31,  2006 which have been
filed on SEDAR at  WWW.SEDAR.COM,  both sections of which are  incorporated  in
this Annual Information Form by reference.

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

The following table sets forth information  respecting  future  abandonment and
reclamation costs for surface leases, wells,  facilities and pipelines which we
expect to incur for the periods indicated.

<TABLE>
<CAPTION>
                                      Abandonment and Reclamation    Abandonment and Reclamation
                                        Costs escalated at 2.0%        Costs escalated at 2.0%
                                             Undiscounted                 Discounted at 10%
                                                 ($MM)                          ($MM)
                                      ---------------------------    ---------------------------
<S>                                           <C>                              <C>
Total as at December 31, 2006                 1,042.6                          102.5
Anticipated to be paid in 2007                    4.6                            4.2
Anticipated to be paid in 2008                    5.0                            4.2
Anticipated to be paid in 2009                    4.8                            3.6
</TABLE>

We will be liable for our share of ongoing  environmental  obligations  and for
the ultimate  reclamation of the  properties  held by us upon  abandonment.  We
estimate  that we have  6,153 net  wells  which are  subject  to  environmental
reclamation obligations.  Ongoing environmental  obligations are expected to be
funded out of cash flow and any  balance  available  in our  reclamation  fund.

We have a reclamation fund to pay future asset retirement obligations costs. We
currently estimate that the future environmental and reclamation obligations in
respect of our properties will be  approximately  $1,043 million  calculated by
escalating  costs at two per cent per year  (reflected  in the 2006  financials
statements as an asset  retirement  obligation of $177.3 million  calculated by
escalating  costs at two per cent per year and discounting at a blended rate of
6.5 per cent).  The Board of Directors of ARC Resources has approved  voluntary
contributions to our reclamation fund over a twenty year period that results in
minimum  annual  contributions  of $6.0 million ($6.0 million in 2005) based on
properties  owned as at December 31,  2006.  During  2006,  $5.7 million  ($4.6
million for 2005) of actual  expenditures  were charged against the reclamation
fund resulting in net  contributions for the year of $1.3 million ($2.2 million
in 2005).

In  addition  the  Trust  has  committed  to  a  restricted  reclamation  trust
associated with the Redwater property  acquired in the Acquisition  pursuant to
which ARC Resources  has agreed to  contribute  to such trust  certain  minimum
amounts,  totalling  approximately  $110 million over a 50 year period, to fund
future  environmental  and  reclamation  obligations in respect of the Redwater
properties,  or to expend certain  minimum amounts  towards  discharging  these
obligations. The restricted contribution commenced in 2006 for $6.1 million and
continues at a declining rate through 2055.

We estimate  the costs to abandon  and  reclaim  all our shut in and  producing
wells, facilities, gas plants, pipelines, batteries and satellites. No estimate
of salvage value is netted against the estimated cost. Our model for estimating
the amount and timing of future  abandonment and reclamation  expenditures  was
created on an operating area level.  Estimated  expenditures for each operating
area are based on the Alberta Energy Utilities Board  methodology which details
the cost of abandonment and reclamation in eight specific  geographic  regions.

<PAGE>
                                      25


Each region was  assigned  an average  cost per well to abandon and reclaim the
wells in that area.

Abandonment  and  reclamation  costs have been estimated over a 61 year period.
Facility  reclamation  costs are scheduled to be incurred in the year following
the end of the reserves life of its associated reserve.

The  additional  liability  associated  with  well,  pipelines  and  facilities
reclamation  costs  which were not  deducted  by GLJ in  estimating  future net
revenue in the GLJ Report are $799.6 million  (escalating costs at two per cent
and  undiscounted)  and  $6.5  million  (escalating  costs  at two per cent and
discounted at 10 per cent).  Only the abandonment  costs  associated with wells
with reserves were deducted by GLJ in estimating future net revenue.

TAX HORIZON

As  a  result  of  our  tax  efficient  structure,  annual  taxable  income  is
transferred  from our  operating  entities  to the  Trust and from the Trust to
Unitholders.  This is  primarily  accomplished  through  the  deduction  by our
operating  entities of the Royalties on underlying  oil and gas  properties and
the  deduction  of interest on the Long Term Notes.  Absent the  Government  of
Canada's tax proposals  discussed below, it can be expected that minimal income
taxes  would be  incurred by the Trust or its  operating  entities  provided we
maintain this  organizational tax structure.  However,  annual operating income
retained  to pay a portion  of capital  expenditures  or used to repay debt may
result in income tax liabilities within ARC Resources from time to time.

On  October  31,  2006,  the  Government  of  Canada  announced  tax  proposals
pertaining to taxation of  distributions  paid by Trusts.  The proposals  would
result in a  two-tiered  tax  structure  whereby  distributions  would first be
subject  to a 31.5 per cent tax (the  proposed  tax rate for 2011) at the Trust
level and then investors  would be subject to tax equivalent to the taxation on
an eligible  dividend.  If enacted,  the proposals would apply to the Trust and
its  Unitholders  effective  January 1, 2011.  For more  information,  on these
proposals,  see  "Proposed  Federal Tax Changes"  and "Risk  Factors - Proposed
Federal Tax Changes".

CAPITAL EXPENDITURES

The following tables summarize capital  expenditures (net of incentives and net
of certain  proceeds  and  including  capitalized  general  and  administrative
expenses) related to our activities for the year ended December 31, 2006:

                                                    2006
                                                    $MM
                                              -----------------
           Corporate acquisition costs(1)            16.6
           Property acquisition costs(2)
                Proved properties                   107.4
                Undeveloped properties                7.8
           Exploration costs(3)                      49.4
           Development costs(4)                     312.5
           Corporate costs                            2.6
                                              -----------------
           Total                                    496.3
                                              =================
Notes:
(1)  Represents total consideration for the acquisition transactions, including
     fees,  but is prior to the  related  future  income tax  liability,  asset
     retirement obligation and working capital assumed on acquisition.
(2)  Represents acquisition costs net of dispositions and property swaps.
(3)  Costs of land acquired,  geological and geophysical  capital  expenditures
     and drilling costs for 2006 exploration wells drilled.

<PAGE>
                                      26


(4)  Development and facilities capital expenditures.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following  table sets forth the gross and net  exploratory  and development
wells that we participated in during the year ended December 31, 2006:

<TABLE>
<CAPTION>
                            EXploratory Wells       Development Wells             Total
                            ----------------       -------------------      ---------------
                            Gross        Net       Gross           Net      Gross       Net
                            -----        ---       -----           ---      -----       ---
<S>                         <C>          <C>       <C>           <C>        <C>        <C>
Light and Medium Oil           12        6.9         176          74.7       188       81.6
Heavy Oil                       0        0.0          12           0.0        12        0.0
Natural Gas                    31        4.8         478         168.8       508      173.6
Service                         0        0.0          14           4.6        14        4.6
Dry                             6        3.4           6           0.1        12        3.6
                               --       ----         ---         -----       ---      -----
Total:                         49       15.2         686         248.3       735      263.4
                               ==       ====         ===         =====       ===      =====
</TABLE>

We have an  extensive  capital  program of $360 million  planned for 2007.  The
primary components of our program are as follows.

Our planned  $54.7  million  program in Dawson  includes  the  drilling of four
vertical and four horizontal  development and delineation wells. In addition to
drilling  activities,  capital will also be devoted to  expanding  the existing
infrastructure.

In Ante Creek,  our planned $30.3 million capital program includes the drilling
of nine development wells, one exploration well, optimization on existing wells
and waterflood facility upgrades.

In Delburne,  we plan to drill 26 shallow wells and install new  facilities and
compression  as part of the Natural Gas from Coal program.  The area capital of
$12.8 million also plans to include the drilling of four Viking infill wells.

In the  Jenner  and  Crane  Lake  areas  of  Southeast  Alberta  and  Southwest
Saskatchewan,  we plan to  drill  105  gross  shallow  gas  wells  and  perform
optimization on 55 existing shallow gas wells at a cost of $19.4 million.

PRODUCTION ESTIMATES

The  following  table sets out the volume of our  production  estimated for the
year ended  December  31, 2007 which is reflected in the estimate of future net
revenue disclosed in the tables contained under "Statement of Reserves Data and
Other Oil and Gas Information - Disclosure of Reserves Data".

<TABLE>
<CAPTION>
                                 Light and                                               Natural Gas
                                 Medium Oil        Heavy Oil         Natural Gas           Liquids             Boe
                                  (bbls/d)         (bbls/d)             (Mcfpd)            (bbls/d)         (boe/d)
                             ---------------   --------------    ------------------    --------------  ---------------
                              Gross      Net   Gross      Net      Gross        Net    Gross      Net   Gross      Net
                              -----      ---   -----      ---      -----        ---    -----      ---   -----      ---
<S>                          <C>      <C>      <C>      <C>      <C>        <C>        <C>      <C>    <C>      <C>
Proved Producing             25,503   21,815     982      984    163,304    133,023    3,605    2,588  57,308   47,557
Proved Developed Non-
Producing                       584      477       0        0      4,947      3,613       58       41   1,467    1,120
Proved Undeveloped            1,885    1,560       0        0      8,356      6,328      264      185   3,542    2,799
                             ------   ------   -----    -----    -------    -------    -----    -----  ------   ------
Total Proved                 27,973   23,852     982      984    176,607    142,964    3,927    2,813  62,317   51,476
Total Probable                1,108      823      46       42      5,564      4,177      132       93   2,213    1,655
                             ------   ------   -----    -----    -------    -------    -----    -----  ------   ------
Total Proved Plus
Probable                     29,081   24,674   1,028    1,026    182,171    147,141    4,059    2,907  64,530   53,131
                             ======   ======   =====    =====    =======    =======    =====    =====  ======   ======
</TABLE>
<PAGE>
                                      27


PRODUCTION HISTORY

The  following  tables  summarize   certain   information  in  respect  of  our
production,  product prices received,  royalties paid,  operating  expenses and
resulting netback for the periods indicated below:

<TABLE>
<CAPTION>
                                                                     Quarter Ended
                                                                         2006
                                                   ---------------------------------------------------  Year Ended
(6:1)                                              Mar. 31     June 30      Sept. 30       Dec. 31         2006
                                                   -------     -------      --------       -------       -------
<S>                                               <C>          <C>           <C>           <C>           <C>
Average Daily Production(1)
  Light and Medium Crude Oil (bbl/d)               28,300       26,501        27,670        28,226        27,674
  Heavy Oil (bbl/d)                                 1,351        1,304         1,438         1,379         1,368
  Gas (MMcfpd)                                    184,974      178,504       173,427       179,483       179,067
  NGLs (bbl/d)                                      4,120        4,247         4,166         4,144         4,170
  Combined (boe/d)                                 64,600       61,803        62,178        63,663        63,056

Average Net Production Prices Received
  Light and Medium Crude Oil ($/bbl)                60.67        72.74         72.64         59.09         66.16
  Heavy Oil ($/bbl)                                 35.67        53.98         56.34         41.20         46.90
  Gas ($/Mcf)                                        8.40         6.35         6.10          6.99          6.97
  NGLs ($/bbl)                                      52.92        54.44         56.60         46.52         52.63
  Combined ($/boe)                                  54.86        54.54         54.59         49.95         53.46

Royalties Paid
  Light and Medium Crude Oil ($/bbl)                 9.68        11.84         12.25         9.50          10.80
  Heavy Oil ($/bbl)                                  4.53         5.65         5.71          3.56          4.86
  Gas ($/Mcf)                                        1.93         1.21         1.00          1.30          1.37
  NGLs ($/bbl)                                      13.27        15.74         14.41         12.86         14.08
  Combined ($/boe)                                  10.71         9.78         9.34          8.80          9.66

Operating Expenses (2)(3)
  Light and Medium Crude Oil ($/bbl)                10.09        11.21         12.61         12.33         11.51
  Heavy Oil ($/bbl)                                 11.97         9.57         7.26          14.10         10.63
  Gas ($/Mcf)                                        0.96         0.44         0.91          1.01          0.96
  NGLs ($/bbl)                                       6.21         7.22         7.46          7.83          7.49
  Combined ($/boe)                                   7.80         8.20         8.82          9.13          8.49

Transportation Paid
  Light and Medium Crude Oil ($/bbl)                 0.05         0.16         0.13          0.19          0.14
  Heavy Oil ($/bbl)                                  1.02         1.16         0.44          0.85          0.86
  Gas ($/Mcf)                                        0.20         0.20         0.19          0.19          0.19
  NGLs ($/bbl)                                       0.00         0.00         0.00          0.00          0.00
  Combined ($/boe)                                   0.61         0.66         0.60          0.64          0.63

(Gain)/Loss on Commodity and Foreign
Exchange Contracts
  Light and Medium Crude Oil ($/bbl)                (0.84)        0.81        (0.06)        (0.04)        (0.05)
  Heavy Oil ($/bbl)                                  0.00         0.00         0.00          0.00          0.00
  Gas ($/Mcf)                                        0.05         0.57         0.61          0.60          0.45
  NGLs ($/bbl)                                       0.00         0.00         0.00          0.00          0.00
  Combined ($/boe)                                  (0.24)        2.00         1.67          1.68          1.27

Netback Received(4)
  Light and Medium Crude Oil ($/bbl)(5)              4.01        50.34         47.59         37.03         43.66
  Heavy Oil ($/bbl)                                 18.15        37.60         42.93         22.69         30.55
  Gas ($/Mcf)                                        5.36         4.57         4.61          5.09          4.90
  NGLs ($/bbl)                                      33.44        31.48         34.73         25.83         31.06
  Combined ($/boe)                                  35.50        37.90         37.50         33.05         35.95
</TABLE>
Notes:
(1)  Before deduction of royalties.
(2)  Operating  expenses are composed of direct costs  incurred to operate both
     oil and gas wells.  A number of  assumptions  have been made in allocating
     these costs between oil, natural gas and natural gas liquids production.

<PAGE>
                                      28


(3)  Operating  recoveries  associated  with operated  properties were excluded
     from  operating  costs and  accounted  for as a  reduction  to general and
     administrative costs.
(4)  Netbacks  are  calculated  by  subtracting  royalties,   operating  costs,
     transportation  costs,  and losses/gains on commodity and foreign exchange
     contracts from revenues.
(5)  Heavy oil net backs have been included in  light/medium  oil netbacks,  as
     only a minor amount of our production comes from heavy oil.

No  property  accounts  for more  than 7 per cent of the  production  disclosed
above.  For more  information,  see "Other Oil and Gas  Information - Principal
Properties".

MARKETING ARRANGEMENTS

NATURAL GAS

During 2006,  we continued our  marketing  strategy of increasing  the level of
direct control and diversification of marketing and transportation arrangements
for our natural gas production.

The  average  natural  gas price we  received  during 2006 was $6.97 per Mcf as
compared to $8.96 per Mcf for 2005.  This price was  achieved  with a portfolio
mix that on average  through the year  received AECO index based pricing for 65
per cent,  aggregator netback prices for 24 per cent, and Chicago Index Pricing
for 11 per cent of total production.

To manage natural gas price volatility and to stabilize the revenue stream, our
natural gas portfolio is directed towards maintaining balanced exposure to U.S.
and Canadian markets with market sensitive and hedgeable pricing terms, as well
as aggregator  netback  arrangements.  We also strive for a high utilization of
contracted pipeline and processing capacity.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our liquids production in 2006 was comprised of approximately 40 per cent light
quality  crude oil (greater  than  35(degree)API),  44 per cent medium  quality
crude  oil  (25  to  35  API),  4 per  cent  heavy  quality  crude  (less  than
25(degree)API),  4 per cent  condensate  and 10 per cent  natural gas  liquids.
During 2006,  our average sales prices were $66.16 per bbl for light and medium
crude oil, $46.90 per bbl for heavy crude oil and $52.63 per bbl of natural gas
liquids;  these  prices  compare to 2005 prices of $62.18 per bbl for light and
medium  crude oil,  $42.63  per bbl for heavy  crude oil and $49.91 per bbl for
natural gas liquids.  Our crude oil is sold under contracts of varying terms of
up to one year,  based on market sensitive  pricing terms.  Natural gas liquids
are sold under annual  arrangements.  Industry pricing benchmarks for crude oil
and natural gas liquids are continuously monitored to ensure optimal netbacks.

ACQUISITIONS AND DISPOSITIONS

We completed property acquisitions,  net of dispositions,  of $115.2 million in
2006. We also completed one corporate  acquisition for total  consideration  of
$16.6 million resulting in total acquisitions,  net of dispositions,  of $131.8
million in the year.

                         SHARE CAPITAL OF ARC RESOURCES

COMMON SHARES

ARC Resources has authorized for issuance an unlimited  number of common shares
of which  1,000,111  common shares are issued and  outstanding  and held by the
Trust.  The voting of such shares is delegated to ARC Resources under the Trust
Indenture.  The holders of common  shares are  entitled to notice of, to attend
and to one  vote per  share  held at any  meeting  of the  shareholders  of ARC
Resources;  to receive  dividends as and when declared by Board of Directors of
ARC  Resources  on  the  common  shares  as  a  class,  and  subject  to  prior

<PAGE>
                                      29


satisfaction of all preferential  rights to dividends attached to all shares of
other classes;  and in the event of any liquidation,  dissolution or winding-up
of ARC Resources,  whether voluntary or involuntary,  or any other distribution
of the  assets of ARC  Resources  among its  shareholders  for the  purpose  of
winding-up its affairs,  and subject to prior  satisfaction of all preferential
rights to return of  capital  on  dissolution  attached  to all shares of other
classes of shares of ARC Resources  ranking in priority to the common shares in
respect of return of capital on dissolution,  to share rateably,  together with
the shares of any other class of shares of ARC Resources  ranking  equally with
the common  shares in respect  of return of  capital  on  dissolution,  in such
assets of ARC Resources as are available for distribution.

EXCHANGEABLE SHARES

ARC Resources is authorized to issue an unlimited number of Exchangeable Shares
of which, as at December 31, 2006, 1,433,132 were outstanding. The Exchangeable
Shares rank prior to the common shares of ARC Resources,  the second  preferred
shares of ARC Resources and any other shares ranking junior to the Exchangeable
Shares with respect to the payment of dividends and the  distribution of assets
in the event of the  liquidation,  dissolution  or winding-up of ARC Resources;
provided  that   notwithstanding  such  ranking  ARC  Resources  shall  not  be
restricted in any way from repaying  indebtedness of ARC Resources to the Trust
from time to time. The  Exchangeable  Share provisions have been filed on SEDAR
at WWW.SEDAR.COM.

The  Exchangeable  Shares  provide  holders  with a security  having  economic,
ownership  and voting  rights which are  substantially  equivalent  to those of
Trust Units. As at December 31, 2006 the Exchange Ratio was 2.01251 Trust Units
per Exchangeable  Share.  Holders of Exchangeable  Shares will not receive cash
distributions,  rather  the  Exchangeable  Shares are  maintained  economically
equivalent to the Trust Units by the progressive increase in the Exchange Ratio
to reflect  distributions  paid by the Trust to Unitholders.  The  Exchangeable
Shares are provided equivalent voting rights as those of Unitholders through an
agreement (the Exchangeable Share Voting and Exchange Trust Agreement) pursuant
to which the holders of  Exchangeable  Shares can direct the Trustee to vote at
meetings of Unitholders. The holders of Exchangeable Shares are further assured
of the delivery of Trust Units by us in  satisfaction of the obligations of ARC
Resources under the Exchangeable  Share terms through the provisions of another
agreement  (the   Exchangeable   Share  Support   Agreement).   Copies  of  the
Exchangeable  Share Voting and Exchange  Trust  Agreement and the  Exchangeable
Share Support Agreement have been filed on SEDAR at WWW.SEDAR.COM.

Computershare  Trust  Company  of  Canada  acts as the  transfer  agent for the
Exchangeable Shares.

Holders of Exchangeable Shares are entitled to receive, as and when declared by
the Board of Directors in its sole  discretion,  from time to time,  cumulative
preferential  cash dividends in an amount per share equal to the Exchange Ratio
on the  preceding  business day  multiplied by the fair market value of a Trust
Unit as at the preceding  business day (determined on the basis of the weighted
average  price of the Trust Unit on the TSX for the 10 trading  days  preceding
that date).  It is not  anticipated  that dividends will be declared or paid on
the  Exchangeable  Shares,  however the Board of Directors has the right in its
sole  discretion  to do so,  and if so,  the  Exchange  Ratio  would be reduced
accordingly to reflect such dividends.

ARC Resources  will not,  without  obtaining the approval of the holders of the
Exchangeable Shares:

     (a)   pay any  dividend  on the  common  shares of ARC  Resources,  second
           preferred shares of ARC Resources or any other shares ranking junior
           to the Exchangeable  Shares,  other than the stock dividends payable
           in common shares of ARC  Resources or any such other shares  ranking
           junior to the Exchangeable Shares;

<PAGE>
                                      30


     (b)   redeem,  purchase or make any capital distribution in respect of the
           common  shares  of ARC  Resources,  second  preferred  shares of ARC
           Resources or any other  shares  ranking  junior to the  Exchangeable
           Shares;

     (c)   redeem or purchase any other shares of ARC Resources ranking equally
           with  respect to the  payment  of  dividends  or on any  liquidation
           distribution; or

     (d)   issue any shares, other than Exchangeable  Shares,  second preferred
           shares of ARC  Resources or common  shares of ARC  Resources,  which
           rank superior to the Exchangeable Shares with respect to the payment
           of dividends or on any liquidation distribution.

Notwithstanding the foregoing,  the restrictions in paragraphs (a), (b) and (c)
above shall only be  applicable  if dividends  which have been  declared on the
outstanding Exchangeable Shares have not been paid in full.

The  Exchangeable   Share  Provisions  entitle  the  holder  to  exchange  each
Exchangeable  Share at any time  into the  number of Trust  Units  equal to the
Exchange Ratio then in effect. The Exchange Ratio is determined by reference to
the  distributions  paid on Trust Units in a given month and the current market
price of the Trust Units.

SECOND PREFERRED SHARES

ARC  Resources  also has  authorized  an unlimited  number of Second  Preferred
Shares  which  may at any time or from  time to time be  issued  in one or more
series.  Before any shares of a  particular  series  are  issued,  the Board of
Directors of ARC Resources shall, by resolution,  fix the number of shares that
will form such series and shall,  subject to the limitations set out herein, by
resolution fix the designation, rights, privileges, restrictions and conditions
to be  attached  to the  Second  Preferred  Shares of such  series.  The Second
Preferred Shares of each series shall rank behind the  Exchangeable  Shares and
on a parity with the Second Preferred Shares of every other series with respect
to accumulated dividends and return of capital. The Second Preferred Shares are
entitled to a  preference  over the Common  Shares and over any other shares of
ARC Resources  ranking  junior to the Second  Preferred  Shares with respect to
priority in the payment of dividends and in the  distribution  of assets in the
event of the liquidation,  dissolution or winding-up of ARC Resources,  whether
voluntary  or  involuntary,  or any  other  distribution  of the  assets of ARC
Resources among its shareholders for the purpose of winding-up its affairs.  As
at the date  hereof,  no  Second  Preferred  Shares  have  been  issued  or are
outstanding.

                   OTHER INFORMATION RELATING TO OUR BUSINESS

BORROWING

We borrow  funds from time to time to finance the purchase of  properties,  for
capital  expenditures  or for other  financial  obligations or  expenditures in
respect of properties  held by us or for working  capital  purposes.  We have a
policy  relating  to  borrowing  which  requires  a  quarterly   assessment  by
management,  subject to review by the Board of Directors of ARC  Resources,  of
the  appropriateness  of borrowing levels. We have granted security in priority
to the Royalties to secure the loan of such funds.

Debt  service  charges  on  borrowed  funds  attributable  to  our  properties,
including  funds  borrowed  by our  subsidiaries  from us,  will be deducted in
computing royalty income.  The debt repayment will be scheduled to minimize any
income tax payable by ARC Resources.

<PAGE>
                                      31


At  December  31, 2006 we had a $572  million  secured,  extendible,  financial
covenant based three year syndicated credit facility that expires in March 2009
and a $25  million  demand  working  capital  facility  in  addition to US $224
million of senior secured notes  outstanding.  The credit facilities and senior
secured notes contain provisions which restrict the ability of ARC Resources to
pay  Royalties  and  interest  under the Long Term Notes to us and  thereby may
restrict  distributions  to  Unitholders,  in the  event of the  occurrence  of
certain events of default. For more information, reference is made to note 8 of
our audited  consolidated  financial statements for the year ended December 31,
2006,  which is incorporated by reference in this Annual  Information  Form and
which has been filed on SEDAR at WWW.SEDAR.COM.

RESTRICTION ON RESALE AGREEMENTS

In  connection  with the  internalization  transaction  and in order to  ensure
continuity of management and key individuals, we entered into escrow agreements
with certain  holders of ARML shares dated August 28, 2002. On August 28, 2002,
9,013  Trust  Units  and  2,008,699   ARML   exchangeable   shares   (1,735,221
Exchangeable  Shares  following  the  exchange  May 16,  2003) were placed into
escrow.  The escrow  agreements  commenced August 28, 2002 and under certain of
the escrow  agreements,  the  original  securities  deposited  into escrow were
releasable  annually  through 2007. On August 29, 2005,  the escrow  agreements
which had not yet expired were terminated. While it was determined not to enter
into replacement  agreements in respect of all of the securities which remained
in escrow prior to the  termination  of the escrow  agreements,  ARC  Resources
entered into new agreements in respect of an aggregate  88,692o Trust Units and
335,642  Exchangeable  Shares  (including  those  securities  held  by  certain
officers and  directors of ARC  Resources  which were  formerly held in escrow)
pursuant  to which the holders of such  securities  agreed to  restrictions  on
resale  which  are  substantially  similar  to those  contained  in the  escrow
agreements which were terminated.  Pursuant to these  restriction on resale, 50
per cent of the  securities  were released on August 29, 2006 and the remaining
50 per cent of the securities will be released on August 29, 2007.

The  following  table sets forth the number and  percentage  of Trust Units and
Exchangeable  Shares,  which to our knowledge,  are subject to  restrictions on
resale as at the date hereof.

                            TRUST UNITS AND EXCHANGEABLE SHARES
                                      Number Subject
     Designation of Class        to Resale Restrictions     Percentage of Class
     --------------------------------------------------------------------------
     Trust Units                          44,346                  0.02
     Exchangeable Shares                 167,821                 11.7

RETENTION PAYMENTS

As a condition of the  internalization  transaction,  ARML  declared  retention
payments to the Chief  Executive  Officer and the five  Vice-Presidents  of ARC
Resources  as at August 28,  2002.  ARML and ARC  Resources  were  subsequently
amalgamated  and  accordingly  ARC Resources is responsible for these retention
payments.  This payment was to be made in equal  increments  of an aggregate of
$1,000,000 per year for five years but only if the individual remained employed
by ARC Resources or another affiliate of the Trust. The retention payments were
funded  by an  effective  reduction  in the  purchase  price  resulting  in the
existing  holders  of  ARML  shares  effectively  paying  for  this  management
retention program.

                                OUR INFORMATION

TRUST UNITS

A maximum  of  650,000,000  Trust  Units  have been  created  and may be issued
pursuant to the Trust  Indenture.  The Trust Units  represent  equal  undivided
beneficial interests in the Trust. All Trust Units

<PAGE>
                                      32


share equally in all  distributions  made by us and all Trust Units carry equal
voting rights at meetings of  Unitholders.  No Unitholder will be liable to pay
any further calls or assessments in respect of the Trust Units.  No conversion,
retraction, redemption or pre-emptive rights attach to the Trust Units.

SPECIAL VOTING UNIT

The Trust  Indenture  also  provides for the  issuance of special  voting units
which are to be issued to a trustee  and which are  entitled  to such number of
votes at meetings of  Unitholders  equal to the number of Trust Units  reserved
for issuance that such special voting units represent, such number of votes and
any other  rights or  limitations  prescribed  by the Board of Directors of ARC
Resources when the Board authorizes issuing such special voting units.

A Special  Voting Unit has been  designated  by the Board of  Directors  of ARC
Resources as the Special  Voting Unit,  Exchangeable  Shares  ("Special  Voting
Unit"). The Special Voting Unit possesses a number of votes for the election of
directors  of ARC  Resources  and on all other  matters  submitted to a vote of
Unitholders equal to the number of outstanding Exchangeable Shares from time to
time not owned by Trust or ARC Subco. The holders of Trust Units and the holder
of the Special Voting Unit vote together as a single class on all matters.

In the event of any liquidation, dissolution or winding-up of Trust, the holder
of the  Special  Voting  Unit will not be entitled to receive any of our assets
available for  distribution  to  Unitholders.  The holder of the Special Voting
Unit will not be entitled  to receive  dividends.  The Special  Voting Unit has
been issued to Computershare  Trust Company of Canada, as trustee. At such time
as the  Special  Voting Unit has no votes  attached to it because  there are no
Exchangeable  Share  outstanding  that are not owned by Trust or ARC Subco, the
Special Voting Unit will be cancelled.

THE TRUST INDENTURE

The Trust Indenture,  among other things,  provides for the calling of meetings
of  Unitholders,  the  conduct of  business  thereof,  notice  provisions,  the
appointment and removal of the Trustee and the form of Trust Unit certificates.
The Trust Indenture may be amended from time to time. Substantive amendments to
the Trust Indenture,  including early  termination of the Trust and the sale or
transfer of the  property of the Trust as an  entirety or  substantially  as an
entirety requires approval by Special  Resolution of Unitholders.  Any approval
or consent of Unitholders in relation to any matter  required by any regulatory
body will require a majority of, or such other level of approval of Unitholders
as  may  be  stipulated  by  such  regulatory  authority,  including  as to the
exclusion of interested or other  Unitholders in the  calculation of such level
of approval. See "Meetings and Voting".

The following is a summary of certain provisions of the Trust Indenture.  For a
complete  description of such indenture,  reference should be made to the Trust
Indenture, a copy of which has been filed on SEDAR at www.sedar.com,  or may be
obtained from the Trustee.

TRUSTEE

Computershare Trust Company of Canada is the trustee of the Trust and also acts
as the transfer  agent for the Trust  Units.  The Trustee is  responsible  for,
among other  things:  (a) accepting  subscriptions  for Trust Units and issuing
Trust Units pursuant  thereto;  (b) maintaining  books and records of the Trust
and  providing  timely  reports to holders of Trust Units;  and (c) paying cash
distributions  to Unitholders.  The Trust  Indenture  provides that the Trustee
shall  exercise its powers and carry out its  functions  thereunder  as Trustee
honestly,  in good faith and in the best interests of the Trust and Unitholders
and, in connection therewith, shall exercise that degree of care, diligence and
skill  that  a  reasonably   prudent   trustee  would  exercise  in  comparable
circumstances.

<PAGE>
                                      33


The term of the  Trustee's  appointment  is until the next  annual  meeting  of
Unitholders.  At each annual  meeting the Trustee may be reappointed or changed
as determined  by a majority of the votes cast at such meeting of  Unitholders.
The Trustee may resign upon 60 days' notice to the Trust.  The Trustee may also
be removed by Special  Resolution of Unitholders.  Such  resignation or removal
becomes effective upon the acceptance or appointment of a successor trustee.

ARC Resources  presently  administers  the Trust on behalf of the Trustee.  ARC
Resources,  on behalf of the  Trustee,  keeps  such  books and  records  as are
necessary for the proper recording of the business transactions of the Trust.

The Trust  Indenture  provides that the Trustee shall be under no liability for
any action or failure to act unless such liabilities arise out of the Trustee's
gross  negligence,  wilful default or fraud. The Trustee,  where it has met its
standard of care,  shall be indemnified  out of the assets of the Trust for any
taxes or other  government  charges  imposed upon the Trustee in consequence of
its  performance  of its duties but shall have no additional  recourse  against
Unitholders.   In  addition,  the  Trust  Indenture  contains  other  customary
provisions limiting the liability of the Trustee.

FUTURE OFFERINGS

Under the Trust Indenture, the Trust may offer additional Trust Units or rights
to acquire  additional Trust Units at such times and on such terms as the Board
of Directors of ARC Resources may  determine.  At the option of the Trust,  the
net  proceeds  from any  offerings  may be used to finance the  acquisition  of
additional  properties,  make  additional  capital  expenditures  or  to  repay
indebtedness incurred in connection with such acquisitions.

MEETINGS AND VOTING

There  will be at least one  meeting  of  Unitholders  held  annually.  Special
meetings of  Unitholders  may be called at any time by the Trustee and shall be
called by the  Trustee  upon the  written  request  of  Unitholders  holding in
aggregate not less than 20 per cent of the Trust Units.  Notice of all meetings
of  Unitholders  shall be given to  Unitholders  at least 21 days  prior to the
meeting.

Unitholders will be entitled at each annual meeting to appoint the Trustee,  to
appoint the  auditors of the Trust and to elect all the members of the Board of
Directors of ARC Resources.

OUR MANAGEMENT

The Trust Indenture  provides for delegation to ARC Resources by the Trustee of
broad  discretion to  administer  and manage our day to day  operations,  which
includes  responsibility and authority to make executive decisions on behalf of
all of our direct or indirect  subsidiaries  and to exercise  the powers of the
Trustee.   Without  limitation  of  the  foregoing,   ARC  Resources  has  been
specifically  delegated to provide certain  administrative and support services
to us,  including  those  necessary:  (i) to ensure  compliance with continuous
disclosure obligations under applicable securities legislation; (ii) to provide
investor  relations  services;  (iii) to  provide  or cause to be  provided  to
Unitholders all  information to which  Unitholders are entitled under the Trust
Indenture;  (iv) to call, hold and distribute  materials  including  notices of
meetings  and  information  circulars in respect of all  necessary  meetings of
Unitholders;  (v) to  determine  the  amounts  payable  from  time  to  time to
Unitholders and to arrange for  distributions  to Unitholders of  distributable
income; and (vi) to determine the timing and terms of future offerings of Trust
Units, if any.

ARC Resources has accepted all such  delegation and has agreed that, in respect
of such matters, it shall carry out its functions  honestly,  in good faith and
in our best interests and the best interests of Unitholders

<PAGE>
                                      34


and, in connection therewith, shall exercise that degree of care, diligence and
skill  that  a  reasonably   prudent   person  would   exercise  in  comparable
circumstances.

ARC FINANCIAL ADVISORY AGREEMENT

We entered an agreement dated August 28, 2002 whereby ARC Financial Corporation
agreed to provide us with  certain  ongoing  research  in respect to supply and
demand  information which may impact our crude oil and natural gas prices for a
five year period  without  further  cost.  ARC Financial  Corporation  has also
agreed not to, act as manager or promoter  of another  publicly  listed  energy
related trust for a period of five years, with certain exceptions.

LIMITATION ON NON-RESIDENT OWNERSHIP

The Trust intends to comply with the  requirements  under the Tax Act for "unit
trusts" and "mutual fund  trusts" at all  relevant  times such that we maintain
our status of a unit trust and a mutual fund trust for purposes of the Tax Act.
In this  regard,  we may,  from  time to time,  among  other  things,  take all
necessary  steps to monitor the  activities  of the Trust and  ownership of the
Trust Units.  If at any time we become aware that the  activities  of the Trust
and ownership of the Trust Units by non-residents  (non-residents of Canada and
partnerships) may threaten the status of the Trust under the Tax Act as a "unit
trust" or "mutual fund trust",  we are authorized to take such action as may be
necessary  in the opinion of ARC  Resources to maintain the status of the Trust
as a  unit  trust  and  a  mutual  fund  trust,  including  the  imposition  of
restrictions  on the issuance by the Trust,  or the transfer by any Unitholder,
of Trust Units to a non resident.  See "Risk  Factors - Change of  Legislation"
and "Risk Factors - Non-Resident Ownership of Trust Units".

RIGHT OF REDEMPTION

Trust Units will be  redeemable  at any time on demand by the  holders  thereof
upon delivery to us of the certificate or certificates  representing such Trust
Units,  accompanied by a duly completed and properly executed notice requesting
redemption. Upon receipt of the redemption request, all rights to and under the
Trust Units tendered for redemption shall be surrendered and the holder thereof
shall be entitled to receive a price per Unit ("Market Redemption Price") equal
to the  lesser  of: (i) 90 per cent of the  market  price,  being the  weighted
average  trading price of the Trust Units on the principal  market on which the
Trust Units are quoted for trading during the 10 trading day period  commencing
immediately  after  the date on which  the  Trust  Units  are  surrendered  for
redemption;  and (ii) the closing market price on the principal market on which
the Trust  Units are  quoted for  trading on the date that the Trust  Units are
surrendered for redemption.

The  aggregate  cash Market  Redemption  Price  payable by us in respect of any
Trust Units  surrendered  for  redemption  during any  calendar  month shall be
satisfied  by way of a cash  payment  on the last day of the  following  month;
provided  that  the  entitlement  of  Unitholders  to  receive  cash  upon  the
redemption of their Trust Units is subject to a number of conditions, including
the  condition  that the total  amount  payable  by us in respect of such Trust
Units and all other Trust Units  tendered for  retraction  in the same calendar
month must not exceed  $100,000  provided  that we may waive such  condition in
respect of any calendar month.

If a Unitholder  is not entitled to receive cash upon the  redemption  of Trust
Units  then we  shall,  at the  discretion  of the  Board of  Directors  of ARC
Resources,  pay  the  Market  Redemption  Price  by  distributing  either:  (i)
unsecured subordinated promissory notes bearing interest at 4.5 per cent with a
20 year term,  or (ii)  distributing  a portion of some or all of the assets of
ARC having in the  opinion of the Board of  Directors  of ARC  Resources a fair
market value equal to the Market Redemption Price. Alternatively,

<PAGE>
                                      35


the Board of Directors  of ARC  Resources  may decide to  distribute a pro rata
share of the assets of the Trust, net of any liabilities of the Trust.

It is anticipated  that the foregoing  retraction right will not be the primary
mechanism  for  holders of Trust  Units to dispose of their  Trust  Units.  ARC
Resources Notes which may be distributed IN SPECIE to Unitholders in connection
with a  redemption  will not be listed on any stock  exchange  and no market is
expected to develop in the ARC  Resources  Notes.  ARC  Resources  Notes may be
subject to resale restrictions under applicable  securities laws. ARC Resources
Notes so  distributed  may be  qualified  investments  for trusts  governed  by
registered  retirement savings plans,  registered  retirement income trusts and
deferred profit sharing plans.

TERMINATION OF THE TRUST

Unitholders  may vote to  terminate  the Trust at any  meeting of  Unitholders,
subject to the  following:  (a) a vote may only be held if requested in writing
by the holders of not less than 20 per cent of the Trust Units; (b) a quorum of
50 per cent of the issued and  outstanding  Trust Units is present in person or
by proxy;  and (c) the  termination  must be approved by Special  Resolution of
Unitholders.

Unless the Trust is terminated or extended by vote of Unitholders  earlier, the
Trustee  shall  commence to wind-up  the  affairs of the Trust on December  31,
2095. In the event that the Trust is wound-up,  the Trustee will  liquidate all
the assets of the Trust,  pay, retire,  discharge or make provision for some or
all obligations of the Trust and then distribute the remaining proceeds of sale
to Unitholders.

REPORTING TO UNITHOLDERS

Our financial statements will be audited annually by an independent  recognized
firm of chartered accountants. Our audited financial statements,  together with
the report of such chartered accountants, will be mailed to Unitholders and the
unaudited  interim  financial  statements  of  the  Trust  will  be  mailed  to
Unitholders as prescribed by securities  legislation.  Our year end is December
31.  We  are  subject  to  the  continuous  disclosure  obligations  under  all
applicable securities legislation.

Unitholders  are entitled to inspect,  during  normal  business  hours,  at the
offices of the Trustee, and, upon payment of reasonable  reproduction costs, to
receive  photocopies of certain material  contracts,  the Trust Indenture and a
listing of the registered holders of Trust Units.

DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE PLAN

A plan has been established to provide  Unitholders who are residents of Canada
(within  the  meaning  of  the  Tax  Act)  with  a  method  to  reinvest   cash
distributions by purchasing additional Trust Units.


                             CORPORATE GOVERNANCE

GENERAL

In general, ARC Resources has been delegated substantially all of our management
decisions. Unitholders are entitled to elect all of the Board of Directors of
ARC Resources pursuant to the terms of the Trust Indenture. The Articles of ARC
Resources provides that the Board of Directors of ARC Resources shall consist of
a minimum of three and a maximum of nine directors.

TRUST INDENTURE

Pursuant to the Trust Indenture,  Unitholders are entitled to direct the manner
in which we will vote our shares in ARC Resources at all meetings in respect of
matters, relating to the election of the directors of ARC Resources,  approving
its financial  statements and appointing auditors of ARC Resources who shall be
the  same as our  auditors.  Prior  to  exercising  our  voting  rights  in ARC
Resources,  each  Unitholder  is  entitled to vote on the basis of one vote per
Trust Unit held,  and we are  required to vote our shares in ARC  Resources  in
accordance with the result of the vote of Unitholders.

DECISION MAKING

The  Board of  Directors  of ARC  Resources  has a  mandate  to  supervise  the
management  of our  business  and  affairs  and to act  with a view to our best
interests. The Board of Directors of

<PAGE>
                                      36


ARC  Resources  supervises  the  management  of the business and affairs of our
subsidiaries.  The Board of Directors' mandate includes: (a) the responsibility
for managing our affairs; (b) monitoring our management and our activities; (c)
reviewing strategic operating,  capital and financial plans; and (d) compliance
reporting and corporate communications. In particular,  significant operational
decisions and all decisions relating to: (i) the acquisition and disposition of
properties for a purchase  price or proceeds in excess of an amount  prescribed
from time to time by the  Board of  Directors;  (ii) the  approval  of  capital
expenditure  budgets;  and (iii) establishment of credit facilities are made by
the Board of Directors of ARC Resources. In addition, the Trustee has delegated
broad  discretion  in  relation  to our day to day  operations  to the Board of
Directors of ARC Resources  including  all  decisions  relating to: (i) matters
relating to any offers for Trust  Units;  (ii)  issuances of  additional  Trust
Units; and (iii) the determination of the amount of distributable  income.  Any
amendment  to the  royalty  agreements  requires  the  approval of the Board of
Directors  of ARC  Resources  on our  behalf.  The  Board of  Directors  of ARC
Resources holds regularly  scheduled  meetings at least quarterly to review the
business  and  affairs of our  subsidiaries  and make any  necessary  decisions
relating thereto.

The  Trust  Indenture  gives to the Board of  Directors  of ARC  Resources  the
authority  to  exercise  the  rights,  powers and  privileges  for all  matters
relating to the  maximization  of  Unitholder  value in the context of an offer
including any Unitholder  rights  protection  plan, any defensive  action to an
offer, any directors  circular in response to an offer, any regulatory or court
proceeding relating to an offer and any related or ancillary matter.

BOARD OF DIRECTORS OF ARC RESOURCES

ARC Resources has a Board of Directors consisting of eight individuals,  all of
whom  have  been  elected  by  Unitholders,  including  by the  holders  of the
Exchangeable Shares through the Special Voting Unit.

The name,  municipality of resident,  position held and principal occupation of
each director and officer of ARC Resources are set out below:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
           NAME AND                             OFFICES HELD
   MUNICIPALITY OF RESIDENCE                AND TIME AS DIRECTOR                          PRINCIPAL OCCUPATION
--------------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>                                         <C>
Mac H. Van Wielingen(1)(3)(4)          Chairman of the Board and Director          Co-Chairman of ARC Financial Corporation
Calgary, Alberta, Canada               since May 3, 1996                           (an investment management company)
--------------------------------------------------------------------------------------------------------------------------------
Walter DeBoni(1) (4) (5)               Vice Chairman and Director since            Independent Businessman
Calgary, Alberta, Canada               June 26, 1996
--------------------------------------------------------------------------------------------------------------------------------
John P. Dielwart                       President, Chief Executive Officer          President and Chief Executive Officer of
Calgary, Alberta, Canada               and Director since May 3, 1996              ARC Resources
--------------------------------------------------------------------------------------------------------------------------------
Frederic C. Coles(2)(3) (5)            Director since May 3, 1996                  Independent Businessman
Calgary, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<PAGE>
                                      37

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
           NAME AND                             OFFICES HELD
   MUNICIPALITY OF RESIDENCE                AND TIME AS DIRECTOR                          PRINCIPAL OCCUPATION
--------------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>                                         <C>
Fred J. Dyment(1)(2)                   Director since April 17, 2003               Independent Businessman
Calgary, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
Michael M. Kanovsky(1)(2)              Director since May 3, 1996                  Independent Businessman
Victoria, B.C., Canada
--------------------------------------------------------------------------------------------------------------------------------
Herbert C. Pinder, Jr.(3)(4)           Director since January 1, 2006              Independent Businessman
Saskatoon, Saskatchewan, Canada
--------------------------------------------------------------------------------------------------------------------------------
John M. Stewart(3)(4)(5)               Director since February 11, 1998            Vice Chairman of ARC Financial Corporation
Phoenix, Arizona, U.S.A.                                                           (an investment management company)
--------------------------------------------------------------------------------------------------------------------------------
Doug J. Bonner                         Senior Vice-President, Corporate            Senior Vice-President, Corporate
Calgary, Alberta, Canada               Development                                 Development of ARC Resources
--------------------------------------------------------------------------------------------------------------------------------
David P. Carey                         Senior Vice-President, Capital              Senior Vice-President, Capital Markets of
Calgary, Alberta, Canada               Markets                                     ARC Resources
--------------------------------------------------------------------------------------------------------------------------------
Susan D. Healy                         Senior Vice-President, Corporate            Senior Vice-President, Corporate Services
Calgary, Alberta,  Canada              Services                                    of ARC Resources
--------------------------------------------------------------------------------------------------------------------------------
Steven W. Sinclair                     Senior Vice-President, Finance and          Senior Vice-President, Finance and Chief
Calgary, Alberta, Canada               Chief Financial Officer                     Financial Officer of ARC Resources
--------------------------------------------------------------------------------------------------------------------------------
Myron M. Stadnyk                       Senior Vice-President and Chief             Senior Vice-President and Chief Operating
Calgary, Alberta, Canada               Operating Officer                           Officer of ARC Resources
--------------------------------------------------------------------------------------------------------------------------------
Terry M. Anderson                      Vice-President, Operations                  Vice-President, Operations of ARC Resources
Calgary, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
Yvan Chretien                          Vice-President, Land                        Vice-President, Land of ARC Resources
Calgary, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
Ingram B. Gillmore                     Vice-President, Engineering                 Vice-President, Engineering of ARC Resources
Calgary, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
P. Van R. Dafoe                        Treasurer                                   Treasurer of ARC Resources
Calgary, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
Allan R. Twa                           Secretary                                   Partner, Burnet, Duckworth & Palmer LLP
Calgary, Alberta, Canada                                                           (barristers and solicitors)
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Notes:
(1)      Member of Audit Committee.
(2)  Member of Reserves Committee.
(3)  Member of Human Resources and Compensation Committee.
(4)  Member of Policy and Board Governance Committee.
(5)  Member of Health, Safety and Environment Committee.

Each of the  directors  and officers have held the position set forth as his or
her principal  occupation  for the last five years except for Walter DeBoni who
prior to November  2005 was  Vice-President,  Canada  Frontier &  International
Business  of Husky  Energy  Inc.  (a  public  oil and gas  company);  Steven W.
Sinclair,  who prior to  November  2005 was  Vice-President,  Finance and Chief
Financial   officer;   David  P.  Carey  who,   prior  to  November   2005  was
Vice-President,  Business Development;  Doug Bonner, who prior to November 2005
was Vice-President, Engineering; Myron J. Stadnyk, who prior to September

<PAGE>
                                      38


2004,   was  Vice   President   Operations  and  prior  to  November  2005  was
Vice-President,  Operations and Land, of ARC Resources; and Susan D. Healy, who
prior to September 2004, was Vice-President Land and prior to November 2005 was
Vice-President, Corporate Services of ARC Resources; P. Van R, Dafoe, who prior
to March 2005, was Controller of ARC Resources; Terry M. Anderson, who prior to
November 2005, was Manager,  Field Operations of ARC Resources;  Yvan Chretien,
who prior to  November  2005,  was Land  Manager of ARC  Resources;  and Ingram
Gillmore who prior to January 2007, was Engineering Manager of ARC Resources.

The following  comprises a brief  description of the background of the officers
of ARC Resources.

JOHN P. DIELWART, B.SC., P.ENG.

Mr. Dielwart is President and Chief Executive Officer of ARC Resources Ltd. and
has overall  management  responsibility  for the Trust. Prior to joining ARC in
1994,  Mr.  Dielwart  spent 12 years with a major Calgary based oil and natural
gas engineering consulting firm, as senior vice-president and a director, where
he gained  extensive  technical  knowledge of oil and natural gas properties in
western Canada. He began his career working for five years with a major oil and
natural gas company in Calgary. Mr. Dielwart is a Past-Chairman of the board of
governors for the Canadian  Association of Petroleum Producers (CAPP). He holds
a Bachelor of Science with Distinction (Civil Engineering)  degree,  University
of Calgary. He has also been a director of ARC since 1996.

STEVEN W. SINCLAIR, B. COMM., CA

Mr. Sinclair is Senior  Vice-President  Finance and Chief Financial  Officer of
ARC Resources  Ltd. and oversees all of the financial and marketing  affairs of
ARC Energy Trust.  Mr.  Sinclair has a Bachelor of Commerce from the University
of Calgary,  obtained his Chartered  Accountant's  designation  in 1981 and has
over 25 years experience  within the finance,  accounting and taxation areas of
the oil and gas industry. Mr. Sinclair has been with the Trust since 1996.

DOUGLAS J. BONNER, B.SC., P.ENG.

Mr. Bonner is Senior  Vice-President,  Corporate  Development  of ARC Resources
Ltd. and is responsible  for the strategic  development  and expansion of ARC's
assets.  He holds a B.Sc.  in  Geological  Engineering  from the  University of
Manitoba.  Mr. Bonner's major area of expertise is reservoir engineering and he
has  extensive  technical  knowledge  of oil and natural gas fields  throughout
western  Canada,  the east coast and northern  Canada.  Prior to joining ARC in
1996,  Mr.  Bonner  spent 18 years  with  various  major  oil and  natural  gas
companies in positions of increasing responsibility.

DAVID P. CAREY, B.SC., P.ENG., MBA

Mr. Carey is Senior  Vice-President,  Capital Markets of ARC Resources Ltd. and
is responsible for all facets of investor  relations and corporate  governance.
He  holds  both a  B.Sc.  in  Geological  Engineering  and a MBA  from  Queen's
University.  Mr. Carey has over 20 years of diverse  experience in the Canadian
and  International  energy  industries  covering  exploration,  production  and
project  evaluations in western Canada,  oilsands,  the Canadian  frontiers and
internationally.  Prior to joining ARC Resources in 2001, Mr. Carey held senior
positions  with Athabasca Oil Sands  Investments  Inc. and a major Canadian oil
and gas company.

SUSAN D. HEALY, P. LAND

Ms. Healy is Senior  Vice-President,  Corporate  Services of ARC Resources Ltd.
and oversees all human  resources,  information  technology and office services
related activities. Ms. Healy joined the Trust at

<PAGE>
                                      39


inception in July 1996,  bringing with her over 17 years of diverse  experience
gained from working with junior and senior oil and gas companies.

MYRON M. STADNYK, B.SC., P.ENG.

Mr.  Stadnyk  is Senior  Vice-President  and  Chief  Operating  Officer  of ARC
Resources Ltd. and is responsible for all aspects of ARC's ongoing  operational
and production management and strategies. He has 22 years experience in the oil
and gas business.  Prior to joining ARC  Resources  Ltd. in 1997,  Mr.  Stadnyk
worked  with a major oil and gas  company in both  domestic  and  international
operations.  He has a B.Sc. in mechanical  Engineering  from the  University of
Saskatchewan  and is a member of the Association of  Professional  Engineers in
Alberta, British Columbia and Saskatchewan.

TERRY M. ANDERSON, P.ENG.

Mr.  Anderson  is  Vice-President,  Operations  of ARC  Resources  Ltd.  and is
responsible  for  all  of  ARC's  operational  activities.  He has a  B.Sc.  in
Petroleum  Engineering  and is a  member  of the  Association  of  Professional
Engineers in Alberta,  Saskatchewan and British  Columbia.  Mr. Anderson has 13
years of experience in drilling, completion,  pipeline, facility and production
operations.  Prior to  joining  ARC in 2000,  he  worked at a major oil and gas
company.

YVAN CHRETIEN, B.COMM.

Mr. Chretien is  Vice-President,  Land of ARC Resources Ltd. and is responsible
for all of ARC's  land  related  activities.  He has 16  years of land  related
experience.  Prior to joining ARC in 2001,  Mr Chretien  worked for both senior
and intermediate oil and gas companies.

INGRAM B. GILLMORE, P.ENG.

Mr.  Gillmore is  Vice-President,  Engineering  of ARC  Resources  Ltd.  and is
responsible  for all of ARC's  engineering,  geophysical,  geological and joint
venture related activities. He holds a B.Sc. in Chemical engineering (1991) and
a Bachelor of Fine Arts.  Mr.  Gillmore  has been at ARC since  2002.  Prior to
joining  ARC,  Mr.  Gillmore  held  positions  with  several  major oil and gas
companies.   His  varied   experience   includes   working  on  and   directing
multifunctional   teams  growing  both  development  and  exploration  oriented
production across western Canada.

P. VAN R. DAFOE, B.COMM., CMA

Mr. Dafoe is  Treasurer of ARC  Resources  Ltd. and is  responsible  for all of
ARC's Treasury related activities. He has a Bachelor of Commerce - Honours from
the University of Manitoba and obtained his Certified  Management  Accountant's
designation  in 1995.  Mr. Dafoe joined ARC in 1999 after 13 years with various
companies in the finance and accounting area of the oil and gas industry.

ALLAN R. TWA, Q.C.

Mr.  Twa acts as  Corporate  Secretary  of ARC  Resources  Ltd. A member of the
Alberta Bar since 1971, Mr. Twa is a partner in the law firm Burnet,  Duckworth
& Palmer LLP. Mr. Twa holds a B.A.  (Political  Science) from the University of
Calgary, a LL.B. from the University of Alberta and a LL.M. from the University
of London, England. Over the last 25 years, Mr. Twa has been engaged in a legal
practice  involving  legal  administration  of  public  companies  and  trusts,
corporate finance, and mergers and acquisitions.

<PAGE>
                                      40


Mac Van  Wielingen is the Chairman  and a Director of ARC  Resources  and was a
director of Gauntlet  Energy  Corporation  which  secured  creditor  protection
pursuant to the COMPANIES'  CREDITORS  ARRANGEMENT ACT on June 17, 2003 and was
subsequently acquired by Ketch Resources Ltd. in December, 2003.

All of the  directors  of ARC  Resources  were  elected on May 15, 2006 to hold
office  until  the next  annual  general  meeting  of ARC  Resources,  which is
scheduled for May 23, 2007. As at December 31, 2006, the directors and officers
of ARC Resources,  as a group,  beneficially owned, directly or indirectly,  or
exercised  control or direction over,  767,502 Trust Units or approximately 0.4
per cent of the outstanding  Trust Units,  and 894,697  Exchangeable  Shares or
approximately 62 per cent of the outstanding Exchangeable Shares. If all of the
Exchangeable Shares had been exchanged for Trust Units at the Exchange Ratio in
effect on December 31, 2006,  the  directors and officers of ARC Resources as a
group would hold  2,727,823  Trust Units or  approximately  1.3 per cent of the
outstanding Trust Units as at December 31, 2006.

                          AUDIT COMMITTEE DISCLOSURES

Multilateral  Instrument  52-110 ("MI 52-110") relating to audit committees has
mandated certain disclosures for inclusion in this Annual Information Form. The
text of the Audit Committee's  mandate is attached as Appendix C to this Annual
Information Form.

MEMBERS OF THE AUDIT COMMITTEE

The  members of the Audit  Committee  are Fred J.  Dyment,  chairman,  and Walt
DeBoni, Michael Kanovsky and Mac Van Wielingen, each of whom is independent and
financially literate within the meaning of MI 52-110. The following comprises a
brief summary of each member's education and experience:

FRED J. DYMENT

Mr. Dyment has 30 years experience in the oil and gas business and is currently
an independent  businessman.  His past business  career  included  positions as
President  and CEO for Maxx  Petroleum  and  President  and CEO of  Ranger  Oil
Limited.  Mr.  Dyment  received a  Chartered  Accountant  designation  from the
province of Ontario in 1972.  Mr.  Dyment  currently  sits as a Director on the
Boards of Tesco  Corporation,  Western  Oil  Sands,  ZCL  Composites  Inc.  and
Transglobe Energy Corporation. He has been a Director of ARC since 2003.

WALT DEBONI

Mr. DeBoni  recently  retired from Husky Energy Inc. where he held the position
of VP, Canada Frontier & International  Business.  Prior to this Mr. DeBoni was
CEO of Bow Valley  Energy  for a number of years.  In  addition  to his time at
Husky and Bow Valley he has also held numerous top  executive  posts in the oil
and gas industry with major corporations. Mr. DeBoni holds a B.A.Sc. Chem. Eng.
from the University of British  Columbia,  a MBA degree with a major in Finance
from  the  University  of  Calgary  and  is a  member  of  the  association  of
Professional Engineers, Geologists and Geophysicists of Alberta and the Society
of Petroleum Engineers.  He is a past Chairman of the Petroleum Society of CIM,
a past  Director of the Society of Petroleum  Engineers and has been a Director
of ARC Resources since 1996.

MICHAEL KANOVSKY

Mr. Kanovsky graduated from Queen's University and the Ivey School of Business.
Mr. Kanovsky's business career included the position of VP of Corporate Finance
with a major  Canadian  investment  dealer  followed by  co-founding  Northstar
Energy Corporation and PowerLink Corporation (electrical

<PAGE>
                                      41


cogeneration)  where he served as Senior Executive Board Chairman and Director.
Mr.  Kanovsky  is a Director  of  Bonavista  Petroleum  Inc.  and Devon  Energy
Corporation. He has been a Director of ARC since 1996.

MAC VAN WIELINGEN

Mr. Van  Wielingen  has served as a Director of ARC  Resources  Ltd.  since its
formation  in  1996.  He  is  Co-Chairman   and  a  founder  of  ARC  Financial
Corporation.  Previously  Mr. Van  Wielingen  was a Senior  Vice-President  and
Director of a major national  investment  dealer  responsible for all corporate
finance activities in Alberta.  He has managed numerous  significant  corporate
merger  and  acquisition  transactions,  capital  raising  projects  and equity
investments  relating to the energy sector.  Mr. Van Wielingen holds an Honours
Business Degree from the University of Western Ontario  Business School and has
studied post-graduate Economics at Harvard University.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Audit  Committee has not adopted  specific  policies and procedures for the
engagement of non-audit  services and pre-approves each such engagement or type
of engagement for every fiscal year.

Our external  auditor is Deloitte & Touche LLP.  The  following is a summary of
the external audit services fees by category.

AUDIT FEES

The aggregate fees billed by our external auditor for audit services are:

      2006       $293,426
      2005       $280,750

AUDIT RELATED FEES

The  aggregate  fees billed by our external  auditor for  assurance and related
services that are reasonably  related to the performance of the audit or review
of the financial statements (not included in audit services fees) are:

      2006       $444,200
      2005       $110,900

TAX FEES

The aggregate fees billed by our external auditor for professional services for
municipal property tax compliance, tax advice and tax planning are:

      2006       $158,195
      2005       $110,532

ALL OTHER FEES

The aggregate fees billed by our external auditor for products and services not
included under the headings:  Audit Fees,  Audit Related Fees, Tax Fees and All
Other Fees.

      2006       $0
      2005       $0

<PAGE>
                                      42


                             CONFLICTS OF INTEREST

The Board of Directors has adopted a Code of Business  Conduct and Ethics and a
Code of Ethics for Senior  Financial  Officers (the "Codes").  In general,  the
private  investment  activities  of  employees,  directors and officers are not
prohibited, however, should an existing investment pose a potential conflict of
interest the potential conflict is required by the Codes to be disclosed to the
President or the Board of Directors.  Any other  activities of employees  which
pose a  potential  conflict of  interest  are also  required by the Codes to be
disclosed  to the  President  or the  Board of  Directors.  Any such  potential
conflicts of interests  will be dealt with openly with full  disclosure  of the
nature and extent of the potential conflicts of interests with the Trust.

It is acknowledged  in the Codes that employees,  officers and directors may be
directors or officers of other  entities  engaged in the oil and gas  business,
and that such entities may compete  directly or indirectly  with the Trust.  No
assurance  can be given  that  opportunities  identified  by  directors  of ARC
Resources  will be provided  to us.  Passive  investments  in public or private
entities of less than one per cent of the outstanding shares will not be viewed
as  "competing"  with the  Trust.  Any  director,  officer or  employee  of ARC
Resources  which is a director or officer of any entity  engaged in the oil and
gas business  shall  disclose such  occurrence  to the Board of Directors.  Any
director,  officer or employee of ARC Resources who is actively  engaged in the
management  of,  or who  owns  an  investment  of one  per  cent or more of the
outstanding  shares,  in public or private entities shall disclose such holding
to the Board of Directors. In the event that any circumstance should arise as a
result of such  positions or investments  being held or otherwise  which in the
opinion of the Board of  Directors  constitutes  a conflict of  interest  which
reasonably  affects  such  person's  ability  to act  with a view  to the  best
interests of the Trust,  the Board of  Directors  will take such actions as are
reasonably  required to resolve such matters with a view to the best  interests
of the Trust.  Such actions,  without  limitation,  may include  excluding such
directors,  officers or employees from certain information or activities of the
Trust.

The BUSINESS  CORPORATIONS  ACT  (Alberta)  provides  that in the event that an
officer or  director  is a party to, or is a director or an officer of or has a
material  interest  in any  person who is a party to, a  material  contract  or
material  transaction  or  proposed  material  contract  or  proposed  material
transaction,  such officer or director  shall disclose the nature and extent of
his or her interest and shall  refrain from voting to approve such  contract or
transaction.

          INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There is no material  interest,  direct or indirect,  of any director or senior
officer,  or to our  knowledge  any  person or  company  that is the  direct or
beneficial  owner, or who exercises  control or direction over more than 10 per
cent of  outstanding  Trust Units,  or any associate or affiliate of any of the
foregoing,  in  any  transaction  within  the  three  most  recently  completed
financial years.

                          DISTRIBUTIONS TO UNITHOLDERS

The  following  per Trust Unit  distributions  have been made in the last three
completed financial years:

                     2004             Distribution Per Trust Unit
              -------------------     ---------------------------
                First Quarter                    $0.45
                Second Quarter                   $0.45
                Third Quarter                    $0.45
                Fourth Quarter                   $0.45

<PAGE>
                                      43


                     2005             Distribution Per Trust Unit
              -------------------     ---------------------------
                First Quarter                    $0.45
                Second Quarter                   $0.45
                Third Quarter                    $0.49
                Fourth Quarter                   $0.60

                     2006             Distribution Per Trust Unit
              -------------------     ---------------------------
                First Quarter                    $0.60
                Second Quarter                   $0.60
                Third Quarter                    $0.60
                Fourth Quarter                   $0.60

In certain  circumstances,  distributions  may be  restricted  by our borrowing
agreements.  For  more  information  see  "Other  Information  Relating  to Our
Business - Borrowing".  Cash  distributions  paid to Unitholders in 2004 were 6
per cent tax deferred, 2005 cash distributions were 2 per cent tax deferred and
2006 cash distributions were 2 per cent tax deferred. For more information, see
"Our Business - Cash Distributions and Distribution Policy".


                 PRICE RANGE AND TRADING VOLUME OF TRUST UNITS
                            AND EXCHANGEABLE SHARES

The Trust Units are listed and posted for trading on the Toronto Stock Exchange
("TSX").  The trading symbol for the Trust Units is AET.UN. The following table
sets forth the high and low closing prices and the aggregate  volume of trading
of the Trust Units on the TSX for the periods indicated (as quoted by the TSX):

                                        TORONTO STOCK EXCHANGE
                                        ----------------------
    2006 PERIOD                HIGH                 LOW              VOLUME
    -----------                ----                 ---              ------
                                $                    $
    January                     27.13               25.54          10,042,065
    February                    28.41               23.25          13,603,734
    March                       27.52               24.85          11,220,941
    April                       27.78               26.56          6,890,569
    May                         28.50               25.17          13,541,543
    June                        28.95               24.07          14,087,208
    July                        29.99               27.01          8,763,931
    August                      31.20               28.44          13,213,731
    September                   29.83               24.55          16,149,570
    October                     29.58               24.01          16,247,875
    November                    24.99               19.05          41,761,610
    December                    22.03               22.02          11,716,135

The  Exchangeable  Shares are listed  and  posted for  trading on the TSX.  The
trading  symbol for the  Exchangeable  Shares is ARX. The following  table sets
forth the high and low closing  prices and the  aggregate  volume of trading of
the Exchangeable  Shares on the TSX for the periods indicated (as quoted by the
TSX):

                                        TORONTO STOCK EXCHANGE
     2006 PERIOD               HIGH                 LOW              VOLUME
    ------------               ----                 ---              ------
                                $                    $
    January                     50.36               48.85            3,295
    February                    51.98               46.00            3,180
    March                       52.50               48.76            31,540
    April                       52.14               51.40            2,431
    May                         50.30               49.35            1,390


<PAGE>
                                      44


                                        TORONTO STOCK EXCHANGE
     2006 PERIOD               HIGH                 LOW              VOLUME
    ------------               ----                 ---              ------
                                $                    $
    June                        55.00               47.50            10,500
    July                        57.00               53.92            14,034
    August                      60.00               56.00            2,240
    September                   55.00               48.85            8,010
    October                     55.73               49.90            2,007
    November                    46.08               42.00            5,540
    December                    50.00               46.02            2,429


                              INDUSTRY REGULATIONS

The oil  and  natural  gas  industry  is  subject  to  extensive  controls  and
regulations  governing  its  operations  (including  land tenure,  exploration,
development,  production, refining,  transportation,  and marketing) imposed by
legislation enacted by various levels of government and with respect to pricing
and  taxation of oil and natural gas by  agreements  among the  governments  of
Canada,  Alberta,  British Columbia,  and Saskatchewan,  all of which should be
carefully  considered  by  investors  in the oil and  gas  industry.  It is not
expected that any of these controls or  regulations  will affect our operations
in a manner  materially  different  than they  would  affect  other oil and gas
companies of similar size. All current legislation is a matter of public record
and we are unable to predict what  additional  legislation or amendments may be
enacted.  Outlined  below are some of the  principal  aspects  of  legislation,
regulations and agreements governing the oil and gas industry.

PRICING AND MARKETING - OIL AND NATURAL GAS

The producers of oil are entitled to negotiate  sales  contracts  directly with
oil  purchasers,  with the result that the market  determines the price of oil.
Oil prices are  primarily  based on worldwide  supply and demand.  The specific
price depends in part on oil quality,  prices of competing  fuels,  distance to
market,  the value of refined products,  the supply/demand  balance,  and other
contractual  terms.  Oil  exporters  are also  entitled  to enter  into  export
contracts  with terms not exceeding one year in the case of light crude oil and
two years in the case of heavy crude oil, provided that an order approving such
export has been obtained from the National  Energy Board of Canada (the "NEB").
Any oil export to be made  pursuant  to a  contract  of longer  duration  (to a
maximum of 25 years)  requires an exporter to obtain an export licence from the
NEB and the issuance of such  licence  requires the approval of the Governor in
Council.

The price of  natural  gas is  determined  by  negotiation  between  buyers and
sellers.  Natural gas exported  from Canada is subject to regulation by the NEB
and the Government of Canada.  Exporters are free to negotiate prices and other
terms with purchasers, provided that the export contracts must continue to meet
certain  other  criteria  prescribed  by the NEB and the  Government of Canada.
Natural  gas  exports for a term of less than two years or for a term of two to
20  years  (in  quantities  of not more  than  30,000  m(3)/day),  must be made
pursuant  to an NEB order.  Any  natural  gas export to be made  pursuant  to a
contract  of longer  duration  (to a maximum of 25 years) or a larger  quantity
requires an exporter to obtain an export  licence from the NEB and the issuance
of such licence requires the approval of the Governor in Council.

The governments of Alberta,  British  Columbia,  and Saskatchewan also regulate
the  volume  of  natural  gas that may be  removed  from  those  provinces  for
consumption   elsewhere   based  on  such  factors  as  reserve   availability,
transportation arrangements, and market considerations.

<PAGE>
                                      45


PIPELINE CAPACITY

Although  pipeline  expansions are ongoing,  the lack of firm pipeline capacity
continues  to affect the oil and natural gas  industry and limit the ability to
produce and to market natural gas production. In addition, the pro-rationing of
capacity on the inter-provincial  pipeline systems also continues to affect the
ability to export oil and natural gas.

THE NORTH AMERICAN FREE TRADE AGREEMENT

The North  American Free Trade  Agreement  ("NAFTA")  among the  governments of
Canada,  United States of America,  and Mexico  became  effective on January 1,
1994.  NAFTA  carries  forward  most of the  material  energy  terms  that  are
contained in the Canada United States Free Trade  Agreement.  In the context of
energy resources,  Canada continues to remain free to determine whether exports
of energy  resources to the United  States or Mexico will be allowed,  provided
that any  export  restrictions  do not:  (i) reduce  the  proportion  of energy
resources  exported  relative  to  domestic  use  (based  upon  the  proportion
prevailing  in the most recent 36 month  period);  (ii) impose an export  price
higher than the domestic  price subject to an exception with respect to certain
voluntary measures which only restrict the volume of exports; and (iii) disrupt
normal  channels of supply.  All three  countries are prohibited  from imposing
minimum or maximum export or import price requirements,  provided,  in the case
of export price  requirements,  prohibition in any  circumstances  in which any
other  form of  quantitative  restriction  is  prohibited,  and in the  case of
import-price  requirements,  such  requirements  do not apply  with  respect to
enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican  restrictive trade practices in the
energy  sector by 2010 and prohibits  discriminatory  border  restrictions  and
export taxes.  NAFTA also  contemplates  clearer  disciplines  on regulators to
ensure fair implementation of any regulatory changes and to minimize disruption
of  contractual   arrangements  and  avoid  undue  interference  with  pricing,
marketing  and  distribution  arrangements,  which is  important  for  Canadian
natural gas exports.

PROVINCIAL ROYALTIES AND INCENTIVES

GENERAL

In  addition  to  federal   regulation,   each  province  has  legislation  and
regulations   which   govern  land   tenure,   royalties,   production   rates,
environmental   protection,   and  other  matters.  The  royalty  regime  is  a
significant  factor in the  profitability  of crude oil,  natural gas  liquids,
sulphur, and natural gas production. Royalties payable on production from lands
other than Crown lands are determined by negotiations between the mineral owner
and the  lessee,  although  production  from such  lands is  subject to certain
provincial taxes and royalties.  Crown royalties are determined by governmental
regulation  and are  generally  calculated  as a percentage of the value of the
gross  production.  The rate of royalties  payable generally depends in part on
prescribed reference prices, well productivity,  geographical  location,  field
discovery  date,  method of recovery,  and the type or quality of the petroleum
product produced.  Other royalties and royalty-like interests are, from time to
time,  carved out of the working interest  owner's interest through  non-public
transactions.  These are  often  referred  to as  overriding  royalties,  gross
overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive
programs for  exploration  and  development.  Such  programs  often provide for
royalty rate reductions,  royalty holidays,  and tax credits, and are generally
introduced  when  commodity  prices  are low.  The  programs  are  designed  to
encourage  exploration and development  activity by improving earnings and cash
flow within the  industry.  Royalty  holidays and  reductions  would reduce the
amount  of Crown  royalties  paid by oil and gas  producers  to the  provincial
governments and would increase the net income and funds from

<PAGE>
                                      46


operations of such producers.  However,  the trend in recent years has been for
provincial governments to eliminate,  amend or allow such incentive programs to
expire  without  renewal,  and  consequently  few such  incentive  programs are
currently operative.

The  Canadian  federal  corporate  income tax rate levied on taxable  income is
22.1% effective  January 1, 2007 for active business income including  resource
income.  With the elimination of the corporate surtax effective January 1, 2008
and other rate reductions  introduced in the 2006 Federal  Budget,  the federal
corporate income tax rate will decrease to 19% in three steps: 20.5% on January
1, 2008, 20% on January 1, 2009 and 19% on January 1, 2010.

ALBERTA

In Alberta,  companies  are  granted the right to explore,  produce and develop
petroleum  and  natural gas  resources  in exchange  for  royalties,  bonus bid
payments  and rents.  Currently,  the amount of  royalties  that are payable is
influenced  by the oil  production,  density of the oil, and the vintage of the
oil.  Originally,  the  vintage  classified  oil in "new  oil"  and  "old  oil"
depending on when the oil pools were  discovered.  If discovered prior to March
31, 1974 is considered "old oil", if discovered after March 31, 1974 and before
September 1, 1992, is considered "New oil". The Alberta  government  introduced
in 1992 a Third Tier  Royalty with a base rate of 10 per cent and a rate cap of
25 per cent for oil pools  discovered  after  September  1,  1992.  The new oil
royalty  reserved to the Crown has a base rate of 10 per cent and a rate cap of
30 per cent.  The old oil  royalty  reserved to the Crown has a base rate of 10
per cent and a rate cap of 35 per cent.

The royalty reserved to the Crown in respect of natural gas production, subject
to various  incentives,  is between 15 per cent and 30 per cent, in the case of
new natural  gas,  and between 15 per cent and 35 per cent,  in the case of old
natural gas,  depending upon a prescribed or corporate average reference price.
Natural gas produced from qualifying intervals in eligible gas wells spudded or
deepened to a depth below 2,500 metres is also subject to a royalty  exemption,
the amount of which depends on the depth of the well.

Oil sands projects are subject to a specific  regulation made effective July 1,
1997,  and expiring June 30, 2007,  which,  among other things,  determines the
Crown's share of crude and processed oil sands products.

Regulations  made  pursuant to the MINES AND  MINERALS ACT  (Alberta)  provided
various  incentives  for  exploring  and  developing  oil  reserves in Alberta.
However,  the Alberta Government  announced in August of 2006 that four royalty
programs were to be amended, a new program was to be introduced and the Alberta
Royalty Tax Credit Program ("ARTC") was to be eliminated,  effective January 1,
2007.  The  programs  affected by this  announcement  are: (i) Deep Gas Royalty
Holiday;  (ii) Low Productivity Well Royalty Reduction;  (iii) Reactivated Well
Royalty Exemption;  and (iv) Horizontal Re-Entry Royalty Reduction. The program
being  introduced is the Innovative  Energy  Technologies  Program (the "IETP")
which is intended to promote the producers' investment in research,  technology
and innovation for the purposes of improving  environmental  performance whilst
creating  commercial  value.  The IETP provides  royalty  reductions  which are
presumed to reduce  financial  risk.  Alberta  Energy will be the one to decide
which  projects  qualify and the level of support  that will be  provided.  The
deadline for the IETP's third round of applications is May 31, 2007.

On February 16, 2007,  the Alberta  Government  announced  that a review of the
province's  royalty and tax regime  (including  income tax and freehold mineral
rights tax)  pertaining  to oil, gas and oil sands will be conducted by a panel
of experts,  with the assistance of individual  Albertans and key stakeholders.
The purpose of this process is to ensure that  Albertans  are  receiving a fair
share from energy development through royalties,  taxes and fees. The issues to
be reviewed during this examination process are:

<PAGE>
                                      47


(i)  undertaking a comparison of Alberta's  royalty system to other oil and gas
producing jurisdictions,  taking into account investment economics and industry
returns  and  risks in  Alberta;  (ii)  whether  Alberta's  royalty  system  is
sufficiently sensitive to market conditions;  (iii) whether the current revenue
minus cost system for oil sands royalties is optimal; (iv) which programs built
into the existing royalty system should be retained or strengthened,  and which
should be adapted or  eliminated;  (v) how the tax treatment of the oil and gas
sector  compares to other  sectors and  jurisdictions;  (vi) the  economic  and
fiscal  impacts  of any  possible  changes to the  royalty  and  corporate  tax
structures;  and (vii) how existing resource  development  should be treated if
changes are to be made to the fiscal  regime.  The review panel is to produce a
final report that will be  presented to the Minister of Finance by August,  31,
2007.

BRITISH COLUMBIA

Producers  of oil and  natural  gas in the  Province  of British  Columbia  are
required to pay annual  rental  payments  with  respect to the Crown leases and
royalties and freehold production taxes in respect of oil and gas produced from
Crown and  freehold  lands.  The amount  payable as a royalty in respect of oil
depends on the type of oil,  the value of the oil, the quantity of oil produced
in a month, and the vintage of the oil. Generally,  the vintage of oil is based
on the  determination  of whether  the oil is produced  from a pool  discovered
before October 31, 1975 (old oil),  between  October 31, 1975, and June 1, 1998
(new oil),  or after  June 1, 1998  (third-tier  oil).  The  royalty  rates are
calculated in three stages,  which take into account the vintage of the oil, if
the oil produced has already been sold and any royalty exempt value  applicable
(exempt wells). Oil produced from newly discovered pools may be exempt from the
payment  of a  royalty  for the first 36 months  of  production  or  11,450m(3)
produced,  whichever comes first;  and the royalties for third-tier oil are the
lowest  reflecting  the higher costs of  exploration  and  extraction  that the
producers  would incur.  The royalty  payable on natural gas is determined by a
sliding  scale  based on a reference  price,  which is the greater of the price
obtained by the producer,  and a prescribed  minimum price.  However,  when the
reference price is below the select price (a parameter used in the royalty rate
formula),  the royalty rate is fixed.  As an incentive for the  production  and
marketing of natural gas,  which may have been flared,  natural gas produced in
association  with  oil  has  a  lower  royalty  then  the  royalty  payable  on
non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for the province of British
Columbia announced an Oil and Gas Development Strategy for the Heartlands
("Strategy"). The Strategy is a comprehensive program to address road
infrastructure, targeted royalties and regulatory reduction, and British
Columbia service sector opportunities. In addition, the Strategy will result in
economic and employment opportunities for communities in British Columbia's
heartlands.

Some of the financial incentives in the Strategy include:

    o    Royalty   credits  of  up  to  $30   million   annually   towards  the
         construction,  upgrading,  and maintenance of road  infrastructure  in
         support of  resource  exploration  and  development.  Funding  will be
         contingent upon an equal contribution from industry.

    o    Changes  to   provincial   royalties:   new  royalty   rates  for  low
         productivity  natural  gas to enhance  marginally  economic  resources
         plays,  royalty credits for deep gas exploration to locate new sources
         of natural gas, and royalty  credits for summer drilling to expand the
         drilling season.

On February 27, 2007 the  Government  of British  Columbia  unveiled the Energy
Plan  outlining  the  Province's  strategy  towards the  environment  and which
includes  targeting  for zero  net  greenhouse  gas  emissions,  promoting  new
investments  in  innovation,  and  becoming the world's  leader in  sustainable
environmental  management.  With  regards  to the  oil  and  gas  industry  the
objective is to achieve clean energy through  conservation and energy efficient
practices,  whilst  competitiveness is advocated in order to attract investment
for the  development  of the  oil  and gas  sector.  Among  the  changes  to be
implemented are:

<PAGE>
                                      48


(i) a new of Net Profit  Royalty  Program;  (ii) the  creation  of a  Petroleum
Registry;   (iii)  the  establishing  of  an  infrastructure   royalty  program
(combining  roads and  pipelines);  (iv) the  elimination of routine flaring at
producing wells; (v) the creation of policies and measures for the reduction of
emissions;  (vi) the development of unconventional  resources such as tight gas
and coalbed gas; and (vii) new the Oil and Gas  Technology  Transfer  Incentive
Program  that  encourages  the  research,  development  and  use of  innovative
technologies  to  increase  recoveries  from  existing  reserves  and  promotes
responsible development of new oil and gas reserves.

SASKATCHEWAN

In  Saskatchewan,  the amount payable as a royalty in respect of oil depends on
the vintage of the oil,  the type of oil,  the  quantity  of oil  produced in a
month, and the value of the oil. For Crown royalty and freehold  production tax
purposes,  crude oil is considered "heavy oil",  "southwest designated oil", or
"non-heavy oil other than southwest  designated oil". The conventional  royalty
and production tax  classifications  ("fourth tier oil"  introduced  October 1,
2002,  "third  tier  oil",  "new  oil",  or "old  oil") of oil  production  are
applicable to each of the three crude oil types. The Crown royalty and freehold
production  tax structure for crude oil is price  sensitive and varies  between
the base  royalty  rates of 5 per cent for all "fourth tier oil" to 20 per cent
for "old oil". Marginal royalty rates are 30 per cent for all "fourth tier oil"
to 45 per cent for "old oil".

The amount  payable as a royalty in respect of natural gas is  determined  by a
sliding  scale based on a reference  price  (which is the greater of the amount
obtained by the producer and a prescribed minimum price), the quantity produced
in a given month,  the type of natural gas, and the vintage of the natural gas.
As an incentive for the  production and marketing of natural gas which may have
been flared,  the royalty rate on natural gas produced in association  with oil
is less than on  non-associated  natural  gas. The royalty and  production  tax
classifications  of gas production are "fourth tier gas" introduced  October 1,
2002,  "third  tier gas",  "new  gas",  and "old gas".  The Crown  royalty  and
freehold  production tax for gas is price sensitive and varies between the base
royalty rate of 5 per cent for "fourth tier gas" and 20 per cent for "old gas".
The marginal royalty rates are between 30 per cent for "fourth tier gas" and 45
per cent for "old gas".

On October 1, 2002,  the  following  changes  were made to the  royalty and tax
regime in Saskatchewan:

    o    A new Crown royalty and freehold  production tax regime  applicable to
         associated  natural gas (gas produced from oil wells) that is gathered
         for use or sale. The royalty/tax will be payable on associated natural
         gas produced from an oil well that exceeds  approximately  65 thousand
         cubic metres in a month.

    o    A modified system of incentive  volumes and maximum  royalty/tax rates
         applicable to the initial production from oil wells and gas wells with
         a finished  drilling date on or after October 1, 2002, was introduced.
         The  incentive  volumes are  applicable  to various well types and are
         subject  to a  maximum  royalty  rate of 2.5 per cent  and a  freehold
         production tax rate of zero per cent.

    o    The elimination of the re entry and short section  horizontal oil well
         royalty/tax  categories.  All  horizontal  oil wells  with a  finished
         drilling  date on or after  October 1, 2002,  will receive the "fourth
         tier" royalty/ tax rates and new incentive volumes.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR")
as a response to the  Government  of Canada  disallowing  crown  royalties  and
similar taxes as a deductible  business expense for income tax purposes.  As of
January 1, 2007, the remaining balance of any unused RTR will be limited in its
carry forward to five years since the  Government of Canada had the  initiative
to reintroduce the full deduction of provincial resource royalties from federal
and provincial taxable income.

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                                      49


LAND TENURE

Crude  oil  and  natural  gas  located  in  the  western   provinces  is  owned
predominantly by the respective provincial governments.  Provincial governments
grant rights to explore for and produce oil and natural gas pursuant to leases,
licences,  and permits for varying terms from two years,  and on conditions set
forth in provincial legislation including requirements to perform specific work
or make  payments.  Oil and natural gas located in such  provinces  can also be
privately  owned and rights to explore for and produce such oil and natural gas
are granted by lease on such terms and conditions as may be negotiated.

ENVIRONMENTAL REGULATION

The  oil and  natural  gas  industry  is  currently  subject  to  environmental
regulations pursuant to a variety of provincial and federal  legislation.  Such
legislation  provides  for  restrictions  and  prohibitions  on the  release or
emission of various substances produced in association with certain oil and gas
industry  operations.  In addition,  such  legislation  requires  that well and
facility  sites be abandoned  and reclaimed to the  satisfaction  of provincial
authorities.   Compliance  with  such   legislation  can  require   significant
expenditures  and a breach of such  requirements  may result in  suspension  or
revocation  of  necessary  licenses and  authorizations,  civil  liability  for
pollution damage, and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into
the ENVIRONMENTAL  PROTECTION AND ENHANCEMENT ACT (Alberta) (the "EPEA"), which
came into force on  September  1, 1993,  and the OIL AND GAS  CONSERVATION  ACT
(Alberta)  (the  "OGCA").  The  EPEA  and OGCA  impose  stricter  environmental
standards,   require  more  stringent  compliance,   reporting  and  monitoring
obligations,  and  significantly  increased  penalties.  In 2006,  the  Alberta
Government  enacted  regulations  pursuant to the EPEA to  specifically  target
sulphur oxide and nitrous oxide emissions from industrial  operations including
the oil and  gas  industry.  No  additional  expenses  are  foreseen  that  are
associated with complying with the new  regulations.  The  Corporation  will be
committed to meeting its  responsibilities to protect the environment  wherever
it operates and anticipates making increased expenditures of both a capital and
an expense  nature as a result of the  increasingly  stringent laws relating to
the protection of the environment, and will be taking such steps as required to
ensure compliance with the EPEA and similar  legislation in other jurisdictions
in which it  operates.  The  Corporation  believes  that it will be in material
compliance with applicable environmental laws and regulations.  The Corporation
also  believes that it is  reasonably  likely that the trend  towards  stricter
standards in environmental legislation and regulation will continue.

The Alberta  Government has also released draft  regulations  that will require
facilities  that emit over 100,000  tonnes of CO2E (total  Greenhouse  Gases in
terms of CO2 equivalent) to reduce their emissions intensity (quantity of gases
releases  per  unit  of  production)  by 12  percent  starting  July  1,  2007.
Facilities  that do not reduce  their  emissions  intensity by this amount will
either be charged $15/tonne for every tonne they are over the 12 percent target
or they will have to invest in projects outside of their facility, but still in
Alberta,  that  reduce or  offset  emissions  on their  behalf.  ARC  currently
operates  five  facilities  that fall  under the  current  regulations  and has
assessed the impact of this  regulation  and believes  that these  targets will
result in minimal increased operating costs for facilities that are under these
regulations.

British Columbia's ENVIRONMENTAL ASSESSMENT ACT became effective June 30, 1995.
This  legislation  rolls the previous  processes for the review of major energy
projects   into  a  single   environmental   assessment   process  with  public
participation in the environmental review process.

In  December,  2002,  the  Government  of Canada  ratified  the Kyoto  Protocol
("Protocol").  The  Protocol  calls for  Canada to reduce  its  greenhouse  gas
emissions to 6 per cent below 1990 "business-as-usual"  levels between 2008 and
2012. Given revised estimates of Canada's normal emissions levels,  this target

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                                      50


translates  into an  approximately  40 per cent  gross  reduction  in  Canada's
current emissions.  It remains uncertain whether the Kyoto target of 6 per cent
below 1990 emission levels will be enforced in Canada. The Government of Canada
has introduced  legislation aimed at reducing  greenhouse gas emissions using a
"intensity  based" approach,  the specifics of which have yet to be determined.
Bill C-288,  which is intended to ensure that Canada  meets its global  climate
change obligations under the Kyoto Protocol, was passed by the House of Commons
on February 14, 2007.

                                 RISK FACTORS

The following is a summary of certain risk factors  relating to the business of
the Trust which prospective investors should carefully consider before deciding
whether to purchase Trust Units or Exchangeable Shares.

VOLATILITY OF OIL AND NATURAL GAS PRICES

Our operational results and financial  condition,  and therefore the amounts we
pay to  Unitholders,  will be  dependent  on the  prices  received  for oil and
natural gas  production.  Oil and natural  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 our financial condition and therefore on the distributable  income to
be  distributed  to holders of Trust Units.  We may manage the risk  associated
with  changes in  commodity  prices by  entering  into oil or natural gas price
hedges.  If we hedge our commodity price exposure,  we will forego the benefits
we  would  otherwise  experience  if  commodity  prices  were to  increase.  In
addition, commodity hedging activities could expose us to losses. To the extent
that we engage in risk management  activities  related to commodity  prices, we
will be subject to credit risks  associated with  counterparties  with which we
contract.

PROPOSED FEDERAL TAX CHANGES

On October 31, 2006 the Federal  Minister of Finance proposed to apply a tax at
the trust level on  distributions of certain income from publicly traded mutual
fund trusts at rates of tax  comparable to the combined  federal and provincial
corporate tax and to treat such  distributions  as dividends to the Unitholders
(the  "October 31  Proposals").  On December  21, 2006 the Federal  Minister of
Finance released draft  legislation to implement the October 31, 2006 Proposals
pursuant to which,  commencing  January 1, 2011 (provided ARC only  experiences
"normal  growth" and no "undue  expansion"  before then) certain  distributions
from us which would have otherwise been taxed as ordinary income generally will
be  characterized as dividends in addition to being subject to tax at corporate
rates at the Trust  level.  Assuming the October 31  Proposals  are  ultimately
enacted in their form, the implementation of such legislation would be expected
to result in adverse tax consequences to us and certain Unitholders  (including
most particularly Unitholders that are tax deferred or non-residents of Canada)
and may impact cash distributions from us.

Management  believes  that the October 31 Proposals may reduce the value of the
Trust  Units,  which would be  expected to increase  the cost to ARC of raising
capital in the public capital markets. In addition management believes that the
October 31 Proposals are expected to place ARC and other Canadian energy trusts
at a potential  disadvantage relative to industry  competitors,  including U.S.
master  limited  partnerships,  which will continue to not be subject to entity
level  taxation.  The October 31 Proposals  are also expected to make the Trust
Units less attractive as an acquisition  currency.  As a result,  it may become
more difficult for us to compete effectively for acquisition opportunities.  We
are currently  investigating  alternatives  for the mitigation of the effect of
the October 31 Proposals but there can be no

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                                      51


assurance  that we will be able to  reorganize  our legal and tax  structure to
substantially mitigate the expected impact of the October 31 Proposals.

Further,  the proposals  provide  that,  while there is no intention to prevent
"normal growth" during the  transitional  period,  any "undue  expansion" could
result in the transition period being "revisited",  presumably with the loss of
the benefit to us of that  transitional  period.  As a result,  the adverse tax
consequences resulting from the proposals could be realized sooner than January
1, 2011. On December 15, 2006, the Department of Finance issued guidelines with
respect to what is meant by "normal growth" in this context.  Specifically, the
Department of Finance  stated that "normal  growth" would include equity growth
within  certain "safe  harbour"  limits,  measured by reference to a "specified
investment  flow-through's"  ("SIFT")  market  capitalization  as of the end of
trading on October 31, 2006 (which  would  include only the market value of the
SIFT's  issued  and  outstanding  publicly-traded  trust  units,  and  not  any
convertible debt,  options or other interests  convertible into or exchangeable
for trust units). Those safe harbour limits are 40 per cent for the period from
November 1, 2006 to December 31, 2007,  and 20 per cent each for calendar 2008,
2009 and 2010. Moreover, these limits are cumulative,  so that any unused limit
for a period carries over into the subsequent period. Additional details of the
Department of Finance's guidelines include the following:

        (a)     new equity for these  purposes  includes units and debt that is
                convertible  into units (and may include other  substitutes for
                equity if attempts are made to develop those);

        (b)     replacing debt that was outstanding as of October 31, 2006 with
                new  equity,  whether  by a  conversion  into  trust  units  of
                convertible  debentures  or  otherwise,  will not be considered
                growth for these  purposes  and will  therefore  not affect the
                safe harbour; and

        (c)     the  exchange,  for trust units,  of  exchangeable  partnership
                units or exchangeable  shares that were  outstanding on October
                31, 2006 will not be considered  growth for those  purposes and
                will  therefore  not affect the safe harbour where the issuance
                of the trust units is made in  satisfaction  of the exercise of
                the exchange right by a person other than the SIFT.

Our market  capitalization  as of the close of trading  on  October  31,  2006,
having regard only to its issued and outstanding  publicly-traded  Trust Units,
was  approximately  $5.7 billion,  which means our "safe harbour" equity growth
amount for the period ending December 31, 2007 is  approximately  $2.3 billion,
and for each of calendar  2008,  2009 and 2010 is an  additional  approximately
$1.1  billion  (in  any  case,  not  including  equity,  including  convertible
debentures, issued to replace debt that was outstanding on October 31, 2006).

While  these  guidelines  are such that it is  unlikely  they would  affect our
ability  to raise  the  capital  required  to  maintain  and grow our  existing
operations in the ordinary  course  during the  transition  period,  they could
adversely  affect the cost of raising capital and our ability to undertake more
significant acquisitions.

The Government of Canada confirmed its intention to proceed with the October 31
Proposals in its budget speech of March 19, 2007.

IT IS NOT KNOWN AT THIS TIME WHEN THE OCTOBER 31  PROPOSALS  WILL BE ENACTED BY
PARLIAMENT,  IF AT ALL, OR WHETHER THE OCTOBER 31 PROPOSALS  WILL BE ENACTED IN
THE FORM CURRENTLY  PROPOSED OR NEW PROPOSALS WILL BE PROPOSED OR ENACTED.  SEE
"RISK FACTORS - CHANGES IN LEGISLATION".

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                                      52


OPERATIONAL MATTERS

The  operation of oil and gas wells  involves a number of operating and natural
hazards which may result in blowouts, environmental damage and other unexpected
or dangerous  conditions  resulting  in damage to us and possible  liability to
third  parties.  We carry  insurance  policies  to provide  protection  for our
working  interests  in the  properties  which cover  property  damage,  general
liability and, for certain properties,  business interruption. We determine the
ongoing level,  type and maintenance of insurance  based upon the  availability
and cost of such  insurance  and our  perception  of the  risk of loss.  We may
become  liable for damages  arising  from such events  against  which we cannot
insure or  against  which we 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 royalty income.

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.  A reduction of the
royalty income could result in such circumstances.

RESERVES ESTIMATES

There are numerous  uncertainties  inherent in  estimating  quantities  of oil,
natural  gas and  natural  gas  liquids  reserves  and the  future  cash  flows
attributed to such reserves. In general,  estimates of economically recoverable
oil and natural gas reserves and the future net cash flows  therefrom are based
upon  a  number  of  variable  factors  and  assumptions,  such  as  historical
production from the properties,  production  rates,  ultimate reserve recovery,
timing  and  amount  of  capital  expenditures,  marketability  of oil and gas,
royalty rates,  the assumed effects of regulation by governmental  agencies and
future  operating  costs, all of which may vary materially from actual results.
All such  estimates  are to some degree  speculative,  and  classifications  of
reserves are only attempts to define the degree of  speculation  involved.  For
those reasons,  estimates of the  economically  recoverable oil and natural gas
reserves attributable to any particular group of properties,  classification of
such  reserves  based on risk of recovery and  estimates of future net revenues
associated  with  reserves  prepared  by  different  engineers,  or by the same
engineers at different times, may vary. Our actual production,  revenues, taxes
and  development and operating  expenditures  with respect to its reserves will
vary from estimates thereof and such variations could be material.

Estimates of proved  reserves  that may be developed and produced in the future
are often based upon volumetric  calculations and upon analogy to similar types
of  reserves  rather  than  actual  production  history.  Recovery  factors and
drainage areas were  estimated by experience  and analogy to similar  producing
pools.  Estimates based on these methods are generally less reliable than those
based on actual production history.  Subsequent evaluation of the same reserves
based  upon  production  history  and  production   practices  will  result  in
variations in the estimated reserves and such variations could be material.

The reserves and  recovery  information  contained in the GLJ Report is only an
estimate and the actual  production  and ultimate  reserves from the properties
may be greater or less than the  estimates  prepared by GLJ. The GLJ Report has
been prepared using certain  commodity price assumptions which are described in
the notes to the  reserves  tables.  If we realize  lower prices for crude oil,
natural gas liquids  and  natural  gas and they are  substituted  for the price
assumptions  utilized in those reserves reports, the present value of estimated
future net cash flows for our reserves would be reduced and the reduction could
be significant, particularly based on the constant price case assumptions.

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                                      53


VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES

An increase in interest  rates could  result in a  significant  increase in the
amount we pay to service  debt,  resulting  in a decrease in  distributions  to
Unitholders, as well as impact the market price of the Trust Units on the TSX.

World oil prices are quoted in Unites States  dollars and the price received by
Canadian producers is therefore  affected by the Canadian/U.S.  dollar exchange
rate that may  fluctuate  over time.  A material  increase  in the value of the
Canadian dollar may negatively impact our net production revenue.

In addition,  the exchange rate for the Canadian  dollar versus the U.S. dollar
has increased  significantly over the last 12 months,  resulting in our receipt
of  fewer  Canadian   dollars  for  our  production  which  may  affect  future
distributions.  We have  initiated  certain hedges to attempt to mitigate these
risks.  To the extent that we engage in risk management  activities  related to
foreign  exchange  rates,  it will be subject to credit  risk  associated  with
counterparties  with which we contract.  The increase in the exchange  rate for
the  Canadian  dollar and future  Canadian/United  States  exchange  rates will
impact future  distributions and the future value of our reserves as determined
by independent evaluators.

PURCHASE OF PROPERTIES

The price we paid for the purchase of the  properties  is based on  engineering
and economic  estimates of the reserves made by independent  engineers modified
to reflect our technical and economic views. 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
which will be imposed over the producing  life of the  reserves.  Many of these
factors are subject to change and are beyond our control and the control of the
operators  of the  properties.  In  particular,  changes  in the  prices of and
markets for petroleum,  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 Trust Units. In addition, all
such  estimates  involve a measure of geological  and  engineering  uncertainty
which could result in lower  production  and reserves  than  attributed  to the
properties.  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.  See "ARC Energy
Trust - General Development of the Business".

ENHANCED OIL RECOVERY

We announced the  Acquisition in December,  2005 which was comprised of a 45.57
per cent working  interest in the North Pembina  Cardium Unit #1 in Alberta and
the  vendors'  working  interests  in the  Redwater  area of Alberta.  For more
information,  see "ARC Energy Trust - General Development of the Business".  We
believe  the  Acquisition  strategically  positions  us  for  participation  in
properties with large reserves of unrecovered original resources in place which
may be amenable to secondary recovery techniques such as carbon dioxide ("CO2")
miscible or immiscible  flooding.  The implementation of secondary oil recovery
techniques  on properties  like  Redwater or the Pembina  Cardium Unit #1 would
require  long term supply  agreements  for CO2 and large  scale  infrastructure
investments.  We have  just  begun to  devote  resources  to the  study of such
matters.  There  is no  assurance  as to  when or if  such  secondary  recovery
techniques  will be implemented,  or if implemented,  when or if such secondary
recovery techniques would be successful.

Currently,  companies  are  permitted to emit CO2 into the  atmosphere  with no
requirement to capture and re-inject the emissions.  In order for ARC Resources
to carry out its enhanced oil recovery program it is necessary to obtain CO2 at
a cost  effective  rate.  Given that  companies are not forced to capture their

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                                      54


emissions,  the  infrastructure  has not been put in place to  facilitate  this
process.  Without any additional  provisions from the government,  the economic
parameters of the Trust's enhanced oil recovery programs would be limited.  For
more information, see "Risk Factors - Environmental Concerns".

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 us and our Unitholders.  Tax authorities having  jurisdiction
over us or  Unitholders  may disagree  with how we calculate our income for tax
purposes or could  change  administrative  practises  to our  detriment  or the
detriment of Unitholders.

We intend to continue to qualify as a mutual fund trust for purposes of the Tax
Act. We may not, however, always be able to satisfy any future requirements for
the maintenance of mutual fund trust status. Should our status as a mutual fund
trust be lost or successfully  challenged by a relevant tax authority,  certain
adverse consequences may arise for us and Unitholders.  Some of the significant
consequences of losing mutual fund trust status are as follows:

    o    We  would  be  taxed  on  certain  types  of  income   distributed  to
         Unitholders,  including  income generated by the Royalties held by us.
         Payment  of  this  tax  may  have   adverse   consequences   for  some
         Unitholders, particularly Unitholders that are not residents of Canada
         and residents of Canada that are otherwise exempt from Canadian income
         tax.

    o    We would cease to be eligible for the capital  gains refund  mechanism
         available  under  Canadian  tax laws if it ceased to be a mutual  fund
         trust.

    o    Trust Units held by Unitholders that are not residents of Canada would
         become taxable Canadian property.  These non-resident holders would be
         subject to Canadian  income tax on any gains realized on a disposition
         of Trust Units held by them.

    o    Trust Units would not constitute qualified  investments for registered
         retirement savings plans ("RRSPs"), registered retirement income funds
         ("RRIFs"),  registered  education  savings plans ("RESTs") or deferred
         profit sharing plans  ("DPSPs").  If, at the end of any month,  one of
         these  exempt   plans  holds  Trust  Units  that  are  not   qualified
         investments, the plan must pay a tax equal to one per cent of the fair
         market  value of the  Trust  Units at the time the  Trust  Units  were
         acquired by the exempt  plan.  An RRSP or RRIF  holding  non-qualified
         Trust Units would be subject to taxation on income attributable to the
         Trust Units. If an RESP holds  non-qualified  Trust Units, it may have
         its registration revoked by the Canada Revenue Agency.

In  addition,  we may take  certain  measures  in the  future to the  extent we
believe necessary to ensure that we maintain the status as a mutual fund trust.
These measures could be adverse to certain holders of Trust Units, particularly
non-residents of Canada as defined in the Tax Act.

On February 16,  2007,  the Alberta  government  launched a review of Alberta's
royalty regime for oil sands, conventional oil and gas and coalbed methane. The
review is intended to assess  whether the existing  royalty regime is providing
Albertans  with a  fair  return  on  the  province's  natural  resources  while
maintaining  an  internationally  competitive  system  that  allows the Alberta
economy to continue to prosper. The review,  expected to be completed by August
31,  2007,  may result in  recommendations  which  could  adversely  impact the
current  royalty  structure in place for our economics for our coalbed  methane
prospects.

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                                      55


For more  information,  see "Risk  Factors -  Non-resident  Ownership  of Trust
Units",  "Risk  Factors  -  Proposed  Federal  Tax  Changes",  "Risk  Factors -
Environmental Concerns",  "Industry Regulations - Environmental Reuglation" and
"Risk Factors - Kyoto Protocol".

MAINTENANCE OF DISTRIBUTIONS

We conduct  limited  exploration  activities  for oil and natural gas reserves.
Instead,  we add  to  our  oil  and  natural  gas  reserves  primarily  through
development and acquisitions.  As a result, future oil and natural gas reserves
are highly  dependent  on our success in  exploiting  existing  properties  and
acquiring additional reserves.  We also distribute the majority of our net cash
flow  to  Unitholders  rather  than  reinvesting  it  in  reserves   additions.
Accordingly,  if  external  sources  of  capital,  including  the  issuance  of
additional   Trust  Units,   become  limited  or  unavailable  on  commercially
reasonable  terms,  our ability to make the necessary  capital  investments  to
maintain or expand its oil and natural gas reserves  will be  impaired.  To the
extent that we are required to use cash flow to finance capital expenditures or
property  acquisitions,  the level of cash flow available for  distribution  to
Unitholders will be reduced.  Additionally, we cannot guarantee that we will be
successful in developing  additional reserves or acquiring  additional reserves
on terms that meet our investment objectives. Without these reserves additions,
our reserves will deplete and as a consequence,  either production from, or the
average  reserves  life of, our  properties  will decline.  Either  decline may
result in a reduction  in the value of Trust  Units and in a reduction  in cash
available for distributions to Unitholders.

EXPANSION OF OPERATIONS

Our operations and expertise are currently  focused on conventional oil and gas
production and development in the Western  Canadian  Sedimentary  Basin. In the
future, we may acquire oil and gas properties  outside this geographic area. In
addition,  the Trust  Indenture  does not limit our  activities  to oil and gas
production and  development,  and we 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  adversely  affect our future
operational and financial conditions.

NON-RESIDENT OWNERSHIP OF TRUST UNITS

The Trust intends to comply with the  requirements  under the Tax Act for "unit
trusts" and "mutual fund  trusts" at all  relevant  times such that we maintain
our status of a unit trust and a mutual fund trust for purposes of the Tax Act.
In this  regard,  we may,  from  time to time,  among  other  things,  take all
necessary  steps to monitor the  activities  of the Trust and  ownership of the
Trust Units.  If at any time we become aware that the  activities  of the Trust
and ownership of the Trust Units by non-residents  (non-residents of Canada and
partnerships) may threaten the status of the Trust under the Tax Act as a "unit
trust" or "mutual fund trust",  we are authorized to take such action as may be
necessary  in the opinion of ARC  Resources to maintain the status of the Trust
as a  unit  trust  and  a  mutual  fund  trust,  including  the  imposition  of
restrictions  on the issuance by the Trust,  or the transfer by any Unitholder,
of Trust Units to a non resident.  See "Limitations on Non-Resident  Ownership"
and "Risk Factors - Change of Legislation".

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 us or our properties.  Such  legislation may be changed to
impose  higher  standards  and  potentially  more  costly  obligations  on  us.
Furthermore, management believes the political climate

<PAGE>
                                      56


appears  to  favour  new  programs  for  environmental   laws  and  regulation,
particularly  in  relation  to the  reduction  of  emissions,  and  there is no
assurance that any such programs, laws or regulations, if proposed and enacted,
will not contain emission reduction targets which we cannot meet, and financial
penalties or charges  could be incurred as a result of the failure to meet such
targets.  In  particular  there is  uncertainty  regarding  the  Government  of
Canada's Clean Air Act of 2006. The Clean Air Act proposes to reduce greenhouse
gas emissions,  however emission  targets and compliance  deadlines differ from
those outlined in the Kyoto  Protocol which was ratified by Canada.  If passed,
the Clean Air Act may have adverse  operational  and financial  implications to
the Trust. See "Industry Regulations - Environmental  Regulation".  Although we
have  established a  reclamation  fund for the purpose of funding our currently
estimated future environmental and reclamation obligations based on our current
knowledge, there can be no assurance that we will be able to satisfy our actual
future environmental and reclamation obligations.

Provincial emission reduction requirements, such as those proposed in Alberta's
Bill 37 Climate Change and Emissions  Management,  may require the reduction of
emissions or emissions  intensity of our operations and facilities.  The direct
or indirect costs of these  regulations may adversely and materially affect our
business.

In December 2002 the  Government of Canada  ratified the Kyoto  Protocol and it
became legally  binding on February 16, 2005. This protocol calls for Canada to
reduce its  greenhouse  gas  emissions to six per cent below 1990 levels during
the period  between 2008 and 2012.  See "Risk Factors - Change of  Legislation"
and "Risk Factors - Kyoto Protocol" below.

KYOTO PROTOCOL

Canada is a signatory to the United  Nations  Framework  Convention  on Climate
Change  and has  ratified  the Kyoto  Protocol  established  thereunder  to set
legally  binding  targets to reduce  nationwide  emissions  of carbon  dioxide,
methane,  nitrous oxide and other so-called "greenhouse gases". Our exploration
and production  facilities and other  operations and activities emit greenhouse
gases that may subject us to  legislation  regulating  emissions of  greenhouse
gases.  The  Government  of Canada has put  forward a Climate  Change  Plan for
Canada which suggests  further  legislation  will set greenhouse gases emission
reduction requirements for various industrial activities, including oil and gas
exploration  and  production.  While the  protocol  became  legally  binding on
February 16, 2005, details of any specific  requirements have not been released
and as a  result  the  potential  impact  on our  operations  and  business  is
difficult to quantify.


ADDITIONAL FINANCING

In the normal course of making  capital  investments to maintain and expand our
oil and gas reserves  additional Trust Units are issued from treasury which may
result in a decline in  production  per Trust Unit and reserves per Trust Unit.
Additionally,  from time to time we issue Trust 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
Trust Units become  limited or  unavailable,  our ability to make the necessary
capital  investments  to  maintain or expand our oil and gas  reserves  will be
impaired.  Management  believes  that the October 31  Proposals  may reduce the
value of the Trust  Units,  which would be  expected  to  increase  the cost of
capital to ARC of raising  capital in the public  capital  markets..  See "Risk
Factors - Proposed Federal Tax Changes".  To the extent that we are required to
use cash flow to finance capital  expenditures  or property  acquisitions or to
pay debt service charges or to reduce debt, the level of  distributable  income
will be reduced.

<PAGE>
                                      57


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,  who are
competing  for the  acquisitions  of  properties  with longer life reserves and
properties  with  exploitation  and development  opportunities.  The October 31
Proposals of the  Government  of Canada are expected by  management to make our
Trust Units less  attractive as an  acquisition  currency.  See "Risk Factors -
Proposed Federal Tax Changes". As a result of such increasing  competition,  it
will be more difficult to acquire reserves on beneficial terms. We also compete
for  reserves  acquisitions  with a  substantial  number  of other  oil and gas
companies,  many of  which  have  significantly  greater  financial  and  other
resources than we do.

The Trust  competes with other oil and gas entities to hire and retain  skilled
personnel  necessary for running of daily operations of the Trust including the
execution of the annual capital development  program. The inability to hire and
retain  skilled  personnel  could  adversely  impact  certain  operational  and
financial results of the Trust.

ACCOUNTING WRITE-DOWNS AS A RESULT OF GAAP

Canadian  Generally  Accepted  Accounting   Principles  ("GAAP")  require  that
management  apply certain  accounting  policies and make certain  estimates and
assumptions  which  affect  reported  amounts  in  our  consolidated  financial
statements.  The  accounting  policies  may result in  non-cash  charges to net
income and write-downs of net assets in the financial statements. Such non-cash
charges and write-downs may be viewed unfavourably by the market and may result
in an  inability  to borrow  funds  and/or may result in a decline in the Trust
Unit price.

Under  GAAP,  the net  amounts at which  petroleum  and  natural gas costs on a
property or project basis are carried are subject to a cost-recovery test which
is based in part upon  estimated  future net cash flows from  reserves.  If net
capitalized  costs exceed the estimated  recoverable  amounts,  we will have to
charge the amounts of the excess to earnings. A decline in the net value of oil
and natural gas  properties  could cause  capitalized  costs to exceed the cost
ceiling,  resulting in a charge against earnings.  The net value of oil and gas
properties  are highly  dependent  upon the prices of oil and natural  gas. See
"Risk Factors - Volatility of Oil and Natural Gas Prices".

GAAP  requires  that  goodwill  balances  be  assessed  at least  annually  for
impairment  and that any  permanent  impairment  be  charged to net  income.  A
permanent reduction in reserves,  decline in commodity prices, and/or reduction
in the Trust Unit price may indicate  goodwill  impairment.  As at December 31,
2006 we had $157.6  million  recorded on its balance sheet as goodwill  arising
out of our  acquisition  of Star Oil & Gas Ltd. in 2003.  An  impairment  would
result in a write-down of the goodwill value and a non-cash  charge against net
income. The calculation of impairment value is subject to management  estimates
and assumptions.

New GAAP surrounding  accounting for derivatives may result in non-cash charges
against  net  income  as a  result  of  changes  in the  fair  market  value of
derivative  instruments.  A decrease in the fair market value of the derivative
instruments  as the result of  fluctuations  in  commodity  prices and  foreign
exchange  rates may result in a write-down of net assets and a non-cash  charge
against net income.  Such  write-downs and non-cash charges may be temporary in
nature if the fair market value subsequently increases.

DEBT SERVICE

Amounts paid in respect of interest and  principal on debt  incurred in respect
of the properties will reduce royalty income.  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 the Royalties
and interest

<PAGE>
                                      58


on the Long Term  Notes and  distributable  income.  Certain  covenants  of the
agreements  with  our  lenders  may  also  limit  distributions  to us from our
subsidiaries.  Although we believe the credit facilities will be sufficient for
our immediate  requirements,  there can be no assurance that the amount will be
adequate for our future financial  obligations or that additional funds will be
able to be obtained.  For more information,  see "Other Information Relating To
Our Business - Borrowing".

The lenders have or will be provided with security  over  substantially  all of
our assets.  If we become  unable to pay our debt service  charges or otherwise
commit an event of default such as  bankruptcy,  the lender may foreclose on or
sell the properties  free from or together with the  Royalties.  The payment of
interest and principal on debt may also result in us having  taxable income and
cash  taxes  payable as  taxable  income  would no longer be reduced by royalty
payments at the time debt repayment occurs.

DELAY IN CASH DISTRIBUTIONS

In addition to the usual delays in payment by purchasers of oil and natural gas
to the operators of the properties, and by the operator to us, payments between
any of such  parties  may also be delayed by  restrictions  imposed by lenders,
delays in the sale or delivery of products,  delays in the  connection of wells
to a gathering system, blowouts or other accidents, recovery by the operator of
expenses  incurred in the operation of the properties or the  establishment  by
the operator of reserves for such expenses.

RELIANCE ON MANAGEMENT

Unitholders   will  be   dependent  on  our   management   in  respect  of  the
administration  and management of all matters  relating to our properties,  the
Royalties and Trust Units.  As of December 31, 2006, we operated  approximately
70 per cent of the total daily production of our properties.  Investors who are
not willing to rely on our management should not invest in Trust Units.

DEPLETION OF RESERVES

Distributions  of  distributable  income  in  respect  of  properties,   absent
commodity  price  increases  or  cost  effective  acquisition  and  development
activities,  will  decline  over  time in a manner  consistent  with  declining
production from typical oil, natural gas and natural gas liquids  reserves.  We
will  not be  reinvesting  cash  flow in the  same  manner  as  other  industry
participants as we conduct only minimal exploratory activities; nor to the same
extent  as other  industry  participants  as one of our main  objectives  is to
maximize long-term distributions.  Accordingly,  absent capital injections, our
initial   production  levels  and  reserves  will  decline  and  the  level  of
distributable income will be reduced.

Our future oil and natural gas reserves and production,  and therefore our cash
flows,  will be highly dependent on our success in exploiting our reserves base
and  acquiring   additional   reserves.   Without  reserves  additions  through
acquisition or development activities, our reserves and production will decline
over time as reserves are exploited.

To the extent that  external  sources of  capital,  including  the  issuance of
additional  Trust Units become limited or unavailable,  our ability to make the
necessary  capital  investments  to  maintain or expand our oil and natural gas
reserves will be impaired.  To the extent that we are required to use cash flow
to  finance  capital  expenditures  or  property  acquisitions,  the  level  of
distributable income will be reduced.

There can be no assurance that we will be successful in developing or acquiring
additional reserves on terms that meet our investment objectives.

<PAGE>
                                      59


NET ASSET VALUE

The net asset value of our assets from time to time will vary  dependent upon a
number of factors  beyond  the  control of  management,  including  oil and gas
prices.  The  trading  prices  of the  Trust  Units  from  time to time is also
determined  by a number of factors  which are beyond the control of  management
and such trading prices may be greater than the net asset value of our assets.

RETURN OF CAPITAL

Trust Units will have no value when 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 and are not  comparable  to bonds or other
fixed yield  securities,  where  investors are entitled to a full return of the
principal  amount of debt on maturity  in  addition  to a return on  investment
through  interest  payments.  Distributions  represent  a blend  of  return  of
Unitholders initial investment and a return on Unitholders initial investment.

Unitholders  have a limited right to require a repurchase of their Trust Units,
which is referred to as a redemption  right.  See "Our  Information  - Right of
Redemption."  It is  anticipated  that  the  redemption  right  will not be the
primary mechanism for Unitholders to liquidate their  investment.  The right to
receive cash in  connection  with a redemption is subject to  limitations.  Any
securities which may be distributed IN SPECIE to Unitholders in connection with
a  redemption  may not be  listed on any stock  exchange  and a market  may not
develop for such  securities.  In  addition,  there may be resale  restrictions
imposed by law upon the recipients of the securities pursuant to the redemption
right.

NATURE OF TRUST UNITS

The  Trust  Units do not  represent  a  traditional  investment  in the oil and
natural  gas  sector and  should  not be viewed by  investors  as shares in ARC
Resources.  The Trust  Units  represent  a  fractional  interest  in the Trust.
Corporate  law does not  govern  the Trust and the  rights of  Unitholders.  As
holders of Trust Units, Unitholders will not have the statutory rights normally
associated  with ownership of shares of a corporation  including,  for example,
the right to bring oppression or derivative actions.  The rights of Unitholders
are specifically set forth in the Trust Indenture. In addition,  trusts are not
defined as recognized  entities within the  definitions of legislation  such as
the  BANKRUPTCY  AND   INSOLVENCY  ACT  (Canada),   the  COMPANIES'   CREDITORS
ARRANGEMENT ACT (Canada) and in some cases the WINDING UP AND RESTRUCTURING ACT
(Canada).  As a  result,  in the event of an  insolvency  or  restructuring,  a
Unitholder's position as such may be quite different than that of a shareholder
of a  corporation.  The  Trust's  sole  assets  will be the  royalty  and other
investments  in  securities.  The  price  per  Trust  Unit  is  a  function  of
anticipated distributable income, the properties acquired by us and our ability
to effect  long-term  growth in our value.  The market price of the Trust Units
will be sensitive to a variety of market conditions including,  but not limited
to,  interest  rates and our  ability to acquire  suitable  oil and natural gas
properties. Changes in market conditions may adversely affect the trading price
of the Trust Units.

THE TRUST UNITS ARE NOT  "DEPOSITS"  WITHIN THE  MEANING OF THE CANADA  DEPOSIT
INSURANCE  CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF
THAT ACT OR ANY OTHER LEGISLATION. FURTHERMORE, WE ARE NOT A TRUST COMPANY AND,
ACCORDINGLY, ARE NOT REGISTERED UNDER ANY TRUST AND LOAN COMPANY LEGISLATION AS
WE DO NOT CARRY ON OR INTEND TO CARRY ON THE BUSINESS OF A TRUST COMPANY.

UNITHOLDER LIMITED LIABILITY

The  Trust  Indenture  provides  that  no  Unitholder  will be  subject  to any
liability  in  connection  with us or our  obligations  and affairs and, in the
event that a court determines Unitholders are subject to any such

<PAGE>
                                      60


liabilities,  the  liabilities  will be enforceable  only against,  and will be
satisfied  only out of our  assets.  Pursuant to the Trust  Indenture,  we will
indemnify  and  hold  harmless  each  Unitholder   from  any  costs,   damages,
liabilities,  expenses,  charges and losses suffered by a Unitholder  resulting
from or arising out of such Unitholder not having such limited liability.

The Trust  Indenture  provides  that all  written  instruments  signed by or on
behalf of the Trust must contain a provision to the effect that such obligation
will not be binding upon Unitholders  personally.  The principal  investment of
the Trust is the royalty  agreements  which contain such  provisions.  Personal
liability  may also arise in respect  of claims  against  the Trust that do not
arise under contracts,  including claims in tort, claims for taxes and possibly
certain other statutory liabilities.  The possibility of any personal liability
of this nature arising is considered unlikely.  The INCOME TRUSTS LIABILITY ACT
(Alberta)  came into force on July 1, 2004.  The  legislation  provides  that a
unitholder  will  not  be,  as a  beneficiary,  liable  for any  act,  default,
obligation or liability of the trustee that arises after the  legislation  came
into force.

Our operations will be conducted, upon the advice of counsel, in such a way and
in such  jurisdictions  as to avoid as far as  possible  any  material  risk of
liability on Unitholders for claims against the Trust.

TITLE TO PROPERTIES

The rights to produce  petroleum and gas substances are subject to an agreement
between us and the owners of the mineral resource.  The terms of this agreement
contains  certain ongoing  obligations and commitments  that, if not fulfilled,
can result in the forfeiture of the agreement to the mineral right owner or the
payment of cash compensation.

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 our claim to certain properties.  In
certain  situations  there may be multiple  mineral  resource  owners  claiming
various  ownership over the same parcel of land. Any settlement of a dispute of
ownership  may result in the  forfeiture  of the mineral  resource by us or the
payment of cash compensation to the mineral resource owner.

                        TRANSFER AGENTS AND REGISTRARS

The  transfer  agent and  registrar  for the Trust  Units and the  Exchangeable
Shares is  Computershare  Trust Company of Canada at its  principal  offices in
Calgary and Toronto.

                              MATERIAL CONTRACTS

The following  comprises  particulars of every  material  contract to the Trust
that was entered into within the most  recently  completed  financial  year, or
entered into before the most recently  completed  financial year which is still
in  effect,  other  than a  contract  entered  into in the  ordinary  course of
business:

1.      Trust Indenture. For information,  see "Our Information" and "Corporate
        Governance".

2.      Exchangeable Share Provisions.  For information,  see "Share Capital of
        ARC Resources - Exchangeable Shares".

3.      Exchangeable   Share  Voting  and   Exchange   Trust   Agreement.   For
        information,  see  "Share  Capital  of  ARC  Resources  -  Exchangeable
        Shares".

4.      Exchangeable  Share  Support  Agreement.  For  information,  see "Share
        Capital of ARC Resources - Exchangeable Shares".

<PAGE>
                                      61


Copies of each of these documents have been filed on SEDAR at WWW.SEDAR.COM.

                              INTEREST OF EXPERTS

There is no person or company whose profession or business gives authority to a
statement made by such person or company and who is named as having prepared or
certified a statement,  report or valuation  described or included in a filing,
or referred to in a filing, made under National Instrument 51-102 by us during,
or related to, our most recently  completed  financial year other than GLJ, our
independent engineering evaluator,  and Deloitte & Touche LLP, our auditors. As
at the date hereof the designated  professionals  of GLJ Petroleum  Consultants
Ltd., as a group,  beneficially owned, directly or indirectly,  less than 1 per
cent of our outstanding securities,  including the securities of our associates
and  affiliates.  Deloitte  & Touche  LLP is the  auditor  of the  Trust and is
independent  within  the  meaning of the Rules of  Professional  Conduct of the
Institute of Chartered Accountants, Alberta.

In addition, none of the aforementioned persons or companies, nor any director,
officer or employee of any of the aforementioned persons or companies, is or is
expected  to be  elected,  appointed  or  employed  as a  director,  officer or
employee of ARC  Resources or of any of our  associate  or affiliate  entities.
Allan R. Twa, the Corporate Secretary of ARC Resources, is a partner of Burnet,
Duckworth & Palmer LLP, which law firm renders legal services to us.

                             ADDITIONAL INFORMATION

Additional information including remuneration and indebtedness of directors and
officers of ARC Resources,  principal holders of the Trust Units,  Exchangeable
Shares and rights to purchase  Trust Units,  is  contained  in the  Information
Circular - Proxy  Statement of the Trust which relates to the Annual Meeting of
Unitholders  to be held on May 23, 2007.  Additional  financial  information is
provided in our consolidated financial statements and accompanying management's
discussion and analysis for the year ended  December 31, 2006,  which have been
filed on SEDAR at www.sedar.com.



<PAGE>

                                   APPENDIX A
                                  FORM 51-101F2

      REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

To the board of directors of ARC Resources Ltd. (the "Company"):

1.   We have  prepared  an  evaluation  of the  Company's  reserves  data as at
     December 31, 2006. The reserves data consist of the following:

     (a)  (i)    proved and proved plus probable oil and gas reserves estimated
                 as at December 31, 2006 using forecast prices and costs; and

          (ii)   the related estimated future net revenue; and

     (b)  (i)    proved oil and gas reserves  estimated as at December 31, 2006
                 using constant prices and costs; and

          (ii)   the related estimated future net revenue.

2.   The reserves data are the responsibility of the Company's management.  Our
     responsibility  is to express an opinion on the reserves data based on our
     evaluation.

     We carried out our evaluation in accordance  with standards set out in the
     Canadian Oil and Gas Evaluation  Handbook (the "COGE  Handbook")  prepared
     jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
     and the Canadian  Institute of Mining,  Metallurgy & Petroleum  (Petroleum
     Society).

3.   Those  standards  require that we plan and perform an evaluation to obtain
     reasonable  assurance as to whether the reserves data are free of material
     misstatement.  An evaluation also includes  assessing whether the reserves
     data are in accordance with  principles and  definitions  presented in the
     COGE Handbook.

4.   The following  table sets forth the estimated  future net revenue  (before
     deduction of income taxes)  attributed  to proved plus probable  reserves,
     estimated using forecast prices and costs and calculated  using a discount
     rate  of 10  per  cent,  included  in the  reserves  data  of the  Company
     evaluated by us for the year ended  December 31, 2006,  and identifies the
     respective  portions thereof that we have audited,  evaluated and reviewed
     and reported on to the Company's board of directors:

<TABLE>
<CAPTION>
                                                         Location of
                                                          Reserves
                                                         (Country or            Net Present Value of Future Net Revenue
         Independent             Description and           Foreign       (before income taxes, 10% discount rate, million dollars)
     Qualified Reserves        Preparation Date of       Geographic      ---------------------------------------------------------
          Evaluator             Evaluation Report           Area)         Audited        Evaluated        Reviewed        Total
   ---------------------     ----------------------     --------------   ---------      -----------      ----------     ----------
<S>                          <C>                        <C>              <C>            <C>              <C>            <C>
        GLJ Petroleum            January 23, 2007          Canada            -             $4,056             -          $4,056
      Consultants Ltd.
</TABLE>

5.   In our opinion,  the reserves data  respectively  evaluated by us have, in
     all material respects, been determined and are in accordance with the COGE
     Handbook.

6.   We have no  responsibility  to  update  this  evaluation  for  events  and
     circumstances occurring after the preparation dates.

<PAGE>
                                      A-2


7.   Because the reserves data are based on judgments  regarding future events,
     actual results will vary and the variations may be material.



Executed as to our report referred to above:


GLJ Petroleum Consultants Ltd.                    Dated February 12, 2007
Calgary, Alberta, Canada


/s/ James H. Willmon
------------------------
James H. Willmon, P.Eng
Vice President



<PAGE>

                                   APPENDIX B

                     REPORT OF MANAGEMENT AND DIRECTORS ON
                      RESERVES DATA AND OTHER INFORMATION

Management of ARC Resources Ltd. (the  "Company") on behalf of ARC Energy Trust
(the "Trust") are responsible for the preparation and disclosure of information
with respect to the Company's and the other Trust's  subsidiaries'  oil and gas
activities  in  accordance  with  securities  regulatory   requirements.   This
information includes reserves data, which consist of the following:

     (a)  (i)    proved and proved plus probable oil and gas reserves estimated
                 as at December 31, 2006 using forecast prices and costs; and

          (ii)   the related estimated future net revenue; and

     (b)  (i)    proved oil and gas reserves  estimated as at December 31, 2006
                 using constant prices and costs; and

          (ii)   the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Company's and the
other  Trust's  subsidiaries'  reserves  data.  The  report of the  independent
qualified reserves evaluator is presented below.

The Reserves Committee of the board of directors of the Company has

     (c)  reviewed the Company's  procedures  for providing  information to the
          independent qualified reserves evaluator;

     (d)  met with the independent  qualified  reserves  evaluator to determine
          whether any  restrictions  affected  the  ability of the  independent
          qualified reserves evaluator to report without reservation; and

     (e)  reviewed  the  reserves  data  with  management  and the  independent
          qualified reserves evaluator.

The Reserves  Committee of the board of  directors  has reviewed the  Company's
procedures for assembling and reporting other  information  associated with oil
and gas activities and has reviewed that information with management. The board
of directors has, on the recommendation of the Reserves Committee, approved

     (f)  the content and filing with securities regulatory  authorities of the
          reserves data and other oil and gas information;

     (g)  the  filing  of the  report  of the  independent  qualified  reserves
          evaluator on the reserves data; and

     (h)  the content and filing of this report.

<PAGE>
                                      B-2


Because the  reserves  data are based on  judgments  regarding  future  events,
actual results will vary and the variations may be material.


/s/ John P. Dielwart                            /s/ Myron Stadnyk
------------------------                        ---------------------
JOHN P. DIELWART                                MYRON STADNYK
President and Chief Executive                   Senior Vice-President and Chief
Officer                                         Operating Officer



/s/ Frederic Coles                              /s/ Fred J. Dyment
------------------------                        ---------------------
FREDERIC COLES                                  Fred J. DYMENT
Director and Chairman of the                    Director and Member of the
Reserves Committee                              Reserves Committee


March 22, 2007


<PAGE>

                                   APPENDIX C

                         MANDATE OF THE AUDIT COMMITTEE

ROLE AND OBJECTIVE

The Audit Committee (the  "Committee") is a committee of the Board of Directors
of  ARC  Resources   Ltd.   ("ARL")  to  which  the  Board  has  delegated  its
responsibility  for  oversight  of the nature  and scope of the  annual  audit,
management's   reporting  on  internal  accounting   standards  and  practices,
financial   information  and  accounting  systems  and  procedures,   financial
reporting and statements and recommending,  for Board of Director approval, the
audited financial statements and other mandatory disclosure releases containing
financial information. The objectives of the Committee, with respect to ARL and
ARC Energy Trust (the "Trust") (hereinafter collectively referred to as "ARC"),
are as follows:

--    To assist  Directors  to meet  their  responsibilities  in respect of the
      preparation and disclosure of the financial statements of ARC and related
      matters.

--    To provide better communication between directors and external auditors.

--    To ensure the external auditors' independence.

--    To increase the credibility and objectivity of financial reports.

--    To strengthen the role of the outside  directors by facilitating in depth
      discussions  between directors on the Committee,  management and external
      auditors.


MANDATE AND RESPONSIBILITIES OF COMMITTEE

o     It is the  responsibility of the Committee to satisfy itself on behalf of
      the Board with respect to ARC's internal control systems:

      -   identifying, monitoring and mitigating business risks.

      -   ensuring compliance with legal and regulatory requirements.

o     It is a primary  responsibility of the Committee to review the annual and
      quarterly  financial  statements of ARC prior to their  submission to the
      Board of Directors for approval.  The process  should  include but not be
      limited to:

      -   reviewing changes in accounting principles,  or in their application,
          which may have a  material  impact on the  current  or future  years'
          financial statements;

      -   reviewing significant  accruals,  reserves or other estimates such as
          the ceiling test calculation;

      -   reviewing   accounting   treatment   of  unusual   or   non-recurring
          transactions;

      -   reviewing  the  Trust's  status as a "mutual  fund  trust"  under the
          INCOME TAX ACT (Canada);

      -   ascertaining  compliance  with  covenants  under loan  agreements and
          Trust Indenture;

      -   reviewing   financial   reporting   relating   to  asset   retirement
          obligations;

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                                      C-2


      -   reviewing disclosure requirements for commitments and contingencies;

      -   reviewing adjustments raised by the external auditors, whether or not
          included in the financial statements;

      -   reviewing unresolved  differences between management and the external
          auditors;

      -   obtain   explanations  of  significant   variances  with  comparative
          reporting periods; and

      -   determine through inquiry if there are any related party transactions
          and ensure the nature and extent of such  transactions  are  properly
          disclosed.

o     The  Committee  is  to  review  the  financial   statements  and  related
      information included in prospectuses,  management discussion and analysis
      (MD&A),  information  circular-proxy  statements  and annual  information
      forms (AIF), prior to Board approval.

o     With respect to the  appointment of external  auditors by the Board,  the
      Committee shall:

      -     be directly  responsible  for  overseeing  the work of the external
            auditors  engaged for the purpose of issuing an auditors' report or
            performing  other audit,  review or attest  services for the Trust,
            including the resolution of  disagreements  between  management and
            the external auditor regarding financial reporting;

      -     review management's  recommendation for the appointment of external
            auditors  and  recommend  to  the  Board  appointment  of  external
            auditors and the compensation of the external auditors;

      -     review the terms of engagement of the external auditors,  including
            the appropriateness and reasonableness of the auditors' fees;

      -     when there is to be a change in auditors, review the issues related
            to the change and the  information  to be included in the  required
            notice to securities regulators of such change; and

      -     review and  approve  any  non-audit  services to be provided by the
            external auditors' firm and consider the impact on the independence
            of the auditors.

o     Review with external  auditors (and internal  auditor if one is appointed
      by ARC) their  assessment of the internal  controls of ARC, their written
      reports  containing  recommendations  for  improvement,  and management's
      response and follow-up to any identified weaknesses.  The Committee shall
      also review  annually  with the  external  auditors  their plan for their
      audit and, upon completion of the audit, their reports upon the financial
      statements of ARC and its subsidiaries.

o     Review all public disclosure  containing  audited or unaudited  financial
      information before release.

o     Review financial reporting relating to risk exposure.

o     Review ARC's plans and strategies  around investment  practices,  banking
      performance and treasury risk management.

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                                      C-3


o     Satisfy  itself that adequate  procedures  are in place for the review of
      the Trust's public  disclosure of financial  information from the Trust's
      financial  statements  and  periodically  assess  the  adequacy  of those
      procedures.

o     Establish procedures for:

      -     the receipt,  retention and treatment of complaints received by the
            Trust  regarding  accounting,   internal  accounting  controls,  or
            auditing matters; and

      -     the confidential, anonymous submission by employees of the Trust of
            concerns regarding questionable accounting or auditing matters.

o     Review and approve ARC's hiring policies  regarding  partners,  employees
      and former partners and employees of the present and external auditors of
      ARC.

o     Review any other matters that the Audit  Committee feels are important to
      its mandate or that the Board chooses to delegate to it.

o     Undertake  annually a review of this mandate and make  recommendations to
      the Policy and Board Governance Committee as to proposed changes.


COMPOSITION

o     This Committee shall be composed of at least three individuals  appointed
      by the Board from  amongst  its  members,  all of which  members  will be
      independent  (within the meaning of Multilateral  Instrument 52-110 Audit
      Committees)  unless the Board  determines  to rely on an  exemption in NI
      52-110.  "Independent"  generally  means free from any  business or other
      direct or indirect material relationship with ARC that could, in the view
      of the Board of Directors,  reasonably interfere with the exercise of the
      member's independent judgment.

o     The Secretary to the Board shall act as Secretary of the Committee.

o     A quorum shall be a majority of the members of the Committee.

o     All of the members must be financially  literate within the meaning of NI
      52-110  unless the Board has  determined  to rely on an  exemption  in NI
      52-110.  Being  "financially  literate" means members have the ability to
      read and understand a set of financial  statements that present a breadth
      and  level  of  complexity  of  accounting   issues  that  are  generally
      comparable to the breadth and complexity of issues that can reasonably be
      expected to be raised by the Trust's financial statements.


MEETINGS

o     The  Committee  shall meet at least four times per year  and/or as deemed
      appropriate by the Committee Chair.

o     The  Committee  shall  meet not less than  quarterly  with the  auditors,
      independent of the presence of management.

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                                      C-4


o     Agendas,  with input from  management,  shall be  circulated to Committee
      members  and  relevant   management   personnel   along  with  background
      information on a timely basis prior to the Committee meetings.

o     Minutes  of each  meeting  shall  be  prepared  by the  Secretary  to the
      Committee.

o     The Chief  Executive  Officer  and the Chief  Financial  Officer or their
      designates  shall be available to attend at all meetings of the Committee
      upon the invitation of the Committee.

o     The Controller,  Treasurer and such other staff as appropriate to provide
      information to the Committee shall attend meetings upon invitation by the
      Committee.


REPORTING / AUTHORITY

o     Following  each meeting,  in addition to a verbal  report,  the Committee
      will  report to the Board by way of  providing  copies of the  minutes of
      such Committee  meeting at the next Board meeting after a meeting is held
      (these may still be in draft form).

o     Supporting  schedules and information  reviewed by the Committee shall be
      available for examination by any director.

o     The  Committee  shall have the  authority to  investigate  any  financial
      activity of the Corporation and to communicate directly with the internal
      and external auditors. All employees are to cooperate as requested by the
      Committee.


The Committee may retain, and set and pay the compensation for, persons having
special expertise and/or obtain independent professional advice to assist in
fulfilling its duties and responsibilities at the expense of ARC.