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



                                ARC ENERGY TRUST



                          2004 ANNUAL INFORMATION FORM



                                 MARCH 22, 2005



<PAGE>


                                TABLE OF CONTENTS

                                                                            PAGE

GLOSSARY OF TERMS..............................................................1
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS..............................2
ARC ENERGY TRUST...............................................................3
   GENERAL.....................................................................3
   GENERAL DEVELOPMENT OF OUR BUSINESS.........................................3
OUR BUSINESS...................................................................5
   OVERVIEW....................................................................5
   OUR ORGANIZATIONAL STRUCTURE................................................6
   MANAGEMENT POLICIES.........................................................6
   CASH DISTRIBUTIONS AND DISTRIBUTION POLICY..................................7
   CAPITAL EXPENDITURES........................................................7
   POTENTIAL ACQUISITIONS......................................................7
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION...................7
   DISCLOSURE OF RESERVES DATA.................................................8
   RESERVES DATA (CONSTANT PRICES AND COSTS)...................................8
   RESERVES DATA (FORECAST PRICES AND COSTS)..................................10
   DEFINITIONS AND NOTES TO RESERVE DATA TABLES:..............................12
   RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE..............17
   ADDITIONAL INFORMATION RELATING TO RESERVES DATA...........................18
   OTHER OIL AND GAS INFORMATION..............................................19
   MARKETING ARRANGEMENTS.....................................................27
   ACQUISITIONS AND DISPOSITIONS..............................................27
SHARE CAPITAL OF ARC RESOURCES................................................27
   COMMON SHARES..............................................................27
   EXCHANGEABLE SHARES........................................................28
   SECOND PREFERRED SHARES....................................................29
OTHER INFORMATION RELATING TO OUR BUSINESS....................................29
   BORROWING..................................................................29
   ESCROW AGREEMENTS..........................................................30
   RETENTION BONUSES AND EXECUTIVE EMPLOYMENT AGREEMENTS......................31
OUR INFORMATION...............................................................31
   TRUST UNITS................................................................31
   SPECIAL VOTING UNIT........................................................31
   THE TRUST INDENTURE........................................................31
   TRUSTEE....................................................................32
   FUTURE OFFERINGS...........................................................32
   MEETINGS AND VOTING........................................................32
   OUR MANAGEMENT.............................................................33
   ARC FINANCIAL ADVISORY AGREEMENT...........................................33
   LIMITATION ON NON-RESIDENT OWNERSHIP.......................................33
   RIGHT OF REDEMPTION........................................................33
   TERMINATION OF THE TRUST...................................................34
   REPORTING TO UNITHOLDERS...................................................34
   DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE PLAN............35
CORPORATE GOVERNANCE..........................................................35
   GENERAL....................................................................35

<PAGE>
                                       ii


   TRUST INDENTURE............................................................35
   DECISION MAKING............................................................35
   BOARD OF DIRECTORS OF ARC RESOURCES........................................36
CONFLICTS OF INTEREST.........................................................39
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS....................39
DISTRIBUTIONS TO UNITHOLDERS..................................................39
PRICE RANGE AND TRADING VOLUME OF TRUST UNITS AND EXCHANGEABLE SHARES.........40
INDUSTRY REGULATIONS..........................................................40
   PRICING AND MARKETING OF OIL AND NATURAL GAS...............................41
   PIPELINE CAPACITY..........................................................41
   THE NORTH AMERICAN FREE TRADE AGREEMENT....................................41
   PROVINCIAL ROYALTIES AND INCENTIVES........................................42
   LAND TENURE................................................................42
   ENVIRONMENTAL REGULATION...................................................42
RISK FACTORS..................................................................43
   VOLATILITY OF OIL AND NATURAL GAS PRICES...................................43
   RESERVE ESTIMATES..........................................................43
   PURCHASE OF PROPERTIES.....................................................43
   VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES....................44
   CHANGES IN LEGISLATION.....................................................44
   MAINTENANCE OF DISTRIBUTIONS...............................................45
   OPERATIONAL MATTERS........................................................45
   EXPANSION OF OPERATIONS....................................................46
   NON-RESIDENT OWNERSHIP OF TRUST UNITS......................................46
   ACCOUNTING WRITE-DOWNS AS A RESULT OF GAAP.................................46
   ENVIRONMENTAL CONCERNS.....................................................47
   KYOTO PROTOCOL.............................................................47
   DEBT SERVICE...............................................................47
   DELAY IN CASH DISTRIBUTIONS................................................48
   RELIANCE ON MANAGEMENT.....................................................48
   DEPLETION OF RESERVES......................................................48
   NET ASSET VALUE............................................................48
   ADDITIONAL FINANCING.......................................................49
   COMPETITION................................................................49
   RETURN OF CAPITAL..........................................................49
   NATURE OF TRUST UNITS......................................................49
   UNITHOLDER LIMITED LIABILITY...............................................50
   TITLE TO PROPERTIES........................................................50
TRANSFER AGENTS AND REGISTRARS................................................50
MATERIAL CONTRACTS............................................................51
INTEREST OF EXPERTS...........................................................51
ADDITIONAL INFORMATION........................................................51

APPENDIX A          -    REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED
                         RESERVES EVALUATOR

APPENDIX B          -    REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND
                         OTHER INFORMATION

<PAGE>
                                      iii

<TABLE>
<CAPTION>
ABBREVIATIONS AND CONVERSIONS

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

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:

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 908563 Alberta Ltd.;

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 Gilbert Laustsen Jung Associates Ltd., independent petroleum
consultants of Calgary, Alberta;

GLJ REPORT means the report prepared by GLJ dated February 7, 2005 evaluating
the crude oil, natural gas, natural gas liquids and sulphur reserves
attributable to the Properties at December 31, 2004;

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;

SPECIAL DEBENTURE means the special 8 per cent special adjustable convertible
subordinated debenture dated April 16, 2003, in the principal amount of
$320,000,000 issued by us as partial payment for Star Oil & Gas Ltd.;

TRUST INDENTURE means the trust indenture between Computershare Trust Company of
Canada, as trustee, and ARC Resources Ltd., amended and restated as of May 16,
2003;

TRUST UNITS means the units of the Trust, each unit representing an equal
undivided beneficial interest therein; 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 NOTE 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 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 of acquisitions;

    o    geological, technical, drilling and processing problems;

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

    o    the other factors discussed under "RISK FACTORS".

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.

<PAGE>
                                       3


                                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 material amendments being approved at the annual and special meeting of
Unitholders held April 17, 2003, which included an amendment to eliminate the
delegation of responsibilities and powers of the Trustee to a manager and to
delegate to ARC Resources all of the matters formerly delegated to that manager.

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
ARC Canadian Oil & Gas 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 offerings were 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>
3-Jun-02          22-May-02      10,000,000      $12.05     $120,500,000    Fund a crude oil and natural gas property
                                                                            acquisition and repay outstanding
                                                                            indebtedness

25-Feb-03         13-Feb-03      12,500,000      $11.50     $143,750,000    Repay outstanding indebtedness and
                                                                            partially fund 2003 capital program

17-Nov-03         10-Nov-03      14,500,000      $13.40     $194,300,000    Repay outstanding indebtedness and
                                                                            partially fund 2004 capital program
</TABLE>

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

On August 28, 2002, the internalization of our management was approved by
Unitholders at a special meeting, resulting in our wholly-owned subsidiary,
980445 Alberta Ltd., acquiring all of the common shares of ARML in exchange for
$4,247,658 in cash, the assumption of the obligation of ARML to pay retention
bonuses to key individuals in aggregate of $5,000,000 over a period of five
years and the issuance of 298,648 Trust Units and 3,281,279 ARML exchangeable
shares (exchangeable for Trust Units). Mr. Van Wielingen, Mr. Stewart, Mr.
Dielwart, Mr. Bonner, Mr. Carey, Ms. Healy, Mr. Sinclair and Mr. Stadnyk
received approximately 49 per cent of the Trust Units and exchangeable shares
issued under the internalization transaction. As part of the transaction, 9,013
Trust Units and 2,008,699 ARML

<PAGE>
                                       4


exchangeable shares were placed in escrow. In addition, ARC Financial
Corporation agreed to provide certain ongoing research and strategic services to
us until August 2007 at no further cost. As a result of the internalization,
Unitholders are entitled to select all of our Board of Directors. Former holders
of ARML exchangeable shares received a total of 1,735,221 Exchangeable Shares on
May 16, 2003 when ARML was subsequently wound-up into ARC Resources.

On March 31, 2003 we entered into an agreement with United Energy LLC and
acquired all the shares of Star Oil & Gas Ltd. for $710,000,000 (before closing
adjustments) effective January 1, 2003. We paid for this acquisition by issuing
the Special Debenture for $320,000,000, repaying $187,372,000 of corporate and
shareholder debt and payment of $202,628,000 in cash. We concurrently agreed to
sell our interest in certain producing properties and undeveloped acreage to
third parties for $78,200,000. We increased our aggregate credit facilities to
$650,000,000 to finance the transaction, which closed on April 16, 2003. The
reserves attributed to the Star properties as at January 1, 2003 were 67.1
million of barrels of oil equivalent and 80.5 million of barrels of oil
equivalent for total proved reserves and for total established reserves (proved
reserves plus probable reserves risked at 50 per cent), respectively.

The Special Debenture was fully converted into Trust Units as follows. On May
20, 2003, United ARC L.P. converted $200,000,000 of principal amount into
16,891,891 Trust Units at $11.84 per Trust Unit. United ARC L.P. sold the
16,891,891 Trust Units and remaining $120,000,000 principal amount in a
secondary offering to the public. By August 1, 2003 all of the remaining Special
Debenture was fully converted into 10,135,131 Trust Units at a price of $11.84
per Trust Unit.

On August 15, 2003, we disposed of non core assets to third parties for
approximately $77,000,000. Net production represented by these properties was
approximately 3,700 boe/d and established reserves at January 1, 2003 were 9.3
million boe of which 40 per cent were crude oil and natural gas liquids.
Concurrent with the disposition, we reduced our borrowing base from $650,000,000
to $620,000,000. We used the proceeds from the disposition to reduce our
outstanding indebtedness.

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 $15.00 per Trust Unit.

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 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.



<PAGE>
                                       5


                                  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, the Long Term Notes and the common
shares of ARC Canadian Oil & Gas Ltd. 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
and debt repayments, 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 "Information Relating to the Trust -
Right of Redemption".



<PAGE>
                                       6


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]


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 1,783,776 Exchangeable Shares outstanding
         as at December 31, 2004 that were exchangeable for approximately
         2,982,170 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.

<PAGE>
                                       7


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.

Our current distribution policy generally provides for a minimum of 20 per cent
of cash available for distribution to be used to fund a portion of our annual
capital expenditure program, including both exploitation expenditures and minor
property acquisitions, but excluding major acquisitions. This holdback is
designed to focus on production replacement activities in order to enhance
long-term Unitholder returns and is reviewed from time to time to ensure our
ongoing capital needs are being met. The actual amount withheld is dependent on
the commodity price environment. In addition, we withhold approximately $6
million per annum to contribute to our reclamation fund for eventual abandonment
of oil and gas properties.

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
three 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.

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,
2004 and the preparation date of the Statement is January 18, 2005. The Report
of Management and Directors on Oil and Gas Disclosure on Form 51-101F3 and

<PAGE>
                                       8


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, 2004 contained in the GLJ Report dated February
7, 2005. 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, not including the
impact of any hedging activities. 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 Reserve Data
Tables" below.

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

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 RESERVE 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 - RESERVE
ESTIMATES" AND "RISK FACTORS - VOLATILITY OF OIL AND NATURAL GAS PRICES".

RESERVES DATA (CONSTANT PRICES AND COSTS)

                         SUMMARY OF OIL AND GAS RESERVES
                  AND NET PRESENT VALUES OF FUTURE NET REVENUE
                             as of December 31, 2004
                            CONSTANT PRICES AND COSTS

<TABLE>
<CAPTION>
                                                           RESERVES
                                --------------------------------------------------------------
                                     LIGHT AND MEDIUM OIL                  HEAVY OIL
                                -------------------------------  -----------------------------
                                    GROSS             NET           GROSS            NET
                                --------------  ---------------  ------------  ---------------
<S>                                <C>              <C>            <C>             <C>
RESERVES CATEGORY                   (Mbbl)          (Mbbl)          (Mbbl)         (Mbbl)

PROVED
     Developed Producing            66,744          58,234          2,756          2,865
     Developed Non-Producing           635             562              0              0
     Undeveloped                    14,565          12,430            111            104
TOTAL PROVED                        81,944          71,226          2,867          2,969

PROBABLE                            23,723          20,306            813            789

TOTAL PROVED PLUS PROBABLE         105,666          91,532         3,680           3,758
</TABLE>


<PAGE>
                                       9

<TABLE>
<CAPTION>
                                                           RESERVES
                                ---------------------------------------------------------
                                         NATURAL GAS              NATURAL GAS LIQUIDS
                                -----------------------------  --------------------------
                                    GROSS            NET          GROSS          NET
                                --------------  -------------  ------------  ------------
<S>                                <C>            <C>            <C>           <C>
RESERVES CATEGORY                   (Mbbl)         (Mbbl)         (Mbbl)        (Mbbl)

PROVED
     Developed Producing           439,423        373,961        9,512         6,946
     Developed Non-Producing         9,348          7,336          143           101
     Undeveloped                   133,752        109,558        1,739         1,232
TOTAL PROVED                       582,523        490,855       11,394         8,280

PROBABLE                           134,521        111,917        2,659         1,986

TOTAL PROVED PLUS PROBABLE         717,044        602,772       14,053        10,266
</TABLE>

                                           RESERVES
                                -----------------------------
                                            TOTAL
                                -----------------------------
                                    GROSS            NET
                                --------------  -------------
RESERVES CATEGORY                   (mboe)         (mboe)

PROVED
     Developed Producing           152,250        130,372
     Developed Non-Producing         2,335          1,886
     Undeveloped                    38,706         32,026
TOTAL PROVED                       193,292        164,284

PROBABLE                            49,615         41,734

TOTAL PROVED PLUS PROBABLE         242,906        206,018


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

PROVED
   Developed Producing                      3,414.4            1953.1
   Developed Non-Producing                     54.3              25.9
   Undeveloped                                698.6             283.6
TOTAL PROVED                                4,167.3           2,262.7

PROBABLE                                    1,078.3             347.5

TOTAL PROVED PLUS PROBABLE                  5,245.6           2,610.1

<PAGE>
                                       10

<TABLE>
<CAPTION>
                                                  TOTAL FUTURE NET REVENUE
                                                       (UNDISCOUNTED)
                                                  as of December 31, 2004
                                                 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      7,783.6      1,231.6      1,926.2         360.3             98.2           4,167.3       0           4,167.3

Proved Plus          9,748.0      1,558.2      2,355.0         485.3            104.0           5,245.6       0           5,245.6
Probable
Reserves
</TABLE>

<TABLE>
<CAPTION>
                                        FUTURE NET REVENUE
                                        BY PRODUCTION GROUP
                                      as of December 31, 2004
                                     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               1,021.3
                                    Heavy Oil                                   25.7
                                    Natural Gas                              1,206.4

Proved Plus Probable Reserves       Light and Medium Crude Oil               1,213.4
                                    Heavy Oil                                   30.6
                                    Natural Gas                              1,356.8
Notes:
</TABLE>

(1)      The total amounts for the future net reserves from the proved reserves
         and the probable reserves do not correspond to the totals set forth in
         previous tables because ARTC has not been allocated amongst production
         groups.

(2)      The unallocated portion for proved reserves and for proved plus
         probable reserves is $9.3 MM.

RESERVES DATA (FORECAST PRICES AND COSTS)

                         SUMMARY OF OIL AND GAS RESERVES
                  AND NET PRESENT VALUES OF FUTURE NET REVENUE
                             as of December 31, 2004
                            FORECAST PRICES AND COSTS

<TABLE>
<CAPTION>
                                                         RESERVES
                                ---------------------------------------------------------
                                    LIGHT AND MEDIUM OIL               HEAVY OIL
                                ---------------------------------------------------------
RESERVES CATEGORY                  GROSS            NET          GROSS          NET
-----------------               --------------  -------------  ------------  ------------
                                   (Mbbl)         (Mbbl)         (Mbbl)        (Mbbl)
<S>                                 <C>              <C>          <C>            <C>
PROVED
     Developed Producing             65,659          57,226       2,783          2,870
     Developed Non-Producing            658             585           0              0
     Undeveloped                     14,575          12,569          97             90
TOTAL PROVED                         80,892          70,380       2,880          2,960

PROBABLE                             23,906          20,591         815            784

TOTAL PROVED PLUS PROBABLE          104,798          90,971       3,695          3,744
</TABLE>

<PAGE>
                                       11

<TABLE>
<CAPTION>
                                                        RESERVES
                                ---------------------------------------------------------
                                         NATURAL GAS              NATURAL GAS LIQUIDS
                                -----------------------------  --------------------------
                                    GROSS            NET          GROSS          NET
                                --------------  -------------  ------------  ------------
RESERVES CATEGORY                   (Mbbl)         (Mbbl)         (Mbbl)        (Mbbl)

<S>                                   <C>             <C>           <C>       <C>
PROVED
     Developed Producing              433,826         369,009        9,442     6,911
     Developed Non-Producing            9,261           7,270          144       102
     Undeveloped                      133,276         109,101        1,743     1,239
TOTAL PROVED                          576,362         485,381       11,328     8,251

PROBABLE                              133,511         111,014        2,655     1,992

TOTAL PROVED PLUS PROBABLE            709,873         596,395       13,984    10,243
</TABLE>


                                          RESERVES
                                -----------------------------
                                            TOTAL
                                -----------------------------
                                    GROSS            NET
RESERVES CATEGORY                   (mboe)         (mboe)
-----------------               --------------  -------------

PROVED
     Developed Producing           150,188         128,508
     Developed Non-Producing         2,346           1,899
     Undeveloped                    38,627          32,081
TOTAL PROVED                       191,160         162,488

PROBABLE                            49,628          41,869

TOTAL PROVED PLUS PROBABLE         240,788         204,357

<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            3,055.3        2,248.6         1,817.3        1,545.7         1,357.0
   Developed Non-Producing           52.0           32.5            23.8           18.8            15.5
   Undeveloped                      595.7          363.8           234.5          155.1           102.9
TOTAL PROVED                      3,702.9        2,644.9         2,075.6        1,719.6         1,475.3

PROBABLE                          1,037.4          516.6           313.5          213.0           155.1

TOTAL PROVED PLUS PROBABLE        4,740.3        3,161.5         2,389.1        1,932.6         1,630.5
</TABLE>

<PAGE>
                                       12

<TABLE>
<CAPTION>
                                                            TOTAL FUTURE NET REVENUE
                                                                 (UNDISCOUNTED)
                                                             as December 31, 2004
                                                          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      7,780.4        1,215.7       2,342.4       374.2          145.2          3,702.9       0         3,702.9

Proved Plus          9,976.7        1,558.0       3,005.9       507.6          164.9          4,740.3       0         4,740.3
Probable
Reserves
</TABLE>

<TABLE>
<CAPTION>
                                            FUTURE NET REVENUE
                                           BY PRODUCTION GROUP
                                         as of December 31, 2004
                                       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                      992.4
                                    Heavy Oil                                        36.1
                                    Natural Gas                                   1,037.7

Proved Plus Probable Reserves       Light and Medium Crude Oil                    1,175.8
                                    Heavy Oil                                        42.7
                                    Natural Gas                                   1,161.2
</TABLE>
Notes:
(1)      The total amounts for the future net reserves from the proved reserves
         do not correspond to the totals set forth in previous tables because
         ARTC has not been allocated amongst production groups.

(2)      The unallocated portion for proved reserves and for proved plus
         probable reserves is $9.3 MM.

DEFINITIONS AND NOTES TO RESERVE 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

         (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;

<PAGE>
                                       13


         (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 reserve 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:

         RESERVE 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

         (a)      analysis of drilling, geological, geophysical and engineering
                  data;

         (b)      the use of established technology; and

         (c)      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 reserve 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 production, and the
                           date of resumption of production must be known with
                           reasonable certainty.

<PAGE>
                                       14


                  (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 reserve 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 percent probability that the quantities actually
                  recovered will equal or exceed the estimated proved reserves;
                  and

         (b)      at least a 50 percent 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.

         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, 2005, inflation
         and exchange rates utilized in the GLJ Report were as follows:

<PAGE>
                                       15

<TABLE>
<CAPTION>
                                        SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
                                                     as of December 31, 2004
                                                    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
2005            42.00     50.25      27.50      43.75        6.60        32.25       37.25      50.75        2.0%        0.82
2006            40.00     47.75      28.50      41.50        6.35        30.50       35.25      48.25        2.0%        0.82
2007            38.00     45.50      28.75      39.50        6.15        29.00       33.75      46.00        2.0%        0.82
2008            36.00     43.25      27.25      37.75        6.00        27.75       32.00      43.75        2.0%        0.82
2009            34.00     40.75      25.50      35.50        6.00        26.00       30.25      41.25        2.0%        0.82
2010            33.00     39.50      24.75      34.25        6.00        25.25       29.25      40.00        2.0%        0.82
2011            33.00     39.50      24.75      34.25        6.00        25.25       29.25      40.00        2.0%        0.82
2012            33.00     39.50      24.75      34.25        6.00        25.25       29.25      40.00        2.0%        0.82
2013            33.50     40.00      24.75      34.75        6.10        25.50       29.50      40.50        2.0%        0.82
2014            34.00     40.75      25.50      35.50        6.20        26.00       30.25      41.25        2.0%        0.82
2015            34.50     41.25      25.75      36.00        6.30        26.50       30.50      41.75        2.0%        0.82
Thereafter      +2.0%     +2.0%      +2.0%      +2.0%       +2.0%        +2.0%       +2.0%      +2.0%        2.0%        0.82
</TABLE>

Notes:
(1)      Inflation rates for forecasting prices and costs.

(2)      Exchange rates used to generate the benchmark reference prices in this
         table.

         Weighted average actual prices realized for the year ended December 31,
         2004, were $6.78/Mcf for natural gas, $47.03/bbl for crude oil and
         $39.04/bbl for natural gas liquids. Only a minor amount of our
         production is characterized as heavy oil. The weighted average actual
         price for heavy oil for the year ended December 31, 2004 has been
         included in the weighted average actual price for crude oil noted above
         for this same period.

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>
                                       16

<TABLE>
<CAPTION>
                                                 SUMMARY OF PRICING ASSUMPTIONS
                                                     as of December 31, 2004
                                                   CONSTANT PRICES AND COSTS

                                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   INFLATION
             Oklahoma       API      Hardesty       API         Price     Propane    Butane       Plus       RATE(1)
   Year      ($US/bbl)   ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/MMBtu) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/bbl)    %/Year
   ----      ---------   ---------- ---------- ----------  ------------ ---------- ----------  ----------    ------
<S>            <C>          <C>       <C>        <C>            <C>        <C>        <C>         <C>        <C>
December 31,   43.45        46.54     24.33      32.12          6.79       29.79      34.44       48.97      0.8308
2004
</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 reserve
         categories noted below.

<TABLE>
<CAPTION>
                                           FORECAST PRICES AND COSTS            CONSTANT PRICES AND COSTS
                                   -----------------------------------------    -------------------------
                                   PROVED RESERVES      PROVED PLUS PROBABLE
              YEAR                      (MM$)                RESERVES (MM$)       PROVED RESERVES (MM$)
              ----                      -----                --------------       ---------------------
<C>                                    <C>                     <C>                          <C>
2005                                   134.0                   158.9                        134.0
2006                                    96.8                   124.1                         94.9
2007                                    62.5                    73.4                         60.1
2008                                    22.5                    58.7                         21.2
2009                                     9.7                    28.6                          9.0
Total: Undiscounted                    374.2                   507.6                        360.3
Total:  Discounted at 10%/year         304.2                   403.8                        296.4
</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.       The Alberta royalty tax credit ("ARTC") is included in the cumulative
         cash flow amounts. ARTC is based on the program announced November 1989
         by the Alberta government with modifications effective January 1, 1995.

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

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

<PAGE>
                                       17


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

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

RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

The following table sets forth the reconciliation of our net reserves as at
December 31, 2004, using forecast price and cost estimates derived from the GLJ
Report. Net reserves as at December 31, 2004 and as at December 31, 2003 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               CONVENTIONAL 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, 2003       76,193     21,101     97,294    3,116      790        3,906    488,240     97,004    585,244

 Extensions              1,158          0      1,158        0        0            0      4,808      1,565      6,372
 Improved Recovery(1)    1,325        146      1,471       38        7           45     14,017     11,841     25,858
 Technical Revisions      (434)       224       (209)     (41)     (42)         (83)     8,793     (2,850)     5,942
 Discoveries                47         12         59      168       42          210      1,416        743      2,159
 Acquisitions            1,515        745      2,260        0        0            0     18,290      2,503     20,793
 Dispositions           (4,402)      (806)    (5,208)       0        0            0    (10,318)    (3,026)   (13,344)
 Economic Factors        1,696       (832)       864      120      (13)         107     11,463      3,235     14,698
 Production             (6,718)         0     (6,718)    (441)       0         (441)   (51,328)         0    (51,238)

December 31, 2004       70,380     20,591     90,971    2,960      784        3,744    485,381    111,014    596,395
</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, 2003        8,882      1,851     10,733    169,564   39,910    209,474

 Extensions                141         46        187     2,100       307      2,407
 Improved Recovery(1)      256        107        363     3,955     2,234      6,189
 Technical Revisions       511         25        536     1,502      (268)     1,234
 Discoveries                 6          2          8       458       179        637
 Acquisitions               16          3         20     4,579     1,166      5,745
 Dispositions             (421)       (72)      (493)   (6,543)   (1,382)    (7,925)
 Economic Factors           87         29        116     3,814      (277)     3,537
 Production             (1,227)         0     (1,227)   (16,941)       0    (16,941)

December 31, 2004        8,251      1,992     10,243    162,488   41,869    204,357
</TABLE>

Note:
(1)      Improved recovery includes infill drilling additions of 3,245.5 mboe
         total proved, 1,852.2 mboe total probable, and 5,097.7 mboe proved plus
         probable.

<PAGE>
                                       18

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

                                                                                        2004
PERIOD AND FACTOR                                                                       (MM$)
-----------------                                                                       -----
<S>                                                                                   <C>
Estimated Future Net Revenue at Beginning of Year                                     2,020.5

         Sales and Transfers of Oil and Gas Produced, Net of Production Costs and      (485.6)
           Royalties(1)
         Net Change in Prices, Production Costs and Royalties Related to Future         369.7
           Production(2)
         Development Costs Incurred During the Period(3)                                186.5
         Changes in Estimated Future Development Costs(4)                              (213.9)
         Extensions and Improved Recovery(5)                                             55.4
         Discoveries(5)                                                                   9.7
         Acquisitions(5)                                                                 69.2
         Dispositions(5)                                                                 (3.1)
         Net Change Resulting from Revisions in Quantity Estimates & Economic
           Factors(5)                                                                    87.4
         Accretion of Discount(6)                                                       202.1
         Net Change in Income Taxes(7)                                                     --
         Miscellaneous Differences                                                      (35.2)

Estimated Future Net Revenue at End of Year                                           2,262.7
</TABLE>

Notes:
(1)      Actual revenues received before income and large corporation 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 related reserves
(6)      Estimated as 10 per cent of the beginning of period net present value
(7)      The difference between forecast income taxes at beginning of the period
         and the actual taxes for the period plus forecast income taxes at the
         end of the period

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 2 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>
                                       19


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, 2004 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, 2004. Reserve amounts are stated at December 31, 2004, 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, 2004, and information in respect of production is for the year ended
December 31, 2004 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, 2004 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 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>
                                       20


                                     NET RESERVES AND PRODUCTION
                             --------------------------------------------
                                                              PROVED PLUS
                                               PROVED          PROBABLE
                             PRODUCTION       RESERVES         RESERVES
                               (BOE/D)         (MBOE)            (MBOE)
                               -------         ------            ------
        Ante Creek             3,258           12,007           15,062
        Lougheed               2,568            6,125            8,137
        Hatton                 2,359           10,111           11,503
        Dawson                 2,248           14,302           19,455
        Jenner                 2,212           11,961           15,571
        Pouce Coupe            1,687            3,477            3,967
        Weyburn                1,536            7,313           10,045
        MIPA                   1,329            8,893           10,746
        Brooks                 1,219            3,515            4,024
        Prestville               600            5,080            7,703

ANTE CREEK

The Ante Creek property is located in northwest Alberta. We are the operator and
own an average land interest of 93 per cent. During 2004, net production from
the area averaged 3,258 boe/d of oil, gas and natural gas liquids from 99 net
wells. During 2004, 11 new wells were drilled. GLJ assigned net proved reserves
of 12,007 mboe and net proved plus probable reserves of 15,062 mboe of oil, gas
and natural gas liquids to this area, or 7.4 per cent of total net proved plus
probable reserves.

LOUGHEED

The Lougheed property is located in southeast Saskatchewan. We are the operator
and own an average land interest of 84 per cent. During 2004, net production
from the area averaged 2,568 boe/d of oil and natural gas liquids from 107 net
wells. During 2004, 6 new wells were drilled. GLJ assigned net proved reserves
of 6,125 mboe and net proved plus probable reserves of 8,137 mboe of oil and
natural gas liquids to this area, or 4.0 per cent of total net proved plus
probable reserves.

HATTON

         The Hatton property is located in southwest Saskatchewan. We are the
operator and own an average land interest of 50 per cent. During 2004, net
production from the area averaged 2,359 boe/d of natural gas from 380 net wells.
During 2004, 40 new wells were drilled. GLJ assigned net proved reserves of
10,111 mboe and net proved plus probable reserves of 11,503 mboe of natural gas
to this area, or 5.6 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 95 per cent. During 2004, net
production from the area averaged 2,248 boe/d of gas and natural gas liquids
from 50 net wells. During 2004, 5 new wells were drilled. GLJ assigned net
proved reserves of 14,302 mboe and net proved plus probable reserves of 19,455
mboe of gas and natural gas liquids to this area, or 9.5 per cent of total net
proved plus probable reserves.

JENNER

The Jenner property is located in southeast Alberta. We are the operator and own
an average land interest of 76 per cent. During 2004, net production from the
area averaged 2,212 boe/d of oil and natural gas from 623 net wells. During
2004, 88 new wells were drilled. GLJ assigned net proved reserves of 11,961

<PAGE>
21


mboe and net proved plus probable reserves of 15,571 mboe of oil and natural gas
to this area, or 7.6 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 67 per cent. During 2004, net production
from the area averaged 1,687 boe/d of oil, gas and natural gas liquids from 32
net wells. During 2004, 2 new wells were drilled. GLJ assigned net proved
reserves of 3,477 mboe and net proved plus probable reserves of 3,967 mboe of
oil, gas and natural gas liquids to this area, or 1.9 per cent of total net
proved plus probable reserves.

WEYBURN

The Weyburn property is located in southeast Saskatchewan. Encana Energy
operates the Weyburn Unit which comprises 89 per cent of the Weyburn area
production. We own a working interest of 6.5 per cent in the Weyburn Unit and a
weighted average land interest of 69 per cent in the Weyburn area in production
and reserves. During 2004, net production from the area averaged 1,536 boe/d of
oil and natural gas liquids from 65 net wells. During 2004, 13 new wells were
drilled. GLJ assigned net proved reserves of 7,313 mboe and net proved plus
probable reserves of 10,045 mboe of oil and natural gas liquids to this area, or
4.9 per cent of total net proved plus probable reserves.

MIPA

The MIPA property is located in central Alberta. We are the operator and own a
100 per cent interest in production and reserves in the Cardium zone. During
2004, net production from the area averaged 1,329 boe/d of oil, gas and natural
gas liquids from 139 net wells. During 2004, 8 new wells were drilled. GLJ
assigned net proved reserves of 8,893 mboe and net proved plus probable reserves
of 10,746 mboe of oil, gas and natural gas liquids to this area, or 5.3 per cent
of total net proved plus probable reserves.

BROOKS

The Brooks property is located in southeast Alberta. We are the operator and own
an average working interest of 93 per cent. During 2004, net production from the
area averaged 1,219 boe/d of natural gas from 291 net wells. GLJ assigned net
proved reserves of 3,515 mboe and net proved plus probable reserves of 4,024
mboe of natural gas to this area, or 2.0 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. During 2004, net
production from the area averaged 600 boe/d of oil, gas and natural gas liquids
from 5 net wells. During 2004, 5 new wells were drilled. GLJ assigned net proved
reserves of 5,080 mboe and net proved plus probable reserves of 7,703 mboe of
oil, gas and natural gas liquids to this area, or 3.8 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, 2004.

<PAGE>
                                       22


<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               3,494.0     858.0     1,002.0       111.3    3,291.0    1,470.6     225.0       45.2
British Columbia        125.0       1.6        30.0         1.6      224.0       59.1      33.0        9.7
Saskatchewan          1,862.0     655.3       285.0        88.5    4,717.0      625.0      79.0       22.0
                      -------   -------     -------       -----    -------    -------     -----       ----
Total                 5,481.0   1,514.9     1,317.0       201.4    8,232.0    2,154.7     337.0       76.9
                      =======   =======     =======       =====    =======    =======     =====       ====
</TABLE>

PROPERTIES WITH NO ATTRIBUTABLE RESERVES

The following table sets out our undeveloped land holdings as at December 31,
2004.

                                         UNDEVELOPED ACRES
                                      ----------------------
                                         GROSS           NET
                                         -----           ---

        Alberta                         583,839      270,428
        British Columbia                 79,111       56,652
        Saskatchewan                    334,613       82,793
        Northwest Territories           276,263       27,881
        Total                         1,273,825      437,754

We currently have no material work commitments on these lands. We expect that
rights to explore, develop and exploit 91,558 net acres of our undeveloped land
holdings will expire by December 31, 2005.


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 oil and natural gas
liquids production for up to 12 months and up to 35 per cent of oil and natural
gas liquids production for the period commencing one year in the future for a
maximum of 12 months. With respect to natural gas hedging, the program permits
the hedging of up to 70 per cent of our natural gas production for up to 24
months and up to 35 per cent of 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 50 per cent on a boe basis for up to 12 months, up to 25 per
cent on a boe basis for the 12 month period thereafter (year two in the future)
and up to 15 per cent on a boe basis for the 36 month period thereafter (years
three to five in the future). These hedge limits can be increased upon approval
by the Board of Directors.

A summary of financial and physical contracts in respect of hedging activities
can be found in Note 10 "Financial Instruments" to our audited consolidated
financial statements for the year ended December 31, 2004 and under the heading
"Risk Management and Hedging" in our management discussion and analysis and
results of operations for the year ended December 31, 2004 which have been filed
on SEDAR at WWW.SEDAR.COM, both sections of which are incorporated herein by
reference.

<PAGE>
                                       23


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, 2004                 247.0                          73.0
Anticipated to be paid in 2005                  1.6                           1.5
Anticipated to be paid in 2006                  2.1                           1.8
Anticipated to be paid in 2007                  2.0                           1.7
</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. Ongoing
environmental obligations are expected to be funded out of cash flow.

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 $247.0 million escalated at 1.5
per cent per year (reflected in the 2004 financials statements as an asset
retirement obligation of $73 million calculated by escalating costs at 2.0 per
cent per year and discounted at a blended rate of 6.9 per cent). We anticipate
contributing over a 20 year period with minimum annual contributions of $6.0
million ($5.5 million in 2003) based upon properties owned as at December 31,
2004 (less current year site reclamation and abandonment costs). During 2004,
$3.1 million ($1.9 million for 2003) of actual expenditures were charged against
the reclamation fund resulting in net contributions for the year of $2.9 million
($3.6 million in 2003).

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 8 specific geographic regions. 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 reserve life of its associated reserve.

The following table sets forth information respecting 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. Only the
abandonment costs associated with reserve wells were deducted by GLJ in
estimating future net revenue.

<PAGE>
                                       24


<TABLE>
<CAPTION>
                                                     TOTAL PROVED PLUS PROBABLE RESERVES
                                           -------------------------------------------------------
                                           CONSTANT PRICES AND COSTS     FORECAST PRICES AND COSTS
                                           -------------------------     -------------------------
<S>                                                 <C>                           <C>
Net producing wells for which GLJ
estimated we will incur reclamation
and abandonment costs                               3,794                         3,794

Additional reclamation and
abandonment liability not deducted by
GLJ in estimating future net revenue
($MM)                                               133.0                          82.1

Additional reclamation and
abandonment liability not deducted by
GLJ in estimating future net revenue
discounted at 10 per cent
($MM)                                                30.1                          23.0
</TABLE>


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. Therefore, it can be expected that no income tax liability
would be incurred by us for as long as we maintain this organizational tax
structure.

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, 2004:

                                                    2004
                                              ----------------
                                                     $M
           Property acquisition costs
                Proved properties                  $13,790
                Undeveloped properties                   0
           Exploration costs(1)                     20,096
           Development costs(2)                    170,868
           Corporate costs                           2,820
           Total                                  $207,574

Notes:
(1)      Costs of land acquired, geological and geophysical capital expenditures
         and drilling costs for 2004 exploration wells drilled.
(2)      Development and facilities capital expenditures.


<PAGE>
                                       25


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, 2004:

                                      EXPLORATORY WELLS        DEVELOPMENT WELLS
                                      -----------------        -----------------
                                      GROSS         NET        GROSS         NET
                                      -----         ---        -----         ---
Light and Medium Oil                     15         7.1           84        35.8
Natural Gas                              48        11.7          446       129.3
Service                                   0         0.0            7         0.5
Dry                                       1         1.0            7         3.9
Total:                                   64        19.8          544       169.5

We have an extensive capital program of $240 MM planned for 2005. The primary
components of our program are as follows.

In the Prestville area of northern Alberta our $21.1MM program includes the
drilling of 6 development and delineation wells in the Cranberry Slave Point D
Pool oil reservoir along with 1.5 net exploratory wells on our land holdings in
the region. In addition to drilling activities, a water injection facility will
be constructed to initiate a waterflood project into the Cranberry Slave Point D
Pool. Construction of the water injection facilities should be completed in the
last half of 2005.

In Ante Creek, our $29.9MM capital program includes the drilling of 14 stepout
and development wells, well reactivations, waterflood pump upgrades and
additional compression. In the Dawson area, our $17.8MM capital program includes
2 horizontal and 5 vertical wells.

In the Jenner and Hatton areas of Southeast Alberta and Southwest Saskatchewan,
we plan to drill approximately 170 shallow gas wells at a cost of $26.0MM.


PRODUCTION ESTIMATES

The following table sets out the volume of our production estimated for the year
ended December 31, 2005 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             19,244   16,139   1,076    1,124    153,775    124,634    3,661    2,660  49,610   40,695
Proved Developed Non-
  Producing                      93       79       0        0      2,499      1,834       50       34     560      418
Proved Undeveloped            1,532    1,243       8        7      5,088      3,946      133       92   2,520    2,000
Total Proved                 20,870   17,461   1,083    1,131    161,362    130,413    3,844    2,785  52,690   43,113
Total Probable                  684      538      88       75      4,775      3,707       95       70   1,662    1,301
Total Proved Plus
Probable                     21,553   18,000   1,172    1,206    166,136    134,119    3,938    2,855  54,353   44,414
</TABLE>

<PAGE>
                                       26


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
                                                                     2004
                                              ---------------------------------------------  YEAR ENDED
(6:1)                                          MAR. 31      JUNE 30     SEPT. 30    DEC. 31        2004
                                               -------      -------     --------    -------  ----------
<S>                                             <C>          <C>         <C>         <C>         <C>
Average Daily Production(1)
  Light and Medium Crude Oil (bbl/d)            23,663       22,720      22,496      22,969      22,961
  Gas (MMcfpd)                                   174.5        186.7       177.4       174.7       178.3
  NGLs (bbl/d)                                   4,323        4,313       4,034       4,097       4,191
  Combined (boe/d)                              57,075       58,147      56,096      56,179      56,870

Average Net Production Prices Received
  Light and Medium Crude Oil ($/bbl)             40.41        47.43       51.00       49.48       47.03
  Gas ($/Mcf)                                     6.64         6.99        6.65        6.82        6.78
  NGLs ($/bbl)                                   32.30        38.22       42.30       43.72       39.04
  Combined ($/boe)                               39.58        44.09       44.72       44.91       43.32

Royalties Paid
  Light and Medium Crude Oil ($/bbl)              7.49         7.73        9.21        9.02        8.30
  Gas ($/Mcf)                                     1.20         1.51        1.45        1.36        1.39
  NGLs ($/bbl)                                    9.03        10.35       12.41       11.44       10.72
  Combined ($/boe)                                7.46         8.64        9.17        8.75        8.51

Operating Expenses (2)(3)
  Light and Medium Crude Oil ($/bbl)              7.47         8.31        8.96        7.71        8.46
  Gas ($/Mcf)                                     0.95         0.90        0.98        1.04        0.93
  NGLs ($/bbl)                                    5.81         6.97        4.18        5.46        5.28
  Combined ($/boe)                                6.45         6.64        6.98        6.77        6.71

Transportation Paid
  Light and Medium Crude Oil ($/bbl)              0.23         0.30        0.07        0.15        0.19
  Gas ($/Mcf)                                     0.21         0.18        0.21        0.22        0.20
  NGLs ($/bbl)                                      --           --          --          --          --
  Combined ($/boe)                                0.74         0.68        0.69        0.73        0.71

(Gain)/Loss on Commodity and Foreign
Exchange Contracts
  Light and Medium Crude Oil ($/bbl)              5.26         7.30       10.67       14.46        9.41
  Gas ($/Mcf)                                    (0.01)        0.11        0.06        0.02        0.05
  NGLs ($/bbl)                                      --           --          --          --          --
  Combined ($/boe)                                2.15         3.20        4.48        5.97        3.94

Netback Received(4)
  Light and Medium Crude Oil ($/bbl)(5)          19.96        23.79       22.09       18.14       20.67
  Gas ($/Mcf)                                     4.29         4.29        3.95        4.18        4.21
  NGLs ($/bbl)                                   17.46        20.90       25.71       26.82       23.04
  Combined ($/boe)                               22.78        24.93       23.40       22.69       23.45
</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.
(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.

<PAGE>
                                       27


No property accounts for more than 7.0 per cent of the production disclosed
above. For more information, see "Other Oil and Gas Information - Principal
Properties".

MARKETING ARRANGEMENTS

In accordance with CICA section 1100 implemented on January 1, 2004, product
prices and revenue for 2003 have been reclassified to reflect prices prior to
transportation charges. In addition, changes to hedge accounting under section
1100 require that average prices be calculated prior to gains and losses on
commodity and foreign currency contracts. Accordingly, average prices for 2003
and 2004 discussed below both reflect the new accounting policies and are
calculated prior to transportation charges and prior to gains and losses on
commodity and foreign currency contracts. Previous disclosure by the Trust
relating to 2003 average prices included transportation costs and gains and
losses on commodity and foreign currency contracts.

NATURAL GAS

During 2004, 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 2004 was $6.78 per Mcf as
compared to $6.49 for 2003. This price was achieved with a portfolio mix that on
average through the year received AECO index based pricing for 61 per cent,
aggregator netback prices for 24 per cent, Chicago Index Pricing for 11 per cent
and fixed price for 4 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 2004 was comprised of approximately 39 per cent light
quality crude oil (greater than 35(degree) API), 41 per cent medium quality
crude oil (25(degree) to 35(degree) API), 5 per cent heavy quality crude (less
than 25(degree) API), 7 per cent condensate and 8 per cent natural gas liquids.
During 2004, our average sales prices were $47.03 per bbl for oil and $39.04 per
bbl for condensate and natural gas liquids; these prices compare to 2003 prices
of $38.15 per bbl for oil and $32.19 per bbl for natural gas liquids. Our crude
oil is sold under short term contracts (30-180 days) while 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 dispositions of $58.2 million, net of adjustments, in
2004. We also completed two corporate acquisitions for total consideration of
$82.0 million resulting in total acquisitions, net of dispositions, of $23.8
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 100 common shares are issued and outstanding and held by the Trust. The
voting of such shares is delegated

<PAGE>
                                       28


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 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, 2004, 1,783,776 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, 2004 the Exchange Ratio was 1.67183 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

<PAGE>
                                       29


                  the stock dividends payable in common shares of ARC Resources
                  or any such other shares ranking junior to the Exchangeable
                  Shares;

         (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.

<PAGE>
                                       30


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.

At December 31, 2004, we had revolving credit facilities to a combined maximum
of $620 million including US $183 million of senior secured notes at December
31, 2004. 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 including a
borrowing base short fall. The revolving credit facilities are borrowing base
and have a 364 day extendable period and a two year term. For more information,
reference is made to note 7 of our Consolidated Financial Statements that are
incorporated by reference.

ESCROW 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. The escrow agreements
are subject to amendment by the board of directors. 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 following table sets forth the number and percentage of Trust Units and
Exchangeable Shares, which to our knowledge, are held in escrow as at the date
hereof.

                       ESCROWED TRUST UNITS AND EXCHANGEABLE SHARES
         DESIGNATION OF CLASS    NUMBER HELD IN ESCROW    PERCENTAGE OF CLASS
         --------------------    ---------------------    -------------------
         Trust Units                          180,083                 0.096%
         Exchangeable Shares                  624,926                 0.336%

         Notes:
         (1)  Both Computershare Trust Company of Canada and ARC Forfeiture
              Holdings Ltd. are the escrow agents under the escrow agreements.
         (2)  Three classes of escrowed securities (A, B and C) exist under the
              Computershare escrow agreements. The escrow agreements commenced
              August 28, 2002 and under escrow agreement A and B, 20 per cent of
              the original securities deposited into escrow are releasable on
              each of August 29, 2003 through 2007. Under escrow agreement C,
              33? per cent of the original securities deposited into escrow are
              releasable on each of August 29 of 2003 through 2005.
         (3)  The ARC Forfeiture Holdings Escrow Agreements commenced August 28,
              2002 and provide that 20 per cent of the original securities
              deposited into escrow are releasable on each of August 29, 2003
              through 2007.

All the distributions received on the Trust Units (or attributable to
Exchangeable Shares) held in escrow flow through to the underlying holders of
the Trust Units or Exchangeable Shares. Distributions on the Trust Units are
made directly to the holder of the escrowed Trust Units. Distributions
attributable to Exchangeable Shares are, on the request of a holder of
Exchangeable Shares, released periodically, by release of such number of
Exchangeable Shares which reflect the increase in the number of Trust Units as a
result of distributions on Trust Units to which such escrowed holder is entitled
at the time. In the event of a change in control of ARC Resources or the Trust
other than among affiliates, all Trust Units and Exchangeable Shares held in
escrow are to be released. Securities held in escrow may be charged, pledged or
encumbered, provided that the securities remain in escrow pursuant to the terms
of the escrow agreements.

As at March 22, 2005, 193,539 Exchangeable Shares held in escrow will be
forfeited by the holder if he or she ceases to be an employee, director or
officer of ARC Resources, ARC Financial Corporation, an affiliate of the Trust
or any other member of the ARC Financial group of companies. Any Exchangeable

<PAGE>
                                       31


Shares forfeited will be redistributed among the remaining parties to this
escrow. In the event of a change in control of the Trust, the forfeiture
provisions will be cancelled.

The escrow provisions and forfeiture provisions were intended to enhance
alignment between management and unitholder interests.

RETENTION BONUSES AND EXECUTIVE EMPLOYMENT AGREEMENTS

As a condition of the internalization transaction, ARML declared retention
bonuses to the Chief Executive Officer and the five Vice-Presidents of ARC
Resources as at August 28, 2002. 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 bonuses 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 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

<PAGE>
                                       32


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.

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

<PAGE>
                                       33


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 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 and strategic services for a
five year period without further cost. This ensures the continuing availability
of research and strategic advice in the energy sector, which has been beneficial
to us in the past. ARC Financial Corporation has also agreed not to, and will
use reasonable commercial efforts, to cause any of the ARC Financial group of
companies, not to act as manager or promoter of another publicly listed energy
related trust for a period of five years, with certain exceptions relating to
the ARC venture capital activities carried out by any member of the ARC
Financial group of companies.

LIMITATION ON NON-RESIDENT OWNERSHIP

In order that we maintain our status as a mutual fund trust under the Tax Act,
we must not be established or maintained primarily for the benefit of
non-residents of Canada ("non-residents") within the meaning of the Tax Act.
Accordingly, the Trust Indenture provides that we shall, among other things,
take all necessary steps to monitor the ownership of the Trust Units in order
that we maintain the status of a unit trust and a mutual fund trust for the
purposes of the Tax Act. The Trust Indenture also provides that if at any time
we become aware that the beneficial owners of 50 per cent or more of the Trust
Units then outstanding are or may be non-residents or that such a situation is
imminent, we shall take such action as may be necessary to carry out the
foregoing intentions.

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

<PAGE>
                                       34


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 pay the Market Redemption Price for such Trust Units on the
last day of the following month by distributing unsecured promissory notes of
ARC Resources ("ARC Resources Notes") having an aggregate principal amount equal
to the aggregate Market Redemption Price of the Trust Units tendered for
redemption, which notes will bear interest at the rate of 6 per cent per annum
and will mature on the 15th anniversary of the date of issuance.

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.

<PAGE>
                                       35


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 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 require 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.

<PAGE>
                                       36


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      Vice-President, Canada Frontier &
Calgary, Alberta, Canada       June 26, 1996                         International Business of Husky Energy
                                                                     Inc. (a public oil and gas company)

John P. Dielwart               President, Chief Executive Officer    President and Chief Executive Officer of
Calgary, Alberta, Canada       and Director since May 3, 1996        ARC Resources

John M. Beddome(2)(4)          Director since May 3, 1996            Independent Businessman
Calgary, Alberta, Canada

Frederic C. Coles(2)(3) (5)    Director since May 3, 1996            Independent Businessman
Calgary, Alberta, Canada

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

John M. Stewart(3)(4)(5)       Director since February 11, 1998      Vice Chairman of ARC Financial Corporation
Calgary, Alberta, Canada

Doug J. Bonner                 Vice-President, Engineering           Vice-President, Engineering of ARC Resources
Calgary, Alberta, Canada

David P. Carey                 Vice President, Business Development  Vice President, Business Development of ARC
Calgary, Alberta, Canada                                             Resources

Susan D. Healy                 Vice-President, Corporate Services    Vice-President, Corporate Services of ARC
Calgary, Alberta,  Canada                                            Resources

Steven W. Sinclair             Vice-President, Finance and Chief     Vice-President, Finance and Chief Financial
Calgary, Alberta, Canada       Financial Officer                     Officer of ARC Resources

Myron M. Stadnyk               Vice-President, Operations and Land   Vice-President, Operations and Land of ARC
Calgary, Alberta, Canada                                             Resources

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 Reserve Audit Committee.
(3)      Member of Human Resources and Compensation Committee.

<PAGE>
                                       37


(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 or the last five years except for Walter DeBoni who,
prior to February 2002, was President and Chief Executive Officer of Bow Valley
Energy Ltd. (an oil and gas company); Fred Dyment who prior to May 2001 was
President and Chief Executive Officer of Maxx Petroleum Ltd. (an oil and gas
company) and prior to July 2000 was President and Chief Executive Officer of
Ranger Oil Ltd. (an oil and gas company); David P. Carey who, prior to November
2001, was Director of Investor Relations of Gulf Canada Resources; Myron J.
Stadnyk, who prior to September 2004, was Vice President Operations of ARC
Resources; and Susan D. Healy, who prior to September 2004, was Vice President
Land 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 CEO of ARC Resources 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 member of the Associate of Professional Engineers,
Geologists and Geophysicists of Alberta (APEGGA). Mr. Dielwart is a recent 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. Mr. Dielwart is a director of ARC
Financial Corporation. He has been a director of ARC Resources since 1996.

STEVEN W. SINCLAIR, B. COMM., CA

Mr. Sinclair is Vice-President Finance and Chief Financial Officer of ARC
Resources and oversees all of the financial affairs of the Trust. Mr. Sinclair
has a Bachelor of Commerce from the University of Calgary, obtained his
Chartered Accountant's designation in 1981 and has over 20 years experience
within the finance, accounting and taxation areas of the oil and gas industry.
Mr. Sinclair has been with the Trust since 1996. Mr. Sinclair is a member of
both the Alberta and Canadian Institute of Chartered Accountants

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

Mr. Bonner is Vice-President, Engineering of ARC Resources and is responsible
for all exploitation and development activities. 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. Mr. Bonner is a member of the Association of Professional
Engineers, Geologists and Geophysicists of Alberta. Prior to joining ARC
Resources 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 Vice-President, Business Development of ARC Resources and is
responsible for all facets of business development and investor relations. 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

<PAGE>
                                       38


Canada, oilsands, the Canadian frontiers and internationally. Mr. Carey is a
member of the Association of Professional Engineers, Geologists and
Geophysicists of Alberta. 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 Vice-President, Corporate Services and is responsible for all
office services and human resources related activities. Ms. Healy joined the
Trust at inception in July 1996, bringing with her over 17 years of diverse
experience gained from working with junior and senior oil and gas companies. Ms.
Healy has a Professional Land designation granted by the Canadian Association of
Petroleum Landmen.

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

Mr. Stadnyk is Vice-President, Operations and Land of ARC Resources and is
responsible for all of ARC Resources' operational activities. He has 18 years
experience in all aspects of oil and gas production operations. Prior to joining
ARC Resources in 1997, Mr. Stadnyk worked with a major oil and gas company in
both domestic and international operations and oil and gas facility design and
construction. He has a B.Sc. in Mechanical Engineering and is a member of the
Association of Professional Engineers, Geologists and Geophysicists in Alberta
and Saskatchewan.

ALLAN R. TWA, Q.C.

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. Mr. Twa is the
Corporate Secretary.

Allan R. Twa, the Secretary of ARC Resources, was a director of Bracknell
Corporation until November 1, 2001 at which time Mr. Twa and the other directors
of Bracknell resigned. At that time the principal bankers of Bracknell had given
notice of default under Bracknell's credit facilities and expressed their intent
to realize on their security. Bracknell consented to those proceedings.

Mac Van Wielingen is the Chairman and a Director of ARC Resources and Allan R.
Twa is the Secretary of ARC Resources. Mr. Van Wielingen and Mr. Twa were
directors 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 12, 2004 to hold
office until the next annual general meeting of ARC Resources, which is
scheduled for May 12, 2005. As at March 22, 2005, the directors and officers of
ARC Resources, as a group, beneficially owned, directly or indirectly, or
exercised control or direction over, 915,606 Trust Units or approximately 0.5
per cent of the outstanding Trust Units, and 1,080,204 Exchangeable Shares or
approximately 62.0 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 March 22, 2005, the directors and officers of ARC Resources as a
group would hold 2,765,617 Trust Units or approximately 1.5 per cent of the
outstanding Trust Units as at March 22, 2005.

<PAGE>
                                       39


                              CONFLICTS OF INTEREST

Circumstances may arise where members of the Board of Directors of ARC Resources
serve as directors or officers of corporations which are in competition to our
interests. No assurances can be given that opportunities identified by such
board members will be provided to us.

The BUSINESS CORPORATIONS ACT (Alberta) provides that in the event that a
director has an interest in a contract or proposed contract or agreement, the
director shall disclose his interest in such contract or agreement and shall
refrain from voting on any matter in respect of such contract or agreement
unless otherwise provided under such Act. To the extent that conflicts of
interest arise, such conflicts will be resolved in accordance with the
provisions of such Act.

           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 except for the interest of certain directors and officers of ARC Resources
in relation to the internalization transaction which is described under the
heading, "ARC Energy Trust - General Development of Our Business".

                          DISTRIBUTIONS TO UNITHOLDERS

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

                    2002          DISTRIBUTION PER TRUST UNIT
                    ----          ---------------------------
                First Quarter              $0.39
                Second Quarter             $0.39
                Third Quarter              $0.39
                Fourth Quarter             $0.39

                    2003
                    ----
                First Quarter              $0.45
                Second Quarter             $0.45
                Third Quarter              $0.45
                Fourth Quarter             $0.45

                    2004
                    ----
                First Quarter              $0.45
                Second Quarter             $0.45
                Third Quarter              $0.45
                Fourth Quarter             $0.45

In certain circumstances, distributions may be restricted by our borrowing
agreements. For more information see "Our Other Information - Borrowing". Cash
distributions paid to Unitholders in 2002 were 32 per cent tax deferred, 2003
cash distributions were 15 per cent tax deferred and 2004 cash distributions
were 6 per cent tax deferred. For more information, see "Business of the Trust -
Cash Distributions of Distributable Income and Distribution Policy".

<PAGE>
                                       40


      PRICE RANGE AND TRADING VOLUME OF TRUST UNITS AND EXCHANGEABLE SHARES

The Trust Units are listed and posted for trading on the 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):

                                                   THE TORONTO STOCK EXCHANGE
                                                   --------------------------
    2004 PERIOD                                  HIGH         LOW         VOLUME
    -----------                                  ----         ---         ------
                                                  $            $
    January                                     14.92       14.12     10,748,631
    February                                    15.32       13.90     12,622,116
    March                                       15.67       15.18     8,734,426
    April                                       15.60       14.75     6,412,103
    May                                         15.51       14.55     8,283,334
    June                                        15.35       14.32     6,624,167
    July                                        16.04       15.20     5,602,586
    August                                      16.25       15.61     8,343,903
    September                                   17.09       15.85     10,215,403
    October                                     17.25       16.24     10,608,030
    November                                    17.42       15.83      9,629,952
    December                                    17.90       16.57      8,476,024


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):

                                                  THE TORONTO STOCK EXCHANGE
                                                  --------------------------
     2004 PERIOD                                 HIGH          LOW     VOLUME
     -----------                                 ----          ---     ------
                                                  $             $
    January                                     22.68        21.30     23,413
    February                                    22.35        21.10     2,200
    March                                       23.99        23.20     5,773
    April                                       25.00        23.25     1,490
    May                                         23.50        22.81     2,600
    June                                        25.24        22.80     4,420
    July                                        27.00        24.15     1,950
    August                                      28.00        26.50     6,100
    September                                   27.62        26.50     3,712
    October                                     28.50        27.50     5,187
    November                                    29.34        26.24     1,744
    December                                    30.22        29.52     2,079


                              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

<PAGE>
                                       41


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 OF 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. Such
price depends in part on oil quality, prices of competing oils, distance to
market, the value of refined products and the supply/demand balance. 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 among producers, marketers
and purchasers. Natural gas exported from Canada is subject to regulation by the
NEB and the Government of Canada. Exporters are free to negotiate prices 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 2 years or for a term of 2 to 20 years (in
quantities of not more than 30,000 m3/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.

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. The governments of Alberta,
British Columbia and Saskatchewan also regulate the volume of natural gas which
may be removed from those provinces for consumption elsewhere based on such
factors as reserve ability, transportation arrangements and market
considerations. The prorationing 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. 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; or (iii) disrupt normal channels of
supply. All three countries are prohibited from imposing minimum export or
import price requirements.

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

<PAGE>
                                       42


PROVINCIAL ROYALTIES AND INCENTIVES

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 and the
type or quality of the petroleum product produced.

From time to time 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.

In the Province of Alberta, a producer of oil or natural gas is entitled to a
credit against the royalties payable to the Crown by virtue of the Alberta
royalty tax credit ("ARTC") program. The ARTC rate is based on a price sensitive
formula and the ARTC rate varies between 75 per cent at prices at and below $100
per m3 and 25 per cent at prices at and above $210 per m3. The ARTC rate is
applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each
producer or associated group of producers. Crown royalties on production from
producing properties acquired from a corporation claiming maximum entitlement to
ARTC will generally not be eligible for ARTC. The rate will be established
quarterly based on the average par price, as determined by the Alberta
Department of Energy for the previous quarterly period.

Crude oil and natural gas royalty programs for specific wells and royalty
reductions reduce the amount of Crown royalties we pay to the provincial
governments. In general, the ARTC program provides a rebate on Alberta Crown
royalties paid in respect of eligible producing properties.

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 2 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.

<PAGE>
                                       43


Environmental legislation in the Province of Alberta was consolidated into the
Alberta Environmental Protection and Enhancement Act (the "APEA"), which came
into force on September 1, 1993. The APEA imposes strict environmental
standards, requiring compliance, reporting and monitoring obligations and
significant penalties. We are committed to meeting our responsibilities to
protect the environment wherever we operate and anticipate making increased
expenditures of both a capital and an expense nature as a result of laws
relating to the protection of the environment and will be taking such steps as
required to ensure compliance with the APEA and similar legislation in other
jurisdictions in which we operate. We believe that we are in material compliance
with applicable environmental laws and regulations. We also believe that it is
reasonably likely there will be even stricter standards in environmental
legislation and regulation in the future.

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 6 percent below 1990 levels during the
period between 2008 and 2012. See also "Risk Factors - Kyoto Protocol".

                                  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.

RESERVE ESTIMATES

The reserve 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 reserve 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 reserve 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.

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

<PAGE>
                                       44


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.

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.

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.

In Saskatchewan, we carry on all of our operations through a trust structure. As
a result of this structure, we are not subject to Saskatchewan capital tax
because the Saskatchewan capital tax legislation only applies to corporations.
Due to the increase in the number of oil and gas producers that are now
operating in Saskatchewan through a trust structure, the Saskatchewan government
is currently considering the inclusion of trusts into its capital tax
legislation. If the Saskatchewan capital tax legislation is amended to include
trusts, we will effectively be subject to a 3.6 per cent resource surcharge on
all of our oil and gas working interest revenue earned in Saskatchewan. Using
our 2004 revenue, this would have amounted to $8.0 million.

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:

<PAGE>
                                       45


    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 1 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 Customs and 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. See "Risk Factors -
Non-resident Ownership of Trust Units".

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 reserve 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 reserve additions, our reserves
will deplete and as a consequence, either production from, or the average
reserve 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.

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

<PAGE>
                                       46


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.

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

In order for us to maintain our status as a mutual fund trust under the Tax Act,
we must not be established or maintained primarily for the benefit of
non-residents of Canada (non-residents) within the meaning of the Tax Act. The
Trust Indenture provides that if at any time we become aware that the beneficial
owners of 50 per cent or more of the Trust Units then outstanding are or may be
non-residents or that such a situation is imminent, we shall take such action as
may be necessary to carry out the foregoing intention. See "Information Relating
to the Trust - Limitations on Non-resident Ownership".

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 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,
2004 we had $157.6 million recorded on its balance sheet as goodwill arising out
of our acquisition of Star Oil & Gas Ltd. An impairment would result in a

<PAGE>
                                       47


write-down of the goodwill value anda 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.

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. 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.

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 6 percent below 1990 levels during the
period between 2008 and 2012. See "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.
However, the Canadian Association of Petroleum Producers has secured specific
non-binding limitations from the Government of Canada on reductions required by
the oil and gas industry and the cost thereof. On the basis of these
limitations, the impact of the Kyoto Protocol on our operations is currently not
expected to be material.

Future federal legislation, together with 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 beyond what was agreed to by the
Canadian Association of Petroleum Producers. The direct or indirect costs of
these regulations may adversely affect our business.

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 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

<PAGE>
                                       48


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, 2004, we operated approximately 63 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 reserve base
and acquiring additional reserves. Without reserve 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.

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

<PAGE>
                                       49


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.

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. 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.

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. As a result of such increasing
competition, it will be more difficult to acquire reserves on beneficial terms.
We also compete for reserve acquisitions and skilled industry personnel with a
substantial number of other oil and gas companies, many of which have
significantly greater financial and other resources than we do.

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 Information Relating to the
Trust - 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. 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 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

<PAGE>
                                       50


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 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 our
behalf 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 us 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 us.

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.

<PAGE>
                                       51


                               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 after January 1, 2002 and 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 "Information Relating to the
         Trust" 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".

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. The
interest of GLJ in our Trust Units and Exchangeable Shares represents and
represented at the time it prepared the report less than 1% of each of the
issued and outstanding Trust Units or Exchangeable Shares. The interest of
Deloitte & Touche LLP in our Trust Units and Exchangeable Shares represents and
represented at the time it prepared the report less than 1% of each of the
issued and outstanding Trust Units or Exchangeable Shares.

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, except for
Allan R. Twa, the Corporate Secretary of ARC Resources, is a partner at 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 12, 2005. Additional financial information is
provided in our consolidated financial statements and accompanying management's
discussion and analysis for the year ended December 31, 2004, which have been
filed on SEDAR at www.sedar.com.



<PAGE>


                                   APPENDIX A

       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, 2004. The reserves data consist of the following:

         (a)      (i)      proved and proved plus probable oil and gas reserves
                           estimated as at December 31, 2004 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, 2004 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 percent, included in the reserves data of the
         Company evaluated by us for the year ended December 31, 2004, 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>
                                                                       NET PRESENT VALUE OF FUTURE NET REVENUE
                                      LOCATION OF RESERVES   (BEFORE INCOME TAXES, 10% DISCOUNT RATE, MILLIONS DOLLARS)
DESCRIPTION AND PREPARATION DATE      (COUNTRY OR FOREIGN    ----------------------------------------------------------
      OF EVALUATION REPORT              GEOGRAPHIC AREA)         AUDITED       EVALUATED      REVIEWED        TOTAL
      --------------------              ----------------         -------       ---------      --------        -----

        <S>                                  <C>                   <C>           <C>             <C>          <C>
        January 18, 2005                     Canada                --            2,389           --           2,389
</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 judgements regarding future
         events, actual results will vary and the variations may be material.

Executed as to our report referred to above:



 Gilbert Laustsen Jung Associates Ltd.                  Dated January 18, 2005
 Calgary, Alberta, Canada


 (SIGNED) "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, 2004 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, 2004 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 Reserve Audit 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 Reserve Audit 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 Reserve Audit 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.

(signed) "JOHN P. DIELWART"                    (signed) "DOUG BONNER"
JOHN P. DIELWART                               DOUG BONNER
President and Chief Executive Officer          Vice-President, Engineering


(signed) "FREDERIC COLES"                      (signed) "JOHN BEDDOME"
FREDERIC COLES                                 JOHN BEDDOME
Director and Chairman of the Reserve Audit     Director and Member of the
Committee                                      Reserve Audit Committee

March 22, 2005