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ARC Resources Ltd. Announces Record 320 Per Cent Replacement of Produced Reserves Through Development Activities in 2017

CALGARY, Feb. 8, 2018 (Canada NewsWire via COMTEX) --

(ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its 2017 year-end reserves and resources information.

"2017 marks ARC's largest addition of development reserves in our company's history, having added 145 MMboe of proved plus probable reserves, and replacing 320 per cent of 2017 produced reserves," stated Myron Stadnyk, President and CEO. "Our Montney assets in northeast British Columbia are becoming increasingly significant to our liquids portfolio, and now account for 25 per cent of our total corporate proved plus probable oil reserves and nearly 50 per cent of our total corporate liquids when considering our condensate and natural gas liquids reserves. These meaningful figures are a clear demonstration of ARC's deliberate transition to the Montney, and most notably into the more liquids-rich portions of the Montney fairway. Our oil and gas portfolio remains best-in-class, with now over 10.5 billion barrels of tight oil and 106.0 Tcf of shale gas initially-in-place identified across ARC's Montney lands in northeast British Columbia and Pouce Coupe in Alberta. Supported by our strong financial position and our excellent capital and operating efficiencies, we are excited about the future development opportunities and the value our Montney assets will allow us to create for our shareholders over the long term."

HIGHLIGHTS

    --  Replaced 320 per cent of total 2017 production ((1)), adding
        144.6 MMboe of proved plus probable ("2P") reserves through
        development activities. Over the last 10 years, ARC has
        replaced an average of 200 per cent or greater produced
        reserves through development activities. ARC's 2P reserve life
        index ("RLI") is 17.4 years ((1)).

    --  Replaced 388 per cent of 2017 natural gas production, adding
        0.7 Tcf of 2P natural gas reserves. Replaced 129 per cent of
        2017 natural gas liquids ("NGLs") production, adding 5.1 MMbbl
        of 2P NGLs reserves. Replaced 176 per cent of 2017 oil
        production, adding 15.4 MMbbl of 2P oil reserves.

    --  Positive technical revisions of 60 MMboe (2P) were realized,
        predominantly in Sunrise and Dawson, reflecting the strong well
        performance from ARC's Montney assets.

    --  Proved developed producing ("PDP") reserves increased by eight
        per cent, from 212 MMboe to 230 MMboe. The net increase in PDP
        reserves was due to both development adds from ARC's core
        Montney properties, as well as positive technical revisions
        reflecting ARC's increased confidence in well performance.

    --  Total proved reserves increased by 19 per cent from 426 MMboe
        to 506 MMboe, and 2P reserves increased by 13 per cent from 737
        MMboe to 836 MMboe.

    --  Material reserves growth was realized in ARC's Montney assets,
        particularly in Attachie, Dawson, Parkland/Tower, Sunrise, and
        Pouce Coupe.

    --  Three-year average Finding, Development and Acquisition
        ("FD&A") ((1)) costs were $5.52 per boe for proved reserves and
        $3.09 per boe for 2P reserves, including Future Development
        Capital ("FDC").

    --  Finding and Development ("F&D") costs ((1)) were $6.41 per boe
        for 2P reserves, $7.40 per boe for proved reserves and $14.98
        per boe for proved producing reserves, excluding FDC.

    --  Before-tax net present value ("NPV") for 2P reserves,
        discounted at 10 per cent, is $5.7 billion at year-end 2017,
        evaluated on GLJ Petroleum Consultants ("GLJ") commodity price
        forecast at January 1, 2018.

  o Year-end 2016 2P NPV of $5.8 billion on GLJ price forecast at
    January 1, 2017.

  o Year-end 2017 2P NPV of $6.9 billion on GLJ price forecast at
    January 1, 2017. Reserves additions increased value by
    approximately 18 per cent.

  o Year-end 2017 2P NPV of $5.7 billion on GLJ price forecast at
    January 1, 2018. Price deck reduced value by approximately 18 per
    cent.

    --  Increased NE BC Montney acreage, including lands at Pouce Coupe
        in Alberta, by four per cent in 2017 with the addition of 27
        high-quality net sections, strengthening ARC's existing
        position across core areas of Attachie and greater Dawson.

    --  ARC updated an Independent Resources Evaluation (the "Resources
        Evaluation" or "Independent Resources Evaluation") for its
        lands in the NE BC Montney region, including lands at Pouce
        Coupe in Alberta. The updated evaluation realized an increase
        in the identified resource base on ARC's NE BC Montney lands.
        The shale gas Total Petroleum Initially-in-Place ("TPIIP")
        increased to 106.0 Tcf in 2017, and tight oil TPIIP was 10.5
        billion barrels of oil in 2017 ((2)).


            (1)    "Reserve replacement", "reserve
                    life index" or "RLI", "Finding,
                    Development and Acquisitions
                    costs" or "FD&A costs", and
                    "Finding and Development costs" or
                    "F&D costs" do not have
                    standardized meanings. See
                    "Information Regarding Disclosure
                    on Oil and Gas Reserves, Resources
                    and Operational Information"
                    contained in this news release.

            (2)    The year-end 2017 Resources
                    Evaluation complies with current
                    Canadian Oil and Gas Evaluation
                    Handbook ("COGE Handbook")
                    guidelines. The Resources
                    Evaluation volumes provided are
                    the "Best Estimate" case. Year-
                    end 2017 and 2016 TPIIP estimates
                    utilize a one per cent porosity
                    cut-off for shale gas and tight
                    oil based upon "Best Estimate"
                    case.

2017 INDEPENDENT RESERVES EVALUATION

GLJ conducted an Independent Reserves Evaluation (the "Reserves Evaluation" or "Independent Reserves Evaluation") effective December 31, 2017, which was prepared in accordance with definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2018, as outlined in Table 1 below.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted. In addition to the detailed information disclosed in this news release, more detailed information will be included in ARC's Annual Information Form ("AIF") for the year ended December 31, 2017, which will be available on ARC's website at www.arcresources.com and filed on SEDAR at www.sedar.com on or before March 30, 2018.

Based on this Independent Reserves Evaluation, ARC's reserves profile as at December 31, 2017 is summarized below:

    --  13 per cent increase in 2017 2P reserves to 836 MMboe compared
        to 737 MMboe of 2P reserves at year-end 2016. 2P reserves are
        comprised of 3.8 Tcf of natural gas, 131 MMbbl of oil ((1)) and
        73 MMbbl of NGLs at year-end 2017. The NGLs are comprised of 48
        per cent condensate (35 MMbbl), 32 per cent propane (23 MMbbl),
        and 20 per cent butane (14 MMbbl).

    --  144.6 MMboe of 2P reserve additions from development activities
        (including revisions), before net acquisitions and dispositions
        of negative 0.5 MMboe and 2017 production of 44.7 MMboe.
        Technical revisions of 60.1 MMboe more than offset the removal
        of 6.0 MMboe due to economic factor revisions resulting from
        the decrease in commodity price forecasts since year-end 2016.

    --  Replaced 320 per cent of total 2017 production, adding 144.6
        MMboe of 2P reserves through development activities, with 2017
        production of 44.7 MMboe.

    --  Total proved reserves account for 61 per cent of 2P reserves.

    --  PDP reserves represent 45 per cent of total proved reserves and
        27 per cent of 2P reserves.

    --  Oil and NGLs comprise 24 per cent of 2P reserves and natural
        gas comprises 76 per cent of 2P reserves, using the commonly
        accepted boe conversion ratio of six Mcf to one barrel.

    --  Additions from development activities resulted in increased
        reserves, coupled with increased FDC for these development
        activities, resulting in one-year 2P F&D costs, including FDC,
        of $9.61 per boe for 2017, and $5.52 per boe for the three-year
        average. Proved F&D costs, including FDC, were $9.34 per boe
        for 2017 and $7.91 per boe for the three-year average.

    --  Strong 2P RLI of 17.4 years at year-end 2017 was up from 16.4
        years at year-end 2016. The increase in RLI is attributed to
        strong reserves growth in 2017. For details on ARC's 2018
        production guidance, see the November 9, 2017 news release
        entitled, "ARC Resources Ltd. Announces $690 Million Capital
        Program for 2018" available on ARC's website at
        www.arcresources.com
        and on SEDAR at
        www.sedar.com.

    --  Recycle ratio ((2)) of 2.5 times and 2.7 times for the current
        year and the three-year average, respectively, for 2P reserves,
        based on current and three-year average F&D costs, excluding
        FDC, which are based on current and three-year average
        operating netbacks ((3)) of $15.94 per boe and $15.32 per boe,
        respectively.

    --  FDC increased by $460 million compared to year-end 2016, to
        total $3.2 billion at year-end 2017, and was driven by the
        booking of future development activities in ARC's core Montney
        acreage.

    --  Before-tax NPV for 2P reserves, discounted at 10 per cent, is
        $5.7 billion at year-end 2017.

    --  Abandonment and reclamation costs increased from $462 million
        (undiscounted) at year-end 2016 to $527 million (undiscounted)
        at year-end 2017. These costs have been included in the 2P
        reserves, which account for the abandonment and reclamation of
        all wells to which reserves have been attributed.


            (1)    Total oil includes light, medium,
                    heavy, and tight oil. See Tables 2
                    and 3 for detailed breakdown.

            (2)    "Recycle ratio" does not have a
                    standardized meaning. See
                    "Information Regarding Disclosure
                    on Oil and Gas Reserves, Resources
                    and Operational Information"
                    contained in this news release.

            (3)    "Operating netback" is a non-GAAP
                    measure and does not have a
                    standardized meaning under IFRS.
                    See "Non-GAAP Measures" contained
                    within ARC's Management's
                    Discussion and Analysis ("MD&A").

Table 1


    GLJ Price Forecast            WTI Crude Oil            Edmonton Light Oil            AECO Natural Gas             Foreign
                                                                                                                   Exchange

                                    (US$/bbl)                  (Cdn$/bbl)                  (Cdn$/MMBtu)             (US$/Cdn$)
    ---                             ---------                  ----------                  ------------             ----------

                                  2018           2017          2018           2017           2018          2017       2018       2017
                                  ----           ----          ----           ----           ----          ----       ----       ----

    2018                         59.00          59.00         70.25          72.26           2.20          3.10      0.790      0.775

    2019                         59.00          64.00         70.25          75.00           2.54          3.27      0.790      0.800

    2020                         60.00          67.00         70.31          76.36           2.88          3.49      0.800      0.825

    2021                         63.00          71.00         72.84          78.82           3.24          3.67      0.810      0.850

    2022                         66.00          74.00         75.61          82.35           3.47          3.86      0.820      0.850

    2023                         69.00          77.00         78.31          85.88           3.58          4.05      0.830      0.850

    2024                         72.00          80.00         81.93          89.41           3.66          4.16      0.830      0.850

    2025                         75.00          83.00         85.54          92.94           3.73          4.24      0.830      0.850

    2026                         77.33          86.05         88.35          95.61           3.80          4.32      0.830      0.850

    2027 (1)                    78.88                       90.22                         3.88                   0.830      0.850
    -------                      -----                       -----                         ----                   -----      -----

    Escalate thereafter at +2% / year    +2% / year   +2% / year    +2% / year    +2% / year    +2% / year     0.830      0.850
    ---------------------- ----------    ----------   ----------    ----------    ----------    ----------     -----      -----


    (1)             Escalated at two per cent
                    per year starting in 2027
                    in the January 1, 2018 GLJ
                    price forecast with the
                    exception of foreign
                    exchange, which remains
                    flat.

Table 2


    Reserves Summary          Light, Tight Oil    NGLs       Natural      2017 Oil       2016 Oil

    Company Gross (1)     Medium and    (Mbbl)  (Mbbl)       Gas (3)    Equivalent     Equivalent

                       Heavy Oil (2)                          (MMcf)        (Mboe)         (Mboe)

                              (Mbbl)
    ---                        -----

    Proved Developed
     Producing                51,470     14,650   17,780        873,778        229,530         212,341

    Proved Developed
     Non-producing             1,030      2,856    4,230        183,661         38,726          10,930

    Proved Undeveloped         7,132     16,438   20,582      1,163,457        238,063         202,656
    ------------------         -----     ------   ------      ---------        -------         -------

    Total Proved              59,632     33,944   42,593      2,220,896        506,319         425,927
    ------------              ------     ------   ------      ---------        -------         -------

    Proved plus
     Probable             79,151 (4)    51,489   72,570  3,797,360 (5)       836,103         736,733
    -----------            ---------    ------   ------   ------------       -------         -------


            (1)    Amounts may not add due to
                    rounding.

            (2)    Light, Medium and Heavy Oil
                    includes light, medium and heavy
                    crude oil product types, as heavy
                    oil makes up three per cent of
                    total light, medium and heavy
                    crude oil and is considered to be
                    immaterial.

            (3)    Natural Gas includes shale gas and
                    conventional natural gas product
                    types, as conventional natural gas
                    makes up three per cent of total
                    gas and is considered to be
                    immaterial.

            (4)    Proved plus Probable Light, Medium
                    and Heavy Oil closing balance by
                    percentage weighting of product
                    type: approximately 97 per cent
                    light and medium crude oil and
                    three per cent heavy crude oil.

            (5)    Proved plus Probable Natural Gas
                    closing balance by percentage
                    weighting of product type:
                    approximately 97 per cent shale
                    gas and three per cent
                    conventional natural gas.

Table 3


    Reserves Reconciliation                               Light,  Tight Oil    NGLs  Natural           Oil

    Company Gross (1)                                 Medium and     (Mbbl)  (Mbbl)  Gas (3)    Equivalent

                                                   Heavy Oil (2)                      (MMcf)        (Mboe)

                                                          (Mbbl)
    ---                                                    -----

    Proved Producing

                            Opening Balance, January 1, 2017         53,259   13,697    13,040        794,069      212,341

                            Discoveries                                   -       -        -             -           -

                            Extensions and Improved Recovery (4)      1,316    4,071     2,918         92,902       23,789

                            Technical Revisions                       1,811    1,422     5,885        186,594       40,217

                            Acquisitions                                  -       -        -            22            4

                            Dispositions                                  -       -      (3)         (307)        (54)

                            Economic Factors                          (597)   (111)     (78)       (7,772)     (2,081)

                            Production                              (4,320) (4,428)  (3,983)     (191,729)    (44,685)
                            ----------                               ------   ------    ------       --------      -------

                            Ending Balance, December 31, 2017        51,470   14,650    17,780        873,778      229,530
                            ---------------------------------        ------   ------    ------        -------      -------

    Total Proved

                            Opening Balance, January 1, 2017         60,155   28,628    38,064      1,794,476      425,927

                            Discoveries                                   -       -        -             -           -

                            Extensions and Improved Recovery (4)      2,889    8,082     7,403        203,905       52,359

                            Technical Revisions                       1,545    2,620     1,552        435,982       78,381

                            Acquisitions                                  -       -        -            22            4

                            Dispositions                                  -       -     (32)       (1,200)       (232)

                            Economic Factors                          (637)   (958)    (412)      (20,560)     (5,434)

                            Production                              (4,320) (4,428)  (3,983)     (191,729)    (44,685)
                            ----------                               ------   ------    ------       --------      -------

                            Ending Balance, December 31, 2017        59,632   33,944    42,593      2,220,896      506,319
                            ---------------------------------        ------   ------    ------      ---------      -------

    Proved plus Probable

                            Opening Balance, January 1, 2017         79,735   44,261    71,504      3,247,395      736,733

                            Discoveries                                   -       -        -             -           -

                            Extensions and Improved Recovery (4)      4,268    8,720    13,078        386,253       90,441

                            Technical Revisions                         238    3,445   (7,663)       384,477       60,099

                            Acquisitions                                  -       -        -            26            5

                            Dispositions                                  -       -     (76)       (2,759)       (536)

                            Economic Factors                          (771)   (509)    (290)      (26,303)     (5,954)

                            Production                              (4,320) (4,428)  (3,983)     (191,729)    (44,685)
                            ----------                               ------   ------    ------       --------      -------

                            Ending Balance, December 31, 2017    79,151 (5)  51,489    72,570  3,797,360 (6)     836,103
                            ---------------------------------     ---------   ------    ------   ------------      -------


            (1)    Amounts may not add due to
                    rounding.

            (2)    Light, Medium and Heavy Oil
                    includes light, medium and heavy
                    crude oil product types, as heavy
                    oil makes up three per cent of
                    total light, medium and heavy
                    crude oil and is considered to be
                    immaterial.

            (3)    Natural Gas includes shale gas and
                    conventional natural gas product
                    types, as conventional natural gas
                    makes up three per cent of total
                    gas and is considered to be
                    immaterial.

                   Reserves additions for infill
                    drilling, improved recovery, and
                    extensions are combined and
                    reported as "Extensions and
            (4)    Improved Recovery".

            (5)    Proved plus Probable Light, Medium
                    and Heavy Oil closing balance by
                    percentage weighting of product
                    type: approximately 97 per cent
                    light and medium crude oil and
                    three per cent heavy crude oil.

            (6)    Proved plus Probable Natural Gas
                    closing balance by percentage
                    weighting of product type:
                    approximately 97 per cent shale
                    gas and three per cent
                    conventional natural gas.

Reserve Life Index

ARC's 2P RLI was 17.4 years at year-end 2017, and the proved RLI was 10.5 years. The RLIs are derived by dividing the appropriate GLJ reserves category by ARC's 2018 production guidance midpoint of 132,000 boe per day, which is contingent upon the execution of a $690 million capital program for 2018. The 2P RLI has been maintained at greater than 15 years since year-end 2010 as a result of successful delineation and reserves growth of ARC's Montney assets in northeast British Columbia. ARC's annual average production has increased from 96,087 boe per day in 2013 to 122,937 boe per day in 2017. Table 4 summarizes ARC's historical RLI.

Table 4


    Reserve Life Index   2017 (1) 2016  2015  2014  2013
    ------------------    ------- ----  ----  ----  ----

    Total Proved             10.5   9.6   9.1   8.5   9.1

    Proved plus Probable     17.4  16.4  15.9  15.0  15.5
    --------------------     ----  ----  ----  ----  ----


            (1)    Based on production
                    guidance midpoint of
                    132,000 boe per day for
                    2018.

Net Present Value Summary

ARC's oil, natural gas and NGLs reserves were evaluated using GLJ's commodity price forecasts at January 1, 2018. The NPV is prior to provision for interest, debt service charges, and general and administrative expenses. It should not be assumed that the NPV of future net revenue estimated by GLJ represents the fair market value of the reserves. The NPV of ARC's reserves decreased relative to year-end 2016, despite material reserve adds in 2017, primarily due to lower forecasted prices by GLJ. NPVs on both a before- and after-tax basis are presented in Table 5.

Table 5


    NPV of Future Net Revenue (1)(2)                                Undiscounted Discounted Discounted  Discounted   Discounted

    ($ millions)                                                                      at 5%    at 10%     at 15%      at 20%
    -----------                                                                        ----      -----       -----        -----

    Before-tax

                                     Proved Developed Producing                       4,449       3,172        2,475         2,045 1,755

                                     Proved Developed Non-producing                     658         506          411           349   305

                                     Proved Undeveloped                               2,690       1,581          973           609   377

                                     Total Proved                                     7,796       5,258        3,860         3,004 2,437

                                     Probable                                         5,858       3,062        1,883         1,280   927

                                     Proved plus Probable                            13,654       8,320        5,743         4,284 3,364
                                     --------------------                            ------       -----        -----         ----- -----

    After-tax (3)(4)

                                     Proved Developed Producing                       3,758       2,751        2,187         1,832 1,587

                                     Proved Developed Non-producing                     479         368          298           252   220

                                     Proved Undeveloped                               1,956       1,104          634           353   175

                                     Total Proved                                     6,194       4,222        3,119         2,437 1,982

                                     Probable                                         4,268       2,206        1,334           888   629

                                     Proved plus Probable                            10,462       6,429        4,453         3,325 2,612
                                     --------------------                            ------       -----        -----         ----- -----


            (1)    Amounts may not add due to
                    rounding.

            (2)    Based on NI 51-101 company net
                    interest reserves and GLJ price
                    forecasts and costs at January
                    1, 2018.

            (3)    Based on ARC's estimated tax
                    pools at year-end 2017.

            (4)    The after-tax NPV of the future
                    net revenue attributed to ARC's
                    oil and natural gas properties
                    reflects the tax burden on the
                    properties on a standalone
                    basis. It does not consider the
                    business entity tax-level
                    situation or tax planning, nor
                    does it provide an estimate of
                    the value at the level of the
                    business entity, which may be
                    significantly different. ARC's
                    audited consolidated financial
                    statements and notes and MD&A
                    should be consulted for
                    information at the business
                    entity level.

At a 10 per cent discount factor, and on a before-tax basis, the future net revenue attributed to the proved producing reserves constitutes 64 per cent of the future net revenue attributed to the total proved reserves (NPV10 before-tax), similar to the future net revenue attributed to the total proved reserves, which accounts for 67 per cent of the future net revenue attributed to the 2P reserves (NPV10 before-tax).

Future Development Capital

FDC reflects the independent evaluator's best estimate of what it will cost to bring the proved and probable developed and undeveloped reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities, and changes in capital cost estimates based on improvements in well design and performance, as well as changes in service costs. FDC increased by $460 million compared to year-end 2016, to total $3.2 billion at year-end 2017. The increase in FDC was driven by development activities in the Montney and is consistent with the increase in 2P reserves volumes.

Table 6 outlines GLJ's estimated FDC required to bring total proved and total 2P reserves on production.

Table 6


    Future Development Capital (1)(2) Total Proved Total Proved plus
                                                            Probable

    ($ millions)
    -----------

    2018                                       500                621

    2019                                       513                602

    2020                                       450                564

    2021                                       290                612

    2022                                       119                313

    Remainder                                  278                504
    ---------                                  ---                ---

    Total FDC, Undiscounted                  2,150              3,215
    -----------------------                  -----              -----

    Total FDC, Discounted at 10%           1,666              2,413
    ---------------------------              -----              -----


            (1)    Amounts may not add due to
                    rounding.

    (2)             FDC as per GLJ Independent
                    Reserves Evaluation as of
                    December 31, 2017 and based on
                    GLJ forecast pricing at January
                    1, 2018.

ARC's 2018 capital budget is $690 million, 10 per cent higher than the proved plus probable FDC forecast for 2018. The total proved plus probable FDC, undiscounted, is less than five times ARC's 2018 capital budget. For details on ARC's 2018 capital budget, see the November 9, 2017 news release entitled, "ARC Resources Ltd. Announces $690 Million Capital Program for 2018" available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

Finding, Development and Acquisition Costs

ARC's 2017 F&D costs were $6.41 per boe and $7.40 per boe for 2P and proved reserves, respectively, excluding FDC ($9.61 per boe and $9.34 per boe, respectively, for 2P and proved reserves, including FDC). ARC's three-year average F&D costs were $5.73 per boe for 2P reserves and $6.88 per boe for proved reserves, excluding FDC. The low F&D costs are attributed to the high-quality nature of ARC's portfolio of assets, strong results from ARC's development program, and meaningful reserves growth, notably at Sunrise, Dawson and Parkland/Tower. ARC's 2017 F&D costs include approximately $98 million of capital investment on Crown lands, with no significant associated reserves or production associated with these acquisitions in the current year.

Including net acquisitions, ARC's 2017 Finding, Development and Acquisition ((1)) costs were $6.45 per boe for 2P reserves and $7.43 per boe for proved reserves, excluding FDC ($9.64 per boe and $9.37 per boe, respectively, for 2P and proved reserves, including FDC). The three-year average FD&A costs were $4.54 per boe for 2P reserves and $5.24 per boe for proved reserves, excluding FDC. ARC's low FD&A costs reflect ARC's focus on high-quality assets, cost management, and allocation of resources and capital investment to high rate of return projects. ARC's 2017 FD&A costs include approximately $98 million of capital investment on Crown lands, with no significant associated reserves or production. Additionally, ARC's FD&A costs incorporate the net acquisition of properties with associated reserves and production for approximately $2.5 million in 2017.

    (1)             "Finding, development and
                    acquisition costs" or "FD&A
                    costs" does not have a
                    standardized meaning. See
                    "Information Regarding
                    Disclosure on Oil and Gas
                    Reserves, Resources and
                    Operational Information"
                    contained in this news release.

Table 7 highlights ARC's reserves, F&D costs, FD&A costs and the associated recycle ratios for the past three years.

Table 7


    Reserves (Company
     Gross), Capital
     Expenditures and                                     2017    2016    2015

    Operating Netbacks
     (1)(2)(3)
    ------------------

    Reserves (Mboe)

                         Proved Producing                229,530 212,341 221,509

                         Total Proved                    506,319 425,927 393,327

                         Proved plus Probable            836,103 736,733 686,851
                         --------------------            ------- ------- -------

    Capital Expenditures
     ($ millions)

                         Exploration and Development       927.3   456.1   548.3

                          Net Property Acquisitions
                          (Dispositions)                     2.5 (532.5) (74.4)


                         Total Capital Expenditures        929.8  (76.4)  473.9

                                                                           ---

    Operating Netbacks
     ($/boe)

                         Operating Netback                 15.94   13.45   16.61

                          Operating Netback - Three-year
                          Average                          15.32   20.83   25.81
                          ------------------------------   -----   -----   -----


            (1)    Amounts may not add due to
                    rounding.

                   "Operating netback" is a non-
                    GAAP measure and does not have
                    a standardized meaning under
                    IFRS. See "Non-GAAP Measures"
            (2)    contained within ARC's MD&A.

            (3)    Operating netbacks exclude other
                    income.

Table 7a


    Finding and Development Costs,
     excluding FDC (1)(2)(3)(4)                       2017   2016   2015

    Company Gross
    -------------

    Proved Producing

                                    Reserve
                                    Additions
                                    (MMboe)                 61.9   43.6   66.0

                                   F&D Costs ($/boe)       14.98  10.46   8.31

                                   F&D Recycle Ratio         1.1    1.3    2.0

                                    F&D Costs - Three-year
                                    Average ($/boe)        11.26  12.77  15.05

                                    F&D Recycle Ratio -
                                    Three-year Average       1.4    1.6    1.7
                                   --------------------      ---    ---    ---

    Total Proved

                                    Reserve
                                    Additions
                                    (MMboe)                125.3   88.6   66.9

                                   F&D Costs ($/boe)        7.40   5.15   8.20

                                   F&D Recycle Ratio         2.2    2.6    2.0

                                    F&D Costs - Three-year
                                    Average ($/boe)         6.88   9.56  14.13

                                    F&D Recycle Ratio -
                                    Three-year Average       2.2    2.2    1.8
                                   --------------------      ---    ---    ---

    Proved plus Probable

                                    Reserve
                                    Additions
                                    (MMboe)                144.6  113.5   78.7

                                   F&D Costs ($/boe)        6.41   4.02   6.97

                                   F&D Recycle Ratio         2.5    3.3    2.4

                                    F&D Costs - Three-year
                                    Average ($/boe)         5.73   7.19  10.36

                                    F&D Recycle Ratio -
                                    Three-year Average       2.7    2.9    2.5
                                   --------------------      ---    ---    ---


            (1)    F&D costs take into account
                    reserves revisions during the
                    year on a per boe basis.

            (2)    The aggregate of the exploration
                    and development costs incurred
                    in the financial year and the
                    changes during that year in
                    estimated future development
                    costs may not reflect the total
                    F&D costs related to reserves
                    additions for that year.

            (3)    "Finding and development recycle
                    ratio" or "F&D recycle ratio"
                    does not have a standardized
                    meaning. See "Information
                    Regarding Disclosure on Oil and
                    Gas Reserves, Resources and
                    Operational Information"
                    contained in this news release.

    (4)             2015 and 2016 recycle ratios
                    have been restated to reflect
                    the exclusion of other income
                    in operating netbacks.

Table 7b


    Finding and Development
     Costs, including FDC
     (1)(2)(3)(4)                              2017   2016   2015

    Company Gross
    -------------

    Proved Producing

                             Change in FDC
                             ($ millions)            35.5   19.0   (53.5)

                             Reserve
                             Additions
                             (MMboe)                 61.9   43.6     66.0

                            F&D Costs ($/boe)       15.55  10.90     7.49

                            F&D Recycle Ratio         1.0    1.2      2.2

                             F&D Costs - Three-year
                             Average ($/boe)        11.27  12.76    15.19

                             F&D Recycle Ratio -
                             Three-year Average       1.4    1.6      1.7
                            --------------------      ---    ---      ---

    Total Proved

                             Change in FDC
                             ($ millions)           242.9  581.3  (535.6)

                             Reserve
                             Additions
                             (MMboe)                125.3   88.6     66.9

                            F&D Costs ($/boe)        9.34  11.71     0.19

                            F&D Recycle Ratio         1.7    1.1     87.4

                             F&D Costs - Three-year
                             Average ($/boe)         7.91  10.11    11.61

                             F&D Recycle Ratio -
                             Three-year Average       1.9    2.1      2.2
                            --------------------      ---    ---      ---

    Proved plus Probable

                             Change in FDC
                             ($ millions)           461.9  236.5  (770.3)

                             Reserve
                             Additions
                             (MMboe)                144.6  113.5     78.7

                            F&D Costs ($/boe)        9.61   6.10   (2.82)

                            F&D Recycle Ratio         1.7    2.2    (5.9)

                             F&D Costs - Three-year
                             Average ($/boe)         5.52   6.48     8.11

                             F&D Recycle Ratio -
                             Three-year Average       2.8    3.2      3.2
                            --------------------      ---    ---      ---


            (1)    F&D costs take into account
                    reserves revisions during the
                    year on a per boe basis.

            (2)    The aggregate of the exploration
                    and development costs incurred
                    in the financial year and the
                    changes during that year in
                    estimated future development
                    costs may not reflect the total
                    F&D costs related to reserves
                    additions for that year.

            (3)    "Finding and development recycle
                    ratio" or "F&D recycle ratio"
                    does not have a standardized
                    meaning. See "Information
                    Regarding Disclosure on Oil and
                    Gas Reserves, Resources and
                    Operational Information"
                    contained in this news release.

    (4)             2015 and 2016 recycle ratios
                    have been restated to reflect
                    the exclusion of other income
                    in operating netbacks.

Table 7c


    Finding, Development and
     Acquisition Costs, excluding
     FDC (1)(2)(3)(4)                              2017   2016    2015

    Company Gross
    -------------

    Proved Producing

                                  Reserve
                                   Additions,
                                   including
                                   Net
                                   Acquisitions
                                   (Dispositions)
                                   (MMboe)               61.9    34.0   53.4

                                  FD&A Costs ($/boe)    15.03  (2.25)  8.88

                                  FD&A Recycle Ratio      1.1   (6.0)   1.9

                                   FD&A Costs - Three-
                                   year Average ($/boe)  8.89   11.15  17.02

                                   FD&A Recycle Ratio -
                                   Three-year Average     1.7     1.9    1.5
                                  ---------------------   ---     ---    ---

    Total Proved

                                  Reserve
                                   Additions,
                                   including
                                   Net
                                   Acquisitions
                                   (Dispositions)
                                   (MMboe)              125.1    75.7   52.6

                                  FD&A Costs ($/boe)     7.43  (1.01)  9.00

                                  FD&A Recycle Ratio      2.1  (13.3)   1.8

                                   FD&A Costs - Three-
                                   year Average ($/boe)  5.24    8.13  15.98

                                   FD&A Recycle Ratio -
                                   Three-year Average     2.9     2.6    1.6
                                  ---------------------   ---     ---    ---

    Proved plus Probable

                                  Reserve
                                   Additions,
                                   including
                                   Net
                                   Acquisitions
                                   (Dispositions)
                                   (MMboe)              144.1    93.0   55.5

                                  FD&A Costs ($/boe)     6.45  (0.82)  8.54

                                  FD&A Recycle Ratio      2.5  (16.4)   1.9

                                   FD&A Costs - Three-
                                   year Average ($/boe)  4.54    6.31  11.88

                                   FD&A Recycle Ratio -
                                   Three-year Average     3.4     3.3    2.2
                                  ---------------------   ---     ---    ---


            (1)    FD&A costs take into account
                    reserves revisions during the
                    year on a per boe basis.

            (2)    The aggregate of the exploration
                    and development costs incurred
                    in the financial year and the
                    changes during that year in
                    estimated future development
                    costs may not reflect the total
                    F&D costs related to reserves
                    additions for that year.

            (3)    "Finding, development and
                    acquisition recycle ratio" or
                    "FD&A recycle ratio" does not
                    have a standardized meaning.
                    See "Information Regarding
                    Disclosure on Oil and Gas
                    Reserves, Resources and
                    Operational Information"
                    contained in this news release.

            (4)    2015 and 2016 recycle ratios
                    have been restated to reflect
                    the exclusion of other income
                    in operating netbacks.

Table 7d


    Finding, Development and
     Acquisition Costs, including
     FDC (1)(2)(3)(4)                              2017   2016    2015

    Company Gross
    -------------

    Proved Producing

                                   Change in FDC
                                   ($ millions)          35.5  (95.9)  (63.4)

                                  Reserve
                                   Additions,
                                   including
                                   Net
                                   Acquisitions
                                   (Dispositions)
                                   (MMboe)               61.9    34.0     53.4

                                  FD&A Costs ($/boe)    15.60  (5.07)    7.69

                                  FD&A Recycle Ratio      1.0   (2.7)     2.2

                                   FD&A Costs - Three-
                                   year Average ($/boe)  8.06   10.16    17.09

                                   FD&A Recycle Ratio -
                                   Three-year Average     1.9     2.1      1.5
                                  ---------------------   ---     ---      ---

    Total Proved

                                   Change in FDC
                                   ($ millions)         241.6   419.7  (589.5)

                                  Reserve
                                   Additions,
                                   including
                                   Net
                                   Acquisitions
                                   (Dispositions)
                                   (MMboe)              125.1    75.7     52.6

                                  FD&A Costs ($/boe)     9.37    4.53   (2.20)

                                  FD&A Recycle Ratio      1.7     3.0    (7.6)

                                   FD&A Costs - Three-
                                   year Average ($/boe)  5.52    7.56    12.69

                                   FD&A Recycle Ratio -
                                   Three-year Average     2.8     2.8      2.0
                                  ---------------------   ---     ---      ---

    Proved plus Probable

                                   Change in FDC
                                   ($ millions)         459.4    25.0  (906.2)

                                  Reserve
                                   Additions,
                                   including
                                   Net
                                   Acquisitions
                                   (Dispositions)
                                   (MMboe)              144.1    93.0     55.5

                                  FD&A Costs ($/boe)     9.64  (0.55)  (7.80)

                                  FD&A Recycle Ratio      1.7  (24.5)   (2.1)

                                   FD&A Costs - Three-
                                   year Average ($/boe)  3.09    3.91     8.58

                                   FD&A Recycle Ratio -
                                   Three-year Average     5.0     5.3      3.0
                                  ---------------------   ---     ---      ---


            (1)    FD&A costs take into account
                    reserves revisions during the
                    year on a per boe basis.

            (2)    The aggregate of the exploration
                    and development costs incurred
                    in the financial year and the
                    changes during that year in
                    estimated future development
                    costs may not reflect the total
                    F&D costs related to reserves
                    additions for that year.

            (3)    "Finding, development and
                    acquisition recycle ratio" or
                    "FD&A recycle ratio" does not
                    have a standardized meaning.
                    See "Information Regarding
                    Disclosure on Oil and Gas
                    Reserves, Resources and
                    Operational Information"
                    contained in this news release.

    (4)             2015 and 2016 recycle ratios
                    have been restated to reflect
                    the exclusion of other income
                    in operating netbacks.

NE BC MONTNEY RESOURCES EVALUATION

The following discussion in "NE BC Montney Resources Evaluation" is subject to a number of cautionary statements, assumptions and risks as set forth therein. See "Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information" at the end of this news release for additional cautionary language, explanations and discussion, and see "Forward-looking Information and Statements" for a statement of principal assumptions and risks that may apply. See also "Definitions of Oil and Gas Resources and Reserves" in this news release. The discussion includes reference to TPIIP, Discovered Petroleum Initially-in-Place ("DPIIP"), Undiscovered Petroleum Initially-in-Place ("UPIIP") and Economic Contingent Resource ("ECR") as per the GLJ Resources Evaluation as at December 31, 2017, prepared in accordance with the COGE Handbook. Unless otherwise indicated in this news release, all references to ECR and Prospective volumes are Best Estimate ECR and Best Estimate Prospective volumes, respectively.

The Montney formation in northeast British Columbia and Alberta has been identified as a world-class unconventional natural gas resource play with the potential for significant volumes of recoverable resources. The area includes dry gas, liquids-rich gas and tight oil development opportunities. It is one of the largest and lowest-cost natural gas resource plays in North America. ARC has a significant presence in northeast British Columbia and across the provincial border at Pouce Coupe, with a land position of 771 net sections, located primarily in the most prospective areas of the play.

GLJ was commissioned in 2017 and in 2016 to conduct independent resource evaluations for ARC's lands in the NE BC Montney region, including Dawson, Parkland/Tower, Sunrise/Sunset, Sundown, Septimus, Attachie, Red Creek and Blueberry in northeast British Columbia, and Pouce Coupe just across the provincial border in Alberta (the "Evaluated Areas"). The Independent Resources Evaluation was effective December 31, 2017 based on GLJ forecast pricing at January 1, 2018. The GLJ Independent Resources Evaluation conducted in respect of 2016 was effective December 31, 2016 based on GLJ forecast pricing at January 1, 2017 (the "2016 Resources Evaluation"). All references in the following discussion to TPIIP, DPIIP, UPIIP and ECR are in reference to the Evaluated Areas included in the 2017 Independent Resources Evaluation and 2016 Independent Resources Evaluation. The results of the 2017 and 2016 resources evaluations are summarized in the discussion and tables that follow.

The evaluation reaffirmed that ARC's NE BC Montney assets provide significant long-term growth opportunities with considerable resources, extending well beyond existing booked reserves and even the current estimates of ECR. ARC's NE BC Montney assets provide optionality for future growth through commodity price cycles given the diversity of ARC's Montney landholdings with exposure to liquids-rich natural gas, crude oil and dry natural gas. ARC believes that the concentrated nature of the assets will result in additional upside based on expected capital efficiencies.

ARC's 2017 capital development program was primarily focused on Montney development, which was inclusive of crude oil, liquids-rich gas and dry gas opportunities. In northeast British Columbia and Pouce Coupe, Alberta, ARC's capital development program consisted of drilling 87 gross operated wells (87 net wells), comprised of 29 tight oil wells at Tower, 37 wells at Dawson that were a combination of dry gas and liquids-rich wells, five dry gas wells at Sunrise, and 16 liquids-rich wells elsewhere in NE BC (nine in Attachie, six in Parkland, and one in Pouce Coupe).

TPIIP for the shale gas-bearing lands in the Evaluated Areas increased four per cent to 106.0 Tcf relative to 2016. DPIIP for the shale gas-bearing lands increased by nine per cent for the Evaluated Areas to 45.5 Tcf.

Shale gas ECR was evaluated on an unrisked and risked basis in 2017 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending shale gas ECR totaled 4.0 Tcf and risked development unclarified shale gas ECR totaled 3.1 Tcf. The risked prospective shale gas ECR totaled 6.4 Tcf.

NGLs ECR was evaluated on an unrisked and risked basis in 2017 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending NGLs ECR totaled 90 MMbbl and risked development unclarified NGLs ECR totaled 100 MMbbl. The risked prospective NGLs ECR totaled 475 MMbbl.

On the tight oil-bearing lands at Tower, Red Creek and Attachie, TPIIP remained consistent with 2016 at 10.5 MMbbl and DPIIP increased four per cent to 6.4 MMbbl.

Tight Oil ECR was evaluated on an unrisked and risked basis in 2017 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending tight oil ECR totaled 33 MMbbl and risked development unclarified tight oil ECR totaled 115 MMbbl. The risked prospective tight oil ECR totaled 76 MMbbl.

Risking of the economic contingent resources included a quantitative assessment of the economic status, the recovery technology status, the project evaluation scenario status, and the development time frame. Risking of the prospective resources included a quantitative assessment of these same factors, as wells as a quantitative assessment of the chance of discovery.

Table 8


    Shale Gas Resources (1)(2)(3)(4)   2017  2016

    (Tcf)
    ----

    Total Petroleum Initially-in-
     Place                            106.0 101.5

    Discovered Petroleum Initially-
     in-Place (5)                      45.5  41.8

    Undiscovered Petroleum Initially-
     in-Place (6)                      60.5  59.7
    ---------------------------------  ----  ----


            (1)    TPIIP, DPIIP and UPIIP have been
                    estimated using a one per cent
                    porosity cut-off in both 2017
                    and 2016, which means that
                    essentially all gas-bearing
                    rock has been incorporated into
                    the calculations.

            (2)    The resource categories in this
                    table do not include free crude
                    oil or liquids.

            (3)    All volumes listed in the table
                    are company gross and raw gas
                    volumes.

            (4)   All numbers are "Best Estimates".

            (5)    There is uncertainty that it will
                    be commercially viable to
                    produce any portion of the
                    resources.

            (6)    There is no certainty that any
                    portion of the resources will be
                    discovered. If discovered, there
                    is no certainty that it will be
                    commercially viable to produce
                    any portion of the resources.

Table 9


    Tight Oil Resources (1)(2)(3)(4)    2017   2016

    (MMbbl)
    ------

    Total Petroleum Initially-in-
     Place                            10,488 10,529

    Discovered Petroleum Initially-
     in-Place (5)                      6,427  6,180

    Undiscovered Petroleum Initially-
     in-Place (6)                      4,061  4,349
    ---------------------------------  -----  -----


    (1)             TPIIP, DPIIP and UPIIP have been
                    estimated using a one per cent
                    porosity cut-off in both 2017
                    and 2016 for tight oil.

            (2)    All volumes listed in the table
                    are company gross.

            (3)    The tight oil DPIIP is a Stock
                    Tank Barrel.

            (4)   All numbers are "Best Estimates".

            (5)    There is uncertainty that it will
                    be commercially viable to
                    produce any portion of the
                    resources.

            (6)    There is no certainty that any
                    portion of the resources will be
                    discovered. If discovered, there
                    is no certainty that it will be
                    commercially viable to produce
                    any portion of the resources.

Table 10


                                                                                                2017                            2016
                                                                                                ----                            ----

    Reserves and Risked and                                       Chance of     Best     Best   Chance of      Best       Best

    Unrisked ECR (1)(2)(3)(4)(5)(6)                             Development Estimate Estimate Development  Estimate   Estimate

                                                                            Unrisked   Risked              Unrisked     Risked
    ---                                                                     --------   ------              --------     ------

    Shale Gas (Tcf)

                                    Reserves                                    100%      3.5          3.5       100%        3.0        3.0


                                    Development Pending ECR                      86%      4.6          4.0        91%        2.9        2.6


                                    Development Unclarified ECR                  62%      4.2          3.1        74%        4.8        3.6

                                                                                                                                     ---

    NGLs (MMbbl)

                                    Reserves                                    100%     62.1         62.1       100%       61.9       61.9


                                    Development Pending ECR                      85%    105.9         90.4        91%       58.6       53.5


                                    Development Unclarified ECR                  66%    139.8        100.3        74%      286.7      212.5

                                                                                                                                     ---

    Tight Oil (MMbbl)

                                    Reserves                                    100%     31.2         31.2       100%       25.2       25.2


                                    Development Pending ECR                      92%     35.5         32.6        95%       42.0       39.9


                                    Development Unclarified ECR                  73%    156.9        114.5        69%      154.3      106.9

                                                                                                                                     ---


            (1)    All DPIIP, other than cumulative
                    production, reserves, and ECR, has
                    been categorized as unrecoverable.
                    Cumulative raw production to year-
                    end 2017 was 0.9 Tcf of shale gas
                    and 7.8 MMbbl of tight oil, all of
                    which are immaterial in relation to
                    the magnitude of the reserves and
                    ECR. NGLs cumulative production is
                    calculated based on current NGLs
                    recoveries.

            (2)    All volumes listed in the table are
                    company gross and sales volumes.

            (3)   All numbers are "Best Estimates".

            (4)    All ECR have been risked for chance
                    of development. For ECR, the chance
                    of development is defined as the
                    probability of a project being
                    commercially viable. In quantifying
                    the chance of development, factors
                    that were assessed quantitatively
                    to be less than one in the risking
                    calculation included the economic
                    status, the project evaluation
                    scenario status, and the
                    development time frame. The chance
                    of development is multiplied by the
                    unrisked resource volume estimate,
                    which yields the risked volume
                    estimate. As many of these factors
                    have a wide range of uncertainty
                    and are difficult to quantify, the
                    chance of development is an
                    uncertain value that should be used
                    with caution.

            (5)    For reserves, the volumes under the
                    heading "Best Estimate" are 2P
                    reserves.

            (6)    There is uncertainty that it will be
                    commercially viable to produce any
                    portion of the resources.

An estimate of risked NPV of future net revenues of the development pending contingent resources subclass only is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of ARC proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked NPV of future net revenue will be realized. The other subclasses of resources are not included in this NPV, and therefore, this is not reflective of the value of the resource base.

Table 1

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