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Tourmaline Adds 558 Mmboe of 2P Reserves, Grows Liquid Reserves by 73% and 2P Reserve Value by $2.4 Billion¹

CALGARY, Feb. 14, 2018 (Canada NewsWire via COMTEX) --

Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to report very strong total reserve growth, liquids reserve growth and a significant reserve value increase in the current declining natural gas price environment. The Company executed on the 2017 plan to concentrate almost entirely on internal EP growth and has produced the best reserve metrics in Company history. In addition, Q4 2017 cash flow((2)) of $348.2 million exceeded Q4 capital spending of $332.7 million (excluding acquisitions) as the Company transitioned to a free cash flow((3)) generation growth model.

HIGHLIGHTS

    --  Proved plus probable reserves ("2P") increased by 470 mmboe to
        2.22 billion boe during 2017, a 27% increase over 2016 year-end
        reserves of 1.75 billion boe (26% per diluted share) and a 32%
        increase of 558 mmboe which includes annual production of 88.4
        million boe. Total proved ("TP") reserves increased 33% to 1.1
        billion boe and proved, developed producing ("PDP") reserves of
        436.2 mmboe increased 49% over year-end 2016 when including
        2017 annual production.
    --  Total 2P liquid reserves (oil, condensate, NGLs) increased by
        73% in 2017 to 431.6 mmboe resulting in total liquids reserve
        additions of 187.4 mmboe including production of 14.1 mmboe.
        This strong liquid reserve growth underpins the Company's
        rapidly growing oil and liquids production.
    --  2017 2P reserve net present value of $15.1 billion increased by
        $2.4 billion over 2016 with an estimated 2P reserve net present
        value ("NPV")((4)) of $55.70 per diluted share, an 18% increase
        over 2016. Tourmaline's 2P reserves of 2.2 billion boe
        incorporates only 14% (2,077 locations (gross)) of a
        well-defined future drilling inventory of 14,922 locations
        (gross), all within reach of existing Company-owned
        infrastructure.
    --  After nine years of operation, Tourmaline has 2P natural gas
        reserves of 10.7 tcf and 2P liquid reserves of 431.6 mmboe of
        oil, condensate and liquids (December 31, 2017).
    --  Approximately 96% of the 2017 2P reserve additions were
        delivered organically by Tourmaline's internal EP program.
    --  Proved plus probable NPV of $55.70/diluted share, total proved
        NPV of $31.73/diluted share and a PDP NPV of $16.94/diluted
        share at December 31, 2017.
    --  Proved plus probable finding, development and acquisition costs
        ("FD&A") in 2017 of $3.76/boe including changes in future
        development capital ("FDC") ($2.55/boe excluding change in
        FDC); total proved FD&A in 2017 of $6.79/boe including change
        in FDC ($4.98/boe excluding change in FDC). 2017 PDP FD&A of
        $8.23/boe was down 44% from 2016 PDP FD&A of $14.69/boe, as the
        Company focused on developing its massive existing drilling
        inventories in 2017.
    --  The record low finding and development costs in 2017 are a
        direct result of the Company's focus on continuing to reduce
        drill and complete capital costs. Tourmaline has the lowest
        capital costs of industry in all the core operated complexes
        (Alberta Deep Basin, NEBC Montney and Peace River High Triassic
        oil).
    --  The 2017 2P recycle ratio was 3.6 based on 2P FD&A of $3.76/boe
        (including FDC), and 2017 estimated cash flow of $13.63/boe.
        The 2017 TP recycle ratio was 2.0 and the 2017 PDP recycle
        ratio was 1.7, all records for the Company.
    --  2P reserve replacement ratio((5)) of 6.3 times based on 2P
        reserve additions of 558 mmboe before 2017 production of 88.4
        mboe.
    --  Tourmaline systematically converts TP and 2P reserves to PDP
        reserves; 167 wells (gross) of the 305 wells (gross) rig
        released in 2017 converted pre-existing TP/2P reserves to PDP
        reserves. The future development capital (FDC) in the 2017 2P
        reserve category represents approximately 4.5 years of
        future-projected Company cash flow.
    --  The 2P reserves were up 32% in 2017 while the corresponding
        increase in 2P FDC was 11%.
    --  Full-year 2017 average production of 242,326 boepd was 31%
        higher than 2016 production of 185,672 boepd and within
        original guidance.
    --  Q4 2017 average production of 263,308 boepd was 11% higher than
        Q3 2017 production and generated free cash flow of $15.5
        million.
    --  Q4 2017 liquids production (oil, condensate, NGL) was 62%
        higher than Q4 2016 liquids production. Tourmaline is
        forecasting 2018 average liquids production of 50,000 bpd, and
        anticipating a further 50% growth to 70,000-75,000 bpd by Q4
        2019, ahead of the current 2019 forecast.
    --  In 2017, Tourmaline's EP capital program of $1.3 billion
        generated approximately 140 mboepd of new production resulting
        in a 2017 capital efficiency of $9,500/boepd.
    --  Q4 2017 cash flow was $348.2 million and Q4 capital spending
        was $332.7 million, excluding acquisitions. The Company
        completed an acquisition of primarily undeveloped land in the
        Peace River High Triassic oil complex for $20.1 million during
        the quarter, expanding both the Lower Montney oil and Charlie
        Lake play coverage. As previously disclosed, net debt((6)) at
        Q4 2017 will be reduced from Q3 2017 net debt and the Company
        is now expecting Q1 2018 capital spending of less than $300.0
        million with production guidance remaining unchanged.


    _________________

    (1)              2P reserves discounted at 10%.

    (2)               Cash flow is defined as cash provided
                      by operations before changes in non-
                      cash operating working capital.  See
                      "Non-GAAP Financial Measures" in
                      this release for additional
                      information.  All financial
                      information is unaudited.  See
                      unaudited financial information
                      section in this release.

    (3)               Free cash flow is defined as cash
                       flow less capital spending which
                       excludes acquisitions and
                       divestitures, but includes other
                       corporate expenditures.

    (4)               Reserve NPV per share is calculated
                      as the before tax net present value
                      of the reserves at December 31, 2017
                      discounted at 10% divided by total
                      diluted shares outstanding at
                      December 31, 2017.

    (5)               Reserve replacement ratio is
                      calculated by dividing the annual
                      2P reserve additions (including
                      annual production) by annual
                      production.

    (6)               "Net debt" is defined as long-term
                      debt plus working capital (adjusted
                      for the fair value of financial
                      instruments).  See "Non-GAAP
                      Financial Measures" in this release
                      for additional information.  All
                      financial information is unaudited.
                      See unaudited financial information
                      section in this release.

2017 RESERVE SUMMARY

The following tables summarize the Company's gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.

Reserves and Future Net Revenue Data (Forecast Prices and Costs)

                                                                      Summary of Oil and Gas Reserves and

                                                                    Net Present Values of Future Net Revenue

                                                                            as of December 31, 2017

                                                                         Forecast Prices and Costs(1)


                                        Light & Medium Crude Oil      Conventional Natural Gas               Shale Natural Gas(2)      Natural Gas Liquids        Total Oil Equivalent
                                        ------------------------      ------------------------               -------------------       -------------------        --------------------


    Reserves Category                             Company                     Company                              Company                   Company                    Company               Company           Company         Company         Company           Company
                                                   Gross                        Net                                 Gross                      Net                                                               Gross            Net
                                                  (Mbbls)                     (Mbbls)                               (MMcf)                    (MMcf)                     Gross                  Net             (Mbbls)         (Mbbls)          Gross              Net
                                                                                                                                                                         (MMcf)                (MMcf)
                                                                                                                                                                                                                                                 (Mboe)            (Mboe)

    Proved Producing                                          9,823                        8,179                             1,544,673                  1,419,852                     662,309           627,141          58,555          49,262           436,208           398,607

    Proved Developed Non-Producing                            1,449                        1,225                                65,134                     59,725                     134,419           126,530          10,666           9,484            45,374            41,752

    Proved Undeveloped                                       20,692                       17,432                             1,790,816                  1,667,190                   1,028,389           948,523          83,560          74,817           574,119           528,201
                                                             ------                       ------                             ---------                  ---------                   ---------           -------          ------          ------           -------           -------

    Total Proved Reserves                                    31,964                       26,837                             3,400,624                  3,146,767                   1,825,118         1,702,194         152,781         133,563         1,055,702           968,560

    Total Probable Reserves                                  33,325                       27,471                             2,232,988                  2,026,272                   3,248,846         2,796,081         213,540         181,516         1,160,504         1,012,713
                                                             ------                       ------                             ---------                  ---------                   ---------         ---------         -------         -------         ---------         ---------

    Total Proved Plus Probable Reserves                      65,288                       54,308                             5,633,612                  5,173,040                   5,073,964         4,498,275         366,321         315,079         2,216,206         1,981,273
                                                             ======                       ======                             =========                  =========                   =========         =========         =======         =======         =========         =========

                                     Reserves Category                                                              Net Present Values Of Future Net Revenue ($000s)
                                     -----------------                                                               -----------------------------------------------

                                                                  Before Future Income Taxes Discounted at                                                                                                 Unit Value Before
                                                                                  (%/year)                                                                                                                     Income Tax
                                                                      After Future Income Taxes Discounted at (3)                                  Discounted
                                                                                       (%/year)                                                   at 10%/year


                                                         0                     5                       10                       15                       20                0              5             10                    15            20             ($/Boe)         ($/Mcfe)
                                                       ---                   ---                      ---                      ---                      ---              ---            ---            ---                   ---           ---           -------        --------

    Proved Producing                                        6,575,489                5,482,849                4,593,448                3,953,746               3,485,149      6,558,865      5,475,763      4,590,302            3,952,296     3,484,457          11.52         1.92

    Proved Developed Non-Producing                            789,218                  593,292                  473,409                  393,997                 337,946        585,431        482,896        411,239              357,764       316,176          11.34         1.89

    Proved Undeveloped                                      7,994,642                5,154,248                3,535,606                2,531,581               1,866,331      5,913,565      3,770,425      2,551,805            1,798,229     1,300,426           6.69         1.12
                                                            ---------                ---------                ---------                ---------               ---------      ---------      ---------      ---------            ---------     ---------           ----         ----

    Total Proved Reserves                                  15,359,349               11,230,388                8,602,464                6,879,324               5,689,426     13,057,861      9,729,084      7,553,346            6,108,289     5,101,059           8.88         1.48

    Total Probable Reserves                                21,218,590               10,873,051                6,498,239                4,294,592               3,040,227     15,710,014      7,953,788      4,692,519            3,061,346     2,140,753           6.42         1.07
                                                           ----------               ----------                ---------                ---------               ---------     ----------      ---------      ---------            ---------     ---------           ----         ----

    Total Proved Plus Probable Reserves                    36,577,939               22,103,440               15,100,702               11,173,916               8,729,653     28,767,875     17,682,872     12,245,865            9,169,635     7,241,812           7.62         1.27
                                                           ==========               ==========               ==========               ==========               =========     ==========     ==========     ==========            =========     =========           ====         ====


    Notes:


    (1)                     Tables may not add due to rounding.

    (2)                      Shale Natural Gas is required to be
                             presented separately from
                             Conventional Natural Gas as its own
                             product type pursuant to National
                             Instrument 51-101 - Standards of
                             Disclosure for Oil and Gas Activities
                             ("NI 51-101").  While the Tourmaline
                             Montney reserves do not strictly fit
                             the definition of "shale gas" as
                             defined in NI 51-101 because the
                             natural gas is not "primarily
                             adsorbed" as stated within the
                             definition, the Montney reserves have
                             been included as shale gas for
                             purposes of this disclosure.

    (3)                      The after-tax net present value of
                             the Company's oil and gas properties
                             reflects the tax burden on the
                             properties on a stand-alone basis.
                             It does not consider the corporate
                             tax situation, or tax planning.  It
                             does not provide an estimate of the
                             value at the Company level which may
                             be significantly different.  The
                             Company's financial statements and
                             management's discussion and analysis
                             should be consulted for information
                             at the Company level.

                                                              Total Future Net Revenue ($000s)

                                                                       (Undiscounted)

                                                                   as of December 31, 2017

                                                                Forecast Prices and Costs(1)





    Reserves Category  Revenue            Royalties                 Operating                    Capital             Abandonment          Future Net             Income           Future Net
                                                                      Costs                    Development               and               Revenue               Taxes             Revenue
                                                                                                  Costs              Reclamation            Before                                  After
                                                                                                                        Costs            Income Taxes                               Income
                                                                                                                                                                                   Taxes(2)
    ---                                                                                                                                                                            -------

    Proved Producing           11,481,179             981,801                   3,707,283                        138             216,468               6,575,489           16,624             6,558,865

    Proved Developed
     Non-Producing              1,262,332             117,558                     284,521                     56,520              14,515                 789,218          203,787               585,431

    Proved Undeveloped         16,056,744           1,378,192                   3,093,629                  3,446,939             143,341               7,994,642        2,081,076             5,913,565
                               ----------           ---------                   ---------                  ---------             -------               ---------        ---------             ---------

    Total Proved               28,800,255           2,477,551                   7,085,433                  3,503,597             374,325              15,359,349        2,301,488            13,057,861

    Total Probable             38,848,000           5,214,941                   8,548,346                  3,591,679             274,444              21,218,590        5,508,576            15,710,014
                               ----------           ---------                   ---------                  ---------             -------              ----------        ---------            ----------

    Total Proved Plus
     Probable                  67,648,255           7,692,492                  15,633,779                  7,095,275             648,769              36,577,939        7,810,064            28,767,875
                               ==========           =========                  ==========                  =========             =======              ==========        =========            ==========


    Note:


    (1)                   Table may not add due to rounding.

    (2)                    The after-tax net present value of
                           the Company's oil and gas properties
                           reflects the tax burden on the
                           properties on a stand-alone basis.
                           It does not consider the corporate
                           tax situation, or tax planning.  It
                           does not provide an estimate of the
                           value at the Company level which may
                           be significantly different.  The
                           Company's financial statements and
                           management's discussion and analysis
                           should be consulted for information
                           at the Company level.

                                                                                Summary of Pricing and Inflation Rate Assumptions

                                                                                          Forecast Prices and Costs (1)


    Year                       Inflation(2)                                                    Crude Oil and Natural Gas Liquids Pricing

                                    %
    ---                            ---


                          NYMEX WTI Near Month                    Light, Sweet Crude                                                   Alberta Natural Gas Liquids
                           Futures Contract Crude Oil
                                  at                          Oil (40 API, 0.3%S) at                                                   (Then Current Dollars)
                          Cushing Oklahoma
                                                                     Edmonton
                                                                   Then Current
                                                                                         $Cdn/Bbl
                                                                                         --------

         CAD/USD           Constant                  Then       Spec                    Edmonton                    Edmonton                    Edmonton
         Exchange             2018 $                Current     Ethane                   Propane                      Butane                    C5+ Stream
           Rate              $US/Bbl                    $US/   $Cdn/Bbl                  $Cdn/Bbl                         $Cdn/Bbl               Quality
              $US/$Cdn(3)                            Bbl                                                                                         $Cdn/Bbl
              -----------                            ---                                                                                         --------

    2018                         0.7                   0.7900       57.50                      57.50                             68.60                    7.61            35.69         51.29          72.41

    2019                         2.0                   0.8000       59.71                      60.90                             72.02                    8.79            35.82         52.29          74.90

    2020                         2.0                   0.8167       61.64                      64.13                             74.48                   10.21            34.85         53.92          77.07

    2021                         2.0                   0.8283       64.39                      68.33                             78.60                   11.22            36.07         56.70          81.07

    2022                         2.0                   0.8400       65.77                      71.19                             80.84                   11.90            35.89         58.32          83.32

    2023                         2.0                   0.8433       66.25                      73.15                             82.83                   12.18            36.28         59.72          85.35

    2024                         2.0                   0.8433       66.74                      75.16                             85.17                   12.42            37.39         61.42          87.75

    2025                         2.0                   0.8433       67.18                      77.17                             87.53                   12.67            38.50         63.08          90.13

    2026                         2.0                   0.8433       67.43                      79.01                             89.66                   12.98            39.52         64.60          92.32

    2027                         2.0                   0.8433       67.44                      80.60                             91.49                   13.23            40.37         65.95          94.21

    2028                         2.0                   0.8433       67.43                  +2.0%/yr                     +2.0/yr                    +2.0%/yr        +2.0%/yr     +2.0%/yr      +2.0%/yr

                                                                    Natural Gas and Sulphur Pricing
                                                                    -------------------------------

                Henry Hub Nymex   Midwest Price @                             Alberta Plant Gate                                              British Columbia
              Near Month Contract
                                                   AECO/NIT Spot
                                                   Then Current
                                                            $Cdn/
                                                       MMbtu
                                                       -----

                                  Spot
                                  ----

         Year   Constant 2018 $         Then          Chicago                                      Constant           Then Current $Cdn/MMbtu                    ARP $Cdn/           Sumas Spot           Westcoast Station 2           Spot Plant Gate
                             $US/      Current     Then Current                                      2018 $                                                         MMbtu                   $US/                    $Cdn/MMbtu                $Cdn/MMbtu
                      MMbtu             $US/MMbtu            $US/                                     $Cdn/                                                                             MMbtu
                                                       MMbtu                                        MMbtu
    ---                                                -----                                        -----

    2018                     3.03             3.03             2.93                            2.43                2.19                                        2.19                 2.19                  2.66                           1.88                     1.69

    2019                     3.12             3.18             3.08                            2.77                2.47                                        2.52                 2.52                  2.75                           2.33                     2.14

    2020                     3.36             3.50             3.40                            3.19                2.84                                        2.95                 2.95                  3.09                           2.81                     2.62

    2021                     3.50             3.71             3.61                            3.48                3.04                                        3.23                 3.23                  3.32                           3.16                     2.97

    2022                     3.59             3.89             3.79                            3.67                3.16                                        3.42                 3.42                  3.51                           3.35                     3.16

    2023                     3.60             3.98             3.88                            3.76                3.18                                        3.51                 3.51                  3.61                           3.44                     3.25

    2024                     3.61             4.07             3.97                            3.85                3.18                                        3.58                 3.58                  3.70                           3.50                     3.31

    2025                     3.61             4.15             4.05                            3.93                3.18                                        3.66                 3.66                  3.77                           3.58                     3.38

    2026                     3.61             4.23             4.13                            4.02                3.20                                        3.75                 3.75                  3.86                           3.67                     3.48

    2027                     3.61             4.31             4.21                            4.10                3.20                                        3.83                 3.83                  3.93                           3.75                     3.55

    2028                     3.61      +2.0%/yr       +2.0%/yr                       +2.0%/yr               +2.0/yr                                 +2.0%/yr               +2.0%/yr              +2.0%/yr                      +2.0%/yr                  +2.0%/yr

    Notes:


    (1)                      Crude oil and natural gas benchmark reference
                             pricing, inflation and exchange rates
                             utilized by GLJ in the GLJ Reserve Report and
                             Deloitte in the Deloitte Reserve Report, were
                             an average of forecast prices and costs
                             published by GLJ, Sproule Associates Ltd. and
                             McDaniel & Associates Consultants Ltd.
                             effective January 1, 2018 (each of which is
                             available on their respective websites at
                             www.gljpc.com, www.sproule.com and
                             www.mcdan.com).

    (2)                      Inflation rates used for forecasting prices
                             and costs.

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

RESERVES PERFORMANCE RATIOS

The following tables highlight Tourmaline's reserves, F&D and FD&A costs as well as the associated recycle ratios.

Reserves, Capital Expenditures((2)) and Cash Flow((1)(2))

    As at December 31,                     2017      2016      2015
    ------------------                     ----      ----      ----

    Reserves (Mboe)

    Proved Producing                    436,208   351,931   263,227

    Total Proved                      1,055,702   858,932   644,059

    Proved Plus Probable              2,216,206 1,746,822 1,108,279

    Capital Expenditures ($ millions)

    Exploration and Development(3)        1,364       756     1,451

    Net Acquisitions (Dispositions)          58     1,545       451
                                            ---     -----       ---

    Total Capital Expenditures            1,422     2,301     1,902

    Cash Flow ($/boe)

    Cash Flow                             13.63     10.77     15.09

    Cash Flow - Three Year Average        13.11     15.17     18.47
    ------------------------------        -----     -----     -----


    Notes:

    (1)                      Cash flow is defined as cash provided
                             by operations before changes in non-
                             cash operating working capital. See
                             "Non-GAAP Financial Measures" below
                             and in the Company's most recently
                             filed Management's Discussion and
                             Analysis for further discussion.

    (2)                     2017 Financial numbers are unaudited.

    (3)                      Includes unaudited capitalized G&A of
                             $27 million, $25 million and $26
                             million for 2017, 2016 and 2015
                             respectively.

Finding and Development Costs

    Finding and Development Costs, Excluding FDC  2017    2016     2015 2015-2017
                                                                          Avg.
    ---                                                                   ----

    Total Proved

    Reserve Additions (MMboe)                    272.8   126.4    187.1

    F&D Costs ($/boe)                             5.00    5.98     7.76      6.09

    F&D Recycle Ratio(1)                           2.7     1.8      1.9       2.2

    Total Proved Plus Probable

    Reserve Additions (MMboe)                    537.5   158.7    260.2

    F&D Costs ($/boe)                             2.54    4.76     5.58      3.73

    F&D Recycle Ratio(1)                           5.4     2.3      2.7       3.5
    -------------------                            ---     ---      ---       ---


    Finding and Development Costs, Including FDC  2017    2016     2015 2015-2017
                                                                          Avg.
    ---                                                                   ----

    Total Proved

    Change in FDC ($ millions)                   481.1 (239.9)  (42.7)

    Reserve Additions (MMboe)                    272.8   126.4    187.1

    F&D Costs ($/boe)                             6.76    4.08     7.53      6.43

    F&D Recycle Ratio(1)                           2.0     2.6      2.0       2.0

    Total Proved Plus Probable

    Change in FDC ($ millions)                   612.1 (518.6) (190.5)

    Reserve Additions (MMboe)                    537.5   158.7    260.2

    F&D Costs ($/boe)                             3.68    1.49     4.84      3.63

    F&D Recycle Ratio(1)                           3.7     7.2      3.1       3.6
    -------------------                            ---     ---      ---       ---

Finding, Development and Acquisition Costs

    Finding, Development and Acquisition Costs,  2017    2016   2015 2015-2017
    Excluding FDC                                                      Avg.
    -------------                                                      ----

    Total Proved

    Reserve Additions (MMboe)                   285.2   282.8  228.1

    FD&A Costs ($/boe)                           4.98    8.14   8.34      7.06

    FD&A Recycle Ratio(1)                         2.7     1.3    1.8       1.9

    Total Proved Plus Probable

    Reserve Additions (MMboe)                   557.8   706.5  308.8

    FD&A Costs ($/boe)                           2.55    3.26   6.16      3.58

    FD&A Recycle Ratio(1)                         5.3     3.3    2.5       3.7
    --------------------                          ---     ---    ---       ---


    Finding, Development and Acquisition Costs,  2017    2016   2015 2015-2017
    Including FDC                                                      Avg.
    -------------                                                      ----

    Total Proved

    Change in FDC ($ millions)                  515.7   304.0   21.7

    Reserve Additions (MMboe)                   285.2   282.8  228.1

    FD&A Costs ($/boe)                           6.79    9.21   8.43      8.12

    FD&A Recycle Ratio(1)                         2.0     1.2    1.8       1.6

    Total Proved Plus Probable

    Change in FDC ($ millions)                  678.3 1,894.0 (84.1)

    Reserve Additions (MMboe)                   557.8   706.5  308.8

    FD&A Costs ($/boe)                           3.76    5.94   5.89      5.16

    FD&A Recycle Ratio(1)                         3.6     1.8    2.6       2.5
    --------------------                          ---     ---    ---       ---


    Note:

    (1)                    The recycle ratio is calculated
                            by dividing the cash flow per
                            boe by the appropriate F&D or
                            FD&A costs related to the
                            reserve additions for that
                            year.

INVESTOR RELATIONS ACTIVITIES

Tourmaline is scheduled to press release full-year 2017 financial results after the close of markets on March 6, 2018.

Reader Advisories

CURRENCY

All amounts in this news release are stated in Canadian dollars unless otherwise specified.

RESERVES DATA

The reserves data set forth above is based upon the reports of GLJ Petroleum Consultants Ltd. ("GLJ") and Deloitte LLP, each dated effective December 31, 2017, which have been consolidated into one report by GLJ and adjusted to apply certain of GLJ's assumptions and methodologies and pricing and cost assumptions. The consolidated report includes 100% of the reserves and future net revenue attributable to the properties of Exshaw Oil Corp., a subsidiary of the Company, without reduction to reflect the 9.4% third-party minority interest in Exshaw. The price forecast used in the reserve evaluations is an average of the January 1, 2018 price forecasts for GLJ, Sproule Associates Ltd. and McDaniel & Associates Consultants Ltd., each of which is available on their respective websites, www.gljpc.com, www.sproule.com and www.mcdan.com, and will be contained in the Company's Annual Information Form for the year ended December 31, 2017, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2018.

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

All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company's oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company's tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company's financial statements and the management's discussion and analysis should be consulted for information at the level of the Company.

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 effects of aggregations. The estimated values of future net revenue disclosed in this news release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.

The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2017, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2018.

UNAUDITED FINANCIAL INFORMATION

Certain financial and operating results included in this news release such as FD&A costs, F&D costs, recycle ratio, cash flow, capital expenditures, operating costs and production information are based on unaudited estimated results. These estimated results are subject to change upon completion of the audited financial statements for the year ended December 31, 2017, and changes could be material. Tourmaline anticipates filing its audited financial statements and related management's discussion and analysis for the year ended December 31, 2017 on SEDAR on March 6, 2018.

Per share information is based on the total common shares outstanding, after accounting for outstanding Company options, at year-end 2017 and 2016, respectively.

BOE EQUIVALENCY

In this news release, production and reserves information may be presented on a "barrel of oil equivalent" or "BOE" basis. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

INDUSTRY METRICS

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are "reserve replacement", "F&D" costs, "FD&A" costs, "recycle ratio", "F&D recycle ratio", "FD&A recycle ratio", "NPV per share" and "capital efficiency". These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time, however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods.

"F&D" costs are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.

"FD&A costs" are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.

The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

FINANCIAL OUTLOOK

Also included in this news release is an estimate of the number of years of the Company's currently estimated cash flow that the future development capital in the 2017 2P reserve category represents, which estimate is based on, among other things, various assumptions as to production levels, capital expenditures, and other assumptions including average production levels of 270,000 boed for 2018 increasing to 355,000 boed by 2022 with price assumptions for natural gas (AECO - $2.50/mcf) and crude oil (WTI (US) - $52/bbl), an exchange rate assumption of $0.80 (US/CAD) and costs inflated at 2.5% annually after 2018. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on February 14, 2018 and is included to provide readers with an understanding of Tourmaline's anticipated ability to fund its future development capital out of cash flow based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes. In particular readers are cautioned that estimates for 2019 and beyond are provided for illustration only as budgets and forecasts beyond 2018 have not been finalized and are subject to a variety of factors including prior year's results.

FORWARD-LOOKING INFORMATION

This news release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this news release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including anticipated petroleum and natural gas production for various periods, drilling inventory or locations, cash flow and debt to cash flow levels, capital spending, projected operating and drilling costs, the timing for facility expansions and facility start-up dates, as well as Tourmaline's future drilling prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; and ability to market crude oil, natural gas and NGL successfully.

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

Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.

Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein), Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline's website (www.tourmalineoil.com).

The forward-looking information contained in this news release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.

ADDITIONAL READER ADVISORIES

Non-GAAP Financial Measures

This news release includes references to "cash flow" and "net debt" which are financial measures commonly used in the oil and gas industry and do not have a standardized meaning prescribed by International Financial Reporting Standards ("GAAP"). Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the term "cash flow" and "net debt" for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. Investors are cautioned that this non-GAAP measure should not be construed as an alternative to net income or cash from operating activities determined in accordance with GAAP as an indication of the Company's performance. See "Non-GAAP Financial Measures" in the November 8, 2017 Management's Discussion and Analysis for the definition and description of these terms.

Estimated Drilling Inventory

This news release discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 14,922 (gross) locations disclosed in this news release, 1,056 are proved undeveloped locations, 21 are proved non-producing locations, 1,000 are probable undeveloped locations, nil are probable non-producing and 12,845 are unbooked. Proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by GLJ and Deloitte LLP as of December 31, 2017 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

    CERTAIN DEFINITIONS:


    bbl                  barrel

    bbls/day             barrels per day

    bbl/mmcf             barrels per million cubic feet

    bcf                  billion cubic feet

    bcfe                 billion cubic feet equivalent

    bpd or bbl/d         barrels per day

    boe                  barrel of oil equivalent

    boepd or boe/d       barrel of oil equivalent per day

    bopd or bbl/d         barrel of oil, condensate or
                          liquids per day

    DUC                  drilled but uncompleted wells

    EUR                  estimated ultimate recovery

    FCP                  final circulating pressure

    gj                   gigajoule

    gjs/d                gigajoules per day

    mbbls                thousand barrels

    mmbbls               million barrels

    mboe                  thousand barrels of oil
                          equivalent

    mcf                  thousand cubic feet

    mcfpd or mcf/d       thousand cubic feet per day

    mcfe                 thousand cubic feet equivalent

    mmboe                 million barrels of oil
                          equivalent

    mmbtu                million British thermal units

    mmbtu/d               million British thermal units
                          per day

    mmcf                 million cubic feet

    mmcfpd or mmcf/d     million cubic feet per day

    MPa                  megapascal

    NGL or NGLs          natural gas liquids

    tcf                  trillion cubic feet

ABOUT TOURMALINE OIL CORP.

Tourmaline is a Canadian senior crude oil and natural gas exploration and production company focused on long-term growth through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin.

SOURCE Tourmaline Oil Corp.

View original content: http://www.newswire.ca/en/releases/archive/February2018/14/c8895.html

SOURCE: Tourmaline Oil Corp.

Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer,
(403) 266-5992; Tourmaline Oil Corp., Brian Robinson, Vice President, Finance and
Chief Financial Officer, (403) 767-3587; robinson@tourmalineoil.com; Tourmaline Oil
Corp., Scott Kirker, Secretary and General Counsel, (403) 767-3593;
kirker@tourmalineoil.com; Tourmaline Oil Corp., Suite 3700, 250 - 6th Avenue S.W.,
Calgary, Alberta  T2P 3H7, Phone:  (403) 266-5992, Facsimile:  (403) 266-5952,
Website:  www.tourmalineoil.com, E-mail:  info@tourmalineoil.com

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