Calgary, Alberta – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to announce three new extensive exploration and production (“EP”) opportunities within its existing core complexes and provide an update on its EP activities.



Liquid-rich Viking at Brazeau River
Tourmaline has been delineating a new extensive liquid-rich opportunity in the Brazeau River area at the south end of the Company’s Deep Basin complex. The Company has brought on production eight liquid-rich Viking horizontals over the past two years. The average initial production (“IP”) 30-day rate of these wells is 11.7 mmcfpd of natural gas, the average IP 365 day rate is 4.8 mmcfpd of natural gas, with average liquids production of 27.5 bbls/mmcf and drill and complete costs averaging $4.3 million. The type curve based on these eight producing wells indicates an internally estimated ultimate recovery (“EUR”) of 5.1 bcf of sales gas and 146.5 mboe of condensate and NGL yielding an implied value of $10.5 million per well (net present value, discounted at 10%, before tax). The Company has a defined future inventory of approximately 60 additional horizontals, all of which can access Company operated infrastructure.

Liquid-rich Cardium at Hinton-Anderson-Lambert
Tourmaline’s initial horizontal well into an extensive, liquid-rich, Cardium complex at Hinton-Anderson-Lambert has produced 1.6 bcf and 48,000 bbls of liquid (95% C5+) over the first 100 days of production, with the well being production constrained as it is only producing up tubing. Initial internal EURs are in excess of 10 bcf and 300 mboe of liquids for the 16-25-50-23W5M well, drill and complete costs were $3.5 million (1,500 m lateral, 30 stage completion). The Company plans 4-5 follow-up and delineation wells prior to year-end to further evaluate this potentially large gas/condensate complex, with a very large associated drilling inventory.

Peace River High Montney Oil
Tourmaline’s most recent Lower Montney horizontal at Valhalla is currently producing at 1,540 boepd, 1,107 bpd of oil and 2.6 mmcfpd of natural gas after five days of production. Multiple follow-up wells are planned over the next few months with all of the incremental oil able to access Tourmaline’s oil and gas processing facilities at Spirit River. The Company has a substantial inventory of Lower Montney horizontals on existing lands which will be further defined with the upcoming drilling program. The Lower Montney opportunity complements the new extensive Lower Charlie Lake development announced earlier this month (15 new wells on production, 284 future Lower Charlie Lake locations in inventory).



Full-year 2017 annual EP capital spending of $1.33 billion remains unchanged and will generate approximately 30% production growth in 2017 and is anticipated to be funded with available cash flow. The Company plans to operate 18 rigs in 2H 2017, with an estimated 175 new wells completed and brought on production by year end. Q2 2017 production has averaged 240,000-245,000 boepd to date which is already within the full year average production guidance of 240,000-260,000 boepd. The Company will provide full Q2 production guidance after the magnitude of the third party firm transportation restrictions, currently planned for June, are better quantified.



  • The Company’s Spirit River 3-10 sour gas injection plant has been expanded from 30 to 60 mmcfpd during the second quarter. This will facilitate accelerated development of the new Lower Charlie Lake and Lower Montney oil developments along with the ongoing Upper Charlie Lake program.
  • Enhanced stimulation of the Lower Montney turbidite at Dawson-Sunrise is yielding strong initial results. The Sunrise D9-10 well, completed with 38 stages (vs 28 stages historically), is testing 5.9 mmcfpd of natural gas with 621 bbls/day of condensate at the wellhead after 20 days of production. Total liquid production from the
    well, including plant liquid recoveries, is 1,250 bpd gross (210 bbls/mmcfpd). Completed well cost was $2.9 million.
  • The Company has now drilled five Triassic Montney horizontals on the first 9 well pad at Gundy Ck in NEBC. To date drilling costs have been reduced from the $3.1 million (as contained in the existing year-end independent reserve report for the previous operator) to $1.6 million per well (average lateral length of 1,715 m).



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

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, the net present value of future net reserves related to certain of the Company’s wells, capital spending, cost reduction initiatives, 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 and future 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.

Information relating to “reserves” is also deemed to be forward looking information, as it involves 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 ( or Tourmaline’s website ( 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.

Any references in this news release to IP rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.

This news release contains an estimate of the net present value of future net revenue from the estimated reserves associated with certain of the Company’s wells. Such net present value has been calculated based on the Q2 2017 GLJ pricing assumptions and total drill, complete and tie-in costs of $4.6 million per well, and is based on the Company’s internal evaluation of reserves prepared by a qualified reserves evaluator in accordance NI‐51‐101 and the COGE Handbook. Such estimates of future net revenue are after the deduction of royalties, development costs, production costs and well abandonment costs but before deduction of future income tax expenses and before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue does not represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions upon which such estimates are made will be attained and variances could be material. The reserve estimates of the Company’s crude oil, NGL and natural gas reserves and any estimated recovery factors provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves and related net present values may be greater than or less than the estimates provided herein.

In this news release, production and reserves information may be presented on a “barrel of oil equivalent” or “boe” basis. Boe’s 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.

The type curve information included in this news release, including IP 30, represents estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. This information is based on internally generated type curves based on a combination of historical performance of older wells and management’s expectation of what might be achieved from future wells. The information represents what management thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. There is no certainty that future wells will generate results to match historic type curves presented herein.

The term EUR, while commonly used in the oil and gas industry, does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. This metric has been included to provide readers with an additional measure to evaluate the Company’s performance; however, such measure is not a reliable indicator of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore this metric should not be unduly relied upon. EUR is calculated as estimated ultimate recovery of oil from a typical well in the area. EUR was determined internally by the Company by a non-independent qualified reserves evaluator incorporating current well results and historical well performance from the Company’s analogous pools in the nearby area.

This news release discloses drilling locations based on 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 Company’s 344 undrilled locations which are disclosed herein, 29 are proved undeveloped locations, nil are proved non-producing locations, 19 are probable undeveloped locations, nil are probable non-producing and 296 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 Petroleum Consultants Ltd. and Deloitte LLP as of December 31, 2016 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 natural 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 certain 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 natural gas reserves, resources or production.


  • 2P – proved plus probable
  • 3D – three dimensional
  • 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
  • EP – exploration and production
  • 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
  • mstboe – thousand stock tank barrels of oil equivalent
  • NGL or NGLs – natural gas liquids
  • NPV 10 – before tax – net present value at December 31, 2017 discounted at 10% – before tax
  • PDP – proved developed producing
  • tcf – trillion cubic feet
  • TCPL – TransCanada Pipelines



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


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;


Tourmaline Oil Corp.
Scott Kirker
Secretary and General Counsel
(403) 767-3593;


Tourmaline Oil Corp.
Suite 3700, 250 – 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 266-5992
Facsimile: (403) 266-5952