CALGARY, Nov. 8, 2017 /CNW/ - Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to release strong financial and operating results for the third quarter of 2017.

PRODUCTION UPDATE

• Current production is ranging between approximately 255,000-265,000 boepd and the Company expects 2017 exit production of between 270,000-280,000 boepd, both ahead of original internal estimates.
  
  
• The Company also currently has additional behind-pipe or shut-in volumes of approximately 25,000 boepd, which is expected to grow to 30,000 boepd by exit 2017.
  
  
• Q3 average production was 236,905 boepd - a 40% increase over Q3 2016.
  
  
• The Company elected to leave natural gas volumes of approximately 50 mmcfpd shut-in during the East Gate maintenance related low price periods in August, September and October.   East Gate price-related curtailments and the significant James River curtailment reduced August/September volumes by approximately 10,000 boepd.
  
  
• Q3 average liquids production (oil, condensate and NGLs) at 38,995 bpd is 94% higher than Q3 2016 and 8% higher than Q2 2017.  Current liquids production is averaging 42,000 bpd.
  
  
• Unchanged from its original guidance, the Company is expecting 2017 full-year production to average between 240,000 and 250,000 boepd. 
  
  
• Tourmaline will deliver approximately 30% year-over-year production growth in 2017.
  
  
• Tourmaline is expecting 2018 production to average between 270,000 and 280,000 boepd, down from its previous guidance of 280,000-300,000 boepd with a corresponding capital spending reduction of 29%.  This will now yield 2018 year-over-year production growth of approximately 10%.
  
  
• Liquids production is expected to grow to approximately 50,000 bpd in 2018 and is expected to reach 60,000-65,000 bpd in 2H 2019 with the start-up of the Tourmaline-operated Gundy 200 mmcfpd deep cut natural gas plant. 

EP UPDATE

• Tourmaline expects to drill approximately 300 wells in 2017 across all three core-operated complexes.
  
  
• Drilling execution has generally been ahead of schedule.  The Company is currently operating 15 rigs, down from the peak of 18 rigs earlier in Q3.  The Company will reduce the operated rig fleet to 14 rigs during Q4 as planned drilling programs are completed.  An average 12-rig program is now planned for 2018.
  
  
• Tourmaline continues to drill the lowest cost, completed-per-stage horizontal wells across all three operated complexes.
  
  
• The Peace River High oil drilling program was increased to four rigs during the third quarter as the Company expands efforts developing the Montney and Lower Charlie Lake horizons in addition to the main Upper Charlie Lake development program.  During the next two months, Tourmaline will bring on-production ten new Montney oil wells and three Lower Charlie Lake oil wells that are already drilled and being completed.  The Company's Progress 1-4 Lower Montney well has an IP 90 of 466 bopd and 2.5 mmcfpd of gas (891 boepd).   With drill and complete costs of $2.4 million, an IP 365 of 244 boepd and a 2P estimated ultimate recovery (or EUR) of 345 mboe, the Upper Charlie Lake horizontals are amongst the most profitable oil wells in North America.  The three most recent Upper Charlie Lake wells stimulated with the Company's CCFT (Confined Cecil Frac Technology) are averaging between 300 and 400 bopd and 0.3 mmcfpd gas after the first week of production.  Drill-and-complete costs for these wells is approximately $2.0 million, given the reduced stimulation costs.
  
  
• Development of the Gundy property has exceeded expectations for both increased well performance and capital cost reduction. The Company has drilled and completed two pads (16 wells in aggregate) with a third 11-well pad drilled awaiting stimulation.  Current drill-and-complete costs are 40-50% less than those carried in the 2016 independent reserve reports.  The most recent pacesetter horizontal well was drilled in 6.4 days for $1.3 million, down from drilling costs of $3.5 million in 2014.  Initial well performance is significantly ahead of the 5.5 bcfe performance curves utilized in the 2016 independent reserve report, with some initial flow rates more than double original expectation.  The A-M78-A/94-B-16 well was flowing at 22.5 mmcfpd at a flowing casing pressure of 8,625 KPa with 590 bbls/day of wellhead condensate after five days of production testing (4,340 boepd).

Q3 FINANCIAL RESULTS

• Q3 2017 cash flow⁽¹⁾ was $251.3 million ($0.93/diluted share) up 35% from Q3 2016 (18%/diluted share).
  
  
• Q3 2017 after-tax earnings were $50.6 million ($0.19/diluted share) underscoring the fundamental profitability of the business.  With a realized average natural gas price in Q3 of $2.52/mcf and continued earnings, the Company continues to lower the threshold natural gas price required for full cycle profitability.
  
  
• Q3 operating costs were $3.00/boe, down 8% from Q3 2016 and down 7% from the second quarter of 2017. 
  
  
• Weaker than expected natural gas prices related to the new East Gate natural gas transportation restrictions directly impacted Q3 2017 cash flow by $55.0 million as the Company had significant new volumes from new pads receiving the much lower than anticipated daily index price.  Uncontracted daily natural gas volumes are significantly less in Q4 2017 and in Q1 2018.  The Company now has winter 2018 fixed volumes of 413 mmcfpd at $3.21/mcf Cdn at AECO that take effect, as well as 116 mmcf/d of new service on the Mainline to Dawn, Ontario, effective November 1, 2017.
  
  
• For the nine months ending September 30, 2017, cash flow was $857.5 million or $3.18/diluted share compared to $479.3 million or $2.09/diluted share for the same period in 2016, a 52% per diluted share improvement.

CAPITAL PROGRAM AND FINANCIAL OUTLOOK

2H 2017 Capital Program

• Q3 2017 E&P capital spending was $432.4 million as the Company aggressively pursued the second half 2017 drilling program with up to 18 rigs in July/August, to ensure that new production is ready for exit 2017/Winter 2018.  The Company has purposefully grown the behind-pipe production volumes and the DUC (drilled uncompleted) inventory to provide flexibility to take advantage of potentially improved winter prices as well as facilitate overall production decline management in 2018.  The Company currently has a total of 110 DUC wells and completed wells across all three core complexes to bring on-stream in Q4 2017 and during Q1 2018.  The Q4 2017 EP program is at a reduced 14-rig pace as several of the planned drilling programs have been competed ahead of schedule.  Tourmaline expects Q4 2017 E&P spending to match Q4 2017 cash flow of an estimated $325-$335 million.  Full-year E&P capital spending is now forecast to be $1.34 billion, with revised full-year cash flow estimated at $1.19 billion, reflecting lower natural gas prices than originally forecast in Q3 2017.  
  
  
• Tourmaline expects to grow 2017 cash flow per share by approximately 40% in 2017 over 2016, despite a challenging natural gas price environment. 
  
  
• The Company completed a land swap in NEBC during Q3 2017, allowing for a significant consolidation in the Sundown complex prior to the planned 2018/2019 development program.  Tourmaline consolidated 150 existing development locations at Sundown to 100% working interest and acquired an estimated additional 75 locations.  None of these locations were booked in the 2016 independent reserve report.  The Company acquired 9.12 mmboe of internally-estimated 2P reserves at Sundown and approximately 350 boepd of current production in exchange for 1.44 mmboe of currently-booked reserves on the traded property as well as $19.0 million in cash paid by Tourmaline at closing.
  
  
• The Q3 capital included $25.0 million for the initiation of the Gundy deep-cut facility construction.  The Company will expend an additional $5.0 million in Q4 2017, approximately $60.0 million in 2018 and $85.0 million in 2019 to complete the project.  The Gundy plant will bring approximately 200 mmcf/d of natural gas and 12,500-15,000 bpd of liquids production on-stream.

2018 Program and Updated Five-Year Growth Plan

• The Company has reached a point in its eight year evolution to a senior producer that it can provide both strong, predictable annual growth and a steady return to shareholders.  Tourmaline has three expansive resource plays that have been de-risked through the drilling of 1,075 operated wells with Company owned-and-operated infrastructure in place in all three complexes.  The Company drills the least expensive per-stage completed wells in each area by Industry and is one of the lowest cost operators in Western Canada.  Tourmaline had booked 2P reserves of 1.75 billion boe (8.93 TCF of natural gas, 258.4 mmbbls of oil, condensate, NGLs) at year end 2016, utilizing only 1,819 future locations of an inventory of 15,016 locations.   The Company has created a long lasting natural gas and liquids business that can continue to profitably grow and provide a steady return to shareholders.
  
  
• The Company has elected to moderate growth in its natural gas business until the Western Canadian and North American supply/demand outlook is more transparent and balanced.  The Company will keep 2018 daily natural gas production essentially flat at 2017 exit production levels of 1.35 bcf/day, unless there is a material improvement in the natural gas price outlook.  Tourmaline can generate a strong full-cycle return at natural gas prices as low as $2.30-$2.40/mcf Cdn, but does not believe it is beneficial to shareholders to aggressively grow the natural gas business at prices in that range.
  
  
• Tourmaline has reduced the natural gas price utilized in its five-year plan from $3.15/mcf Cdn at AECO to $2.50/mcf Cdn.  By mid-2018 Tourmaline also has approximately 0.5 bcf/day of corporate natural gas production that is transported to hubs that are essentially NYMEX priced.  The Company is now utilizing a $3.10/mcf US NYMEX price in the plan down from $3.25/mcf US previously.  Tourmaline's annual realized natural gas price on Alberta sales has exceeded the actual AECO price in each of the last seven years, outperforming the index by an average of 13% over the seven-year period.  The Company has also decreased the oil price employed in the five-year outlook to a flat $52/bbl US WTI.
  
  
• The 2018 EP capital program has been reduced from $1.52 billion to $1.08 billion, reducing planned production growth from 15% to 10% for the year.  An average 5-10% per annum production growth is maintained through the balance of the five-year plan based on the $2.50/mcf Cdn at AECO flat natural gas pricing in the plan.  The 2018 EP program is a 12-rig program; however, the Company has the capability to operate over a 20-rig fleet and can quickly ramp up the EP program in an improved natural gas price environment, in turn increasing annual growth rates to the 10 to 15% range.  The slightly lower growth rate in 2019 is a result of the majority of the Gundy development capital (drilling and plant installation) occurring during calendar 2019 with the plant only on-stream for the second half of the year.
  
  
• The Company will continue to aggressively grow the liquids business in 2018 and 2019, which has doubled in the past 15 months to over 40,000 bpd (oil, condensate, NGLs).  A further 50% growth in daily total liquids volumes is expected over the next two years.
  
  
• Even with the much lower commodity pricing employed, the significantly reduced capital spending in the five-year plan creates material free cash flow^([2]), estimated at $251.0 million in 2018.  This will allow the Company to begin paying a modest dividend starting at 8¢ per share per quarter, for a total of approximately $86 million per year - significantly less than forecast annual free cash flow.  The dividend is expected to commence in Q1 2018.
  
  
• A significant portion of the dividend funding will be provided by Tourmaline's growing third-party revenues from the Company's extensive infrastructure assets. Third-party revenues of approximately $30 - $40 million from Tourmaline infrastructure are forecast in 2017, and are expected to be between $40 - $50 million in 2018.  Tourmaline's extensive, new state-of-the-art natural gas plant network is currently capable of processing up to 1.5 bcf/day, providing ample capacity for Tourmaline natural gas volumes and a component of third party volumes.  Tourmaline currently plans to expand the natural gas processing infrastructure again in 2019.  The 200 mmcfpd Gundy BC deep-cut natural gas plant remains in the development outlook with a planned 2H 2019 start-up.  The Gundy property will actually support a 400 mmcf/d project, consuming only half of the 1,600 internally-recognized locations by 2037.  The decision to proceed with a phase 2 expansion in the 2020/2021 time frame has not been made and will be controlled primarily by the commodity price outlook.
  
  
• The remaining free cash flow after the dividend distribution will be utilized to reduce existing corporate debt.  Tourmaline continues to maintain an extremely strong balance sheet with forecast 2017 net debt to cash flow of 1.5 times, dropping to 1.1 times by exit 2018.  The Company has grown rapidly to a senior producer while maintaining strong capital discipline since inception with a net debt to cash flow average of 1.4 over the last seven years.  As at September 30, 2017, the Company has $1.06 billion of available unused credit capacity.
  
  
• Tourmaline expects to drill approximately 233 wells in 2018, down from approximately 300 wells in 2017 with a total 2018 EP capital program of $1.082 billion.  The Company has the flexibility to reduce this program by $50-75 million without affecting the full-year production estimate.

CORPORATE SUMMARY – THIRD QUARTER 2017

Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)

Tourmaline will host a conference call tomorrow, November 9, 2017 starting at 9:00 a.m. MT (11:00 a.m. ET).  To participate, please dial 1-888-231-8191 (toll-free in North America), or international dial-in 647-427-7450, a few minutes prior to the conference call.

Conference ID is 91799506.

Reader Advisories

CURRENCY

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

FORWARD-LOOKING INFORMATION

This news release contains forward-looking information and statements (collectively, "forward-looking information") within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "on track", "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 the following: anticipated petroleum and natural gas production and production growth for various periods; the commencement of the payment of dividends and the timing and amount thereof; drilling inventory or locations; cash flow; cash flow per share; free cash flow; net debt to cash flow levels; production levels supported by certain of the Company's reserves and drilling inventory; 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 the following: prevailing and future 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. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and  the funds available for the payment of dividends from time to time will be dependent upon, among  other things, free cash flow, financial requirements  for the Company's operations and the execution of its growth strategy, fluctuations in working capital and  the timing and amount of capital expenditures, debt service requirements and other factors  beyond the Company's control. Further, the ability of Tourmaline to pay dividends will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.

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 it 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.

FINANCIAL OUTLOOK

Also included in this news release are estimates of Tourmaline's year-end 2017 and 2018 net debt to cash flow levels, 2017 and 2018 capital spending, 2017 cash flow, 2017 cash flow per share and 2018 free cash flow, which are based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release and including Tourmaline's estimated 2017 average production of 240,000-250,000 boepd, 2018 average production of 270,000-280,000 boepd and commodity price assumptions for natural gas (AECO - $2.25/mcf for 2017 and AECO - $2.50/mcf for 2018), and crude oil (WTI (US) - $51.00/bbl for 2017 and WTI (US) - $52.00/bbl for 2018) and an exchange rate assumption of $0.78 (US/CAD) for 2017 and $0.80 (US/CAD) for 2018. To the extent such estimates constitute a financial outlook, they were approved by management and the Board of Directors of Tourmaline on November 8, 2017 and are included to provide readers with an understanding of Tourmaline's anticipated net debt to cash flow levels, capital spending and free 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.

INITIAL PRODUCTION (IP) RATES

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.

ESTIMATED DRILLING INVENTORY

Certain information in this news release is based on assumptions regarding the Company's drilling locations, which are 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 15,016 undrilled locations, 906 are proved undeveloped locations, 20 are proved non-producing locations, 893 are probable undeveloped locations, nil are probable non-producing and 13,197 are unbooked. Proved producing wells, 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.

PACESETTER WELLS

Tourmaline uses the term "pacesetter" well in its description of its drilling results at the Gundy property. A pacesetter well in this context refers to the fastest well drilled by Tourmaline in the area, measured from spud to rig release.

GENERAL

See also "Forward-Looking Statements", "Boe Conversions" and "Non-GAAP Financial Measures" in the Company's Q3 2017 Management's Discussion and Analysis.

CERTAIN DEFINITIONS:

MANAGEMENT'S DISCUSSION AND ANALYSIS AND INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

To view Tourmaline's Management's Discussion and Analysis and Interim Condensed Consolidated Financial Statements for the periods ended September 30, 2017 and 2016, please refer to the SEDAR (www.sedar.com) as well as Tourmaline's website at www.tourmalineoil.com.

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.

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