Tourmaline adds 338 mmboe of reserves in 2018, 2P reserves increased to 2.46 billion boe

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Tourmaline adds 338 mmboe of reserves in 2018, 2P reserves increased to 2.46 billion boe

Canada NewsWire

CALGARY, Feb. 20, 2019 /CNW/ - Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to report very strong total reserve growth, liquids reserve growth and a continued reserve value increase in the current depressed natural gas price environment.  The Company executed on the 2017-2018 plan to concentrate almost entirely on internal EP growth and has produced the best reserve metrics in the Company's 10 year history over the past two years.

Tourmaline Oil Corp. (CNW Group/Tourmaline Oil Corp.)

RESERVE HIGHLIGHTS

  • Proved plus probable reserves ("2P") increased by 241.2 mmboe to 2.46 billion boe during 2018, an 11% increase over 2017 year-end reserves of 2.22 billion boe and a 15% increase of 337.9 mmboe which includes annual production of 96.7 million boe.  Total proved ("TP") reserves increased 23% to 1.21 billion boe and proved, developed producing ("PDP") reserves of 473.3 mmboe increased 31% over year-end 2017 when including 2018 annual production.

  • After ten years of operation, Tourmaline has 2P natural gas reserves of 11.7 tcf and 2P liquid reserves of 505.2 mmboe of oil, condensate and liquids (December 31, 2018).  The Company has the largest publicly-reported, independently-assessed, 2P natural gas reserves in Canada.

  • 2P reserve net present value ("NPV")(1) of $58.57 per diluted share, TP reserve NPV of $33.67 per diluted share and a PDP reserve NPV of $17.36 per diluted share at December 31, 2018.  The Company was able to continue to grow reserve NPV per diluted share in 2018 despite significantly lower natural gas pricing used in the independent reserve report. 

  • 2P finding, development and acquisition costs ("FD&A") in 2018 were $5.15/boe including changes in future development capital ("FDC") ($3.59/boe excluding change in FDC) based on total capital expenditures of $1.214 billion; TP FD&A in 2018 were $6.79/boe including change in FDC ($4.91/boe excluding change in FDC).  2018 PDP FD&A were $9.11/boe.

  • The 2018 2P recycle ratio was 2.6 based on 2P FD&A of $5.15/boe (including FDC), and 2018 estimated cash flow(2) of $13.47/boe.  The 2018 TP recycle ratio was 2.0 and the 2018 PDP recycle ratio was 1.5.

  • 2P reserve replacement ratio(3) of 3.5 times based on 2P reserve additions of 337.9 mmboe before 2018 production of 96.7 mmboe.

  • Tourmaline systematically converts TP and 2P reserves to PDP reserves; 145 wells (gross) of the 239 wells (gross) rig released in 2018 converted pre-existing TP/2P reserves to PDP reserves.  The FDC in the 2018 2P reserve category represents approximately 4.5 years of future-projected Company cash flow.

  • For the sixth year in a row the Company realized net positive technical revisions to previously booked reserves.

Consistent Value Growth and Industry-Leading Efficiencies


PDP FD&A

($/boe)

1P FD&A

($/boe)

2P FD&A

($/boe)

2P PV10 Annual

Reserve Value Growth



Excl FDC

Incl FDC

Excl FDC

Incl FDC


2018

9.11

4.91

6.79

3.59

5.15

$832.8 MM

2015-2017 (Avg)

11.94

7.06

8.12

3.58

5.16

$2.48 B

 

PRODUCTION HIGHLIGHTS

  • Full-year 2018 average production of 265,044 boepd was 9% higher than 2017 average production of 242,325 boepd and within the guidance range.

  • Q4 2018 liquids production (oil, condensate, NGL) of 51,938 bpd was 14% higher than Q4 2017 average liquids production.  Tourmaline is forecasting 2019 average liquids production of 66,000 bpd, representing 39% year-over-year growth, forecast to be amongst the highest liquids growth rates in the industry this year.

  • In 2018, Tourmaline's EP capital program of $1.23 billion generated approximately 110 mboepd of new production resulting in a 2018 capital efficiency of $11,200 boepd.

  • Q4 2018 average production of 276,568 boepd was 9% higher than Q3 2018 average production of 254,185 boepd.

  • Tourmaline has been producing at the 1H 2019 guidance range of 290,000 – 300,000 boepd during the first quarter; the Company will bring on the 50,000 boepd Gundy deep cut facility during June.

FINANCIAL HIGHLIGHTS

  • Full-year 2018 EP capital spending was $1.23 billion.  Q4 2018 cash flow was $391.5 million and Q4 EP capital spending was $363.2 million. Tourmaline's low cash costs and industry-leading capital execution costs allow the Company to achieve cash flow per share growth, generate free cash flow, and pay a dividend.

  • The Company completed a small acquisition in the Peace River High Triassic oil complex for $21.2 million during the fourth quarter of 2018, consolidating acreage in the core Upper Charlie Lake pool at Spirit River proper.

     
  • The 2018 EP capital program included approximately $110.0 million for the Gundy deep cut gas plant, the benefit of which will be realized in 2H 2019.

  • The 2019 EP capital program is anticipated to be $1.225 billion(4), reflecting the $75.0 million reduction announced on January 15, 2019.  Full-year production guidance remains unchanged at 300,000 boepd.

  • 1H 2019 EP capital spending of $600 million is planned compared to forecast 1H 2019 cash flow of $700 - $750 million.

  • The Company expects to sell $20.0 - $25.0 million of non-core, non-producing assets during the first half of 2019.

  • Tourmaline has secured multiple long-term liquid processing and handling agreements in BC and Alberta to allow for premium pricing for the Company's future liquid streams, including the large volumes at Gundy in BC.

EP UPDATE

  • Tourmaline is currently operating a total of 13 drilling rigs across the three core EP complexes, with the rig count dropping to six during spring break-up.

  • The Company's initial delineation well at Attachie, where the Company has 29,000 undeveloped acres, tested at 767 boepd at the end of a 157 hour test (200 bpd oil and 3.4 mmcfpd of sweet natural gas).  At least one follow-up appraisal well is planned for 2H 2019, where the Company has a large number of future drilling locations on the existing land block.

  • The most recent Cardium horizontal in the Company's frontal foothills overthrust play along the western margin of the Deep Basin was flowing at 21.5 mmcfpd of natural gas with 979 bbls/d of condensate after 70 hours on-stream.  Six of the eight wells drilled on this Cardium play are tier 1 locations with estimated EUR ranging between 12-15 bcf of gas and 225-400 mstb of condensate plus liquids per well (ref. GLJ/Deloitte).  The Company plans further delineation wells along the 225 km play trend during the balance of 2019.

______________________________



(1)

Reserve NPV per share is calculated as the before tax net present value of the reserves at December 31, 2018 discounted at 10% divided by total diluted shares outstanding at December 31, 2018.

(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)

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

(4)

The capital reduction has not been reflected in the Company's current formal guidance. The Company intends to update formal guidance, including these capital reductions, along with the year-end financial results in March 2019.

 

2018 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, 2018
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
Gross
(Mbbls)


Company
Net
(Mbbls)


Company
Gross
(MMcf)


Company
Net
(MMcf)


Company
Gross
(MMcf)


Company
Net
(MMcf)


Company
Gross
(Mbbls)


Company
Net
(Mbbls)


Company

Gross

(Mboe)


Company

Net

(Mboe)

Proved Producing


12,776


10,695


1,647,883


1,522,885


718,631


700,727


66,075


56,622


473,269


437,919

Proved Developed Non-Producing


1,842


1,511


93,816


86,327


189,425


187,149


12,455


11,135


61,504


58,225

Proved Undeveloped


25,008


20,897


1,927,661


1,802,825


1,310,008


1,254,523


106,988


97,913


671,607


628,368

Total Proved Reserves


39,626


33,103


3,669,359


3,412,037


2,218,064


2,142,398


185,518


165,670


1,206,381


1,124,512

Total Probable Reserves


42,421


34,475


2,402,017


2,202,990


3,423,238


3,114,362


237,681


205,613


1,250,977


1,126,313

Total Proved Plus Probable
Reserves


82,046


67,578


6,071,376


5,615,028


5,641,302


5,256,760


423,198


371,283


2,457,358


2,250,826

 

Reserves Category


Net Present Values Of Future Net Revenue ($000s)


Before Future Income Taxes Discounted at
(%/year)


After Income Taxes Discounted at (3)
(%/year)


Unit Value Before
Income Tax
Discounted
at 10%/year


0


5


10


15


20


0


5


10


15


20


($/Boe)


($/Mcfe)

Proved Producing


7,240,410


5,717,521


4,721,579


4,036,357


3,541,211


7,114,318


5,656,857


4,691,064


4,020,391


3,532,559


10.78


1.80

Proved Developed Non-Producing


1,028,081


762,593


601,144


495,218


421,209


753,006


598,008


498,946


429,756


378,150


10.32


1.72

Proved Undeveloped


8,822,179


5,638,372


3,838,123


2,730,228


2,000,951


6,469,863


4,075,075


2,723,454


1,895,281


1,352,929


6.11


1.02

Total Proved Reserves


17,090,670


12,118,486


9,160,845


7,261,803


5,963,372


14,337,187


10,329,941


7,913,463


6,345,428


5,263,638


8.15


1.36

Total Probable Reserves


21,980,983


11,338,472


6,772,624


4,457,988


3,135,558


16,081,110


8,219,331


4,847,751


3,146,492


2,181,518


6.01


1.00

Total Proved Plus Probable
Reserves


39,071,654


23,456,959


15,933,470


11,719,791


9,098,929


30,418,297


18,549,272


12,761,214


9,491,920


7,445,156


7.08


1.18


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, 2018
Forecast Prices and Costs(1)

Reserves Category


Revenue


Royalties


Operating
Costs


Capital
Development
Costs


Abandonment
and
Reclamation
Costs


Future Net
Revenue
Before
Income Taxes


Income
Taxes


Future Net
Revenue
After
Income
Taxes (2)

Proved Producing


11,832,962


981,507


3,366,201


4,000


240,845


7,240,410


126,092


7,114,318

Proved Developed Non-Producing


1,616,557


125,184


387,629


55,012


20,650


1,028,081


275,075


753,006

Proved Undeveloped


17,752,646


1,347,202


3,500,253


3,905,987


177,026


8,822,179


2,352,316


6,469,863

Total Proved


31,202,165


2,453,892


7,254,083


3,964,999


438,520


17,090,670


2,753,483


14,337,187

Total Probable


39,628,699


4,567,376


9,127,569


3,657,044


295,726


21,980,983


5,899,874


16,081,110

Total Proved Plus
Probable


70,830,864


7,021,268


16,381,652


7,622,043


734,246


39,071,654


8,653,357


30,418,297



Notes:  




(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




Crude Oil and Natural Gas Liquids Pricing






NYMEX WTI Near Month

Futures Contract Crude Oil at 

Cushing, Oklahoma




Alberta Natural Gas Liquids
(Then Current Dollars)

Inflation%(2)


CAD/USD
Exchange
Rate
$US/$Cdn(3)


Constant
2019 $
$US/Bbl


Then
Current
$US/Bbl


MSW, Light Crude Oil
(40 API, 0.3%S) at
Edmonton
Then Current
$Cdn/Bbl


Spec
Ethane
$Cdn/Bbl


Edmonton
Propane
$Cdn/Bbl


Edmonton
Butane
$Cdn/Bbl


Edmonton
C5+ Stream
Quality
$Cdn/Bbl

2019


0.0


0.7567


58.58


58.58


67.30


6.82


26.13


27.32


70.10

2020


2.0


0.7817


63.33


64.60


75.84


8.40


31.27


41.10


79.21

2021


2.0


0.7967


65.55


68.20


80.17


9.98


34.58


49.28


83.33

2022


2.0


0.8033


66.90


71.00


83.22


11.22


37.25


55.65


86.20

2023


2.0


0.8067


67.27


72.81


85.34


11.89


38.73


57.92


88.16

2024


2.0


0.8083


67.56


74.59


87.33


12.22


39.75


59.27


90.20

2025


2.0


0.8083


67.86


76.42


89.50


12.45


40.76


60.77


92.43

2026


2.0


0.8083


68.25


78.40


91.89


12.71


41.93


62.37


94.87

2027


2.0


0.8083


68.27


79.98


93.76


12.96


42.84


63.65


96.80

2028


2.0


0.8083


68.27


81.59


95.68


13.28


43.80


64.97


98.79

2029


2.0


0.8083


68.27


83.22


97.57


13.53


44.73


66.26


100.76

2030


2.0


0.8083


68.26


84.87


99.52


13.85


45.64


67.56


102.77

2031


2.0


0.8083


68.26


86.57


101.52


14.10


46.56


68.92


104.84

2032


2.0


0.8083


68.26


88.30


103.55


14.36


47.46


70.33


106.94

2033


2.0


0.8083


68.27


90.08


105.65


14.68


48.44


71.72


109.10

2034


2.0


0.8083


68.27


+2.0%/yr


+2.0%/yr


+2.0%/yr


+2.0%/yr


+2.0%/yr


+2.0%/yr

 

Year

Natural Gas and Sulphur Pricing


Henry Hub Nymex
Near Month Contract






Alberta Plant Gate




British Columbia



 

Midwest Price @
Chicago
Then Current
$US/
MMbtu




Spot










Constant
2019 $
$US/
MMbtu


Then
Current
$US/MMbtu



AECO/NIT Spot
Then Current
$Cdn/
MMbtu


Constant
2019 $
$Cdn/
MMbtu


Then
Current
$Cdn/MMbtu


ARP $Cdn/
MMbtu


Sumas
Spot
$US/
MMbtu


Westcoast
Station 2
$Cdn/MMbtu


Spot Plant
Gate
$Cdn/MMbtu

2019


3.00


3.00


2.91


1.88


1.67


1.67


1.67


2.47


1.42


1.24

2020


3.07


3.13


3.04


2.31


2.06


2.10


2.10


2.59


1.94


1.75

2021


3.20


3.33


3.24


2.74


2.42


2.52


2.52


2.88


2.41


2.22

2022


3.30


3.51


3.41


3.05


2.66


2.83


2.83


3.09


2.76


2.56

2023


3.35


3.62


3.53


3.21


2.76


2.99


2.99


3.20


2.93


2.74

2024


3.35


3.70


3.61


3.31


2.79


3.08


3.08


3.28


3.06


2.86

2025


3.35


3.77


3.68


3.39


2.80


3.15


3.15


3.35


3.12


2.91

2026


3.35


3.85


3.76


3.46


2.80


3.22


3.22


3.43


3.19


2.98

2027


3.35


3.92


3.83


3.54


2.81


3.29


3.29


3.50


3.26


3.06

2028


3.35


4.01


3.91


3.62


2.83


3.38


3.38


3.59


3.35


3.14

2029


3.34


4.08


3.98


3.70


2.82


3.44


3.44


3.65


3.42


3.21

2030


3.35


4.16


4.07


3.78


2.83


3.52


3.52


3.73


3.51


3.28

2031


3.35


4.25


4.16


3.85


2.83


3.58


3.58


3.82


3.57


3.34

2032


3.34


4.33


4.23


3.92


2.82


3.65


3.65


3.89


3.63


3.40

2033


3.35


4.42


4.32


4.00


2.83


3.73


3.73


3.97


3.72


3.48

2034


3.35


+2.0%/yr


+2.0%/yr


+2.0%/yr


2.83


+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, 2019 (each of which is available on their respective websites at www.gljpc.com, www.sproule.com and www.mcdan.com). GLJ assigns a value to the Company's existing physical diversification contracts for natural gas for consuming markets at Dawn, Chicago, Ventura, Malin and PG&E based upon GLJ's forecasted differential to NYMEX Henry Hub, contracted volumes, and transportation costs.  No incremental value is assigned to potential future contracts which were not in place as of December 31, 2018.



(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,

2018

2017

2016

Reserves (Mboe)




Proved Producing

473,269

436,208

351,931

Total Proved

1,206,381

1,055,702

858,932

Proved Plus Probable

2,457,358

2,216,206

1,746,822

Capital Expenditures ($ millions)




Exploration and Development(3)

1,261

1,364

756

Net Acquisitions (Dispositions)

(47)

58

1,545

Total Capital Expenditures

1,214

1,422

2,301

Cash Flow ($/boe)




Cash Flow

13.47

13.63

10.77

Cash Flow - Three Year Average

12.80

13.11

15.17



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)

2018 Financial numbers are unaudited.

(3)

Includes unaudited capitalized G&A of $30 million, $27 million and $25 million for 2018, 2017 and 2016 respectively.

 

Finding and Development Costs


Finding and Development Costs, Excluding FDC

2018

2017

2016

3-Year Avg.

Total Proved





Reserve Additions (MMboe)

241.0

272.8

126.4


F&D Costs ($/boe)

5.24

5.00

5.98

5.28

F&D Recycle Ratio(1)

2.6

2.7

1.8

2.4

Total Proved Plus Probable





Reserve Additions (MMboe)

326.6

537.5

158.7


F&D Costs ($/boe)

3.86

2.54

4.76

3.31

F&D Recycle Ratio(1)

3.5

5.4

2.3

3.9






Finding and Development Costs, Including FDC

2018

2017

2016

3-Year Avg.

Total Proved





Change in FDC ($ millions)

441.7

481.1

(239.9)


Reserve Additions (MMboe)

241.0

272.8

126.4


F&D Costs ($/boe)

7.07

6.76

4.08

6.35

F&D Recycle Ratio(1)

1.9

2.0

2.6

2.0

Total Proved Plus Probable





Change in FDC ($ millions)

486.3

612.1

(518.6)


Reserve Additions (MMboe)

326.6

537.5

158.7


F&D Costs ($/boe)

5.35

3.68

1.49

3.87

F&D Recycle Ratio(1)

2.5

3.7

7.2

3.3

 

Finding, Development and Acquisition Costs

Finding, Development and Acquisition Costs, Excluding FDC

2018

2017

2016

3-Year Avg.

Total Proved





Reserve Additions (MMboe)

247.4

285.2

282.8


FD&A Costs ($/boe)

4.91

4.98

8.14

6.05

FD&A Recycle Ratio(1)

2.7

2.7

1.3

2.1

Total Proved Plus Probable





Reserve Additions (MMboe)

337.9

557.8

706.5


FD&A Costs ($/boe)

3.59

2.55

3.26

3.08

FD&A Recycle Ratio(1)

3.7

5.3

3.3

4.2






Finding, Development and Acquisition Costs, Including FDC

2018

2017

2016

3-Year Avg.

Total Proved





Change in FDC ($ millions)

465.3

515.7

304.0


Reserve Additions (MMboe)

247.4

285.2

282.8


FD&A Costs ($/boe)

6.79

6.79

9.21

7.63

FD&A Recycle Ratio(1)

2.0

2.0

1.2

1.7

Total Proved Plus Probable





Change in FDC ($ millions)

526.8

678.3

1,894.0


Reserve Additions (MMboe)

337.9

557.8

706.5


FD&A Costs ($/boe)

5.15

3.76

5.94

5.02

FD&A Recycle Ratio(1)

2.6

3.6

1.8

2.6

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 2018 financial results after the close of markets on March 5, 2019.  Conference call to be held on March 6, 2019 at 9:00 a.m.  Details can be found on Tourmaline's website at www.tourmalineoil.com.

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, 2018, 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, 2019 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, 2018, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2019.

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, 2018, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2019.

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, 2018, 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, 2018 on SEDAR on March 5, 2019.

Per share information is based on the total common shares outstanding, after accounting for outstanding Company options, at year-end 2018 and 2017, 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 2018 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 300,000 boed for 2019 increasing to 373,000 boed by 2023 with price assumptions for natural gas (AECO - $2.25/mcf) and crude oil (WTI (US) - $60/bbl for 2019 and $55/bbl from 2020 to 2023), an exchange rate assumption of $0.80 (US/CAD) and costs inflated at 2.5% annually after 2019.  To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on November 7, 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 2020 and beyond are provided for illustration only as budgets and forecasts beyond 2020 have not been finalized and are subject to a variety of factors including prior year's results.

INITIAL PRODUCTION RATES

Any references in this news release to initial production 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 ULTIMATE RECOVERY (EUR)

This news release contains a metric commonly used in the oil and natural gas industry, "estimated ultimate recovery" (EUR).  The term EUR is the estimated quantity petroleum that is potentially recoverable or has already been recovered from a well.  EUR does not have a standardized meaning and may not be comparable to similar measures presented by other companies.  As such, it should not be used to make comparisons.  Management uses EUR for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measure is not a reliable indicator of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.  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.

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" which is a financial measure commonly used in the oil and gas industry and does not have a standardized meaning prescribed by International Financial Reporting Standards ("GAAP").  Accordingly, the Company's use of this term may not be comparable to similarly defined measures presented by other companies.  Management uses the term "cash flow" 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 7, 2018 Management's Discussion and Analysis for the definition and description of these terms.

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

EUR

estimated ultimate recovery

gj

 gigajoule

gjs/d

gigajoules per day

mbbls

thousand barrels

mmbbls

million barrels

mboe

thousand barrels of oil equivalent

mboepd

thousand barrels of oil equivalent per day

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

mstb

thousand stock tank barrels

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.

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