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Tourmaline Oil Corp.

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

Canada NewsWire

CALGARY, Feb. 14, 2018 /CNW/ - 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
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


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
(%/year)


 

After Future 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


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
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


11,481,179


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
Futures Contract Crude Oil at
Cushing Oklahoma


Light, Sweet Crude
Oil (
40 API, 0.3%S) at

Edmonton
Then Current
$Cdn/Bbl


Alberta Natural Gas Liquids
(Then Current Dollars)

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


Constant
2018 $
$US/Bbl


Then
Current
$US/
Bbl


Spec
Ethane
$Cdn/Bbl


Edmonton
Propane
$Cdn/Bbl


Edmonton
Butane
$Cdn/Bbl


Edmonton
C5+ Stream
Quality
$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
Near Month Contract


Midwest Price @


 

AECO/NIT Spot
Then Current
$Cdn/
MMbtu


Alberta Plant Gate




British Columbia




Spot





Year


Constant 2018 $
$US/
MMbtu


Then
Current
$US/MMbtu


Chicago
Then Current
$US/
MMbtu



Constant
2018 $
$Cdn/
MMbtu


Then Current $Cdn/MMbtu


ARP $Cdn/
MMbtu


Sumas Spot
$US/
MMbtu


Westcoast Station 2
$Cdn/MMbtu


Spot Plant Gate
$Cdn/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,
Excluding FDC

2017

2016

2015

2015-2017
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,
Including FDC

2017

2016

2015

2015-2017
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

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.comCopyright CNW Group 2018

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