BOE Report

Tourmaline Oil Corp. Reserves Reach 1.1 Billion Barrels of Oil Equivalent

CALGARY, AB–(Marketwired – February 22, 2016) – Tourmaline Oil Corp. (TSX: TOU) (“Tourmaline” or the “Company”) enjoyed another record year of material, profitable reserve additions with ever-improving efficiencies.

HIGHLIGHTS

  • Proved plus probable reserves (“2P”) increased to 1,108.3 mmboe during 2015, a 30% increase over 2014 reserves of 855.8 mmboe and a 36% increase (22% per diluted share) before taking into account annual production of 56.4 mmboe. Total proved (“TP”) reserves increased 48% and proved developed producing (“PDP”) reserves increased by 80% over 2014 before taking into account annual production of 56.4 mmboe.
  • Tourmaline now has 2P reserves of 5.7 TCF of natural gas and 159.3 mmbbls of oil, condensate and liquids at January 1, 2016.
  • 2P reserve replacement of approximately 550% for 2015 based on 2P reserve additions of 308.9 mmboe before taking into account 2015 annual production of 56.4 mmboe.
  • 2015 2P finding, development and acquisition (“FD&A”) cost of $5.89/boe including changes in future development capital (“FDC”), 2015 TP FD&A cost of $8.43/boe including FDC and 2015 PDP FD&A cost of $13.42/boe, all are the lowest in the Company’s seven year history.
  • In 2015, Tourmaline’s E&P capital program of approximately $1.45 billion generated over 90,000 boe/d of new production resulting in capital efficiency of approximately $15,500 boe/d, an improvement of 26% over 2014 E&P capital efficiency of approximately $20,900 boe/d.
  • After seven years, Tourmaline now has 1.1 billion boe of independently recognized 2P reserves at year end 2015, essentially all of which will be serviced by Company-owned infrastructure. The Company has also produced 162.6 mmboe during the first seven years of operation.
  • A 2P reserve addition of 308.9 mmboe in 2015 was generated even though 93.1 net wells (108 gross) of the 181.3 net wells (221 gross) rig released in 2015 were locations already included in the 2014 report.
  • 2015 2P recycle ratio of 2.6 times based on 2P FD&A of $5.89/boe (including FDC) and 2015 estimated cash flow per boe of $15.09.
  • 2015 2P reserve value (PV10 before tax) increase of $580.0 million over 2014 despite dramatically lower commodity prices. The estimated 2P reserve NAV (PV10 before tax) at year end 2015 was $37.26/per diluted share.
  • Positive technical revisions of 42.5 mmboe were reported in 2015 representing the fourth year in a row of positive technical revisions.
  • Year end 2015 PDP reserves of 263.2 mmboe as a percentage of 2P reserves in 2015 improved to 23.8% from 20.8% in 2014.
  • Fourth quarter 2015 production averaged 179,610 boepd, a 37% increase over the fourth quarter of 2014. Full year 2015 average production of 154,403 boepd represented a 37% increase (29% per diluted share) over 2014 average production of 112,929 boepd.
  • Q1 2016 average production remains on target, ranging between 190,000-200,000 boepd, having recently reached production as high as 204,000 boepd.
  • Tourmaline now produces over 1.0 bcf/day of natural gas and has recognized future reserves of over one billion boe.
  • The Company spudded its first well February 9, 2009, and has subsequently drilled a total of 722 wells in its three, expansive core areas. The future drilling inventory is expanding more rapidly than the Company is drilling on an annual basis.
  • The Company has only booked 999 net locations (1,196 gross) in the 2015 reserve report of a well-defined future development drilling inventory of 10,591 gross locations. The infrastructure skeleton, which is now complete in all three core areas, essentially reaches all of the future locations.
  • Tourmaline has maintained a very strong balance sheet and financial position throughout its seven year history, and intends to maintain a top quartile debt to cash flow ratio.
  • Q4 2015 capital expenditures of $325.5 million were 23% lower than Q3 2015 with significant further reductions for the first of half of 2016 with an E&P budget currently set at $350 million.

2015 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, 2015
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 Developed Producing 6,799 5,858 968,183 891,976 412,736 381,537 26,275 20,857 263,227 238,967
Proved Developed Non-Producing 201 178 52,860 48,113 70,163 65,789 3,262 2,749 23,967 21,911
Proved Undeveloped 14,037 11,746 1,176,582 1,101,882 649,202 587,093 38,531 33,030 356,866 326,272
Total Proved Reserves 21,037 17,783 2,197,624 2,041,971 1,132,100 1,034,420 68,068 56,636 644,059 587,151
Total Probable Reserves 21,270 17,682 1,557,770 1,444,852 806,566 712,250 48,894 39,429 464,219 416,628
Total Proved Plus Probable Reserves 42,306 35,465 3,755,394 3,486,824 1,938,666 1,746,670 116,962 96,065 1,108,279 1,003,779
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 ($/Mcfe) ($/Boe)
Proved Developed Producing 4,456,875 3,455,951 2,824,461 2,397,253 2,091,396 4,456,875 3,455,951 2,824,461 2,397,253 2,091,396 1.97 11.82
Proved Developed Non-Producing 421,765 304,524 235,340 190,322 159,011 421,765 304,524 235,340 190,322 159,011 1.79 10.74
Proved Undeveloped 5,126,177 3,192,880 2,100,691 1,429,915 990,620 3,883,262 2,449,482 1,623,165 1,105,974 761,394 1.07 6.44
Total Proved Reserves 10,004,817 6,953,355 5,160,492 4,017,490 3,241,027 8,761,901 6,209,958 4,682,966 3,693,549 3,011,800 1.46 8.79
Total Probable Reserves 9,703,591 5,121,938 3,086,513 2,033,597 1,425,243 7,134,504 3,729,770 2,218,997 1,441,214 995,195 1.23 7.41
Total Proved Plus Probable Reserves 19,708,408 12,075,293 8,247,005 6,051,088 4,666,270 15,896,406 9,939,727 6,901,964 5,134,763 4,006,995 1.37 8.22

Notes:

  1. Tables may not add due to rounding.
  2. Shale Natural Gas is now 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. In previous years, Montney gas has been classified as product type “Natural Gas”.
  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 level 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.
Total Future Net Revenue ($000s)
(Undiscounted)
as of December 31, 2015
Forecast Prices and Costs
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

(1)
Proved Producing 7,468,158 763,039 2,101,406 – 146,838 4,456,875 – 4,456,875
Proved Developed Non-Producing 721,317 74,507 167,923 49,846 7,277 421,765 – 421,765
Proved Undeveloped 10,979,420 1,117,691 2,019,465 2,634,212 81,874 5,126,177 1,242,915 3,883,262
Total Proved 19,168,895 1,955,238 4,288,795 2,684,058 235,988 10,004,817 1,242,915 8,761,901
Total Probable 17,418,562 2,067,187 3,714,388 1,839,137 94,259 9,703,591 2,569,087 7,134,504
Total Proved Plus Probable 36,587,457 4,022,425 8,003,183 4,523,195 330,247 19,708,408 3,812,002 15,896,406

Note:

  1. 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 level 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.
Summary of Pricing and Inflation Rate Assumptions
Forecast Prices and Costs

(1)
Year Inflation(2)% Crude Oil and Natural Gas Liquids Pricing
Bank of
Canada Average
Noon Exchange
Rate
$US/$Cdn(3)		 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)
Constant
2016
$
$US/Bbl		 Then
Current
$US/
Bbl		 Spec
Ethane
$Cdn/Bbl		 Edmonton
Propane
$Cdn/Bbl		 Edmonton
Butane
$Cdn/Bbl		 Edmonton
Pentanes
Plus
$Cdn/Bbl
2016 0.7 0.7350 44.67 44.67 55.89 8.35 9.76 38.73 60.16
2017 1.3 0.7667 54.47 55.20 66.47 10.24 15.88 46.91 70.95
2018 1.8 0.8017 61.51 63.47 73.21 11.35 24.09 52.58 78.05
2019 1.8 0.8167 67.57 71.00 81.35 12.41 30.49 59.42 86.58
2020 1.8 0.8333 69.87 74.77 84.57 13.03 33.69 62.81 90.00
2021 1.8 0.8417 71.80 78.24 87.88 13.53 34.95 65.25 93.46
2022 1.8 0.8417 73.67 81.75 92.01 14.10 36.45 68.33 97.79
2023 1.8 0.8417 75.55 85.37 96.24 14.73 38.06 71.46 102.23
2024 1.8 0.8417 75.88 87.32 98.17 15.17 38.79 72.90 104.29
2025 1.8 0.8417 75.87 88.90 99.94 15.49 39.50 74.22 106.16
2026+ 1.8 0.8417 75.90 1.8%/yr 1.8%/yr 1.8%/yr 1.8%/yr 1.8%/yr 1.8%/yr
Year Natural Gas and Sulphur Pricing
Henry Hub Nymex
Near Month Contract		 Midwest
Price @ Chicago Then Current $US/
MMbtu		 AECO/NIT
Spot Then Current
$Cdn/
MMbtu		 Alberta Plant Gate Sumas
Spot
$US/
MMbtu		 British Columbia
Spot ARP $/
MMbtu		 Alliance
$/MMbtu		 Westcoast
Station 2
$/MMbtu		 Spot Plant Gate
$MMbtu
Constant
2015 $
$US/
MMbtu		 Then
Current $US/MMbtu		 Constant 2016 $
$/MMbtu		 Then
Current
$MMbtu
2016 2.45 2.45 2.54 2.57 2.35 2.35 2.35 2.00 2.35 1.91 1.73
2017 2.98 3.02 3.11 3.14 2.88 2.92 2.92 2.55 2.90 2.70 2.52
2018 3.29 3.40 3.49 3.47 3.15 3.25 3.25 2.89 3.27 3.14 2.95
2019 3.55 3.73 3.83 3.80 3.40 3.57 3.57 3.22 3.60 3.51 3.32
2020 3.69 3.95 4.05 3.99 3.51 3.76 3.76 3.40 3.83 3.70 3.51
2021 3.78 4.12 4.22 4.13 3.58 3.90 3.90 3.57 4.01 3.84 3.65
2022 3.86 4.28 4.37 4.30 3.66 4.06 4.06 3.74 4.17 3.98 3.79
2023 3.94 4.45 4.54 4.48 3.75 4.23 4.23 3.94 4.34 4.16 3.97
2024 3.97 4.57 4.67 4.60 3.79 4.36 4.36 4.08 4.47 4.28 4.09
2025 3.98 4.66 4.75 4.70 3.79 4.45 4.45 4.18 4.56 4.38 4.19
2026+ 3.98 +1.8%/yr +1.8%/yr +1.8%/yr 3.81 +1.8%/yr +1.8%/yr +1.8%/yr +1.8%/yr +1.8%/yr +1.8%/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. as at December 31, 2015 (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. Throughout the year, Tourmaline experienced significant improvements in overall efficiencies resulting in 2P FD&A cost reductions, including FDC, of 43% to $5.89 per boe from $10.40 per boe in 2014.

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

As at December 31, 2015 2014 2013

Reserves (Mboe)
Proved Producing 263,227 177,811 122,327
Total Proved 644,059 472,296 316,461
Proved Plus Probable 1,108,279 855,794 590,099

Capital Expenditures

($ millions)
Exploration and Development 1,451 2,031 1,167
Net Acquisitions (Dispositions) 451 (250) 149
Total Capital Expenditures 1,902 1,782 1,315

Cash Flow

($/boe)
Cash Flow 15.09 22.54 19.29
Cash Flow – Three Year Average 18.47 19.93 18.32

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. 2015 Financial numbers are unaudited.

Finding and Development Costs

Finding and Development Costs, Excluding FDC 2015 2014 2013 2013-2015
Avg.

Total Proved
Reserve Additions (MMboe) 187.1 190.1 85.3
F&D Costs ($/boe) 7.76 10.68 13.68 10.05
F&D Recycle Ratio(1) 1.9 2.1 1.4 1.8

Total Proved Plus Probable
Reserve Additions (MMboe) 260.2 300.7 158.0
F&D Costs ($/boe) 5.58 6.75 7.38 6.47
F&D Recycle Ratio(1) 2.7 3.3 2.6 2.9
Finding and Development Costs, Including FDC
 2015 2014 2013 2013-2015
Avg.

Total Proved
Change in FDC ($ millions) (42.7) 935.8 388.7
Reserve Additions (MMboe) 187.1 190.1 85.3
F&D Costs ($/boe) 7.53 15.61 18.24 12.82
F&D Recycle Ratio(1) 2.0 1.4 1.1 1.4

Total Proved Plus Probable
Change in FDC ($ millions) (190.5) 1,430.3 878.1
Reserve Additions (MMboe) 260.2 300.7 158.0
F&D Costs ($/boe) 4.84 11.51 12.94 9.41
F&D Recycle Ratio(1) 3.1 2.0 1.5 2.0
Finding, Development and Acquisition Costs 
Finding, Development and Acquisition Costs, Excluding FDC
 2015 2014 2013 2013-2015 Avg.

Total Proved
Reserve Additions (MMboe) 228.1 197.1 94.6
FD&A Costs ($/boe) 8.34 9.04 13.91 9.62
FD&A Recycle Ratio(1) 1.8 2.5 1.4 1.9

Total Proved Plus Probable
Reserve Additions (MMboe) 308.9 306.9 179.4
FD&A Costs ($/boe) 6.16 5.80 7.33 6.29
FD&A Recycle Ratio(1) 2.5 3.9 2.6 2.9
Finding, Development and Acquisition Costs, Including FDC
 2015 2014 2013 2013-2015 Avg.

Total Proved
Change in FDC ($ millions) 21.7 919.3 341.1
Reserve Additions (MMboe) 228.1 197.1 94.6
FD&A Costs ($/boe) 8.43 13.71 17.52 12.09
FD&A Recycle Ratio(1) 1.8 1.6 1.1 1.5

Total Proved Plus Probable
Change in FDC ($ millions) (84.1) 1,410.8 808.3
Reserve Additions (MMboe) 308.9 306.9 179.4
FD&A Costs ($/boe) 5.89 10.40 11.84 8.97
FD&A Recycle Ratio(1) 2.6 2.2 1.6 2.1

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. 
Advisories & Contact
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, 2015, 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, 2016 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, 2015, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 30, 2016.

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 press 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, 2015, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2016.

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, 2015, 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, 2015 on SEDAR on or before March 30, 2016.

Per share information is based on the total common shares outstanding, after accounting for outstanding Company options, at year end 2015 and 2014, respectively.

BOE EQUIVALENCY

In this press 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.

F&D AND FD&A COSTS

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.

FORWARD-LOOKING INFORMATION

This press 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 press 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 press 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 press release includes references to a financial measure commonly used in the oil and gas industry, “cash flow”, which 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 terms “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 determined in accordance with GAAP as an indication of the Company’s performance. See “Non-GAAP Financial Measures” in the November 4, 2015 Management’s Discussion and Analysis for the definition and description of this term.


Estimated Drilling Inventory

This press 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 10,591 undrilled locations disclosed in this press release, 711 are proved undeveloped locations, 15 are proved non-producing locations, 468 are probable undeveloped locations, 2 are probable non-producing and 9,395 are unbooked. Proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. and Deloitte LLP as of December 31, 2015 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 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 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
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
gj gigajoule
gjs/d gigajoules per day
mbbls thousand 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
mmbbls million barrels
mmboe million barrels of oil equivalent
mmbtu million British thermal units
mmbtu/d million British thermal units per day
mmcf million cubic feet
mmcfpd or mmcf/d million cubic feet per day
MPa megapascal
mstboe thousand stock tank barrels of oil equivalent
NGL natural gas liquids
tcf trillion cubic feet

ABOUT TOURMALINE OIL CORP.

Tourmaline is a Canadian intermediate 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.

FOR FURTHER INFORMATION, PLEASE CONTACT:

Tourmaline Oil Corp.
Michael Rose
Chairman, President and Chief Executive Officer
(403) 266-5992

OR

Tourmaline Oil Corp.
Brian Robinson
Vice President, Finance and Chief Financial Officer
(403) 767-3587; robinson@tourmalineoil.com

OR

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

OR

Tourmaline Oil Corp.
Suite 3700, 250 – 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 266-5992
Facsimile: (403) 266-5952
Website: www.tourmalineoil.com
E-mail: info@tourmalineoil.com