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 |
Company |
Company |
Company |
Company Gross |
Company Net |
Company |
Company |
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 ($000s) |
|||||||||||||||||||||||
Before Future Income Taxes Discounted at |
After Future Income Taxes Discounted at (3) |
Unit Value Before |
||||||||||||||||||||||
0 |
5 |
10 |
15 |
20 |
0 |
5 |
10 |
15 |
20 |
($/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 |
Capital |
Abandonment |
Future Net |
Income |
Future Net |
||||||||
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 |
Light, Sweet Crude Edmonton |
Alberta Natural Gas Liquids |
||||||||||||||||
CAD/USD |
Constant |
Then |
Spec |
Edmonton |
Edmonton |
Edmonton |
||||||||||||
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 |
Midwest Price @ |
AECO/NIT Spot |
Alberta Plant Gate |
British Columbia |
||||||||||||||||
Spot |
||||||||||||||||||||
Year |
Constant 2018 $ |
Then |
Chicago |
Constant |
Then Current $Cdn/MMbtu |
ARP $Cdn/ |
Sumas Spot |
Westcoast Station 2 |
Spot Plant Gate |
|||||||||||
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 $26 million for 2017, 2016 and 2015 respectively. |
Finding and Development Costs
Finding and Development Costs, Excluding FDC |
2017 |
2016 |
2015 |
2015-2017 |
Total Proved |
||||
Reserve Additions (MMboe) |
272.8 |
126.4 |
187.1 |
|
F&D Costs ($/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 ($/boe) |
2.54 |
4.76 |
5.58 |
3.73 |
F&D Recycle Ratio(1) |
5.4 |
2.3 |
2.7 |
3.5 |
Finding and Development Costs, Including FDC |
2017 |
2016 |
2015 |
2015-2017 |
Total Proved |
||||
Change in FDC ($ 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 ($/boe) |
3.68 |
1.49 |
4.84 |
3.63 |
F&D Recycle Ratio(1) |
3.7 |
7.2 |
3.1 |
3.6 |
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, |
2017 |
2016 |
2015 |
2015-2017 |
Total Proved |
||||
Reserve Additions (MMboe) |
285.2 |
282.8 |
228.1 |
|
FD&A Costs ($/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 ($/boe) |
2.55 |
3.26 |
6.16 |
3.58 |
FD&A Recycle Ratio(1) |
5.3 |
3.3 |
2.5 |
3.7 |
Finding, Development and Acquisition Costs, |
2017 |
2016 |
2015 |
2015-2017 |
Total Proved |
||||
Change in FDC ($ 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.