CALGARY, Feb. 20, 2019 /CNW/ – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to report very strong total reserve growth, liquids reserve growth and a continued reserve value increase in the current depressed natural gas price environment. The Company executed on the 2017-2018 plan to concentrate almost entirely on internal EP growth and has produced the best reserve metrics in the Company’s 10 year history over the past two years.
RESERVE HIGHLIGHTS
Consistent Value Growth and Industry-Leading Efficiencies
PDP FD&A ($/boe) |
1P FD&A ($/boe) |
2P FD&A ($/boe) |
2P PV10 Annual Reserve Value Growth |
|||
Excl FDC |
Incl FDC |
Excl FDC |
Incl FDC |
|||
2018 |
9.11 |
4.91 |
6.79 |
3.59 |
5.15 |
$832.8 MM |
2015-2017 (Avg) |
11.94 |
7.06 |
8.12 |
3.58 |
5.16 |
$2.48 B |
PRODUCTION HIGHLIGHTS
FINANCIAL HIGHLIGHTS
EP UPDATE
______________________________ |
|
(1) |
Reserve NPV per share is calculated as the before tax net present value of the reserves at December 31, 2018 discounted at 10% divided by total diluted shares outstanding at December 31, 2018. |
(2) |
Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” in this release for additional information. All financial information is unaudited. See unaudited financial information section in this release. |
(3) |
Reserve replacement ratio is calculated by dividing the annual 2P reserve additions (including annual production) by annual production. |
(4) |
The capital reduction has not been reflected in the Company’s current formal guidance. The Company intends to update formal guidance, including these capital reductions, along with the year-end financial results in March 2019. |
2018 RESERVE SUMMARY
The following tables summarize the Company’s gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.
Reserves and Future Net Revenue Data (Forecast Prices and Costs)
Summary of Oil and Gas Reserves and |
|||||||||||||||||||||
Light & Medium Crude Oil |
Conventional Natural Gas |
Shale Natural Gas(2) |
Natural Gas Liquids |
Total Oil Equivalent |
|||||||||||||||||
Reserves Category |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company Gross (Mboe) |
Company Net (Mboe) |
|||||||||||
Proved Producing |
12,776 |
10,695 |
1,647,883 |
1,522,885 |
718,631 |
700,727 |
66,075 |
56,622 |
473,269 |
437,919 |
|||||||||||
Proved Developed Non-Producing |
1,842 |
1,511 |
93,816 |
86,327 |
189,425 |
187,149 |
12,455 |
11,135 |
61,504 |
58,225 |
|||||||||||
Proved Undeveloped |
25,008 |
20,897 |
1,927,661 |
1,802,825 |
1,310,008 |
1,254,523 |
106,988 |
97,913 |
671,607 |
628,368 |
|||||||||||
Total Proved Reserves |
39,626 |
33,103 |
3,669,359 |
3,412,037 |
2,218,064 |
2,142,398 |
185,518 |
165,670 |
1,206,381 |
1,124,512 |
|||||||||||
Total Probable Reserves |
42,421 |
34,475 |
2,402,017 |
2,202,990 |
3,423,238 |
3,114,362 |
237,681 |
205,613 |
1,250,977 |
1,126,313 |
|||||||||||
Total Proved Plus Probable |
82,046 |
67,578 |
6,071,376 |
5,615,028 |
5,641,302 |
5,256,760 |
423,198 |
371,283 |
2,457,358 |
2,250,826 |
Reserves Category |
Net Present Values Of Future Net Revenue ($000s) |
|||||||||||||||||||||||
Before Future Income Taxes Discounted at |
After Income Taxes Discounted at (3) |
Unit Value Before |
||||||||||||||||||||||
0 |
5 |
10 |
15 |
20 |
0 |
5 |
10 |
15 |
20 |
($/Boe) |
($/Mcfe) |
|||||||||||||
Proved Producing |
7,240,410 |
5,717,521 |
4,721,579 |
4,036,357 |
3,541,211 |
7,114,318 |
5,656,857 |
4,691,064 |
4,020,391 |
3,532,559 |
10.78 |
1.80 |
||||||||||||
Proved Developed Non-Producing |
1,028,081 |
762,593 |
601,144 |
495,218 |
421,209 |
753,006 |
598,008 |
498,946 |
429,756 |
378,150 |
10.32 |
1.72 |
||||||||||||
Proved Undeveloped |
8,822,179 |
5,638,372 |
3,838,123 |
2,730,228 |
2,000,951 |
6,469,863 |
4,075,075 |
2,723,454 |
1,895,281 |
1,352,929 |
6.11 |
1.02 |
||||||||||||
Total Proved Reserves |
17,090,670 |
12,118,486 |
9,160,845 |
7,261,803 |
5,963,372 |
14,337,187 |
10,329,941 |
7,913,463 |
6,345,428 |
5,263,638 |
8.15 |
1.36 |
||||||||||||
Total Probable Reserves |
21,980,983 |
11,338,472 |
6,772,624 |
4,457,988 |
3,135,558 |
16,081,110 |
8,219,331 |
4,847,751 |
3,146,492 |
2,181,518 |
6.01 |
1.00 |
||||||||||||
Total Proved Plus Probable |
39,071,654 |
23,456,959 |
15,933,470 |
11,719,791 |
9,098,929 |
30,418,297 |
18,549,272 |
12,761,214 |
9,491,920 |
7,445,156 |
7.08 |
1.18 |
Notes: |
|
(1) |
Tables may not add due to rounding. |
(2) |
Shale Natural Gas is required to be presented separately from Conventional Natural Gas as its own product type pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). While the Tourmaline Montney reserves do not strictly fit the definition of “shale gas” as defined in NI 51-101 because the natural gas is not “primarily adsorbed” as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure. |
(3) |
The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level. |
Total Future Net Revenue ($000s) |
||||||||||||||||
Reserves Category |
Revenue |
Royalties |
Operating |
Capital |
Abandonment |
Future Net |
Income |
Future Net |
||||||||
Proved Producing |
11,832,962 |
981,507 |
3,366,201 |
4,000 |
240,845 |
7,240,410 |
126,092 |
7,114,318 |
||||||||
Proved Developed Non-Producing |
1,616,557 |
125,184 |
387,629 |
55,012 |
20,650 |
1,028,081 |
275,075 |
753,006 |
||||||||
Proved Undeveloped |
17,752,646 |
1,347,202 |
3,500,253 |
3,905,987 |
177,026 |
8,822,179 |
2,352,316 |
6,469,863 |
||||||||
Total Proved |
31,202,165 |
2,453,892 |
7,254,083 |
3,964,999 |
438,520 |
17,090,670 |
2,753,483 |
14,337,187 |
||||||||
Total Probable |
39,628,699 |
4,567,376 |
9,127,569 |
3,657,044 |
295,726 |
21,980,983 |
5,899,874 |
16,081,110 |
||||||||
Total Proved Plus |
70,830,864 |
7,021,268 |
16,381,652 |
7,622,043 |
734,246 |
39,071,654 |
8,653,357 |
30,418,297 |
Notes: |
|
(1) |
Table may not add due to rounding. |
(2) |
The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level. |
Summary of Pricing and Inflation Rate Assumptions |
||||||||||||||||||||||
Year |
Crude Oil and Natural Gas Liquids Pricing |
|||||||||||||||||||||
NYMEX WTI Near Month Futures Contract Crude Oil at Cushing, Oklahoma |
Alberta Natural Gas Liquids |
|||||||||||||||||||||
Inflation%(2) |
CAD/USD |
Constant |
Then |
MSW, Light Crude Oil |
Spec |
Edmonton |
Edmonton |
Edmonton |
||||||||||||||
2019 |
0.0 |
0.7567 |
58.58 |
58.58 |
67.30 |
6.82 |
26.13 |
27.32 |
70.10 |
|||||||||||||
2020 |
2.0 |
0.7817 |
63.33 |
64.60 |
75.84 |
8.40 |
31.27 |
41.10 |
79.21 |
|||||||||||||
2021 |
2.0 |
0.7967 |
65.55 |
68.20 |
80.17 |
9.98 |
34.58 |
49.28 |
83.33 |
|||||||||||||
2022 |
2.0 |
0.8033 |
66.90 |
71.00 |
83.22 |
11.22 |
37.25 |
55.65 |
86.20 |
|||||||||||||
2023 |
2.0 |
0.8067 |
67.27 |
72.81 |
85.34 |
11.89 |
38.73 |
57.92 |
88.16 |
|||||||||||||
2024 |
2.0 |
0.8083 |
67.56 |
74.59 |
87.33 |
12.22 |
39.75 |
59.27 |
90.20 |
|||||||||||||
2025 |
2.0 |
0.8083 |
67.86 |
76.42 |
89.50 |
12.45 |
40.76 |
60.77 |
92.43 |
|||||||||||||
2026 |
2.0 |
0.8083 |
68.25 |
78.40 |
91.89 |
12.71 |
41.93 |
62.37 |
94.87 |
|||||||||||||
2027 |
2.0 |
0.8083 |
68.27 |
79.98 |
93.76 |
12.96 |
42.84 |
63.65 |
96.80 |
|||||||||||||
2028 |
2.0 |
0.8083 |
68.27 |
81.59 |
95.68 |
13.28 |
43.80 |
64.97 |
98.79 |
|||||||||||||
2029 |
2.0 |
0.8083 |
68.27 |
83.22 |
97.57 |
13.53 |
44.73 |
66.26 |
100.76 |
|||||||||||||
2030 |
2.0 |
0.8083 |
68.26 |
84.87 |
99.52 |
13.85 |
45.64 |
67.56 |
102.77 |
|||||||||||||
2031 |
2.0 |
0.8083 |
68.26 |
86.57 |
101.52 |
14.10 |
46.56 |
68.92 |
104.84 |
|||||||||||||
2032 |
2.0 |
0.8083 |
68.26 |
88.30 |
103.55 |
14.36 |
47.46 |
70.33 |
106.94 |
|||||||||||||
2033 |
2.0 |
0.8083 |
68.27 |
90.08 |
105.65 |
14.68 |
48.44 |
71.72 |
109.10 |
|||||||||||||
2034 |
2.0 |
0.8083 |
68.27 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
Year |
Natural Gas and Sulphur Pricing |
|||||||||||||||||||
Henry Hub Nymex |
Alberta Plant Gate |
British Columbia |
||||||||||||||||||
Midwest Price @ |
Spot |
|||||||||||||||||||
Constant |
Then |
AECO/NIT Spot |
Constant |
Then |
ARP $Cdn/ |
Sumas |
Westcoast |
Spot Plant |
||||||||||||
2019 |
3.00 |
3.00 |
2.91 |
1.88 |
1.67 |
1.67 |
1.67 |
2.47 |
1.42 |
1.24 |
||||||||||
2020 |
3.07 |
3.13 |
3.04 |
2.31 |
2.06 |
2.10 |
2.10 |
2.59 |
1.94 |
1.75 |
||||||||||
2021 |
3.20 |
3.33 |
3.24 |
2.74 |
2.42 |
2.52 |
2.52 |
2.88 |
2.41 |
2.22 |
||||||||||
2022 |
3.30 |
3.51 |
3.41 |
3.05 |
2.66 |
2.83 |
2.83 |
3.09 |
2.76 |
2.56 |
||||||||||
2023 |
3.35 |
3.62 |
3.53 |
3.21 |
2.76 |
2.99 |
2.99 |
3.20 |
2.93 |
2.74 |
||||||||||
2024 |
3.35 |
3.70 |
3.61 |
3.31 |
2.79 |
3.08 |
3.08 |
3.28 |
3.06 |
2.86 |
||||||||||
2025 |
3.35 |
3.77 |
3.68 |
3.39 |
2.80 |
3.15 |
3.15 |
3.35 |
3.12 |
2.91 |
||||||||||
2026 |
3.35 |
3.85 |
3.76 |
3.46 |
2.80 |
3.22 |
3.22 |
3.43 |
3.19 |
2.98 |
||||||||||
2027 |
3.35 |
3.92 |
3.83 |
3.54 |
2.81 |
3.29 |
3.29 |
3.50 |
3.26 |
3.06 |
||||||||||
2028 |
3.35 |
4.01 |
3.91 |
3.62 |
2.83 |
3.38 |
3.38 |
3.59 |
3.35 |
3.14 |
||||||||||
2029 |
3.34 |
4.08 |
3.98 |
3.70 |
2.82 |
3.44 |
3.44 |
3.65 |
3.42 |
3.21 |
||||||||||
2030 |
3.35 |
4.16 |
4.07 |
3.78 |
2.83 |
3.52 |
3.52 |
3.73 |
3.51 |
3.28 |
||||||||||
2031 |
3.35 |
4.25 |
4.16 |
3.85 |
2.83 |
3.58 |
3.58 |
3.82 |
3.57 |
3.34 |
||||||||||
2032 |
3.34 |
4.33 |
4.23 |
3.92 |
2.82 |
3.65 |
3.65 |
3.89 |
3.63 |
3.40 |
||||||||||
2033 |
3.35 |
4.42 |
4.32 |
4.00 |
2.83 |
3.73 |
3.73 |
3.97 |
3.72 |
3.48 |
||||||||||
2034 |
3.35 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
2.83 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
Notes: |
|
(1) |
Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the GLJ Reserve Report and Deloitte in the Deloitte Reserve Report, were an average of forecast prices and costs published by GLJ, Sproule Associates Ltd. and McDaniel & Associates Consultants Ltd. effective January 1, 2019 (each of which is available on their respective websites at www.gljpc.com, www.sproule.com and www.mcdan.com). GLJ assigns a value to the Company’s existing physical diversification contracts for natural gas for consuming markets at Dawn, Chicago, Ventura, Malin and PG&E based upon GLJ’s forecasted differential to NYMEX Henry Hub, contracted volumes, and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2018. |
(2) |
Inflation rates used for forecasting prices and costs. |
(3) |
Exchange rates used to generate the benchmark reference prices in this table. |
Reserves Performance Ratios
The following tables highlight Tourmaline’s reserves, F&D and FD&A costs as well as the associated recycle ratios.
Reserves, Capital Expenditures(2) and Cash Flow(1)(2)
As at December 31, |
2018 |
2017 |
2016 |
Reserves (Mboe) |
|||
Proved Producing |
473,269 |
436,208 |
351,931 |
Total Proved |
1,206,381 |
1,055,702 |
858,932 |
Proved Plus Probable |
2,457,358 |
2,216,206 |
1,746,822 |
Capital Expenditures ($ millions) |
|||
Exploration and Development(3) |
1,261 |
1,364 |
756 |
Net Acquisitions (Dispositions) |
(47) |
58 |
1,545 |
Total Capital Expenditures |
1,214 |
1,422 |
2,301 |
Cash Flow ($/boe) |
|||
Cash Flow |
13.47 |
13.63 |
10.77 |
Cash Flow – Three Year Average |
12.80 |
13.11 |
15.17 |
Notes: |
|
(1) |
Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” below and in the Company’s most recently filed Management’s Discussion and Analysis for further discussion. |
(2) |
2018 Financial numbers are unaudited. |
(3) |
Includes unaudited capitalized G&A of $30 million, $27 million and $25 million for 2018, 2017 and 2016 respectively. |
Finding and Development Costs
Finding and Development Costs, Excluding FDC |
2018 |
2017 |
2016 |
3-Year Avg. |
Total Proved |
||||
Reserve Additions (MMboe) |
241.0 |
272.8 |
126.4 |
|
F&D Costs ($/boe) |
5.24 |
5.00 |
5.98 |
5.28 |
F&D Recycle Ratio(1) |
2.6 |
2.7 |
1.8 |
2.4 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
326.6 |
537.5 |
158.7 |
|
F&D Costs ($/boe) |
3.86 |
2.54 |
4.76 |
3.31 |
F&D Recycle Ratio(1) |
3.5 |
5.4 |
2.3 |
3.9 |
Finding and Development Costs, Including FDC |
2018 |
2017 |
2016 |
3-Year Avg. |
Total Proved |
||||
Change in FDC ($ millions) |
441.7 |
481.1 |
(239.9) |
|
Reserve Additions (MMboe) |
241.0 |
272.8 |
126.4 |
|
F&D Costs ($/boe) |
7.07 |
6.76 |
4.08 |
6.35 |
F&D Recycle Ratio(1) |
1.9 |
2.0 |
2.6 |
2.0 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
486.3 |
612.1 |
(518.6) |
|
Reserve Additions (MMboe) |
326.6 |
537.5 |
158.7 |
|
F&D Costs ($/boe) |
5.35 |
3.68 |
1.49 |
3.87 |
F&D Recycle Ratio(1) |
2.5 |
3.7 |
7.2 |
3.3 |
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, Excluding FDC |
2018 |
2017 |
2016 |
3-Year Avg. |
Total Proved |
||||
Reserve Additions (MMboe) |
247.4 |
285.2 |
282.8 |
|
FD&A Costs ($/boe) |
4.91 |
4.98 |
8.14 |
6.05 |
FD&A Recycle Ratio(1) |
2.7 |
2.7 |
1.3 |
2.1 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
337.9 |
557.8 |
706.5 |
|
FD&A Costs ($/boe) |
3.59 |
2.55 |
3.26 |
3.08 |
FD&A Recycle Ratio(1) |
3.7 |
5.3 |
3.3 |
4.2 |
Finding, Development and Acquisition Costs, Including FDC |
2018 |
2017 |
2016 |
3-Year Avg. |
Total Proved |
||||
Change in FDC ($ millions) |
465.3 |
515.7 |
304.0 |
|
Reserve Additions (MMboe) |
247.4 |
285.2 |
282.8 |
|
FD&A Costs ($/boe) |
6.79 |
6.79 |
9.21 |
7.63 |
FD&A Recycle Ratio(1) |
2.0 |
2.0 |
1.2 |
1.7 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
526.8 |
678.3 |
1,894.0 |
|
Reserve Additions (MMboe) |
337.9 |
557.8 |
706.5 |
|
FD&A Costs ($/boe) |
5.15 |
3.76 |
5.94 |
5.02 |
FD&A Recycle Ratio(1) |
2.6 |
3.6 |
1.8 |
2.6 |
Note: |
|
(1) |
The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year. |
INVESTOR RELATIONS ACTIVITIES
Tourmaline is scheduled to press release full-year 2018 financial results after the close of markets on March 5, 2019. Conference call to be held on March 6, 2019 at 9:00 a.m. Details can be found on Tourmaline’s website at www.tourmalineoil.com.
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