CALGARY, Feb. 22, 2017 /CNW/ – 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 1,746.8 mmboe during 2016, a 58% increase over 2015 reserves of 1,108.3 mmboe and a 64% increase (34% per diluted share) before taking into account annual production of 68.0 mmboe. Total proved (“TP”) reserves increased 44% and proved developed producing (“PDP”) reserves increased 60% over 2015 before taking into account annual production of 68.0 mmboe.
- 2016 2P reserve net present value (PV10 before tax) increase of $4.46 billion over 2015; the estimated 2P reserve NAV(1) (PV10 before tax) at year-end 2016 was $47.11 per diluted share.
- Tourmaline now has 2P reserves of 8.93 TCF of natural gas and 258.4 mmbbls of oil, condensate and natural gas liquids at December 31, 2016.
- 2P reserve replacement(2) of 10.4 times for 2016 based on 2P reserve additions of 706.5 mmboe before taking into account 2016 annual production.
- 2016 2P finding, development and acquisition (“FD&A”) costs of $5.94/boe including changes in future development capital (“FDC”), 2016 TP FD&A costs of $9.21/boe including FDC and 2016 PDP FD&A costs of $14.69/boe.
- In 2016, Tourmaline’s E&P capital program of approximately $730.7 million generated over 75,000 boe/d of new production resulting in capital efficiency of approximately $9,500 boe/d, an improvement of 39% over 2015 E&P capital efficiency of approximately $15,500 boe/d.
- After eight years, Tourmaline now has 1.75 billion boe of independently recognized 2P reserves at year-end 2016, essentially all of which will be serviced by Company-owned infrastructure. The Company has also produced 230.6 mmboe during the first eight years of operation.
- 2016 2P recycle ratio of 1.8 times based on 2P FD&A of $5.94/boe (including FDC) and 2016 estimated cash flow(3) of $10.77/boe. Q4 2016 estimated cash flow was $14.31/boe as gas prices recovered significantly.
- 2016 full-year average production of 185,672 boepd was 20% higher than 2015 average production of 154,403 boepd (10% per diluted share).
- Current daily Company production is approximately 235,000 boepd.
- The Company has only 1,819 gross locations recognized in the 2016 reserve report of a well-defined future development drilling inventory of 14,713 gross locations. The infrastructure skeleton, which is now complete in all three core areas, is in general reach of all of the future locations.
__________________________
(1) 2P Reserve NAV per share is calculated as 2P NPV10 reserve value divided by total diluted shares outstanding at December 31, 2016.
(2) Reserve replacement is calculated by dividing the annual 2P reserve additions by annual production.
(3) See Non-GAAP Financial Measures.
RESERVE REPORT OVERVIEW
Record Reserve Additions in 2016
The Company increased 2P reserves by 64% in 2016 to 1.75 billion boe (34% per diluted share), total proved reserves by 44% to 858.9 mmboe and PDP reserves by 60% to 351.9 mmboe, prior to annual 2016 production of 68.0 mmboe. The net 2016 2P addition of 638.5 mmboe in a single year is a Company record as was the total proved reserve addition of 214.9 mmboe. This was driven in part by the Shell Canada (“Shell”) acquisition that was completed in November 2016. The acquisition was weighted to 2P reserves (PDP – 51.0 mmboe, TP – 121.6 mmboe, 2P – 483.9 mmboe) due primarily to the undeveloped nature of the Gundy BC Montney assets. Tourmaline is executing a three-year development plan that will convert the majority of the 2P reserve base at Gundy to proved reserves.
Historical Reserve Growth and Value Creation
Tourmaline consistently achieves top decile annual reserve growth. Three-year total reserve growth is 224% for 2P reserves (135% per diluted share), 224% for total proved reserves (135% per diluted share) and 323% for PDP reserves (207% per diluted share), before taking into account three-year total production of 165.5 mmboe. 2P reserve net present value increased by $4.46 billion in 2016 to $12.71 billion (PV10 before tax). Proved plus probable reserve NAV (PV10 before tax) at year-end 2016 is now $47.11 per diluted share, an increase of 26% from 2015.
Historical Reserve Category Conversion
Over the past eight years, Tourmaline has consistently and systematically converted 2P reserves to proven reserves and PDP reserves. The 2P reserves to proved reserves conversion occurs over approximately two years and the 2P reserves to PDP reserves occurs over approximately four years. Of the 140 wells rig-released by the Company in 2016, 88 of those wells were conversions of existing undeveloped locations. Similarly in 2015, 93 of the 181 wells rig-released were conversions from the undeveloped reserve category. PDP reserves grew by 60% in 2016 prior to annual 2016 production of 68.0 mmboe, despite 41 fewer wells drilled during the year. Tourmaline estimates further Q1 2017 PDP reserve additions of 52.0 mmboe as approximately 70-75 wells (gross) will be tied-in during the quarter. FDC for 2P reserves in the 2016 report of $6.4 billion represents under four years of forecast future cash flow. For 2016, 2P FDC increased by $1.9 billion, which includes $2.2 billion attributable to the Deep Basin and Gundy assets acquired from Shell Canada partially offset by a decrease of 2P FDC of $518.6 million reflecting significant decreases in capital costs.
Balance as at December 31, |
2016 |
2015 |
2014 |
2013 |
2012 |
2011 |
5 Year |
|
Reserves (Mboe) |
||||||||
Proved Producing |
351,931 |
263,227 |
177,811 |
122,327 |
91,952 |
67,312 |
423% |
|
Total Proved |
858,932 |
644,059 |
472,296 |
316,462 |
249,210 |
149,049 |
476% |
|
Proved plus Probable |
1,746,822 |
1,108,279 |
855,793 |
590,099 |
438,038 |
270,069 |
547% |
Reserve Replacement
Proved plus probable reserves were replaced by 1,040% in 2016, a record for the Company, before taking into account 2016 annual production of 68.0 mmboe. Total proved reserves were replaced by 416% in 2016 and PDP reserves were replaced by 231%, before production. The three-year 2P reserve replacement ratio is 799%, before taking into account three-year production. Total proved reserve life is a conservative 9.3 years, consistent with anticipated 2017 production range of 240,000 – 260,000 boepd.
Reserve Addition Costs, Recycle Ratios
The 2P FD&A costs (including FDC) were $5.94/boe in 2016 and total proved reserve FD&A costs (including FDC) were $9.21/boe yielding annual recycle ratios of 1.8 times for 2P and 1.2 times for TP, respectively. Excluding acquisitions and divestitures (“A&D”), PDP finding and development (“F&D”) costs (including FDC) were $8.59/boe in 2016 yielding a PDP recycle ratio of 1.3 times. Three-year average 2P FD&A costs (including FDC) are now $6.96/boe as the Company continues to systematically improve these metrics over time. E&P capital efficiency in 2016, excluding A&D, was approximately $9,500 boepd.
Technical Revisions
Proved plus probable technical revisions in 2016 relating to reserve bookings in previous years were 10.7 mmboe. This is the fifth consecutive year in which the Company has realized positive technical revisions to pre-existing reports. This is primarily driven by continued improvements in well performance in all three core areas.
Gas, Oil, Condensate and Liquids Reserves
Tourmaline now has a 2P natural gas reserve base of 8.93 TCF, one of the largest in Canada. The Company has approximately 12% of the existing well defined future drilling inventory recognized in the 2016 report (1,819 gross locations booked of a total inventory of 14,713 locations). All three core areas are largely de-risked from a subsurface standpoint with over 200 horizontal wells drilled in each of the three core areas to date. This significant, independently recognized reserve base is anticipated to double in approximately 5 years assuming a drilling pace comparable to 2017. The current Company-operated infrastructure skeleton is in general reach of all the locations in the 2016 reserve report.
Oil, condensate and NGL reserves are 258.4 mmboe at year-end 2016, a 202% increase over the past 3 years. With expected total liquid production in excess of 40,000 bpd in 2017, Tourmaline is now a top ten Canadian liquids producer, as well as the second largest producer of Canadian natural gas (current daily gas production of between 1.2 and 1.3 bcf/day).
PRODUCTION UPDATE
- Current daily production is approximately 235,000 boepd.
- The Company expects average Q1 2017 production of between 230,000 and 235,000 boepd.
- Anticipated average annual production guidance for 2017 of 240,000-260,000 boepd, including over 40,000 bpd of oil, condensate and NGL production. The Company has increased the production range to better account for unscheduled firm service reductions throughout the year.
- The Doe 2-11 gas plant remains on schedule for a late March/early April start-up, adding an additional 12,500 boepd of total production including 3,000-3,500 bpd of condensate.
- Tourmaline has added approximately 3,000 boepd to the Shell Deep Basin assets since acquiring them in November 2016 through existing well and plant optimization activities. Drilling operations have now commenced on two pads on the Shell Deep Basin acreage.
- An incremental 6,000-7,000 bpd of light oil production from the Peace River High Charlie Lake complex is also expected to come on-stream during the first quarter, some of which was deferred from Q4 2016.
- In total, the Company expects to bring 75-80 new wells on-stream during the first quarter of 2017.
- 2016 average production was 185,672 boepd, approximately 2% less than annual guidance, with Q4 2016 average production of 191,814 boepd. Q4 production was negatively impacted by firm service interruptions on all three major pipeline systems as well as weather related delays during the first half of the fourth quarter. These restrictions postponed certain tie-ins into Q1 2017. Facility capital deferrals (pipeline loops, in-field compression) made in the first half of 2016 led to some in-field production bottlenecks in Q4 2016 given the extremely high deliverability of a number of the new wells. These pipeline looping and compression projects are being completed in Q1 2017, eliminating these bottlenecks.
- 2016 annual production growth was 20% over 2015, amongst the best in the sector.
EP UPDATE
- Tourmaline is currently operating 17 drilling rigs with 11 of the rigs in the Alberta Deep Basin, 3 rigs in the NEBC Montney gas-condensate complexes and 3 rigs on the Peace River High.
- The Company continues to deliver some of the strongest wells historically in all three core areas at continuing record low drill and complete capital costs.
- The Minehead 16-15-49-19W5M Notikewin horizontal well in the Alberta Deep Basin averaged 29.7 mmcfpd over the first 60 days on-stream with 2.20 bcf of cumulative gas production to date.
- The Kakwa 12-35-61-6W6M Falher C horizontal well in the Alberta Deep Basin averaged 20.5 mmcfpd over the first 50 days on-stream, with 27,531 bbls of condensate produced to date (26 bbls/mmcf, 249 bbls/day).
- The Minehead 15-25-50-20W5M Falher C horizontal in the Alberta Deep Basin has averaged 11.3 mmcfpd over the first 60 days of production.
- The Ansel 15-31-50-19W5M Wilrich horizontal in the Alberta Deep Basin has averaged 13.4 mmcfpd over the first 60 days of production.
- The C12-21-80-15W6M Upper Montney horizontal well in Sunrise-Dawson BC averaged 1,461 boepd over the first 60 days of production (8.0 mmcfpd of gas and 128 bbls/day of condensate and liquids). The B12-21-80-15W6M Middle Montney horizontal averaged 1,398 boepd over the first 60 days of production (6.9 mmcfpd of gas and 248 bbls/day of condensate and liquids). The A13-21-80-15W6M Lower Montney Turbidite horizontal averaged 775 boepd over the first 60 days of production (1.84 mmcfpd of gas and 469 bbls/day of condensate and liquids). All three wells were brought on-stream during November and are restricted to flowing up tubing. Tourmaline’s previous operational practice was to flow NEBC Montney wells unrestricted up casing for the first few months of production and run tubing at a later date. The new field practice saves approximately $200,000 in per pad costs, but reduces IP 30 and IP 90 production rates.
- The Spirit River 16-14-77-8W6M Lower Charlie Lake well averaged 1,158 boepd (841 bpd oil and 1.9 mmcfpd of gas) over the first 90 days of production. The well has produced 80,330 bbls of oil after 103 days of production. The Company is bringing another 5 Lower Charlie Lake wells on-stream in the first quarter.
- The Mulligan 4-13-83-8W6M Upper Charlie Lake well has averaged 798 boepd (631 bpd oil and 1.0 mmcfpd of gas) over the first 90 days of production and has now produced 63,257 bbls of oil after 102 days of production. The Company has 4 additional multi-well pads to bring on-stream at Mulligan during the first quarter.
- Development of the Gundy BC Montney property has commenced with the first rig already drilling. A second rig will arrive in mid-summer and the Company expects to have 75 wells drilled, completed and tied into the 200 mmcfpd facility that the Company is planning for the second half of 2018.
2016/2017 CAPITAL PROGRAM
- 2016 EP capital spending was $730.7 million, consistent with full-year cash flow.
- The 2017 EP capital program of $1.3 billion includes a 17-rig drilling program that will deliver 35% annual production growth for less than anticipated 2017 cash flow of $1.4 billion ($3.15/mcf AECO 2017 forecast natural gas price).
- The Company expects an exit 2017 debt-to-cash flow of approximately 1.0 times.
MARKETING AND HEDGING
- For 2017, Tourmaline has approximately 265 mmcfpd hedged at a weighted average fixed price of $3.11/mcf (AECO) and an additional 134 mmcfpd of basis differential at a weighted average of $0.62 Cdn/mcf.
- In addition, for 2017, 235 mmcfpd is sold to export markets attracting prices similar to the prevailing U.S. NYMEX prices. The export component is scheduled to grow to 340 mmcfpd by exit 2018.
- 520 mmcfpd of Tourmaline’s 2017 forecast gas production is exposed to short-term AECO prices, 120 mmcfpd is priced at Station 2, and 40 mmcfpd is priced at Sumas, BC.
2016 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, 2016 |
||||||||||||||||||||
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 Gross |
Company Net |
Company Gross (Mboe) |
Company Net (Mboe) |
||||||||||
Proved Developed Producing |
8,259 |
6,836 |
1,333,542 |
1,229,132 |
505,572 |
471,239 |
37,141 |
30,677 |
351,931 |
320,920 |
||||||||||
Proved Developed Non-Producing |
425 |
364 |
71,567 |
65,260 |
73,281 |
69,321 |
3,414 |
2,926 |
27,981 |
25,720 |
||||||||||
Proved Undeveloped |
18,213 |
15,244 |
1,560,004 |
1,444,218 |
852,666 |
789,754 |
58,695 |
52,564 |
479,020 |
440,136 |
||||||||||
Total Proved Reserves |
26,898 |
22,444 |
2,965,113 |
2,738,610 |
1,431,519 |
1,330,315 |
99,250 |
86,167 |
858,932 |
786,777 |
||||||||||
Total Probable Reserves |
27,447 |
22,647 |
2,004,129 |
1,802,306 |
2,529,840 |
2,247,300 |
104,777 |
89,140 |
887,891 |
786,727 |
||||||||||
Total Proved Plus Probable Reserves |
54,344 |
45,092 |
4,969,243 |
4,540,916 |
3,961,358 |
3,577,615 |
204,027 |
175,307 |
1,746,822 |
1,573,504 |
Net Present Values Of Future Net Revenue ($000s) |
||||||||||||||||||||||||
Before Future Income Taxes Discounted at |
After Future Income Taxes Discounted at (3) |
Unit Value Before Income Tax Discounted |
||||||||||||||||||||||
Reserves Category |
0 |
5 |
10 |
15 |
20 |
0 |
5 |
10 |
15 |
20 |
($/Mcfe) |
($/Boe) |
||||||||||||
Proved Developed Producing |
6,007,635 |
4,785,453 |
3,962,143 |
3,398,090 |
2,993,090 |
6,007,635 |
4,785,453 |
3,962,143 |
3,398,090 |
2,993,090 |
2.06 |
12.35 |
||||||||||||
Proved Developed Non-Producing |
537,122 |
404,308 |
323,230 |
269,716 |
232,093 |
537,122 |
404,308 |
323,230 |
269,716 |
232,093 |
2.09 |
12.57 |
||||||||||||
Proved Undeveloped |
7,030,367 |
4,626,831 |
3,248,018 |
2,386,932 |
1,811,983 |
5,203,885 |
3,452,904 |
2,436,399 |
1,794,495 |
1,361,532 |
1.23 |
7.38 |
||||||||||||
Total Proved Reserves |
13,575,124 |
9,816,592 |
7,533,390 |
6,054,737 |
5,037,165 |
11,748,642 |
8,642,665 |
6,721,772 |
5,462,301 |
4,586,715 |
1.60 |
9.57 |
||||||||||||
Total Probable Reserves |
16,506,314 |
8,619,703 |
5,172,017 |
3,411,853 |
2,403,437 |
12,142,663 |
6,262,189 |
3,695,293 |
2,393,053 |
1,654,009 |
1.10 |
6.57 |
||||||||||||
Total Proved Plus Probable Reserves |
30,081,438 |
18,436,295 |
12,705,407 |
9,466,590 |
7,440,602 |
23,891,305 |
14,904,855 |
10,417,064 |
7,855,354 |
6,240,724 |
1.35 |
8.07 |
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. Prior to the Company’s December 31, 2015 reserve report, Montney gas was 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, 2016 |
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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 |
9,959,761 |
919,608 |
2,842,234 |
– |
190,284 |
6,007,635 |
– |
6,007,635 |
||||||||
Proved Developed Non-Producing |
802,207 |
72,607 |
142,404 |
40,781 |
9,293 |
537,122 |
– |
537,122 |
||||||||
Proved Undeveloped |
13,965,981 |
1,218,611 |
2,649,199 |
2,947,285 |
120,520 |
7,030,367 |
1,826,481 |
5,203,885 |
||||||||
Total Proved |
24,727,950 |
2,210,825 |
5,633,837 |
2,988,066 |
320,097 |
13,575,124 |
1,826,481 |
11,748,642 |
||||||||
Total Probable |
31,464,890 |
3,805,153 |
7,492,904 |
3,429,046 |
231,473 |
16,506,314 |
4,363,651 |
12,142,663 |
||||||||
Total Proved Plus Probable |
56,192,840 |
6,015,978 |
13,126,742 |
6,417,111 |
551,571 |
30,081,438 |
6,190,132 |
23,891,305 |
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 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 |
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Forecast Prices and Costs (1) |
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Crude Oil and Natural Gas Liquids Pricing |
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NYMEX WTI Near Month |
Light, Sweet Crude |
Alberta Natural Gas Liquids |
||||||||||||||||
Year |
Inflation(2) |
CAD/USD |
Constant |
Then |
Spec Ethane |
Edmonton |
Edmonton |
Edmonton |
||||||||||
2017 |
0.7 |
0.7600 |
55.00 |
55.00 |
68.24 |
11.16 |
24.82 |
47.01 |
70.95 |
|||||||||
2018 |
2.0 |
0.7900 |
59.71 |
60.90 |
73.16 |
10.26 |
26.16 |
52.53 |
75.40 |
|||||||||
2019 |
2.0 |
0.8167 |
62.93 |
65.47 |
76.25 |
10.61 |
27.70 |
54.57 |
78.72 |
|||||||||
2020 |
2.0 |
0.8333 |
65.14 |
69.13 |
79.37 |
11.90 |
29.10 |
57.49 |
81.52 |
|||||||||
2021 |
2.0 |
0.8500 |
67.63 |
73.21 |
82.56 |
12.58 |
30.61 |
60.83 |
84.77 |
|||||||||
2022 |
2.0 |
0.8500 |
68.10 |
75.19 |
84.85 |
12.96 |
31.80 |
62.55 |
87.17 |
|||||||||
2023 |
2.0 |
0.8500 |
68.54 |
77.19 |
87.15 |
13.41 |
33.01 |
64.24 |
89.44 |
|||||||||
2024 |
2.0 |
0.8500 |
68.97 |
79.23 |
89.50 |
13.82 |
34.26 |
66.00 |
91.86 |
|||||||||
2025 |
2.0 |
0.8500 |
69.37 |
81.28 |
91.89 |
14.07 |
35.54 |
67.74 |
94.67 |
|||||||||
2026 |
2.0 |
0.8500 |
69.78 |
83.39 |
94.01 |
14.40 |
36.73 |
69.31 |
96.73 |
|||||||||
2027 |
2.0 |
0.8500 |
69.75 |
85.03 |
95.85 |
14.72 |
37.82 |
70.69 |
98.66 |
|||||||||
2028 |
2.0 |
0.8500 |
69.75 |
86.73 |
97.78 |
15.04 |
38.59 |
72.10 |
100.62 |
|||||||||
2029 |
2.0 |
0.8500 |
69.77 |
88.48 |
99.74 |
15.29 |
39.36 |
73.56 |
102.65 |
|||||||||
2030 |
2.0 |
0.8500 |
69.77 |
90.26 |
101.76 |
15.61 |
40.14 |
75.03 |
104.73 |
|||||||||
2031 |
2.0 |
0.8500 |
69.77 |
92.06 |
103.78 |
15.94 |
40.97 |
76.53 |
106.81 |
|||||||||
2032 |
2.0 |
0.8500 |
69.77 |
+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 |
Midwest Price @ |
AECO/NIT Spot |
Alberta Plant Gate |
British Columbia |
||||||||||||||||
Spot |
||||||||||||||||||||
Constant |
Then |
Constant |
Then |
ARP $Cdn/ |
Sumas Spot |
Westcoast |
Spot Plant |
|||||||||||||
2017 |
3.50 |
3.50 |
3.55 |
3.43 |
3.20 |
3.20 |
3.20 |
3.02 |
3.00 |
2.84 |
||||||||||
2018 |
3.24 |
3.30 |
3.35 |
3.17 |
2.88 |
2.94 |
2.94 |
2.87 |
2.78 |
2.62 |
||||||||||
2019 |
3.29 |
3.42 |
3.47 |
3.26 |
2.91 |
3.03 |
3.03 |
3.01 |
2.94 |
2.78 |
||||||||||
2020 |
3.53 |
3.75 |
3.80 |
3.67 |
3.23 |
3.43 |
3.43 |
3.44 |
3.35 |
3.18 |
||||||||||
2021 |
3.66 |
3.96 |
4.01 |
3.86 |
3.34 |
3.62 |
3.62 |
3.71 |
3.54 |
3.37 |
||||||||||
2022 |
3.69 |
4.07 |
4.12 |
3.97 |
3.38 |
3.73 |
3.73 |
3.82 |
3.65 |
3.48 |
||||||||||
2023 |
3.73 |
4.20 |
4.25 |
4.11 |
3.42 |
3.86 |
3.86 |
3.95 |
3.76 |
3.59 |
||||||||||
2024 |
3.74 |
4.30 |
4.35 |
4.23 |
3.46 |
3.98 |
3.98 |
4.05 |
3.88 |
3.71 |
||||||||||
2025 |
3.73 |
4.37 |
4.42 |
4.31 |
3.46 |
4.05 |
4.05 |
4.12 |
3.96 |
3.79 |
||||||||||
2026 |
3.73 |
4.46 |
4.51 |
4.41 |
3.47 |
4.15 |
4.15 |
4.21 |
4.06 |
3.89 |
||||||||||
2027 |
3.73 |
4.55 |
4.60 |
4.51 |
3.48 |
4.24 |
4.24 |
4.31 |
4.16 |
3.98 |
||||||||||
2028 |
3.74 |
4.65 |
4.70 |
4.60 |
3.48 |
4.33 |
4.33 |
4.40 |
4.24 |
4.07 |
||||||||||
2029 |
3.73 |
4.73 |
4.78 |
4.68 |
3.48 |
4.41 |
4.41 |
4.47 |
4.32 |
4.14 |
||||||||||
2030 |
3.73 |
4.82 |
4.87 |
4.77 |
3.48 |
4.50 |
4.50 |
4.56 |
4.41 |
4.23 |
||||||||||
2031 |
3.73 |
4.92 |
4.97 |
4.87 |
3.48 |
4.59 |
4.59 |
4.66 |
4.51 |
4.32 |
||||||||||
2032 |
3.73 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
3.48 |
+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, 2017 (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 and Cash Flow(1)(2)
As at December 31, |
2016 |
2015 |
2014 |
Reserves (Mboe) |
|||
Proved Producing |
351,931 |
263,227 |
177,811 |
Total Proved |
858,932 |
644,059 |
472,296 |
Proved Plus Probable |
1,746,822 |
1,108,279 |
855,793 |
Capital Expenditures ($ millions) |
|||
Exploration and Development(3) |
756 |
1,451 |
2,031 |
Net Acquisitions (Dispositions) |
1,545 |
451 |
(250) |
Total Capital Expenditures |
2,301 |
1,902 |
1,782 |
Cash Flow ($/boe) |
|||
Cash Flow |
10.77 |
15.09 |
22.54 |
Cash Flow – Three Year Average |
15.17 |
18.47 |
19.93 |
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) |
2016 Financial numbers are unaudited. |
(3) |
Includes capitalized G&A of $25 million, $26 million and $21 million for 2016, 2015 and 2014 respectively. |
Finding and Development Costs
Finding and Development Costs, Excluding FDC |
2016 |
2015 |
2014 |
2014-2016 |
Total Proved |
||||
Reserve Additions (MMboe) |
126.4 |
187.1 |
190.1 |
|
F&D Costs ($/boe) |
5.98 |
7.76 |
10.68 |
8.42 |
F&D Recycle Ratio(1) |
1.8 |
1.9 |
2.1 |
1.8 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
158.7 |
260.2 |
300.7 |
|
F&D Costs ($/boe) |
4.76 |
5.58 |
6.75 |
5.89 |
F&D Recycle Ratio(1) |
2.3 |
2.7 |
3.3 |
2.6 |
Finding and Development Costs, Including FDC |
2016 |
2015 |
2014 |
2014-2016 |
Total Proved |
||||
Change in FDC ($ millions) |
(239.9) |
(42.7) |
935.8 |
|
Reserve Additions (MMboe) |
126.4 |
187.1 |
190.1 |
|
F&D Costs ($/boe) |
4.08 |
7.53 |
15.61 |
9.71 |
F&D Recycle Ratio(1) |
2.6 |
2.0 |
1.4 |
1.6 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
(518.6) |
(190.5) |
1,430.3 |
|
Reserve Additions (MMboe) |
158.7 |
260.2 |
300.7 |
|
F&D Costs ($/boe) |
1.49 |
4.84 |
11.51 |
6.89 |
F&D Recycle Ratio(1) |
7.2 |
3.1 |
2.0 |
2.2 |
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, Excluding FDC |
2016 |
2015 |
2014 |
2014-2016 |
Total Proved |
||||
Reserve Additions (MMboe) |
282.8 |
228.1 |
197.1 |
|
FD&A Costs ($/boe) |
8.14 |
8.34 |
9.04 |
8.45 |
FD&A Recycle Ratio(1) |
1.3 |
1.8 |
2.5 |
1.8 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
706.5 |
308.9 |
306.9 |
|
FD&A Costs ($/boe) |
3.26 |
6.16 |
5.80 |
4.53 |
FD&A Recycle Ratio(1) |
3.3 |
2.5 |
3.9 |
3.4 |
Finding, Development and Acquisition Costs, Including FDC |
2016 |
2015 |
2014 |
2014-2016 |
Total Proved |
||||
Change in FDC ($ millions) |
304.0 |
21.7 |
919.3 |
|
Reserve Additions (MMboe) |
282.8 |
228.1 |
197.1 |
|
FD&A Costs ($/boe) |
9.21 |
8.43 |
13.71 |
10.21 |
FD&A Recycle Ratio(1) |
1.1 |
1.8 |
1.6 |
1.5 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
1,894.0 |
(84.1) |
1,410.8 |
|
Reserve Additions (MMboe) |
706.5 |
308.9 |
306.9 |
|
FD&A Costs ($/boe) |
5.94 |
5.89 |
10.40 |
6.96 |
FD&A Recycle Ratio(1) |
1.8 |
2.6 |
2.2 |
2.2 |
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 2016 financial results after the close of markets on March 7, 2017. A conference call discussing these results will be held at 7:30 a.m. Mountain Time on MaRch 8, 2017.