CALGARY, Nov. 8, 2017 /CNW/ – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to release strong financial and operating results for the third quarter of 2017.
PRODUCTION UPDATE
- Current production is ranging between approximately 255,000-265,000 boepd and the Company expects 2017 exit production of between 270,000-280,000 boepd, both ahead of original internal estimates.
- The Company also currently has additional behind-pipe or shut-in volumes of approximately 25,000 boepd, which is expected to grow to 30,000 boepd by exit 2017.
- Q3 average production was 236,905 boepd – a 40% increase over Q3 2016.
- The Company elected to leave natural gas volumes of approximately 50 mmcfpd shut-in during the East Gate maintenance related low price periods in August, September and October. East Gate price-related curtailments and the significant James River curtailment reduced August/September volumes by approximately 10,000 boepd.
- Q3 average liquids production (oil, condensate and NGLs) at 38,995 bpd is 94% higher than Q3 2016 and 8% higher than Q2 2017. Current liquids production is averaging 42,000 bpd.
- Unchanged from its original guidance, the Company is expecting 2017 full-year production to average between 240,000 and 250,000 boepd.
- Tourmaline will deliver approximately 30% year-over-year production growth in 2017.
- Tourmaline is expecting 2018 production to average between 270,000 and 280,000 boepd, down from its previous guidance of 280,000-300,000 boepd with a corresponding capital spending reduction of 29%. This will now yield 2018 year-over-year production growth of approximately 10%.
- Liquids production is expected to grow to approximately 50,000 bpd in 2018 and is expected to reach 60,000-65,000 bpd in 2H 2019 with the start-up of the Tourmaline-operated Gundy 200 mmcfpd deep cut natural gas plant.
EP UPDATE
- Tourmaline expects to drill approximately 300 wells in 2017 across all three core-operated complexes.
- Drilling execution has generally been ahead of schedule. The Company is currently operating 15 rigs, down from the peak of 18 rigs earlier in Q3. The Company will reduce the operated rig fleet to 14 rigs during Q4 as planned drilling programs are completed. An average 12-rig program is now planned for 2018.
- Tourmaline continues to drill the lowest cost, completed-per-stage horizontal wells across all three operated complexes.
- The Peace River High oil drilling program was increased to four rigs during the third quarter as the Company expands efforts developing the Montney and Lower Charlie Lake horizons in addition to the main Upper Charlie Lake development program. During the next two months, Tourmaline will bring on-production ten new Montney oil wells and three Lower Charlie Lake oil wells that are already drilled and being completed. The Company’s Progress 1-4 Lower Montney well has an IP 90 of 466 bopd and 2.5 mmcfpd of gas (891 boepd). With drill and complete costs of $2.4 million, an IP 365 of 244 boepd and a 2P estimated ultimate recovery (or EUR) of 345 mboe, the Upper Charlie Lake horizontals are amongst the most profitable oil wells in North America. The three most recent Upper Charlie Lake wells stimulated with the Company’s CCFT (Confined Cecil Frac Technology) are averaging between 300 and 400 bopd and 0.3 mmcfpd gas after the first week of production. Drill-and-complete costs for these wells is approximately $2.0 million, given the reduced stimulation costs.
- Development of the Gundy property has exceeded expectations for both increased well performance and capital cost reduction. The Company has drilled and completed two pads (16 wells in aggregate) with a third 11-well pad drilled awaiting stimulation. Current drill-and-complete costs are 40-50% less than those carried in the 2016 independent reserve reports. The most recent pacesetter horizontal well was drilled in 6.4 days for $1.3 million, down from drilling costs of $3.5 million in 2014. Initial well performance is significantly ahead of the 5.5 bcfe performance curves utilized in the 2016 independent reserve report, with some initial flow rates more than double original expectation. The A-M78-A/94-B-16 well was flowing at 22.5 mmcfpd at a flowing casing pressure of 8,625 KPa with 590 bbls/day of wellhead condensate after five days of production testing (4,340 boepd).
Q3 FINANCIAL RESULTS
- Q3 2017 cash flow(1) was $251.3 million ($0.93/diluted share) up 35% from Q3 2016 (18%/diluted share).
- Q3 2017 after-tax earnings were $50.6 million ($0.19/diluted share) underscoring the fundamental profitability of the business. With a realized average natural gas price in Q3 of $2.52/mcf and continued earnings, the Company continues to lower the threshold natural gas price required for full cycle profitability.
- Q3 operating costs were $3.00/boe, down 8% from Q3 2016 and down 7% from the second quarter of 2017.
- Weaker than expected natural gas prices related to the new East Gate natural gas transportation restrictions directly impacted Q3 2017 cash flow by $55.0 million as the Company had significant new volumes from new pads receiving the much lower than anticipated daily index price. Uncontracted daily natural gas volumes are significantly less in Q4 2017 and in Q1 2018. The Company now has winter 2018 fixed volumes of 413 mmcfpd at $3.21/mcf Cdn at AECO that take effect, as well as 116 mmcf/d of new service on the Mainline to Dawn, Ontario, effective November 1, 2017.
- For the nine months ending September 30, 2017, cash flow was $857.5 million or $3.18/diluted share compared to $479.3 millionor $2.09/diluted share for the same period in 2016, a 52% per diluted share improvement.
CAPITAL PROGRAM AND FINANCIAL OUTLOOK
2H 2017 Capital Program
- Q3 2017 E&P capital spending was $432.4 million as the Company aggressively pursued the second half 2017 drilling program with up to 18 rigs in July/August, to ensure that new production is ready for exit 2017/Winter 2018. The Company has purposefully grown the behind-pipe production volumes and the DUC (drilled uncompleted) inventory to provide flexibility to take advantage of potentially improved winter prices as well as facilitate overall production decline management in 2018. The Company currently has a total of 110 DUC wells and completed wells across all three core complexes to bring on-stream in Q4 2017 and during Q1 2018. The Q4 2017 EP program is at a reduced 14-rig pace as several of the planned drilling programs have been competed ahead of schedule. Tourmaline expects Q4 2017 E&P spending to match Q4 2017 cash flow of an estimated $325-$335 million. Full-year E&P capital spending is now forecast to be $1.34 billion, with revised full-year cash flow estimated at $1.19 billion, reflecting lower natural gas prices than originally forecast in Q3 2017.
- Tourmaline expects to grow 2017 cash flow per share by approximately 40% in 2017 over 2016, despite a challenging natural gas price environment.
- The Company completed a land swap in NEBC during Q3 2017, allowing for a significant consolidation in the Sundown complex prior to the planned 2018/2019 development program. Tourmaline consolidated 150 existing development locations at Sundown to 100% working interest and acquired an estimated additional 75 locations. None of these locations were booked in the 2016 independent reserve report. The Company acquired 9.12 mmboe of internally-estimated 2P reserves at Sundown and approximately 350 boepd of current production in exchange for 1.44 mmboe of currently-booked reserves on the traded property as well as $19.0 million in cash paid by Tourmaline at closing.
- The Q3 capital included $25.0 million for the initiation of the Gundy deep-cut facility construction. The Company will expend an additional $5.0 million in Q4 2017, approximately $60.0 million in 2018 and $85.0 million in 2019 to complete the project. The Gundy plant will bring approximately 200 mmcf/d of natural gas and 12,500-15,000 bpd of liquids production on-stream.
2018 Program and Updated Five-Year Growth Plan
- The Company has reached a point in its eight year evolution to a senior producer that it can provide both strong, predictable annual growth and a steady return to shareholders. Tourmaline has three expansive resource plays that have been de-risked through the drilling of 1,075 operated wells with Company owned-and-operated infrastructure in place in all three complexes. The Company drills the least expensive per-stage completed wells in each area by Industry and is one of the lowest cost operators in Western Canada. Tourmaline had booked 2P reserves of 1.75 billion boe (8.93 TCF of natural gas, 258.4 mmbbls of oil, condensate, NGLs) at year end 2016, utilizing only 1,819 future locations of an inventory of 15,016 locations. The Company has created a long lasting natural gas and liquids business that can continue to profitably grow and provide a steady return to shareholders.
- The Company has elected to moderate growth in its natural gas business until the Western Canadian and North American supply/demand outlook is more transparent and balanced. The Company will keep 2018 daily natural gas production essentially flat at 2017 exit production levels of 1.35 bcf/day, unless there is a material improvement in the natural gas price outlook. Tourmaline can generate a strong full-cycle return at natural gas prices as low as $2.30-$2.40/mcf Cdn, but does not believe it is beneficial to shareholders to aggressively grow the natural gas business at prices in that range.
- Tourmaline has reduced the natural gas price utilized in its five-year plan from $3.15/mcf Cdn at AECO to $2.50/mcf Cdn. By mid-2018 Tourmaline also has approximately 0.5 bcf/day of corporate natural gas production that is transported to hubs that are essentially NYMEX priced. The Company is now utilizing a $3.10/mcf US NYMEX price in the plan down from $3.25/mcf US previously. Tourmaline’s annual realized natural gas price on Alberta sales has exceeded the actual AECO price in each of the last seven years, outperforming the index by an average of 13% over the seven-year period. The Company has also decreased the oil price employed in the five-year outlook to a flat $52/bbl US WTI.
- The 2018 EP capital program has been reduced from $1.52 billion to $1.08 billion, reducing planned production growth from 15% to 10% for the year. An average 5-10% per annum production growth is maintained through the balance of the five-year plan based on the $2.50/mcf Cdn at AECO flat natural gas pricing in the plan. The 2018 EP program is a 12-rig program; however, the Company has the capability to operate over a 20-rig fleet and can quickly ramp up the EP program in an improved natural gas price environment, in turn increasing annual growth rates to the 10 to 15% range. The slightly lower growth rate in 2019 is a result of the majority of the Gundy development capital (drilling and plant installation) occurring during calendar 2019 with the plant only on-stream for the second half of the year.
- The Company will continue to aggressively grow the liquids business in 2018 and 2019, which has doubled in the past 15 months to over 40,000 bpd (oil, condensate, NGLs). A further 50% growth in daily total liquids volumes is expected over the next two years.
- Even with the much lower commodity pricing employed, the significantly reduced capital spending in the five-year plan creates material free cash flow([2]), estimated at $251.0 million in 2018. This will allow the Company to begin paying a modest dividend starting at 8¢ per share per quarter, for a total of approximately $86 million per year – significantly less than forecast annual free cash flow. The dividend is expected to commence in Q1 2018.
- A significant portion of the dividend funding will be provided by Tourmaline’s growing third-party revenues from the Company’s extensive infrastructure assets. Third-party revenues of approximately $30 – $40 million from Tourmaline infrastructure are forecast in 2017, and are expected to be between $40 – $50 million in 2018. Tourmaline’s extensive, new state-of-the-art natural gas plant network is currently capable of processing up to 1.5 bcf/day, providing ample capacity for Tourmaline natural gas volumes and a component of third party volumes. Tourmaline currently plans to expand the natural gas processing infrastructure again in 2019. The 200 mmcfpd Gundy BC deep-cut natural gas plant remains in the development outlook with a planned 2H 2019 start-up. The Gundy property will actually support a 400 mmcf/d project, consuming only half of the 1,600 internally-recognized locations by 2037. The decision to proceed with a phase 2 expansion in the 2020/2021 time frame has not been made and will be controlled primarily by the commodity price outlook.
- The remaining free cash flow after the dividend distribution will be utilized to reduce existing corporate debt. Tourmaline continues to maintain an extremely strong balance sheet with forecast 2017 net debt to cash flow of 1.5 times, dropping to 1.1 times by exit 2018. The Company has grown rapidly to a senior producer while maintaining strong capital discipline since inception with a net debt to cash flow average of 1.4 over the last seven years. As at September 30, 2017, the Company has $1.06 billion of available unused credit capacity.
- Tourmaline expects to drill approximately 233 wells in 2018, down from approximately 300 wells in 2017 with a total 2018 EP capital program of $1.082 billion. The Company has the flexibility to reduce this program by $50-75 million without affecting the full-year production estimate.
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(1) |
“Cash flow” is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” in the Company’s Q3 2017 Management’s Discussion and Analysis. |
(2) |
“Free cash flow” is defined as cash flow less capital expenditures. |
CORPORATE SUMMARY – THIRD QUARTER 2017
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||
2017 |
2016 |
Change |
2017 |
2016 |
Change |
||||||||||
OPERATIONS |
|||||||||||||||
Production |
|||||||||||||||
Natural gas (mcf/d) |
1,187,462 |
895,256 |
33% |
1,192,748 |
969,089 |
23% |
|||||||||
Crude oil and NGL (bbl/d) |
38,995 |
20,138 |
94% |
36,464 |
22,095 |
65% |
|||||||||
Oil equivalent (boe/d) |
236,905 |
169,347 |
40% |
235,255 |
183,610 |
28% |
|||||||||
Product prices(1) |
|||||||||||||||
Natural gas ($/mcf) |
$ |
2.52 |
$ |
2.80 |
(10)% |
$ |
2.95 |
$ |
2.28 |
29% |
|||||
Crude oil and NGL ($/bbl) |
$ |
37.63 |
$ |
39.98 |
(6)% |
$ |
39.69 |
$ |
37.37 |
6% |
|||||
Operating expenses ($/boe) |
$ |
3.00 |
$ |
3.26 |
(8)% |
$ |
3.24 |
$ |
3.46 |
(6)% |
|||||
Transportation costs ($/boe) |
$ |
3.01 |
$ |
2.82 |
7% |
$ |
2.90 |
$ |
2.23 |
30% |
|||||
Operating netback(3) ($/boe) |
$ |
12.27 |
$ |
12.69 |
(3)% |
$ |
14.06 |
$ |
10.28 |
37% |
|||||
Cash general and administrative expenses ($/boe)(2) |
$ |
0.46 |
$ |
0.49 |
(6)% |
$ |
0.47 |
$ |
0.46 |
2% |
|||||
FINANCIAL |
|||||||||||||||
($000, except share and per share) |
|||||||||||||||
Revenue |
410,591 |
304,480 |
35% |
1,356,505 |
830,711 |
63% |
|||||||||
Royalties |
12,265 |
11,985 |
2% |
59,525 |
27,105 |
120% |
|||||||||
Cash flow(3) |
251,327 |
185,531 |
35% |
857,531 |
479,259 |
79% |
|||||||||
Cash flow per share (diluted)(3) |
$ |
0.93 |
$ |
0.79 |
18% |
$ |
3.18 |
$ |
2.09 |
52% |
|||||
Net earnings (loss) |
50,580 |
24,738 |
104% |
258,694 |
(91,592) |
382% |
|||||||||
Net earnings (loss) per share (diluted) |
$ |
0.19 |
$ |
0.10 |
90% |
$ |
0.96 |
$ |
(0.40) |
340% |
|||||
Capital expenditures |
465,466 |
224,448 |
107% |
1,054,383 |
688,315 |
53% |
|||||||||
Weighted average shares outstanding (diluted) |
269,439,702 |
229,507,106 |
17% |
||||||||||||
Net debt(3) |
(1,772,158) |
(1,389,401) |
28% |
(1) Product prices include realized gains and losses on financial instrument contracts. |
(2) Excluding interest and financing charges. |
(3) See “Non-GAAP Financial Measures” in the Company’s Q3 2017 Management’s Discussion and Analysis. |
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, November 9, 2017 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-888-231-8191 (toll-free in North America), or international dial-in 647-427-7450, a few minutes prior to the conference call.
Conference ID is 91799506.