CALGARY, ALBERTA–(Marketwired – March 7, 2017) – NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce results for the three months and year ended December 31, 2016 and provide an update on our future business plans.
2016 Success Provides Foundation For NuVista Long Term Strategy
Operationally, 2016 was a very strong year for NuVista. We have:
These factors have allowed NuVista to grow despite the low commodity price environment of the past two years. With prices stabilizing somewhat, we are now in a strong position to accelerate growth as previously announced, towards our five year plan. NuVista has a material position in the Wapiti Montney play, which with prudent management has the ability to deliver top financial returns to shareholders over the long term and across many commodity cycles. Our strategy is to actively manage the balance sheet to allow accelerated spending flexibility when commodity prices and returns are strong. When commodity prices are low, we moderate our pace to spend the minimum required amount to protect the business. We maintain flexibility to handle near term events while adhering to our long term growth foundations. We ensure strong alignment for every employee through our compensation structure which is linked to key financial metrics and shareholder returns.
Significant Operating Highlights for the quarter and year ended December 31, 2016:
Significant Reserves Highlights for 2016
NuVista is pleased to announce a significant increase in our reserves value as a result of the 2016 year end independent evaluation of our reserves by GLJ Petroleum Consultants Ltd (“GLJ”) (the “GLJ Report”). 2016 marked the completion of our transition to a pure-play condensate rich Montney company. Dispositions and continued Montney development have resulted in 99% of our reserves now being booked in the Montney. In 2016, we have been focused on converting undeveloped locations to producers in Bilbo and Elmworth. Gold Creek reserves were largely unchanged after a year of low activity, however we have commenced a very active drilling program in this area in 2017. At Pipestone, NuVista is just months away from spudding our first well, but industry has already been very active in the area providing positive proven results directly offsetting our acreage.
We have increased our condensate weighting, underpinning our improving net backs and exposure to a recovery in global oil prices despite a volatile natural gas market. The net present value (“NPV”) of NuVista’s reserves has increased materially while F&D cost performance has continued to improve significantly. For the year ended December 31, 2016 NuVista:
NuVista is pleased to note that our Montney PDP and TP+PA reserves have grown at a compounded annual growth rate of 130% and 84% respectively over the past 5 years. As the proportion of reserves attributed to the Montney has increased, so has the weighting to condensate which now forms 25% of the Company’s reserves, up from 19% in 2015.
Credit Facility and Other Items
2017 Guidance
NuVista will continue drilling with five rigs until spring breakup and then reduce to approximately three rigs in operation for the second half of 2017. As previously noted, 2016 capital spending was approximately $18 million below the midpoint of 2016 guidance primarily as a result of weather-deferred activity. These deferred costs are being incurred in 2017. As a result, we expect 2017 capital expenditures to be at the higher end of our existing capital spending guidance range of $260 – $300 million.
Due to some uncertainty in the quarterly phasing of planned maintenance outages, our original guidance was 26,000 – 29,000 Boe/d for each of the first three quarters of 2017. As planned, 5 new wells came on stream in Bilbo in the first quarter. After minor delays, these wells came on-stream in early March as opposed to early February. As a result, first quarter production is expected to be at or slightly below the lower end of our guidance range. As of the first week of March, production has already reached 27,000 Boe/d. The initial productivity of the new wells appears very strong therefore the guidance ranges for the remainder of the year and full year are unchanged. Annual 2017 production guidance is 28,000 – 31,000 Boe/d.
NuVista has top quality assets and every team member is focused upon relentless improvement. We are excited to continue pursuing our 5 year growth plan to 60,000 Boe/d. We would like to thank our staff, contractors, and suppliers for their continued dedication and delivery, and we thank our board of directors and our shareholders for their continued guidance and support.
Please note that our corporate presentation is being updated and will be available at www.nuvistaenergy.com by March 8, 2017. NuVista’s financial statements for the year ended December 31, 2016, notes to the financial statements and management’s discussion and analysis will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on or before Wednesday, March 8, 2017 and can also be accessed on NuVista’s website.
Corporate Highlights | |||||||||||||||||
Three months ended December 31 | Year ended December 31 | ||||||||||||||||
($ thousands, except per share and per $/Boe) | 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||||||
Financial | |||||||||||||||||
Oil and natural gas revenues | $ | 74,538 | $ | 55,592 | 34 | $ | 257,252 | $ | 225,685 | 14 | |||||||
Funds from operations (1) | 40,697 | 32,544 | 25 | 137,841 | 124,989 | 10 | |||||||||||
Per basic and diluted share | 0.24 | 0.21 | 14 | 0.87 | 0.84 | 4 | |||||||||||
Net income (loss) | 1,135 | (69,074 | ) | (102 | ) | (1,653 | ) | (172,925 | ) | (99 | ) | ||||||
Per basic and diluted share | 0.01 | (0.45 | ) | (102 | ) | (0.01 | ) | (1.16 | ) | (99 | ) | ||||||
Total assets | 961,240 | 981,637 | (2 | ) | |||||||||||||
Net debt (1) | 82,692 | 220,625 | (63 | ) | |||||||||||||
Capital expenditures | 55,785 | 52,278 | 7 | 189,061 | 273,242 | (31 | ) | ||||||||||
Proceeds on property dispositions | 2,082 | 12,947 | (84 | ) | 75,983 | 26,858 | 183 | ||||||||||
Weighted average common shares outstanding – basic | 167,938 | 153,305 | 10 | 157,977 | 148,523 | 6 | |||||||||||
End of period common shares outstanding | 172,746 | 153,310 | 13 | ||||||||||||||
Operating | |||||||||||||||||
Production | |||||||||||||||||
Natural gas (MMcf/d) | 96.3 | 96.4 | – | 97.0 | 94.3 | 3 | |||||||||||
Condensate & oil (Bbls/d) | 7,258 | 5,421 | 34 | 6,892 | 5,042 | 37 | |||||||||||
NGLs (Bbls/d) (2) | 1,402 | 1,875 | (25 | ) | 1,575 | 1,648 | (4 | ) | |||||||||
Total (Boe/d) | 24,716 | 23,355 | 6 | 24,638 | 22,408 | 10 | |||||||||||
Condensate, oil & NGLs weighting | 35 | % | 31 | % | 34 | % | 30 | % | |||||||||
Condensate & oil weighting | 29 | % | 23 | % | 28 | % | 23 | % | |||||||||
Average selling prices (3) & (4) | |||||||||||||||||
Natural gas ($/Mcf) | 3.74 | 3.55 | 5 | 3.54 | 3.64 | (3 | ) | ||||||||||
Condensate & oil ($/Bbl) | 58.21 | 45.28 | 29 | 49.81 | 51.34 | (3 | ) | ||||||||||
NGLs ($/Bbl) | 19.35 | 8.76 | 121 | 10.43 | 9.96 | 5 | |||||||||||
Netbacks ($/Boe) | |||||||||||||||||
Oil and natural gas revenues | 32.78 | 25.88 | 27 | 28.53 | 27.59 | 3 | |||||||||||
Realized gain on financial derivatives | 1.02 | 5.15 | (80 | ) | 2.92 | 5.23 | (44 | ) | |||||||||
Royalties | (0.42 | ) | (0.58 | ) | (28 | ) | (0.21 | ) | (0.83 | ) | (75 | ) | |||||
Transportation expenses | (2.14 | ) | (1.23 | ) | 74 | (2.34 | ) | (1.55 | ) | 51 | |||||||
Operating expenses | (10.44 | ) | (11.17 | ) | (7 | ) | (10.52 | ) | (11.88 | ) | (11 | ) | |||||
Operating netback (1) | 20.80 | 18.05 | 15 | 18.38 | 18.56 | (1 | ) | ||||||||||
Funds from operations netback (1) | 17.90 | 15.15 | 18 | 15.28 | 15.28 | – | |||||||||||
Share trading statistics | |||||||||||||||||
High | 7.80 | 6.35 | 23 | 7.80 | 9.54 | (18 | ) | ||||||||||
Low | 6.28 | 3.28 | 91 | 2.72 | 3.28 | (17 | ) | ||||||||||
Close | 6.94 | 4.07 | 71 | 6.94 | 4.07 | 71 | |||||||||||
Average daily volume | 693,415 | 582,682 | 19 | 549,049 | 456,570 | 20 |
(1) | See “Non-GAAP measurements”. |
(2) | Natural gas liquids (“NGLs”) include butane, propane and ethane. |
(3) | Product prices exclude realized gains/losses on financial derivatives. |
(4) | The average NGLs selling price is net of tariffs and fractionation fees. |
Summary of Corporate Reserves Data
The following table provides summary reserve information based upon the GLJ Report using the published GLJ January 1, 2017 price forecast:
Natural Gas(2) | Natural Gas Liquids |
Oil(3) | Total | ||
Company Gross | Company Gross | Company Gross | Company Gross | ||
Reserves category(1) | Interest | Interest | Interest | Interest | |
(MMcf) | (MBbls) | (MBbls) | (MBoe) | ||
Proved | |||||
Developed producing | 155,230 | 12,000 | 7 | 37,878 | |
Developed non-producing | 32,594 | 2,551 | 28 | 8,011 | |
Undeveloped | 359,222 | 28,036 | 29 | 87,936 | |
Total proved | 547,047 | 42,587 | 65 | 133,826 | |
Probable | 503,075 | 39,668 | 21 | 123,535 | |
Total proved plus probable | 1,050,121 | 82,255 | 86 | 257,361 |
NOTES: | |
(1) | Numbers may not add due to rounding. |
(2) | Includes conventional natural gas and shale gas and coal bed methane. |
(3) | Includes light, medium crude oil. |
The following table is a summary reconciliation of the 2016 year end working interest reserves with the working interest reserves reported in the 2016 year end reserves report:
Natural Gas(1)(3) (MMcf) |
Liquids(1) (MBbls) |
Oil(1)(4) (MBbls) |
Total Oil Equivalent(1) (MBoe) |
|||||
Total proved | ||||||||
Balance, December 31, 2015 | 491,521 | 35,901 | 72 | 117,894 | ||||
Exploration and development(2) | 137,859 | 11,576 | – | 34,552 | ||||
Technical revisions | 3,229 | 1,576 | – | 2,114 | ||||
Acquisitions | 3,375 | 247 | – | 810 | ||||
Dispositions | (47,261 | ) | (3,403 | ) | (5 | ) | (11,285 | ) |
Economic Factors | (6,222 | ) | (221 | ) | – | (1,258 | ) | |
Production | (35,456 | ) | (3,089 | ) | (3 | ) | (9,001 | ) |
Balance, December 31, 2016 | 547,046 | 42,587 | 65 | 133,826 | ||||
Total proved plus probable | ||||||||
Balance, December 31, 2015 | 1,052,372 | 77,196 | 135 | 252,727 | ||||
Exploration and development(2) | 138,076 | 12,868 | 0 | 35,880 | ||||
Technical revisions | (4,454 | ) | 2,647 | (0 | ) | 1,905 | ||
Acquisitions | 5,430 | 396 | 0 | 1,301 | ||||
Dispositions | (96,894 | ) | (7,422 | ) | (27 | ) | (23,598 | ) |
Economic Factors | (8,953 | ) | (342 | ) | (19 | ) | (1,853 | ) |
Production | (35,456 | ) | (3,089 | ) | (3 | ) | (9,001 | ) |
Balance, December 31, 2016 | 1,050,121 | 82,255 | 86 | 257,361 |
NOTES: | |
(1) | Numbers may not add due to rounding. |
(2) | Reserve additions for drilling extensions, infill drilling and improved recovery. |
(3) | Includes conventional natural gas, shale gas and coal bed methane. |
(4) | Includes light, medium crude oil. |
The following table summarizes the future development capital included in the GLJ Report:
($ thousands, undiscounted) | Proved | Proved plus probable |
2017 | 122,210 | 184,130 |
2018 | 163,422 | 285,479 |
2019 | 252,068 | 354,543 |
2020 | 165,115 | 286,985 |
2021 | 192,126 | 290,325 |
Remaining | – | 222,742 |
Total (Undiscounted) | 894,942 | 1,624,203 |
The following table outlines NuVista’s corporate finding and development costs in more detail:
3 Year-Average (1) | 2016 (1) | 2015 (1) | ||||
Proved plus | Proved plus | Proved plus | ||||
Proved | probable | Proved | probable | Proved | probable | |
After reserve revisions and including changes in future development capital | ||||||
Finding and development costs ($/Boe) | $11.48 | $8.42 | $10.13 | $8.39 | $8.11 | $3.69 |
NOTE: | |
(1) | F&D costs are used as a measure of capital efficiency. The calculation for finding and development costs includes all exploration and development capital for that period (as outlined in the Company’s year end financial statements) plus the change in future development capital for that period. This total capital including the change in the future development capital is then divided by the change in reserves for that period including revisions for that same period. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year. |
As noted earlier in the highlights, PDP F&D results have improved dramatically over prior years, reaching a record low PDP F&D of $10.80/Boe in 2016 with a corresponding PDP full year recycle ratio of 1.4x. The corresponding recycle ratios for Total Proved and TP+PA reserves were 1.5x and 1.8x respectively. Total Proved and TP+PA F&D costs were favorable in 2016 notwithstanding the increase from 2015. This increase in 2016 is merely due to the anomalously low numbers achieved in 2015 due to a large one-time reduction in FDC due to cost efficiency gains.
Summary of Corporate Net Present Value Data
The estimated net present values of future net revenue before income taxes associated with NuVista’s reserves effective December 31, 2016 and based on published GLJ future price forecast as at January 1, 2017 as set forth below are summarized in the following table:
The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
Before Income Taxes | ||||||
Discount Factor (%/year) | ||||||
Reserves category (1) ($ thousands) | 0% | 5% | 10% | 15% | 20% | |
Proved | ||||||
Developed producing | 562,763 | 457,909 | 387,982 | 339,283 | 303,763 | |
Developed non-producing | 129,157 | 98,193 | 79,385 | 67,185 | 58,734 | |
Undeveloped | 746,885 | 396,404 | 207,449 | 99,762 | 35,198 | |
Total proved | 1,438,805 | 952,506 | 674,815 | 506,231 | 397,695 | |
Probable | 1,728,286 | 870,318 | 489,750 | 298,124 | 190,867 | |
Total proved plus probable | 3,167,092 | 1,822,825 | 1,164,566 | 804,354 | 588,562 |
(1) | Numbers may not add due to rounding. |
The following table is a summary of pricing and inflation rate assumptions based on published GLJ forecast prices and costs as at January 1, 2017:
Natural Gas | Liquids | Oil | ||||||
Year | AECO Gas Price ($Cdn/ Mmbtu) | Edmonton Condensate ($Cdn/Bbl) | Edmonton Propane ($Cdn/Bbl) | Edmonton Butane ($Cdn/Bbl) | WTI Cushing Oklahoma ($US/Bbl) | Edmonton Par Price 40 API ($Cdn/Bbl) | Inflation Rates % / Year(1) |
Exchange Rate(2) ($US/$Cdn) |
Forecast | ||||||||
2017 | 3.46 | 72.11 | 28.43 | 49.92 | 55.00 | 69.33 | 2.0 | 0.750 |
2018 | 3.10 | 74.79 | 26.74 | 54.19 | 59.00 | 72.26 | 2.0 | 0.775 |
2019 | 3.27 | 78.75 | 26.25 | 56.25 | 64.00 | 75.00 | 2.0 | 0.800 |
2020 | 3.49 | 79.80 | 26.73 | 57.27 | 67.00 | 76.36 | 2.0 | 0.825 |
2021 | 3.67 | 82.37 | 27.59 | 59.12 | 71.00 | 78.82 | 2.0 | 0.850 |
2022 | 3.86 | 86.06 | 28.82 | 61.76 | 74.00 | 82.35 | 2.0 | 0.850 |
2023 | 4.05 | 89.32 | 30.06 | 64.41 | 77.00 | 85.88 | 2.0 | 0.850 |
2024 | 4.16 | 92.99 | 31.29 | 67.06 | 80.00 | 89.41 | 2.0 | 0.850 |
2025 | 4.24 | 97.59 | 32.53 | 69.71 | 83.00 | 92.94 | 2.0 | 0.850 |
2026 | 4.32 | 99.91 | 33.46 | 71.71 | 86.05 | 95.61 | 2.0 | 0.850 |
2026+ | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 2.0 | 0.850 |
NOTES: | |
(1) | Inflation rate for costs. |
(2) | Exchange rate used to generate the benchmark reference prices in this table. |
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