CALGARY, ALBERTA--(Marketwired - March 8, 2015) - NuVista Energy Ltd. ("NuVista") (or the "Company") (TSX:NVA) is pleased to announce results for the three and twelve months ended December 31, 2014 and provide an update on its future business plans. NuVista had an exceptional year in 2014 on many fronts by:
- Increasing natural gas and condensate production, reserves and contingent resources;
- Successfully commencing operations of our new Bilbo compressor station on time and on budget;
- Bringing on production 17 new Wapiti Montney wells for a total of 33;
- Improving the performance of our Wapiti wells versus typecurve;
- Further reducing total well costs per metre of rock accessed;
- Materially increasing the volumes and prices associated with our commodity hedging program;
- Continuing our rolling annual non-core divestiture program;
- Continuing our successful delineation drilling and expiry management program; and
- Significantly improving corporate netbacks while prudently managing our balance sheet.
These factors have placed NuVista in a position to weather the current low price environment with patience and strength without impairing our ability to grow rapidly and profitably in a healthy long term commodity price environment. In 2015, NuVista is prepared to use our flexibility to limit capital spending for prudent balance sheet management, and in turn retain the ability to accelerate capital spending should the commodity price environment improve as expected.
NuVista is pleased to announce a significant increase in our reserves and contingent resources as a result of the 2014 year end independent reserves and resources evaluation by GLJ Petroleum Consultants Ltd ("GLJ") (the "GLJ Report"). The Wapiti Montney play continues to exceed expectations as our flagship play with line-of-sight to exceptional organic production, reserves, and value growth for shareholders.
Significant Reserves Highlights for the year ending December 31, 2014:
- Increased proved plus probable reserves ("TP+PA") by 58% to 220 MMBoe and total proved reserves ("TP") by 38% to 111 MMBoe as compared to year end 2013, despite divestitures of non-core assets through the year. Excluding the effect of these divestitures, the TP+PA and TP reserve increases were 72% and 54% respectively;
- Increased condensate reserves versus the prior year by 80% on a TP+PA basis to 44.7 MMBoe. Condensate volumes now represent 20% of total TP+PA reserves, up from 18% in 2013;
- Achieved 2014 corporate finding and development ("F&D") costs of $10.55/Boe on a TP+PA basis, including changes in future development costs ("FDC");
- Improved the Company's recycle ratio to 1.6x on a TP+PA basis as compared to 1.0 in 2013 as the transformation to a Montney-focused company continued successfully;
- Increased Montney TP+PA operating recycle ratio to 2.8x with full year Montney operating netbacks of $29.80/Boe;
- Achieved positive technical reserves revisions on both a TP and TP+PA basis due to continued outperformance of producing wells;
- Replaced 1,590% of production in the year on a TP+PA basis, while proved developed producing reserve additions alone replaced 250% of annual production;
- Increased our reserve life index(1) ("RLI") on a TP+PA basis from 20.8 years to 25.9 years and increased the RLI on a TP basis from 12.0 years to 13.1 years as compared to year end 2013;
- Increased our best estimate of Economic Contingent Resources ("ECR") by 23% to 3.13 Tcfe, from 2.55 Tcfe at the close of 2013. In addition TP+PA reserves increased by 0.58 Tcfe; and
- Increased the total inventory of undrilled locations for TP+PA reserves to 194 wells and for ECR to 710 wells for a total of 904.
The ECR evaluation only includes approximately 65% of the NuVista holdings in the Wapiti Middle Montney, and does not yet include any of the Lower Montney zone. It is expected that significant value remains to be unlocked as NuVista continues to delineate its landholdings, and as resources are converted to reserves and production.
(1)RLI was calculated by dividing 2014 year end reserves by the midpoint of 2015 production guidance.
Significant Operating Highlights for the quarter and year ending December 31, 2014:
- Achieved and exceeded the top end of our annual and fourth quarter guidance ranges, respectively. For the fourth quarter of 2014, NuVista's average production was 23,165 Boe/d compared to average production of 18,034 Boe/d for the fourth quarter of 2013 and 18,030 Boe/d for the third quarter of 2014. The increase in production of 28% from the fourth quarter of 2013 is due to strong performance of new and existing Wapiti Montney wells. This growth rate was partially offset by the sale of non core properties in 2014;
- Achieved funds from operations of $36.7 million ($0.26/share, basic) for the three months ended December 31, 2014, a 70% increase from $21.5 million ($0.17/share, basic) for the three months ended December 31, 2013 due to increased production volumes more than offsetting weaker pricing, and the increased contribution of higher netback Wapiti Montney volumes. For the year ended December 31, 2014, NuVista's funds from operations were $110 million ($0.81/share, basic), a 46% increase from $75.3 million ($0.63/share, basic) in the same period of 2013 due to increased production volumes and commodity prices;
- Successfully executed an annual capital program of $312 million. Drilled 21 (19.7 net) wells in our Montney condensate rich resource play while constructing and commencing production in our Bilbo block compressor station and trunk lines;
- Entered into significant new firm processing contracts, strategically providing our Wapiti Montney play with capacity to grow to at least 2017 with flexibility, and guaranteed downstream liquids and natural gas transportation and fractionation;
- Completed the disposition of certain non-core assets producing approximately 2,065 Boe/d for net proceeds of $81.6 million; and
- Exited 2014 with bank borrowings of $172 million on a current facility of $300 million. Net debt, including the working capital deficiency was $184 million and net debt to annualized fourth quarter funds from operations was 1.3x;
- Achieved several new IP30 Montney well results as shown in the table below:
New Well IP30 Results
| Well | Raw Gas | Liquid Hydrocarbons | Total Sales | CGR C5+/Raw |
| (MMcf/d) | (Bbls/d) | (Boe/d) | (Bbls/MMcf) | |
| Average Bilbo Montney development typecurve | 5.8 | 435 Condensate |
1,356 | 75 |
| Well 30 (Bilbo Development) Location: 15-34-65-6 W6M | 7.8 | 752 Condensate |
1,978 | 97 |
| Well 31 (Bilbo Development) Location: 16-34-65-6 W6M | 8.8 | 663 Condensate |
2,007 | 75 |
| Well 32 (Bilbo Development) Location: 02/16-34-65-6 W6M | 4.4 | 467 Condensate |
1,158 | 107 |
| Average Wapiti Montney delineation well typecurve | 5.8 | 261 Condensate |
1,217 | 45 |
| Well 33 (South Delineation) Location: 1-28-66-6 W6M | 2.9 | 481 Condensate |
881 | 167 |
As evidenced by the strong well results, significant progress has been made in optimizing well completion technology for ever-improving results versus our typecurve. Progress on reducing well costs per metre of rock accessed has continued positively as we transition to two and three well pads as opposed to single well locations which dominated our drilling in 2011-2013. We anticipate costs to continue falling as the unit costs of supplies and services moves downward commensurate with the commodity price environment. Cost reductions in all aspects of our business remains a key area of focus for NuVista.
In 2014, NuVista announced significant progress in signing flexible firm processing arrangements for future growth with two tranches of raw gas processing contracts for capacity of 30 MMcf/d each, with startup anticipated in midyear of 2015 and 2016 respectively. We commenced construction in the fourth quarter of 2014 on the new Elmworth compressor station with an anticipated startup date of mid 2015. The station has an ultimate raw natural gas design capacity of 80 MMcf/d which will be added in modular stages as needed to serve the announced processing contracts plus potential future contracts.
2015 Guidance
In response to the recent downturn in commodity pricing NuVista announced in early 2015 that we had elected to revise our 2015 capital budget to a range of $270 to $290 million, which is reduced and high-graded from the original capital budget of $340 to $380 million announced in November of 2014. Spending for the first half of 2015 will be approximately 50 to 60% of the annual total. Activity for the first quarter of 2015 includes running two to three drilling rigs in the Wapiti area, ongoing completion and well tie-in activities, and constructing the Elmworth compressor station.
We will hold this pace of spending until the middle of the second quarter of 2015, where we will re-evaluate the capital program upon entering the spring breakup period. We have a high level of flexibility to further reduce the remaining 2015 capital spending plan if needed, in order to maintain balance sheet strength and maximize value in tune with market conditions at that time. Alternatively, should conditions warrant, we could scale up our capital program quickly and efficiently to take advantage of lower service costs and growth opportunities.
Our production guidance range for 2015 is unchanged at 22,500 to 24,000 Boe/d and we anticipate production in the range of 22,000 to 23,000 Boe/d for the first half of 2015. We would also like to affirm that our revised 2015 and 2016 production estimate in this environment is forecast to be sufficient to fulfill essentially all Take or Pay ("TOP") obligations with midstream companies as a result of the flexible terms which we have put in place previously. Despite reduced spending in this environment, our long term plans for 2016 and beyond still remain solid and intact.
NuVista is pleased to have delivered strong reserves and production growth in 2014, with metrics which showcase the high value and significant running room of the Wapiti Montney play. We will make the necessary adjustments to weather this low commodity price environment with strength and patience, while limiting capital spending to prudently protect our balance sheet. We are fortunate that the Wapiti Montney play is among the most prolific and economic in North America, and this may prove even more important during poor commodity price periods than in favorable periods. We would like to take this opportunity to thank our shareholders, our Board, and our staff for their support and dedication as we continue to build an ever more valuable future for NuVista.
Corporate Highlights |
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| Three months ended December 31, |
Year ended December 31, |
|||||||||
| ($ thousands, except per share) | 2014 | 2013 | 2014 | 2013 | ||||||
| Financial | ||||||||||
| Oil and natural gas revenue | 72,050 | 57,143 | 259,107 | 213,469 | ||||||
| Funds from operations(1) | 36,703 | 21,533 | 109,975 | 75,306 | ||||||
| Per basic and diluted share | 0.26 | 0.17 | 0.81 | 0.63 | ||||||
| Net loss | (42,478 | ) | (47,405 | ) | (58,881 | ) | (61,144 | ) | ||
| Per basic and diluted share | (0.31 | ) | (0.38 | ) | (0.43 | ) | (0.51 | ) | ||
| Adjusted net earnings (loss)(1) | 1,066 | (4,245 | ) | (3,569 | ) | (20,133 | ) | |||
| Per basic and diluted share | 0.01 | (0.03 | ) | (0.03 | ) | (0.17 | ) | |||
| Total assets | 1,024,080 | 905,711 | ||||||||
| Long-term debt, net of adjusted working capital(1) | 183,770 | 47,495 | ||||||||
| Capital expenditures | 67,968 | 80,011 | 312,208 | 224,389 | ||||||
| Property acquisitions | 35,075 | - | 45,237 | 2,183 | ||||||
| Proceeds on property dispositions | 69,377 | 17,878 | 81,550 | 30,270 | ||||||
| Weighted average common shares outstanding (thousands): | ||||||||||
| Basic and diluted | 138,579 | 125,411 | 136,497 | 120,430 | ||||||
| Operating | ||||||||||
| Production | ||||||||||
| Natural gas (MMcf/d) | 94.6 | 73.9 | 75.9 | 71.8 | ||||||
| Condensate (Bbls/d) | 4,732 | 2,500 | 3,137 | 1,925 | ||||||
| Butane (Bbls/d) | 544 | 482 | 540 | 458 | ||||||
| Propane (Bbls/d) | 780 | 712 | 687 | 710 | ||||||
| Ethane (Bbls/d) | 937 | 744 | 769 | 801 | ||||||
| Oil (Bbls/d) | 401 | 1,280 | 613 | 1,478 | ||||||
| Total oil equivalent (Boe/d) | 23,165 | 18,034 | 18,391 | 17,329 | ||||||
| Average product prices (2) | ||||||||||
| Natural gas ($/Mcf) | 3.77 | 3.40 | 4.19 | 3.28 | ||||||
| Condensate ($/Bbl) | 73.10 | 85.26 | 87.30 | 93.27 | ||||||
| Butane ($/Bbl) | 40.22 | 58.34 | 52.40 | 58.62 | ||||||
| Propane ($/Bbl) | 23.10 | 40.51 | 37.49 | 28.16 | ||||||
| Ethane ($/Bbl) | 13.96 | 10.91 | 14.15 | 9.42 | ||||||
| Oil ($/Bbl) | 67.95 | 71.46 | 86.77 | 78.48 | ||||||
| Operating expenses ($/Boe) | 10.92 | 11.16 | 11.22 | 11.70 | ||||||
| Operating netback ($/Boe) | 20.41 | 17.99 | 21.21 | 16.54 | ||||||
| Funds from operations netback ($/Boe)(1) | 17.22 | 12.99 | 16.39 | 11.91 | ||||||
| Share trading statistics | ||||||||||
| High | 10.83 | 7.57 | 12.47 | 8.40 | ||||||
| Low | 5.89 | 6.11 | 5.89 | 5.16 | ||||||
| Close | 7.41 | 7.14 | 7.41 | 7.14 | ||||||
| Average daily volume | 594,394 | 436,143 | 486,250 | 360,536 | ||||||
| NOTES: |
| (1) Funds from operations, revenue, funds from operations per share, funds from operations netback, operating netback, adjusted net earnings, adjusted net earnings per share and adjusted working capital are not defined by GAAP in Canada and are referred to as non-GAAP measures. Funds from operations are based on cash flow from operating activities as per the statement of cash flows before changes in non-cash working capital and asset retirement expenditures. Funds from operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net earnings (loss) per share. Funds from operations netback equals the total of revenues including realized commodity derivative gains/losses less royalties, transportation, operating, general and administrative, restricted stock units, interest expenses and cash taxes calculated on a Boe basis. Adjusted net earnings equals net earnings excluding after tax unrealized gains (losses) on commodity derivatives, impairments, impairment reversals, goodwill impairments and gains (losses) on property divestments. Operating netback equals the total of revenues including realized commodity derivative gains/losses less royalties, transportation and operating expenses calculated on a Boe basis. Adjusted working capital is current assets less current liabilities and excludes the current portions of the commodity derivative asset or liability. Long-term debt, net of adjusted working capital is calculated as long-term debt plus adjusted working capital. Total Boe is calculated by multiplying the daily production by the number of days in the period. For more details on non-GAAP measures, including reconciliation to GAAP measures refer to NuVista's "Management's Discussion and Analysis". |
| (2) Product prices exclude realized gains/losses on commodity derivatives. |
Summary of Corporate Reserves Data
The following table outlines NuVista's corporate finding and development costs in more detail:
| 3 Year-Average (1) | 2014 (1) | 2013 (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) | $14.75 | $11.64 | $13.67 | $10.55 | $14.51 | $12.31 |
| (1) 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. |
The following table provides summary reserve information based upon the GLJ Report using the published GLJ January 1, 2015 price forecast set forth later in this document:
| Natural Gas | Condensate | Other Liquids(2) |
Oil | Total | ||
| Reserves category(1) | Working Interest (MMcf) |
Working Interest (MBbls) |
Working Interest (MBbls) |
Working Interest (MBbls) |
Working Interest (MBoe) |
|
| Proved | ||||||
| Developed producing | 135,706 | 5,727 | 4,162 | 604 | 33,110 | |
| Developed non-producing | 43,623 | 1,469 | 823 | 465 | 10,027 | |
| Undeveloped | 279,866 | 15,011 | 5,876 | 337 | 67,868 | |
| Total proved | 459,195 | 22,207 | 10,861 | 1,405 | 111,006 | |
| Probable | 447,541 | 22,484 | 10,519 | 1,248 | 108,842 | |
| Total proved plus probable | 906,736 | 44,691 | 21,380 | 2,654 | 219,847 | |
| (1) Numbers may not add due to rounding. |
| (2) Propane, Butane, Ethane. |
The following table is a summary reconciliation of the 2014 year end working interest reserves with the working interest reserves reported in the 2013 year end reserves report:
Natural Gas(1) (MMcf) |
Liquids(1) (MBbls) |
Oil(1) (MBbls) |
Total Oil Equivalent(1) (MBoe) |
|||||
| Total proved | ||||||||
| Balance, December 31, 2013 | 330,507 | 22,756 | 2,615 | 80,456 | ||||
| Exploration and development(2) | 197,825 | 15,586 | 92 | 48,649 | ||||
| Technical revisions | 14,730 | (504 | ) | (129 | ) | 1,822 | ||
| Acquisitions | - | - | - | - | ||||
| Dispositions | (56,213 | ) | (2,898 | ) | (963 | ) | (13,229 | ) |
| Production | (27,654 | ) | (1,873 | ) | (209 | ) | (6,691 | ) |
| Balance, December 31, 2014 | 459,195 | 33,068 | 1,405 | 111,006 | ||||
| Total proved plus probable | ||||||||
| Balance, December 31, 2013 | 566,655 | 39,928 | 4,860 | 139,230 | ||||
| Exploration and development(2) | 409,773 | 32,053 | 146 | 100,495 | ||||
| Technical revisions | 37,604 | 77 | (454 | ) | 5,889 | |||
| Acquisitions | - | - | - | - | ||||
| Dispositions | (79,642 | ) | (4,114 | ) | (1,689 | ) | (19,077 | ) |
| Production | (27,654 | ) | (1,873 | ) | (209 | ) | (6,691 | ) |
| Balance, December 31, 2014 | 906,736 | 66,071 | 2,653 | 219,847 |
| (1) Numbers may not add due to rounding. |
| (2) Reserve additions for drilling extensions, infill drilling and improved recovery. |
The following table summarizes the future development capital included in the GLJ Report:
($ thousands, undiscounted) |
Proved |
Proved plus probable |
||
| Balance, December 31, 2013 | 587,069 | 1,027,761 | ||
| Dispositions | (96,681 | ) | (123,156 | ) |
| Exploration and development | 377,725 | 809,786 | ||
| Balance, December 31, 2014 | 868,113 | 1,714,391 |
Summary Wapiti Montney Play Reserves Data
The following table summarizes the reserves for the Wapiti Montney play based upon the GLJ Report using the published GLJ January 1, 2015 price forecast set forth below (with comparatives at January 1, 2014 price forecast):
| December 31, 2014 | December 31, 2013 | |
| Reserves category | Working Interest (Mboe) |
Working Interest (Mboe) |
| Proved producing | 20,000 | 9,716 |
| Total proved | 89,349 | 46,068 |
| Total proved plus probable | 183,703 | 86,174 |
The following table summarizes the future development capital for the Wapiti Montney play included in the GLJ Report:
($ thousands, undiscounted) |
Proved |
Proved plus probable |
||
| Balance, December 31, 2013 | 449,016 | 801,109 | ||
| Dispositions | (19,228 | ) | (21,990 | ) |
| Exploration and development | 386,291 | 792,836 | ||
| Balance, December 31, 2014 | 816,079 | 1,571,955 |
The estimates of reserves for the Wapiti Montney play may not reflect the same confidence level as estimates of reserves of all NuVista's properties due to the effect of aggregation.
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, 2014 and based on published GLJ future price forecast as at January 1, 2015 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)(2) ($ thousands) | 0% | 5% | 10% | 15% | 20% | |
| Proved | ||||||
| Developed producing | 592,507 | 448,911 | 364,552 | 309,899 | 271,789 | |
| Developed non-producing | 159,893 | 110,015 | 82,703 | 65,838 | 54,470 | |
| Undeveloped | 1,067,785 | 570,215 | 321,255 | 183,054 | 100,274 | |
| Total proved | 1,820,186 | 1,129,141 | 768,510 | 558,790 | 426,533 | |
| Probable | 2,337,846 | 1,141,376 | 637,223 | 384,409 | 241,337 | |
| Total proved plus probable | 4,158,032 | 2,270,517 | 1,405,733 | 943,199 | 667,869 | |
| (1) Numbers may not add due to rounding. |
| (2) Estimate future net revenues of reserves do not represent the fair market value of reserves. |
The following table is a summary of pricing and inflation rate assumptions based on published GLJ forecast prices and costs as at January 1, 2015:
| 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 | ||||||||
| 2015 | 3.31 | 69.24 | 19.63 | 52.91 | 62.50 | 64.71 | 2.0 | 0.850 |
| 2016 | 3.77 | 85.60 | 32.00 | 60.80 | 75.00 | 80.00 | 2.0 | 0.875 |
| 2017 | 4.02 | 91.71 | 38.57 | 65.14 | 80.00 | 85.71 | 2.0 | 0.875 |
| 2018 | 4.27 | 97.83 | 41.14 | 69.49 | 85.00 | 91.43 | 2.0 | 0.875 |
| 2019 | 4.53 | 103.94 | 43.71 | 73.83 | 90.00 | 97.14 | 2.0 | 0.875 |
| 2020 | 4.78 | 110.06 | 46.29 | 78.17 | 95.00 | 102.86 | 2.0 | 0.875 |
| 2021 | 5.03 | 113.62 | 47.78 | 80.70 | 98.54 | 106.18 | 2.0 | 0.875 |
| 2022 | 5.28 | 115.89 | 48.74 | 82.31 | 100.51 | 108.31 | 2.0 | 0.875 |
| 2023 | 5.53 | 118.20 | 49.71 | 83.96 | 102.52 | 110.47 | 2.0 | 0.875 |
| 2024 | 5.71 | 120.56 | 50.70 | 85.63 | 104.57 | 112.67 | 2.0 | 0.875 |
| 2025+ | +2%/yr | +2%/yr | +2%/yr | +2%/yr | +2%/yr | +2%/yr | 2.0 | 0.875 |
| (1) Inflation rate for costs. |
| (2) Exchange rate used to generate the benchmark reference prices in this table. |
For full disclosure, information regarding our 2014 Year End Reserves and Economic Contingent Resources Evaluations will be filed on SEDAR and can also be accessed on our website at www.nuvistaenergy.com on March 9, 2015.
ADVISORY REGARDING OIL AND GAS INFORMATION
This news release contains the terms barrels of oil equivalent ("Boe"). Natural gas is converted to a Boe using six thousand cubic feet of gas to one barrel of oil. Boes may be misleading, particularly if used in isolation. The foregoing conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As well, given that the value ratio based on the current price of crude oil to natural gas is significantly different from the 6:1 energy equivalency ratio, using a conversion ratio on a 6:1 basis may be misleading as an indication of value.
Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.
NuVista has presented certain typecurves and well economics which are based on NuVista's historical production in the Bilbo and Elmworth development areas, in addition to production history from analogous Montney developments located in close proximity to the Wapiti area. Such typecurves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in the Montney area and for determining the success of the performance of development wells; however, such typecurves and well economics are not necessarily determinative of the production rates and performance of existing and future wells. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the typecurves presented; however, there is no certainty that NuVista will ultimately recover such volumes from the wells it drills.
This press release discloses drilling locations in two categories: (i) proved and/or probable reserves locations; and (ii) Contingent Resources locations. Proved and probable locations and Contingent Resources locations are derived from the Corporation's most recent independent reserves and resources evaluation as prepared by GLJ as of December 31, 2014 and account for drilling locations that have associated proved and/or probable reserves or Contingent Resources, as applicable. There is no certainty that NuVista will drill all drilling locations and if drilled there is no certainty that such locations will result in additional production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory, oil and natural gas prices, costs, actual drilling results and other factors.
ADVISORY REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
This press release contains forward-looking statements and forward-looking information (collectively, "forward-looking statements") within the meaning of applicable securities laws. The use of any of the words "will", "expects", "believe", "plans", "potential" and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this press release contains forward looking statements, including management's assessment of: NuVista's future strategy, plans, opportunities and operations; forecast production; production mix; drilling, development, completion and tie-in plans and timing and results thereof; expectations of timing of construction of facilities and the benefits thereof; ability to fulfill all TOP obligations; plans to limit capital spending to manage NuVista's balance sheet and maximize value, commodity price expectations, future processing capacity, future drilling and completions costs;
NuVista's assessment of field conditions; typecurves; condensate and natural gas liquid yields; the timing, allocation and efficiency of NuVista's capital program and the results therefrom; the anticipated potential of NuVista's asset base; reserves life indexes; and industry conditions. By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, current and future commodity prices, currency and interest rates, anticipated production rates, borrowing, operating and other costs and funds from operations, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; and including, without limitation, those risks considered under "Risk Factors" in our Annual Information Form. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. NuVista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
CONSOLIDATED FINANCIAL STATEMENTS AND MD&A
December 31, 2014 audited consolidated financial statements and notes to the consolidated financial statements and Management's Discussion and Analysis for NuVista Energy Ltd. will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on Monday, March 9, 2015 and can also be accessed on NuVista's website at www.nuvistaenergy.com.
RESERVES AND RESOURCES ADVISORIES
The reserves and resources estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and are effective as of December 31, 2014. All reserves and resources information has been presented on a gross basis, which are the Company's working interest share before deduction of royalties and without including any royalty interests of the Company. The reserves and resources have been categorized accordance with the reserves and resource definitions as set out in the COGE Handbook.
The Company has presented certain estimates of Contingent Resources and Economic Contingent Resources ("ECR"). The following is the definition of Contingent Resources and Economic Contingent Resources as provided in the COGE Handbook:
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources or that any portion of the volumes currently classified as Contingent Resources will be produced. The recovery and resource estimates provided herein are estimates. The volumes of Contingent Resources that may be re-classified as Reserves and future production from such Contingent Resources may be greater than or less than the estimates provided herein.
Economic Contingent Resources ("ECR") are those Contingent Resources that are currently economically recoverable based on specific forecasts of commodity prices and costs.
The resources estimates contained herein have been presented on best estimate basis, which represents the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that quantities actually recovered will equal or exceed the best estimate.
The primary contingency that prevents the classification of the ECR as reserves is for additional drilling, completion and testing to occur and confirm viable commercial rates. Proved or proved and probable reserves were assigned by GLJ for areas in the immediate vicinity of producing or tested wells. ECR were assigned by GLJ beyond areas that were assigned reserves but within 3 miles of existing wells. As continued delineation drilling occurs, some resources currently classified as ECR are expected to be re-classified as Reserves. An additional contingency is the lack of infrastructure to facilitate full development in the short term, including the necessary facilities for gas gathering and processing and for the extraction of natural gas liquids. The re-classification of the ECR as Reserves is also subject to various non-technical contingencies which must be overcome such as lack of markets, legal, environmental and political concerns surrounding the possible banning of hydraulic fracturing, a technology required to develop the ECR, and other operational risks applicable to oil and gas issuers.
Volumes of resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. The currently producing assets of NuVista and other industry parties in the Wapiti Montney area are used as performance analogs for ECR within these areas. The evaluation of ECR is based on an independent third party evaluation that assumes that the vast majority of Nuvista's ECR will be recovered using horizontal multistage hydraulic fracturing using multi-well pad drilling, which is an established technology.
Continuous resource assessment through multi-year delineation and development programs and significant levels of future capital expenditures are required in order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low commodity prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fracking technology and applications. For ECR to be converted to reserves, management and the board of NuVista need to ascertain commercial production rates, then develop firm plans, including timing, infrastructure, and the commitment of capital. Confirmation of commercial productivity is generally required before the company can prepare firm development plans and commit required capital for the development of the ECR.
See "Reserves and Resource Disclosure" and the disclosure under the heading "Risk Factors" in the Annual Information Form, which will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on or before March 31, 2015.
Contact Information:
Jonathan A. Wright
President and CEO
(403) 538-8501
NuVista Energy Ltd.
Ross L. Andreachuk
VP, Finance and CFO
(403) 538-8539