CALGARY, ALBERTA–(Marketwired – Feb. 5, 2015) – Bonavista Energy Corporation (“Bonavista”) (TSX:BNP) is pleased to announce production and reserves for 2014. Bonavista’s strategy to concentrate development spending in our core areas has resulted in improved capital and operating efficiencies throughout 2014 leading to low cost reserves additions and record production.
2014 Production:
For the year ended December 31, 2014, we invested $535.8 million (unaudited) into the concentration of our asset portfolio and the development of our key plays in our core areas. This resulted in production of 77,211 boe per day representing a 5% increase over the same period in 2013. Highlights of this production performance include:
2014 Reserves Highlights:
The economics of our key plays rank amongst the best in western Canada and they continue to improve with time and technology. The successful execution of our 2014 capital program continues to reinforce the quality of our asset portfolio as demonstrated by the highlights listed below:
2014 Independent Reserves Evaluation:
The evaluation of our reserves was done in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserves information as required under NI 51-101 will be included in Bonavista’s Annual Information Form which will be filed on SEDAR on or before March 31, 2015.
Independent reserve evaluators, GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated 90% of our reserves (on a net present value discounted at 10% basis) and the balance of our reserves were evaluated internally and reviewed by GLJ in their report dated February 3, 2015 and effective December 31, 2014 (the “GLJ Report”).
Reserves Summary:
The following tables summarize our working interest oil, natural gas liquids and natural gas reserves and the net present values of future net revenue for these reserves (before taxes) using forecast prices and costs as set forth in the GLJ Report.
| Working Interest Reserves(1): | Natural Gas (MMcf) |
Light, Medium and Heavy Oil (Mbbls) |
Natural Gas Liquids (Mbbls) | Total Reserves (Mboe) | NPV of Future Net Revenue Discounted at 5% ($000’s) |
NPV of Future Net Revenue Discounted at 10% ($000’s) |
NPV of Future Net Revenue Discounted at 15% ($000’s) |
||||||||
| Proved: | |||||||||||||||
| Proved Producing | 661,960 | 17,520 | 41,609 | 169,456 | 2,436,216 | 1,905,214 | 1,569,033 | ||||||||
| Proved Non-Producing | 13,999 | 321 | 795 | 3,449 | 42,137 | 31,356 | 24,199 | ||||||||
| Proved Undeveloped | 418,441 | 3,527 | 29,556 | 102,823 | 1,009,712 | 635,195 | 408,721 | ||||||||
| Total Proved | 1,094,400 | 21,369 | 71,960 | 275,729 | 3,488,065 | 2,571,766 | 2,001,953 | ||||||||
| Probable | 595,491 | 9,075 | 42,715 | 151,038 | 1,914,143 | 1,160,804 | 780,703 | ||||||||
| Proved plus Probable | 1,689,891 | 30,444 | 114,675 | 426,767 | 5,402,209 | 3,732,570 | 2,782,656 | ||||||||
| (1) Amounts may not add due to rounding. | |||||||||||||||
The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2015 as outlined below. The GLJ January 1, 2015 forecast pricing for natural gas at AECO and West Texas Intermediate (“WTI”) oil are Cdn$3.31/mmbtu and US$62.50/bbl respectively. This represents a 22% decline in forecast natural gas pricing and a 36% decline in forecast 2015 WTI oil pricing when compared to GLJ’s forecast pricing for 2015 at January 1, 2014.
| Price Forecast | West Texas Intermediate Crude Oil ($US/bbl) |
Edmonton Light Crude Oil ($Cdn/bbl) |
Natural Gas at AECO ($Cdn/mmbtu) |
Exchange Rate ($US/$Cdn) |
| 2015 | 62.50 | 64.71 | 3.31 | 0.850 |
| 2016 | 75.00 | 80.00 | 3.77 | 0.875 |
| 2017 | 80.00 | 85.71 | 4.02 | 0.875 |
| 2018 | 85.00 | 91.43 | 4.27 | 0.875 |
| 2019 | 90.00 | 97.14 | 4.53 | 0.875 |
| 2020 | 95.00 | 102.86 | 4.78 | 0.875 |
| 2021 | 98.54 | 106.18 | 5.03 | 0.875 |
| 2022 | 100.51 | 108.31 | 5.28 | 0.875 |
| 2023 | 102.52 | 110.47 | 5.53 | 0.875 |
| 2024 | 104.57 | 112.67 | 5.71 | 0.875 |
| Escalate thereafter at | 2.0%/year | 2.0%/year | 2.0%/year | 0.875 |
Reserve Life Index (“RLI”):
Our business plan to maximize shareholder value is based upon a balanced approach of generating income and growth. The profitable growth of our reserves coupled with the sustainable production of these reserves will generate long term returns for our shareholders.
In 2014, our RLI did not change materially demonstrating the sustainable balance that exists between our capital program, our reserves additions and our production levels. The production decline characteristics of our asset portfolio influence our RLI. For 2015, GLJ is forecasting a base decline rate of 29% for all wells on production at December 31, 2014.
The following table highlights our historical RLI.
| Reserve Life Index (Years) (1) | 2014 | 2013 | 2012 | 2011 | 2010 |
| Total Proved | 9.4 | 9.1 | 9.6 | 8.8 | 9.1 |
| Proved plus Probable | 13.1 | 13.2 | 13.5 | 12.2 | 12.0 |
| (1) Calculated based on the amount for the relevant reserves category divided by the production forecast for the applicable year prepared by GLJ. | |||||
Future Development Costs:
Changes in forecast FDC occur annually and result from development, acquisition and disposition activities. Cost estimates reflect GLJ’s best estimate of the costs required to bring the proved and proved plus probable reserves on production. We have 203 mmboe reserves assigned to $1.5 billion of FDC. At a cost of $7.52 per boe, these future reserves generate $1.3 billion of net present value discounted at 10%.
Current year FDC as a ratio of trailing average three year E&D expenditures and funds from operations are 3.1:1 and 3.2:1 times respectively, representing prudent and sustainable development forecasts.
The following table sets forth the schedule of FDC required to develop these future reserves (using forecast prices and costs).
| Future Development Costs | Total Proved ($ millions) |
Proved plus Probable ($ millions) |
| 2015 | 236 | 315 |
| 2016 | 329 | 472 |
| 2017 | 210 | 314 |
| 2018 | 111 | 241 |
| 2019 | 82 | 115 |
| Remaining | 45 | 65 |
| Total (Undiscounted) | 1,013 | 1,522 |
| Total (Discounted at 10%) | 828 | 1,233 |
Reserves Performance Ratios:
The following tables highlight Bonavista’s reserves, finding and development (“F&D”) costs, finding, development and acquisition (“FD&A”) costs and the associated recycle ratios. Throughout the year, Bonavista experienced significant improvements in overall efficiencies resulting in F&D and FD&A cost reductions of 9% ($10.84 per boe) and 10% ($9.95 per boe), respectively.
Bonavista considers recycle ratio as an important measure of profitability. It is measured by dividing the operating netback by the F&D or FD&A costs per boe for the year. Bonavista delivered an F&D recycle ratio of 2.1:1 for proved plus probable reserves and FD&A recycle ratio of 2.3:1 for proved plus probable reserves including revisions and changes in future development costs.
| 2014 | 2013 | 2012 | |||
| Reserves (Mboe): | |||||
| Proved producing | 169,456 | 154,833 | 148,755 | ||
| Total proved | 275,729 | 256,216 | 248,409 | ||
| Proved plus probable | 426,767 | 398,529 | 372,220 | ||
| Capital Expenditures ($Millions): | |||||
| Exploration and development | 642.6 | 443.8 | 402.1 | ||
| Acquisitions, net of dispositions | (106.8) | 20.5 | (11.0) | ||
| Total capital expenditures | 535.8 | 464.3 | 391.1 | ||
| Operating Netback ($/boe)(1): | |||||
| Current year | 22.60 | 20.54 | 17.70 | ||
| Three-year weighted average | 20.37 | 20.92 | 22.00 | ||
| Finding and Development Costs: | |||||
| Proved Producing: | |||||
| Change in FDC ($Millions) | 1.1 | 10.2 | 3.3 | ||
| Reserves additions (MMboe) | 49.5 | 27.4 | 23.2 | ||
| F&D costs ($/boe)(2) | 12.83 | 16.46 | 17.45 | ||
| F&D recycle ratio(3) | 1.8 | 1.2 | 1.0 | ||
| F&D three-year weighted costs ($/boe)(2) | 14.89 | 16.68 | 15.45 | ||
| F&D recycle ratio three-year weighted average(3) | 1.4 | 1.3 | 1.4 | ||
| Total Proved: | |||||
| Change in FDC ($Millions) | 45.0 | 40.1 | 145.2 | ||
| Reserves additions (MMboe) | 49.5 | 25.9 | 27.9 | ||
| F&D costs ($/boe)(2) | 12.95 | 15.57 | 16.98 | ||
| F&D recycle ratio(3) | 1.7 | 1.3 | 1.0 | ||
| F&D three-year weighted costs ($/boe)(2) | 14.70 | 17.10 | 15.92 | ||
| F&D recycle ratio three-year weighted average(3) | 1.4 | 1.2 | 1.4 | ||
| Proved plus Probable: | |||||
| Change in FDC ($Millions) | 27.9 | 120.7 | 234.7 | ||
| Reserves additions(MMboe) | 57.2 | 38.4 | 35.8 | ||
| F&D costs ($/boe)(2) | 10.84 | 11.95 | 14.66 | ||
| F&D recycle ratio(3) | 2.1 | 1.7 | 1.2 | ||
| F&D three-year weighted costs ($/boe)(2) | 12.20 | 13.62 | 13.89 | ||
| F&D recycle ratio three-year weighted average(3) | 1.7 | 1.5 | 1.6 | ||
| Finding, Development and Acquisition Expenditures: | |||||
| Proved Producing: | |||||
| Change in FDC ($Millions) | 1.1 | 10.2 | 3.3 | ||
| Reserves additions (MMboe) | 42.8 | 32.8 | 28.9 | ||
| FD&A costs ($/boe)(2) | 12.49 | 14.45 | 13.66 | ||
| FD&A recycle ratio(3) | 1.8 | 1.4 | 1.3 | ||
| FD&A three-year weighted costs ($/boe)(2) | 13.43 | 15.65 | 16.10 | ||
| FD&A recycle ratio three-year weighted average(3) | 1.5 | 1.3 | 1.4 | ||
| Total Proved: | |||||
| Change in FDC ($Millions) | 45.0 | 40.1 | 145.2 | ||
| Reserves additions (MMboe) | 47.6 | 34.6 | 41.9 | ||
| FD&A costs ($/boe)(2) | 12.13 | 14.60 | 12.81 | ||
| FD&A recycle ratio(3) | 1.9 | 1.4 | 1.4 | ||
| FD&A three-year weighted costs ($/boe)(2) | 13.05 | 15.31 | 15.11 | ||
| FD&A recycle ratio three-year weighted average(3) | 1.6 | 1.4 | 1.5 | ||
| Proved plus Probable: | |||||
| Change in FDC ($Millions) | 27.9 | 120.7 | 234.7 | ||
| Reserves additions (MMboe) | 56.4 | 53.1 | 56.1 | ||
| FD&A costs ($/boe)(2) | 9.95 | 11.03 | 11.16 | ||
| FD&A recycle ratio(3) | 2.3 | 1.9 | 1.6 | ||
| FD&A three-year weighted costs ($/boe)(2) | 10.70 | 12.07 | 12.82 | ||
| FD&A recycle ratio three-year weighted average(3) | 1.9 | 1.7 | 1.7 | ||
| (1) Operating netback is calculated using production revenues including realized gains and losses on financial instruments commodity contracts less royalties, transportation and operating costs calculated on a per boe equivalent basis. | |||||
| (2) Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis (6:1). | |||||
| (3) Recycle ratio is defined as operating netback per boe divided by either F&D or FD&A costs on a per boe basis. | |||||
| (4) The aggregate of the E&D costs incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. | |||||
Bonavista is a mid-sized energy corporation committed to maintaining its emphasis on operating high quality oil and natural gas properties, providing a balance of growth and income to our shareholders while ensuring financial strength and sustainability.
[expand title=”Advisories & Contact”]General
This news release contains certain financial information that has been derived from our unaudited consolidated financial statements for the year ended December 31, 2014.
Oil and Gas Advisories
The reserves estimates contained in this press release represent our gross reserves as at December 31, 2014 and are defined under NI 51-101, as our interest before deduction of royalties and without including any of our royalty interests. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis. Estimated values of future net revenue disclosed herein do not represent fair market value.
Finding and development costs both including and excluding acquisitions and dispositions have been presented above. While NI 51-101 requires that the effects of acquisitions and dispositions be excluded, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.
To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. 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 6:1 conversion ratio may be misleading as an indication of value.
Forward Looking Statements
Corporate information provided herein contains forward-looking information relating to our plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities including statements about our plans to maximize shareholder value, generate long term returns to our shareholders and to profitably grow our reserves. Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
The reader is cautioned that assumptions used in the preparation of such information, particularly those pertaining to cash dividends, production volumes, commodity prices, operating costs and drilling results, which are considered reasonable by Bonavista at the time of preparation, may be proven to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein and the variations may be material. There is no representation by Bonavista that actual results achieved during the forecast period will be the same in whole or in part as those forecasts. Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Non-GAAP Measures
This press release contains the term “operating netbacks” which does not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other companies. Bonavista uses operating netbacks to analyze financial and operating performance. Bonavista believes these benchmarks are key measures of profitability and overall sustainability. These terms are commonly used in the oil and gas industry. Operating netbacks are not intended to represent operating profits nor should they be viewed as an alternative to funds from operations provided by operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Operating netback is calculated using production revenues including realized gains and losses on financial instruments commodity contracts less royalties, transportation and operating costs calculated on a per boe basis.
Jason E. Skehar
President & CEO
Glenn A. Hamilton
Senior Vice President & CFO
Berk Sumen
Manager, Investor Relations
Bonavista Energy Corporation
1500, 525 – 8th Avenue SW
Calgary, AB T2P 1G1
Phone: (403) 213-4300
Website: www.bonavistaenergy.com
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