CALGARY, ALBERTA–(Marketwired – Jan. 27, 2016) – Bonavista Energy Corporation (“Bonavista”) (TSX:BNP) is pleased to report that our 2015 exploration and development (“E&D”) program has resulted in a finding and development cost of $7.26 per boe on a proved plus probable basis.
For the year ended December 31, 2015, we invested $283.4 million (unaudited) into the development of the key plays in our two core areas. This has resulted in average production of 79,288 boe per day for 2015, a 3% increase over the same period in 2014 notwithstanding a 47% reduction in capital spending. The 67.1 net wells placed on-stream in 2015 added 33,800 boe per day of production in their first month of production at a cost of $240.0 million. This represents a 15% improvement (over 2014) in our cost to add production. Furthermore, with operating costs below $6.00 per boe in the fourth quarter, our 2015 net operating income was approximately $16.20 per boe, generating a proved plus probable recycle ratio of 2.2:1 from our E&D program.
2015 Reserves Highlights:
Our key plays delivered consistent results and resilient economics in 2015, ranking them amongst the best in western Canada. The successful execution of our 2015 capital program continues to reinforce the quality of our asset portfolio as demonstrated by the highlights listed below:
- Reduced finding and development costs (“F&D”) by 33% to $7.26 per boe on a proved plus probable basis, including changes in future development costs (“FDC”), resulting in a recycle ratio of 2.2:1;
- Finding, development and acquisition costs (“FD&A”) remained similar to last year at $9.84 per boe on a proved plus probable basis, including changes in FDC, despite the burden of the disposition of high cost, low value reserves;
- Maintained a balanced proved plus probable reserve composition with 40% of the reserves and 51% of the net present value of the future net revenue of the reserves discounted at 10% (“PV10 value”) being proved developed producing;
- Replaced 91% of production with proved developed producing reserve additions, despite the removal of 10.3 MMboe resulting from the price-related acceleration of economic cutoffs; and
- Using the December 31, 2015 independent reserves evaluation, the PV10 value of our reserves, net of estimated debt would result in a value of approximately $5.24 per common share.
2015 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 our Annual Information Form which will be filed on SEDAR on or before March 30, 2016.
Independent reserve evaluators, GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated 98% of our reserves (on a PV10 basis) and the balance of our reserves were evaluated internally and reviewed by GLJ in their report dated January 25, 2016 and effective December 31, 2015 (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(2) |
Crude Oil(3) |
Natural Gas Liquids |
Oil Equiv- alent Total Re- serves |
NPV of Future Net Revenue Discounted at | |||
5% | 10% | 15% | ||||||
(MMcf) | (Mbbls) | (Mbbls) | (Mboe) | ($000’s) | ($000’s) | ($000’s) | ||
Proved: | ||||||||
Proved Producing | 614,884 | 14,377 | 45,215 | 162,072 | 1,510,109 | 1,231,447 | 1,034,190 | |
Proved Non-Producing | 19,293 | 623 | 1,294 | 5,132 | 49,633 | 38,086 | 30,297 | |
Proved Undeveloped | 391,783 | 2,975 | 26,748 | 95,020 | 610,869 | 363,464 | 216,315 | |
Total Proved | 1,025,960 | 17,974 | 73,256 | 262,224 | 2,170,612 | 1,632,998 | 1,280,802 | |
Probable | 575,745 | 8,092 | 40,221 | 144,270 | 1,321,645 | 778,725 | 506,772 | |
Total Proved plus Probable | 1,601,705 | 26,066 | 113,477 | 406,494 | 3,492,256 | 2,411,723 | 1,787,574 |
- Amounts may not add due to rounding.
- Includes Conventional Natural Gas, Shale Natural Gas and Coal Bed Methane.
- Includes Light, Medium, Heavy and Tight Oil.
The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2016 as outlined below. The GLJ January 1, 2016 forecast pricing for natural gas at AECO and West Texas Intermediate (“WTI”) oil are CDN$2.76/MMBtu and US$44.00/bbl respectively. This represents a 27% reduction in forecast natural gas pricing and a 41% reduction in forecast 2016 WTI oil pricing when compared to GLJ’s forecast pricing for 2016 at January 1, 2015.
Price Forecast | Edmonton Light Crude Oil | WTI Oil | AECO Natural Gas | Exchange Rate |
(CDN$/bbl) | (US$/bbl) | (CDN$/MMBtu) | (US$/CDN$) | |
2016 | 55.86 | 44.00 | 2.76 | 0.725 |
2017 | 64.00 | 52.00 | 3.27 | 0.750 |
2018 | 68.39 | 58.00 | 3.45 | 0.775 |
2019 | 73.75 | 64.00 | 3.63 | 0.800 |
2020 | 78.79 | 70.00 | 3.81 | 0.825 |
2021 | 82.35 | 75.00 | 3.90 | 0.850 |
2022 | 88.24 | 80.00 | 4.10 | 0.850 |
2023 | 94.12 | 85.00 | 4.30 | 0.850 |
2024 | 96.48 | 87.88 | 4.50 | 0.850 |
2025 | 98.41 | 89.63 | 4.60 | 0.850 |
Thereafter | 2.0%/year | 2.0%/year | 2.0%/year | 0.850 |
Reserves Reconciliation
RECONCILIATION OF GROSS RESERVES BY PRINCIPAL PRODUCT TYPE FORECAST PRICES AND COSTS(1) | |||||||
LIGHT AND MEDIUM OIL | HEAVY OIL | ||||||
Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | ||
(Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | ||
December 31, 2014 | 20,373 | 8,751 | 29,124 | 996 | 324 | 1,320 | |
Extensions and Improved Recovery(2) | 415 | 454 | 868 | – | – | – | |
Technical Revisions | (55) | (992) | (1,045) | (273) | (64) | (338) | |
Discoveries | – | – | – | – | – | – | |
Acquisitions | 117 | 42 | 159 | – | – | – | |
Dispositions | (850) | (380) | (1,230) | (184) | (70) | (255) | |
Economic Factors | (569) | 64 | (505) | (14) | (37) | (51) | |
Production | (1,955) | – | (1,955) | (26) | – | (26) | |
December 31, 2015 | 17,476 | 7,939 | 25,416 | 498 | 153 | 651 | |
NATURAL GAS | NATURAL GAS LIQUIDS | ||||||
Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | ||
(MMcf) | (MMcf) | (MMcf) | (Mbbls) | (Mbbls) | (Mbbls) | ||
December 31, 2014 | 1,094,400 | 595,491 | 1,689,891 | 71,960 | 42,715 | 114,675 | |
Extensions and Improved Recovery(2) | 143,821 | 38,494 | 182,315 | 7,969 | (80) | 7,890 | |
Technical Revisions | (37,148) | (39,227) | (76,375) | 1,367 | (2,446) | (1,079) | |
Discoveries | – | – | – | – | – | – | |
Acquisitions | 12,299 | 5,789 | 18,089 | 1,008 | 418 | 1,426 | |
Dispositions | (37,068) | (24,485) | (61,553) | (920) | (1,292) | (2,212) | |
Economic Factors | (27,502) | (318) | (27,820) | (1,689) | 906 | (783) | |
Production | (122,841) | – | (122,841) | (6,438) | – | (6,438) | |
December 31, 2015 | 1,025,960 | 575,745 | 1,601,705 | 73,256 | 40,221 | 113,477 | |
OIL EQUIVALENT | ||||
Proved | Probable | Proved Plus Probable | ||
(Mboe) | (Mboe) | (Mboe) | ||
December 31, 2014 | 275,729 | 151,038 | 426,768 | |
Extensions and Improved Recovery(2) | 32,354 | 6,790 | 39,143 | |
Technical Revisions | (5,152) | (10,040) | (15,192) | |
Discoveries | – | – | – | |
Acquisitions | 3,175 | 1,425 | 4,599 | |
Dispositions | (8,133) | (5,823) | (13,956) | |
Economic Factors | (6,856) | 880 | (5,976) | |
Production | (28,893) | – | (28,893) | |
December 31, 2015 | 262,224 | 144,270 | 406,494 |
- Amounts may not add due to rounding.
- Infill Drilling, Improved Recovery and Extensions have been grouped as Extensions and Improved Recovery as per NI 51-101.
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 2015, our RLI increased by 8% to 14.1 years 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 2016, GLJ is forecasting a proved developed producing decline rate of 25.6%.
The following table highlights our historical RLI.
Reserve Life Index (Years)(1) | 2015 | 2014 | 2013 | 2012 | 2011 |
Total Proved | 9.7 | 9.4 | 9.1 | 9.6 | 8.8 |
Total Proved plus Probable | 14.1 | 13.1 | 13.2 | 13.5 | 12.2 |
- 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 180.4 MMboe reserves assigned to $1,269 million of FDC. At a cost of $7.03 per boe, these future reserves generate $778 million of Net Present Value discounted at 10%.
Current year FDC as a ratio of trailing average three year E&D expenditures are 2.8:1 times, representing prudent and sustainable development forecasts.
The following table sets forth the schedule of FDC required to develop these future reserves (using forecast prices and costs).
Future Development Costs | Total Proved | Total Proved plus Probable |
($ thousands) | ($ thousands) | |
2016 | 138,294 | 154,097 |
2017 | 216,841 | 326,874 |
2018 | 263,530 | 357,396 |
2019 | 97,221 | 190,035 |
2020 | 53,345 | 213,179 |
Remaining | 57,307 | 82,315 |
Total (Undiscounted) | 826,538 | 1,323,896 |
Total (Discounted at 10%) | 657,700 | 1,025,431 |
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 proved plus probable F&D cost reductions of 33% to $7.26 per boe.
Bonavista considers recycle ratio an important measure of profitability. It is measured by dividing the operating netback by the F&D costs per boe for the year. Bonavista delivered an F&D recycle ratio of 2.2:1 for proved plus probable reserves including revisions and changes in future development costs.
2015 | 2014 | 2013 | ||
Reserves (Mboe): | ||||
Proved producing | 162,072 | 169,456 | 154,833 | |
Total proved | 262,224 | 275,729 | 256,216 | |
Proved plus probable | 406,494 | 426,768 | 398,529 | |
Capital Expenditures ($ millions): | ||||
E&D | 313.9 | 639.6 | 443.8 | |
Acquisitions, net of dispositions | (30.6) | (106.8) | 20.5 | |
Total capital expenditures | 283.4 | 532.8 | 464.4 | |
Operating Netback ($/boe)(1): | ||||
Current year | 16.20 | 22.60 | 20.54 | |
Three-year weighted average | 19.74 | 20.37 | 20.92 |
- Amounts may not add due to rounding.
Finding and Development Costs: | 2015 | 2014 | 2013 | |
Proved Producing: | ||||
Change in FDC ($ millions) | (0.3) | (4.0) | 7.2 | |
Reserves additions (MMboe) | 26.3 | 49.5 | 27.4 | |
F&D costs ($/boe)(2) | 11.94 | 12.84 | 16.46 | |
F&D recycle ratio(3) | 1.4 | 1.8 | 1.2 | |
F&D three-year weighted costs ($/boe)(2) | 13.57 | 14.90 | 16.68 | |
F&D recycle ratio three-year weighted average(3) | 1.5 | 1.4 | 1.3 | |
Total Proved: | ||||
Change in FDC ($ millions) | (188.7) | 1.3 | (41.0) | |
Reserves additions (MMboe) | 20.3 | 49.5 | 25.9 | |
F&D costs ($/boe)(2) | 6.15 | 12.96 | 15.57 | |
F&D recycle ratio(3) | 2.6 | 1.7 | 1.3 | |
F&D three-year weighted costs ($/boe)(2) | 12.21 | 14.70 | 17.10 | |
F&D recycle ratio three-year weighted average(3) | 1.6 | 1.4 | 1.2 | |
Total Proved plus Probable: | ||||
Change in FDC ($ millions) | (183.5) | (19.1) | 15.0 | |
Reserves additions (MMboe) | 18.0 | 57.1 | 38.4 | |
F&D costs ($/boe)(2) | 7.26 | 10.86 | 11.95 | |
F&D recycle ratio(3) | 2.2 | 2.1 | 1.7 | |
F&D three-year weighted costs ($/boe)(2) | 10.65 | 12.21 | 13.62 | |
F&D recycle ratio three-year weighted average(3) | 1.9 | 1.7 | 1.5 | |
Finding, Development and Acquisition Expenditures: | 2015 | 2014 | 2013 | |
Proved Producing: | ||||
Change in FDC ($ millions) | 4.7 | 1.1 | 10.2 | |
Reserves additions (MMboe) | 21.5 | 42.8 | 32.8 | |
FD&A costs ($/boe)(2) | 13.37 | 12.49 | 14.45 | |
FD&A recycle ratio(3) | 1.2 | 1.8 | 1.4 | |
FD&A three-year weighted costs ($/boe)(2) | 13.35 | 13.43 | 15.65 | |
FD&A recycle ratio three-year weighted average(3) | 1.5 | 1.5 | 1.3 | |
Total Proved: | ||||
Change in FDC ($ millions) | (186.0) | 45.0 | 40.1 | |
Reserves additions (MMboe) | 15.4 | 47.6 | 34.6 | |
FD&A costs ($/boe)(2) | 6.32 | 12.13 | 14.60 | |
FD&A recycle ratio(3) | 2.6 | 1.9 | 1.4 | |
FD&A three-year weighted costs ($/boe)(2) | 12.10 | 13.05 | 15.31 | |
FD&A recycle ratio three-year weighted average(3) | 1.6 | 1.6 | 1.4 | |
Total Proved plus Probable: | ||||
Change in FDC ($ millions) | (198.6) | 28.2 | 120.7 | |
Reserves additions (MMboe) | 8.6 | 56.4 | 53.1 | |
FD&A costs ($/boe)(2) | 9.84 | 9.95 | 11.03 | |
FD&A recycle ratio(3) | 1.6 | 2.3 | 1.9 | |
FD&A three-year weighted costs ($/boe)(2) | 10.42 | 10.71 | 12.07 | |
FD&A recycle ratio three-year weighted average(3) | 1.9 | 1.9 | 1.7 |
- Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, transportation and operating expenditures, calculated on a per boe equivalent basis.
- Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.
- Recycle ratio is defined as operating netback per barrel of oil equivalent divided by either F&D or FD&A costs on a per barrel of oil equivalent.
- The aggregate of the E&D costs incurred in the financial year and the changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
2016 Revised Guidance
We remain focused on maintaining our total payout ratio in the range of 85% – 95% and improving our financial flexibility. With the continuing decline in commodity prices and the corresponding impact to our forecasted funds from operations, the 2016 capital budget has been reduced to a range of $190 million to $210 million. Our revised guidance incorporates the disposition of high-cost, non-core assets in the fourth quarter of 2015 and revised ethane curtailments. The table below outlines the impact of the reduction in capital spending:
Revised | Previous | |
Payout ratio (%) | 85 – 95 | 85 – 95 |
Capital expenditures ($ millions) | 190 – 210 | 210 – 240 |
Production (boe/d) | 73,000 – 76,000 | 76,000 – 79,000 |
Funds from operations ($ millions) | 245 – 260 | 290 – 305 |
Dividends ($ millions) | 25 | 25 |
Wells (net) | 45 – 55 | 50 – 60 |
WTI oil (US$/bbl) | 35.47 | 49.68 |
AECO natural gas (CDN$/gj) | 2.30 | 2.59 |
Exchange rate ($CDN/$US) | 0.71 | 0.76 |
We are encouraged by our operating and capital cost trends and remain focused on further enhancing these efficiencies as we assess the impact of changes in commodity prices and foreign exchange rates on our business. Our 2016 capital budget will remain flexible to accommodate continued uncertainty in commodity pricing.
General
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.
This news release contains certain financial information that has been derived from our unaudited consolidated financial statements for the year ended 2015.