(TSX:BNP) – CALGARY, Jan. 31, 2018 /CNW/ – Bonavista Energy Corporation (“Bonavista”) is pleased to report that our 2017 exploration and development (“E&D”) program has resulted in a finding and development (“F&D”) cost of $7.60 per barrel of oil equivalent (“boe”) on a proved plus probable basis. When combined with our acquisition and divestiture program (“A&D”), finding, development and acquisition (“FD&A”) costs were $7.56 per boe on a proved plus probable basis, in each case including changes in future development costs (“FDC”).
2017 Reserves Highlights:
The success we have experienced in the execution of our 2017 capital program continues to reinforce the quality and consistency of the opportunities that exist in our core areas as demonstrated by the highlights listed below:
- Replaced 189% of 2017 production with the addition of 49.8 MMboe of proved plus probable reserves;
- Proved plus probable reserves growth of six percent to 437.7 MMboe;
- Achieved a proved plus probable FD&A recycle ratio of 1.8:1, despite negative revisions of 2.4 MMboe due to low natural gas prices;
- Oil and natural gas liquids reserves comprised 29% of proved plus probable reserves;
- Invested $96 million in 2017 to increase proved developed producing and proved plus probable reserves by 59% and 40% respectively at our Ansell Wilrich play in our Deep Basin core area;
- Invested $51 million in 2017 to increase proved developed producing and proved plus probable reserves by 28% and 20% respectively at our Morningside Falher play in our West Central core area; and
- Using the independent reserves evaluation effective December 31, 2017, the PV10 before taxes of our proved plus probable reserves of $2,451 million, net of long-term debt (net of adjusted working capital) of approximately $840 million equates to $6.28 per common share (based on 256 million equivalent basic common shares outstanding). With the addition of an internally estimated total land value of $138 million, our net asset value would be approximately $6.82 per common share.
Operational and Financial Update:
During the fourth quarter of 2017, we produced 74,799 boe per day representing growth from the previous quarter of five percent. For the year ended December 31, 2017, we invested $282 million into our two core areas drilling 61 (56.7 net) wells resulting in average production of 72,156 boe per day. Currently we are producing approximately 74,000 boe per day. Specific operational highlights include the following:
- Annual and fourth quarter production growth of five percent and eight percent respectively;
- Reduced annual 2017 cash costs by five percent to $8.92 per boe when compared to the same period in 2016; and
- Reduced our cost to add production through our E&D program by eight percent to $12,500 per boe per day when compared to 2016.
2017 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 31, 2018.
Independent reserve evaluators, GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated 100% of our total net present value reserves in their report dated January 31, 2018 and effective December 31, 2017 (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 (“NPV”) of future net revenue for these reserves (before taxes) using forecast prices and costs as set forth in the GLJ Report.
Natural Gas(2) |
Crude Oil(3) |
Natural Gas |
Oil |
NPV of Future Net Revenue |
||||
Gross Reserves(1): |
5% |
10% |
15% |
|||||
(MMcf) |
(Mbbls) |
(Mbbls) |
(Mboe) |
($000’s) |
($000’s) |
($000’s) |
||
Proved: |
||||||||
Proved Producing |
642,376 |
4,489 |
43,267 |
154,819 |
1,409,379 |
1,156,575 |
980,204 |
|
Proved Non-Producing |
33,151 |
325 |
1,808 |
7,658 |
51,707 |
42,041 |
34,900 |
|
Proved Undeveloped |
479,484 |
1,548 |
31,069 |
112,531 |
719,599 |
448,841 |
284,435 |
|
Total Proved |
1,155,012 |
6,362 |
76,145 |
275,008 |
2,180,686 |
1,647,457 |
1,299,538 |
|
Probable |
722,009 |
2,905 |
39,495 |
162,735 |
1,339,358 |
804,384 |
530,395 |
|
Total Proved plus |
1,877,021 |
9,266 |
115,640 |
437,743 |
3,520,044 |
2,451,840 |
1,829,933 |
(1) |
Amounts may not add due to rounding. |
(2) |
Includes conventional natural gas, shale natural gas and coal bed methane. |
(3) |
Includes light, medium, heavy and tight oil. |
The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2018 as outlined below. The GLJ January 1, 2018 forecast pricing for natural gas at AECO and West Texas Intermediate (“WTI”) oil for 2018 are CDN$2.20/MMBtu and US$59.00/bbl respectively. This represents a 29% reduction in forecast 2018 natural gas pricing and no change to the 2018 forecast WTI oil price when compared to GLJ’s forecast pricing one year ago.
Price Forecast |
Edmonton Light |
WTI |
AECO |
Exchange Rate |
(CDN$/bbl) |
(US$/bbl) |
(CDN$/MMBtu) |
(US$/CDN$) |
|
2018 |
70.25 |
59.00 |
2.20 |
0.790 |
2019 |
70.25 |
59.00 |
2.54 |
0.790 |
2020 |
70.31 |
60.00 |
2.88 |
0.800 |
2021 |
72.84 |
63.00 |
3.24 |
0.810 |
2022 |
75.61 |
66.00 |
3.47 |
0.820 |
2023 |
78.31 |
69.00 |
3.58 |
0.830 |
2024 |
81.93 |
72.00 |
3.66 |
0.830 |
2025 |
85.54 |
75.00 |
3.73 |
0.830 |
2026 |
88.35 |
77.33 |
3.80 |
0.830 |
2027 |
90.22 |
78.88 |
3.88 |
0.830 |
Thereafter |
2.0%/year |
2.0%/year |
2.0%/year |
0.830 |
Reserves Reconciliation:
RECONCILIATION OF GROSS RESERVES BY PRINCIPAL PRODUCT TYPE |
|||||||||||||
LIGHT AND MEDIUM OIL |
HEAVY OIL |
||||||||||||
Proved |
Probable |
Proved Plus |
Proved |
Probable |
Proved Plus |
||||||||
(Mbbls) |
(Mbbls) |
(Mbbls) |
(Mbbls) |
(Mbbls) |
(Mbbls) |
||||||||
December 31, 2016 |
7,511 |
3,111 |
10,622 |
417 |
130 |
547 |
|||||||
Extensions and Improved Recovery(2) |
355 |
317 |
673 |
— |
— |
— |
|||||||
Technical Revisions |
(842) |
(591) |
(1,433) |
7 |
2 |
8 |
|||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||
Acquisitions |
2 |
1 |
3 |
— |
— |
— |
|||||||
Dispositions |
(165) |
(57) |
(222) |
— |
— |
— |
|||||||
Economic Factors |
(45) |
(9) |
(53) |
(2) |
— |
(2) |
|||||||
Production |
(854) |
— |
(854) |
(22) |
— |
(22) |
|||||||
December 31, 2017 |
5,962 |
2,773 |
8,735 |
400 |
132 |
532 |
NATURAL GAS |
NATURAL GAS LIQUIDS |
||||||||||||
Proved |
Probable |
Proved Plus |
Proved |
Probable |
Proved Plus |
||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbls) |
(Mbbls) |
(Mbbls) |
||||||||
December 31, 2016 |
1,128,147 |
592,890 |
1,721,037 |
77,231 |
38,966 |
116,197 |
|||||||
Extensions and Improved |
157,950 |
141,426 |
299,376 |
5,213 |
2,397 |
7,611 |
|||||||
Technical Revisions |
(14,927) |
(18,031) |
(32,958) |
912 |
(1,873) |
(961) |
|||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||
Acquisitions |
9,000 |
19,890 |
28,890 |
257 |
517 |
774 |
|||||||
Dispositions |
(8,381) |
(8,452) |
(16,832) |
(340) |
(341) |
(681) |
|||||||
Economic Factors |
(5,458) |
(5,714) |
(11,172) |
(289) |
(172) |
(461) |
|||||||
Production |
(111,319) |
— |
(111,319) |
(6,841) |
— |
(6,841) |
|||||||
December 31, 2017 |
1,155,012 |
722,009 |
1,877,021 |
76,145 |
39,495 |
115,640 |
OIL EQUIVALENT |
|||||||
Proved |
Probable |
Proved Plus |
|||||
(Mboe) |
(Mboe) |
(Mboe) |
|||||
December 31, 2016 |
273,183 |
141,022 |
414,205 |
||||
Extensions and Improved |
31,894 |
26,286 |
58,181 |
||||
Technical Revisions |
(2,411) |
(5,468) |
(7,879) |
||||
Discoveries |
— |
— |
— |
||||
Acquisitions |
1,759 |
3,833 |
5,592 |
||||
Dispositions |
(1,902) |
(1,806) |
(3,708) |
||||
Economic Factors |
(1,245) |
(1,133) |
(2,378) |
||||
Production |
(26,270) |
— |
(26,270) |
||||
December 31, 2017 |
275,008 |
162,735 |
437,743 |
(1) |
Amounts may not add due to rounding. |
(2) |
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 is to create premium shareholder value through the efficient development of high quality oil and natural gas assets. The profitable growth of our reserves coupled with the sustainable production of these reserves will generate long-term returns for our shareholders.
In 2017, our proved plus probable RLI increased by six percent to 15.2 years demonstrating the sustainable balance that exists between our capital program, our reserves additions and our production levels.
The following table highlights our historical RLI.
Reserve Life Index (Years)(1) |
2017 |
2016 |
2015 |
2014 |
2013 |
Total Proved |
10.3 |
10.5 |
9.7 |
9.4 |
9.1 |
Total Proved plus Probable |
15.2 |
14.4 |
14.1 |
13.1 |
13.2 |
(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. Future development cost estimates reflect GLJ’s best estimate of the costs required to bring the proved and proved plus probable reserves on production. We have 219.7 MMboe proved plus probable undeveloped reserves assigned to $1,373.1 million of total undiscounted FDC. At a cost of $6.25 per boe, these future reserves generate $942 million of net present value discounted at 10%.
Total undiscounted FDC as a ratio of trailing average three year E&D expenditures of $252.3 million is 5.6:1 times at year-end 2017, representing prudent and sustainable development forecasts.
The following table sets forth the schedule of FDC required to develop these future reserves (using forecast prices and costs).
Future Development Costs(1)(2) |
Total Proved |
Total Proved plus Probable |
($ thousands) |
($ thousands) |
|
2018 |
126,229 |
176,563 |
2019 |
295,740 |
402,978 |
2020 |
227,282 |
287,325 |
2021 |
106,207 |
211,703 |
2022 |
120,880 |
214,624 |
Remaining |
23,015 |
121,947 |
Total (Undiscounted) |
899,352 |
1,415,138 |
Total (Discounted at 10%) |
720,616 |
1,099,287 |
(1) |
Amounts may not add due to rounding. |
(2) |
Future development costs include both developed and undeveloped reserves. |
Reserves Performance Ratios:
The following tables highlight Bonavista’s reserves, F&D costs and FD&A costs and the associated recycle ratios for the trailing three years.
Bonavista considers recycle ratio an important measure of long-term profitability. It is measured by dividing the operating netback by the F&D costs per boe for the year. Bonavista has delivered a three year weighted average F&D recycle ratio of 2.0:1 and FD&A recycle ratio of 3.0:1 for proved plus probable reserves including revisions and changes in FDC.
2017 |
2016 |
2015 |
||
Reserves (Mboe): |
||||
Proved producing |
154,819 |
155,907 |
162,072 |
|
Total proved |
275,008 |
273,183 |
262,224 |
|
Proved plus probable |
437,743 |
414,205 |
406,494 |
|
Capital Expenditures ($ millions): |
||||
E&D |
289.0 |
153.9 |
313.9 |
|
Dispositions, net of acquisitions |
(7.8) |
(167.9) |
(30.6) |
|
Total capital expenditures |
281.2 |
(14.0) |
283.4 |
|
Operating Netback ($/boe)(1): |
||||
Current year |
13.85 |
13.44 |
16.16 |
|
Three-year weighted average |
14.55 |
17.54 |
19.72 |
(1) |
Amounts may not add due to rounding. |
Finding and Development Costs: |
2017 |
2016 |
2015 |
|
Proved Producing: |
||||
Change in FDC ($ millions) |
(11.818) |
(0.173) |
(0.339) |
|
Reserves additions (MMboe) |
25.902 |
15.831 |
26.252 |
|
F&D costs ($/boe)(2) |
10.70 |
9.71 |
11.94 |
|
F&D recycle ratio(3) |
1.3 |
1.4 |
1.4 |
|
F&D three-year weighted costs ($/boe)(2) |
10.95 |
12.04 |
13.57 |
|
F&D recycle ratio three-year weighted average(3) |
1.3 |
1.5 |
1.5 |
|
Total Proved: |
||||
Change in FDC ($ millions) |
(41.615) |
86.377 |
(188.683) |
|
Reserves additions (MMboe) |
28.237 |
26.972 |
20.346 |
|
F&D costs ($/boe)(2) |
8.76 |
8.91 |
6.15 |
|
F&D recycle ratio(3) |
1.6 |
1.5 |
2.6 |
|
F&D three-year weighted costs ($/boe)(2) |
8.11 |
10.40 |
12.21 |
|
F&D recycle ratio three-year weighted average(3) |
1.8 |
1.7 |
1.6 |
|
Total Proved plus Probable: |
||||
Change in FDC ($ millions) |
75.423 |
60.902 |
(183.483) |
|
Reserves additions (MMboe) |
47.923 |
30.824 |
17.975 |
|
F&D costs ($/boe)(2) |
7.60 |
6.97 |
7.26 |
|
F&D recycle ratio(3) |
1.8 |
1.9 |
2.2 |
|
F&D three-year weighted costs ($/boe)(2) |
7.34 |
9.11 |
10.65 |
|
F&D recycle ratio three-year weighted average(3) |
2.0 |
1.9 |
1.9 |
|
Finding, Development and Acquisition Expenditures: |
2017 |
2016 |
2015 |
|
Proved Producing: |
||||
Change in FDC ($ millions) |
(13.638) |
(2.269) |
4.667 |
|
Reserves additions (MMboe) |
25.182 |
18.879 |
21.539 |
|
FD&A costs ($/boe)(2) |
10.62 |
(0.86) |
13.37 |
|
FD&A recycle ratio(3) |
1.3 |
(15.6) |
1.2 |
|
FD&A three-year weighted costs ($/boe)(2) |
8.22 |
9.69 |
13.35 |
|
FD&A recycle ratio three-year weighted average(3) |
1.8 |
1.8 |
1.5 |
|
Total Proved: |
||||
Change in FDC ($ millions) |
(38.762) |
111.576 |
(186.034) |
|
Reserves additions (MMboe) |
28.095 |
36.004 |
15.388 |
|
FD&A costs ($/boe)(2) |
8.63 |
2.71 |
6.32 |
|
FD&A recycle ratio(3) |
1.6 |
5.0 |
2.6 |
|
FD&A three-year weighted costs ($/boe)(2) |
5.50 |
7.81 |
12.10 |
|
FD&A recycle ratio three-year weighted average(3) |
2.6 |
2.2 |
1.6 |
|
Total Proved plus Probable: |
||||
Change in FDC ($ millions) |
95.119 |
(3.821) |
(198.572) |
|
Reserves additions (MMboe) |
49.808 |
32.756 |
8.618 |
|
FD&A costs ($/boe)(2) |
7.56 |
(0.55) |
9.84 |
|
FD&A recycle ratio(3) |
1.8 |
(24.4) |
1.6 |
|
FD&A three-year weighted costs ($/boe)(2) |
4.86 |
6.42 |
10.42 |
|
FD&A recycle ratio three-year weighted average(3) |
3.0 |
2.7 |
1.9 |
(1) |
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 basis. |
(2) |
Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. |
(3) |
Recycle ratio is defined as operating netback per boe divided by either F&D or FD&A costs per boe. |
Hedging & Diversification:
Bonavista has prudently reduced its AECO exposure by diversifying to non-AECO markets and strengthening its hedging position. Currently, only 23% of our forecasted natural gas volumes and nine percent of our 2018 forecasted petroleum and natural gas revenues are exposed to the AECO spot market in 2018. Currently, Bonavista has hedged approximately 50% of our forecasted 2018 natural gas production at an AECO price of $3.07 per mcf.
General
Bonavista is focused on creating premium shareholder value through the efficient development of high quality oil and natural gas assets.