Bonavista Energy Corporation Reports Finding and Development Costs of $7.26 per boe and Fourth Quarter Operating Costs Below $6.00 per boe, Both the Lowest in Over a Decade
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.
----------------------------------------------------------------------------
Oil
Equiv-
alent
Working Natural Total
Interest Natural Crude Gas Re- NPV of Future Net Revenue
Reserves(1): Gas(2) Oil(3) Liquids serves 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
----------------------------------------------------------------------------
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, 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$44.00/bbl respectively. This represents a 27% reduction in forecast natural gas pricing and a 41% reduction in forecast 2016 WTI oil pricing when compared to GLJ's forecast pricing for 2016 at January 1, 2015.
----------------------------------------------------------------------------
Edmonton Light AECO Natural
Price Forecast Crude Oil WTI Oil Gas Exchange Rate
----------------------------------------------------------------------------
(CDN$/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 Proved
Plus Plus
Proved Probable Probable Proved Probable 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 Proved
Plus Plus
Proved Probable Probable Proved Probable 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 Plus
Proved Probable 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
----------------------------------------------------------------------------
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 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
----------------------------------------------------------------------------
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 180.4 MMboe reserves assigned to $1,269 million of FDC. At a cost of $7.03 per boe, these future reserves generate $778 million of Net Present Value discounted at 10%.
Current year FDC as a ratio of trailing average three year E&D expenditures are 2.8:1 times, representing prudent and sustainable development forecasts.
The following table sets forth the schedule of FDC required to develop these future reserves (using forecast prices and costs).
----------------------------------------------------------------------------
Total Proved plus
Future Development Costs Total Proved Probable
----------------------------------------------------------------------------
($ 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 ($/boe)(1):
Current year 16.20 22.60 20.54
Three-year weighted average 19.74 20.37 20.92
----------------------------------------------------------------------------
1. Amounts may not add due to rounding.
----------------------------------------------------------------------------
Finding and Development Costs: 2015 2014 2013
----------------------------------------------------------------------------
Proved Producing:
Change in FDC ($ 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
----------------------------------------------------------------------------
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 equivalent 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 barrel of oil
equivalent divided by either F&D or FD&A costs on a per barrel of oil
equivalent.
4. 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.
Oil and Gas Advisories
The reserves estimates contained in this press release represent our gross reserves as at December 31, 2015 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 estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs, and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses.. 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.
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.
This press release contains metrics commonly used in the oil and natural gas industry, such as "proved plus probable recycle ratio from our E&D program", "recycle ratio", "finding and development costs", "finding and development recycle ratio", "finding development and acquisition costs", "operating netbacks", "reserve life index" and "PV10 value of reserves net of estimated debt". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
Finding and development costs are $7.26 per boe and finding development and acquisition costs are $9.84 per boe. Both finding and development costs and finding development and acquisition costs take into account reserves revisions during the year on a per boe basis. The aggregate of the E&D costs incurred in the financial year and 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. Finding and development costs both including and excluding acquisitions and dispositions have been presented in this press release 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. Recycle ratio is measured by dividing the operating netback by the F&D costs per boe for the year. Proved plus probable recycle ratio from our E&D program is calculated by dividing the operating netback by the proved plus probable F&D costs for the year. 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. Reserve life index is calculated based on the amount for the relevant reserves category divided by the production forecast for the applicable year prepared by GLJ.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Bonavista's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.
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 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, industry conditions, commodity prices and exchange rates, our dividend policy and our financial, operating and production plans and results including our 2016 capital program and allocation thereof, future production, decline rates, funds from operations and future development and other costs.
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.
This press release also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about our prospective results of operations and funds from operations, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. 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 FOFI and forward-looking statements. Bonavista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and FOFI, or if any of them do so, what benefits Bonavista will derive therefrom. Bonavista has included the forward-looking statements and FOFI in this press release in order to provide readers with a more complete perspective on Bonavista's future operations and such information may not be appropriate for other purposes. Bonavista 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.
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 instrument commodity contracts less royalties, transportation and operating expenditures calculated on a per boe basis. Common share values in our PV10 value of our reserves, net of estimated debt are calculated by including our outstanding common shares and exchangeable shares which are converted into common shares on certain terms and conditions.
FOR FURTHER INFORMATION PLEASE CONTACT:
Jason E. Skehar
President & CEO
Bruce W. Jensen
Chief Operating Officer
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
Source: Bonavista Energy Corporation
DISCLOSURE: The views and opinions expressed in this article are those of the authors, and do not represent the views of equities.com. Readers should not consider statements made by the author as formal recommendations and should consult their financial advisor before making any investment decisions. To read our full disclosure, please go to: http://www.equities.com/disclaimer
