Bonterra Energy Corp. Announces 2017 Year End Corporate Reserves Information

CALGARY, Alberta, Feb. 07, 2018 (GLOBE NEWSWIRE) — Bonterra Energy Corp. (www.bonterraenergy.com) (TSX:BNE) (“Bonterra” or “the Company”) is pleased to provide the summary results of its independent reserve report (the “Sproule Report”) prepared by Sproule Associates Limited (“Sproule”) with an effective date of December 31, 2017. 

Corporate Reserves Information

The following summarizes certain information contained in the Sproule Report. The Sproule Report was prepared 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 reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form which will be filed on SEDAR on or by March 13, 2018.

Reserve Report Highlights

  • Increased proved plus probable (“P+P”) reserves by five percent to 99.8 million BOE (70 percent oil and liquids) and total proved reserves by six percent to 78.6 million BOE (70 percent oil and liquids).
  • Increased total proved reserves by 4.3 million BOE which replaced production by 193 percent.
  • Total proved reserves represent 79 percent of total P+P reserves.
  • P+P reserves per fully diluted share increased to 3.00 BOE per share compared to 2.85 BOE per share from the prior year, an increase of five percent.
  • Reserve life index of approximately 21 years on a P+P basis, 17 years on a total proved basis, and nine years on a proved developed producing (“PDP”) basis (based on 2017 average production rate of 12,827 BOE per day).

Summary of Gross Oil and Gas Reserves as of December 31, 2017

  Light and
Medium Oil
Solution
Gas
Natural
Gas
Natural
Gas
Liquids
Oil
equivalent(4)
Future
Development
Capital
  (MBbl)  (MMcf) (MMcf)  (MBbl)  (MBoe) (000s)
Proved            
  Developed Producing 25,760 66,598 7,152 3,147 41,199
  Developed Non-producing 617 1,468 244 69 971 1,136
  Undeveloped 22,369 52,022 13,893 3,068 36,423 605,140
Total proved 48,746 120,088 21,288 6,284 78,592 606,275
Total Probable 13,148 31,894 6,604 1,684 21,248 9,651
Total P+P(1) (2) (3) 61,894 151,982 27,893 7,968 99,840 615,926

Notes:

(1)       Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including any royalty interests of the Company.
(2)       Totals may not add due to rounding.
(3)       Based on Sproule’s December 31, 2017 escalated price deck.
(4)       Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

Reconciliation of Company Gross Reserves by Principal Product Type as of
December 31, 2017 (1)(2)

  Light &
Medium Oil
Conventional
Natural Gas
Natural Gas
Liquids
Oil Equivalent
  Total
Proved
Proved +
Probable
Total
Proved
Proved +
Probable
Total
Proved
Proved +
Probable
Total
Proved
Proved +
Probable
  (MBbl) (MBbl) (MMcf) (MMcf) (MBbl) (MBbl) (MBoe) (MBoe)
Opening Balance, December 31, 2016 47,581   60,320   129,108   167,269   5,157   6,707   74,257   94,905  
Extensions & Improved Recovery(2) 4,086   5,166   7,130   9,009   427   540   5,701   7,207  
Technical Revisions (882)   (1,785)   11,905   9,803   960   964   2,062   814  
Discoveries                
Acquisitions 697   868   1,730   2,170   57   71   1,043   1,301  
Dispositions(3)                
Economic Factors 150   211   295   415   13   16   212   296  
Production (2,886)   (2,886)   (8,792)   (8,792)   (331)   (331)   (4,682)   (4,682)  
Closing Balance, December 31, 2017(4) 48,746   61,894   141,376   179,874   6,284   7,968   78,592   99,840  

Notes:

(1)       Gross Reserves means the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s royalty interests.
(2)       Increases to Extensions & Improved Recovery include infill drilling and are the result of step-out locations drilled by Bonterra and other operators on and near Company-owned lands.
(3)       Includes volumes associated with Farm outs.
(4)       Totals may not add due to rounding.
       

Summary of Net Present Values of Future Net Revenue as of December 31, 2017

($M) Net Present Value Before Income Taxes Discounted at (% per Year)
Reserves Category: 0%   5%   10%   15%  
Proved        
  Producing 1,379,164   935,526   706,099   569,452  
  Non-producing 20,761   18,112   14,854   12,272  
  Undeveloped 930,643   514,685   306,474   190,432  
Total proved 2,330,568   1,468,324   1,027,427   772,156  
Probable 946,292   492,725   317,563   231,218  
Total proved plus probable(1)(2)(3) 3,276,860   1,961,049   1,344,990   1,003,374  

Notes:

(1)       Evaluated by Sproule as at December 31, 2017. Net present value of future net revenue does not represent fair value of the reserves.
(2)       Net present values equals net present value before income taxes based on Sproule’s forecast prices and costs as of December 31, 2017. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.
(3)       Includes abandonment and reclamation costs as defined in NI 51-101.

Finding, Development & Acquisition (“FD&A”) and Finding & Development (“F&D”) Costs

Over the past three years, Bonterra has incurred the following FD&A(3) and F&D(3) costs both excluding and including Future Development Capital (“FDC”):

  Total Proved Reserves Net Additions   P+P Reserves Net Additions
  2017   2016   2015 3 Yr Avg(4)     2017   2016   2015 3 Yr Avg(4)
FD&A Costs per BOE (1)(2)(3)
Including FDC .66 .87 .52 .60   .74 .93 .60 .77
Excluding FDC .06 .91 .50 .62   .57 .58 .29 .51
 
F&D Costs per BOE (1)(2)(3)
Including FDC .02 .89 .76 .04   .22 .91 .12 .96
Excluding FDC .55 .81 .26 .73   .25 .44 .32 .64

Notes:

(1)       Barrels of oil equivalent may be misleading, particularly if used in isolation.  A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2)       The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development capital generally will not reflect total finding and development costs related to reserve additions for that year.
(3)       FD&A and F&D costs are net of proceeds of disposition and the FD&A costs per BOE are based on reserves acquired net of reserves disposed of.
(4)       Three year average is calculated using three year total capital costs and reserve additions on both a total proved and P+P reserves on a weighted average basis.

FD&A and F&D Highlights

  • The increase in FDC was primarily a result of increased investment infrastructure capital of million directed to initiatives designed to reduce future operating costs by enhancing water and gas handling capabilities, as well as increased drilling and completion costs due to higher industry demand.
  • FD&A for 2017 was positively impacted by reserve additions from two acquisitions totaling .5 million.
  • On December 20, 2017, the Company closed the sale of a two percent non-convertible gross overriding royalty (“GORR”) on its Pembina Cardium pool for consideration of .7 million (comprised of million cash and incremental Cardium assets). The GORR transaction has been reflected in the Company’s net reserves.

Operational Highlights

Bonterra realized ongoing success in its core Pembina Cardium area through 2017 and maintained stable production volumes as a result of its low corporate decline rate and successful drilling program.  The Company was able to grow reserves and lower net debt with no shareholder dilution due to the GORR transaction and its successful 2017 development program. Bonterra’s realized oil prices are based on Edmonton Par pricing; accordingly, the Company has not been exposed to the significantly lower differentials which have negatively impacted the Western Canadian Select benchmark price.

Bonterra’s 2017 full year and fourth quarter production summary follows:

  • Average daily production for the full year was 12,827 BOE per day (70 percent oil and liquids), which was in line with the Company’s 2017 guidance of 12,900 BOE per day, representing a two percent increase over the 12,650 BOE per day average in 2016;
  • Average daily production in the fourth quarter was 12,807 BOE per day, an increase of six percent compared to the fourth quarter of 2016; and
  • During the fourth quarter of 2017, the Company experienced pipeline restrictions which resulted in 80 barrels of oil per day being produced into inventory rather than being sold. In addition, due to extremely cold weather, numerous pipelines and wellhead freeze offs resulted in unplanned downtime of 218 BOE per day. Without these production curtailments, the Company would have averaged 13,105 BOE per day in Q4 2017. The inventory build will be included in Q1 2018 production and unplanned downtime is expected to be resolved early in the first quarter of 2018.

2018 Guidance

Bonterra is maintaining the 2018 capital budget at million which will be directed largely to new wells and facility upgrades focused primarily in the Pembina Cardium area. Bonterra anticipates the 2018 average annual production to range between 13,200 and 13,500 BOE per day.

Certain financial and operating information, such as production information, and F&D costs included in this press release are based on estimated unaudited financial results for the quarter and year ended December 31, 2017 and are subject to the same limitations as discussed under Forward Looking Statements set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2017 and changes could be material.

For further information please contact:
George F. Fink, Chairman and CEO
Robb D. Thompson, CFO       
Adrian Neumann, COO
Telephone: (403) 262-5307
Fax: (403) 265-7488
Email: info@bonterraenergy.com

Caution Regarding Engineering Terms

Disclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6 MCF to 1 barrel has been used in all cases in this disclosure. This BOE conversion ratio is based on an energy equivalency conversion method primarily available at the burner tip and does not represent a value equivalency at the wellhead.

Summary of Selected Price Forecasts Sproule (December 31, 2017)

Year WTI Cushing
Oklahoma 40o API
($US/bbl)
Canadian Light
Sweet Crude 40o
API $/bbl
AECO-C Spot
$/Mmbtu
Exchange Rate
$US/$CDN
2018   55.00   65.44 2.85 0.79
2019   65.00   74.51 3.11 0.82
2020   70.00   78.24 3.65 0.85
2021    73.00(1)    82.45(1) 3.80 0.85
  1. Escalation Rate 2% thereafter

Forward Looking Information

Certain statements contained in this release include statements which contain words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “believe” and similar expressions, relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this release includes, but is not limited to: expected cash provided by continuing operations; cash dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.

All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control.

Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do, what benefits will be derived there from. Except as required by law, Bonterra disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

The forward-looking information contained herein is expressly qualified by this cautionary statement.

The TSX does not accept responsibility for the accuracy of this release.