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Bonterra Energy Corp. Announces Fully-Funded 2020 Budget, 2019 Reserves Information and 2019 Operational Highlights


CALGARYFeb. 12, 2020 /CNW/ – Bonterra Energy Corp. (www.bonterraenergy.com) (TSX: BNE) (“Bonterra” or the “Company”) today announces that the Company’s Board of Directors has approved an initial 2020 capital budget set at approximately $70 million, while also sharing key operational highlights from 2019, and providing the summary results of its independent reserve report (the “Sproule Report”) prepared by Sproule Associates Limited (“Sproule”) with an effective date of December 31, 2019.

Fully-Funded 2020 Budget and Guidance

Bonterra’s 2020 capital budget incorporates a measured approach to address the continued volatility in crude oil prices. The crude market for WTI pricing has dropped approximately 20 percent in the last month, with some signs it could accelerate further as the Coronavirus continues to spread. As active measures to contain the virus are implemented, it is anticipated that prices may respond accordingly with signs of recovery. There have been encouraging developments regarding the potential for additional pipeline capacity in Canada, including Keystone XL, Trans Mountain and Enbridge Line 3 Replacement. The positive impact of such incremental transportation could contribute to the country’s ability to receive a competitive price for crude oil over the longer term.

2020 Capital Budget

Bonterra’s 2020 capital budget is designed to afford the Company greater flexibility around the execution of the capital program while prioritizing balance sheet protection, net debt reduction and the monthly amount of dividend payments. The planned budget structure will enable the Company to increase or decrease the level of spending on a monthly basis depending on the realized Canadian (“Edmonton Par”) crude oil and natural gas pricing.

Bonterra intends to direct its 2020 budget to new wells primarily targeting the Cardium formation across the Company’s Carnwood, Willesden Green and Rose Creek areas along with funds directed to facilities and pipelines, non-operated drilling and completion activities and a continued commitment to abandonments.

2020 Capital Budget Objectives:

  • Invest in higher rate-of-return, lower-risk light oil opportunities within the Company’s extensive drilling inventory;
  • Maintain an all-in (capital plus dividends and abandonments) payout ratio of less than 100 percent of funds flow;
  • Direct the pace of the capital program to maintain spending flexibility throughout the year and effectively respond to a shifting price environment; and
  • Maintain financial flexibility to achieve longer-term growth in production, reserves and funds flow per share while generating positive returns for shareholders.

Annual average production volumes are expected to range between 12,300 and 12,600 BOE per day. In the context of ongoing volatility in commodity prices, Bonterra will review on a monthly basis and may elect to adjust the amount and timing of capital spending to ensure sustainability and a payout ratio of less than 100 percent of funds flow.

Through continuous deployment of a single drilling rig, Bonterra’s 2020 capital program forecasts the allocation of approximately $65 million to drill, complete and tie-in (“DCT”) 34.9 gross (29.9 net) wells, and approximately $5 million for infrastructure costs, for total capital expenditures forecast at $70 million. With this level of capital, Bonterra expects to maintain or achieve modest growth in annual average production volumes, which are forecast to range between 12,300 barrels of oil equivalent (“BOE”) per day and 12,600 BOE per day, weighted 67 percent to light crude oil and natural gas liquids.  The 2020 budget also features an increased target well abandonment program targeting 55 to 60 wells for between $1.5 and $2.0 million, representing more than twice the total number of wells budgeted to be drilled for the year, further supporting the Company’s ongoing focus on responsible environmental, social and governance (“ESG”) initiatives.

Based on the pricing and production assumptions for 2020 outlined below, Bonterra anticipates generating $86 million in corporate funds flow and incurring approximately $4 million in dividend payments for the year, resulting in Free Funds Flow or funds flow net of development capital expenditures, abandonment costs and dividends (“Free Funds Flow”) of approximately 10 million1. Bonterra expects to direct Free Funds Flow to further reduce outstanding bank debt. Consistent with its strategy to deliver per share returns to shareholders, should commodity prices improve, the balance sheet strengthen and debt to funds flow ratios further decline, Bonterra may consider increasing the monthly dividend, expanding its growth capital program, or a combination of both.

Budget Summary

2020 Budget

Canadian Realized Oil Pricing per Bbl 1

$60

Average Daily Production (BOE per day)

12,300 – 12,600

Oil and NGL weighting

67%

Funds Flow (millions) 2

$86

Capital Expenditures (millions)

$70

Dividends (millions)

$4

Free Funds Flow (millions) 1

$10

Notes:

(1)

Canadian realized oil price is based on WTI US $53.44 per barrel; Edmonton par differential of $(6.00) per barrel; CAD/USD exchange rate of $0.75; and a quality differential of CAD $(3.25) per barrel.

(2)

Funds Flow is estimated using the Canadian realized oil price above, a natural gas price of $2.20 per mcf; and an NGL price of CAD $30.00 per barrel.

Bonterra will continue to regularly monitor changes to commodity prices and funds flow with the primary objective of directing funds flow to a prudent capital program, sustainable dividend and meaningful debt reduction.  Bonterra’s 2020 capital budget is designed to maximize Free Funds Flow in order to strengthen the balance sheet while returning capital to shareholders in the form of dividends1. The Company may elect to adjust the amount and timing of capital spending to ensure optimal returns while seeking to further reduce its debt levels. A commitment to sustainability and debt reduction will remain intact through 2020.

2019 Operational Highlights

During 2019, Bonterra invested approximately $54 million2 in capital, directing approximately $45 million2 to drilling 30 gross (23.7 net) wells, with 27 gross (20.7 net) wells tied-in and placed on production.  The remaining three gross (3.0 net) wells commenced production in early Q1 2020. In addition, the Company spent approximately $9 million2 towards infrastructure costs, while maintaining average daily production of 12,305 BOE per day2,3, despite approximately 350 BOE per day of production being shut-in through the year related to facility maintenance and low natural gas prices. The Company returned approximately $4 million to shareholders in the form of dividends, achieving a capital plus dividend payout ratio1 of 60 percent in 20192.

During 2019, Bonterra generated Free Funds Flow1 of $36.1 million2 which was directed to net debt reduction, having closed the year with net debt of $292.8 million2, an 11 percent decrease from the $328.9 million of net debt at December 31, 2018. Cash flow after capital and dividend outlays continues to be prioritized for the enhancement of debt ratios.

(1)

“Free Funds Flow” and “Capital and Dividend Payout Ratio” do not have standardized meanings.  See “Cautionary Statements” below.

(2)

All 2019 financial amounts are unaudited. See advisories.

(3)

Comprised of 67% light oil and natural gas liquids and 33% conventional natural gas.

2019 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 reserves 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 10, 2020.

Reserve Report Highlights

  • Total proved reserves increased by 0.9 million BOE to 81.5 million BOE (67 percent oil and liquids), while total proved plus probable (“P+P”) reserves were maintained at 101.1 million BOE (67 percent oil and liquids).
  • Total proved reserves per fully diluted share totaled 2.44 BOE, a 1.0 percent increase over 2.42 BOE in 2018, while P+P reserves per fully diluted share totaled 3.03 BOE compared to 3.04 BOE per share in 2018.
  • Growth in total proved reserves before production of 5.4 million BOE resulted in production replacement of 120 percent.
  • Total proved reserves represent 81 percent of total P+P reserves, compared to 80 percent in 2018, exemplifying the low-risk nature of Bonterra’s asset base.
  • Net present value of future net revenue discounted at 10 percent (before tax) (“NPV10 BT”) for P+P reserves totaled $1.2 billion, while total proved reserves totaled $961.9 million and proved developed producing (“PDP”) reserves totaled $586.4 million. The Company’s PDP NPV10 BT was 38 percent higher than Bonterra’s year end 2019 enterprise value (market capitalization plus net debt of $292.8 million).
  • Generated finding and development (“F&D”)4,5 recycle ratios4,5 of 1.85 times on a total proved basis and 1.45 times on a P+P basis, calculated based on the Company’s estimated annual average field netback4,5 of $26.45 per BOE (unaudited) divided by the F&D costs4,5 (including future development capital (“FDC”).
  • Increased P+P, TP, and PDP reserve life indices (“RLI”)5 to approximately 23 years on a P+P basis, 19 years on a total proved basis, and nine years on a PDP basis (based on 2019 average production of 12,305 BOE per day), supporting Bonterra’s ability to continue drilling and developing its attractive, Cardium oil focused asset base.

(4)

All 2019 financial amounts are unaudited. See advisories.

(5)

“Finding and Development costs” or “F&D costs”, “recycle ratio”, “operating netback” and “reserve life index” do not have standardized meanings. See the table “Capital Program Efficiency” and “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” contained in this news release.

Summary of Gross Oil and Gas Reserves as of December 31, 2019

 

Light and
Medium Oil

Solution Gas

Natural Gas

Natural Gas
Liquids

Oil
equivalent4

Future
Development
Capital

(MBbl)

 (MMcf)

(MMcf)

 (MBbl)

 (MBoe)

($000s)

Proved

Developed Producing

22,227

69,928

5,616

3,319

38,136

76

Developed Non-producing

591

1,177

42

55

849

1,374

Undeveloped

23,891

72,637

12,945

4,398

42,552

638,193

Total Proved

46,709

143,742

18,603

7,771

81,537

639,643

Total Probable

11,165

34,109

4,872

1,878

19,540

12,006

Total P+P 1,2,3

57,874

177,851

23,475

9,649

101,077

651,650

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, 2019 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, 2019 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, 2018

47,885

60,067

153,973

193,380

7,086

8,928

80,634

101,225

Extensions & Improved Recovery 2

2,551

3,154

9,348

11,543

664

817

4,773

5,894

Technical Revisions

(375)

(2,034)

8,517

5,825

481

365

1,525

(698)

Discoveries

Acquisitions

Dispositions 3

Economic Factors

(685)

(645)

(714)

(643)

(100)

(101)

(904)

(853)

Production

(2,668)

(2,668)

(8,779)

(8,779)

(360)

(360)

(4,491)

(4,491)

Closing Balance,
December 31, 2019 
4

46,709

57,874

162,345

201,326

7,771

9,649

81,537

101,077

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, 2019

($M)

Net Present Value Before Income Taxes Discounted at (% per Year)

Reserves Category:

0%

5%

10%

15%

Proved

Producing

789,954

727,746

586,445

485,957

Non-producing

17,432

13,466

10,627

8,593

Undeveloped

981,038

578,193

364,808

241,291

Total proved

1,788,424

1,319,405

961,880

735,842

Probable

731,254

402,609

266,354

196,077

Total proved plus probable 1,2,3

2,519,678

1,722,014

1,228,235

931,919

Notes:

(1)

Evaluated by Sproule as at December 31, 2019. Net present value of future net revenue does not represent fair value of the reserves.

(2)

Net present values equal net present value before income taxes based on Sproule’s forecast prices and costs as of December 31, 2019. 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.

Commencing in 2019, Sproule began to include additional abandonment, decommissioning and reclamation obligations (“ADR”) in the Company’s reserves, resulting in a decrease of values compared to 2018. The Company previously reported certain Asset Restoration Obligations (“ARO”) separately from those contained in the Company’s December 31, 2018 evaluation in the Annual Information Form. This substantial change to the prior years’ practices, which were consistent with the reporting of many other companies in the industry, was based on new Canadian Oil and Gas Evaluation Handbook  (“COGE Handbook”) guidelines that recommend the inclusion of ADR costs associated with the Company’s assets in the reserve report. This change incorporates costs for active and inactive wells, including producing wells, suspended wells, service wells and also gathering systems, facilities, and surface land reclamation for all of Bonterra’s assets. Sproule’s evaluation of Bonterra’s NPV10 BT at December 31, 2019 (estimated before tax net present value of future net revenues associated with the Company’s reserves, discounted at 10%) for ADR related to Proved plus Probable, Proved and Proved Developed Producing reserves was $23.6 million$23.8 million, and $22.8 million, respectively, reflecting an increase of $17.6 million$15.9 million, and $16.0 million compared to the ADR measures at year-end 2018.

F&D Costs, Finding, Development & Acquisition (“FD&A”) Costs and Recycle Ratio 7
Over the past three years, Bonterra has incurred the following FD&A3 and F&D3 costs both excluding and including FDC:

Total Proved Reserves Net Additions

P+P Reserves Net Additions

2019

2018

2017

3 Yr Avg 5

2019

2018

2017

3 Yr Avg 5

FD&A Costs per BOE 1,2,3,4,5

Including FDC

$14.32

$12.82

$15.66

$14.41

$18.24

$14.33

$13.74

$14.89

Excluding FDC

$9.94

$11.40

$9.06

$10.04

$12.35

$12.70

$8.57

$10.65

F&D Costs per BOE 1,2,3,4,5

Including FDC

$14.32

$12.99

$16.93

$14.98

$18.24

$15.56

$15.13

$16.02

Excluding FDC

$9.94

$12.54

$9.46

$10.55

$12.35

$14.95

$9.16

$11.59

Recycle Ratio 2,6

F&D (including FDC)

1.9

2.1

1.7

1.9

1.5

1.9

2.0

1.8

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)

All 2019 financial amounts are unaudited. See advisories.

(3)

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.

(4)

The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production.  In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

(5)

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.

(6)

Recycle ratio is defined as field netback per BOE divided by F&D costs on a per boe basis.  Field netback is a Non-IFRS Measure and calculated as revenue minus royalties, operating expenses and transportation expenses.  Bonterra’s operating netback in 2019, used in the above calculations, averaged $26.45 per BOE (unaudited). 

(7)

“FD&A Cost”, “F&D Cost”, and “Recycle Ratio” do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities.  See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this news release.

Bonterra Energy Corp. is a conventional oil and gas corporation with operations in AlbertaSaskatchewan and British Columbia, focused on its long-term model of generating sustainable growth plus a dividend. The Company’s shares are listed on The Toronto Stock Exchange under the symbol “BNE”.



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