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Bonterra Energy Corp. Announces Fourth Quarter and Year End 2020 Results and Reserves


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These translations are done via Google Translate

CALGARY, ABMarch 9, 2021 /CNW/ – Bonterra Energy Corp. (www.bonterraenergy.com) (TSX: BNE) (“Bonterra” or the “Company”) is pleased to announce its operating and financial results for the year ended December 31, 2020 and provide summary results of its independent reserve report (the “Sproule Report”) prepared by Sproule Associates Limited (“Sproule”) with an effective date of December 31, 2020.  The related financial statements and notes, as well as management’s discussion and analysis (“MD&A”) for the year ended December 31, 2020 and annual information form (“AIF”) as of December 31, 2020 are available on SEDAR at www.sedar.com and on Bonterra’s website at www.bonterraenergy.com.

HIGHLIGHTS

As at and for the year ended

December 31,
 2020

December 31,
 2019

December 31,
 2018

($000s except $ per share)

FINANCIAL

Revenue – realized oil and gas sales

121,642

202,749

223,388

Funds flow (1)

27,789

96,261

107,251

Per share – basic and diluted

0.83

2.88

3.22

Dividend payout ratio

4%

4%

34%

Cash flow from operations

32,073

81,132

115,963

Per share – basic and diluted

0.96

2.43

3.48

Payout ratio

3%

5%

32%

Cash dividends per share

0.03

0.12

1.11

Net earnings (loss)(2)

(306,889)

21,923

7,167

Per share – basic and diluted

(9.19)

0.66

0.22

Capital expenditures

43,728

53,627

78,737

Total assets

731,859

1,087,817

1,103,833

Net debt(3)

315,573

292,810

328,941

Shareholders’ equity

196,633

503,949

483,970

OPERATIONS

Light oil

-bbl per day

5,832

7,310

8,119

-average price ($ per bbl)

44.31

66.34

65.51

NGLs

-bbl per day

1,032

986

995

-average price ($ per bbl)

18.65

25.83

40.32

Conventional natural gas

-MCF per day

22,268

24,053

24,549

-average price ($ per MCF)

2.46

1.87

1.63

Total barrels of oil equivalent per day (BOE)(4)

10,575

12,305

13,206

(1)

Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning expenditures settled.

(2)

In the first quarter of 2020 the Company recorded a $331,678,000 impairment provision less a $54,107,000 deferred income tax recovery related to its Alberta CGU’s oil and gas assets due to the impact of COVID-19 on forward benchmark prices for crude oil.

(3)

Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-term bank debt and subordinated debt.

(4)

BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

FINANCIAL & OPERATING HIGHLIGHTS

  • Averaged 10,575 BOE per day of production in 2020 reflecting modest capital spending in the year coupled with approximately 875 BOE per day of shut-in production volumes related to facility maintenance and low commodity prices.
  • Invested $43.7 million into a conservative capital program for the year (approximately 43 percent of which was invested in Q4 2020) with $37.1 million directed to drilling 24 gross (23.8 net) operated wells and the completion, equip and tie-in of 23 gross (22.9 net) operated wells which were placed on production, three of which were drilled late in 2019, along with $6.6 million directed to related infrastructure and recompletions. Subsequent to year end 2020, the Company completed and tied in four gross (3.8 net) wells that had been drilled in 2020.
  • Continued to focus on incremental operating cost savings across the organization, with production costs per BOE declining three percent to $15.12 per BOE, and costs to drill, complete, equip and tie-in approximately 23 percent lower compared to 2019.
  • Generated Funds Flow1 of $27.8 million ($0.83 per share) in 2020, and for Q4 2020 generated $2.7 million ($0.08 per share) of Funds Flow1 as stronger realized pricing for all products helped to offset lower production volumes during the quarter.
  • Field netbacks1 averaged $14.22 per BOE in Q4 2020 and $14.39 per BOE in the twelve months ended December 31, 2020, reflecting significantly lower per unit revenue, offset by lower royalty expenses and production costs per BOE when compared to 2019.
  • Supported by Alberta’s Site Rehabilitation Program (“SRP”), successfully abandoned 143 net wells during 2020, supporting the Company’s ongoing focus on responsible environmental, social and governance (“ESG”) initiatives.
  • Year end 2020 net debt1 increased by $22.8 million compared to December 31, 2019 primarily due to the Company’s increased capital program in the fourth quarter through the utilization of $28 million of the $45 million available on the Business Development Bank of Canada (“BDC”) funding, targeting to return production to pre-COVID-19 levels and increasing Funds Flow.

2020 YEAR IN REVIEW

Throughout 2020, the world faced numerous, unprecedented global events that included the combination of an oil price war followed by severe demand destruction for crude oil related to the COVID-19 pandemic. Addressing these challenges, Bonterra responded swiftly and prudently to navigate the challenges of the macro environment, including taking steps to protect the health and safety of employees by implementing remote work protocols.  In the interests of maintaining sustainability, the Company curtailed capital expenditures to preserve Funds Flow and protect its balance sheet. Against the backdrop of an extremely challenging commodity price and operating environment, Bonterra was able to minimize spending while taking steps to mitigate production declines in 2020, reflecting the low-risk and resilient nature of the Company’s asset base.

The Company achieved many milestones throughout the year, including cost savings of approximately 23 percent for drilling, completion and equipping activities compared to 2019, securing funding through the BDC and SRP, along with a lending backstop from Export Development Canada (“EDC”).

________________________________

1 Non-IFRS Measure. “Funds Flow”, “field netbacks” and “net debt” do not have standardized measures prescribed by International Financial Reporting Standards (“IFRS”), and therefore may not be comparable with the calculations of similar measures for other companies. See “Cautionary Statements” within this press release and the Company’s MD&A for details including reasons for use.

Bonterra was one of the first Canadian energy producers to qualify, and be approved, for both the EDC and BDC government support programs in 2020, a condition of which is financial viability. The near-term liquidity afforded by the BDC second lien non-revolving four-year term facility for $45 million funded a significant portion of Bonterra’s 2020-2021 winter drilling program, which in turn is targeting long-term, sustainable net asset value per share growth for the Company as the economy recovers. Through a commitment of $38.4 million, EDC has joined Bonterra’s banking syndicate, demonstrating strong alignment with the Company’s current capital providers and management team. The Company’s banking syndicate also supports its strategic plan and extended the maturity date of Bonterra’s senior credit facility to December 31, 2021 while maintaining the current $300 million borrowing base. These developments contributed to the Company exiting the year in a strong position due to prudent production management, control of non-recurring corporate costs, enhanced operational efficiencies and a bolstered risk management position.

Effective April 1, 2020 the Company chose to suspend both its monthly dividend and capital program as crude oil prices reached record lows in May. Bonterra remains committed to conservative financial management, further efficiency improvements and capturing continued cost reduction opportunities across the organization. To further support stability amidst continued market volatility, and as part of Bonterra’s ongoing efforts to diversify commodity pricing and to protect future Funds Flow, the Company has executed physical delivery sales and risk management contracts for 2021, described in more detail below.

OUTLOOK – POSITIONING FOR LONG-TERM SUSTAINABILITY

Through 2021, Bonterra intends to maintain a fully-funded capital program between $65 and $75 million targeting high rate-of-return, low-risk light oil opportunities and carefully control the pace of development to retain flexibility to rapidly respond to changing commodity prices. The Company plans to run a single drilling rig through 2021 with approximately $58 million allocated to drill, complete and tie-in 43 gross (38.1 net) wells, with the balance directed to facilities, pipelines, recompletion and workover costs. Through the execution of this development plan, Bonterra aims to further improve drilling and completions efficiencies, with estimated 2021 per well drill, complete and tie-in costs forecast at approximately $1.4 to $1.6 million.

Based on this established budget and capital plan, Bonterra expects to grow production by more than 30 percent which will return average annual volumes to pre-COVID levels of approximately 12,800 to 13,200 BOE per day in 2021. This positions Bonterra to benefit from rising commodity prices and a lean cost structure, both of which can enhance Funds Flow. Based on forecast 2021 commodity prices, the Company’s capital budget and associated production volumes, Bonterra is modeling Funds Flow of approximately $80 to $88 million2, and Free Funds Flow of approximately $13.0 to $13.9 million2. Holding all other variable constant, should WTI increase to US $65.00 per barrel, approximately $30 million of Free Funds Flow2 could be generated.

As part of an ongoing focus on responsible ESG initiatives, Bonterra’s 2021 budget includes $3 million targeting well abandonment and reclamation initiatives to reduce the Company’s operated inactive well count in 2021 by approximately 191 net wells. By the end of 2021, Bonterra expects to have reduced its inactive well count by approximately 60 percent under current approvals through the SRP and other provincial programs. The anticipated impact of such programs is a reduction in Bonterra’s annual spending commitments from $3.3 million down to $2.0 million starting in 2023 under Alberta’s Area Based Closure program. The Company remains committed to being a positive and meaningful contributor to the economic success of the communities where it operates in central Alberta, by employing local services and to upholding stringent safety measures to ensure the health and well-being of its employees, contractors and partners.

_______________________________

2 “Funds Flow” and “Free Funds Flow” do not have standardized meanings. See “Cautionary Statements” below.

To further underpin sustainability and protect against volatility, through year end 2021 Bonterra has hedged a total of 638,750 barrels of light crude oil in 2021 (approximately 1,750 barrels of oil per day) at fixed WTI prices ranging from $36.00 USD to $50.50 USD per barrel, with a fixed differential from WTI to Edmonton Par prices in Canadian dollars for 532,750 barrels of oil (approximately 1,460 barrels of oil per day) at prices ranging from $6.34 to $8.10 per barrel. In addition, Bonterra also fixed 1,800 GJ per day of natural gas for the 2021 year at $2.24 per GJ.

YEAR END FILINGS

Bonterra has also filed its AIF today on SEDAR.  Selected financial and operational information is outlined above and should be read in conjunction with the Financial Statements, which were prepared in accordance with IFRS, and the related MD&A.  The AIF includes information pursuant to the requirements of National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators relating to reserves data and other oil and gas information.  The AIF, Financial Statements, and related MD&A can be accessed either on Bonterra’s website at www.bonterraenergy.com or under the Company’s profile on SEDAR at www.sedar.com.

2020 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 NI 51-101. Additional reserves information as required under NI 51-101 has been included in the Company’s Annual Information Form which can be found on SEDAR.

  • Total proved (“TP”) reserves decreased by 6.2 million BOE to 75.3 million BOE (67 percent oil and liquids), and total proved plus probable (“TPP”) reserves decreased by 7.2 million BOE to 93.9 million BOE (67 percent oil and liquids), due primarily to reductions in forecast pricing compared to 2019 and a curtailed drilling program in response to the pandemic.
  • TP reserves per fully diluted share were 2.25 BOE in 2020 while TPP reserves per fully diluted share were 2.81 BOE.
  • TP reserves represented 80 percent of total TPP reserves in 2020, compared to 81 percent in 2019, 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 TPP reserves totaled $867.0 million, while TP reserves totaled $642.5 million and proved developed producing (“PDP”) reserves totaled $402.0 million.
  • Increased TPP, TP, and PDP reserve life indices (“RLI”)3 to approximately 24 years on a TPP basis, 20 years on a TP basis, and nine years on a PDP basis (based on 2020 average production of 10,575 BOE per day).

________________________________

3 “Reserve life index” does not have a standardized meaning. See “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, 2020

Light and
Medium Crude
Oil

Conventional
Natural Gas4

Natural Gas
Liquids

Oil equivalent5

Future
Development
Capital

(MBbl)

(MMcf)

 (MBbl)

 (MBoe)

($000s)

Proved

Developed Producing

18,442

69,482

3,220

33,243

242

Developed Non-producing

1,748

3,989

158

2,571

2,460

Undeveloped

22,877

77,005

3,794

39,505

564,916

Total Proved

43,067

150,476

7,172

75,319

567,618

Total Probable

10,662

36,986

1,765

18,592

7,760

Total Proved plus Probable 1,2,3

53,729

187,462

8,938

93,910

575,378

Notes for table above:

(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, 2020 escalated price deck.

(4)

Conventional natural gas amounts shown include solution gas.

(5)

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, 2020 1,2

Light & Medium
Crude Oil

Conventional
Natural Gas
5

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, 2019

46,709

57,874

162,345

201,326

7,771

9,649

81,537

101,077

Extensions & Improved Recovery 2

1,597

2,007

4,583

5,738

291

364

2,652

3,328

Technical Revisions

(94)

(272)

(301)

(864)

(87)

(86)

(231)

(502)

Discoveries

Acquisitions

Dispositions 3

Economic Factors

(3,011)

(3,746)

(8,002)

(10,588)

(425)

(612)

(4,770)

(6,123)

Production

(2,134)

(2,134)

(8,150)

(8,150)

(378)

(378)

(3,870)

(3,870)

Closing Balance, December 31, 2020 4

43,067

53,729

150,476

187,462

7,172

8,938

75,319

93,910

Notes for table above:

(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.

(5) 

Conventional natural gas amounts shown include solution gas.

Summary of Net Present Values of Future Net Revenue as of December 31, 2020

($M)

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

Reserves Category:

0%

5%

10%

15%

Proved

    Producing

558,627

489,583

401,988

338,882

    Non-producing

40,354

28,707

21,224

16,344

    Undeveloped

617,171

361,515

219,293

135,561

Total Proved

1,216,153

879,806

642,505

490,787

Probable

555,740

328,279

224,462

168,443

Total Proved plus Probable 1,2,3

1,771,893

1,208,084

866,967

659,230

Notes for table above:

(1)

Evaluated by Sproule as at December 31, 2020. 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, 2020. 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.

FUTURE DEVELOPMENT CAPITAL, F&D COSTS6 AND RECYCLE RATIOS6

Future development capital (“FDC”) reflects Sproule’s best estimate of the costs to bring Bonterra’s proved and probable developed and undeveloped reserves on production. Changes in forecasted FDC occur annually as a result of development activities, acquisition and disposition activities, changes in capital cost estimates based on improvements in well design and performance, and changes in service costs. Undiscounted TPP FDC at December 31, 2020 decreased by $76 million relative to December 31, 2019, and totaled $575 million. The year-over-year decrease is driven primarily by capital efficiency improvements related to drilling and completions activities.

Over the past three years, Bonterra has incurred the following finding, development and acquisition (“FD&A”)6 and finding and development (“F&D”)6 costs both excluding and including FDC:

TP Reserves Net Additions

TPP Reserves Net Additions

2020

2019

2018

3 Yr Avg4

2020

2019

2018

3 Yr Avg4

FD&A Costs per BOE 1,2,3,6

Including FDC

$(12.08)

$12.26

$12.66

$8.68

$(11.52)

$15.24

$13.90

$9.40

Excluding FDC

$17.66

$8.51

$11.25

$11.14

$15.47

$10.32

$12.32

$12.22

F&D Costs per BOE 1,2,3,6

Including FDC

$(12.08)

$12.26

$12.79

$8.50

$(11.52)

$15.24

$15.00

$9.45

Excluding FDC

$17.66

$8.51

$12.35

$11.59

$15.47

$10.32

$14.41

$13.04

Recycle Ratio 2,5,6

F&D (including FDC)

N/A

2.2

2.1

1.2

N/A

1.7

1.9

0.9

Notes for table above:

(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) 

The calculation of F&D and FD&A costs both includes or excludes, as labelled, the change in FDC required to bring proved undeveloped and developed reserves into production.  The F&D or FD&A number is calculated by dividing the identified capital expenditures by applicable reserve additions including extensions, infills. revisions and acquisitions, excluding economic factors, after or before changes in FDC costs (as labelled).

(4) 

Three-year average is calculated using three-year total capital costs and reserve additions on both a TP and TPP reserves on a weighted average basis.

(5) 

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 field netback in 2020, used in the above calculations, averaged $14.49 per BOE (unaudited). 

(6) 

“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.

RECOMMENDATION FOR SHAREHOLDERS TO REJECT THE HOSTILE BID

Bonterra and its Board of Directors reiterates the previous recommendation that shareholders reject Obsidian Energy Ltd.’s (“Obsidian”) highly-conditional, unsolicited bid to acquire all of the issued and outstanding common shares of Bonterra in exchange for shares of Obsidian (the “Hostile Bid”) and continues to strongly recommend that Bonterra shareholders TAKE NO ACTION and REJECT the Hostile Bid by NOT TENDERING their shares.

For more information, including the Company’s recent shareholder letters, Directors’ Circular and other relevant materials, please visit Bonterra’s website at www.bonterraenergy.com or the Company’s profile on the SEDAR website at https://www.sedar.com/.

Shareholder Questions:

Shareholders with questions related to the Hostile Bid are encouraged to call Bonterra’s information agent, Laurel Hill Advisory Group at 1-877-452-7184 (+1-416-304-0211 outside North America) or email assistance@laurelhill.com.

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

Cautionary Statements

This summarized news release should not be considered a suitable source of information for readers who are unfamiliar with Bonterra Energy Corp. and should not be considered in any way as a substitute for reading the full report.  For the full report, please go to www.bonterraenergy.com

Use of Non-IFRS Financial Measures

Throughout this release the Company uses the terms “funds flow”, “free funds flow”, “net debt” and “field netback” to analyze operating performance, which are not standardized measures recognized under IFRS and do not have a standardized meaning prescribed by IFRS. These measures are commonly utilized in the oil and gas industry and are considered informative by management, shareholders and analysts. These measures may differ from those made by other companies and accordingly may not be comparable to such measures as reported by other companies.

The Company defines funds flow as funds provided by operations excluding effects of changes in non-cash working capital items and commissioning expenditures settled. Free funds flow is defined as funds flow less dividends paid to shareholders, capital and decommissioning expenditures settled. Net debt is defined as current liabilities less current assets plus long-term bank debt and subordinated debt. Field netback is defined as revenue minus royalties, operating expenses and transportation expenses.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information

All amounts in this news release are stated in Canadian dollars unless otherwise specified.  Bonterra’s oil and gas reserves statement for the year ended December 31, 2020, which will include complete disclosure of its oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within its Annual Information Form which will be available on Bonterra’s SEDAR profile at www.sedar.com or on the Company’s website on March 9, 2021. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  In relation to the disclosure of estimates for individual properties or subsets thereof, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading “Forward-Looking Information and Statements”.

This press release contains metrics commonly used in the oil and natural gas industry, such as “recycle ratio”, “finding and development costs”, “finding and development recycle ratio”, “finding, development and acquisition costs”, and “field netbacks”. Each of these metrics are determined by Bonterra as specifically set forth in this news release.  These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.  Such metrics have been included to provide readers with additional information to evaluate the Company’s performance however, such metrics should not be unduly relied upon for investment or other purposes.  Management uses these metrics for its own performance measurements and to provide readers with measures to compare Bonterra’s performance over time.

Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.  The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D 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 Bonterra’s ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Bonterra’s performance over time, however, such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the performance in previous periods.  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 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 asset retirement obligations; 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; the impact of the COVID-19 pandemic; 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.

Frequently recurring terms

Bonterra uses the following frequently recurring terms in this press release: “WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States; “MSW Stream Index” or “Edmonton Par” refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; “AECO” refers to Alberta Energy Company, a grade or heating content of natural gas used as benchmark pricing in Alberta, Canada; “bbl” refers to barrel; “NGL” refers to Natural gas liquids; “MCF” refers to thousand cubic feet; “MMBTU” refers to million British Thermal Units; “GJ” refers to gigajoule; and “BOE” refers to barrels of oil equivalent.  Disclosure provided herein in respect of a BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Numerical Amounts

The reporting and the functional currency of the Company is the Canadian dollar.

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

SOURCE Bonterra Energy Corp.

For further information: 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

Related Links

http://www.bonterraenergy.com/

 



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