2021 Q3

For the three and nine		TSX: BNE
	www.bonterraenergy.com
months ended
September 30, 2021

BONTERRA ENERGY REPORTS THIRD QUARTER AND NINE MONTHS ENDED

SEPTEMBER 30, 2021 FINANCIAL AND OPERATING RESULTS

HIGHLIGHTS

		Three months ended	Nine months ended
As at and for the periods ended	September 30,	September 30,	September 30,	September 30,
($ 000s except for $ per share and $ per BOE)	2021	2020	2021	2020
FINANCIAL
Revenue - realized oil and gas sales	64,457	29,155	172,414	89,881
Funds flow (1)		28,658	6,266	68,355	25,121
Per share - basic		0.85	0.19	2.03	0.75
Per share - diluted		0.83	0.19	1.98	0.75
Cash flow from operations		24,616	6,370	58,235	33,272
Per share - basic		0.73	0.19	1.73	1.00
Per share - diluted		0.71	0.19	1.69	1.00
Net earnings (loss)(2)		7,296	(5,211)	162,966	(295,818)
Per share - basic		0.22	(0.16)	4.84	(8.86)
Per share - diluted		0.21	(0.16)	4.72	(8.87)
Capital expenditures		18,578	2,819	49,646	24,664
Total assets				939,835	722,910
Net debt(3)				307,729	295,168
Working capital deficiency				260,976	295,168
Long-term debt				46,753	-
Shareholders' equity				361,590	207,325
OPERATIONS
Light oil	-barrels (bbl) per day	6,948	5,355	7,051	5,987
	-average price ($ per bbl)	78.42	45.73	70.68	43.45
NGLs	-bbl per day	928	1,064	983	1,056
	-average price ($ per bbl)	48.86	19.29	39.82	16.78
Conventional natural gas	- MCF per day	27,995	21,510	26,131	22,169
	- average price ($ per MCF)	3.94	2.40	3.60	2.27
Total barrels of oil equivalent per day (BOE)(4)	12,542	10,004	12,389	10,737

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 innon-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 ofCOVID-19 effect on the forward benchmark prices for crude oil. With stronger forward prices in Q2 2021, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU's oil and gas assets less $47,149,000 deferred income tax expense.
3. Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets pluslong-term 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.

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REPORT TO SHAREHOLDERS

Bonterra Energy Corp. (Bonterra or the Company) is pleased to present our third quarter 2021 financial and operating results, selected highlights from which are provided below. Readers are encouraged to review in conjunction with the Company's full Q3 2021 report which has been filed on SEDAR and is available on Bonterra's website.

Q3 2021 FINANCIAL & OPERATING SNAPSHOT

• Averaged 12,542 BOE per day of production in Q3 2021, 25 percent higher than in Q3 2020, and 12,389 BOE per day in the first nine months of 2021, a 15 percent increase over the comparative period the prior year.

1. Volumes in Q3 2021 were impacted bythird-party midstream issues, including a fire at an NGL fractionation plant and other downtime at downstream pipelines and facilities, which led to approximately 650 BOE per day being shut-in during the period.

• 1. These volumes are expected to be brought backon-stream in Q4 2021, along with approximately 275 BOE per day of production that had previously been shut-in due to weak prices. Bonterra anticipates the impact of these incremental volumes will contribute meaningfully to higher production in the fourth quarter of 2021, with average volumes in the month of October 2021 averaging approximately 14,000 BOE per day1.
• Realized oil and gas sales increased 121 percent over Q3 2020 to total $64.5 million in Q3 2021, and in the first nine months of 2021, increased by 92 percent over the same period in 2020 with increases primarily driven by higher realized crude oil prices and growing production volumes.
• Generated funds flow2of $28.7 million ($0.83 per fully diluted share) in Q3 2021, a 356 percent increase from $6.3 million ($0.19 per fully diluted share) in Q3 2020 while funds flow2in the first nine months of 2021 totaled $68.4 million ($1.98 per fully diluted share) representing an increase of 172 percent from the same period of 2020.
• Production costs per unit were reduced to $14.45 per BOE in Q3 2021, four percent lower than the preceding quarter.
• Drilling, completion and equipping costs in the first nine months of 2021 decreased by approximately 29 percentyear-over-year to average $1.5 million per well.
• Field netbacks2averaged $31.03 per BOE in Q3 2021 and $27.80 per BOE in the first nine months of 2021, representing increases of 107 percent and 92 percent over the comparative periods of 2020, respectively, with the increases primarily reflecting significantly higher per unit revenue offset by realized losses on risk management contracts and increased per unit royalty expenses.
• Capital expenditures totaled $49.6 million in the first nine months of 2021 including $18.6 million invested in Q3 2021. Of the first nine months' capital, $40.5 million was directed to the drilling of 29 gross (27.4 net) wells along with the completion, equip andtie-in of 29 gross (27.2 net) wells, with four of the completed and equipped wells having been drilled in 2020. Of the wells drilled in 2021, 25 have been placed on production as of September 30, 2021. An additional $9.1 million was spent primarily on related infrastructure and recompletions.
• Net debt2totaled $307.7 million as at September 30, 2021, a $7.8 million improvement from year-end 2020, reflecting the effects of improving commodity prices and the more active capital program which has restored production levels to pre-COVID-19 levels. Subsequent to the quarter and in conjunction with the previously announced brokered private placement debt and warrant financings, the Company successfully restructured our bank debt to be a fully conforming revolving credit facility of $220 million, eliminating the non-revolving term loan of $65 million. The first of these financings closed on October 20, 2021, with the second anticipated to close on or about November 10, 2021.

1. October 2021 volumes comprised of 7,980 bbl/d light and medium crude oil, 1,120 bbl/d NGLs and 29,400 mcf/d of conventional natural gas.
2. "Funds Flow", "Field Netback" and "Net Debt" are not recognized measures under IFRS. See "Cautionary Statements" below.

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The Company has continued to benefit from further increases in crude oil and natural gas prices which have now generated nearly $19 million of funds flow in excess of capital expenditures during the first nine months of the year, attributable to our low decline rate and disciplined approach to capital allocation. During the third quarter of 2021, Bonterra realized average oil prices of $78.42 per bbl, average NGL prices of $48.86 per bbl, and average natural gas prices of $3.94 per mcf. These improved revenues contributed to a 12 percent and 24 percent improvement of field and cash netbacks to $31.03 per BOE and $24.84 per BOE, respectively, compared to the prior quarter.

With spring breakup completed, the Company resumed a pace of capital investment during the quarter designed to target sustainable production growth, drilling 13 gross (11.5 net) wells and placing on production nine gross (7.5 net) wells.

Bonterra also continued to reduce our decommissioning liabilities with support of the Alberta Site Rehabilitation Program ("SRP"). By the end of the third quarter, the Company had abandoned 189.4 net wells and decommissioned

2.0 net battery sites during the first nine months of the year, having spent $3.1 million of a $5.1 million commitment for the 2021 fiscal year. As we continue to execute our abandonment program through the remainder of 2021 and 2022, a further 167.8 net wells that have no deemed future potential are forecast to be abandoned. Bonterra continuously reviews our inactive well inventory for future potential to determine if a well bore should be reactivated, repurposed, or abandoned.

During the third quarter of 2021, the Company appointed Ms. Stacey McDonald to our Board of Directors, effective August 16, 2021. Ms. McDonald will assume the role of Chair of the Reserves Committee, while serving on the Audit, Compensation, and Governance and Nominating Committees. Ms. McDonald's 16 years of energy and finance experience will bring valuable insights and contributions to the Board.

OUTLOOK

The Company expects that shut-ins related to the third-party fractionation plant fire and downstream compression issues will be resolved in the fourth quarter of 2021, returning 650 BOE per day of production which was shut-in during the third quarter of 2021. A further 275 BOE per day of voluntary shut-in production volumes are expected to be reactivated during the fourth quarter.

In Q4 2021, the Company expects to drill 8 gross (8.0 net) operated wells, of which 2 gross (2.0 net) wells will be completed and placed on production to further contribute to quarterly volumes. The remaining 6 wells are forecast to begin production in Q1 2022. The Company also plans to place on production an additional 4 gross (4.0 net) wells in Q4 2021 that were drilled in Q3 2021.

Even with the shut-ins experienced during the third quarter, the Company is pleased to reiterate our previous 2021 average annual production guidance range of 12,800 to 13,200 BOE per day3, supported by average production of approximately 14,000 BOE per day4in October 2021. In the near-term, Bonterra anticipates realizing enhanced benefit from new volumes being brought on-stream into improved commodity prices.

Bonterra plans to announce the Board approved 2022 guidance before the end of December 2021. The 2022 preliminary budget estimates production will be in excess of the Company's 2021 average annual guidance range. Assuming this level of production and current forward strip pricing, Bonterra anticipates a meaningful deleveraging of the balance sheet which would result in an improved debt to cash flow ratio between 1.0x and 1.5x by the end of 2022.

As part of the Company's ongoing efforts to diversify commodity prices and protect future cash flows, Bonterra has put in place physical delivery sales and risk management contracts to the end of September 30, 2022, details of which are included in Note 12 to the third quarter 2021 financial statements. With approximately 30 percent of forecast volumes hedged, the Company can continue to benefit from potential commodity price improvements while mitigating market volatility and locking-in economics.

1. 2021 annual forecast volumes comprised of 7,050 to 7,400 bbl/d light and medium crude oil, 1,390 to 1,400 bbl/d NGLs and 26,100 to 26,500 mcf/d conventional natural gas.
2. October 2021 volumes comprised of 7,980 bbl/d light and medium crude oil, 1,120 bbl/d NGLs and 29,400 mcf/d of conventional natural gas.

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FINANCING UPDATE

Subsequent to the quarter end, and as previously announced on October 20, 2021, Bonterra successfully closed a brokered private placement debt and warrant financing (the "Initial Offering"), enhancing our financial flexibility and achieving our goal of restructuring all bank debt to a fully conforming revolving credit facility. The combination of senior unsecured debentures and common share purchase warrants provided gross proceeds of $32 million. Concurrent with the closing of the Initial Offering, Bonterra issued a separate offering, which was subsequently upsized, raising an additional $7.5 million on the same terms and conditions as the Initial Offering. The follow-on offer is expected to close on or about November 10, 2021.

In concert with the financings, the Company amended the terms of our credit facility to a $195 million syndicated revolving credit facility and a $25 million non-syndicated revolving facility, representing an elimination of the previous $65 million non-revolving term loan. The amended facility has $10 million step-downs at December 31, 2021 and March 31, 2022 prior to the next redetermination date before May 31, 2022, and has a maturity date of November 30, 2022.

Management believes the Company is well positioned to continue reducing bank debt and strengthening the balance sheet, a commitment that has been bolstered by a strengthening commodity price environment. The Company plans to generate profitable growth through this period of improving oil and natural gas markets by prudently developing our high-quality, light oil weighted asset base and directing excess funds flow to a combination of debt repayment plus modest growth. In addition, the Company continues to prioritize environmental, social and governance initiatives, and is committed to employing local services, being a key economic contributor to rural and surrounding communities located within central Alberta, upholding a responsible abandonment and reclamation program, and maintaining rigorous safety measures.

George F. Fink

Chief Executive Officer

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MANAGEMENT'S DISCUSSION AND ANALYSIS

The following report dated November 9, 2021 is a review of the operations and current financial position for the three and nine months ended September 30, 2021 for Bonterra Energy Corp. ("Bonterra" or "the Company") and should be read in conjunction with the unaudited condensed financial statements and the audited financial statements including the notes related thereto for the fiscal year ended December 31, 2020 presented under International Financial Reporting Standards (IFRS), as well as Bonterra's Annual Information Form ("AIF"), each of which is filed on SEDAR at www.sedar.com.

Use of Non-IFRS Financial Measures

Throughout this Management's Discussion and Analysis (MD&A) the Company uses the terms "field netback", "cash netback" and "net debt" 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 used 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 calculates cash and field netback by dividing various financial statement items as determined by IFRS by total production for the period on a barrel of oil equivalent basis. The Company calculates net debt as long-term debt plus working capital deficiency (current liabilities less current assets).

Frequently Recurring Terms

Bonterra uses the following frequently recurring terms in this MD&A: "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" is the benchmark price for natural gas 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.

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