Bonterra Energy Announces Third Quarter 2026 Results with Record Production; Provides Operations Update and 2027 Budget Guidance

CALGARY, Alberta, Nov. 13, 2026 (GLOBE NEWSWIRE) -- Bonterra Energy Corp. (TSX: BNE; OTCID: BNEFF) (“Bonterra” or the “Company”), a Calgary based oil and gas producer, is pleased to announce its financial and operating results for the three and nine months ended September 30, 2026, highlighted by record quarterly production of 17,222 barrels of oil equivalent (“BOE”) per day, together with its 2027 budget guidance. Bonterra delivered a 43% increase in funds flow per fully diluted share compared to the third quarter of 2025, supported by 17% growth in light crude oil and natural gas liquids production, with funds flow of $30.7 million ($0.83 per fully diluted share).

The Company’s Board of Directors has also approved its 2027 budget and guidance highlighted by a focus on liquids growth, free funds flow generation and additional derisking of inventory at Bonanza Charlie Lake and Wembley Montney. The related unaudited condensed financial statements and management’s discussion and analysis (“MD&A”), are available on SEDAR+ at www.sedarplus.ca and on Bonterra’s website at www.bonterraenergy.com.

Q3 Highlights:

• Record Quarterly Production averaged 17,222 BOE per day for the quarter, with light crude oil and NGL production up 17% compared to Q3 2025, reflecting focused growth in liquids production
• Strong Funds Flow¹ Growth totaled $30.7 million ($0.83 per fully diluted share), an increase of 43% per fully diluted share compared to Q3 2025, reflecting higher liquids production and a stronger oil pricing environment
• Disciplined Capital Expenditures¹ totaled $15.3 million in the quarter
• Debt Reduction of $8.1 million for the quarter, after funding of the $4.65 million Bonanza Charlie Lake Tuck-in acquisition, brought Adjusted Net Debt¹ to $184.4 million at September 30, 2026
  
  

2027 Budget Guidance Highlights:

• 2027 Guidance targets shareholder returns of approximately 25% comprised of 20% free funds flow yield¹ and 5% year-over-year production growth³
• 2027 Capital Budget Focused on Liquids Growth and Inventory Expansion underpinned by total capital of $120 million, at guidance midpoint, with approximately 90% directed towards base development capital, bringing 23.6 net wells on production and approximately 10% directed towards additional delineation to unlock further drilling inventory at Bonanza Charlie Lake and Wembley Montney that will add production in 2028 with additional infrastructure investment
• 2027 Production and Financial Guidance targets midpoint average production of 17,400 BOE per day², generating approximately 10% liquids growth, $171 million of funds flow¹ ($4.67 per share⁴) and $44 million of free funds flow¹ ($1.20 per share⁴)
• Continued Debt Reduction planned to achieve approximately $125 million to $135 million of adjusted net debt¹ (0.7x EBITDA¹ at guidance midpoint) by year end 2027
  
  

Patrick Oliver, President and Chief Executive Officer, stated: “Our third quarter results reflect record quarterly production and continued growth in liquids production and funds flow per share, supported by disciplined development across our core assets. At Bonanza Charlie Lake, our drilling results to date have expanded our inventory of top tier locations, and ongoing evaluation of well performance is helping us refine and build additional confidence in our development strategy in the play.”

Mr. Oliver added: “Our 2027 plan represents a meaningful step forward for Bonterra. We are well positioned in this commodity environment to generate outsized shareholder returns through production growth and free funds flow generation to achieve significant debt reduction. Our pivot into the Bonanza Charlie Lake and Wembley Montney provides the Company with valuable optionality to allocate development capital across three highly economic light oil plays. Delineation capital detailed in our plan is expected to add Tier 1 inventory with a longer-term view to continued growth. We expect 2027 to be a year of building on our momentum and continuing to generate exceptional operational results across our three core areas.”

Financial & Operating Highlights

Production averaged 17,222 BOE per day during the third quarter of 2026, an increase of 19% compared to the same period in 2025, with combined light crude oil and NGL production up 17% driven by an active first half 2026 capital program and strong production performance from existing producing assets.

Funds Flow¹ totaled $30.7 million ($0.83 per fully diluted share) in the third quarter of 2026, an increase of 43% per fully diluted share compared to the same period in 2025, mainly driven by higher light crude oil and NGL production and a stronger oil price environment.

Net Earnings (Loss) totaled $(4.4) million ($(0.12) per fully diluted share) in Q3 2026, inclusive of a $11.2 million unrealized hedging loss. The non-cash unrealized hedging loss impacted reported earnings but did not directly reduce funds flow for the quarter. Net earnings for the first nine months of 2026 totaled $1.6 million.

Field Netback and Cash Netback¹ in Q3 2026 averaged $24.34 per BOE and $19.40 per BOE, respectively, inclusive of realized hedging losses in the quarter of $4.47 per BOE, with WTI crude oil prices averaging US$85.79 per barrel and AECO natural gas prices averaging $1.56 per mcf during the period.

Production costs averaged $17.99 per BOE in Q3 2026, compared to $16.41 per BOE in the same period in 2025. The increase was driven by higher workover and maintenance activity, as well as temporary water handling costs associated with new wells and higher gas processing costs from increased natural gas volumes.

Capital expenditures¹ totaled $15.3 million in Q3 2026. Approximately 48% was directed to completing, equipping and tying in four gross (4.0 net) operated wells, including one Charlie Lake and three Cardium oil wells. The remaining capital was directed to land acquisitions, recompletions, non-operated activity and supporting infrastructure.

Adjusted Net Debt¹ totaled $184.4 million at the end of the third quarter of 2026, down $8.1 million from the second quarter of 2026 which includes the funding of the $4.65 million Bonanza Charlie Lake Tuck-in acquisition, resulting in an adjusted net debt to trailing twelve-month EBITDA ratio of 1.5:1, compared to 1.6:1 in the previous quarter.

Financial and Operating Results

		Three months ended				Nine months ended
As at and for the periods ended ($ 000s except for $ per share and $ per BOE)		September 30, 2026		September 30, 2025		September 30, 2026	September 30, 2025
FINANCIAL
Revenue - realized oil and gas sales		89,524		55,166		253,174	190,041
Funds flow (1)		30,734		21,330		87,176	72,057
Per share - basic		0.86		0.59		2.42	1.96
Per share - diluted		0.83		0.58		2.35	1.93
Cash flow from operations		19,144		8,344		75,560	67,954
Per share - basic		0.53		0.23		2.09	1.85
Per share - diluted		0.52		0.23		2.04	1.82
Net earnings (loss)		(4,447)		(3,554)		1,615	(12,477)
Per share - basic		(0.12)		(0.10)		0.04	(0.34)
Per share - diluted		(0.12)		(0.10)		0.04	(0.33)
Capital expenditures(1)		15,254		14,783		79,724	53,584
Oil and gas property acquisition(2)		4,737		-		4,737	-
Total assets						973,959	935,536
Adjusted net debt(1)						184,379	168,698
Bank debt						42,066	26,011
Shareholders' equity						524,401	526,565
OPERATIONS
Light oil	-bbl per day	6,933		6,051		6,670	6,462
	-average price ($ per bbl)	112.52		81.92		110.53	84.30
NGLs	-bbl per day	1,738		1,353		1,658	1,512
	-average price ($ per bbl)	50.71		40.42		50.88	42.95
Conventional natural gas	- MCF per day	51,306		42,336		49,096	45,755
	- average price ($ per MCF)	2.04		1.16		2.15	1.89
Total BOE per day		17,222		14,460		16,511	15,600

Notes to the above table:

⁽¹⁾ Non-IFRS measure with no standardized meaning; may not be comparable to other issuers’ measures. See advisories in this press release.
⁽²⁾ On August 10, 2026, the Company acquired all of the issued and outstanding shares of a private oil and gas company holding a non-operated working interest in certain of the Company’s Charlie Lake assets, for cash consideration of $4.18 million and the assumption of a $0.47 million working capital deficiency. This acquisition has been accounted for as an asset acquisition, which resulted in a $4.74 million increase in PP&E and the assumption of $0.09 million in decommissioning liabilities.

Operations Update

Bonanza Charlie Lake

The Company continued to advance development and infrastructure planning at Bonanza Charlie Lake during the third quarter, building on its first-half step-out results, the “03-16” well and the “03-25” well, which validated the lands added in our Q4 2025 acquisition and derisked approximately 20 top tier drilling locations. The Company is incorporating these results into its development inventory and evaluating the infrastructure required to support future production. In the third quarter the Company commenced drilling operations on two additional Charlie Lake wells on the lands added in our Q4 2025 acquisition and plans to complete and bring one of the wells on production in the fourth quarter with the second well planned to be completed and brought on production in the first quarter of 2027.

During the quarter, the Company brought its previously announced “16-11” well on production. The well achieved average 30-day peak rates of approximately 370 BOE per day, including approximately 130 barrels per day of light crude oil, 21 barrels per day of natural gas liquids and 1.3 mmcf per day of conventional natural gas. While initial production results were below internal expectations the well has demonstrated stronger longer-term production potential exhibiting a low production decline to date. At current rates the well is expected to pay out in less than two years on forward strip pricing. The Company continues to monitor production performance, assess potential contributing factors to refine our well design and future planning, and plans to spend delineation capital in the area in 2027.

On August 10, 2026, the Company acquired all of the issued and outstanding shares of a private company with assets located in the Company’s Bonanza Charlie Lake area, for cash consideration of $4.18 million and the assumption of a $0.47 million working capital deficiency. The acquisition consolidates Bonterra’s primary non-operated partner and increases the Company’s working interest across its Bonanza Charlie Lake position from approximately 90% to 100%. Full ownership is expected to simplify future planning, optimize full cycle development costs and provide greater operational flexibility across Bonterra’s core Charlie Lake development. 

Net production from the Bonanza Charlie Lake asset in the third quarter was approximately 5,352 BOE per day², inclusive of the previously announced acquisition closed on August 10, 2026, representing 31% of total production in the quarter.

Wembley Montney

At Wembley Montney, the Company’s third Montney well is now fully cleaned up and has demonstrated strong production results with IP180 rates of approximately 800 BOE per day, including approximately 345 barrels per day of liquids (235 barrels per day of light crude oil, 110 barrels per day of natural gas liquids) and 2.75 mmcf per day of conventional natural gas, which is on par with the Company’s second Montney well, representing its best production result to date.

The Company is incorporating the operational and technical findings from its first three wells into future drilling and completion designs and its assessment of the economics of further development. The 2027 base development budget includes bringing 1.0 net Montney well on production from its existing pad, and within its 2027 delineation budget, the Company plans to drill, complete and test production on an additional well in the northern area of the land base, with an additional infrastructure investment decision to follow upon economic success.

Net production from the Wembley Montney asset in the third quarter was approximately 1,314 BOE per day², representing 8% of total production in the quarter.

Pembina Cardium

The Company continued to optimize production and advance development opportunities across its Pembina Cardium asset during the third quarter. The Company brought three wells on production into an active water flood area and is encouraged with the results demonstrating above type curve performance from the program.

The Company’s Cardium development strategy remains focused on maintaining base production, improving recovery from existing reservoirs under water flood and drilling locations in previously delineated areas that deliver competitive returns. The Cardium base production performance so far in 2026 has been strong, averaging approximately 10,900 BOE per day² over the first three quarters, demonstrating that a refined focus on optimization of the base assets over the past few years has resulted in enhanced sustainability and free funds flow generation.

Building on the strong year for the base Cardium assets in 2026 and taking advantage of the strong oil pricing environment, the 2027 base development budget includes bringing 15.0 net Cardium wells on production, supported by targeted water flood and infrastructure investment. Drilling will be sequenced according to reservoir performance, expected well economics and prevailing commodity prices.

Net production from the Pembina Cardium asset in the third quarter was approximately 10,556 BOE per day², representing 61% of total production in the quarter.

Updated 2026 Outlook

The Company reaffirms its production and capital guidance for 2026 outlined below:

• Annual average production range of 16,600 to 16,800 BOE per day², weighted approximately 50 to 52% to light oil and natural gas liquids; and
• Capital expenditure range, excluding acquisitions and divestitures, of $85 million to $90 million.

For the remainder of the year, Bonterra plans to continue to focus on free funds flow generation and balance sheet management with the fourth quarter capital program scheduled to complete, tie-in and bring on production one Bonanza Charlie Lake well. Bonterra plans to enter 2027 with one Bonanza Charlie Lake well drilled and uncompleted (DUC) offsetting the “03-16” well (referenced on the earlier map).

Bonterra remains committed to managing leverage prudently, with further debt reduction a priority for the remainder of 2026.

2027 Budget: Liquids Driven Growth (~10%)³ generating $44 Million of Free Funds Flow¹

The Company’s Board of Directors (the “Board”) has approved its 2027 budget (the “Budget”) along with the associated guidance outlined below:

	2027 Guidance
Pricing
WTI (US$ per bbl)	$80.00
AECO Natural Gas Prices ($ per GJ)	$2.00
Canadian $ to U.S. $ exchange rate	$0.71
Operating & Financial
Average Daily Production (BOE per day)	17,300 – 17,500
Oil and NGL Weighting (percent)	51 – 53
Funds Flow2,3,4 (millions)	$171
Capital Expenditures4 (millions)	$115 – $125
Asset Retirement Obligations (millions)	$7
Free Funds Flow4 (millions)	$44
Adjusted Net Debt4 at Year End (millions)	$125 – $135
Adjusted Net Debt to Last Twelve Months’ EBITDA4	0.7x

Notes to the above table:
¹ Canadian realized oil price is based on WTI US$80.00 per barrel; Edmonton par differential of US$3.00 per barrel; CAD/USD exchange rate of 0.71 and a quality adjustment of approximately CAD $4.00 per barrel. Pricing includes hedges currently in place.
² Funds Flow is estimated using the Canadian realized oil price above, a realized natural gas price of approximately CAD $2.50 per mcf and a realized NGL price of approximately CAD $54.25 per barrel. Pricing includes hedges currently in place. The Budget excludes acquisitions and dispositions.
 ³ 2027 guidance assumes the enactment of the proposed Productivity Mega Deduction substantially as proposed. Should the deduction not be enacted, the Company may reassess its 2027 guidance.
⁴ Non-IFRS measure with no standardized meaning; may not be comparable to other issuers’ measures. See advisories in this press release.

Budget and Guidance Details

The 2027 Budget is structured to grow liquids-weighted production and generate meaningful free funds flow through continued development of the Company’s established Pembina Cardium production base and Bonanza Charlie Lake asset, supported by targeted drilling, completions, infrastructure and production optimization, alongside measured activity at Wembley Montney. The Budget balances near-term production growth from established development opportunities with longer-term investment to expand and derisk the Company’s drilling inventory. The Company plans to bring 22.0 net operated wells on production in 2027, including 6.0 net Bonanza Charlie Lake wells, 1.0 net Wembley Montney well and 15.0 net Pembina Cardium wells, in addition to $10 million to $15 million directed toward additional delineation at Bonanza Charlie Lake and Wembley Montney to further derisk inventory.

The allocation of the Company’s 2027 planned capital expenditures across base development, delineation and other capital activities is expected to be:

• approximately 30 percent towards the Charlie Lake core area, including the drilling of 5.0 net wells and completion of 6.0 net wells and infrastructure to support the area’s long-term development;
• approximately 10 percent towards the Montney, including the drilling and completion of 1.0 net well;
• approximately 10 percent to further delineation capital at Bonanza Charlie Lake and Wembley Montney requiring additional infrastructure investment; and
• approximately 50 percent towards the Cardium core area, including the drilling and completion of 15.0 net operated wells (16.6 net total wells) and targeted water flood and infrastructure projects.

Bonterra remains committed to a disciplined approach to managing leverage levels and will direct 2027 free funds flow with a primary focus on debt repayment and a secondary focus on opportunistic share buybacks.

To mitigate risk and add stability during periods of market volatility, the Company has continued to add oil, natural gas and foreign exchange hedges. In 2027 the Company has hedged approximately 20% of forecast oil production at fixed WTI prices ranging between US$72.85 to US$82.50, 8% of forecast natural gas production at fixed prices ranging between $1.70 per GJ to $3.10 per GJ and 12% of forecast U.S. dollar exposure at an average USD/CAD exchange rate of 1.3927.

Bonterra’s budget is designed to enable the Company to responsibly manage the pace of capital deployment and prioritize capital based on risk-adjusted project returns. Bonterra plans to regularly review the Budget and may elect to adjust the amount and timing of capital spending depending on operating results and the prevailing commodity price environment.

The following table shows Bonterra’s sensitivity to key commodity price variables. The sensitivity calculations are performed independently and show the effect of changing one variable while holding all other variables constant.

Annualized sensitivity analysis on funds flow, as estimated for 2027¹

Impact on funds flow	Change		$MM		$ per share2
WTI crude oil price (US$/bbl)	$	1.00	$	2.3	$	0.06
AECO natural gas price ($/GJ)	$	0.10	$	2.1	$	0.06
U.S.$ to Canadian $ exchange rate	$	0.01	$	1.4	$	0.04

Notes to the above table:
¹ This analysis uses current royalty rates, annualized estimated average production of 17,400 BOE per day and no changes in working capital. Analysis includes hedges currently in place.
² Based on annualized basic weighted average shares outstanding of 36,587,809.

Notes Excluding Tables

⁽¹⁾ Non-IFRS measure with no standardized meaning; may not be comparable to other issuers’ measures. See advisories in this press release.
⁽²⁾ See “Information Regarding Product Types” contained in this press release.
⁽³⁾ Based on 2026 guidance low end of 16,600 BOE per day² and 2027 guidance midpoint of 17,400 BOE per day².
⁽⁴⁾ Based on annualized basic weighted average shares outstanding of 36,587,809.

About Bonterra

Bonterra Energy Corp. (TSX: BNE | OTCID: BNEFF) is a Calgary-based oil and gas producer offering investors exposure to a portfolio of high-impact assets across three of Alberta’s premier light oil plays. Bonterra leverages the stable production and free funds flow of the Pembina Cardium — one of Canada’s largest oil plays — alongside the growth potential of the Bonanza Charlie Lake and Wembley Montney. Built on disciplined growth, capital efficiency, and steady debt reduction, Bonterra is positioned to deliver long-term, sustainable value to shareholders through commodity cycles. For more information, visit www.bonterraenergy.com or follow Bonterra on LinkedIn and X.

For further information please contact:

Bonterra Energy Corp.
Patrick Oliver, President & CEO
Scott Johnston, CFO

Telephone: (403) 262-5307
Fax: (403) 265-7488
Email: info@bonterraenergy.com 

Cautionary Statements

This press release is a summary of Bonterra’s results for the three and nine months ended September 30, 2026 and should be read together with the Company’s unaudited condensed financial statements and MD&A for the same period, which are available on SEDAR+ and at www.bonterraenergy.com.

Non-IFRS and Other Financial Measures

In this press release, the Company refers to certain financial measures and ratios that are not standardized measures recognized under IFRS® Accounting Standards and may not be comparable with similar measures disclosed by other issuers. These measures include “funds flow”, “funds flow per share”, “free funds flow yield”, “capital expenditures”, “adjusted net debt”, “adjusted net debt to EBITDA”, “field netback” and “cash netback” to analyze operating performance. Management uses these measures to assess operating performance, capital allocation, leverage and financial flexibility. Non-IFRS and other financial measures within this release may refer to forward-looking non-IFRS and other financial measures and are calculated consistently with the three and nine months ended September 30, 2026 reconciliations as outlined below.

Funds Flow and Funds Flow per Share

Funds flow is a non-IFRS financial measure defined as cash flow from operating activities, adjusted to exclude changes in non-cash working capital and decommissioning expenditures settled, to replace finance costs with interest expense, and to include investment income received and proceeds on sale of investments, where applicable. Management considers funds flow useful in assessing the Company’s ability to finance capital expenditures, repay debt and meet other capital requirements.

Funds flow per share is a non-IFRS ratio calculated by dividing funds flow by the weighted average number of basic or diluted shares outstanding for the period, as reported in the Company’s condensed consolidated interim financial statements. Management considers funds flow per share useful in assessing the Company’s ability to generate cash on a per-share basis.

Forecast 2027 funds flow per share is calculated consistently with the historical measure, using a forecast weighted average of 36.6 million diluted shares outstanding. This assumes that shares currently held in trust for the Company’s restricted share unit plan and deferred share unit plan are released to employees, officers and directors on vesting during 2027, and that there are no other material share issuances or repurchases.

The following is a reconciliation of funds flow to the most directly comparable IFRS measure, cash flow from operating activities, and the calculation of basic and diluted funds flow per share:

	Three months ended					Nine months ended
($ millions)	September 30, 2026		September 30, 2025			September 30, 2026		September 30, 2025
Cash flow from operating activities	19.1		8.3			75.6		68.0
Adjusted for:
Changes in non-cash working capital	5.3		6.1			4.0		0.7
Interest expense	(4.3)		(4.1)			(13.0)		(12.6)
Interest paid	7.8		7.7			16.5		10.2
Decommissioning expenditures	2.7		3.2			3.9		5.5
Investment income received	0.1		0.1			0.2		0.3
Funds flow	30.7		21.3			87.2		72.1
Funds Flow per Share
$ per share - basic	0.86		0.59			2.42		1.96
$ per share - diluted	0.83		0.58			2.35		1.93

Capital Expenditures

Capital expenditures is a non-IFRS financial measure calculated as the sum of exploration and evaluation expenditures and property, plant and equipment expenditures, as presented in the statement of cash flows. Management considers capital expenditures useful in assessing the Company’s investment in its development program and its ability to fund that program from funds flow. The most directly comparable IFRS measure is cash flow used in investing activities.

	Three months ended			Nine months ended
($ millions)	September 30, 2026	September 30, 2025		September 30, 2026	September 30, 2025
Comprised of:
Exploration and evaluation expenditures	0.4	0.4		2.0	0.8
Property, plant and equipment expenditures	14.9	14.4		77.7	52.8
Capital Expenditures	15.3	14.8		79.7	53.6

Free Funds Flow and Free Funds Flow per Share

Free funds flow is a non-IFRS financial measure calculated as funds flow plus proceeds on sale of property, less capital expenditures, acquisitions and decommissioning expenditures settled, as presented in the statement of cash flows. When this calculation results in a negative amount, it is referred to as a free funds flow deficiency. Management uses free funds flow to assess the funds available for future capital allocation decisions. Forecast free funds flow in the 2027 budget excludes acquisitions and dispositions.

Free funds flow per share is a non-IFRS ratio calculated by dividing free funds flow by the weighted average number of basic or diluted shares outstanding for the period, as reported in the Company’s condensed consolidated interim financial statements. Management considers free funds flow per share useful in assessing the funds available for capital allocation on a per-share basis.

The following is a reconciliation of free funds flow to funds flow and the calculation of basic and diluted free funds flow per share:

	Three months ended					Nine months ended
($ millions)	September 30, 2026		September 30, 2025			September 30, 2026		September 30, 2025
Funds flow	30.7		21.3			87.2		72.1
Adjusted for:
Capital expenditures	(15.3)		(14.8)			(79.7)		(53.6)
Acquisition	(4.2)		-			(4.2)		-
Proceeds on sale of property	-		0.3			-		2.0
Decommissioning expenditures	(2.7)		(3.2)			(3.9)		(5.5)
Free funds flow (deficiency)	8.5		3.6			(0.6)		15.0
Funds flow (deficiency) per Share
$ per share - basic	0.24		0.10			(0.02)		0.41
$ per share - diluted	0.23		0.10			(0.02)		0.40

Adjusted Net Debt, EBITDA and Adjusted Net Debt to EBITDA

Adjusted net debt is a non-IFRS financial measure calculated as bank debt and subordinated notes, plus current liabilities less current assets, excluding risk management contracts, the current portion of decommissioning liabilities and deferred consideration. Subordinated notes are included at face value, excluding unamortized issue costs.

EBITDA is a non-IFRS financial measure calculated as net earnings (loss), adjusted for unrealized risk management gains or losses, gains or losses on asset sales, deferred consideration, finance costs, share-based compensation, depletion and depreciation, exploration and evaluation expense, loss on debt extinguishment, and current and deferred income taxes.

Adjusted net debt to EBITDA is a non-IFRS ratio calculated as adjusted net debt divided by trailing twelve-month EBITDA.

Management uses these measures to assess the Company’s leverage and financial flexibility. For further information, refer to Note 10 of the Company’s unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2026.

The following is a summary of adjusted net debt and adjusted net debt to EBITDA, and a reconciliation of trailing twelve-month EBITDA to the most directly comparable IFRS measure, net earnings (loss):

($ millions)	September 30, 2026		December 31, 2025
Bank debt	42.1		40.7
Subordinated notes	132.9		135.7
Current liabilities	64.3		43.5
Current assets	(40.3)		(40.9)
Net debt	199.0		179.0
Risk management contracts	(12.5)		2.1
Decommissioning liabilities - current portion	(5.7)		(5.5)
Deferred consideration - current portion	(0.9)		(0.8)
Unamortized issue costs on subordinated notes	4.5		5.2
Adjusted Net Debt	184.4		180.0
Net loss	(3.0)		(17.1)
Adjustments to net loss:
Unrealized loss (gain) on risk management contracts	13.9		(1.3)
Gain on sale of property	-		(4.6)
Deferred consideration	(0.7)		(1.0)
Finance costs	22.5		22.3
Share-based compensation	3.3		2.5
Depletion and depreciation	91.4		101.6
Extinguishment of debt	-		11.6
Current income tax expense (recovery)	0.6		(1.7)
Deferred income tax expense (recovery)	(0.9)		(3.0)
EBITDA (trailing twelve months)	127.1		109.3
Adjusted net debt to EBITDA ratio	1.5		1.6

Field and Cash Netback

Field netback is a non-IFRS financial measure calculated as revenue plus realized gains (or less realized losses) on risk management contracts, less royalties and operating expenses. Field netback per BOE is a non-IFRS ratio calculated as field netback divided by total barrels of oil equivalent produced during the period. Management uses field netback and field netback per BOE to evaluate the Company’s ability to generate a cash margin on a unit-of-production basis.

Cash netback is a non-IFRS financial measure calculated as field netback plus administrative income and investment income received, less interest expense, general and administrative expense and current income tax expense. Cash netback per BOE is a non-IFRS ratio calculated as cash netback divided by total barrels of oil equivalent produced during the period. Management uses cash netback and cash netback per BOE to evaluate the Company’s ability to generate cash flow from continuing corporate activities on a unit-of-production basis.

Field and cash netback are calculated on per unit basis as follows:

	Three months ended					Nine months ended
($ millions)	September 30, 2026		September 30, 2025			September 30, 2026		September 30, 2025
Oil and gas sales	89.5		55.2			253.2		190.0
Realized gain (loss) on risk management contracts	(7.1)		0.5			(23.7)		1.4
Royalties	(15.4)		(7.1)			(37.4)		(25.4)
Production costs	(28.5)		(21.8)			(77.6)		(72.1)
Field Netback	38.5		26.8			114.5		93.9
Office and administration	(1.9)		(1.2)			(4.6)		(4.1)
Employee compensation	(2.5)		(1.7)			(7.5)		(5.3)
Administrative and investment income	0.1		0.1			0.3		-
Interest expense	(4.2)		(4.1)			(12.9)		(12.1)
Current income (tax) recovery	0.7		1.4			(2.6)		(0.3)
Cash Netback	30.7		21.3			87.2		72.1
Barrel of oil equivalent (BOE)	1,584,444		1,330,294			4,507,429		4,258,777
Field Netback ($ per BOE)	24.34		20.16			25.39		22.07
Cash Netback ($ per BOE)	19.40		16.03			19.34		16.92

Free Funds Flow Yield

Free funds flow yield is a non-IFRS ratio calculated as forecast 2027 free funds flow divided by the Company’s market capitalization. Market capitalization is calculated as a forecast weighted average of 36.6 million diluted shares outstanding multiplied by $6.13, the closing price of the Company’s common shares on the Toronto Stock Exchange on November 11, 2026. The forecast share count is based on shares issued at September 30, 2026, including shares held in trust to settle restricted share units, and assumes no material share issuances or repurchases in 2027. Management uses free funds flow yield to assess the free funds flow expected to be generated by the Company relative to its market value.

Information Regarding Product Types

References to natural gas and NGLs in this press release refer to conventional natural gas and natural gas liquids, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. The Company’s average production for the seven most recent quarters and references to light crude oil, NGLs and conventional natural gas consist of the product types shown below, using a conversion ratio of 6 mcf of natural gas to one barrel of oil equivalent.

	2026			2025
	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Average daily production
Light oil (bbls/d)	6,933	6,841	6,228	6,274	6,051	6,794	6,546
NGLs (bbls/d)	1,738	1,695	1,540	1,507	1,353	1,508	1,679
Conventional natural gas (mcf/d)	51,306	49,750	46,173	44,839	42,336	48,584	46,390
Total (BOE/d)	17,222	16,828	15,463	15,254	14,460	16,399	15,957

• 2026 annual average production, at the midpoint of the guidance range, is anticipated to be comprised of approximately 40% light crude oil, 10% NGLs and 50% conventional natural gas.
• 2027 annual average production, at the midpoint of the guidance range, is anticipated to be comprised of approximately 43% light crude oil, 9% NGLs and 48% conventional natural gas.
• Charlie Lake production for Q3 2026 comprised approximately 39% light crude oil, 5% NGLs and 56% conventional natural gas.
• Cardium production for Q3 2026 comprised approximately 42% light crude oil, 12% NGLs and 46% conventional natural gas.
• Montney production for Q3 2026 comprised approximately 32% light crude oil, 15% NGLs and 53% conventional natural gas.

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: the Company’s 2026 financial and operating guidance relating to production, oil and liquids weighting and capital expenditures; the Company’s 2026 priorities and outlook, including the fourth quarter 2026 capital program and the Company’s expectation to enter 2027 with one Bonanza Charlie Lake well drilled and uncompleted; the 2027 Budget and 2027 financial and operating guidance relating to production, oil and liquids weighting, production and liquids growth, funds flow, funds flow per share, free funds flow, free funds flow per share, free funds flow yield, capital expenditures, asset retirement obligations, adjusted net debt, adjusted net debt to EBITDA and pricing; targeted shareholder returns; the expected timing of enactment of the proposed Productivity Mega Deduction and its anticipated impact on the Company’s current income taxes and planned delineation capital; anticipated 2027 well counts and timing; the number and location of wells to be brought on production; the timing of drilling, completion and tie-in of wells; expectations regarding the allocation of base development and exploratory capital, including by asset area; development and infrastructure planning at Bonanza Charlie Lake and the number of derisked drilling locations; development, delineation and infrastructure plans in the Company’s core areas; the anticipated benefits of the Bonanza Charlie Lake Tuck-in; the expected results of delineation activities at Bonanza Charlie Lake and Wembley Montney, including the addition of drilling inventory, the timing of related production and the need for additional infrastructure investment; expected well performance, decline profiles and payout, including in respect of the “16-11” well; the incorporation of operational and technical findings into future Wembley Montney drilling and completion designs; the sequencing of Pembina Cardium drilling and the sustainability of Cardium base production; exploration and development activities; expectations relating to wells planned to come onstream; anticipated production by type; plans relating to repayment of indebtedness and, the Company’s year-end 2027 adjusted net debt target and the allocation of free funds flow to debt repayment and opportunistic share buybacks; abandonment and reclamation activities; the Company’s risk management program, including hedges in place for 2027; the sensitivity of funds flow to changes in commodity prices and foreign exchange rates; 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 other such matters.

The Company’s 2026 and 2027 guidance is based on a number of assumptions, including the successful execution of the Company’s drilling, completion and tie-in program, well performance consistent with internal expectations, the availability of third-party processing and pipeline capacity, commodity prices that support the planned pace of capital activity, the enactment of the proposed Productivity Mega Deduction substantially as proposed, and the absence of material changes to royalty regimes and regulatory requirements. Should the Productivity Mega Deduction not be enacted, the Company may reassess its 2027 guidance. The 2027 guidance also assumes the commodity price and foreign exchange assumptions set out in this release and a forecast weighted average of 36.6 million diluted shares outstanding. Forecast free funds flow yield assumes a recent closing price of the Company’s common shares.

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; delays or cost overruns in drilling, completion, tie-in and infrastructure projects; general economic conditions; industry conditions; geopolitical events, including conflict in the Middle East and its effect on global crude oil supply and prices; the impact on the Canadian energy industry of U.S. tariffs, changes to international trade agreements or the potential imposition of tariffs or other protectionist economic policies by the Canadian federal or provincial governments; applicable environmental, taxation and other laws and regulations as well as how such laws and regulations may limit growth or operations within the oil and gas industry; changes to royalty regimes; changes to proposed tax legislation, including the Productivity Mega Deduction not being enacted, being enacted in a form different from that proposed, or being enacted later than anticipated; the impact of climate-related financial disclosures on financial results; the ability of the Company to raise capital, maintain its syndicated bank facility, including the outcome of semi-annual borrowing base redeterminations, and refinance indebtedness upon maturity; the effect of weather conditions on operations and facilities; the existence of operating risks; uncertainty in well results, including in delineation areas; the availability of third-party infrastructure and processing capacity; the success of integrating acquired assets; 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; the Board revising the Budget; increased competition; stock market volatility and fluctuations in the price of the Company’s common shares; credit risks; climate change risks; cyber security; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors are not exhaustive. Readers are encouraged to review the material risks discussed in the Company’s latest annual information form under the heading “Risk Factors”.

In addition, to the extent that any forward-looking information presented herein constitutes future-oriented financial information or financial outlook, as defined by applicable securities legislation, such information has been approved by management of the Company and has been presented to provide management’s expectations used for budgeting and planning purposes and for providing clarity with respect to the Company’s strategic direction based on the assumptions presented herein and readers are cautioned that this information may not be appropriate for any other purpose.

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 therefrom. 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” 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; “BCF” refers to billion 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.

References in this press release to peak rates, initial production rates, test rates and other short-term production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which wells will commence production or decline thereafter and are not indicative of long-term performance or of ultimate recovery. Readers are cautioned not to place undue reliance on such rates when evaluating aggregate production or future performance. Such results should be considered preliminary.

Numerical Amounts

All amounts in this press release are stated in Canadian dollars unless otherwise specified. 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.

A photo accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/21b9c3e0-0180-4855-8051-757b1334707e