Bonterra Energy Announces 2023 Reserves and Provides Operational Update

CALGARY, AB, Feb. 13, 2024 /CNW/ - Bonterra Energy Corp. (TSX: BNE) ("Bonterra" or the "Company") is pleased to announce the summary results of its independent reserve report (the "Sproule Report") prepared by Sproule Associates Limited ("Sproule") with an effective date of December 31, 2023, and provide an operational update on key fourth quarter highlights and recent activities. The Company has not released its audited 2023 financial results, and therefore the financial figures provided herein are estimates and are unaudited.  

The following provides a summary of specific details from the Sproule Report, which was created following the guidelines, criteria, and methodologies outlined 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"). Further reserves-related information, as mandated by NI 51-101, will be incorporated into Bonterra's Annual Information Form, to be submitted on the Company's profile at https://www.sedarplus.ca  no later than March 31, 2024.

2023 RESERVES & OPERATIONAL HIGHLIGHTS

• Annual  production averaged 14,204 BOE per day¹ in 2023, representing a six percent increase over 2022, and exceeded Bonterra's previously stated 2023 guidance range of 13,500 and 13,700 BOE per day.
• Capital investments totaled approximately $126.5 million² during 2023 and included the drilling of Bonterra's first exploratory Montney well while staying within the original budget. The Company drilled 52 gross (41.2 net) development wells in 2023 and completed, equipped, and tied-in 48 gross (37.6 net) development wells. The four remaining wells are expected to be placed on production in the first quarter of 2024.  
• Production costs of approximately $13.37 per BOE² in Q4 2023 were 20 percent lower than $16.61 per BOE in Q3 2023, resulting in annual average production costs of $16.02 per BOE². This quarter-over-quarter per unit cost decrease was largely due to the impact of increased production from new wells coming on stream in Q4 2023, combined with fewer well workovers in Q4. 
• A targeted 2023 capital program resulted in year-end proved developed producing ("PDP") reserves of 32.8 million BOE (59 percent oil and liquids), total proved ("TP") reserves of 80.1 million BOE (62 percent oil and liquids), and total proved plus probable ("TPP") reserves of 100.7 million BOE (62 percent oil and liquids). On a year-over-year basis, TP and TPP reserves remained relatively unchanged.
• TP represented 80 percent of total TPP in 2023, consistent with 80 percent in 2022, showcasing the predictable and low-risk nature of Bonterra's asset base.
• Net present value of future net revenue discounted at 10 percent (before tax) for TPP totaled $1.4 billion, while TP totaled $1.0 billion and PDP totaled $557.3 million.
• Future Development Capital ("FDC") for TP is forecast to be $716 million, an increase of eight percent or $55 million compared to 2022 TP FDC of $660 million, due primarily to inflation.
• Recycle ratio¹ including FDC of 1.0 times on TP reserves, 1.1 times on TPP reserves and a recycle ratio excluding FDC of 1.4 times on TP reserves and 1.6 on TPP reserves.
• Reserve Life Index ("RLI")² for TPP, TP, and PDP of approximately 19.4 years, 15.5 years and 6.3 years, respectively (based on 2023 average production of 14,204 BOE per day), providing a lengthy development runway for Bonterra's future. 

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1 2023 volumes comprised of 7,209 bbl/d light and medium crude oil, 1,359 bbl/d NGLs and 33,814 mcf/d of conventional natural gas.

2 All 2023 financial amounts are unaudited. See advisories.

Summary of Gross Oil and Gas Reserves as of December 31, 2023

	Light and Medium Crude Oil		Conventional Natural Gas	Natural Gas Liquids	Oil Equivalent	Future Development Capital
	(MBbl)		(MMcf)	(MBbl)	(MBoe)	($000s)
Proved
Developed Producing	16,475		79,677	3,008	32,763	-
Developed Non-producing		2,485	13,626	501	5,257	8,525
Undeveloped		23,245	91,458	3,633	42,121	707,017
Total Proved	42,205		184,761	7,142	80,141	715,542
Total Probable	10,950		49,976	1,827	20,606	3,951
Total Proved plus Probable	53,155		231,737	8,969	100,747	719,493

Reconciliation of Company Gross Reserves by Principal Product Type as of December 31, 2023

	Light & Medium Crude 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, 2022	43,174	53,574	184,352	230,520	6,802	8,496	80,702	100,490
Extensions & Improved Recovery	4,469	5,829	16,768	21,477	756	967	8,019	10,376
Dispositions	-	-	(203)	(256)	(11)	(13)	(44)	(56)
Technical Revisions	(3,053)	(3,908)	(4,113)	(7,975)	79	2	(3,658)	(5,234)
Economic Factors	246	290	299	313	12	13	307	356
Production	(2,631)	(2,631)	(12,342)	(12,342)	(496)	(496)	(5,185)	(5,185)
Closing Balance, December 31, 2023	42,205	53,154	184,761	231,737	7,142	8,969	80,141	100,747

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1Recycle 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, see "Cautionary Statements."

2 "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 Net Present Values of Future Net Revenue as of December 31, 2023

($M)	Net Present Value Before Income Taxes Discounted at (% per Year)
Reserves Category:	0 %	5 %	10 %	15 %
Proved
Producing	899,090	692,144	557,339	468,130
Non-producing	141,106	99,918	76,585	61,736
Undeveloped	1,018,596	629,647	411,865	280,415
Total Proved	2,058,792	1,421,710	1,045,789	810,282
Probable	799,896	483,731	337,012	256,000
Total Proved plus Probable	2,858,688	1,905,441	1,382,801	1,066,282

FUTURE DEVELOPMENT CAPITAL, F&D COSTS⁶ AND RECYCLE RATIOS⁶

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 because of development activities, acquisition and disposition activities, changes in capital cost estimates based on improvements in well design and performance, changes in service costs and changes to cost estimates for capital activities that do not directly drive additions in reserves or production.

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
	2023		2022	2021	3 Yr Avg4		2023	2022	2021	3 Yr Avg4
FD&A Costs per BOE 1,2,3,6
Including FDC	$39.08		$24.85	$6.90	$21.27		$34.16	$23.34	$5.64	$19.36
Excluding FDC	$27.09		$10.47	$8.68	$13.71		$23.24	$10.02	$8.23	$12.68
F&D Costs per BOE 1,2,3,6
Including FDC	$39.08		$24.85	$6.90	$21.27		$34.16	$23.34	$5.64	$19.36
Excluding FDC	$27.09		$10.47	$8.68	$13.71		$23.24	$10.02	$8.23	$12.68
Recycle Ratio 2,5,6
F&D (including FDC)	1.0		1.8	4.3	2.3		1.1	1.9	5.3	2.7
F&D (excluding FDC)	1.4		4.3	3.4	3.0		1.6	4.5	3.6	3.2

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, acquisitions and disposals, and 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, see "Cautionary Statements."  On a BOE basis, Bonterra's (unaudited) field netback used in the above calculations are as follows: 2023  - $37.01; 2022 - $44.93; 2021 - $29.62; Three year weighted average - $37.31.
(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.

OPERATIONAL UPDATE

Building on a highly successful capital program during the first nine months of 2023, Bonterra invested capital of $14 million during the last quarter of the year which was allocated to bring four gross (2.3 net) new development wells onto production, all of which were drilled in the third quarter of 2023, along with the completion of the Company's first exploratory Montney well.

Subsequent to year-end 2023, the Company has remained focused on the execution of its 2024 capital program, budgeted at $90 to $100 million. To date in 2024, Bonterra has drilled five gross operated (4.8 net) wells, which are expected to be completed, equipped and placed on production by the end of the Q1 2024, along with four gross operated (3.6 net) wells that were drilled in Q4 2023.

Bonterra is pleased to reiterate its previously announced 2024 guidance:

• Capital expenditure budget ranging from $90 to $100 million, allocated approximately 66 percent to drilling and completion activities; approximately 24 percent to non-operated activities, infrastructure and facilities; with the balance to land and ARO;
• 2024 production volumes are expected to average between 13,800 and 14,200 BOE per day¹, weighted approximately 60 percent to oil and liquids;
• Based on pricing (assuming US$73.00 WTI) and production assumptions for 2024, as outlined fully in the Company's December 13, 2023 press release, Bonterra anticipates generating approximately $125 to $130 million in corporate funds flow^2,3 for the year. As a result, the Company anticipates generating free funds flow³ of approximately $20 to $25 million, a portion of which could be allocated to debt reduction, contributing to a targeted year-end net debt to EBITDA³ of 0.8 to 0.9 times.

Bonterra remains committed to prioritizing free funds flow³ generation with its 2024 Budget, which affords capital allocation flexibility to further strengthen the balance sheet and achieve modest production growth. This approach supports the Company's ultimate goal of implementing a sustainable dividend once specific metrics are achieved and commodity prices are conducive. As previously communicated, these required metrics include a targeted net debt³ range of $135 to $145 million and a net debt to EBITDA ratio³ of under 1.0 times. Should low commodity prices persist, the Company intends to maintain its focus on responsibly managing the balance sheet and enhancing financial flexibility.

Certain financial and operating information included in this press release, such as production information and F&D costs, are based on estimated unaudited financial results for the quarter and year ended December 31, 2023 and are subject to the same limitations as discussed under Forward Looking Statements set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2023 and changes could be material.

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1 2024 volumes are anticipated to be comprised of 6,766 bbl/d light and medium crude oil, 1,428 bbl/d NGLs and 34,835 mcf/d of conventional natural gas based on a midpoint of 14,000 BOE/d.

2 Funds Flow is estimated using a Canadian realized oil price of $94.83/bbl, a realized natural gas price of $4.07/mcf; and a realized NGL price of CAD $65.02/bbl.

3 Non-IFRS Measure. See "Cautionary Statements" below.

MONTNEY ASSET UPDATE

Bonterra has continued to advance development of its significant Montney discovery at Valhalla following the drilling of the Company's first Montney test well in Q3 2023 at 04-03-074-6W6 (the "04-03 Well"), located on a block of 100 percent owned lands covering 45 sections.

As outlined in the Company's December 13, 2023 press release, Bonterra was pleased with preliminary test results of the 04-03 Well which achieved a peak daily rate of 753 BOE per day (469 BBL per day and 1,707 MCF per day) during the flow test, despite flow rates being restricted. The Company has secured natural gas egress through third party infrastructure and expects to flow the Montney well in the second quarter of 2024, with plans to consider a second well. The results of Bonterra's first Montney well support continued testing and delineation in the area, although the Company will take a disciplined approach to align the pace of future development with available egress solutions. This exciting development could position the Company's Valhalla asset to emerge as a new core area offering optionality for shareholders and an expanded future development runway for Bonterra.

ABOUT BONTERRA

Bonterra Energy Corp. is a conventional oil and gas corporation forging a grounded path forward for Canadian energy. Operations include a large, concentrated land position in Alberta's Pembina Cardium, one of Canada's largest oil plays. Bonterra's liquids-weighted Cardium production provides a foundation for implementing a return of capital strategy over time, which is focused on generating long-term, sustainable growth and value creation for shareholders. An emerging Montney exploration opportunity is expected to provide enhanced optionality and an expanded potential development runway for the future. Our shares are listed on the Toronto Stock Exchange under the symbol "BNE" and we invite stakeholders to follow us on LinkedIn and X (formerly Twitter) for ongoing updates and developments.

Use of Non-IFRS Financial Measures

Throughout this release the Company uses the terms "funds flow", "free funds flow", "net debt", "net debt to EBITDA ratio", "field netback" and "cash 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 cash flow provided by operating activities excluding effects of changes in non-cash working capital items and decommissioning 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, subordinated debentures and subordinated term debt. Net debt to EBITDA ratio is defined as net debt at the end of the period divided by EBITDA for the trailing twelve months. EBITDA is defined as net earnings excluding deferred consideration, finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and unrealized gain or loss on risk management contracts. Field netback is defined as revenue minus royalties, realized gain or loss on risk management contracts and production costs. Cash netback is defined as field netback less interest expense, general and administrative expense and current income tax expense divided by total BOEs for the period.

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, 2023, 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 or before March 31, 2024. 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".

This press release contains metrics commonly used in the oil and natural gas industry, such as "reserve life index", "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.

Reserve life index is an  index  reflecting  the  theoretical  production  life  of  a  property  if  the remaining reserves were to be produced out at current production rates. The index is calculated by dividing the reserves in the selected reserve category at a certain date by the annualized fourth quarter production from the preceding twelve month period. Recycle ratio is defined as field netback per BOE divided by F&D costs on a per BOE basis.

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: the Company's 2024 budget and 2024 financial and operating guidance relating to production, funds flow, free funds flow, capital expenditures, operating costs, asset retirement obligations, netback, indebtedness and pricing; expectations relating to debt repayment and the payment of dividends; abandonment and reclamation activities; risk management strategy; 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; maintenance of existing customer, supplier and partner relationships; 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 or maintain its syndicated bank facility; 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" 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.

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

SOURCE Bonterra Energy Corp.

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