Bonterra Energy Corp. Announces Second Quarter 2021 Results

CALGARY, AB, Aug. 11, 2021 /CNW/ - Bonterra Energy Corp. (www.bonterraenergy.com) (TSX: BNE) ("Bonterra" or the "Company") today announces its operating and financial results for the three and six month periods ended June 30, 2021. The related unaudited condensed financial statements and notes, as well as management's discussion and analysis ("MD&A"), are available on SEDAR at www.sedar.com and on Bonterra's website at www.bonterraenergy.com. 

HIGHLIGHTS

	Three months ended		Six months ended
As at and for the periods ended ($ 000s except for $ per share and $ per BOE)	June 30,  2021	June 30, 2020	June 30,  2021	June 30, 2020
FINANCIAL
Revenue - realized oil and gas sales	59,163	22,171	107,957	60,726
Funds flow ^(1)	23,105	4,185	39,697	18,855
Per share - basic	0.69	0.13	1.18	0.56
Per share - diluted	0.67	0.13	1.16	0.56
Cash flow from operations	18,874	4,429	33,619	26,902
Per share - basic	0.56	0.13	1.00	0.81
Per share - diluted	0.55	0.13	0.98	0.81
Net earnings (loss)^(2)	157,354	(5,954)	155,670	(290,607)
Per share - basic	4.68	(0.18)	4.63	(8.70)
Per share - diluted	4.55	(0.18)	4.53	(8.70)
Capital expenditures	7,607	104	31,068	21,845
Total assets			948,260	732,462
Net debt^(3)			319,310	299,445
Working capital deficiency			273,141	299,445
Long-term debt			46,169	-
Shareholders' equity			353,431	212,342
OPERATIONS
Light oil                                - barrels (bbl) per day	7,370	5,553	7,103	6,306
- average price ($ per bbl)	71.49	33.31	66.84	42.47
NGLs                                     - bbl per day	996	1,104	1,011	1,052
- average price ($ per bbl)	35.59	12.14	35.59	15.50
Conventional natural gas - MCF per day	26,057	21,142	25,184	22,503
- average price ($ per MCF)	3.37	2.14	3.40	2.20
Total barrels of oil equivalent per day (BOE)^(4)	12,709	10,181	12,311	11,108

^(^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 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 plus long-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 methodprimarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Q2 2021 FINANCIAL & OPERATING SNAPSHOT

• Averaged 12,709 BOE per day of production in Q2 2021, 25 percent higher than in Q2 2020, and averaged 12,311 BOE per day in the first six months of 2021, an 11 percent increase over the comparative period the prior year, reflecting a successful drilling program that re-commenced in the fourth quarter of 2020, along with the reactivation of wells that had been voluntarily shut-in due to low commodity prices.
• Realized oil and gas sales increased 167 percent over Q2 2020 to total $59.2 million in Q2 2021, and in the first six months of 2021, increased by 78 percent over the same period in 2020 with increases primarily driven by higher realized crude oil prices and growing production volumes.
• Generated funds flow[1] of $23.1 million ($0.67 per fully diluted share) in Q2 2021, a 452 percent increase from $4.2 million ($0.13 per fully diluted share) in Q2 2020 while funds flow¹ in the first half of 2021 totaled $39.7 million ($1.16 per fully diluted share) representing an increase of 111 percent from the same period of 2020.
• Cost savings remained a priority across the organization, with Bonterra reducing Q2 2021 production costs per unit to $14.98 per BOE, four percent lower than the preceding quarter.
• Drilling, completion and equipping costs in the first half of 2021 decreased by approximately 35 percent year-over-year to average $2.1 million per well.
• Field netbacks¹ averaged $27.59 per BOE in Q2 2021 and $26.12 per BOE in the first half of 2021, representing increases of 194 percent and 83 percent, respectively, with the increases reflecting significantly higher per unit revenue offset by realized losses on risk management contracts and increased per unit royalty expenses.
• Capital expenditures totaled $31.0 million in the first half of 2021 including $7.6 million invested in Q2 2021. Of the first half capital, $24.6 million was directed to the drilling of 16 gross (15.9 net) wells and to complete, equip, tie-in and place on production 20 gross (19.7 net) wells, with approximately $6.4 million spent primarily on related infrastructure and recompletions. Of the completed and equipped wells, four were drilled late in 2020.
• Net debt¹ totaled $319.3 million as at June 30, 2021, a $3.7 million increase from year-end 2020, reflecting the impact of a more active capital program that is designed to return production to pre-COVID-19 levels. As at June 30, 2021, Bonterra had $244 million drawn on the $265 million syndicated bank facility.

QUARTER IN REVIEW

Since the beginning of 2021, the Company has benefitted from increasing crude oil and natural gas prices as stability returns to global commodity markets following severe volatility through most of 2020. During the second quarter of 2021, Bonterra introduced new production volumes into a much higher commodity price environment which resulted in realized average oil prices of $71.49 per bbl in the quarter, an increase of 115 percent over Q2 2020 prices. In addition, the Company's average realized NGL price was $35.59 per bbl, or 193 percent higher than the same period in 2020, while the average realized natural gas price of $3.37 per mcf was 57 percent higher. This price improvement helped to drive meaningful growth in netbacks in the second quarter of 2021, with field and cash netbacks of $27.59 per BOE and $19.98 per BOE, respectively, compared to $9.40 per BOE and $4.52 per BOE in Q2 2020, respectively.  Bonterra will continue to regularly monitor commodity price changes and funds flow with the primary objective of reducing bank debt while continuing to add production and grow reserves value.

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^1	"Funds Flow", "Field Netback" and "Net Debt" are not recognized measures under IFRS. See "Cautionary Statements" below.

In concert with realizing higher prices during the second quarter of 2021, Bonterra also benefited from stronger production volumes, which averaged 12,709 BOE per day, an increase of seven percent over the preceding quarter, and 25 percent over the same period of 2020. Throughout the first half of 2021, the Company invested a total of $31.0 million of capital, or approximately 48 percent of the lower end of its full year capital budget range, with $24.6 million allocated to drilling, completion, equip and tie-in activities. This resulted in 16 gross (15.9 net) wells being drilled and 20 gross (19.7 net) wells being completed, equipped, tied-in and placed on production, with four of the completed and equipped wells having been drilled late in 2020. Approximately $6.4 million was allocated primarily to related infrastructure and recompletions.

As a result of the Company's 2021 capital program, wells that had been drilled, completed and brought on production through the first quarter of the year benefited Bonterra by contributing volumes for a full quarter in Q2 2021. The majority of the production volumes coming from new wells were brought online through March and April of 2021. These higher volumes helped reduce per unit production costs in the quarter, which averaged $14.98 per BOE compared to $15.60 per BOE in the previous quarter despite higher absolute dollar costs, and were $13.84 per BOE in Q2 2020 which reflects the very low levels of activity in that period.

In addition to undertaking new drilling to date in 2021, Bonterra also remained committed to efficiently managing decommissioning liabilities, having abandoned 137.3 net wells during the first six months of this year, supported by the Alberta Site Rehabilitation Program ("SRP"). As Bonterra continues to advance its abandonment program through the remainder of this year and next, it is estimated that a further 170.5 net wells with no deemed future potential can be abandoned.

OUTLOOK

During the third quarter of 2021, approximately eight gross (6.9 net) operated wells are expected to be drilled and completed as Bonterra continues to execute its capital expenditure program. In light of the successful execution of the capital program to date, combined with favourable price forecasts and positive well performance, the Company anticipates average production for 2021 will be within its previously announced annual guidance range of 12,800 to 13,200 BOE per day.

As part of Bonterra's ongoing efforts to diversify commodity prices and protect future cash flows, the Company has put in place physical delivery sales and risk management contracts to the end of June 30, 2022, details of which are included in Note 12 to the financial statements. Through subsequent quarters, Bonterra can continue to participate in upward oil price movements while mitigating market volatility and locking-in economics given approximately 30 percent of forecast volumes are hedged.

Financial discipline and cost control continue to be priorities for Bonterra, and the Company remains committed to reducing bank debt and strengthening the balance sheet, while continuing to add reserve value, particularly into rising commodity prices. Bonterra believes the Company is strategically positioned to drive profitable growth through this period of improving oil and natural gas markets by prudently developing its high-quality, light oil weighted asset base and directing excess funds flow to a combination of debt repayment plus modest growth. The Company continues to prioritize environmental, social and governance ("ESG") initiatives, including being a positive and meaningful contributor to the economic and social success of the communities where it operates in central Alberta, upholding a responsible abandonment and reclamation program, and maintaining stringent safety measures for all employees, contractors and partners.

Bonterra Energy Corp. is a conventional oil and gas corporation with operations in Alberta, Saskatchewan 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.

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; 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 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" 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.

George F. Fink, CEO, Robb D. Thompson, CFO, Adrian Neumann, COO, Telephone: [phone], Fax: [phone], Email: [email protected]

Related Links

http://www.bonterraenergy.com/