CALGARY, AB, Aug. 13, 2024 /CNW/ - Bonterra Energy Corp. (TSX: BNE) ("Bonterra" or the "Company") is pleased to announce its financial and operating results for the three and six month periods ended June 30, 2024. The related unaudited condensed financial statements and notes for the second quarter, as well as management's discussion and analysis ("MD&A"), are available on SEDAR+ at www.sedarplus.ca and on Bonterra's website at www.bonterraenergy.com.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
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Three months ended
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Six months ended
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As at and for the three months ended
($000s except $ per share and $ per BOE)
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June 30,
2024
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June 30,
2023
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June 30,
2024
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June 30,
2023
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FINANCIAL
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Revenue - realized oil and gas sales
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72,465
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75,606
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141,054
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152,869
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Funds flow(1)
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31,484
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34,799
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58,502
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64,141
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Per share - basic
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0.84
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0.94
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1.57
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1.73
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Per share - diluted
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0.84
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0.93
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1.57
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1.72
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Cash flow from operations
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33,180
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33,854
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54,834
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57,872
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Per share - basic
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0.89
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0.91
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1.47
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1.56
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Per share - diluted
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0.89
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0.91
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1.47
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1.55
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Net earnings(2)
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7,310
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8,844
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8,158
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16,484
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Per share - basic
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0.20
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0.24
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0.22
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0.44
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Per share - diluted
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0.20
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0.24
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0.22
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0.44
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Capital expenditures
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21,619
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16,116
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54,543
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76,339
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Oil and gas property acquisition(2)
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-
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-
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24,234
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-
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Total assets
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984,065
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962,021
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Net debt(3)
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172,622
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173,299
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Bank debt
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41,889
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35,506
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Shareholders' equity
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537,498
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498,449
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OPERATIONS
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Light oil
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-bbl per day
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6,571
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7,282
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6,596
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7,175
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-average price ($ per bbl)
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102.09
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93.21
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95.50
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94.44
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NGLs
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-bbl per day
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1,418
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1,248
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1,443
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1,202
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-average price ($ per bbl)
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45.08
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43.97
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45.58
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49.02
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Conventional natural gas
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-MCF per day
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37,519
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32,286
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37,057
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31,869
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-average price ($ per MCF)
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1.64
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3.01
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2.14
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3.39
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Total barrels of oil equivalent per day (BOE)(4)
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14,242
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13,911
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14,216
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13,689
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(1)
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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.
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(2)
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On March 1, 2024, the Company acquired the Charlie Lake Assets for cash consideration of $23.6 million and $0.3 million in non-core mineral rights, including closing adjustments. The Charlie Lake Assets have been accounted for as an asset acquisition, which resulted in an increase of $24.2 million in PP&E and the assumption of $0.3 million in decommissioning liabilities.
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(3)
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Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-term bank debt, subordinated debentures and subordinated term debt.
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(4)
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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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FINANCIAL & OPERATING HIGHLIGHTS
- Production averaged 14,242 BOE per day in Q2 2024, in line with the previous quarter, supported by volumes brought online from new wells drilled in Q1 2024, despite shutting in approximately 650 BOE per day largely due to planned gas plant turnarounds in the quarter. The Company continues to estimate annual production will remain within previously announced 2024 production guidance of 13,800 to 14,200 BOE per day1.
- Funds flow2 totaled $31.5 million ($0.84 per fully diluted share) in Q2 2024, 17 percent higher than the $27.0 million ($0.72 per fully diluted share) generated in Q1 2024, reflecting higher realized oil and gas sales of $72.5 million which benefitted from a 15 percent increase in crude oil prices over the previous quarter, along with lower production costs.
- Field netbacks2 averaged $32.05 per BOE in Q2 2024, while cash netbacks averaged $24.29 per BOE in the period, with the impact of stronger crude oil pricing and decreased production costs partially offset by higher royalty costs and lower realized natural gas prices compared to the previous quarter.
- Production costs averaged $16.18 per BOE in Q2 2024, a ten percent decrease over Q1 2024 and four percent lower than Q2 2023. This was achieved primarily due to lower levels of well maintenance occurring during spring break-up along with a decrease in power rates, which declined 51 percent in the first half of 2024 compared to the same period in 2023.
- Capital expenditures for the first six months of 2024 totaled $54.5 million ($21.6 million during Q2 2024), with $39.1 million directed to drilling 15 gross (14.2 net) operated wells and completing, equipping, tying-in and placing on production 15 gross (14.0 net) operated wells, of which four gross (3.6 net) of those wells were drilled in Q4 2023. The remaining four gross (3.8 net) operated wells were brought on during the third quarter; while $15.4 million was invested in infrastructure, recompletions and to drill, complete and equip a water disposal well for Montney production.
- Successfully integrated the new Charlie Lake asset that was acquired during Q1 2024, with two (1.8 net) of Bonterra's 15 operated wells drilled being located within the Charlie Lake area, having an average gross drilling cost of $2.4 million per well. These wells were completed in July 2024 and are currently at the initial stage of flow back.
- Net debt2 totaled $172.6 million at quarter-end, a five percent decrease from Q1 2024, and $0.7 million lower than June 30, 2023, primarily due to a 29 percent reduction in capital expenditures in the first six months of 2024 compared to 2023, partially offset by the $23.6 million cash consideration for the Charlie Lake asset acquisition, which contributed to a net debt to EBITDA ratio of 1.0 times at the end of Q2 2024.
- On April 30, 2024, Bonterra completed the renewal of its $110 million bank facility, which is structured as a normal course, reserve-based credit facility available on a revolving basis through April 30, 2025, with bi-annual borrowing base redeterminations and a maturity of April 30, 2026.
- The Company intends to continue focusing on net debt reduction and has hedged over 30 percent of forecasted oil and natural gas production over the next nine months to protect cash flow.
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_________________________
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1 2024 annual average volumes are anticipated to be comprised of approximately 6,850 bbl/d light and medium crude oil, 1,450 bbl/d NGLs and 35,000 mcf/d of conventional natural gas based on a midpoint of 14,000 BOE/d.
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2 Non-IFRS measure. See advisories later in this press release.
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FIRST HALF 2024 PERFORMANCE
As Bonterra continued to pursue the profitable development of its high-quality, light oil weighted asset base through the first half of 2024, the second quarter was another successful period in which all key performance metrics, including production volumes, tracked 2024 guidance. Production in the quarter averaged 14,242 BOE per day, two percent higher than the same period in 2023, despite having approximately 650 BOE per day shut-in due to planned major gas plant turnarounds that are required every five years. This volume growth reflects the combination of a successful, front-end loaded 2024 capital program, incremental volumes from the strategic Charlie Lake asset acquisition and the tie-in of Bonterra's 4-3 Montney well.
Higher value light oil and NGL production represented 92 percent of the Company's total realized oil and gas sales in the second quarter, despite being only 56 percent of production volumes. This is attributable to a ten percent increase in realized light oil prices over Q2 2023, and a 15 percent increase over Q1 2024, offset by realized natural gas prices that were 46 percent and 38 percent lower than the same respective periods. The Company's production costs were $16.18 per BOE, reflecting lower well maintenance costs and lower power rates, along with a continued focus on cost controls. The combination of higher pricing and lower costs drove field and cash netbacks1 in Q2 2024 to average $32.05 and $24.29 per BOE, respectively, with funds flow totaling $31.5 million ($0.84 per fully diluted share) and net income remaining positive at $7.3 million, or $0.20 per diluted share. Bonterra has continued to demonstrate full-cycle profitability with Q2 2024 representing the 13th consecutive period of positive net income.
Continued Focus on Balance Sheet Strength
Net debt at the end of the second quarter totaled $172.6 million, $0.7 million lower than the same period in 2023 due largely to a 29 percent decrease in capital spending in the first six months of 2024, partially offset by a draw on the bank line to fund the Charlie Lake acquisition for cash. To protect cash flows over the next nine months, Bonterra has entered into risk management contracts on approximately 30 percent of estimated crude oil and natural gas production. This helps reduce exposure to, and mitigate risk from, volatility in commodity prices, while underpinning the capital expenditure program and supporting Bonterra's ability to generate free funds flow that can be directed to continued debt reduction.
During Q2, Bonterra completed a renewal of its normal course, reserve-based bank credit facility with a total borrowing base of $110 million (the "Bank Facility"). As at June 30, 2024, $41.9 million was drawn on the Bank Facility, which is available on a revolving basis through April 30, 2025, with bi-annual borrowing base redeterminations and a term maturity of April 30, 2026.
Steady Cardium Development and Launch of Charlie Lake Program
A total of $54.5 million was invested capital during the first six months of 2024, contributing to the execution of a solid Cardium winter drilling program. Of the total capital invested, $39.1 million to drill 15 gross (14.2 net) operated wells, and complete, equip, tie-in and place on production 15 gross (14.0 net) operated wells. In addition, $15.4 million was directed to related infrastructure, recompletions and for the drilling, completing and equipping a water disposal well that will aid in reducing water handling costs in the Montney area.
As part of the Company's capital expenditures, Bonterra accelerated the four-well development drilling program in the Charlie Lake area, spudding the first (the "5-20 well") and second (the "13-17 well") wells on June 1st, and June 13th respectively, with both being drilled on budget. Early indications from the first two wells are positive. After the first 20 days on test, and with approximately 60 percent of load fluid recovered, combined net volumes totaled approximately 570 barrels per day of light oil, along with approximately 2.4 mmcf per day of raw natural gas.
These flow numbers are expected to further improve as the wells continue to clean up and incremental load fluid is recovered. The third and fourth wells in the program were drilled in July and are awaiting completion, with expectations that these wells will be on production in Q4 2024.
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1 Non-IFRS measure. See advisories later in this press release.
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First Montney Well Brought on Production Sets Stage for Second Drill
Bonterra's Montney asset is located north of Grand Prairie, Alberta (Valhalla), on a contiguous 47 sections (30,080 acres) of land with 100 percent working interest. During Q2 2024, the Company's first exploratory Montney well (the "4-3 well") was tied-into Bonterra's 100%-owned, 2-16 battery and a brought on production through a third party gas plant. The 4-3 well is performing at or above expectations. Since the beginning of August 2024, with recent optimization efforts, the well is producing approximately 700 BOE per day of raw production, including approximately 300 barrels per day of light crude oil. Bonterra believes that current area infrastructure capacity appears sufficient to support the drilling of a second well from the same pad in Q4 2024. In addition, the water disposal well completed in Q2 2024 is expected to be tied-in by the end of August 2024 which will further control production costs. The Company will continue to execute a measured approach to the pace of development in the Montney that aligns with available infrastructure, egress and capital availability.
Abandonment and Reclamation Activities on Track
The Company continued to responsibly pursue abandonment and reclamation efforts in Q2 2024 with spending and activities on target for the quarter. By the end of 2024, the Company estimates 36.1 net wells and 50 pipelines (for a total length of 46 kilometers of pipe) will have been abandoned, with 219 well sites decommissioned in preparation for future reclamation and 16.0 net well sites reclaimed. Bonterra is forecasting an estimated $7.0 million will be directed to decommissioning liabilities through 2024, exceeding its mandatory spend under the Alberta Energy Regulator's Liability Management Program.
Enhanced Stability Through Risk Management
To protect future cash flows, mitigate commodity price risk and impart stability, Bonterra has layered hedges on approximately 30 percent of expected crude oil and natural gas production through the next nine months. The following risk management contracts have been secured as at June, 2024:
- WTI price between $65.00 USD to $92.80 USD per bbl on 2,112 bbls per day to the end of March 31, 2025;
- From July 1 to December 31, 2024, an average WTI to Edmonton par differential price of $2.60 USD per bbl on 1,000 barrels of oil per day; and
- Natural gas prices between $0.75 to $3.30 per GJ on 12,369 GJ per day to the end of March 31, 2025.
OUTLOOK
Bonterra is pleased to reiterate previously announced 2024 annual guidance targeting 13,800 to 14,200 BOE per day average production, stemming from a $90 million to $100 million 2024 capital expenditure budget.
The Company is uniquely positioned within the junior E&P sector, having recently added two high-performing light oil plays to its portfolio, at attractive entry costs. Today, Bonterra is more sustainable than at any point in its history, with over 450 identified drilling locations across the Cardium, Charlie Lake and Montney areas, complemented by an improved free funds flow profile driven by stronger capital efficiencies.
Bonterra remains sharply focused on the responsible, safe and efficient execution of its business strategy, to develop and optimize the Company's oil-weighted, high-growth and diverse asset portfolio. With the strategic integration of the new and pivotal Charlie Lake core area, along with the emerging contribution from the Montney, Bonterra believes it is well positioned to deliver sustainable value for stakeholders and generate robust free funds flow. Further, we remain committed to capital efficient production increases, ongoing debt repayment and ultimately, to implement our shareholder returns strategy.
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. Emerging Charlie Lake and Montney resource plays are 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.
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.
Non-IFRS and Other Financial Measures
Throughout this release the Company uses the terms "funds flow", "free funds flow", "net debt", "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 funds provided by operations including proceeds from sale of investments and investment income received 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 long-term subordinated term debt, subordinated debentures and bank debt plus working capital deficiency (current liabilities less current assets). Field netback is defined as revenue and realized risk management contract gain (loss) minus royalties and operating expenses divided by total BOEs for the period. 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. Net debt to EBITDA ratio is defined as net debt at the end of the period divided by EBITDA for the trailing twelve months.
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: estimated production; cash flow sensitivity to commodity price variables; earnings sensitivity to interest rates; abandonment and reclamation activities and targets; expected cash provided by continuing operations; return of capital strategy; 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; maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; 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 may limit growth or operations within the oil and gas industry; the impact of climate-related financial disclosures on financial results; the ability of the Company to raise capital, maintain its syndicated bank facility and refinance indebtedness upon maturity; 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; 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.
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; "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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