InPlay Oil Corp press release
InPlay Oil Corp. Announces 2024 Financial, Operating and Reserves Results
TSX - Toronto Stock Exchange · Oil · Natural Gas · Natural Gas Liquids · Canada
Canada NewsWire
CALGARY, AB , March 14, 2025 /CNW/ - InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) ("InPlay" or the "Company") is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2024 , along with the results of its independent oil and gas reserves evaluation effective December 31, 2024 (the "Reserve Report") prepared by Sproule Associates Limited ("Sproule"). InPlay's audited annual financial statements and notes, and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2024 will be available at " www.sedarplus.ca " and the Company's website at " www.inplayoil.com ". An updated presentation will be available after closing of the Pembina Cardium asset acquisition which is expected in April.
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Message to Shareholders:
The upcoming year is set to be a transformational year for InPlay. We believe that the highly accretive acquisition of Pembina Cardium assets from Obsidian Energy Ltd. announced on February 19, 2025 will fundamentally shift the future of the Company. The acquired assets strategically complement InPlay's existing holdings in the Pembina Cardium, an area where the Company has proven operational expertise. The acquisition will significantly expand our operational scale, with attributes including large oil in place, a higher oil weighting, strong netbacks, low decline rates and a robust inventory of high-quality drilling locations, enhancing our overall sustainability. This is expected to strengthen free adjusted funds flow ("FAFF")(4) generation, allowing for debt reduction while supporting our shareholder return strategy, with over three times FAFF coverage of our existing base dividend (11.3%) expected for 2025. We are excited to begin operations of these newly acquired assets acquired in this synergistic acquisition and to demonstrate our expertise and ability to unlock the intrinsic value of our share price. We will remain committed to financial discipline maintaining our strong balance sheet, to ultimately generate shareholder value through FAFF growth and return of capital to shareholders.
The resumption of development of our Pembina Cardium Unit # ("PCU7") asset was a key highlight in 2024. This area is our most prolific asset as it offers high production rates and lower declines. As a result of significantly improved capital costs, PCU7 yields the highest returns and strongest capital efficiencies in our current asset portfolio. Our 2024 development of PCU7 exceeded internal expectations. Operational enhancements since our last PCU7 drilling program in spring of 2022 resulted in costs 25% below budget. These new techniques can be leveraged across our Cardium asset base, including those acquired as part of the Pembina Cardium asset acquisition. Three additional 100% PCU7 extended reach horizontal ("ERH") wells were drilled in the first quarter of 2025 and recently brought on production.
During 2024, InPlay remained focused on operational execution, disciplined capital allocation and prioritizing FAFF while preserving a strong balance sheet which resulted in adjusting our operational and capital activities accordingly. InPlay's disciplined approach allowed the Company to capitalize on the transformational Pembina Cardium asset acquisition.
Following closing of the Pembina Cardium asset acquisition, InPlay will provide updated development plans and revised full-year 2025 guidance. The acquisition is currently expected to close in April 2025 .
2024 was a year of disciplined execution, operational efficiency, and delivering shareholder returns. We remain focused on financial strength, sustainable production, and value creation for our shareholders. As we move into 2025, we believe the Pembina Cardium asset acquisition positions InPlay for significant growth and long-term success. On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support.
2024 Financial and Operating Results:
Achieved average annual production of 8,712 boe/d (1) (58% light crude oil and NGLs) with fourth quarter production average of 9,376 boe/d (1) (57% light crude oil and NGLs). Generated adjusted funds flow ("AFF") (2) of $68.5 million ( $0.76 per basic share (3) ) despite a 44% drop in AECO natural gas prices compared to 2023. Distributed $16.4 million in dividends, equating to a 10.4% yield relative to year-end market capitalization. Since November 2022 , total dividends distributed amounted to $39.2 million ( $0.435 per share, including dividends declared to date in 2025). Invested $63 million in development capital which was $2.5 million below the mid-range of our $64 - $67 million budget and 25% less than 2023. The majority of capital was spent on our drilling program, consisting of 12 (11.9) operated horizontal wells and three (0.65 net) non-operated horizontal wells, including strategic infrastructure projects, and an extensive downhole optimization program. $5.4 million was spent on the optimization program to replace plunger lifts with downhole pumps and lowering pumps in horizontal wells, helping to decrease our base decline rate to 26%. Materially enhanced capital efficiencies through a 25% reduction in drilling and completion costs experienced in PCU7 as a result of operational enhancements on our four H2 2024 wells drilled in the area. Exited 2024 at 0.8x net debt to earnings before interest, taxes and depletion ("EBITDA") (4) which is among the lowest among industry peers. Generated a strong operating income profit margin (4) of 54% and net income of $9.5 million ( $0.11 per basic share, $0.10 per diluted share). Renewed our $110 million revolving Senior Credit Facility, providing significant liquidity for tactical capital investment and strategic acquisitions. Allocated $3.4 million to the successful abandonment of 40 wellbores, 37 pipelines and the reclamation of 25 wellsites.
2024 Financial & Operations Overview:
Our 2024 results reflect our disciplined capital allocation approach to maintain financial strength while delivering strong returns to shareholders. We executed our capital program under budget, generated meaningful adjusted funds flow and returned $16.4 million to shareholders. Production averaged 9,376 boe/d (1) (57% light crude oil & NGLs) in the fourth quarter of 2024.
InPlay's capital program for 2024 consisted of $63.1 million of exploration and development capital. Efficient operational execution in 2024 led to capital expenditures coming in $2.5 million below the mid-point of our $64 – $67 million budget and approximately 25% less than 2023. The Company drilled, completed and brought on production two (1.9 net) ERH wells in Willesden Green, two (2.0 net) one-mile horizontal wells in Willesden Green, three (3.0 net) ERH wells in Pembina, four (4.0 net) PCU7 ERH wells, one (1.0 net) Belly River well, and three (0.65 net) non-operated Willesden Green ERH wells during 2024. This activity amounted to the drilling of 15 (12.6 net) wells. Additionally, the Company incurred drilling costs on one (1.0 net) Glauconite well where drilling challenges resulted in casing failure and led to the termination of drilling operations. In addition, $5.4 million was spent on the optimization of wells during 2024 to change plunger lifts to downhole pumps and lowering pumps in horizontal wells which has led to improved base decline rates. Going forward, InPlay's improved decline rate results in reduced drilling capital required to maintain production and further enhancing our ability to generate FAFF.
Natural gas prices remained low in 2024 due to production growth in North America with higher than normal inventory levels in North America and Europe . This resulted in a 44% decrease in AECO pricing compared to already low prices in 2023. These lower prices resulted in a 11% decline in our realized boe sales price, which was partially offset by realized hedging gains.
Financial and Operating Results:
| (CDN) ($000's) | Three months ended
December 31 | Year ended
December 31 | | | | | 2024 | 2023 | 2024 | 2023 | | Financial | | | | | | Oil and natural gas sales | 40,039 | 47,631 | 153,713 | 179,366 | | Adjusted funds flow (2) | 18,749 | 23,544 | 68,524 | 91,784 | | Per share – basic (3) | 0.21 | 0.26 | 0.76 | 1.03 | | Per share – diluted (3) | 0.20 | 0.26 | 0.73 | 1.01 | | Per boe (3) | 21.74 | 26.67 | 21.49 | 27.86 | | Comprehensive income | 2,220 | 11,576 | 9,469 | 32,702 | | Per share – basic | 0.02 | 0.13 | 0.11 | 0.37 | | Per share – diluted | 0.02 | 0.13 | 0.10 | 0.36 | | Dividends | 4,100 | 4,094 | 16,399 | 16,123 | | Capital expenditures – PP&E and E&E | 6,204 | 14,632 | 63,069 | 84,466 | | Property acquisitions (dispositions) | - | - | (37) | 327 | | Net debt (2) | 60,895 | 45,679 | 60,895 | 45,679 | | Shares outstanding | 90,119,356 | 90,307,765 | 90,119,356 | 90,307,765 | | Basic weighted-average shares | 90,119,356 | 90,257,367 | 90,138,052 | 89,072,110 | | Diluted weighted-average shares | 93,150,691 | 91,749,661 | 93,273,290 | 90,615,976 | | | | | | | | Operational | | | | | | Daily production volumes | | | | | | Light and medium crude oil (bbls/d) | 3,691 | 4,142 | 3,523 | 3,822 | | Natural gas liquids (boe/d) | 1,651 | 1,520 | 1,499 | 1,396 | | Conventional natural gas (Mcf/d) | 24,203 | 23,606 | 22,139 | 22,839 | | Total (boe/d) | 9,376 | 9,596 | 8,712 | 9,025 | | Realized prices (3) | | | | | | Light and medium crude oil & NGLs ($/bbls) | 74.16 | 80.83 | 76.48 | 81.74 | | Conventional natural gas ($/Mcf) | 1.61 | 2.55 | 1.62 | 2.84 | | Total ($/boe) | 46.42 | 53.95 | 48.21 | 54.45 | | Operating netbacks ($/boe) (4) | | | | | | Oil and natural gas sales | 46.42 | 53.95 | 48.21 | 54.45 | | Royalties | (6.09) | (7.18) | (6.26) | (6.84) | | Transportation expense | (0.91) | (1.06) | (0.97) | (0.95) | | Operating costs | (14.39) | (14.99) | (15.12) | (15.05) | | Operating netback (4) | 25.03 | 30.72 | 25.86 | 31.61 | | Realized gain on derivative contracts | 1.62 | 0.66 | 0.86 | 1.10 | | Operating netback (including realized derivative contracts) (4) | 26.65 | 31.38 | 26.72 | 32.71 |
Operations Update:
InPlay's capital program for 2025 is underway with three (3.0 net) ERH wells drilled in PCU7 recently coming on production and are in the early cleanup stage. These wells will offset the three well pad drilled in 2024 which has exceeded internal expectations. Despite the extreme cold temperatures in February, the costs for our first three wells of 2025 came in on time and on budget. Building on the success of our 2024 PCU7 development, we are excited to continue the focused development of this highly prolific area with an additional three net wells planned for the second half of 2025 included in our pre-acquisition 2025 budget. The majority of our remaining 2025 pre-acquisition capital program was scheduled for the second half of the year with minimal spending planned in the second quarter resulting in strong forecasted FAFF.
On March 4, 2025 the government of the United Stated announced tariffs on goods imported from Canada , including a 10% tariff on Canadian energy imports. The situation continues to be fluid and we believe the volatility surrounding these tariffs is already impacting valuations in the energy industry. We continue to monitor the impact of these tariffs on the Company and will make decisions keeping our strategy of disciplined capital allocation, financial flexibility and returns to shareholders at the forefront. InPlay's financial hedges and a resulting weaker Canadian dollar are expected to mitigate the impact of these tariffs on the Company.
Hedging Update
The Company has reacted to commodity price volatility by securing commodity hedges extending through 2025 and into 2026. InPlay has hedged over 60% of pre-acquisition natural gas production and approximately 55% of pre-acquisition light crude oil production during 2025 at favorable pricing levels. Refer below for a summary of the Company's commodity-based hedges.
| | | Q1/25 | Q2/25 | Q3/25 | Q4/25 | Q1/26 | Q2-Q4/26 | | Natural Gas AECO Swap (mcf/d) | | 5,685 | 12,320 | 12,320 | 12,320 | 12,320 | 2,845 | | Hedged price ($AECO/mcf) | | $2.47 | $2.20 | $2.20 | $2.62 | $2.82 | $2.55 | | | | | | | | | | | Natural Gas AECO Costless Collar (mcf/d) | | 6,635 | 2,845 | 2,845 | 2,845 | 2,845 | - | | Hedged price ($AECO/mcf) | | $2.32 - $3.16 | $2.11 - $2.77 | $2.11 - $2.77 | $2.11 - $2.77 | $2.11 - $2.77 | - | | | | | | | | | | | Crude Oil WTI Swap (bbl/d) | | 500 | 500 | 500 | 500 | - | - | | Hedged price ($CAD WTI/bbl) | | $95.60 | $95.60 | $95.60 | $95.60 | - | - | | | | | | | | | | | Crude Oil WTI Three-way Collar (bbl/d) | | 1,700 | 1,700 | 1,300 | 1,300 | - | - | | Low sold put price ($USD WTI/bbl) | | $60.20 | $60.20 | $59.50 | $59.50 | - | - | | Mid bought put price ($USD WTI/bbl) | | $68.10 | $68.10 | $67.50 | $67.50 | - | - | | High sold call price ($USD WTI/bbl) | | $82.90 | $82.90 | $83.00 | $83.00 | - | - | | | | | | | | | | | Crude Oil MSW Differential Swap (bbl/d) | | - | 3,000 | - | - | - | - | | Hedged price ($USD/bbl) | | - | $5.68 | - | - | - | - |
| Notes: | | | 1. | See "Production Breakdown by Product Type" at the end of this press release. | | 2. | Capital management measure. See "Non-GAAP and Other Financial Measures" contained within this press release. | | 3. | Supplementary financial measure. See "Non-GAAP and Other Financial Measures" contained within this press release. | | 4. | Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to "Non-GAAP and Other Financial Measures" contained within this press release and in our most recently filed MD&A. |
2024 Reserves Results (1) :
An organic 2024 capital program without acquisition/disposition ("A&D") activity resulted in: Proved developed producing ("PDP") reserves of 17,207 mboe (54% light and medium crude oil & NGLs) Total proved ("TP") reserves of 43,912 mboe (60% light and medium crude oil & NGLs) Total proved plus probable ("TPP") reserves of 58,724 mboe (61% light and medium crude oil & NGLs)
Reserves life index ("RLI") (2) for PDP, TP and TPP of approximately 5.4 years, 13.8 years and 18.5 years, respectively highlights a sizable drilling inventory for long-term development potential. Achieved NPV BT10 reserve values (1) of: PDP: $222 million TP: $485 million TPP: $706 million
| 1. | See "Corporate Reserves Information" for detailed information from the Reserve Report and associated NPV calculations. | | 2. | RLI is calculated by dividing the reserves in each category by the 2024 average annual production. For example 2024 TP = (43,912 mboe) / (8,712 boe/d) = 13.8 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories. |
Corporate Reserves Information:
The following summarizes certain information contained in the Reserve Report. The Reserve Report was prepared in accordance with the definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form ("AIF") which will be filed on SEDAR+ by the end of March 2025 .
| December 31, 2024 | Light and Medium | | Conventional | Oil | BTAX
NPV | Future Development | Net
Undeveloped | | Reserves Category (1)(2)(3)(4)(5) | Crude Oil | NGLs | Natural Gas | Equivalent | 10 % | Capital | Wells | | Mbbl | Mbbl | MMcf | MBOE | ($000's) | ($000's) | Booked | | | | | | | | | | | | Proved developed producing | 5,910.3 | 3,298.5 | 47,987 | 17,206.5 | 221,816 | 25 | - | | Proved developed non- producing | 591.3 | 276.0 | 4,077 | 1,546.8 | 23,466 | 1,230 | - | | Proved undeveloped | 12,228.3 | 3,879.3 | 54,305 | 25,158.5 | 240,010 | 403,317 | 162.4 | | Total proved | 18,729.8 | 7,453.8 | 106,369 | 43,911.7 | 485,293 | 404,572 | 162.4 | | Probable developed producing | 1,552.3 | 860.0 | 12,341 | 4,469.1 | 51,729 | - | - | | Probable developed non-producing | 169.0 | 108.5 | 1,535 | 533.3 | 7,063 | - | - | | Probable undeveloped | 5,708.5 | 1,227.6 | 17,242 | 9,809.8 | 161,936 | 80,487 | 25.5 | | Total probable | 7,429.7 | 2,196.0 | 31,117 | 14,812.1 | 220,728 | 80,487 | 25.5 | | Total proved plus probable (6) | 26,159.5 | 9,649.9 | 137,486 | 58,723.8 | 706,020 | 485,059 | 187.9 |
| Notes: | | | 1. | Reserves have been presented on a gross basis which are the Company's total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company. | | 2. | Based on an arithmetic average of the price forecasts of three independent reserve evaluator's (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2024, as outlined in the table herein entitled "Pricing Assumptions". | | 3. | It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay's light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. | | 4. | All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis. | | 5. | The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2024 reserve NPV values are also inclusive of currently enacted carbon taxes. | | 6. | Totals may not add due to rounding. |
Net Present Values of Reserves:
InPlay achieved strong before tax estimated net present values ("NPV") of future net revenues associated with our 2024 year-end reserves discounted at 10% ("NPV BT10"), although impacted by weaker future commodity prices in comparison to December 31, 2023 . Forecasted WTI and AECO prices used in the Reserve Report decreased by 5% and 30% in year one and 2% and 18% in year two, respectively, compared to 2023. The Company achieved NPV BT10 reserve values of $222 million (PDP), $485 million (TP) and $706 million (TPP) based on the three independent reserve evaluator average pricing, cost forecast and foreign exchange rates as at December 31, 2024 used in the Reserve Report.
| December 31, 2024 | BTAX NPV 5% | BTAX NPV 10% | | ($000's) | ($000's) | | | PDP NPV (1)(2) | 246,207 | 221,816 | | TP NPV (1)(2) | 629,299 | 485,293 | | TPP NPV (1)(2) | 940,780 | 706,020 |
| Notes: | | | 1. | Evaluated by Sproule as at December 31, 2024. The estimated NPV does not represent fair market value of the reserves. | | 2. | Based on an arithmetic average of the price forecasts of three independent reserve evaluator's (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2024. |
Future Development Costs ("FDCs"):
The following FDCs are included in the 2024 Reserve Report:
| ($ millions) | | | TP | TPP | | 2025 | | | 32.2 | 32.2 | | 2026 | | | 68.4 | 77.2 | | 2027 | | | 103.5 | 121.9 | | 2028 | | | 90.6 | 129.6 | | Remainder | | | 109.9 | 124.2 | | Total undiscounted FDC | | | 404.6 | 485.1 | | Total discounted FDC at 10% per year | | | 308.4 | 367.8 |