Calgary, Alberta–(Newsfile Corp. – February 22, 2024) – Kelt Exploration Ltd. (TSX: KEL) (“Kelt” or the “Company”) reports on its oil & gas reserves and production for the year ended December 31, 2023. Kelt retained Sproule Associates Limited (“Sproule”), an independent qualified reserve evaluator, to prepare a report on its oil and gas reserves. The report is effective as of December 31, 2023. The Company has a Reserves Committee which oversees the selection, qualifications and reporting procedures of the independent qualified reserves evaluator. Reserves effective December 31, 2023 and effective December 31, 2022 were determined using the guidelines and definitions set out under National Instrument 51-101 (“NI 51-101”). Additional reserves disclosure as required under NI 51-101 will be included in Kelt’s Annual Information Form which is expected to be filed on SEDAR on March 8, 2024.
UNAUDITED INFORMATION
All financial and operating information in this press release for the fourth quarter and year ended December 31, 2023, such as FDA&D costs, recycle ratio, net debt, capital expenditures, production, operating income and operating netback is based on unaudited estimated results and have not been reviewed by the Corporation’s auditors. These estimates are subject to change upon completion of audited consolidated financial statements for the year ended December 31, 2023, and changes could be material. Kelt anticipates filing its audited consolidated financial statements and related management’s discussion and analysis for the year ended December 31, 2023 on SEDAR on March 8, 2024.
RESERVES
Kelt continues to remain active operationally in its three main divisions, resulting in increases in all categories of reserves compared to the previous year. Capital expenditures and superior well performance led to significant increases in reserves, as summarized in the table below:
| Summary of Reserves | |||||
| December 31, 2023 | December 31, 2022 | Change | |||
| % Weight | Amount | % Weight | Amount | ||
| Proved Developed Producing Reserves | |||||
| Oil & NGLs (Mbbls) | 35% | 24,700 | 32% | 19,835 | 25% |
| Gas (MMcf) | 65% | 278,283 | 68% | 247,362 | 13% |
| Combined (MBOE) | 100% | 71,081 | 100% | 61,062 | 16% |
| Proved Reserves | |||||
| Oil & NGLs (Mbbls) | 38% | 97,155 | 38% | 72,254 | 34% |
| Gas (MMcf) | 62% | 956,575 | 62% | 718,911 | 33% |
| Combined (MBOE) | 100% | 256,584 | 100% | 192,073 | 34% |
| Proved plus Probable Reserves | |||||
| Oil & NGLs (Mbbls) | 36% | 149,163 | 38% | 129,479 | 15% |
| Gas (MMcf) | 64% | 1,583,515 | 62% | 1,267,931 | 25% |
| Combined (MBOE) | 100% | 413,082 | 100% | 340,801 | 21% |
Proved Developed Producing (“PDP”) reserves at December 31, 2023 were 71.1 million BOE, an increase of 16% from 61.1 million BOE at December 31, 2022. Proved reserves at December 31, 2023 were 256.6 million BOE, up 34% from 192.1 million BOE at December 31, 2022. Proved plus Probable (“P+P”) reserves increased by 72.3 million BOE or 21% from 340.8 million BOE at December 31, 2022 to 413.1 million BOE at December 31, 2023.
Proved plus Probable Oil and NGL reserves increased by 15% year-over-year and the mix increased favourably to a higher netback stream. Light oil, condensate and pentane plus reserves made up 72% of total Oil & NGL reserves, or 107.6 million barrels, at December 31, 2023 compared to 62% or 80.1 million barrels at December 31, 2022.
| Oil & NGLs Mix | |||||
| December 31, 2023 | December 31, 2022 | Change | |||
| % Weight | Amount | % Weight | Amount | ||
| Proved plus Probable Reserves (Mbbls) | |||||
| Light Oil, Condensate and Pentane Plus (C5+) | 72% | 107,610 | 62% | 80,102 | 34% |
| Butane (C4) | 10% | 14,538 | 10% | 12,969 | 12% |
| Propane (C3) | 12% | 17,647 | 14% | 18,005 | (2%) |
| Ethane (C2) | 6% | 9,368 | 14% | 18,403 | (49%) |
| Total Oil & NGLs | 100% | 149,163 | 100% | 129,479 | 15% |
| Note: Refer to advisories regarding Measurements and Abbreviations. |
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The reduction in Propane and Ethane weighting is primarily a result of the change in assumptions at Wembley/ Pipestone where production from future drilling would be processed at various gas plants per the processing agreements entered into by Kelt versus the mix of gas processing that was available to Kelt assumed in the previous year’s evaluation. The change in the mix of gas processing plants also resulted in higher gas reserves due to lower average shrink rates.
Complementing a significant increase in the amount of reserves, the value of the reserves also increased despite lower forecasted oil and gas prices for future years in the December 31, 2023 evaluation (see “Commodity Prices” table included below).
The WTI crude oil price during 2023 averaged USD $77.63 per barrel, 10% lower than Sproule’s 2022 forecast of USD $86.00 per barrel provided in the December 31, 2022 evaluation. Sproule is forecasting an average WTI crude oil price of USD $76.00 per barrel for 2024, a 10% decrease from its previous forecast of USD $84.00 per barrel.
The NYMEX Henry Hub natural gas price during 2023 averaged USD $2.53 per MMBtu, 49% lower than Sproule’s 2023 forecast of USD $5.00 per MMBtu provided in the December 31, 2022 evaluation. Sproule is forecasting an average NYMEX Henry Hub natural gas price of USD $2.75 per MMBtu for 2024, a decrease of 39% from its previous forecast of USD $4.50 per MMBtu.
The following table outlines forecasted future prices that Sproule has used in their evaluation of the Company’s reserves:
| Commodity Prices | ||||||||||
| December 31, 2023 Evaluation | December 31, 2022 Evaluation | |||||||||
| WTI Cushing Crude Oil (USD/bbl) |
NYMEX Henry Hub Natural Gas (USD/MMBtu) |
CAD/USD Exchange (CAD) |
WTI Cushing Crude Oil (USD/bbl) |
NYMEX Henry Hub Natural Gas (USD/MMBtu) |
CAD/ USD Exchange (CAD) |
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| Calendar Year | Price | Change | Price | Change | Rate | Change | Price | Price | Rate | |
| 2019 (historical) | 56.98 | 2.62 | 1.326 | 56.98 | 2.62 | 1.326 | ||||
| 2020 (historical) | 39.24 | 2.08 | 1.340 | 39.24 | 2.08 | 1.340 | ||||
| 2021 (historical) | 68.03 | 3.74 | 1.253 | 68.03 | 3.74 | 1.253 | ||||
| 2022 (historical) | 94.80 | 6.56 | 1.302 | 94.80 | 6.56 | 1.302 | ||||
| 2023 (historical/future) | 77.63 | (10%) | 2.53 | (49%) | 1.350 | 1% | 86.00 | 5.00 | 1.333 | |
| 2024 (future) | 76.00 | (10%) | 2.75 | (39%) | 1.333 | 7% | 84.00 | 4.50 | 1.250 | |
| 2025 (future) | 76.00 | (5%) | 3.75 | (12%) | 1.333 | 7% | 80.00 | 4.25 | 1.250 | |
| 2026 (future) | 76.00 | (7%) | 4.00 | (8%) | 1.333 | 7% | 81.60 | 4.34 | 1.250 | |
| 2027 (future) | 77.52 | (7%) | 4.08 | (8%) | 1.333 | 7% | 83.23 | 4.42 | 1.250 | |
| 2028 (future) | 79.07 | (7%) | 4.16 | (8%) | 1.333 | 7% | 84.90 | 4.51 | 1.250 | |
| Note: Percent change in the above table shows the change in price used in the December 31, 2023 evaluation compared to the price used in the December 31, 2022 evaluation for the respective calendar years from 2023 to 2028. |
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The Company’s net present value of P+P reserves at December 31, 2023, discounted at 10% before tax, was $4.5 billion, an increase of 32% from $3.4 billion at December 31, 2022. On a barrel of oil equivalent basis, the net present value of P+P reserves at December 31, 2023 was $10.93 per BOE, up 9% from $10.06 per BOE at December 31, 2022.
The following table outlines a summary of the net present value of the Company’s reserves by category as at December 31, 2023 and at December 31, 2022:
| Value of Reserves | |||||||
| December 31, 2023 | December 31, 2022 | Percent Change in NPV | |||||
| NPV10% BT ($M) |
NPV ($/BOE) |
NPV10% BT ($M) |
NPV ($/BOE) |
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| Proved Developed Producing | 948,144 | 13.34 | 841,642 | 13.78 | 13% | ||
| Proved | 2,827,673 | 11.02 | 1,927,081 | 10.03 | 47% | ||
| Proved plus Probable | 4,515,374 | 10.93 | 3,430,114 | 10.06 | 32% | ||
At December 31, 2023, Kelt had 194.5 million common shares issued and outstanding. The net present value of reserves, discounted at 10% before tax, per share at December 31, 2023 were as follows:
- $4.87 per share for Proved Developed Producing reserves;
- $14.54 per share for Proved reserves; and
- $23.22 per share for Proved plus Probable reserves.
Results from Kelt’s drilling program during the year replaced 2023 production multiple times in each of its reserve categories. The Company replaced total 2023 production 1.9 times on a PDP basis, 6.8 times on a Proved basis and 7.5 times on a P+P basis.
The following table shows the 2023 production replacement by reserve category:
| Reserves Replacement | |||
| (MBOE) | Proved Developed Producing | Proved | Proved plus Probable |
| Reserve Additions, net | 21,142 | 75,634 | 83,404 |
| 2023 Production [1] | 11,123 | 11,123 | 11,123 |
| Reserves Replacement | 190% | 680% | 750% |
| Note: [1] Sulphur production of 7,688 Lt (77 MMcfe or 13 MBOE) has been excluded from 2023 production in the above table. |
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2023 CAPITAL EXPENDITURES
Capital expenditures, net of A&D, for 2023 were $282.6 million. The Company drilled 27.0 net wells (20.0 wells in Alberta and 7.0 wells in British Columbia) and completed 24.0 net wells (19.0 wells in Alberta and 5.0 wells in British Columbia). Kelt added additional gas compression, enlarged its oil handling facilities and expanded its network of oil and gas gathering pipelines.
FUTURE DEVELOPMENT CAPITAL EXPENDITURES
Future development capital (“FDC”) expenditures of $1.8 billion are included in the evaluation for Proved reserves and are expected to be incurred over five years from 2024 to 2028. FDC expenditures of $2.5 billion are included in the evaluation of P+P reserves and are expected to be incurred over five years from 2024 to 2028.
The following table outlines FDC expenditures and future wells to be drilled by province in the Company’s main horizons, included in the December 31, 2023 reserve evaluation with comparatives from the December 31, 2022 report:
| Future Development Capital Expenditures | ||||||
| December 31, 2023 | Proved Reserves | P+P Reserves | ||||
| FDC ($MM) | Net Wells | FDC/well ($MM) | FDC ($MM) |
Net Wells | FDC/well ($MM) |
|
| Alberta Montney wells | 1,343.2 | 170.7 | 7.9 | 1,676.2 | 214.7 | 7.8 |
| British Columbia Montney wells | 212.9 | 27.0 | 7.9 | 396.6 | 50.0 | 7.9 |
| Alberta Charlie Lake wells | 161.6 | 28.2 | 5.7 | 250.5 | 45.4 | 5.5 |
| Other expenditures, includes completing DUCs | 50.7 | 7.9 | 143.8 | 27.4 | ||
| Total FDC Expenditures | 1,768.4 | 233.8 | 2,467.1 | 337.5 | ||
| December 31, 2022 | Proved Reserves | P+P Reserves | ||||
| FDC ($MM) | Net Wells | FDC/well ($MM) | FDC ($MM) |
Net Wells | FDC/well ($MM) |
|
| Alberta Montney wells | 887.0 | 111.8 | 7.9 | 1,423.5 | 181.8 | 7.8 |
| British Columbia Montney wells | 177.3 | 23.0 | 7.7 | 281.7 | 36.0 | 7.8 |
| Alberta Charlie Lake wells | 96.4 | 16.9 | 5.7 | 182.5 | 31.2 | 5.8 |
| Other expenditures, includes completing DUCs | 49.4 | 7.1 | 156.5 | 21.0 | ||
| Total FDC Expenditures | 1,210.1 | 158.8 | 2,044.2 | 270.0 | ||
FINDING, DEVELOPMENT, ACQUISITION & DISPOSITION COSTS
Capital expenditures, including property acquisitions and after dispositions, in 2023 were $282.6 million compared to $317.5 million in 2022. The change in FDC costs required to develop P+P reserves was $423.0 million ($623.3 million in 2022) and the change in FDC costs required to develop Proved reserves was $558.2 million ($455.8 million in 2022).
During 2023, the Company’s total capital costs resulted in net P+P reserve additions of 83.4 million BOE; net Proved reserve additions of 75.6 million BOE; and net PDP reserve additions of 21.1 million BOE. As a result, the P+P finding, development, acquisition and disposition (“FDA&D”) cost per BOE was $8.46; the Proved FDA&D cost per BOE was $11.12; and the PDP FDA&D cost per BOE was $13.37.
The recycle ratio is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment (or divestment). It accomplishes this by comparing the operating netback per BOE to the same period’s reserve FDA&D cost per BOE. With significant historic costs related to construction of facilities and infrastructure along with historic cumulative land acquisitions, Kelt is positioned to achieve further efficiencies in production additions and finding and development costs over the upcoming years, as the Company continues to transition from exploration and resource delineation to development and multi-well pad drilling.
In 2023, the Company achieved favourable recycle ratios for all three of its major reserve categories. The P+P recycle ratio was 3.0 times (compared to 3.5 times in 2022); the Proved recycle ratio was 2.3 times (compared to 3.0 times in 2022); and the PDP recycle ratio was 1.9 times (compared to 2.9 times in 2022). The following tables provide detailed calculations relating to FDA&D costs and recycle ratios for 2023 and 2022:
| FDA&D Costs and Recycle Ratios – Proved Developed Producing Reserves | ||
| Year ended December 31, 2023 |
Year ended December 31, 2022 |
|
| Capital expenditures, net of dispositions ($M) | 282,646 | 317,540 |
| Change in FDC costs required to develop reserves ($M) | ─ | (1,427) |
| Total capital costs ($M) | 282,646 | 316,113 |
| Reserve additions, net of dispositions (MBOE) | 21,142 | 27,138 |
| FDA&D cost, including FDC ($/BOE) | 13.37 | 11.65 |
| Operating netback ($/BOE) | 25.74 | 33.98 |
| PDP recycle ratio | 1.9 x | 2.9 x |
| FDA&D Costs and Recycle Ratios – Proved Reserves | ||
| Year ended December 31, 2023 |
Year ended December 31, 2022 |
|
| Capital expenditures, net of dispositions ($M) | 282,646 | 317,540 |
| Change in FDC costs required to develop reserves ($M) | 558,245 | 455,788 |
| Total capital costs ($M) | 840,891 | 773,328 |
| Reserve additions, net of dispositions (MBOE) | 75,634 | 67,912 |
| FDA&D cost, including FDC ($/BOE) | 11.12 | 11.39 |
| Operating netback ($/BOE) | 25.74 | 33.98 |
| Proved recycle ratio | 2.3 x | 3.0 x |
| FDA&D Costs and Recycle Ratios – Proved plus Probable Reserves | ||
| Year ended December 31, 2023 |
Year ended December 31, 2022 |
|
| Capital expenditures, net of dispositions ($M) | 282,646 | 317,540 |
| Change in FDC costs required to develop reserves ($M) | 422,973 | 623,296 |
| Total capital costs ($M) | 705,619 | 940,836 |
| Reserve additions, net of dispositions (MBOE) | 83,404 | 96,582 |
| FDA&D cost, including FDC ($/BOE) | 8.46 | 9.74 |
| Operating netback ($/BOE) | 25.74 | 33.98 |
| P+P recycle ratio | 3.0 x | 3.5 x |
RESERVES RECONCILIATION
Kelt’s 2023 capital investment program, resulted in proved plus probable reserve additions of 83.4 million BOE, that replaced 2023 production by a factor of 7.5 times.
A reconciliation of Kelt’s proved plus probable reserves is provided in the table below:
| Proved plus Probable Reserves Reconciliation | |||||||||||||||
| Oil & NGLs (Mbbls) |
Gas (MMcf) |
Combined (MBOE) |
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| Balance, December 31, 2022 | 129,479 | 1,267,931 | 340,801 | ||||||||||||
| Discoveries, extensions and infill drilling | 28,255 | 265,962 | 72,582 | ||||||||||||
| Technical revisions [1] | (4,396) | 90,056 | 10,613 | ||||||||||||
| Economic factors | 106 | 598 | 206 | ||||||||||||
| Acquisitions | 3 | 3 | 3 | ||||||||||||
| Dispositions | 0 | 0 | 0 | ||||||||||||
| Additions, net of dispositions | 23,968 | 356,619 | 83,404 | ||||||||||||
| Less: 2023 Production [2] | (4,284) | (41,035) | (11,123) | ||||||||||||
| Balance, December 31, 2023 | 149,163 | 1,583,515 | 413,082 | ||||||||||||
| Notes: [1] Oil & NGLs technical revisions by product were as follows:
The reduction in Butane, Propane and Ethane barrels were primarily a result of the change in assumptions at Wembley/Pipestone where production from future drilling would be processed at various gas plants per the processing agreements entered into by Kelt versus just deep-cut processing assumed in the previous year’s evaluation. This also resulted in higher gas reserves due to lower shrink rates. |
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Continued outperformance of existing producing wells compared with the previous year’s forecasts resulted in significant positive technical revisions to both producing wells and offsetting future development locations. Kelt added 10.6 million BOE of P+P reserves resulting from positive technical revisions.
NET ASSET VALUE
Kelt’s calculated net asset value per share at December 31, 2023 was $22.75, 298% above the $5.72 closing trading price of the Company’s common shares on the Toronto Stock Exchange on December 29, 2023.
Details of the net asset value calculation are shown in the table below:
| Net Asset Value per Share | ||||
| December 31, 2023 | December 31, 2022 | Change | ||
| $ M | $/share | $/share | ||
| Proved reserves, NPV10% BT [1] | 2,827,673 | 13.75 | 9.65 | 42% |
| Probable reserves, NPV10% BT [1] | 1,687,701 | 8.21 | 7.53 | 9% |
| Undeveloped land [2] | 140,191 | 0.68 | 0.65 | 5% |
| Estimated net debt [3] | (12,997) | (0.06) | (0.05) | 20% |
| Proceeds from exercise of stock options [4] | 33,767 | 0.16 | 0.09 | 78% |
| Net asset value | 4,676,335 | 22.75 | 17.87 | 27% |
| Diluted common shares outstanding (thousands) [4] | 205,590 | |||
| Notes: [1] As estimated by Sproule. [2] The undeveloped land value is based on internal estimates of Kelt’s undeveloped lands which do not have reserves assigned. [3] Based on the Company’s estimated net debt at December 31, 2023. Refer to advisories regarding “Non-GAAP and Other Financial Measures”. [4] The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are “in-the-money” based on the closing price of KEL of $5.72 on December 31, 2023. All outstanding RSUs are included in diluted common shares outstanding. |
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PRODUCTION
Kelt’s average production for 2023 was 30,510 BOE per day, up 12% from average production of 27,236 BOE per day in 2022. Production for 2023 was weighted 38% oil and NGLs and 62% gas. Average production for the fourth quarter of 2023 was 32,344 BOE per day, weighted 38% oil and NGLs and 62% gas.
Production for 2023 compared to 2022 is summarized in the following table:
| Production | |||||
| December 31, 2023 | December 31, 2022 | Change | |||
| % Weight | Amount | % Weight | Amount | ||
| Annual Average Production | |||||
| Oil & NGLs (bbls/d) | 38% | 11,738 | 36% | 9,689 | 21% |
| Gas (Mcf/d) | 62% | 112,634 | 64% | 105,280 | 7% |
| Combined (BOE/d) | 100% | 30,510 | 100% | 27,236 | 12% |
OPERATIONS UPDATE
As the Company transitions from exploration and resource delineation to development and multi-well pad drilling and in anticipation of significant future production growth, Kelt has entered into various agreements that provide the Company with the ability to increase its raw gas processing capacity over the next three years. Kelt’s development program is focused on oil and liquids-rich gas plays and therefore, by adding incremental gas processing capability, the Company is able to grow its oil and associated NGL production through its drilling program. Below is a summary of gas processing arrangements in each of the Company’s three core divisions:
- Wembley/Pipestone Division: Kelt expects to increase firm service raw gas processing capacity from 59 MMcf per day to 124 MMcf per day. Kelt will have access, through ownership interests and firm service arrangements, to five gas processing plants in the Wembley/Pipestone area.
- Pouce Coupe/Progress/Spirit River Division: Kelt expects to increase its overall raw gas processing capacity (through plant ownership interest and third-party facility firm service arrangements) from approximately 82 MMcf per day to 117 MMcf per day. Kelt will have access to five gas processing plants for production from the Pouce Coupe/Progress/Spirit River area.
- Oak/Flatrock Division: Kelt has the ability to increase firm service raw gas processing capacity from 25 MMcf per day to 90 MMcf per day in three tranches from 2024 to 2026 through gas processing arrangements with a third-party.
Current raw gas processing capacity of 166 MMcf per day equates to approximately 34,000 BOE per day (38% oil and NGLs and 62% gas) of sales volume capability (100% run-time). Increasing raw gas processing capacity to 331 MMcf per day by the end of 2026 or early 2027, would equate to capability of approximately 68,000 BOE per day of potential sales volumes at the same liquids to gas ratio.
At Wembley/Pipestone, with the start-up of an expansion to a third-party gas plant in December 2023 where Kelt has 25 MMcf per day of firm raw gas processing capacity, the Company brought on production new wells that were drilled and completed during 2023. Initial production rates from the Montney wells that were recently brought on-stream from the 14-2 pad that is located on the west side of Kelt’s contiguous land block are summarized below:
The gross 100% working interest IP30 rates (estimated sales volumes) are summarized as follows:
- Wembley 100/16-14-73-8W6 (sfc 14-2): 1,285 BOE/d (57% oil and NGLs); and
- Wembley 102/16-14-73-8W6 (sfc 14-2): 1,368 BOE/d (61% oil and NGLs).
Also, at Wembley/Pipestone, where Kelt has 34 MMcf per day of firm raw gas processing capacity at another third-party gas plant, during January 2024, the plant processed an average of 28 MMcf/d (83%) of Kelt’s share of capacity. The operator has scheduled certain maintenance operations during 2024, after which the Company expects it will be able to process incremental volumes leading up to its 34 MMcf per day of available capacity. The Company continues to have existing wells temporarily shut-in as the Company gears up for full gas processing capacity utilization.
In its Wembley/Pipestone Division, during 2024, Kelt expects to drill 14 development wells targeting the Montney oil/liquids-rich gas horizons. The Company plans to commence drilling operations at the first of three pads at its existing 14-2 location (five wells) by mid-March 2024. After which, Kelt will follow-up on two additional pads, five wells and four wells respectively, as it prepares to add production upon start-up of 50 MMcf per day incremental raw gas processing capacity at a new third-party 150 MMcf per day gas plant that is currently under construction. Construction and start-up of this gas plant is expected in the fourth quarter of 2024 or by early 2025.
At Pouce Coupe North, the Company has assembled 32 net sections of Charlie Lake rights and has drilled three horizontal wells in the area. Prior to drilling the horizontal wells, Kelt re-completed nine vertical wells in the Charlie Lake formation at Pouce Coupe North. The Company expects to remain active in the area in 2024.
At Oak, Kelt commenced an 8-well development drilling program in November 2023. Two wells were drilled from an existing pad located at 5-33 and these wells have now been completed and are being put on production. Certain production at Oak was temporarily shut-in as the Company conducted fracing operations. Three wells from an existing pad located at 6-35 have also been drilled and are expected to be completed during the summer of 2024. Drilling operations for the remaining three wells from an existing pad located at 5-31 are currently underway.
2024 GUIDANCE
Crude oil prices continue to remain volatile amid geopolitical impact on supply and concerns of slowing global growth. The WTI crude oil price averaged US$74.15 per barrel during January 2024. Kelt has reduced its forecasted average 2024 WTI oil price by 6% from US$80.00 per barrel to US$75.00 per barrel. North American natural gas prices have dropped after a warm winter, resulting from a strong El Niño weather pattern. This resulted in lower heating related natural gas demand which led to above average gas storage levels. Kelt has reduced its forecasted average 2024 NYMEX Henry Hub natural gas price by 26% from US$3.50/MMBtu to US$2.60 MMBtu and the Company has reduced its forecasted average 2024 AECO natural gas price by 30% from CA$3.16/GJ to CA$2.20/GJ.
In response to lower forecasted natural gas prices, Kelt has reduced its 2024 capital expenditure program to $325.0 million, down 7% from its previous budget of $350.0 million. Kelt expects to drill 29 net wells in 2024, down 15% from its previous budget of 34 net wells. Three of the five wells that have been deferred are at Oak and the other two wells are at Pouce Coupe. The Company will focus its 2024 capital program on wells that have a higher oil weighting.
Despite a reduced capital expenditure program for 2024, the Company has not changed its previous 2024 average production guidance of 36,000 to 39,000 BOE per day. Production during the first quarter of 2024 is expected to average between 33,000 and 34,000 BOE per day. During the second and third quarters of 2024, Kelt expects production to average between 35,000 and 37,000 BOE per day. Kelt has entered into an agreement with a third-party midstream company to process an additional 50 MMcf per day of raw gas at a new gas plant that is currently under construction in the Wembley/Pipestone area. The newly constructed plant is expected to be complete and commence operations by early Q4 2024. In this scenario, Kelt expects its 2024 average production to be at the higher end of its forecasted annual range. In the event, the new plant does not commence operations until late in Q4 2024, Kelt’s 2024 average production is expected to be at the lower end of its forecasted annual range.
Kelt’s forecasted 2024 financial and operating highlights, with comparisons to its previous forecast, are summarized in the table below:
| Financial and Operating Highlights ($ MM, unless otherwise specified) |
2024 Budget (as at November 9, 2023) |
2024 Forecast (as at February 22, 2024) |
Change |
| Oil & NGLs Production (bbls/d) | 14,250 ─ 15,750 (40%) | 14,250 ─ 15,750 (40%) | ─ |
| Gas Production (MMcf/d) | 130,500 ─ 139,500 (60%) | 130,500 ─ 139,500 (60%) | ─ |
| Combined Production (BOE/d) | 36,000 ─ 39,000 (100%) | 36,000 ─ 39,000 (100%) | ─ |
| Production per million shares (BOE/d) | 185 ─ 200 | 185 ─ 200 | ─ |
| P&NG Sales | 670.0 | 583.0 | (13%) |
| Adjusted Funds from Operations [1] | 350.0 | 290.0 | (17%) |
| AFFO per share, diluted ($/share) [1] | 1.76 | 1.46 | (17%) |
| Capital Expenditures, net of A&D [1] | 350.0 | 325.0 | (7%) |
| Net Debt, at year-end [1] | 11.3 | 48.0 | 325% |
| Net Debt/AFFO ratio (times) | 0.0 x | 0.2 x | |
| Note: [1] Refer to advisories regarding “Non-GAAP and Other Financial Measures”. |
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Kelt is pleased with the success of its drilling program in 2023 and the corresponding results that are reflected in significant growth in oil and gas reserves during the year. The Company remains optimistic about the energy industry and its ability to provide shareholders with high rates of return on capital deployed. Kelt expects to continue to reinvest cash flow into developing its high-quality Montney and Charlie Lake plays.
Management looks forward to providing shareholders with its 2023 year-end financial results on March 8, 2024.
For further information, please contact:
Kelt Exploration Ltd., Suite 300, 311 – 6th Avenue SW, Calgary, Alberta, Canada T2P 3H2
David J. Wilson, President and Chief Executive Officer (403) 201-5340, or
Sadiq H. Lalani, Vice President and Chief Financial Officer (403) 215-5310.
Or visit our website at www.keltexploration.com.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS AND INFORMATION
Changes in forecasted commodity prices and variances in production estimates can have a significant impact on estimated reserves values, adjusted funds from operations and profit. Please refer to the cautionary statement on forward-looking statements and information set out below.
This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “forecast”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information or statements. In particular, this press release contains forward-looking statements pertaining to the following: the forecasted future commodity prices used by Sproule in their evaluation, markets for future gas production, future development capital expenditures, expectations for the timing of new wells to be brought on-stream, exploration and development activities and future drilling plans, expectations for high rates of return on capital deployed, achieving further efficiencies in production additions and finding and development cost efficiencies, future production growth expectations, estimates of liquids to gas ratios, the timing around the start-up of a third party gas plant, the Company’s ability to increase its gas processing capacity and Kelt’s intention to transition to increased development and pad drilling. Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Kelt believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Kelt cannot give any assurance that they will prove to be correct. Kelt has made assumptions regarding, but not limited to: existing production sales contracts remaining in place, future commodity prices, royalty rates, tax regulations, timing and amount of capital expenditures, future production expenses, future cash flow, future debt levels and future production volumes.
Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses; failure to obtain necessary regulatory approvals for planned operations; health, safety and environmental risks; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; volatility of commodity prices, currency exchange rate fluctuations; imprecision of reserve estimates; and competition from other explorers) as well as general economic conditions, stock market volatility; and the ability to access sufficient capital. We caution that the foregoing list of risks and uncertainties is not exhaustive.
In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. The forward-looking statements contained herein are made as of the date hereof and the Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise unless expressly required by applicable securities laws.
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves, and the future net revenue attributed to such reserves, including many factors beyond the control of Kelt. The reserves and associated future net revenue information set forth in this press release are estimates only. In general, estimates of economically recoverable oil, natural gas and NGLs reserves and the future net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserves recovery, the timing and amount of capital expenditures, marketability of oil, natural gas and NGLs, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For these reasons, estimates of the economically recoverable oil, natural gas and NGLs reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenue associated with reserves prepared by different engineers, or by the same engineer at different times, may vary.
Kelt’s actual production, revenue, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Corporation’s reserves estimated by the Corporation’s independent qualified reserves evaluators represent the fair market value of those reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. Actual oil, natural gas and NGLs reserves may be greater than or less than the estimates provided herein, and variances could be material.
With respect to the disclosure of reserves contained herein relating to portions of Kelt’s properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. In this press release, unless otherwise stated all references to “reserves” are to Kelt’s gross company reserves before deduction of royalties and without including and royalty interests of Kelt. It should not be assumed that the undiscounted or discounted net present value of the Company’s reserves, as determined by Sproule, represents the fair value of those reserve estimates.
Certain information set out herein is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding Kelt’s reasonable expectations as to the anticipated results of its proposed business activities. Readers are cautioned that this financial outlook may not be appropriate for other purposes.
NON-GAAP AND OTHER FINANCIAL MEASURES
This press release contains certain non-GAAP financial measures and other specified financial measures, as described below, which do not have standardized meanings prescribed by GAAP and do not have standardized meanings under the applicable securities legislation. As these non-GAAP, and other specified financial measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.
NON-GAAP FINANICAL MEASURES
Operating income and operating netback
Operating income is a non-GAAP measure calculated by deducting royalties, production expenses and transportation expenses from petroleum and natural gas sales, net of the cost of purchases and after realized gains or losses on derivative financial instruments. The Company also presents operating income on a per BOE basis, referred to as “operating netback” or “operating income per BOE”, which allows management to better analyze performance against prior periods, on a comparable basis, and is a key industry performance measure of operational efficiency.
Capital Expenditures
“Capital expenditures, before A&D” and “Capital expenditures, net of A&D” are measures the Company uses to monitor its investment in exploration and evaluation, investment in property plant and equipment, and net investment in acquisition and disposition activities. The most directly comparable GAAP measure is “Cash used in investing activities”.
“Future development capital” means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Future development capital excludes capitalized administration costs.
Net asset value
“Net asset value” is calculated by adding the present value of proved plus probable petroleum and natural gas reserves discounted at 10% before tax (as estimated by Sproule effective December 31, 2023), undeveloped land value, proceeds from exercise of stock options, and net bank debt (surplus). “Net asset value per common share” is calculated by dividing the “Net asset value” by the diluted number of common shares outstanding. The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are “in-the-money” based on the closing price of Kelt common shares as at the calculation date. The diluted number of common shares outstanding includes common shares issuable upon conversion of the convertible debentures that are “in-the-money” based on the closing price of Kelt common shares as at the calculation date. Management believes that the “Net asset value” provides a useful measure to analyze the comparative change in the Company’s estimated value on a normalized basis, however it should not be assumed that the “Net Asset Value” represents the fair value of Company’s underlying shares.
See the “Net asset value” section of this press release which provides a reconciliation of the calculation of the net asset value back to Kelt’s present value of 2P P&NG reserves, discounted at 10% before tax.
CAPITAL MANAGEMENT MEASURES
Funds from operations and adjusted funds from operations
Management considers funds from operations and adjusted funds from operations as a key capital management measure as it demonstrates the Company’s ability to meet its financial obligations and cash flow available to fund its capital program. Funds from operations and adjusted funds from operations are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. The most comparable GAAP measure is “Cash provided by operating activities”.
Net debt (surplus) and net debt (surplus) to adjusted funds from operations ratio
Management considers net debt (surplus) and a net debt (surplus) to adjusted funds from operations ratio as key capital management measures to assess the Company’s liquidity at a point in time and to monitor its capital structure and short-term financing requirements. The “net debt (surplus) to adjusted funds from operations ratio” is also indicative of the “net debt to cash flow ratio” calculation used to determine the applicable margin for a quarter under the Company’s Credit Facility agreement (though the calculation may not always be a precise match, it is representative).
“Net debt (surplus)” is equal to bank debt, accounts payable and accrued liabilities, net of cash and cash equivalents, accounts receivables and accrued sales and prepaid expenses and deposits. The Company believes that using a “Net debt (surplus)” non-GAAP measure, which excludes non-cash derivative financial instruments, non-cash lease liabilities, and non-cash decommissioning obligations, provides investors with more useful information to understand the Company’s cash liquidity risk.
SUPPLEMENTARY FINANICAL MEASURES
“Finding, development, acquisition and disposition” (“FDA&D”) cost is the sum of capital expenditures incurred in the period, less proceeds from the disposition of assets during the period and the change in future development capital (“FDC”) required to develop reserves. FDA&D cost per BOE is determined by dividing current period net reserve additions into the corresponding period’s FDA&D cost. Readers are cautioned that the aggregate of capital expenditures incurred in the year, comprised of exploration and development costs and acquisition costs, and proceeds from the disposition of assets, and the change in estimated FDC generally will not reflect total FDA&D costs related to net reserve additions in the year.
“Reserves Replacement” is calculated by dividing the current year’s reserve additions by the current year’s production. Management believes this ratio provides useful information in comparing the rate of reserve growth to the Company’s most recent annual production.
“Recycle ratio” is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment by comparing the operating netback per BOE to FDA&D cost per BOE.
“Initial Production Rates” includes production rates for certain wells over short periods of time (i.e. IP 30). In determining production for the purposes of calculating an IP30 rate, Kelt’s IP30 rate excludes downtime. Short term production rates are preliminary, subject to a high degree of predictive uncertainty, and not determinative of the rates at which those or other wells will continue to produce and thereafter decline. Short term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Production over a longer period will experience natural declines, which can be high and may not be consistent over a longer period. Actual results will differ from those realized during an initial production period and the differences may be material.
MEASUREMENTS
All dollar amounts are referenced in thousands of Canadian dollars, except when noted otherwise. This press release contains various references to the abbreviation BOE which means barrels of oil equivalent. Where amounts are expressed on a BOE basis, natural gas volumes have been converted to oil equivalence at six thousand cubic feet per barrel and sulphur volumes have been converted to oil equivalence at 0.6 long tons per barrel.
The term BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and is significantly different than the value ratio based on the current price of crude oil and natural gas. This conversion factor is an industry accepted norm and is not based on either energy content or current prices. Such abbreviation may be misleading, particularly if used in isolation.
References to “oil” in this press release include crude oil and field condensate. References to “natural gas liquids” or “NGLs” include pentane plus, butane, propane and ethane. References to “gas” in this discussion include natural gas and sulphur.
ABBREVIATIONS
| TSX | the Toronto Stock Exchange |
| KEL | trading symbol for Kelt Exploration Ltd. on the TSX |
| GAAP | Generally Accepted Accounting Principles |
| SEDAR | the System for Electronic Document Analysis and Retrieval |
| PDP | proved developed producing |
| P+P | proved plus probable |
| bbls | barrels |
| bbls/d | barrels per day |
| Mbbls | thousand barrels |
| Mcf | thousand cubic feet |
| Mcf/d | thousand cubic feet per day |
| MMcf | million cubic feet |
| MMcfe | million cubic feet equivalent |
| MMcf/d | million cubic feet per day |
| MMBtu | million British thermal units |
| GJ | gigajoule |
| Lt | long ton |
| BOE | barrel of oil equivalent |
| MBOE | thousand barrels of oil equivalent |
| BOE/d | barrel of oil equivalent per day |
| NGLs | natural gas liquids |
| C2 | ethane |
| C3 | propane |
| C4 | butane |
| C5+ | pentane plus all other heavier natural gas liquids |
| AECO | Alberta Energy Company “C” Meter Station of the NOVA Pipeline System |
| NYMEX HH | the Henry Hub natural gas pipeline delivery location for futures contracts on the New York Mercantile Exchange |
| WTI | West Texas Intermediate |
| USD | United States dollars |
| CAD | Canadian dollars |
| $ | Canadian dollars |
| $M | thousand dollars |
| $MM | million dollars |
| P&NG | petroleum and natural gas |
| FDA&D | finding, development, acquisition and disposition |
| FDC | future development capital |
| NPV | net present value |
| NPV 10% | net present value discounted at ten percent |
| BT | before tax |
| IP30 | initial production from a well for the first 30 days (720 operating hours) |
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/198875
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