Calgary, Alberta – Kelt Exploration Ltd. (TSX: KEL) (“Kelt” or the “Company”) reports on its oil & gas reserves and production for the year ended December 31, 2022. 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, 2022. The Company has a Reserves Committee which oversees the selection, qualifications and reporting procedures of the independent qualified reserves evaluator. Reserves effective December 31, 2022 and effective December 31, 2021 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 3, 2023.
UNAUDITED INFORMATION
All financial and operating information in this press release for the fourth quarter and year ended December 31, 2022, such as FDA&D costs, recycle ratio, net debt, capital expenditures, production 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 financial statements for the year ended December 31, 2022, and changes could be material. Kelt anticipates filing its audited financial statements and related management’s discussion and analysis for the year ended December 31, 2022 on SEDAR on March 3, 2023.
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.
Superior well performance led to significant positive technical revisions in the December 31, 2022 report. Refer to the table under the paragraph entitled “Reserves Reconciliation” for detailed information relating to reserve changes, by category, during the year.
Summary of Reserves | |||||
December 31, 2022 | December 31, 2021 | Change | |||
% Weight | Amount | % Weight | Amount | ||
Proved Developed Producing Reserves | |||||
Oil & NGLs [Mbbls] | 32% | 19,835 | 31% | 13,445 | 48% |
Gas [MMcf] | 68% | 247,362 | 69% | 182,455 | 36% |
Combined [MBOE] | 100% | 61,062 | 100% | 43,854 | 39% |
Proved Reserves | |||||
Oil & NGLs [Mbbls] | 38% | 72,254 | 39% | 52,081 | 39% |
Gas [MMcf] | 62% | 718,911 | 61% | 492,058 | 46% |
Combined [MBOE] | 100% | 192,073 | 100% | 134,091 | 43% |
Proved plus Probable Reserves | |||||
Oil & NGLs [Mbbls] |
38% | 129,479 | 41% | 104,824 | 24% |
Gas [MMcf] | 62% | 1,267,931 | 59% | 895,948 | 42% |
Combined [MBOE] | 100% | 340,801 | 100% | 254,149 | 34% |
Proved Developed Producing (“PDP”) reserves at December 31, 2022 were 61.1 million BOE, an increase of 39% from 43.9 million BOE at December 31, 2021. Proved reserves at December 31, 2022 were 192.1 million BOE, up 43% from 134.1 million BOE at December 31, 2021. Proved plus Probable (“P+P”) reserves increased by 86.7 million BOE or 34% from 254.1 million BOE at December 31, 2021 to 340.8 million BOE at December 31, 2022.
Proved plus Probable Oil and NGL reserves increased by 24% year-over-year and the mix increased favourably to a higher netback stream. Light oil, condensate and pentane plus reserves made up 62% of total Oil & NGL reserves, or 80.1 million barrels, at December 31, 2022 compared to 57% or 59.2 million barrels at December 31, 2021.
Oil & NGLs Mix | |||||
December 31, 2022 | December 31, 2021 | Change | |||
% Weight | Amount | % Weight | Amount | ||
Proved plus Probable Reserves [Mbbls] | |||||
Light Oil, Condensate and Pentane Plus (C5+) | 62% | 80,102 | 57% | 59,178 | 35% |
Butane (C4) | 10% | 12,969 | 11% | 11,542 | 12% |
Propane (C3) | 14% | 18,005 | 15% | 15,797 | 14% |
Ethane (C2) | 14% | 18,403 | 17% | 18,307 | 1% |
Total Oil & NGLs | 100% | 129,479 | 100% | 104,824 | 24% |
Note: Refer to advisories regarding Measurements and Abbreviations. |
Complementing a significant increase in the amount of reserves, the value of the reserves also increased with higher forecasted oil and gas prices for future years in the December 31, 2022 evaluation (see “Commodity Prices” table included below).
The WTI crude oil price during 2022 averaged USD $94.80 per barrel, 30% higher than Sproule’s 2022 forecast of USD $73.00 per barrel provided in the December 31, 2021 evaluation. Sproule is forecasting an average WTI crude oil price of USD $86.00 per barrel for 2023, a 23% increase from its previous forecast of USD $70.00 per barrel.
The NYMEX Henry Hub natural gas price during 2022 averaged USD $6.56 per MMBtu, 64% higher than Sproule’s 2022 forecast of USD $4.00 per MMBtu provided in the December 31, 2021 evaluation. Sproule is forecasting an average NYMEX Henry Hub natural gas price of USD $5.00 per MMBtu for 2023, an increase of 43% from its previous forecast of USD $3.50 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, 2022 Evaluation | December 31, 2021 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] |
|||||
Calendar Year | Price | Change | Price | Change | Rate | Change | Price | Price | Rate | |
2018 (historical) | 64.94 | 3.04 | 1.297 | 64.94 | 3.04 | 1.297 | ||||
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/future) | 94.80 | 30% | 6.56 | 64% | 1.302 | 4% | 73.00 | 4.00 | 1.250 | |
2023 (future) | 86.00 | 23% | 5.00 | 43% | 1.333 | 7% | 70.00 | 3.50 | 1.250 | |
2024 (future) | 84.00 | 24% | 4.50 | 38% | 1.250 | 0% | 68.00 | 3.25 | 1.250 | |
2025 (future) | 80.00 | 15% | 4.25 | 28% | 1.250 | 0% | 69.36 | 3.32 | 1.250 | |
2026 (future) | 81.60 | 15% | 4.34 | 28% | 1.250 | 0% | 70.75 | 3.38 | 1.250 | |
2027 (future) | 83.23 | 15% | 4.42 | 28% | 1.250 | 0% | 72.16 | 3.45 | 1.250 | |
Note: Percent change in the above table shows the change in price used in the December 31, 2022 evaluation compared to the price used in the December 31, 2021 evaluation for the respective calendar years from 2022 to 2027. |
The Company’s net present value of P+P reserves at December 31, 2022, discounted at 10% before tax, was $3,430 million, an increase of 60% from $2,144 million at December 31, 2021. On a barrel of oil equivalent basis, the net present value of P+P reserves at December 31, 2022 was $10.06 per BOE, up 19% from $8.43 per BOE at December 31, 2021.
The following table outlines a summary of the net present value of the Company’s reserves by category as at December 31, 2022 and at December 31, 2021:
Value of Reserves | ||||||
December 31, 2022 | December 31, 2021 | Percent Change in NPV | ||||
NPV10% BT [$M] |
NPV $/BOE |
NPV10% BT [$M] |
NPV $/BOE |
|||
Proved Developed Producing | 841,642 | 13.78 | 519,977 | 11.86 | 62% | |
Proved | 1,927,081 | 10.03 | 1,125,576 | 8.39 | 71% | |
Proved plus Probable | 3,430,114 | 10.06 | 2,143,646 | 8.43 | 60% |
At December 31, 2022, Kelt had 192.0 million common shares issued and outstanding. The net present value of reserves per share at December 31, 2022 were as follows:
Results from Kelt’s drilling program during the year replaced 2022 production multiple times in each of its reserve categories. The Company replaced total 2022 production 2.7 times on a PDP basis, 6.8 times on a Proved basis and 9.7 times on a P+P basis.
The following table shows the 2022 production replacement by reserve category:
Reserves Replacement | |||
[MBOE] | Proved Developed Producing | Proved | Proved plus Probable |
Reserve Additions, net | 27,138 | 67,912 | 96,582 |
2022 Production [1] | 9,930 | 9,930 | 9,930 |
Reserves Replacement | 273% | 684% | 973% |
Note: [1] Sulphur production of 6,686 Lt (67 MMcfe or 11 MBOE) has been excluded from 2022 production in the above table. |
2022 CAPITAL EXPENDITURES
Capital expenditures for 2022 were $317.5 million, net after property dispositions of $2.6 million. The Company drilled 28.4 net wells (25.4 wells in Alberta and 3.0 wells in British Columbia) and completed 32.1 net wells (29.1 wells in Alberta and 3.0 wells in British Columbia). Kelt added additional gas compression and enlarged its oil facilities at Pouce Coupe and Spirit River and built various oil and gas gathering pipelines at Wembley/Pipestone. Capital expenditures for 2022 include equipment and facilities purchased into inventory. In anticipation of potential supply chain bottlenecks, Kelt actively procured casing, tubing, valves, instrumentation and other equipment into inventory in order to facilitate a timely execution of the Company’s 2023 drilling program. Kelt had an equipment and facility inventory balance of $27.8 million at December 31, 2022.
FUTURE DEVELOPMENT CAPITAL EXPENDITURES
Future development capital (“FDC”) expenditures of $1,210.1 million are included in the evaluation for Proved reserves and are expected to be incurred over five years as follows: $227.6 million in 2023, $269.9 million in 2024, $264.2 million in 2025, $201.8 million in 2026 and $246.6 million in 2027. FDC expenditures of $2,044.2 million are included in the evaluation of P+P reserves and are expected to be incurred over five years as follows: $323.6 million in 2023, $393.6 million in 2024, $418.0 million in 2025, $442.6 million in 2026 and $466.4 million in 2027.
The following table outlines FDC expenditures and future wells to be drilled by province, included in the December 31, 2022 reserve evaluation with comparatives from the December 31, 2021 report:
Future Development Capital Expenditures | ||||||
December 31, 2022 Proved Reserves |
December 31, 2022 P+P Reserves |
|||||
FDC [$MM] | Net Wells | FDC/well [$MM] | FDC [$MM] |
Net Wells |
FDC/well [$MM] |
|
Alberta Montney wells | 887.0 | 111.8 | 7.9 | 1,423.5 | 181.8 | 7.8 |
British Columbia Montney wells | 177.3 | 23.0 | 7.7 | 281.7 | 36.0 | 7.8 |
Alberta Charlie Lake wells | 96.4 | 16.9 | 5.7 | 182.5 | 31.2 | 5.8 |
Other formations | 24.8 | 7.1 | 3.5 | 108.4 | 21.0 | 5.2 |
Other expenditures (includes completing DUCs) | 24.6 | ─ | 48.1 | ─ | ||
Total FDC Expenditures | 1,210.1 | 158.8 | 2,044.2 | 270.0 | ||
December 31, 2021 Proved Reserves |
December 31, 2021 P+P Reserves |
|||||
FDC [$MM] |
Net Wells |
FDC/well [$MM] | FDC [$MM] |
Net Wells |
FDC/well [$MM] |
|
Alberta Montney wells | 585.6 | 86.8 | 6.7 | 1,091.1 | 158.3 | 6.9 |
British Columbia Montney wells | 52.6 | 9.0 | 5.8 | 129.5 | 22.0 | 5.9 |
Alberta Charlie Lake wells | 35.7 | 8.5 | 4.2 | 82.8 | 19.6 | 4.2 |
Other formations | 41.7 | 14.5 | 2.9 | 74.6 | 22.2 | 3.4 |
Other expenditures (includes completing DUCs) | 38.7 | ─ | 42.9 | ─ | ||
Total FDC Expenditures | 754.3 | 118.8 | 1,420.9 | 222.1 |
FINDING, DEVELOPMENT, ACQUISITION & DISPOSITION COSTS
Capital expenditures, after acquisitions and dispositions, in 2022 were $317.5 million compared to $213.5 million in 2021. The change in FDC costs required to develop P+P reserves was $623.3 million ($494.3 million in 2021) and the change in FDC costs required to develop Proved reserves was $455.8 million ($217.6 million in 2021).
During 2022, the Company’s total capital costs resulted in net P+P reserve additions of 96.6 million BOE; net Proved reserve additions of 67.9 million BOE; and net PDP reserve additions of 27.1 million BOE. As a result, the P+P finding, development, acquisition and disposition (“FDA&D”) cost per BOE was $9.74; the Proved FDA&D cost per BOE was $11.39; and the PDP FDA&D cost per BOE was $11.65.
The recycle ratio is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment (or divestment). It accomplishes this by comparing the operating netback per BOE to the same period’s reserve FDA&D cost per BOE. With significant construction of facilities and infrastructure along with historic cumulative land acquisitions, Kelt is positioned to achieve further efficiencies in production additions and finding and development costs over the upcoming years, as the Company continues to transition from exploration and resource delineation to development and multi-well pad drilling.
In 2022, the Company achieved historically high recycle ratios for all three of its major reserve categories. The P+P recycle ratio was 3.5 times (compared to 2.6 times in 2021); the Proved recycle ratio was 3.0 times (compared to 2.4 times in 2021); and the PDP recycle ratio was 2.9 times (compared to 2.3 times in 2021). The following tables provides detailed calculations relating to FDA&D costs and recycle ratios for 2022 and 2021:
FDA&D Costs and Recycle Ratios | ||
Year ended December 31, 2022 |
Year ended December 31, 2021 |
|
Proved Developed Producing Reserves | ||
Capital expenditures, net of dispositions [$M] | 317,540 | 213,511 |
Change in FDC costs required to develop reserves [$M] | (1,427) | 1,402 |
Total capital costs [$M] | 316,113 | 214,913 |
Reserve additions, net of dispositions [MBOE] | 27,138 | 21,896 |
FDA&D cost, including FDC [$/BOE] | 11.65 | 9.82 |
Operating netback [$/BOE] | 33.98 | 22.29 |
PDP recycle ratio | 2.9 x | 2.3 x |
FDA&D Costs and Recycle Ratios | ||
Year ended December 31, 2022 |
Year ended December 31, 2021 |
|
Proved Reserves | ||
Capital expenditures, net of dispositions [$M] | 317,540 | 213,511 |
Change in FDC costs required to develop reserves [$M] | 455,788 | 217,631 |
Total capital costs [$M] | 773,328 | 431,142 |
Reserve additions, net of dispositions [MBOE] | 67,912 | 45,784 |
FDA&D cost, including FDC [$/BOE] | 11.39 | 9.42 |
Operating netback [$/BOE] | 33.98 | 22.29 |
Proved recycle ratio | 3.0 x | 2.4 x |
Proved plus Probable Reserves | ||
Capital expenditures, net of dispositions [$M] | 317,540 | 213,511 |
Change in FDC costs required to develop reserves [$M] | 623,296 | 494,307 |
Total capital costs [$M] | 940,836 | 707,818 |
Reserve additions, net of dispositions [MBOE] | 96,582 | 83,015 |
FDA&D cost, including FDC [$/BOE] | 9.74 | 8.53 |
Operating netback [$/BOE] | 33.98 | 22.29 |
P+P recycle ratio | 3.5 x | 2.6 x |
RESERVES RECONCILIATION
Kelt’s 2022 capital investment program, including dispositions, resulted in proved plus probable reserve additions of 96.6 million BOE, that replaced 2022 production by a factor of 9.7 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] |
|
Balance, December 31, 2021 | 104,824 | 895,948 | 254,149 |
Discoveries, extensions and infill drilling | 27,642 | 299,841 | 77,616 |
Technical revisions | (2,051) | 74,868 | 10,426 |
Economic factors | 3,254 | 37,918 | 9,573 |
Acquisitions | 129 | 502 | 213 |
Dispositions | (782) | (2,786) | (1,246) |
Additions, net of dispositions | 28,192 | 410,343 | 96,582 |
Less: 2022 Production [1] | (3,537) | (38,360) | (9,930) |
Balance, December 31, 2022 | 129,479 | 1,267,931 | 340,801 |
Note: [1] Sulphur production of 6,686 Lt (67 MMcfe or 11 MBOE) has been excluded from 2022 production in the above table. |
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 10.4 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, 2022 was $17.87, 257% above the $5.01 closing trading price of the Company’s common shares on the Toronto Stock Exchange on December 30, 2022.
Details of the net asset value calculation are shown in the table below:
Net Asset Value per Share | ||
$ M | $/share | |
Proved reserves, NPV10% BT [1] | 1,927,081 | 9.65 |
Probable reserves, NPV10% BT [1] | 1,503,033 | 7.53 |
Undeveloped land [2] | 129,396 | 0.65 |
Net debt [3] | (9,789) | (0.05) |
Proceeds from exercise of stock options [4] | 18,353 | 0.09 |
Net asset value | 3,568,074 | 17.87 |
Diluted common shares outstanding (000’s) [4] | 199,706 | |
Notes: [1] Includes the net present value of the liability relating to the Company’s estimated future decommissioning obligations. [2] Lands that do not have existing production, however, do have reserves assigned either as proved undeveloped well locations or probable well locations, have been excluded from the undeveloped land value. [3] Based on the Company’s estimated net debt at December 31, 2022. [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 $5.01 on December 31, 2022. All outstanding RSUs are included in diluted common shares outstanding. |
PRODUCTION
Kelt’s average production for 2022 was 27,236 BOE per day, up 30% from average production of 20,987 BOE per day in 2021. Production for 2022 was weighted 36% oil and NGLs and 64% gas. Average production for the fourth quarter of 2022 was 28,036 BOE per day, weighted 35% oil and NGLs and 65% gas.
Production for 2022 compared to 2021 is summarized in the following table:
Production | |||||
December 31, 2022 | December 31, 2021 | Change | |||
% Weight | Amount | % Weight | Amount | ||
Annual Average Production | |||||
Oil & NGLs [bbls/d] | 36% | 9,689 | 37% | 7,846 | 23% |
Gas [Mcf/d] | 64% | 105,280 | 63% | 78,846 | 34% |
Combined [BOE/d] | 100% | 27,236 | 100% | 20,987 | 30% |
OPERATIONS UPDATE
During the first half of 2022, Kelt determined that additional gas processing capacity expected to be made available to the Company in the Wembley/Pipestone area at a third-party facility was postponed until later in 2023 or early in 2024. As a result, during the second half of 2022, Kelt’s drilling program was focused on its Charlie Lake play at Spirit River and Wembley where production rates are weighted towards high netback light oil. The Company expanded its gas compression and oil handling facilities at Spirit River to accommodate production growth.
The start-up of the expanded facility was delayed to January 2023 due to the extreme cold weather experienced in December 2022. Initial production rates from the Charlie Lake wells that have recently been brought on-stream have exceeded type curve expectations.
The gross 100% working interest IP30 rates (estimated sales volumes) are summarized as follows:
At Pouce Coupe North, the Company has assembled 32 net sections of Charlie Lake rights and has drilled its first horizontal well in the area. In addition, Kelt re-completed nine vertical wells in the Charlie Lake formation at Pouce Coupe North. These wells were brought on production in late January and in February into an expanded gas compression and oil battery facility. Additional activity in the area is planned for 2023.
Based on field estimates, total Company production for the month of January is estimated to be approximately 31,000 BOE per day weighted 38% oil and NGLs and 62% gas. Three additional Charlie Lake wells are expected to be brought on-stream in February 2023, two at Spirit River (sfc 4-8) and one at Wembley (sfc 16-8).
Kelt is pleased with the success of its drilling program in 2022 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 2022 year-end financial results on March 3, 2023.