Calgary, Alberta – Kelt Exploration Ltd. (TSX: KEL) (“Kelt” or the “Company”) is pleased to report on its oil & gas reserves and production for the year ended December 31, 2021. 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, 2021. The Company has a Reserves Committee which oversees the selection, qualifications and reporting procedures of the independent qualified reserves evaluator. Reserves effective December 31, 2021 and effective December 31, 2020 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 will be filed on SEDAR on or before March 31, 2022.
UNAUDITED INFORMATION
All financial and operating information in this press release for the fourth quarter and year ended December 31, 2021, such as FDA&D costs, recycle ratio, working capital surplus, 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, 2021, 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, 2021 on SEDAR on March 10, 2022.
RESERVES
On August 21, 2020, Kelt completed the sale of its Inga/Fireweed/Stoddart assets (the “Inga Assets”), one of the Company’s four main divisions. Subsequent to the sale of the Inga Assets, Kelt has been active operationally in its remaining three main divisions, resulting in increases in all categories of reserves compared to the previous year. Both crude oil and natural gas prices have moved higher subsequent to December 31, 2020 resulting in significant increases in net present values per barrel of oil equivalent of the Company’s reserves.
Superior well performance and an improved cost structure led to significant positive technical revisions in the December 31, 2021 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, 2021 | December 31, 2020 | Change | |||
% Weight | Amount | % Weight | Amount | ||
Proved Developed Producing Reserves | |||||
Oil & NGLs [Mbbls] | 31% | 13,445 | 34% | 10,200 | 32% |
Gas [MMcf] | 69% | 182,455 | 66% | 116,437 | 57% |
Combined [MBOE] | 100% | 43,854 | 100% | 29,606 | 48% |
Proved Reserves | |||||
Oil & NGLs [Mbbls] | 39% | 52,081 | 40% | 37,903 | 37% |
Gas [MMcf] | 61% | 492,058 | 60% | 348,315 | 41% |
Combined [MBOE] | 100% | 134,091 | 100% | 95,956 | 40% |
Proved plus Probable Reserves | |||||
Oil & NGLs [Mbbls] | 41% | 104,824 | 42% | 75,619 | 39% |
Gas [MMcf] | 59% | 895,948 | 58% | 618,975 | 45% |
Combined [MBOE] | 100% | 254,149 | 100% | 178,782 | 42% |
Oil & NGLs Mix | |||||
December 31, 2021 | December 31, 2020 | Change | |||
% Weight | Amount | % Weight | Amount | ||
Proved plus Probable Reserves [Mbbls] | |||||
Light Oil, Condensate and Pentane (C5+) | 57% | 59,178 | 62% | 46,538 | 27% |
Butane (C4) | 11% | 11,542 | 10% | 7,678 | 50% |
Propane (C3) | 15% | 15,797 | 13% | 10,009 | 58% |
Ethane (C2) | 17% | 18,307 | 15% | 11,394 | 61% |
Total Oil & NGLs | 100% | 104,824 | 100% | 75,619 | 39% |
Note: Refer to advisories regarding Measurements and Abbreviations. |
Proved Developed Producing (“PDP”) reserves at December 31, 2021 were 43.9 million BOE, an increase of 48% from 29.6 million BOE at December 31, 2020. Proved reserves at December 31, 2021 were 134.1 million BOE, up 40% from 96.0 million BOE at December 31, 2020. Proved plus Probable (“P+P”) reserves increased by 75.4 million BOE or 42% from 178.8 million BOE at December 31, 2020 to 254.1 million BOE at December 31, 2021.
Complementing a significant increase in the amount of reserves, the value of the reserves also increased due to higher forecasted oil and gas prices for future years in the December 31, 2021 evaluation (see “Commodity Prices” table included below).
The Company’s net present value of P+P reserves at December 31, 2021, discounted at 10% before tax, was $2,144 million, an increase of 130% from $932 million at December 31, 2020. On a barrel of oil equivalent basis, net present value of P+P reserves at December 31, 2021 was $8.43 per BOE, up 62% from $5.21 per BOE at December 31, 2020.
Sproule’s forecasted commodity prices for 2022 used to determine the net present value of the Company’s reserves at December 31, 2021, are USD $73.00 per barrel for WTI oil, USD $4.00 per MMBtu for NYMEX Henry Hub natural gas and a USD/CAD exchange rate of USD $0.800 (or CAD $1.250).
The following table outlines a summary of the Company’s reserves by category as at December 31, 2021 and at December 31, 2020:
Value of Reserves | ||||||
December 31, 2021 | Oil & NGLs [Mbbls] |
Gas [MMcf] |
Combined [MBOE] |
NPV10% BT [$M] |
NPV10% BT [$/BOE] |
|
Proved Developed Producing | 13,445 | 182,455 | 43,854 | 519,977 | 11.86 | |
Proved | 52,081 | 492,058 | 134,091 | 1,125,576 | 8.39 | |
Proved plus Probable | 104,824 | 895,948 | 254,149 | 2,143,646 | 8.43 | |
December 31, 2020 | ||||||
Proved Developed Producing | 10,200 | 116,437 | 29,606 | 202,517 | 6.84 | |
Proved | 37,903 | 348,315 | 95,956 | 429,977 | 4.48 | |
Proved plus Probable | 75,619 | 618,975 | 178,782 | 931,756 | 5.21 |
The following table shows the change in the net present value of reserves year-over-year by reserve category:
Change in Value of Reserves | ||||
[$M] | December 31, 2021 | December 31, 2020 | Change in Value | Percent Change |
Proved Developed Producing | 519,977 | 202,517 | 317,460 | 157% |
Proved | 1,125,576 | 429,977 | 695,599 | 162% |
Proved plus Probable | 2,143,646 | 931,756 | 1,211,890 | 130% |
Kelt’s drilling program during the year replaced 2021 production multiple times in each of its reserve categories. The Company replaced total 2021 production 2.9 times on a PDP basis, 6.0 times on a Proved basis and 10.9 times on a P+P basis.
The following table shows the 2021 production replacement by reserve category:
Reserves Replacement | |||
[MBOE] | Proved Developed Producing | Proved | Proved plus Probable |
Reserve Additions, net | 21,896 | 45,784 | 83,015 |
2021 Production [1] | 7,648 | 7,648 | 7,648 |
Reserves Replacement | 286% | 599% | 1,085% |
Note: [1] Sulphur production of 7,292 Lt (73 MMcfe or 12 MBOE) has been excluded from 2021 production in the above table. |
COMMODITY PRICE FORECAST
The WTI crude oil price during 2021 averaged USD $68.03 per barrel, 48% higher than Sproule’s 2021 forecast of USD $46.00 per barrel provided in the December 31, 2020 evaluation. Sproule is forecasting an average WTI crude oil price of USD $73.00 per barrel for 2022, a 52% increase from its previous forecast of USD $48.00 per barrel. The NYMEX Henry Hub natural gas price during 2021 averaged USD $3.74 per MMBtu, 25% higher than Sproule’s 2021 forecast of USD $3.00 per MMBtu provided in the December 31, 2020 evaluation. Sproule is forecasting an average NYMEX Henry Hub natural gas price of USD $4.00 per MMBtu for 2022, an increase of 33% from its previous forecast of USD $3.00 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, 2021 Evaluation | December 31, 2020 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 | |
2017 (historical) | 50.88 | 3.07 | 1.299 | 50.88 | 3.07 | 1.299 | ||||
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 | 1.327 | ||||
2020 (historical) | 39.24 | 2.08 | 1.340 | 39.24 | 2.08 | 1.340 | ||||
2021 (historical/future) | 68.03 | 48% | 3.74 | 25% | 1.253 | (4%) | 46.00 | 3.00 | 1.299 | |
2022 (future) | 73.00 | 52% | 4.00 | 33% | 1.250 | (4%) | 48.00 | 3.00 | 1.299 | |
2023 (future) | 70.00 | 32% | 3.50 | 17% | 1.250 | (4%) | 53.00 | 3.00 | 1.299 | |
2024 (future) | 68.00 | 26% | 3.25 | 6% | 1.250 | (4%) | 54.06 | 3.06 | 1.299 | |
2025 (future) | 69.36 | 26% | 3.32 | 6% | 1.250 | (4%) | 55.14 | 3.12 | 1.299 | |
2026 (future) | 70.75 | 26% | 3.38 | 6% | 1.250 | (4%) | 56.24 | 3.18 | 1.299 | |
Note: Percent change in the above table shows the change in price used in the December 31, 2021 evaluation compared to the price used in the December 31, 2020 evaluation for the respective calendar years from 2021 to 2026. |
2021 CAPITAL EXPENDITURES
Capital expenditures for 2021 were $213.5 million, net after property dispositions of $9.0 million. The Company drilled 20.7 net wells (6.0 wells at Wembley/Pipestone, 9.7 wells at Pouce Coupe/Progress/Spirit River and 5.0 wells at Oak/ Flatrock) and completed 23.0 net wells (6.0 wells at Wembley/Pipestone, 9.0 wells at Pouce Coupe/Progress/Spirit River and 8.0 wells at Oak/Flatrock). Kelt constructed the Oak 6-35 gas compression and oil battery facility and built various oil and gas gathering pipelines in each of its three operating divisions. Capital expenditures for 2021 include equipment and facilities purchased into inventory. In anticipation of rising steel prices and potential supply chain bottlenecks, during the fourth quarter of 2021, Kelt actively procured casing and tubing into inventory. The Company had an equipment and facility inventory balance of $19.3 million at December 31, 2021 and is able to fulfill its current 2022 drilling budget with equipment from inventory.
FUTURE DEVELOPMENT CAPITAL EXPENDITURES
Future development capital (“FDC”) expenditures of $754.3 million are included in the evaluation for Proved reserves and are expected to be incurred over five years as follows: $148.0 million in 2022, $150.0 million in 2023, $148.2 million in 2024, $149.2 million in 2025 and $158.9 million in 2026. FDC expenditures of $1,420.9 million are included in the evaluation of P+P reserves and are expected to be incurred over five years as follows: $206.7 million in 2022, $247.2 million in 2023, $296.5 million in 2024, $295.1 million in 2025 and $375.4 million in 2026 and thereafter.
The following table outlines FDC expenditures and future wells to be drilled by province, included in the December 31, 2021 reserve evaluation:
Future Development Capital Expenditures | ||||||
December 31, 2021 Proved Reserves |
December 31, 2021 P+P Reserves |
|||||
FDC [$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 |
Other formations (including Doig/Charlie Lake) | 77.4 | 23.0 | 3.4 | 157.4 | 41.8 | 3.8 |
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 dispositions, in 2021 were $213.5 million compared to negative $354.0 million in 2020 which included net proceeds of $503.9 million from the disposition of the Inga Assets. The change in FDC costs required to develop P+P reserves was $494.3 million (negative $1,527.9 million in 2020) and the change in FDC costs required to develop Proved reserves was $217.6 million (negative $842.2 million in 2020).
During 2021, the Company’s total capital costs resulted in net P+P reserve additions of 83.0 million BOE; net Proved reserve additions of 45.8 million BOE; and net PDP reserve additions of 21.9 million BOE. As a result, the P+P finding, development, acquisition and disposition (“FDA&D”) cost per BOE was $8.53; the Proved FDA&D cost per BOE was $9.42; and the PDP FDA&D cost per BOE was $9.82.
The recycle ratio is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment (or divestment). It accomplishes this by comparing the operating netback per BOE to the same period’s reserve FDA&D cost per BOE. With significant construction of facilities and infrastructure along with historic cumulative land acquisitions, Kelt is positioned to achieve further efficiencies in production additions and finding and development costs over the upcoming years, as the Company continues to transition from exploration and resource delineation to development and multi-well pad drilling.
In 2021, the Company achieved historically high recycle ratios for all three of its major reserve categories. The P+P recycle ratio was 3.5 times (compared to 1.2 times in 2020); the Proved recycle ratio was 3.2 times (compared to 0.8 times in 2020); and the PDP recycle ratio was 3.1 times (compared to 0.2 times in 2020).
The following tables provides detailed calculations relating to FDA&D costs and recycle ratios for 2021 and 2020:
FDA&D Costs and Recycle Ratios | ||
Year ended December 31, 2021 |
Year ended December 31, 2020 [1] |
|
Proved Developed Producing Reserves | ||
Capital expenditures, net of dispositions [$M] | 213,511 | (353,957) |
Change in FDC costs required to develop reserves [$M] | 1,402 | (9,995) |
Total capital costs [$M] | 214,913 | (363,952) |
Reserve additions, net of dispositions [MBOE] | 21,896 | (10,114) |
FDA&D cost, including FDC [$/BOE] | 9.82 | 35.99 |
Fourth quarter operating netback [$/BOE] [2] [3] | 30.00 | 8.40 |
PDP recycle ratio | 3.1 x | 0.2 x |
Notes: [1] On August 21, 2020, Kelt completed the sale of its Inga Assets. In the table above, capital expenditures have been reduced by the proceeds from the sale; FDC relating to the Inga Assets have been deducted from 2020 total capital costs; and reserves relating to the Inga Assets have been deducted from 2020 net reserve additions. [2] The 2021 PDP recycle ratio using the 2021 operating netback of $22.29/BOE was 2.3 x and the 2020 PDP recycle ratio using the 2020 operating netback of $8.41/BOE was 0.2 x. [3] Based on the Company’s estimated operating netback for the three months ended December 31, 2021. |
FDA&D Costs and Recycle Ratios | ||
Year ended December 31, 2021 | Year ended December 31, 2020 [1] | |
Proved Reserves | ||
Capital expenditures, net of dispositions [$M] | 213,511 | (353,957) |
Change in FDC costs required to develop reserves [$M] | 217,631 | (842,190) |
Total capital costs [$M] | 431,142 | (1,196,147) |
Reserve additions, net of dispositions [MBOE] | 45,784 | (119,491) |
FDA&D cost, including FDC [$/BOE] | 9.42 | 10.01 |
Fourth quarter operating netback [$/BOE] [2] [3] | 30.00 | 8.40 |
Proved recycle ratio | 3.2 x | 0.8 x |
Proved plus Probable Reserves | ||
Capital expenditures, net of dispositions [$M] | 213,511 | (353,957) |
Change in FDC costs required to develop reserves [$M] | 494,307 | (1,527,897) |
Total capital costs [$M] | 707,818 | (1,881,854) |
Reserve additions, net of dispositions [MBOE] | 83,015 | (273,064) |
FDA&D cost, including FDC [$/BOE] | 8.53 | 6.89 |
Fourth quarter operating netback [$/BOE] [2] [3] | 30.00 | 8.40 |
P+P recycle ratio | 3.5 x | 1.2 x |
Notes: [1] On August 21, 2020, Kelt completed the sale of its Inga Assets. In the table above, capital expenditures have been reduced by the proceeds from the sale; FDC relating to the Inga Assets have been deducted from 2020 total capital costs; and reserves relating to the Inga Assets have been deducted from 2020 net reserve additions. [2] The 2021 Proved recycle ratio using the 2021 operating netback of $22.29/BOE was 2.4 x and the 2020 Proved recycle ratio using the 2020 operating netback of $8.41/BOE was 0.8 x. The 2021 P+P recycle ratio using the 2021 operating netback of $22.29/BOE was 2.6 x and the 2020 PDP recycle ratio using the 2020 operating netback of $8.41/BOE was 1.2 x. [3] Based on the Company’s estimated operating netback for the three months ended December 31, 2021. |
RESERVES RECONCILIATION
Kelt’s 2021 capital investment program, including dispositions, resulted in proved plus probable reserve additions of 83.0 million BOE, that replaced 2021 production by a factor of 10.9 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, 2020 | 75,619 | 618,975 | 178,782 |
Extensions and infill drilling | 25,927 | 189,208 | 57,462 |
Technical revisions | 7,718 | 125,403 | 28,618 |
Economic factors | 57 | 600 | 157 |
Acquisitions | 199 | 764 | 326 |
Dispositions | (1,832) | (10,296) | (3,548) |
Additions, net of dispositions | 32,069 | 305,679 | 83,015 |
Less: 2021 Production [1] | (2,864) | (28,706) | (7,648) |
Balance, December 31, 2021 | 104,824 | 895,948 | 254,149 |
Note: [1] Sulphur production of 7,292 Lt (73 MMcfe or 12 MBOE) has been excluded from 2021 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 28.6 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, 2021, was $11.47, 138% above the $4.82 closing trading price of the Company’s common shares on the Toronto Stock Exchange on December 31, 2021. 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] | 1,125,576 | 5.68 |
Probable reserves, NPV10% BT [1] | 1,018,070 | 5.14 |
Undeveloped land [2] | 135,429 | 0.68 |
Net debt [3] | (28,220) | (0.14) |
Proceeds from exercise of stock options [4] | 22,704 | 0.11 |
Net asset value | 2,273,559 | 11.47 |
Diluted common shares outstanding (000’s) [4] | 198,208 | |
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, 2021. [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 $4.82 on December 31, 2021. All outstanding RSUs are included in diluted common shares outstanding. |
PRODUCTION
Kelt’s average production for 2021 was 20,987 BOE per day, down 16% from average production of 24,992 BOE per day in 2020. Production in 2020 includes volumes from the Inga Assets up to the disposition date of August 21, 2020.
Pro-forma average production for 2020, excluding the Inga Assets, was 15,940 BOE per day. The Company’s 2021 production was 32% higher than pro-forma 2020 production.
Production for 2021 was weighted 37% oil and NGLs and 63% gas. Average production for the fourth quarter of 2021 was 25,815 BOE per day, weighted 38% oil and NGLs and 62% gas.
Production for 2021 compared to 2020 is summarized in the following table:
Production | |||||
December 31, 2021 | December 31, 2020 [1] | Change | |||
% Weight | Amount | % Weight | Amount | ||
Annual Average Production | |||||
Oil & NGLs [bbls/d] | 37% | 7,846 | 45% | 11,218 | (30%) |
Gas [Mcf/d] | 63% | 78,846 | 55% | 82,646 | (5%) |
Combined [BOE/d] | 100% | 20,987 | 100% | 24,992 | (16%) |
Note: [1] On August 21, 2020, Kelt completed the sale of its Inga Assets. Pro-forma average production for 2020, excluding the Inga Assets, was 15,940 BOE/d. Oil & NGLs were 6,322 bbls/d (40%) and Gas was 57,708 Mcf/d (60%). Average production for 2021 of 20,987 BOE/d was 32% higher than pro-forma average production for 2020 of 15,940 BOE/d. |
OPERATIONS UPDATE
At Oak, in northeastern British Columbia, Kelt commenced operations at its newly constructed Oak 6-35 gas compression and oil battery facility. Ten newly drilled and completed Montney wells (9 Uppers and 1 Middle) plus one older producing Upper Montney well were connected to the Oak 6-35 facility and brought on production at various times during the month of November 2021. During November and December 2021, the new wells continued to clean-up with the flowback of frac water.
In late January 2022, the Company shut-in two of the recently completed Upper Montney wells (00/16-23 (sfc A13-12) and 00/14-24 (sfc B13-12)) to allow unrecovered frac water from these wells to imbibe into the rock formation. The wells appear to have a water block/wettability issue that is reducing productivity. Kelt expects to keep these wells shut-in for a period of two to three months. The remaining producing wells are expected to keep the compressors at the Oak 6-35 facility fully loaded during the interim shut-in period.
The table below summarizes the production (based on field estimates) for the seven Upper Montney wells (does not include the two shut-in Upper Montney wells nor does it include the Middle Montney well):
Oak Well Performance | |||||
Upper Montney Well [3] [4] | D&C Capex [5] [$MM] |
Cumulative Production [1] [BOE] |
Cumulative Oil & NGLs [%] |
Recent Production [2] [BOE/d] |
Recent Oil & NGLs [%] |
00/13-05-087-18W6 (sfc 5-31) | 6.0 | 99,040 | 33% | 1,073 | 22% |
00/01-09-087-18W6 (sfc 5-33) | 6.0 | 65,152 | 44% | 991 | 32% |
00/04-10-087-18W6 (sfc A5-33) | 5.1 | 72,697 | 49% | 1,153 | 52% |
00/12-12-087-18W6 (sfc B6-35) | 5.3 | 65,744 | 45% | 892 | 41% |
00/08-11-087-18W6 (sfc C6-35) | 5.8 | 67,101 | 45% | 764 | 41% |
00/08-16-087-18W6 (sfc C13-12) | 5.6 | 58,492 | 35% | 652 | 26% |
02/08-16-087-18W6 (sfc D13-12) | 5.2 | 44,577 | 44% | 678 | 34% |
Average Upper Montney Wells | 5.6 | 67,543 | 41% | 886 | 35% |
Notes: [1] Cumulative production is from well start-up at various times during the month of November 2021 until February 14, 2022 (based on field estimates). Certain wells were restricted at times due to start-up facility constraints and also due to optimization of well flowback of frac water. [2] Recent production is average daily production for the 13-day period from February 1, 2022 to February 14, 2022 (based on field estimates and based on producing hours). [3] Production from the two Upper Montney wells located at 00/16-23-087-18W6 (sfc A13-12) and 00/14-24-087-18W6 (sfc B13-12) are not included above as these wells are currently shut-in and production from the Middle Montney well located at 00/16-06-087-18W6 (sfc A5-31) is not included above. [4] Production from the two older producing Upper Montney wells (drilled in 2017 and 2018) located at 02/06-02-086-18W6 (sfc 14-11) and 02/13-13-087-18W6 (sfc 13-12) are not included above. The 02/06-02 well is connected to a third-party facility and the 02/13-13 well is currently shut-in. [5] Average drill & complete (“D&C”) capital expenditures (“Capex”) for all ten Oak Montney wells was $5.5 MM per well. |
Kelt is pleased with the initial results from the Oak drilling program. Average recent production per well has exceeded type curve expectations during the third month of production. Cumulative oil and NGLs production from the seven Upper Montney wells has averaged 41%, of which 88% was light oil, condensate and pentanes (C5+) and 12% was other NGLs (butane and propane). Natural gas produced at Oak receives a premium price due to the high heat value estimated at 1,175 Btu/scf (43.8 MJ/m3). In addition, the Government of British Columbia approved Kelt’s 2019 application to recover approximately 37% of $49.5 million in total infrastructure expenditures (or approximately $18.5 million) through reduced future royalties payable relating to Montney wells drilled at Oak that are associated with the infrastructure.
The Company expects to continue with its delineation program at Oak/Flatrock and expects to initiate a development program offsetting the recently drilled wells. The Company has a large contiguous land block at Oak/Flatrock comprised of 193,111 net acres (or 302 sections). Kelt’s Oak 6-35 facility can be expanded in a cost-effective manner by adding additional compression in the future, as required. Natural gas produced from Oak is processed at the McMahon Gas Plant which currently has significant unused processing capacity.
Sproule’s December 31, 2021 reserves evaluation includes FDC for 22 Oak Montney wells in the Company’s P+P case. On average, Sproule is estimating an IP365 (sales) of 542 BOE/d (33% oil & NGLs) and EUR of 968,000 BOE (25% oil & NGLs). Using the Sproule commodity price deck contained in the December 31, 2021 evaluation, the net present value (10% BT) of an Oak P+P future development well is $8.6 million, after future drill, complete and tie-in capital costs of $5.9 million per well. Sproule’s estimated payout of the future drill, complete and tie-in capital cost is 0.8 years and the before tax rate of return is 136%.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (“ESG”) PERFORMANCE REVIEW
Kelt is committed to continued leadership in ESG performance. The Company has identified opportunities to improve sustainability of existing assets and is testing low carbon solutions for its future capital plans.
With operations across Alberta and British Columbia, Kelt must effectively navigate the requirements and interests of landowners, First Nations and Governments. The Company respects each group’s differences, commits to learning their respective values and priorities, and tailors engagement to ensure positive impact within the communities.
With a focus on constantly improving risk oversight and enhancing accountability to the Company’s shareholders and other stakeholders, Kelt’s Board and management follow high standards of corporate governance. This includes a commitment to diversity both at the board level and throughout the organization.
Highlights of Kelt’s Key ESG Performance Indicators include the following:
- During 2021, Kelt replaced its remaining high bleed methane-venting pneumatic valves in Alberta, reducing approximately 1,000 tonnes of methane emissions annually.
- The Company continues to employ bi-fuel drilling rigs and frac equipment which reduce the use of more carbon intensive fuel by blending it with natural gas.
- GHG emissions intensity compares favourably to the Company’s peer group. Total GHG emissions for 2020 (Scope 1 & 2 combined) were 0.022 tonnes of CO2E per BOE.
- Effective December 31, 2021, Kelt had a strong consolidated LMR rating of 7.0.
- During 2021, the Company incurred $3.6 million in expenditures relating to settlement of decommissioning obligations.
- The Company achieved a reduction in recordable and lost time injury frequency for the fifth consecutive year.
- Kelt completed a renewal on its Board of Directors resulting in current female representation on the Board of 33% (40% of independent Board members).
Kelt is pioneering a model for sustainable oil and gas development at its Oak/Flatrock Division in British Columbia. The Company is reducing greenhouse gas (“GHG”) emissions through a number of initiatives outlined below:
- SOLAR AND INSTRUMENT AIR: well sites, including ESD valves, wellhead chokes and pumps, to be powered with solar electricity. Facility air instruments installed in order to eliminate methane emissions from the devices.
- RENEWABLE HEAT: installed solar powered heat source to surface facilities.
- ELECTRONIC FLARE STACK: to eliminate the need for a continuous pilot flare, reducing CO2 emissions.
- WATER MANAGEMENT: drilled a water injection disposal well and constructed water pipelines for water handling, reducing the use of trucking water loads over long distances.
- CONVERSION TO HYDRO/CLEAN POWER: planned electrical conversion of natural gas compressors and elimination of natural gas generators at the Oak 6-35 facility upon connection to BC Hydro.
The Government of British Columbia approved Kelt’s 2021 application under the “British Columbia Clean Growth Infrastructure Royalty Credit Program” whereby the Company expects to recover approximately 50% of $6.4 million in infrastructure expenditures (relating to the projects outlined above) through reduced future royalties payable relating to oil and gas sales from Kelt’s Montney wells at Oak. Kelt has made an application with BC Hydro and expects to complete its planned electrical conversion at the Oak 6-35 facility by the end of 2022. The entire project is expected to reduce CO2E emissions by approximately 19,630 tonnes annually, resulting in carbon tax savings of approximately $0.8 million per year at the current carbon tax rate of $45/tonne.
Kelt is proud of its ESG successes and would like to thank all employees and contractors who demonstrate hard work, dedication and a commitment to achieving Kelt’s goals while ensuring safe and responsible operating practices.