By Calgary, Alberta – February 17, 2022 (Newsfile Corp.) (Investorideas.com Newswire) 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.
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).
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.
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.
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).
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.
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.
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.
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.
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.
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, exploration and development activities and future drilling plans, including future drilling locations, achieving further efficiencies in production additions, FDC expenditures over the upcoming years as Kelt continues to proceed with development and pad drilling, and any significant delays between the ongoing negotiations with the Province of British Columbia and the Blueberry River First Nation, to finalize an interim approach for reviewing new natural resource activities, may impact the ability of Kelt to obtain licenses in the Province of British Columbia and could delay the Company’s future Oak delineation and development program. 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, 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.
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 FINANCIAL MEASURES AND OTHER KEY PERFORMANCE INDICATORS
This press release contains certain financial measures, as described below, which do not have standardized meanings prescribed by GAAP. In addition, this press release contains other key performance indicators (“KPI”), financial and non-financial, that do not have standardized meanings under the applicable securities legislation. As these non-GAAP financial measures and KPI 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.
“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 previously disclosed a “Net bank debt (surplus)” for its non-GAAP measure which was used to understand the Company’s liquidity risk. In the third quarter of 2021, the Company replaced its “Net bank debt (surplus)” non-GAAP measure with a “Net debt (surplus)” non-GAAP measure. “Net bank debt (surplus)” was equal to bank debt, plus current liabilities, less current assets. 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. The Company uses a “Net debt (surplus) to annualized quarterly adjusted funds from operations ratio” as a benchmark on which management monitors the Company’s capital structure and short-term financing requirements. Management believes that this ratio, as well as the Company’s “Net debt (surplus)”, provides investors with information to understand the Company’s liquidity risk. The “Net debt (surplus) to annualized quarterly adjusted funds from operations ratio” is also indicative of the “Net debt (surplus) to cash flow” 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).
“Operating income” is 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 associated financial instruments. The Company refers to operating income expressed per unit of production as an “operating netback”.
“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.
“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.
“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.
“Net asset value per share” is calculated by adding the net present value of P&NG reserves, undeveloped land value and proceeds from exercise of stock options, less the net present value of decommissioning obligations and net bank debt and dividing 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 KEL common shares as at the calculation date. All outstanding RSUs are included in diluted common shares outstanding.
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.
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
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