Kiwetinohk updates corporate presentation and is scheduled to present at the Peters & Co. Limited’s 2022 Energy Conference

CALGARY, AB – Kiwetinohk Energy Corp. (TSX: KEC) today announced it has updated its corporate presentation now available on its website at www.kiwetinohk.com.  Jakub Brogowski, Chief Financial Officer, will be presenting at the Peters & Co. Limited’s 2022 Energy Conference at 10:00 AM Eastern Time on Thursday September 15, 2022.

The Company updated 2022 guidance on August 24, 2022, following announcement of the Placid Montney asset consolidation (the Montney Acquisition) and that 2022 guidance remains unchanged.  The updated corporate presentation includes:

• Corporate GHG emission objectives and an update for timing of Kiwetinohk’s first corporate ESG report expected to be published in autumn 2022;
• Updated 2023 indicative outlook pro forma the Montney Acquisition;
• Montney Acquisition metrics on a consolidated asset basis; and
• Preliminary project level economics for the Homestead and Opal power projects.

The Montney Acquisition increases the Company’s working interest in the Placid area, adding 1,200 Boe/d of current production, 30 MMcf/d of natural gas and 1,750 bbl/d of condensate plant processing capacity, 35.2 net sections of land (~60% undeveloped) and 42.2 net Montney locations.  At a consolidated asset level, the Company expects Placid area production to plateau between 11,500 to 13,000 boe/d, at which time asset level cash flow is expected to be approximately $145 million to $180 million, based on August 19 strip pricing.  An estimated $160 million of capital is required to reach plateau production from current pro-forma level of 8,200 boe/d, requiring approximately $70 million to $85 million of capital per to sustain production rates and to deliver strong asset level free cash flow of $100 million to $125 million, based on August 19 strip pricing.  Of the $59 million closing transaction price, the Company estimates acquired facility and undeveloped land value of approximately $30 million to $45 million based on facility replacement value and recent comparable land transactions.

While Kiwetinohk has not provided corporate guidance beyond 2022 at this time, the Company provides an indicative 2023 outlook based on the assumption of similar activity levels going forward, including a 3 to 6 gross well outlook on the recently consolidated Montney acreage.  Note that the 2023 Outlook is illustrative only and does not reflect a Board of Directors approved plan and budget.  Based on a 2023 indicative drilling program of 17 to 20 wells, which incorporates the same large completion design being implemented in this year’s program, production would be expected to average 25,000 to 28,000 boe/d, roughly half of which would be natural gas.  First quarter 2023 average production is expected to be in the range of 23,000 boe/d to 24,000 boe/d.  Capital for the year for this drilling cadence, along with required supporting infrastructure such as infield infrastructure and plant debottlenecking capital, would be estimated to be in the range of $390 million to $425 million, supporting adjusted funds flow from operations of $480 million to $530 million based on commodity price strip prices as of August 19.  At these commodity prices and illustrative outlook, Kiwetinohk would expect to exit 2023 with a net debt to adjusted funds flow from operations ratio between 0.1x to 0.3x, well below Kiwetinohk’s acceptable ceiling level of 1.0x

The Homestead Solar project and the Opal Firm Renewable project are progressing toward financing and final investment decision (FID).  Homestead has an estimated project level levered net present value (NPV)_BT8 of $120 million, a run rate EBITDA of $75 million to $85 million and an internal rate of return (IRR) of over 11% based on the principal assumptions noted below. Opal has an estimated project level, unlevered NPV_BT10 of over $110 million; sensitizing Opal to a higher natural gas price increases the estimated unlevered NPV_BT10 to over $440 million.  Integrating Kiwetinohk’s natural gas production into the Opal project, further increases the estimated value in both scenarios to more than $180 million and to more than $570 million respectively, based on the principal assumptions noted below.

Estimated before tax project-level economics are illustrative and based on a number of assumptions and other factors which may change and any such change(s) could have a material effect on such estimated project level economics.  In addition, estimated project-level economics reflect the estimated economics for the entire project and not Kiwetinohk’s estimated economics from the project as Kiwetinohk’s equity in the project may not be 100%. Kiwetinohk’s final economic exposure to these projects will ultimately depend on the Company’s final working interest as well as carried percentage and financing arrangements. See project principal assumptions detailed below and “Forward-looking statements” and “supplementary financial measures”.

Homestead Solar project principal assumptions:

• Power price per EDC Associates Ltd. Q3 2022 7×24 (all hours pricing forecast) less 21% monthly average solar discount.
• First year capacity factor of 27.2%.
• Environmental attribute revenue per EDC Associates Ltd. under proposed Clean Electricity Regulations (CER).
• Construction capital assumes 35% equity and 65% debt. Illustrative capital cost based on Class 2 and 3 estimates for Kiwetinohk’s current power portfolio projects as noted on page 26 of the updated corporate presentation.
• Levered NPV_BT8 and IRR assumes 65% project debt financing with a 7% interest rate, and upon the commercial operations date (COD) converted to 20-year term debt with a 5% interest rate and 20-year amortization period.

Opal project principal assumptions:

• Power price EDC Associates Ltd. Q3 2022 7×24 plus 40% peak price premium, run time of 50%, and $5/MWh ancillary service revenue.
• Natural gas price per EDC Associates Ltd. Q3 2022. The EDC Associates Ltd. gas price sensitivity case uses $8.00/GJ natural gas price and EDC Associates Ltd. Q3 2022 market heat rate forecast to generate the corresponding power price plus a 40% peak price premium.
• Natural gas cash costs for integrated Opal are $2.00/GJ and $3.25/GJ for the EDC Associates Ltd. and $8.00/GJ cases. Integrated natural gas cash cost includes allocations for royalty expense, operating cost expense, and capital.
• Capital costs based on 2021-year-end McDaniel Reserves Report proved Corporate Reserves forecast. Capital costs allocated to gas based on economic value of gas resource.
• Operating cost expense based on run rate operating cost of Kiwetinohk’s business (2022-2025).
• Federal carbon tax assumptions reflect proposed CER system with carbon taxes escalating to $170/tonne by 2030, are escalated by 2% until the end of the EDC forecast (2036) and held flat thereafter.
• Construction capital assumes 50% equity and 50% debt. Illustrative capital cost based on Class 2 and 3 estimates for Kiwetinohk’s current power portfolio projects. Opal Firm Renewable project economics reflect a sensitivity of 15% – 20% increase in capital cost, as the final capital cost is expected to increase due to the current economic environment, inflation and supply chain challenges as noted on page 26 of the corporate presentation.

Kiwetinohk continues to advance three solar projects toward FID, with a combined generation capacity of 850 MW.  These zero-carbon renewable energy projects are a critical pilar of the Company’s energy transition model, supporting the Company’s “net zero” GHG emission objective.

Barrel of Oil Equivalency

The term “boe” may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas per barrel of oil (6 mcf:1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from an energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

Drilling Locations

This news release discloses drilling locations or inventory. The table below shows the total locations broken down into proved locations, probable locations and unbooked locations. Proved locations and probable locations are derived from McDaniel’s reserves evaluation as of December 31, 2021, and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources.

Unbooked locations consist of drilling locations that have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production, and reserves information. There is no certainty that we will drill all of these drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources, or production. The drilling locations on which we drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

References to petroleum, crude oil, NGLs (natural gas liquids), natural gas and average daily production in this news release refer to the light and medium crude oil, tight crude oil, conventional natural gas, shale gas and NGLs product types, as applicable, as defined in NI 51-101.

NI 51-101 includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and separately from other NGLs since the price of condensate as compared to other NGLs is currently significantly higher, and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light oil, medium oil, tight oil, and condensate. NGLs refers to ethane, propane, butane, and pentane combined. Natural gas refers to conventional natural gas and shale gas combined.