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

CALGARY, AB, Sept. 14, 2022 /CNW/ - 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 7x24 (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 7x24 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.

Certain information set forth in this news release contains forward-looking information and statements including, without limitation, management's business strategy, management's assessment of future plans and operations. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "project", "potential" or similar words suggesting future outcomes or statements regarding future performance and outlook. Readers are cautioned that assumptions used in the preparation of such information may prove to be incorrect. Events or circumstances may cause actual results to differ materially from those predicted as a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company.

In particular, this news release contains forward-looking statements pertaining to the following:

• the Company's growth strategy and prospects including operational and financial guidance for 2022;
• the Company's 2023 first quarter average production and year over year growth from first quarter 2022;
• the Company's indicative 2023 outlook, including number of wells drilled and completed, average production, capital expenditures, adjusted funds flow from operations and net debt to adjusted funds flow from operations;
• plant debottlenecking costs, timing and results;
• expectations regarding the further development and operation of the Company's existing upstream properties including expected production growth in 2022 and 2023;
• projections of market prices and costs;
• estimates related to project level economics of the Homestead and Opal projects, including estimates of construction costs, project NPV8 and NPV10, project run rate EBITDA, project IRR and underlying assumptions;
• estimated approximate production in total [and by product type] from the Montney Acquisition;
• the characteristics of the acquired assets including estimated production rates;
• that there is ample room for Montney production growth based on the significant spare capacity of existing owned and third-party infrastructure;
• that increased ownership of the gas processing facility provides the Company with increased processing capacity and optionality for plant optimization;
• anticipated commodity and power prices;
• the Company's drilling and development plan for the Montney Acquisition assets and Kiwetinohk's Placid Montney;
• the plans and expectations to grow the acquired production to certain plateau levels and the capital costs and the timing thereof as well as the expected annual cash flows and free cash flows therefrom; and
• the Company's business strategies, goals and plans;

In addition to other factors and assumptions that may be identified in this news release, assumptions have been made regarding, among other things:

• future oil, natural gas liquids, natural gas, and power prices;
• the Company's ability to realize on expectations regarding low supply cost, reliability and efficiency of its power generation portfolio;
• development and completion of the Company's natural gas-fired and solar power generation projects in a timely and cost-efficient manner and the Company's ability to continue to identify and progress projects for its power generation portfolio;
• capital costs and power generation capacity of the Company's proposed power generation capital projects, forecast economics, project NPV8 and NPV10, project run rate EBITDA, and project IRR of the proposed power generation capital projects.
• the Company's ability to successfully integrate its upstream business and assets with the Company's power generation portfolio;
• the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner;
• the general stability of the economic and political environment in which the Company operates;
• the regulatory framework governing royalties, electricity generation, transmission and distribution, taxes and environmental matters in the jurisdictions in which the Company conducts its business and any other jurisdictions in which the Company may conduct its business in the future;
• the Company's ability to market production of oil, condensate, NGL, natural gas, electricity, low-emissions electricity, hydrogen, CO2 and tax credits and other financial instruments as they emerge and evolve from time to time related to the production of low-emissions electricity and/or hydrogen successfully to customers;
• that the Alberta government carbon credit regime remains favourable to the Company and its projects;
• the Company's ability to buy and sell hydrocarbon gathering and processing services and carbon capture, utilization and storage services to other parties;
• the Company's future production levels;
• that the Company will have access to solar and other renewable resources in amounts and at the costs consistent with the amounts and costs expected by the Company for the development projects in its power generation portfolio;
• the nature of carbon capture technologies and the benefits of their application, including to the Company's proposed projects;
• future cash flows from production;
• future sources of funding for the Company's capital program and the Company's plans for future capital investments;
• the Company's future debt levels;
• the geography of the areas in which the Company is conducting exploration and development activities and the access, economic, regulatory and physical limitations to which the Company may be subject from time to time;
• the impact of war, hostilities, civil insurrection, pandemics (including Covid-19), instability and political and economic conditions (including the ongoing Russian-Ukrainian conflict) on the Company;
• community and stakeholder commitment to sustainable energy sources, and the Company's positioning within the sustainable energy or
  energy transition space;
• the impact of competition on the Company;
• the impact of rising inflation rates and interest rates on the North American and world economies and the corresponding impact on the Company's costs, profitability, and on crude oil, NGLs and natural gas prices;
• currency, exchange and interest rates;
• the Company's ability to obtain the support of stakeholders other than regulators which may affect the Company's ability to efficiently develop its capital projects including the cost or timing thereof; and
• the Company's ability to obtain financing necessary for the advancement of the Company's business plan on acceptable terms.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions that have been used. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements as the Company can give no assurance that such expectations will prove to be correct.

Forward-looking statements or information involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties include, among other things:

• the ability of management to execute its business plan;
• risks associated with developing and operating the power generation and renewable energy business;
• the ability of the Company to achieve its investment and development objectives;
• the ability of the Company to successfully execute its energy transition strategy;
• risks associated with exploration, development and production of crude oil and natural gas, and drilling for unconventional oil, NGL and natural gas;
• risks associated with operating and integrating a newly-combined business;
• global economic and financial conditions;
• capital markets;
• uncertainties as to the availability and cost of financing;
• licences and permits;
• government regulations;
• the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;
• fluctuations in commodity and power prices, foreign currency exchange rates and interest rates;
• the ability to secure adequate processing, transportation, fractionation and storage capacity on acceptable terms;
• health, safety and environmental risks;
• competition in the crude oil and natural gas industry;
• carbon taxes and environmental compliance costs;
• risks of war, hostilities, civil insurrection, pandemics (including Covid-19), instability and political and economic conditions in or affecting jurisdictions in which the Company operates;
• market constraints and access to services and equipment;
• talent, recruitment and retention of key personnel;
• technology risks;
• seasonality;
• environmental, health and safety requirements; and
• other risks and uncertainties described elsewhere in this document and in the Company's other filings with Canadian securities authorities.

Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties.

The forward-looking statements and information contained in this news release speak only as of the date of this news release and the Company undertakes no obligation to publicly update or revise any forward-looking statements or information, except as expressly required by applicable securities laws.

This news release contains the following measures that do not have a standardized meaning under generally accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities: free cash flow, adjusted funds flow from operations, net debt and net debt to adjusted funds flow from operations. These measures should not be considered in isolation or as a substitute for performance measures prepared in accordance with GAAP and should be read in conjunction with the consolidated financial statements of the Company. Readers are cautioned that these non-GAAP measures do not have any standardized meanings and should not be used to make comparisons between Kiwetinohk and other companies without also taking into account any differences in the method by which the calculations are prepared.

Please refer to the Corporation's MD&A as at and for the six months ended June 30, 2022, under the section "Non-GAAP Measures" for a description of these measures, the reason for their use and a reconciliation to their closest GAAP measure where applicable. The Corporation's MD&A is available on Kiwetinohk's SEDAR profile at www.sedar.com

Financial outlook and future-oriented financial information contained in this news release about prospective financial performance, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. In particular, this news release contains free cash flow, net debt, adjusted funds flow from operations and net debt to adjusted funds flow from operations. These projections contain forward-looking statements and are based on a number of material assumptions and factors set out above and are provided to give the reader a better understanding of the potential future performance of the Company in certain areas. Actual results may differ significantly from the projections presented herein. These projections may also be considered to contain future oriented financial information or a financial outlook. The actual results of the Company's operations for any period will likely vary from the amounts set forth in these projections, and such variations may be material. See above and "Risk Factors" in the Company's AIF for the year ended December 31, 2021, published on the Company's profile on SEDAR at www.sedar.com for a further discussion of the risks that could cause actual results to vary. The future oriented financial information and financial outlooks contained in this news release have been approved by management as of the date of this news release. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein.

The Company discloses a number of supplementary financial measures, including net present value (NPV8 and NPV10) and IRR, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included to provide users with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. NPV8 and NPV10 is the difference between the present value of cash inflows and the present value of cash outflows over a period of time at an 8% and 10% discount rate, respectively. IRR is a metric used in financial analysis to estimate the profitability of potential investments whereby the internal rate of return is a discount rate that makes the net present value equal to zero in a discounted cash flow analysis. Management uses these finance metrics for its own performance measurements and to provide users with measures to compare the Company's economic returns and operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics, as presented in this news release, should not be relied upon for investment or other purposes.  Refer to slide 30 of the updated corporate presentation for Green Energy project assumptions.

FOR MORE INFORMATION ON KIWETINOHK, PLEASE CONTACT:

Mark Friesen, Director, Investor Relations
IR phone: (587) 392-4395
IR email: [email protected]

Address: Suite 1900, 250 - 2 Street S.W. Calgary, Alberta T2P 0C1

Pat Carlson, CEO
Jakub Brogowski, CFO

SOURCE Kiwetinohk Energy