Kiwetinohk Announces Corporate Update

Source: www.gulfoilandgas.com 1/12/2022, Location: North America

Kiwetinohk Energy Corp. provides a corporate update and announces its 2022 capital expenditures budget and production guidance.

“This budget is designed to deliver strong baseline cash flow from the upstream business while advancing power projects toward FID,” said CEO Pat Carlson. “The 2022 budget is a further step toward our goal of being a low-cost supplier of natural gas and reliable, dispatchable, low-emission gas-fired and renewable electricity.”

Highlights
• Production guidance for 2022 of 13,000 to 15,000 boe/d with 5 of 11 gross wells to be completed in 2023;
• 2022 capital expenditures budget of $210 to $240 million (subject to commodity prices after hedging) including $10 to $20 million allocated to green energy;
• Advancing five solar and gas-fired power projects totaling 1,800 megawatts (MW) of nameplate generation capacity toward Final Investment Decision (FID);
• At US$70/bbl WTI and US$3.75/MMBtu Henry Hub, expected to deliver approximately $120 to $150 million of Adjusted Funds Flow(1) and 22% - 28% return on average capital employed(2) supported by strong marketing and commodity hedging positions;
• The Toronto Stock Exchange (the TSX) has confirmed that Kiwetinohk’s common shares will be listed on the TSX on Friday, January 14 with the trading symbol KEC;

Green Energy update and capital expenditures
Kiwetinohk has allocated $10 to $20 million of capital in 2022 for pre-FID planning and approvals and securing financing to advance power projects to FID. The Company expects to spend, depending on the project, $3 to $8 million to bring each project to FID. At FID, the Company expects to retain a carried-partnership interest that reflects the higher risk to which it has been exposed to achieve FID. Although Kiwetinohk is also considering other financial structures, this approach to financing, when it works as planned, will enable Kiwetinohk to participate in projects of this nature with returns aligned with its upstream business.

The five power projects with a total nameplate generation capacity of 1,800 MW in early-stage development include:
• one 101 MW Firm Renewable(3) project in the Alberta Electric System Operator (AESO) Stage 2;
• two solar projects in AESO Stage 1 and 2 for a total of 700 MW; and
• two natural gas combined cycle (NGCC) projects in AESO Stage 1 and 2 for a total of 1,000 MW.

The Company is targeting to have a 400 MW solar project and the 101 MW Firm Renewable project achieve FID by year-end 2022.

Kiwetinohk made significant progress in 2021 in advancing its diversified, solar and gas-fired development power portfolio including site selection and acquisition, permitting, environmental studies, community engagement, AESO stage advancement and engineering and economic evaluation. In addition to its ongoing greenfield development program, the Company is evaluating acquisition and partnership opportunities for pre-construction solar and wind projects, as well as hydrogen production opportunities, which complement and expand Kiwetinohk’s existing power portfolio. The Company has updated the target FID and Commercial Operation Date (COD) for its first Firm Renewable and its 400 MW solar project to year-end 2022 and year-end 2024.

The Company's ten-year vision is to generate over 1,500 MW of electricity (over 10% of Alberta grid capacity) from solar, wind and natural gas, with a goal to capture over 90% of the carbon associated with the Company's gas-fired power and hydrogen production operations.

Upstream capital expenditures and guidance
The 2022 upstream capital budget is $200 to $220 million and production guidance is 13,000 to 15,000 boe/d. Expenditures will be subject to commodity prices and will focus in Kiwetinohk’s Fox Creek core area where the Company plans to drill 11 gross wells. During 2022 Kiwetinohk expects to bring 4 wells drilled in late 2021 onto production in the first half of the year, 6 of the 11 new 2022 drilled wells onto production in the second half of the year and 5 of the 11 new 2022 drilled wells onto production in the first half of 2023. Detailed execution plans will address limited surface access and preservation of protected species requirements in Fox Creek. As a result, Kiwetinohk estimates an average time from start of drilling to production of 8 months for the well pads in this year’s program.

The Fox Creek core area provides a low decline production base from which to grow but also requires some investment lead-time due to under-investment for the past few years. Kiwetinohk plans to invest in Fox Creek to increase production and cash flow. Future free cash flow can be channeled to fund additional green energy investment and return capital to investors. The plan is to integrate low-cost natural gas production with clean, reliable, dispatchable and low-cost electricity and hydrogen. The Company acquired these assets for ~$10/boe Proved Developed Producing (PDP) Reserves, or ~$4/boe Total Proved (TP) Reserves, and the assets had a operating netback (before financial hedging) of ~$31/boe in the third quarter of 2021, resulting in a >3x recycle ratio(4).

2022 will be an investment year to arrest declines and commence growing production to fill the property’s facilities, which are currently operating at less than half capacity at Fox Creek. A total of $170 to $185 million is budgeted for drilling, completing, equipping and tie-in (DCET) activity during 2022. The production profile will be back-end weighted with 5 of 11 new wells anticipated to come on production in 2023. As a result of the planned drilling schedule, Kiwetinohk expects production to average 20,000 to 21,000 boe/d during the first quarter of 2023 increasing from currently expected production for first quarter of 2022 of 11,000 to 12,000 boe/d. Anticipated production for Q1 2022 reflects:

• natural production declines;
• typical first quarter weather-related production interruptions;
• minimal contribution from the Company’s drilling activity launched in late 2021; and
• temporary shut-in of producing wells offsetting newly drilled wells to minimize interference during completion activities.

The result is the current decline rate from Q3 2021 to Q1 2022 appears steeper than the established decline rate of the area. The Fox Creek assets have only had a modest amount of capital spent on drilling in recent years by previous operators. As such, the annual production decline rates are relatively shallow in comparison to tight shale gas resource assets that have experienced more consistent allocation of drilling capital. When deploying a significant amount of capital to such upstream assets that have not been drilled for a number of years, the Company expects that the first year of production growth (i.e. 2023 over 2022) will be at a very high rate moderating with time and ongoing drilling.

There are no land expiry issues driving the Company’s operating plans in the Fox Creek Duvernay. After the development program is underway, the investments of one year will better align with the production additions from the prior year of investment for accurate annual capital efficiency calculations.

In the Montney, two wells (gross/net) drilled in late 2021 are scheduled for tie-in during the second quarter of 2022. One step-out delineation well (0.65 net) is planned during 2022 with an early 2023 tie-in, therefore not contributing to 2022 production or cash flow.

The Company’s producing assets, in the vast majority, are tight shale gas resources. The Company uses horizontal wells with multiple hydraulic fractures along the horizontal lateral. In Kiwetinohk’s view, this technology is not mature and reliable models based on physics and/or statistics do not exist. Despite the inadequacies of the approach, the Company looks for correlation between well performance and controllable factors (such as well lateral spacing, lateral length, number of fracs, frac slurry volume, frac pump rate) and uncontrollable factors (such as pressure-depth ratio, resource thickness, condensate to gas ratio, original gas in place per square metre). Performance is thereby estimated with reservations about accuracy from judgements made relative to this kind of data analysis. In order to account for unexpected outcomes, the Company includes capital without production for 1 well out of each 10 planned.

Corporate guidance

Contingent payment
As disclosed at the time of a large property acquisition in April 2021, the Company agreed to 2 contingent payments totaling up to $15 million subject to average 2021 and average 2022 WTI prices. As WTI averaged over US$56/bbl during 2021, a $5 million contingent payment will be made to the vendor in January of 2022. Should WTI oil prices average over US$62/bbl during calendar 2022, a final $10 million contingent payment will be made to the vendor in January of 2023.

Asset Retirement Obligations (ARO):
Kiwetinohk has ~$30 million of inactive ARO(5) liabilities, which it expects to retire over the next 5 to 7 years. Kiwetinohk maintains an attractive Alberta Energy Regulator’s (AER) LMR Liability Rating over 5.

Risk management:
Kiwetinohk has a risk management program designed to protect returns on capital deployed. The Company targets to hedge up to 75% of its first 12 months of future production as it is brought onstream. To date, Kiwetinohk has used a combination of fixed price swaps and costless collars. Please see the Company’s updated hedging summary below for a full detail of Kiwetinohk’s current hedging contracts.

As Kiwetinohk advances its green energy projects toward FID it will look to contract power and hydrogen as appropriate.

Marketing activities:
Kiwetinohk has 120 MMcf/d of contracted transportation capacity on Alliance Pipeline, which is approximately 70 MMcf/d more than the Company’s consolidated third quarter 2021 production. The Company buys third-party natural gas to fill unused capacity. Future gains or losses on marketing activities are dependent on commodity prices, the price of natural gas in Chicago and Alberta and foreign exchange rates net of the cost of transportation. The Company targets back-to-back contracts to avoid speculative natural gas price exposure. Kiwetinohk estimates break-even marketing revenues at an AECO-Chicago basis of approximately US$0.70/MMBtu at current foreign exchange rates.


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