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Kolibri Global Energy (KGEI) Webinar on Feb 29
Kolibri Global Energy (KGEI) Webinar on Feb 29
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Kolibri Global Energy (KGEI) Webinar on Feb 29
Read this before today's webinar. It is from Kolibri's press release on January 29.
------------------------------
2024 Guidance > The Company is providing its forecasted guidance for 2024 as follows:
2024 Forecast % Increase from 2023 Guidance Range
> Average production 3,500 to 4,000 boepd 25% to 33%
> Revenue(1) US$60 million to US$65 million 18% to 23%
> Adjusted EBITDA(2) US$46 million to US$51 million 18% to 24%
> CAPEX US$33 million to US$39 million
> Net Debt US$25 million to US$27 million with year-end Debt to EBITDA Ratio Below 1.0
Footnotes:
(1) Assumptions include forecasted pricing for 2024 of WTI US $72/bbl, $2.60 Henry Hub, and NGL pricing of
$28.40/boe and includes the impact of the Company’s existing hedges.
(2) Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures”
of this news release
The strategy of the Company for 2024 is to continue to develop the field by converting its
significant number of proved undeveloped wells into producing wells that generate cash flow. The
average production, revenue, and Adjusted EBITDA guidance for 2024 shows significant growth
from the latest 2023 forecast numbers, even with a $72 WTI price assumption. As the Company
executes this strategy going forward, it will consider the implementation of a shareholder return
policy in 2024. If all goes as planned, will Kolibri start paying dividends in 2H 2024?
The Company anticipates completing 6-7 wells this year. The Company plans to drill and
complete two wells in the 2nd quarter, drill two to three additional wells later in the year, and then
fracture stimulate the two to three additional wells together with the two Velin wells that the
Company just finished drilling. Why were the two Velin wells that TD'd in December not completed?
Wolf Regener, President and CEO, commented, “We are looking forward to another strong year
of revenue and cash flow growth for the Company, based on our 2024 forecast. We are also very
pleased with our team’s execution. The constant improvement that we strive for has led to a large
reduction in our well costs. The forecasted well costs were $7.2 million last year, and the cost for
the last two Emery wells was about $5.4 million, which is a 25% reduction in well costs.”
This is a significant decrease in completed well costs! For an average Caney well, what is the oil price needed to break even?
Operations Update
The three well Emery pad averaged a total of 960 Barrels of Oil Equivalent per day (“BOEPD”)
(710 Barrels of Oil per day (“BOPD”)) for the first 30 days of production and averaged 1,010
BOEPD (755 BOPD) for five days last week. As previously disclosed, more fracture stimulation
fluid is being recovered from all three wells than from our previous wells, which Management
believes explains the slight uptick in the recent production numbers. Based on our preliminary
analysis, the technical team believes that there is increased natural fracturing in certain areas of
the field, which appears to allow the fracture stimulations to communicate between the T-zone
and the Caney. This connection is likely the cause of the different flowback and early production
profiles of the Emery wells, with more fluid having been pushed into the Caney. The Company is
still conducting further analysis work on the tracers, production, and pressure data that is
continuing to be gathered and intends to complete that analysis before drilling additional T-zone
wells. Does this lower your optimism about the potential of the T-zone?
The three Emery wells were drilled and completed for about US$5.6 million each, with the last
two averaging US$5.4 million each. The last two were drilled utilizing efficiency changes
implemented part-way through drilling the first Emery well. The Company continues to improve
its efficiency in its field operations as the well costs of US$5.4 million are substantially lower than
the well costs of US$7.2 million that were forecast in early 2023 and are also lower than the
US$6.0 million cost of the last two wells, the Barnes 7-4H and Barnes 7-5H.
The Company recently finished drilling the Velin 12-9H well and the Velin 12-10H well, which are
both Caney wells. Both wells were drilled safely and on budget. As the Company continues to
analyze the flowback profile from the three-well Emery pad, the drilling rig has been released as
it determined not to drill the previously planned T-zone well.
Also, as previously disclosed, the fracture stimulation of these three Emery wells impacted the
surrounding wells more than was originally anticipated, which was likely also caused by increased
natural fracturing. These wells have continued to recover, and the Company continues to expect
that recovery to take several months. Have the surrounding wells impacted by completion of the 3 Emery wells fully recovered?
Like many other operators, the Company's operations were impacted by the below-freezing
temperatures in January 2024. This caused much of the Tishomingo field to be shut in for 9 to
14 days. The Company is currently restoring production and anticipates it will be fully restored
this week. Prior to the freeze, the field was producing about 3,800 BOEPD. < Has production fully recovered from the January freeze?
------------------------------
2024 Guidance > The Company is providing its forecasted guidance for 2024 as follows:
2024 Forecast % Increase from 2023 Guidance Range
> Average production 3,500 to 4,000 boepd 25% to 33%
> Revenue(1) US$60 million to US$65 million 18% to 23%
> Adjusted EBITDA(2) US$46 million to US$51 million 18% to 24%
> CAPEX US$33 million to US$39 million
> Net Debt US$25 million to US$27 million with year-end Debt to EBITDA Ratio Below 1.0
Footnotes:
(1) Assumptions include forecasted pricing for 2024 of WTI US $72/bbl, $2.60 Henry Hub, and NGL pricing of
$28.40/boe and includes the impact of the Company’s existing hedges.
(2) Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures”
of this news release
The strategy of the Company for 2024 is to continue to develop the field by converting its
significant number of proved undeveloped wells into producing wells that generate cash flow. The
average production, revenue, and Adjusted EBITDA guidance for 2024 shows significant growth
from the latest 2023 forecast numbers, even with a $72 WTI price assumption. As the Company
executes this strategy going forward, it will consider the implementation of a shareholder return
policy in 2024. If all goes as planned, will Kolibri start paying dividends in 2H 2024?
The Company anticipates completing 6-7 wells this year. The Company plans to drill and
complete two wells in the 2nd quarter, drill two to three additional wells later in the year, and then
fracture stimulate the two to three additional wells together with the two Velin wells that the
Company just finished drilling. Why were the two Velin wells that TD'd in December not completed?
Wolf Regener, President and CEO, commented, “We are looking forward to another strong year
of revenue and cash flow growth for the Company, based on our 2024 forecast. We are also very
pleased with our team’s execution. The constant improvement that we strive for has led to a large
reduction in our well costs. The forecasted well costs were $7.2 million last year, and the cost for
the last two Emery wells was about $5.4 million, which is a 25% reduction in well costs.”
This is a significant decrease in completed well costs! For an average Caney well, what is the oil price needed to break even?
Operations Update
The three well Emery pad averaged a total of 960 Barrels of Oil Equivalent per day (“BOEPD”)
(710 Barrels of Oil per day (“BOPD”)) for the first 30 days of production and averaged 1,010
BOEPD (755 BOPD) for five days last week. As previously disclosed, more fracture stimulation
fluid is being recovered from all three wells than from our previous wells, which Management
believes explains the slight uptick in the recent production numbers. Based on our preliminary
analysis, the technical team believes that there is increased natural fracturing in certain areas of
the field, which appears to allow the fracture stimulations to communicate between the T-zone
and the Caney. This connection is likely the cause of the different flowback and early production
profiles of the Emery wells, with more fluid having been pushed into the Caney. The Company is
still conducting further analysis work on the tracers, production, and pressure data that is
continuing to be gathered and intends to complete that analysis before drilling additional T-zone
wells. Does this lower your optimism about the potential of the T-zone?
The three Emery wells were drilled and completed for about US$5.6 million each, with the last
two averaging US$5.4 million each. The last two were drilled utilizing efficiency changes
implemented part-way through drilling the first Emery well. The Company continues to improve
its efficiency in its field operations as the well costs of US$5.4 million are substantially lower than
the well costs of US$7.2 million that were forecast in early 2023 and are also lower than the
US$6.0 million cost of the last two wells, the Barnes 7-4H and Barnes 7-5H.
The Company recently finished drilling the Velin 12-9H well and the Velin 12-10H well, which are
both Caney wells. Both wells were drilled safely and on budget. As the Company continues to
analyze the flowback profile from the three-well Emery pad, the drilling rig has been released as
it determined not to drill the previously planned T-zone well.
Also, as previously disclosed, the fracture stimulation of these three Emery wells impacted the
surrounding wells more than was originally anticipated, which was likely also caused by increased
natural fracturing. These wells have continued to recover, and the Company continues to expect
that recovery to take several months. Have the surrounding wells impacted by completion of the 3 Emery wells fully recovered?
Like many other operators, the Company's operations were impacted by the below-freezing
temperatures in January 2024. This caused much of the Tishomingo field to be shut in for 9 to
14 days. The Company is currently restoring production and anticipates it will be fully restored
this week. Prior to the freeze, the field was producing about 3,800 BOEPD. < Has production fully recovered from the January freeze?
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group