THOUSAND OAKS, Calif. – All amounts are in U.S. Dollars unless otherwise indicated:
THIRD QUARTER 2023 HIGHLIGHTS
- Average production for the third quarter of 2023 was 2,737 BOEPD, an increase of 61% compared to third quarter 2022 production of 1,702 BOEPD. This increase is due to production from the Emery 17-2H, the Brock 9-3H and the Glenn 16-3H wells, which started production at the end of 2022, and the Barnes 8-1H, Barnes 8-2H and Barnes 8-3H wells, which started production in the last week of June 2023. The production increases were partially offset by production restrictions due to the Company’s gathering system operator, existing wells that were shut-in while completion operations were underway and a few well reworks. These reduced third quarter production by approximately 200 BOEPD
- Adjusted EBITDA(1) was $9.5 million in the third quarter of 2023 compared to $6.9 million in the third quarter of 2022, an increase of 39%. The increase was primarily due to an increase in production of 61% and lower realized losses on commodity contracts, partially offset by a decrease in average prices of 20%
- Revenue, net of royalties was $12.7 million in the third quarter of 2023 compared to $9.9 million for the third quarter of 2022, which was an increase of 29%, as production increased by 61% partially offset by a decrease in average prices of 20%
- Net income for the third quarter of 2023 was $2.3 million and Basic EPS was $0.07/share compared to net income of $9.3 million and Basic EPS of $0.26 for the third quarter of 2022. The decrease was mainly due to an unrealized loss on commodity contracts of $2.6 million in the third quarter of 2023 versus an unrealized gain on commodity contracts of $4.6 million that was recorded in the third quarter of 2022. In addition, the third quarter of 2023 had lower average prices and higher depreciation expense which was offset by higher production compared to the third quarter of 2022
- Average netback from operations(2) for the third quarter of 2023 was $43.28/boe, a decrease of 22% from the prior year third quarter due to lower prices in 2023. Average netback including commodity contracts(2) for the third quarter of 2023 was $41.65 per boe, a decrease of 16% from the prior year third quarter due to lower prices
- Production and operating expenses per barrel averaged $7.34 per BOE in the third quarter of 2023 compared to $7.77 per BOE in the third quarter of 2022, a decrease of 6%. The $7.34 per BOE in the third quarter includes prior month costs, which our gathering system operator had underbilled for previous periods. In addition, due to the Company’s recent completion operations, some of the adjacent existing wells are producing additional water, which is expected to decrease over time
- In October 2023, the credit facility was redetermined with the same $40 million borrowing base. At September 30, 2023, the Company had $15.8 million of available borrowing capacity on its credit agreement and its net debt outstanding was $23.8 million
|
(1) |
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
|
(2) |
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
KEI’s President and Chief Executive Officer, Wolf Regener commented:
“We are pleased that the Company continues to grow our operations with third quarter 2023 adjusted EBITDA(1) of $9.5 million, a 39% increase from the prior year quarter. With the Barnes 7-4H and the Barnes 7-5H wells starting production at the beginning of October and the Emery 17-3H, 17-4H and 17-5H wells expected to start production at the beginning of December, we expect a continued increase in our cash flow in the fourth quarter. The Barnes 7-4H well had a thirty-day production rate of 665 BOEPD, and the Barnes 7-5H had a thirty-day production rate of 613 BOEPD.
“We are also continuing to improve the efficiency of our field operations as the Barnes 7-4H and Barnes 7-5H wells had an average total cost of approximately $6 million per well and the 3 Emery wells were drilled at an average time of only 11 days each. This is a dramatic improvement, as we were estimating 20-day wells at the beginning of this year. We expect to start completion operations for the Emery 17-3H, 17-4H and 17-5 wells in the next week and expect them to begin producing in early December. We are excited to apply our new completion technique to the Emery 17-4H well, which is the second well we have drilled in the T-zone, to demonstrate the repeatability of making economic wells in this new formation.
“We have also scheduled to begin drilling the first well in our next 3 well pad in mid-December. The three well pad will consist of two lower Caney wells and one T-zone well.
“Average production for the third quarter of 2023 was 2,737 BOEPD, an increase of 61% compared to third quarter 2022 production of 1,702 BOEPD due to production from the Emery 17-2H, the Brock 9-3H and the Glenn 16-3H wells, which started production at the end of 2022, and the Barnes 8-1H, Barnes 8-2H and Barnes 8-3H wells, which started production in the last week of June 2023, partially offset by the wells that were shut-in during completion operations and the production restrictions from the gathering system operator.
“Adjusted EBITDA(1) was $9.5 million for the third quarter of 2023 compared to $6.9 million for the prior year third quarter, an increase of 39%. The increase was due to the increase in production partially offset by a decrease in average prices.
“Net revenue was $12.7 million in the third quarter of 2023 compared to $9.9 million for third quarter of 2022, which was an increase of 29% due to higher production partially offset by lower prices.
“Net income for the third quarter of 2023 was $2.3 million compared to net income of $9.3 million for the third quarter of 2022. The decrease was mainly due to an unrealized loss on commodity contracts of $2.6 million in the third quarter of 2023 versus an unrealized gain on commodity contracts of $4.6 million that was recorded in the third quarter of 2022. In addition, the third quarter of 2023 had lower average prices and higher depreciation expense, which was offset by higher production compared to the third quarter of 2022.
“Netback from operations(2) decreased to $43.28 per BOE in the third quarter of 2023 compared to $55.16 per BOE in the same period of 2022, a decrease of 22%. Netback including commodity contracts(2) for the third quarter of 2023 was $41.65 per BOE compared to $49.69 in 2022, a decrease of 16% from the prior year period. The 2023 decreases compared to the same periods in the prior year were due to the decrease in average prices.
“Operating expenses averaged $7.34 per BOE in the third quarter of 2023 compared to $7.77 per BOE in the third quarter of 2022, a decrease of 6%. The $7.34 per BOE in the third quarter includes prior month costs, which our gathering system operator had underbilled for previous periods. In addition, due to the Company’s recent completion operations, some of the adjacent existing wells are producing additional water, which is expected to decrease over time.”
|
|
Third Quarter |
|
First Nine Months |
|
||||||||||||||
|
2023 |
2022 |
% |
2023 |
2022 |
% |
|||||||||||||
|
Net Income: |
||||||||||||||||||
|
$ Thousands |
$2,319 |
$9,299 |
(76)% |
$14,396 |
$13,850 |
4% |
||||||||||||
|
$ per basic common share |
$0.07 |
$0.26 |
(73)% |
$0.41 |
$0.39 |
5% |
||||||||||||
|
$ per diluted shares |
$0.06 |
$0.26 |
(77)% |
$0.40 |
$0.39 |
3% |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
Capital Expenditures |
$17,247 |
$4,940 |
249% |
$37,177 |
$19,913 |
87% |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Average Production (Boepd) |
2,737 |
1,702 |
61% |
2,780 |
1,563 |
78% |
||||||||||||
|
Average Price per BOE |
$65.05 |
$80.89 |
(20)% |
$62.19 |
$84.19 |
(26)% |
||||||||||||
|
Average Netback from operations(2) per Barrel |
$43.28 |
$55.16 |
(22)% |
$42.48 |
$57.05 |
(26)% |
||||||||||||
|
Average Netback including commodity contracts(2) per Barrel |
$41.65 |
$49.69 |
(16)% |
$41.00 |
$48.50 |
(15)% |
||||||||||||
|
September |
June |
December |
||||||||||||||||
|
Cash and Cash Equivalents |
$ |
501 |
|
$ |
975 |
|
$ |
1,037 |
|
|||||||||
|
Working Capital |
$ |
(13,093 |
) |
$ |
(8,274 |
) |
$ |
(6,569 |
) |
|||||||||
|
Borrowing capacity |
$ |
15,842 |
|
|
$ |
21,842 |
|
|
$ |
6,842 |
|
|
||||||
|
(1) |
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
|
(2) |
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
Third Quarter 2023 versus Third Quarter 2022
Oil and gas gross revenues totaled $16.4 million in the third quarter of 2023 versus $12.7 million in the third quarter of 2022, an increase of 29%. Oil gross revenues totaled $15.3 million in the third quarter of 2023 versus $10.8 million in the third quarter of 2022. Oil revenues increased $4.5 million or 42% as oil production increased by 66% to 2,083 BOPD partially offset by average oil price decreases of 15%. Natural gas revenues decreased by $0.6 million or 62% as natural gas prices decreased 74% partially offset by production increases of 45%. Natural gas liquids (NGLs) revenues decreased $0.2 million or 18% as NGL prices decreased 44% to $19.84/boe partially offset by production increases of 46%.
Average third quarter 2023 production per day increased 1,035 boepd or 61% from the third quarter of 2022. The increase was due to the Emery 17-2H, the Brock 9-3H and the Glenn 16-3H wells, which started production at the end of 2022, and the Barnes 8-1H, Barnes 8-2H and Barnes 8-3H wells, which started production in the last week of June 2023, partially offset by the wells that were shut-in during completion operations and the production restrictions from the gathering system operator.
Production and operating expenses increased to $1.6 million in the third quarter of 2023, an increase of 34% due to increased production. Operating expenses averaged $7.34 per BOE for the third quarter of 2023 compared to $7.77 per BOE for the same period in 2022. The $7.34 per BOE in the third quarter includes prior month costs which our gathering system operator had underbilled for previous periods. In addition, due to the Company’s recent completion operations, some of the adjacent existing wells are producing additional water, which is expected to decrease over time.
Depletion and depreciation expense increased $1.9 million or 104% due to increased production and a higher PP&E balance.
General and administrative expenses increased $0.3 million or 29% in the third quarter of 2023 due to higher costs associated with the dual listing process, higher investor relations and marketing costs and increases in payroll costs.
Finance income decreased by $4.6 million in the third quarter of 2023 compared to the third quarter of 2022 due to realized gains on commodity contracts in the third quarter of 2022.
Finance expense increased by $2.5 million in the third quarter due to unrealized losses on commodity contracts in the third quarter of 2023.
FIRST NINE MONTHS 2023 HIGHLIGHTS
- Average production for the nine months ended September 30, 2023 was 2,780 BOEPD, an increase of 78% from the average production of 1,563 BOEPD in the same period of 2022. This increase is due to production from the Emery 17-2H, the Brock 9-3H and the Glenn 16-3H wells, which started production at the end of 2022, and the Barnes 8-1H, Barnes 8-2H and Barnes 8-3H wells, which started production in the last week of June 2023, partially offset by the wells that were shut-in during completion operations and the production restrictions from the gathering system operator
- Adjusted EBITDA(1) was $28.6 million for the nine months ended September 30, 2023 compared to $18.3 million for the prior year period, an increase of 57%. The increase was primarily due to an increase in production of 78% partially offset by a decrease in average prices of 26%
- Revenue, net of royalties was $37.2 million in the first nine months of 2023 compared to $27.8 million for the first nine months of 2022, which was an increase of 34%, as production increased by 78% partially offset by a decrease in average prices of 26%
- Net income for the first nine months of 2023 was $14.5 million and Basic EPS was $0.41/share compared to $13.9 million and Basic EPS of $0.39/share for the first nine months of 2022 primarily due to an increase in production, partially offset by a decrease in average prices and higher depreciation expense
- Average netback from operations(2) for the first nine months of 2023 was $42.48/boe, a decrease of 26% from the prior year period due to lower prices in 2023. Netback including commodity contracts(2) for the first nine months of 2023 was $41.00/boe which was 15% lower than the prior year period
- Production and operating expenses per barrel averaged $6.47 per BOE in the first nine months of 2023 compared to $8.17 per BOE in the first nine months of 2022 due to increased production which reduced the per barrel fixed costs
|
(1) |
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
|
(2) |
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
First Nine Months of 2023 versus First Nine Months of 2022
Oil and gas gross revenues totaled $47.2 million in the first nine months of 2023 versus $35.9 million in the first nine months of 2022, an increase of 31%. Oil revenues were $43.5 million in the first nine months of 2023 versus $31.3 million in the same period of 2022, an increase of 39%, as average production increased by 86% partially offset by a decrease in oil prices of 25%. Natural gas revenues decreased $0.7 million or 34% due to an average natural gas price decrease of 57% partially offset by a 55% increase in natural gas production. NGL revenue decreased $0.2 million or 9% due to an average NGL price decrease of 43% partially offset by an increase in NGL production of 59% in the first nine months of 2023 compared to the comparable prior year period.
Average production per day for the first nine months of 2023 increased 78% to 2,780 boepd from the prior year comparable period. This increase is due to production from the Emery 17-2H, the Brock 9-3H and the Glenn 16-3H wells which started production at the end of 2022 and the Barnes 8-1H, Barnes 8-2H and Barnes 8-3H wells which started production in the last week of June 2023, partially offset by the wells that were shut-in during completion operations and the production restrictions from the gathering system operator.
Production and operating expenses increased to $4.3 million or 24% in the first nine months of 2023 compared to the prior year period. Production and operating expenses per barrel averaged $6.47 per BOE in the first nine months of 2023 compared to $8.17 per BOE in the first nine months of 2022 due to increased production which reduced the per barrel fixed costs.
Depletion and depreciation expense increased $6.4 million due to increased production and a higher PP&E balance.
General and administrative expenses increased $0.7 million or 28% in the first nine months of 2023 due to higher costs associated with the dual listing process, higher investor relations and marketing costs and increases in payroll costs.
Finance income decreased by $1.6 million due to unrealized gains on financial commodity contracts recorded in the first nine months of 2022.
Finance expense decreased $1.2 million in the first nine months of 2023 due to lower realized losses on commodity contracts partially offset by higher interest expense.
|
KOLIBRI GLOBAL ENERGY INC. |
||||||||
|
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION |
||||||||
|
(Unaudited, Expressed in Thousands of United States Dollars) |
||||||||
|
($000 except as noted) |
||||||||
|
|
|
|
|
|
||||
|
|
|
September 30 |
|
December 31 |
||||
|
|
|
2023 |
|
2022 |
||||
|
Current Assets |
||||||||
|
Cash and cash equivalents |
$ |
501 |
|
$ |
1,037 |
|
||
|
Trade and other receivables |
|
5,405 |
|
|
5,773 |
|
||
|
Other current assets |
|
1,094 |
|
|
670 |
|
||
|
|
|
7,000 |
|
|
7,480 |
|
||
|
Non-current assets |
||||||||
|
Property, plant and equipment |
|
203,217 |
|
|
176,554 |
|
||
|
Right of use assets |
|
1,528 |
|
|
48 |
|
||
|
|
|
204,745 |
|
|
176,602 |
|
||
|
Total Assets |
$ |
211,745 |
|
$ |
184,082 |
|
||
|
Current Liabilities |
||||||||
|
Trade and other payables |
|
16,995 |
|
$ |
12,596 |
|
||
|
Lease payable |
|
1,116 |
|
|
32 |
|
||
|
Fair value of commodity contracts |
|
1,982 |
|
|
1,421 |
|
||
|
|
|
20,093 |
|
|
14,049 |
|
||
|
|
|
|
||||||
|
Non-current liabilities |
|
|
||||||
|
Loans and borrowings |
|
23,809 |
|
|
17,799 |
|
||
|
Asset retirement obligations |
|
1,873 |
|
|
1,425 |
|
||
|
Lease payable |
|
364 |
|
|
17 |
|
||
|
Fair value of commodity contracts |
|
294 |
|
|
594 |
|
||
|
|
|
26,340 |
|
|
19,835 |
|
||
|
|
|
|
||||||
|
Equity |
||||||||
|
Share capital |
|
296,232 |
|
|
296,221 |
|
||
|
Contributed surplus |
|
23,874 |
|
|
23,254 |
|
||
|
Deficit |
|
(154,794 |
) |
|
(169,277 |
) |
||
|
Total Equity |
|
165,312 |
|
|
150,198 |
|
||
|
Total Equity and Liabilities |
$ |
211,745 |
|
$ |
184,082 |
|
||
|
KOLIBRI GLOBAL ENERGY INC. |
|||||||||||||
|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) |
|||||||||||||
|
(Unaudited, expressed in Thousands of United States dollars, except per share amounts) |
|||||||||||||
|
($000 except as noted) |
|||||||||||||
|
|
|
|
|
|
|
||||||||
|
|
|
|
Third Quarter |
|
First Nine Months |
||||||||
|
|
|
|
2023 |
|
2022 |
|
2023 |
|
2022 |
||||
|
|
|
|
|
|
|
|
|
|
|||||
|
Oil and natural gas revenue, net |
$ |
12,746 |
|
|
9,851 |
|
37,153 |
|
27,826 |
|
|||
|
Other income |
|
1 |
|
|
16 |
|
|
2 |
|
|
45 |
|
|
|
|
|
12,747 |
|
|
9,867 |
|
|
37,155 |
|
|
27,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Production and operating expenses |
|
1,628 |
|
|
1,216 |
|
|
4,328 |
|
|
3,487 |
|
|
|
Depletion and depreciation expense |
|
3,790 |
|
|
1,860 |
|
|
11,503 |
|
|
5,086 |
|
|
|
General and administrative expenses |
|
1,170 |
|
|
905 |
|
|
3,121 |
|
|
2,435 |
|
|
|
Stock based compensation |
|
157 |
|
|
75 |
|
|
531 |
|
|
232 |
|
|
|
|
|
6,745 |
|
|
4,056 |
|
|
19,483 |
|
|
11,240 |
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Finance income |
|
– |
|
|
4,648 |
|
|
– |
|
|
1,611 |
|
|
|
Finance expense |
|
(3,683 |
) |
|
(1,160 |
) |
|
(3,189 |
) |
|
(4,392 |
) |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net income |
|
2,319 |
|
|
9,299 |
|
|
14,483 |
|
|
13,850 |
|
|
|
Net income per basic share |
$ |
0.07 |
|
0.26 |
|
0.41 |
|
0.39 |
|
||||
|
KOLIBRI GLOBAL ENERGY INC. |
|||||||||||||
|
THIRD QUARTER 2023 |
|||||||||||||
|
(Unaudited, expressed in Thousands of United States dollars, except as noted) |
|||||||||||||
|
|
|||||||||||||
|
|
Third Quarter |
|
First Nine Months |
||||||||||
|
|
2023 |
|
2022 |
|
2023 |
|
2022 |
||||||
|
Oil revenue before royalties |
$ |
15,270 |
|
10,773 |
|
43,537 |
|
31,317 |
|
||||
|
Gas revenue before royalties |
390 |
|
1,020 |
|
1,437 |
|
2,161 |
|
|||||
|
NGL revenue before royalties |
718 |
|
873 |
|
2,224 |
|
2,443 |
|
|||||
|
Oil and Gas gross revenue |
16,378 |
|
12,666 |
|
47,198 |
|
35,921 |
|
|||||
|
|
|
|
|
|
|||||||||
|
Adjusted EBITDA(1) |
9,536 |
|
6,874 |
|
28,578 |
18,258 |
|
||||||
|
Additions to property, plant & equipment |
17,247 |
|
4,940 |
|
37,177 |
19,913 |
|
||||||
|
|
|
|
|
|
|||||||||
|
Statistics: |
|
|
|
|
|||||||||
|
|
Third Quarter |
|
First Nine Months |
||||||||||
|
|
2023 |
|
2022 |
|
2023 |
|
2022 |
||||||
|
Average oil production (Bopd) |
2,083 |
|
1,252 |
|
2,110 |
1,137 |
|
||||||
|
Average natural gas production (mcf/d) |
1,565 |
|
1,083 |
|
1,698 |
1,093 |
|
||||||
|
Average NGL production (Boepd) |
393 |
|
269 |
|
387 |
244 |
|
||||||
|
Average production (Boepd) |
2,737 |
|
1,702 |
|
2,780 |
|
1,563 |
|
|||||
|
Average oil price ($/bbl) |
$79.70 |
|
$93.52 |
|
$75.57 |
$100.91 |
|
||||||
|
Average natural gas price ($/mcf) |
$2.71 |
|
$10.24 |
|
$3.10 |
$7.24 |
|
||||||
|
Average NGL price ($/bbl) |
$19.84 |
|
$35.33 |
|
$21.04 |
|
$36.63 |
|
|||||
|
|
|
|
|
|
|||||||||
|
Average price (Boe) |
$65.04 |
|
$80.89 |
|
$62.19 |
|
$84.19 |
|
|||||
|
Royalties (Boe) |
14.42 |
|
17.96 |
|
13.24 |
|
18.97 |
|
|||||
|
Operating expenses (Boe) |
7.34 |
|
7.77 |
|
6.47 |
|
8.17 |
|
|||||
|
Netback from operations(2) (Boe) |
$43.28 |
|
$55.16 |
|
$42.48 |
|
$57.05 |
|
|||||
|
Price impact from commodity contracts(3) (Boe) |
|
|
(1.63 |
) |
|
(5.47 |
) |
|
(1.48 |
) |
|
(8.55 |
) |
|
Netback including commodity contracts(2) (Boe) |
$41.65 |
|
$49.69 |
|
$41.00 |
|
$48.50 |
|
|||||
|
(1) |
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
|
(2) |
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release. |
|
|
(3) |
Price impact from commodity contracts includes the positive or negative adjustment to the average price per barrel that the Company realized from its commodity contracts. |
|
The information outlined above is extracted from and should be read in conjunction with the Company’s unaudited financial statements for the three and nine months ended September 30, 2022 and the related management’s discussion and analysis thereof, copies of which are available under the Company’s profile at www.sedar.com.
NON-GAAP MEASURES
Netback from operations, netback including commodity contracts and adjusted EBITDA (collectively, the “Company’s Non-GAAP Measures”) are not measures or ratios recognized under Canadian generally accepted accounting principles (“GAAP“) and do not have any standardized meanings prescribed by IFRS. Management of the Company believes that such measures and ratios are relevant for evaluating returns on each of the Company’s projects as well as the performance of the enterprise as a whole. The Company’s Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures and ratios as reported by such organizations. The Company’s Non-GAAP Measures should not be construed as alternatives to net income, cash flows related to operating activities, working capital or other financial measures and ratios determined in accordance with IFRS, as an indicator of the Company’s performance.
An explanation of how the Company’s Non-GAAP Measures provide useful information to an investor and the purposes for which the Company’s management uses the Non-GAAP Measures is set out in the management’s discussion and analysis under the heading “Non-GAAP Measures” which is available under the Company’s profile at www.sedar.com and is incorporated by reference into this earnings release.
Netback from operations per barrel and its components are calculated by dividing revenue, less royalties and operating expenses by the Company’s sales volume during the period. Netback including commodity contracts is calculated by adjusting netback from operations by the realized gains or losses received from commodity contracts during the period. The following is the reconciliation of the non-GAAP ratio netback from operations to net income (loss) from continuing operations, which the Company considers to be the most directly comparable financial measure that is disclosed in the Company’s financial statements:
|
(US $000) |
|
Three months ended |
|
Nine months ended |
||||||||
|
|
|
2023 |
|
2022 |
|
2023 |
|
2022 |
||||
|
Net income |
2,319 |
|
9,299 |
|
14,483 |
|
13,850 |
|
||||
|
Adjustments: |
||||||||||||
|
Finance income |
– |
|
(4,648 |
) |
– |
|
(1,611 |
) |
||||
|
Finance expense |
3,683 |
|
1,160 |
|
3,189 |
|
4,392 |
|
||||
|
Share based compensation |
157 |
|
75 |
|
531 |
|
232 |
|
||||
|
General and administrative expenses |
1,170 |
|
905 |
|
3,121 |
|
2,435 |
|
||||
|
Depletion, depreciation and amortization |
3,790 |
|
1,860 |
|
11,503 |
|
5,086 |
|
||||
|
Other income |
(1 |
) |
(16 |
) |
(2 |
) |
(45 |
) |
||||
|
Operating netback |
11,118 |
|
8,635 |
|
32,825 |
|
24,339 |
|
||||
|
Netback from operations per BOE |
43.28 |
|
55.16 |
|
42.48 |
|
57.05 |
|
||||
Adjusted EBITDA is calculated as net income before interest, taxes, depletion and depreciation and other non-cash and non-operating gains and losses. The Company considers this a key measure as it demonstrates its ability to generate cash from operations necessary for future growth excluding non-cash items, gains and losses that are not part of the normal operations of the Company and financing costs. The following is the reconciliation of the non-GAAP measure adjusted EBITDA:
|
(US $000) |
Three months ended |
|
Nine months ended |
|||||||||
|
2023 |
|
2022 |
|
2023 |
|
2022 |
||||||
|
Net income |
2,319 |
|
9,299 |
|
14,483 |
|
13,850 |
|
||||
|
Depletion and depreciation |
3,790 |
|
1,860 |
|
11,503 |
|
5,086 |
|
||||
|
Accretion |
40 |
|
8 |
|
129 |
|
20 |
|
||||
|
Interest expense |
651 |
|
281 |
|
1,511 |
|
718 |
|
||||
|
Unrealized (gain) loss on commodity contracts |
2,579 |
|
(4,648 |
) |
412 |
|
(1,608 |
) |
||||
|
Share based compensation |
157 |
|
75 |
|
531 |
|
232 |
|
||||
|
Interest income |
– |
|
– |
|
– |
|
(3 |
) |
||||
|
Other income |
(1 |
) |
(16 |
) |
(2 |
) |
(45 |
) |
||||
|
Foreign currency (gain) loss |
1 |
|
15 |
|
11 |
|
8 |
|
||||
|
Adjusted EBITDA |
9,536 |
|
6,874 |
|
28,578 |
|
18,258 |
|
||||
CAUTIONARY STATEMENTS
In this news release and the Company’s other public disclosure:
|
(a) |
The Company’s natural gas production is reported in thousands of cubic feet (“Mcfs“). The Company also uses references to barrels (“Bbls“) and barrels of oil equivalent (“Boes“) to reflect natural gas liquids and oil production and sales. Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does 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 the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. |
|
|
(b) |
Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value. |
|
|
(c) |
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. |
|
|
(d) |
The Company discloses peak and 30-day initial production rates and other short-term production rates. Readers are cautioned that such production rates are preliminary in nature and are not necessarily indicative of long-term performance or of ultimate recovery. |
|
Caution Regarding Forward-Looking Information
This release contains forward-looking information including information regarding the proposed timing and expected results of exploratory and development work including production from the Company’s Tishomingo field, Oklahoma acreage, expectations regarding cash flow, the Company’s reserves based loan facility, including scheduled repayments, expected hedging levels and the Company’s strategy and objectives. The use of any of the words “target”, “plans”, “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements.
Such forward-looking information is based on management’s expectations and assumptions, including that the Company’s geologic and reservoir models and analysis will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled and that declines will match the modeling, that future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management’s expectations, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that anticipated results and estimated costs will be consistent with management’s expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the Company will continue to be able to access sufficient capital through financings, credit facilities, farm-ins or other participation arrangements to maintain its projects, that the Company will continue in compliance with the covenants under its reserves-based loan facility and that the borrowing base will not be reduced, that funds will be available from the Company’s reserves based loan facility when required to fund planned operations, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company’s business and its ability to advance its business strategy.
Forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward-looking information is based vary or prove to be invalid, including that the Company’s geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with management’s expectations, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks including flooding and extended interruptions due to inclement or hazardous weather), the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company’s assumptions, that very low or no production rates are achieved, that the Company will cease to be in compliance with the covenants under its reserves-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base re-determination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that funding is not available from the Company’s reserves-based loan facility at the times or in the amounts required for planned operations, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company’s most recent Annual Information Form under the “Risk Factors” section, the Company’s most recent management’s discussion and analysis and the Company’s other public disclosure, available under the Company’s profile on SEDAR at www.sedar.com.
With respect to estimated reserves, the evaluation of the Company’s reserves is based on a limited number of wells with limited production history and includes a number of assumptions relating to factors such as availability of capital to fund required infrastructure, commodity prices, production performance of the wells drilled, successful drilling of infill wells, the assumed effects of regulation by government agencies and future capital and operating costs. All of these estimates will vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, may vary. The Company’s actual production, revenues, taxes, development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. In addition to the foregoing, other significant factors or uncertainties that may affect either the Company’s reserves or the future net revenue associated with such reserves include material changes to existing taxation or royalty rates and/or regulations, and changes to environmental laws and regulations.
Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this release is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.
About Kolibri Global Energy Inc.
Kolibri Global Energy Inc. is a North American energy company focused on finding and exploiting energy projects in oil and gas. Through various subsidiaries, the Company owns and operates energy properties in the United States. The Company continues to utilize its technical and operational expertise to identify and acquire additional projects in oil, gas and clean and sustainable energy. The Company’s shares are traded on the Toronto Stock Exchange under the stock symbol KEI and on the NASDAQ under the stock symbol KGEI.
View source version on businesswire.com: https://www.businesswire.com/news/home/20231113228344/en/
For further information, contact:
Wolf E. Regener, President and Chief Executive Officer, +1 (805) 484-3613
Email: investorrelations@kolibrienergy.com
Website: www.kolibrienergy.com