Canacol Energy Ltd. (“Canacol” or the “Corporation”) (TSX:CNE;
OTCQX:CNNEF; BVC:CNEC) is pleased to report its conventional
natural gas, light, medium, and heavy crude oil reserves, and
deemed volumes for the fiscal year end December 31, 2023. The
Corporation’s conventional natural gas reserves are located in the
Lower Magdalena Valley basin, Colombia. Canacol has light and
medium crude oil reserves located in the Middle Magdalena Valley
basin, Colombia and light, medium, and heavy crude oil reserves and
deemed volumes in the Llanos basin, Colombia.
Canacol Energy Ltd Gross Conventional Natural Gas,
Light/Medium/Heavy Crude Oil Reserves and Deemed Volumes
Summary(1)(5)
|
|
|
|
|
ProvedDeveloped Producing |
Proved Developed Not Producing |
Proved Undeveloped |
Total Proved |
Total Proved + Probable |
Total Proved + Probable+
Possible |
|
Product Type |
|
("PDP") |
("PDNP") |
("PUD") |
("1P") |
("2P") |
("3P") |
|
Conventional natural gas and light/medium/heavy crude
oil(4) |
Bcfe(2) |
|
98.3 |
|
161.4 |
|
35.5 |
|
295.2 |
|
607.3 |
|
1,042.9 |
|
Total oil equivalent |
MMBOE(2) |
|
17.2 |
|
28.3 |
|
6.2 |
|
51.8 |
|
106.6 |
|
183.0 |
|
Before tax NPV-10(3) |
MM US$ |
$398.6 |
$657.0 |
$60.5 |
$1,116.1 |
$2,135.1 |
$3,200.8 |
|
After tax NPV-10(3) |
MM US$ |
$398.5 |
$655.8 |
$60.5 |
$1,114.8 |
$1,763.5 |
$2,375.7 |
(1) All reserves are represented at Canacol’s working
interest share before royalties.(2) The term “BOE” means a
barrel of oil equivalent and the term “cfe” means cubic feet
equivalent of natural gas on the basis of 5.7 thousand standard
cubic feet (“Mcf”) of natural gas to 1 barrel of oil (“bbl”) as per
Colombian regulatory practice.(3) Net Present Value (NPV) is
stated in millions of USD and is discounted at 10 percent.
(4) Conventional light/medium/heavy crude oil includes deemed
volumes of 100 mbbls PDP, 175 mbbls 1P, 238 mbbls 2P, and 343 mbbls
3P. Deemed volumes are derived from Rancho Hermoso volumes that are
operated but not owned by Canacol where Canacol receives a tariff.
They are calculated by multiplying the 100% sales volumes by the
ratio of the tariff received divided by the sales price of the
light/medium/heavy crude oil that Canacol receives a tariff
for. (5) The numbers in this table may not add due to
rounding.
Highlights
Conventional Natural Gas and Light/Medium/Heavy
Crude Oil Proved + Probable Reserves and Deemed Volumes (“2P”):
- 2P before tax
NPV-10 of US$2.1 billion at December 31 ,2023, a 10% increase over
the prior year value of US$1.9 billion at December 31, 2022
- 2P after tax
NPV-10 of US$1.8 billion at December 31, 2023, a 34% increase over
the prior year value of US$1.3 billion at December 31, 2022. The
significant increase in after tax 2P values is primarily impacted
by the Corporation’s restructuring in the fourth quarter of 2022,
the results of which are first incorporated in this year’s reserve
report
- Decreased by
6.9% since December 31, 2022, totaling 607 billion standard cubic
feet equivalent (“Bcfe”) at December 31, 2023, with a before tax
value discounted at 10% of US$2.1 billion, representing both
CAD$82.62 per share of reserve value, and CAD$54.63 per share of 2P
net asset value (net of US$723.5 million of net
debt)
- Reserve
replacement of 31% based on calendar 2023 conventional natural gas,
light/medium/heavy crude oil reserve, and deemed volume additions
of 15.9 Bcf, 0.5 MMBbls, and 0.2 MMBbls, respectively, totaling 20
Bcfe
- 2P Finding and
Development Cost (“F&D”) of US$3.17 / Mcfe for the three-year
period ending December 31, 2023
- Recycle ratio of
0.4x for the year ended December 31, 2023 (calculated based on the
natural gas netback of US$4.11 / Mcf for the year ended December
31, 2023)
- Recycle ratio of
1.2x for the three-year period ending December 31, 2023 (calculated
based on the weighted average natural gas netback of US$3.73 / Mcf
for the years ended December 31, 2023, 2022 and 2021)
- Reserves life
index (“RLI”) of 9.9 years based on annualized fourth quarter 2023
conventional natural gas production of 168,127 thousand standard
cubic feet per day (“Mscfpd”) or 29,496 barrels of oil equivalent
per day (“BOEPD”)
- RLI of 9.4 years
based on conventional natural gas production guidance of 177,000
Mcfpd for calendar 2024 (high end 2024 production guidance as
announced February 5, 2024)
Conventional Natural Gas and Light/Medium/Heavy
Crude Oil Total Proved Reserves and Deemed Volumes (“1P”):
- Decreased by
13.0% since December 31, 2022, totaling 295 Bcfe at December 31,
2023, with a before tax value discounted at 10% of US$1.1 billion,
representing both CAD$43.19 per share of reserve value, and
CAD$15.19 per share of 1P net asset value (net of US$723.5 million
of net debt)
- Reserve
replacement of 32% based on calendar 2023 conventional natural gas,
light/medium/heavy crude oil reserve, and deemed volume additions
of 18.2 Bcf, 0.3 MMBbls, and 0.2 MMBbls, respectively, totaling 21
Bcfe
- 1P F&D of
US$4.70 / Mcfe for the three-year period ending December 31,
2023
- RLI of 4.8 years
based on annualized fourth quarter 2023 conventional natural gas
production of 168,127 Mcfpd or 29,496 BOEPD
- RLI of 4.6 years
based on conventional natural gas production guidance of 177,000
Mcfpd for calendar 2024 (high end 2024 production guidance as
announced February 5, 2024)
Conventional Natural Gas and Light/Medium/Heavy
Crude Oil Total Proved + Probable + Possible Reserves and Deemed
Volumes (“3P”):
- Decreased by
4.2% since December 31, 2022, totaling 1,043 Bcfe at December 31,
2023, with a before tax value discounted at 10% of US$3.2 billion,
representing both CAD$123.86 per share of reserve value, and
CAD$95.86 per share of 3P net asset value (net of US$723.5 million
of net debt)
- Reserve
replacement of 31% based on calendar 2023 conventional natural gas,
light/medium/heavy crude oil reserve, and deemed volume additions
of 13.3 Bcf and 0.8 MMBbls, and 0.3 MMBbls, respectively, totaling
20 Bcfe
- 3P F&D of
US$1.83 / Mcf for the three-year period ending December 31,
2023
- RLI of 17.0
years based on annualized fourth quarter 2023 conventional natural
gas production of 168,127 Mcfpd or 29,496 BOEPD
- RLI of 16.1
years based on conventional natural gas production guidance of
177,000 Mcfpd for calendar 2024 (high end 2024 production guidance
as announced February 5, 2024)
Ravi Sharma, COO said, “In 2023 we added 20 Bcfe
of 2P reserves and deemed volumes, an increase of 3%, and added 21
Bcfe to the 1P reserve and deemed volumes for an increase of
6%. Our core fields, Clarinete, Nelson, Aguas Vivas and
Pandereta continue to perform well and saw increases in 1P
reserves. Our 2P increases were limited due to lack of
exploration success at the near field Cereza and Piña Norte
prospects, and our inability to get the Natilla exploration well
drilled to the target interval due to technical difficulties
drilling the well and the sidetrack. As our producing fields mature
we are executing development programs to increase PDP reserves by
converting PDNP and PUD reserves to PDP to maintain our productive
capacity and production. Our recent 3D surveys have delineated and
confirmed further prospectivity in VIM 5 and SSJN-7 that we will
drill in 2024, 2025 and beyond to potentially add new production
clusters and add to the over 900 BCF of 2P natural gas reserves the
company has discovered since inception.”
Discussion of Year Ended December 31, 2023 Reserves
Report
During the year ended December 31, 2023, the
Corporation recorded increases in certain reserve categories due to
discoveries at Lulo on the VIM21 block, Piña Norte on the Esperanza
block, and Pistacho on the VIM5 block. All aforementioned additions
are in the Lower Magdalena Valley. Positive technical revisions
were associated primarily with Clarinete, Pandereta, and Claxon on
the VIM5 block, Chinu on the SSJN7 block due to a working interest
consolidation to 100% from 50%, and Rancho Hermoso in the Llanos
basin. Negative technical revisions were associated primarily with
Fresa on the VIM21 block.
The following tables summarize information from
the independent reserves report prepared by Boury Global Energy
Consultants Ltd. (“BGEC”) effective December 31, 2023 (the “BGEC
2023 report”). The BGEC 2023 report covers 100% of the
Corporation’s conventional natural gas and light/medium/heavy oil
reserves and deemed volumes.
The BGEC 2023 report was prepared in accordance
with definitions, standards and procedures contained in the
Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and
National Instrument NI 51-101, Standards of Disclosure for Oil and
Gas Activities (“NI 51-101”). Additional reserve information as
required under NI 51-101 is included in the Corporation’s Annual
Information Form, which will be filed on SEDAR by March 31,
2024.
Canacol Gross Natural Gas,
Light/Medium/Heavy Crude Oil Reserves and Deemed Volumes for the
Year Ended December 31,
2023(1)
|
Reserve
Category(2) |
31-Dec-22 |
|
31-Dec-23 |
|
Difference |
|
|
(MMcfe) |
|
(MMcfe) |
|
(%) |
| Total Proved (1P) |
339,243 |
|
295,171 |
|
-13.0% |
| Total Proved +
Probable (2P) |
652,466 |
|
607,343 |
|
-6.9% |
| Total
Proved + Probable + Possible (3P) |
1,088,172 |
|
1,042,940 |
|
-4.2% |
(1) The numbers in this table may not add due to
rounding.(2) All reserves are Canacol working interest before
royalties.
5-Year Gas and Oil Price Forecasts – BGEC Report
December 31, 2023(1)
|
|
|
Reserve |
|
|
|
|
|
|
|
|
Report Date |
2024 |
2025 |
2026 |
2027 |
2028 |
|
Volume weighted Total Proved + Probable (2P) average gas
price(2) |
US$/Mcf |
31-Dec-23 |
6.86 |
6.47 |
6.56 |
7.90 |
7.69 |
|
Chimela Realized Oil Price- net of quality offset and
transportation(3) |
US$/bbl |
31-Dec-23 |
61.82 |
63.82 |
64.82 |
66.32 |
69.32 |
|
Rancho Realized Oil Price- net of quality offset and
transportation(4) |
US$/bbl |
31-Dec-23 |
72.50 |
74.50 |
76.50 |
78.50 |
80.50 |
(1) The numbers in this table may not add due to
rounding.(2) The gas price forecast is based on existing long
term contracts net of transportation (if applicable) and adjusted
for inflation, along with interruptible gas sales pricing based on
forecasts from S&P.(3) The Chimela oil price forecast is
based on BGEC’s Brent forecast less US$16.18/bbl for quality offset
and transportation costs.(4) The Rancho Hermoso non-tariff oil
price forecast is based on BGEC’s WTI forecast less US$0.50/bbl for
quality offset and transportation costs. Additionally, Canacol
receives tariffs of $17.36/bbl for Mirador production (currently
producing at RH10), $17.36/bbl escalated with inflation for RH11
and RH16 production ($20.32/bbl in January 2024), and a tariff
between $14.50/bbl and $26.00/bbl that fluctuates with Brent
pricing ($20.42/bbl in January 2024).
Conventional Natural Gas, Light/Medium/Heavy Crude Oil
Reserves, and Deemed Volumes Net Present Value Before & After
Tax Summary(1)
|
|
Before tax |
|
After tax |
| |
|
|
Net Asset |
|
|
|
Net Asset |
| |
|
|
Value |
|
|
|
Value |
| Reserve
Category |
31-Dec-23 |
|
31-Dec-23 |
|
31-Dec-23 |
|
31-Dec-23 |
|
|
(M
US$)(2) |
|
(C$/share)(3) |
|
(M
US$)(2) |
|
(C$/share)(3) |
|
Total Proved (1P) |
$ |
1,116,092 |
|
$ |
15.19 |
|
$ |
1,114,821 |
|
$ |
15.14 |
| Total Proved +
Probable (2P) |
$ |
2,135,121 |
|
$ |
54.63 |
|
$ |
1,763,454 |
|
$ |
40.24 |
| Total
Proved + Probable + Possible (3P) |
$ |
3,200,751 |
|
$ |
95.86 |
|
$ |
2,375,662 |
|
$ |
63.94 |
(1) The numbers in this table may not add
due to rounding.(2) Net present value is stated in thousands
of USD and is discounted at 10 percent. The forecast prices used in
the calculation of the present value of future net revenue are
based on the price deck described above. The BGEC forecast for
conventional natural gas, light/medium/heavy crude oil, and deemed
volume prices at December 31, 2023 are included in the
Corporation’s Annual Information Form.(3) Net asset value
("NAV") is calculated as at December 31, 2023 NPV10 less estimated
net debt of US$723.5 million (being US$713.4 million of total debt
plus working capital deficit of US$10 million) divided by 34.1
million basic shares outstanding as at December 31, 2023. NAV
calculations are converted to $CAD at December 31, 2023 effective
rate of USD:CAD =1.32.
Reserve Life Index
(“RLI”)(1)(2)
|
Reserve Category |
31-Dec-22 |
|
31-Dec-23 |
|
|
(yrs)(3) |
|
(yrs)(4) |
| Total Proved (1P) |
5.2 |
|
4.8 |
| Total Proved +
Probable (2P) |
10.0 |
|
9.9 |
| Total
Proved + Probable + Possible (3P) |
16.8 |
|
17.0 |
(1) The numbers in this table may not add
due to rounding.(2) “RLI” Reserve Life Index is calculated by
dividing the applicable reserves category by the annualized fourth
quarter production.(3) Calculated using average 3 month ending
December 31, 2022 natural gas production of 177,985 Mcfpd or 31,225
BOEpd annualized. (4) Calculated using average 3
month ending December 31, 2023 natural gas production of 168,127
Mcfpd or 29,496 BOEpd annualized.
Year Ended December 31, 2023 Canacol Gross Reserves and
Deemed Volumes Reconciliation (1)
|
|
TotalOil |
Light/MedCrude Oil |
HeavyCrude Oil |
ConventionalNatural Gas |
NGL |
TOTAL |
| PROVED DEVELOPED
PRODUCING |
(MBBL) |
(MBBL) |
(MBBL) |
(MMCF) |
(MBBL) |
MBOE |
|
Opening Balance (December 31, 2022) |
- |
- |
- |
161,633 |
- |
28,357 |
|
Extensions |
- |
- |
- |
- |
- |
- |
| Improved Recovery |
- |
- |
- |
- |
- |
- |
| Technical Revisions(2) |
594 |
457 |
137 |
(7,193) |
- |
(668) |
| Discoveries(4) |
- |
- |
- |
5,646 |
- |
991 |
| Acquisitions |
- |
- |
- |
- |
- |
- |
| Dispositions |
- |
- |
- |
- |
- |
- |
| Economic Factors |
- |
- |
- |
- |
- |
- |
|
Production |
(12) |
(12) |
- |
(65,089) |
- |
(11,407) |
|
Closing Balance (December 31, 2023) |
583 |
445 |
137 |
94,997 |
- |
17,249 |
|
|
Total Oil |
Light/Med Crude Oil |
Heavy Crude Oil |
Conventional Natural Gas |
NGL |
TOTAL |
|
TOTAL PROVED |
(MBBL) |
(MBBL) |
(MBBL) |
(MMCF) |
(MBBL) |
MBOE |
|
Opening Balance (December 31, 2022) |
1,023 |
1,023 |
- |
333,412 |
- |
59,516 |
|
Extensions |
- |
- |
- |
- |
- |
- |
| Improved Recovery |
- |
- |
- |
- |
- |
- |
| Technical Revisions(3) |
512 |
300 |
212 |
11,934 |
- |
2,606 |
| Discoveries(4) |
- |
- |
- |
6,232 |
- |
1,093 |
| Acquisitions |
- |
- |
- |
- |
- |
- |
| Dispositions |
- |
- |
- |
- |
- |
- |
| Economic Factors |
- |
- |
- |
- |
- |
- |
|
Production |
(12) |
(12) |
- |
(65,089) |
- |
(11,431) |
|
Closing Balance (December 31, 2023) |
1,523 |
1,311 |
- |
286,489 |
- |
51,784 |
|
|
Total Oil |
Light/Med Crude Oil |
Heavy Crude Oil |
Conventional Natural Gas |
NGL |
TOTAL |
| TOTAL PROVED +
PROBABLE |
(MBBL) |
(MBBL) |
(MBBL) |
(MMCF) |
(MBBL) |
MBOE |
|
Opening Balance (December 31, 2022) |
5,725 |
5,725 |
- |
619,833 |
- |
114,467 |
|
Extensions |
- |
- |
- |
- |
- |
- |
| Improved Recovery |
- |
- |
- |
- |
- |
- |
| Technical Revisions(3) |
725 |
443 |
282 |
1,304 |
- |
954 |
| Discoveries(4) |
- |
- |
- |
14,598 |
- |
2,561 |
| Acquisitions |
- |
- |
- |
- |
- |
- |
| Dispositions |
- |
- |
- |
- |
- |
- |
| Economic Factors |
- |
- |
- |
- |
- |
- |
|
Production |
(12) |
(12) |
- |
(65,089) |
- |
(11,431) |
|
Closing Balance (December 31, 2023) |
6,438 |
6,156 |
282 |
570,645 |
- |
106,552 |
|
|
Total Oil |
Light/MedCrude Oil |
HeavyCrude Oil |
ConventionalNatural Gas |
NGL |
TOTAL |
| TOTAL PROVED +
PROBABLE + POSSIBLE |
(MBBL) |
(MBBL) |
(MBBL) |
(MMCF) |
(MBBL) |
MBOE |
|
Opening Balance (December 31, 2022) |
13,613 |
13,613 |
- |
1,010,578 |
- |
190,908 |
|
Extensions |
- |
- |
- |
- |
- |
- |
| Improved Recovery |
- |
- |
- |
- |
- |
- |
| Technical Revisions(3) |
1,164 |
769 |
394 |
(12,955) |
- |
(1,109) |
| Discoveries(4) |
- |
- |
- |
26,243 |
- |
4,604 |
| Acquisitions |
- |
- |
- |
- |
- |
- |
| Dispositions |
- |
- |
- |
- |
- |
- |
| Economic Factors |
- |
- |
- |
- |
- |
- |
|
Production |
(12) |
(12) |
- |
(65,089) |
- |
(11,431) |
|
Closing Balance (December 31, 2023) |
14,766 |
14,371 |
- |
958,777 |
- |
182,972 |
(1) The numbers in this table may not add
due to rounding.(2) PDP technical revisions due to transfers
to PDNP as certain wells in Nelson, Clarinete, and Alboka that were
producing at December 31, 2022 were not producing and awaiting
workovers to restart production at December 31,
2023.(3) Conventional natural gas technical revisions in 1P
through to 3P are associated primarily with Clarinete, Pandereta,
Siku, San Marcos, Aguas Vivas, Chirimia, and
Toronja.(4) Conventional natural gas discoveries are
associated with Lulo, Aguas Vivas, and Cornamusa on the VIM21
block, Piña Norte and San Marcos on the Esperanza block, and
Pistacho and Pandereta on the VIM5 block.
1P Reserves Metrics Reconciliation – Canacol Working
Interest before
Royalty(1)(2)
|
|
Calendar 2023 |
Three-Year EndingDecember 31, 2023 |
|
Net Capital Expenditures (M$ US)(3) |
$ |
202,923 |
$ |
446,614 |
|
Capital Expenditures - Change in FDC (M$ US)(4) |
$ |
2,288 |
$ |
16,959 |
|
Total F&D (M$ US)(5) |
$ |
205,211 |
$ |
463,573 |
|
Net Acquisitions (M$ US) |
|
- |
|
- |
|
Total FD&A (M$ US)(6)(7) |
$ |
205,211 |
$ |
463,573 |
|
Reserve Additions (MMcfe) |
|
21,084 |
|
98,623 |
|
Reserve Additions – Net Acquisitions |
|
- |
|
- |
|
Reserve Additions Including Net Acquisitions (MMcfe) |
|
21,084 |
|
98,623 |
|
1P F&D per Mcfe
(US$/Mcfe)(5) |
$ |
9.73 |
$ |
4.70 |
|
1P FD&A per Mcfe
(US$/Mcfe)(6)(7) |
$ |
9.73 |
$ |
4.70 |
(1) The numbers in this table may not add
due to rounding.(2) All values in this table are stated on a
1P (Total Proved) basis.(3) The Corporation excludes
investments on the Medellin pipeline from the F&D
calculations. 2023, 2022 and 2021 capital expenditures
exclude US$9 million, US$9.9 million and US$3.2 million related to
expenditures on the Medellin pipeline, respectively. The
Corporation also excludes expenditures on corporate assets from the
F&D calculations. 2023, 2022 and 2021 capital expenditures
exclude US$3.3 million, US$5 million and US$3 million related to
expenditures on corporate assets. (4) “Capital
Expenditures – change in FDC” is rounded. FDC is the 1P (Total
Proved) future development capital.(5) 1P F&D – Finding
and Development Costs on a 1P (Total Proved) basis.(6) 1P
FD&A - Finding, Development and Acquisition Costs on a 1P
(Total Proved) basis.(7) With the finding and development
costs, the aggregate of the exploration and development costs
incurred in the most recent financial year and the change during
that year in estimated future development costs generally will not
reflect total finding and development costs related to reserve
additions for that year.
2P Reserves Metrics Reconciliation – Canacol Working
Interest before
Royalty(1)(2)
|
|
Calendar 2023 |
Three-Year EndingDecember 31, 2023 |
|
Net Capital Expenditures (M$ US)(3) |
$ |
202,923 |
$ |
446,614 |
|
Capital Expenditures - Change in FDC (M$ US)(4) |
$ |
10,828 |
$ |
86,508 |
|
Total F&D (M$ US)(5) |
$ |
213,751 |
$ |
533,122 |
|
Net Acquisitions (M$ US) |
|
- |
|
- |
|
Total FD&A (M$ US)(6)(7) |
$ |
213,751 |
$ |
533,122 |
|
Reserve Additions (MMcfe) |
|
20,035 |
|
168,340 |
|
Reserve Additions – Net Acquisitions |
|
- |
|
- |
|
Reserve Additions Including Net Acquisitions (MMcfe) |
|
20,035 |
|
168,340 |
|
2P F&D per Mcf
(US$/Mcfe)(5) |
$ |
10.67 |
$ |
3.17 |
|
2P FD&A per Mcf
(US$/Mcfe)(6)(7) |
$ |
10.67 |
$ |
3.17 |
(1) The numbers in this table may not add
due to rounding.(2) All values in this table are stated on a
2P (Total Proved + Probable) basis.(3) The Corporation
excludes investments on the Medellin pipeline from the F&D
calculations. 2023, 2022 and 2021 capital expenditures
exclude US$9 million, US$9.9 million and US$3.2 million related to
expenditures on the Medellin pipeline, respectively. The
Corporation also excludes expenditures on corporate assets from the
F&D calculations. 2023, 2022 and 2021 capital expenditures
exclude US$3.3 million, US$5 million and US$3 million related to
expenditures on corporate assets. (4) “Capital
Expenditures – change in FDC” is rounded. FDC is the 2P (Total
Proved + Probable) future development capital.(5) 2P F&D –
Finding and Development Costs on a 2P (Total Proved + Probable)
basis.(6) 2P FD&A - Finding, Development and Acquisition
Costs on a 2P (Total Proved + Probable) basis.(7) With the
finding and development costs, the aggregate of the exploration and
development costs incurred in the most recent financial year and
the change during that year in estimated future development costs
generally will not reflect total finding and development costs
related to reserve additions for that year.
3P Natural Gas Reserves Metrics Reconciliation – Canacol
Working Interest before
Royalty(1)(2)
|
|
Calendar 2023 |
Three-Year Ending December 31, 2023 |
|
Net Capital Expenditures (M$ US)(3) |
$ |
202,923 |
$ |
446,614 |
|
Capital Expenditures - Change in FDC (M$ US)(4) |
$ |
11,313 |
$ |
84,208 |
|
Total F&D (M$ US)(5) |
$ |
214,236 |
$ |
530,822 |
|
Net Acquisitions (M$ US) |
|
- |
|
- |
|
Total FD&A (M$ US)(6)(7) |
$ |
214,236 |
$ |
530,822 |
|
Reserve Additions (MMcfe) |
|
19,923 |
|
290,114 |
|
Reserve Additions – Net Acquisitions |
|
- |
|
- |
|
Reserve Additions Including Net Acquisitions (MMcfe) |
|
19,923 |
|
290,114 |
|
3P F&D per Mcf
(US$/Mcfe)(5) |
$ |
10.75 |
$ |
1.83 |
|
3P FD&A per Mcf
(US$/Mcfe)(6)(7) |
$ |
10.75 |
$ |
1.83 |
(1) The numbers in this table may not add
due to rounding.(2) All values in this table are stated on a
3P (Total Proved + Probable + Possible) basis.(3) The
Corporation excludes investments on the Medellin pipeline from the
F&D calculations. 2023, 2022 and 2021 capital
expenditures exclude US$9 million, US$9.9 million and US$3.2
million related to expenditures on the Medellin pipeline,
respectively. The Corporation also excludes expenditures on
corporate assets from the F&D calculations. 2023, 2022 and 2021
capital expenditures exclude US$3.3 million, US$5 million and US$3
million related to expenditures on corporate assets.
(4) “Capital Expenditures – change in FDC” is rounded. FDC is
the 3P (Total Proved + Probable + Possible) future development
capital.(5) 3P F&D – Finding and Development Costs on a 3P
(Total Proved + Probable + Possible) basis.(6) 3P FD&A -
Finding, Development and Acquisition Costs on a 3P (Total Proved +
Probable + Possible) basis.(7) With the finding and
development costs, the aggregate of the exploration and development
costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally
will not reflect total finding and development costs related to
reserve additions for that year.
The recovery and reserve and deemed volume
estimates of conventional natural gas and light/medium/heavy crude
oil are estimates only. There is no guarantee that the estimated
reserves and deemed volumes will be recovered, and actual reserves
of conventional natural gas and light/medium/heavy crude oil and
deemed volumes may prove to be greater than, or less than, the
estimates provided.
About Canacol
Canacol is a natural gas and oil exploration and
production company with operations focused in Colombia. The
Corporation's common stock trades on the Toronto Stock Exchange,
the OTCQX in the United States of America, and the Colombia Stock
Exchange under ticker symbol CNE, CNNEF, and CNE.C,
respectively.
Forward-Looking Information and Statements
This press release contains certain
forward-looking statements within the meaning of applicable
securities law. Forward-looking statements are frequently
characterized by words such as “plan”, “expect”, “project”,
“target”, “intend”, “believe”, “anticipate”, “estimate” and other
similar words, or statements that certain events or conditions
“may” or “will” occur, including without limitation statements
relating to estimated production rates from the Corporation’s
properties and intended work programs and associated timelines.
Forward-looking statements are based on the opinions and estimates
of management at the date the statements are made and are subject
to a variety of risks and uncertainties and other factors that
could cause actual events or results to differ materially from
those projected in the forward-looking statements. The Corporation
cannot assure that actual results will be consistent with these
forward looking statements. They are made as of the date hereof and
are subject to change and the Corporation assumes no obligation to
revise or update them to reflect new circumstances, except as
required by law. Information and guidance provided herein
supersedes and replaces any forward looking information provided in
prior disclosures. Prospective investors should not place undue
reliance on forward looking statements. These factors include the
inherent risks involved in the exploration for and development of
crude oil and natural gas properties, the uncertainties involved in
interpreting drilling results and other geological and geophysical
data, fluctuating energy prices, the possibility of cost overruns
or unanticipated costs or delays and other uncertainties associated
with the oil and gas industry. Other risk factors could include
risks associated with negotiating with foreign governments as well
as country risk associated with conducting international
activities, and other factors, many of which are beyond the control
of the Corporation. Other risks are more fully described in the
Corporation’s most recent Management Discussion and Analysis
(“MD&A”) and Annual Information Form, which are incorporated
herein by reference and are filed on SEDAR at www.sedar.com.
Average production figures for a given period are derived using
arithmetic averaging of fluctuating historical production data for
the entire period indicated and, accordingly, do not represent a
constant rate of production for such period and are not an
indicator of future production performance. Detailed information in
respect of monthly production in the fields operated by the
Corporation in Colombia is provided by the Corporation to the
Ministry of Mines and Energy of Colombia and is published by the
Ministry on its website; a direct link to this information is
provided on the Corporation’s website.
Use of Non-IFRS
Financial Measures - Such
supplemental measures should not be considered as an alternative
to, or more meaningful than, the measures as determined in
accordance with IFRS as an indicator of the Corporation’s
performance, and such measures may not be comparable to that
reported by other companies. This press release also provides
information on adjusted funds from operations. Adjusted funds from
operations is a measure not defined in IFRS. It represents cash
(used) provided by operating activities before changes in non-cash
working capital, settlement of a litigation settlement liability
and decommissioning obligation expenditures. The Corporation
considers funds from operations a key measure as it demonstrates
the ability of the business to generate the cash flow necessary to
fund future growth through capital investment and to repay debt.
Adjusted funds from operations should not be considered as an
alternative to, or more meaningful than, cash (used) provided by
operating activities as determined in accordance with IFRS as an
indicator of the Corporation’s performance. The Corporation’s
determination of adjusted funds from operations may not be
comparable to that reported by other companies. For more details on
how the Corporation reconciles its cash provided by operating
activities to adjusted funds from operations, please refer to the
“Non-IFRS Measures” section of the Corporation’s MD&A.
Additionally, this press release references Adjusted EBITDAX and
operating netback measures. Adjusted EBITDAX is defined as
consolidated net income adjusted for interest, income taxes,
depreciation, depletion, amortization, exploration expenses and
other similar non-recurring or non-cash charges. Operating netback
is a benchmark common in the oil and gas industry and is calculated
as total natural gas, LNG and petroleum sales, net transportation
expenses, less royalties and operating expenses, calculated on a
per barrel of oil equivalent basis of sales volumes using a
conversion. Operating netback is an important measure in evaluating
operational performance as it demonstrates field level
profitability relative to current commodity prices. Adjusted
EBITDAX and operating netback as presented do not have any
standardized meaning prescribed by IFRS and therefore may not be
comparable with the calculation of similar measures for other
entities.
Operating netback is defined as revenues, net
transportation expenses less royalties and operating expenses.
The reserves evaluation, effective December 31,
2023, was conducted by the Corporation’s independent reserves
evaluator Boury Global Energy Consultants Ltd. (“BGEC”) and are in
accordance with National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities. The reserves are provided on
a Canacol Gross basis in units of thousands of cubic feet (“MMcf”)
and thousands of barrels of oil equivalent (“MBOE”) using a
forecast price deck in US dollars. The estimated values may or may
not represent the fair market value of the reserve estimates.
"Gross" in relation to the Corporation's
interest in production or reserves is its working interest
(operating or non-operating) share before deduction of royalties
and without including any royalty interests of the Corporation;
"Net" in relation to the Corporation's interest
in production or reserves is its working interest (operating or
non-operating) share after deduction of royalty obligations, plus
its royalty interest in production or reserves;
“Proved Developed Producing Reserves" are those
reserves that are expected to be recovered from completion
intervals open at the time of the estimate. These reserves may be
currently producing or, if shut-in, they must have previously been
on production, and the date of resumption of production must be
known with reasonable certainty.
“Proved reserves” are those reserves that can be
estimated with a high degree of certainty to be recoverable. It is
likely that the actual remaining quantities recovered will exceed
the estimated proved reserves;
“Probable reserves” are those additional
reserves that are less certain to be recovered than proved
reserves. It is equally likely that the actual remaining quantities
recovered will be greater or less than the sum of the estimated
proved plus probable reserves;
“Possible reserves” means those additional
reserves that are less certain to be recovered than probable
reserves. It is unlikely that the actual remaining quantities
recovered will exceed the sum of the estimated proved plus probable
plus possible reserves;
“Deemed Volumes” refer to COGEH Section 3.9.4.8
– Assigning Reserves, and refer to the economic interest method
which is used for Risked service contracts where, for volumes
produced, the Corporation does not have a direct interest but
represents reserves attributable to the Corporation. By definition,
these volumes are calculated as the production revenue divided by
the tariff price and are considered additive to volumes certified
as reserves. Under the terms of this risked Service Agreement,
these calculated volumes correspond to actual volumes produced.
BOE and CFE Conversions - “BOE” barrel of oil
equivalent or “CFE” cubic feet of gas equivalent is derived by
converting natural gas to oil or vice versa in the ratio of 5.7 Mcf
of natural gas to one bbl of oil. A BOE or CFE conversion ratio of
5.7 Mcf to 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. As the value ratio
between natural gas and crude oil based on the current prices of
natural gas and crude oil is significantly different from the
energy equivalency of 5.7:1, utilizing a conversion on a 5.7:1
basis may be misleading as an indication of value. In this news
release, the Corporation has expressed BOE using the Colombian
conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of
Mines and Energy of Colombia.
“PDP” means Proved Developed Producing“1P” means
Total Proved“2P” means Total Proved + Probable“3P” means Total
Proved + Probable + Possible
PDP Reserves replacement ratio: Ratio of reserve
additions to production, as reported in financial statements during
the fiscal year ended December 31, excluding acquisitions and
dispositions on a Proved Developed Producing basis.
1P Reserves replacement ratio: Ratio of reserve
additions to production, as reported in financial statements during
the fiscal year ended December 31, excluding acquisitions and
dispositions on a Total Proved basis.
2P Reserves replacement ratio: Ratio of reserve
additions to production, as reported in financial statements during
the fiscal year ended December 31, excluding acquisitions and
dispositions on a Total Proved + Probable basis.
Finding and development costs per thousand cubic
feet (Mcf) represent exploration and development costs incurred per
Mcf of Total Proved + Probable reserves added during the year. The
Corporation, industry analysts, and investors use such metrics to
measure a Corporation’s ability to establish a long-term trend of
adding reserves at a reasonable cost.
Finding, development and acquisition costs per
thousand cubic feet (Mcf) represent property acquisition,
exploration, and development costs incurred per Mcf of Total Proved
+ Probable reserves added during the year. The Corporation,
industry analysts, and investors use such metrics to measure a
Corporation’s ability to establish a long-term trend of adding
reserves at a reasonable cost.
With the finding and development costs, the
aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in
estimated future development costs generally will not reflect total
finding and development costs related to reserve additions for that
year.
Natural gas recycle ratio is calculated by
dividing natural gas netback by finding and development costs.
“RLI” Reserve Life Index is calculated by
dividing the applicable reserves category by the annualized fourth
quarter production.
This press release contains a number of oil and
gas metrics, including F&D, FD&A, reserve replacement and
RLI, 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. Such metrics have been
included herein to provide readers with additional measures to
evaluate the Corporation's performance; however, such measures are
not reliable indicators of the future performance of the
Corporation and future performance may not compare to the
performance in previous periods.
For more information please contact:
Investor Relations
South America: +571.621.1747 IR-SA@canacolenergy.com
Global: +1.403.561.1648 IR-GLOBAL@canacolenergy.com
http://www.canacolenergy.com
Grafico Azioni Canacol Energy (TSX:CNE)
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