Q4 2023 REPORTING PACKAGE
MARCH 21, 2024
TSX: TAL
AIM: PTAL
OTCQX: PTALF
PetroTal Announces Q4 and 2023 Financial and Operating Results
Q4 2023 average sales and production of 15,033 bopd and 14,865 bopd, respectively
2023 average year on year production growth of 17% to 14,248 bopd
Generated 2023 free funds flow of $91 million
Returned over $61 million through dividends and share buybacks in 2023
2023 Return on Capital Employed of 30%
Calgary, AB and Houston, TX – March 21, 2024—PetroTal Corp. (“PetroTal” or the “Company”) (TSX: TAL,
AIM: PTAL and OTCQX: PTALF) is pleased to report its operating and audited financial results for the three
(“Q4”) and twelve months ended December 31, 2023 (“2023”).
Selected financial and operational information is outlined below and should be read in conjunction with the
Company’s audited consolidated financial statements and management’s discussion and analysis (“MD&A”)
for the three and twelve months ended December 31, 2023, which are available on SEDAR+ at
www.sedarplus.ca and on the Company’s website at www.PetroTal‐Corp.com. All amounts herein are in
United States dollars unless otherwise stated.
Selected Q4 and 2023 Highlights
• Average Q4 sales and production of 15,033 and 14,865 barrels (“bbls”) of oil per day (“bopd”),
respectively, impacted by a severe dry season and consequent low river levels that limited barge
transport and tanker unloading capacity at Manaus;
• Average 2023 sales and production of 14,421 bbls and 14,248 bopd, respectively, within guidance
range for the year and generating a production growth rate of 17% over 2022;
•
•
2023 return on capital employed of 30% compared to 49% in 2022;(1)
Exited 2023 in a strong cash position with $111 million in total cash ($91 million unrestricted), after
repaying $80 million of bonds in early 2023 and returning over $61 million in dividends and share
buybacks in 2023;
• Capital expenditures (“capex”) totaled $32.2 million in Q4 and were focused on drilling well 16H,
bringing 2023 total capex spend to just over $108 million, lower than guidance of approximately $120
million;
•
Successfully drilled three new oil wells and one water disposal well in 2023. During 2023, the three
new oil wells produced nearly 1 million bbls of oil and generated approximately $45 million in net
operating income representing nearly a full payout of their cost to drill by December 31, 2023;
2 •
PetroTal successfully executed workover operations on wells 1XD and 2XD in May and June 2023, with
both wells producing between 500 and 700 bopd since July 2023 and accumulating over 180,000 bbls
of oil in the second half of 2023 thereby recovering their workover cost approximately 2.5 times by
the end 2023;
• Generated Q4 EBITDA2 and free funds flow2 of $50.8 million ($36.71/bbl) and $8.1 million ($5.87/bbl),
respectively, and 2023 EBITDA and free funds flow of $210.8 million ($40.06/bbl) and $90.7 million
($17.23/bbl) respectively and in line with cash flow guidance for 2023;
• Delivered Q4 net income of $21.5 million ($0.02/share) and over $110.5 million for 2023
($0.12/share); and,
• Paid total dividends of $0.06/share and repurchased 11.3 million common shares in 2023,
representing approximately $61 million of total capital returned to shareholders (approximately 11%
of December 31, 2023, market capitalization).
(1) Return on capital employed = earnings before interest and tax (“EBIT”) / (Total Assets – Current Liabilities)
(2) Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may
not be comparable with the calculation of similar measures presented by other entities. See “Selected Financial Measures”
section.
Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“PetroTal’s operational and financial targets were achieved in 2023, increasing average production 17% over
2022, repaying $80 million in debt and returning over $61 million to shareholders in the form of dividends and
share buybacks. The Company managed through a challenging dry season, to achieve market guidance and
exit December 2023 with production of approximately 20,000 bopd.
2024 is off to a record start having maintained nearly 19,000 bopd over the first two months in an eighty-
dollar oil price environment, enabling us to maintain a robust cash position through the first quarter. With
continued advancements on the OCP oil export pilot through Ecuador, the Company will continue to prioritize
derisking oil sales so PetroTal can embark on new production growth projects.
With its strong, debt free, balance sheet, PetroTal will continue to evaluate accretive growth opportunities. I
would like to thank shareholders for their continued support, as well as PetroTal’s board of directors and the
rest of the PetroTal team for their continued valuable contributions to our success.”
3 Selected Financial Highlights
The table below summarizes PetroTal’s comparative financial position.
Q4-2023
$/bbl
Three Months Ended
Q3-2023
$/bbl
$ 000
$82.21
$81.05
($20.28)
$60.77
$60.77
$7.00
$7.24
$1.46
$0.60
$0.10
$1.45
$3.61
$42.92
$6.21
$36.71
$29.13
$15.57
14,865
15,033
1,383,061
$84,046
$9,676
$10,010
$2,020
$828
$142
$2,001
$4,991
$59,369
$8,588
$50,781
$40,284
$21,529
912,314
$556,512
$0.02
$32,157
$84.65
$84.31
($19.25)
$65.05
$65.05
$5.49
$8.45
$1.72
$0.80
$0.13
$1.99
$4.64
$46.47
$6.92
$39.55
$50.76
$23.86
Year Ended December 31
$ 000
10,909
11,553
1,062,851
$69,142
$5,835
$8,982
$1,829
$845
$141
$2,114
$4,929
$49,396
$7,355
$42,041
$53,953
$25,359
916,700
$522,519
$0.03
$17,011
2023
$/bbl
$81.53
$80.54
($20.33)
$60.21
$60.21
$5.82
$6.16
$1.30
$0.66
$0.10
$0.78
$2.84
$45.39
$5.33
$40.06
$37.83
$20.99
$ 000
14,248
14,421
5,263,485
$316,911
$30,648
$32,446
$6,857
$3,475
$516
$4,115
$14,963
$238,854
$28,049
$210,805
$199,127
$110,505
912,314
$556,512
$0.12
$108,453
2022
$/bbl
$98.92
$96.67
($21.96)
$74.71
$74.71
$6.66
$6.86
$1.96
$1.34
$0.23
$0.76
$4.29
$56.90
$4.14
$52.77
$53.28
$39.22
$ 000
12,200
13,168
4,806,431
$359,106
$31,991
$32,954
$9,440
$6,431
$1,083
$3,668
$20,622
$273,539
$19,891
$253,648
$256,070
$188,527
862,209
$431,104
$0.219
$94,203
$5.87
$8,127
$34.76
$36,944
$17.23
$90,674
$33.68
$161,868
1.5%
$111,299
$57,298
7.1%
$112,827
$86,545
16.3%
$111,299
$57,298
37.5%
$119,969
$74,224
Average Production (bopd)
Average sales (bopd)
Total sales (bbls)(1)
Average Brent price
Contracted sales price, gross
Tariffs, fees and differentials
Realized sales price, net
Oil revenue(1)
Royalties(2)
Operating expense
Direct Transportation:
Diluent
Barging
Diesel
Storage
Total Transportation
Net Operating Income(3,4)
G&A
EBITDA(3)
Adjusted EBITDA(3,5)
Net Income
Basic Shares Outstanding (000)
Market Capitalization(6)
Net Income/Share ($/share)
Capex
Free Funds Flow(3) (7)
% of Market Capitalization(6)
Total Cash(8)
Net Surplus (Debt) (3) (9)
1. Approximately 85% of Q4 2023 sales were through the Brazilian route vs 82% in Q3 2023.
2. Royalties at year to date December 31, 2023 and December 31, 2022 include the impact of the 2.5% community social trust.
3. Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the
calculation of similar measures presented by other entities. See “Selected Financial Measures” section.
4. Net operating income represents revenues less royalties, operating expenses, and direct transportation.
5. Adjusted EBITDA is net operating income less general and administrative (“G&A”) and plus/minus realized derivative impacts.
6. Market capitalization for Q4, 2023, Q3 2023, and Q4 2022 assume share prices of $0.61 $0.57, and $0.50 respectively.
7. Free funds flow is defined as adjusted EBITDA less capital expenditures. See “Selected Financial Measures” section.
8. Includes restricted cash balances.
9. Net Surplus (Debt) = Total cash + all trade and net VAT receivables + short and long term net derivative balances – total current liabilities – long term debt
– non current lease liabilities – net deferred tax – other long term obligations.
4 Q4 2023 Financial Variance Summary
US$/bbl Variance Summary
Oil Sales (bopd)
Contracted Brent Price
Realized Sales Price
Royalties
Three Months Ended
Q3 2023
Q4 2023
Variance
Year Ended December 31
2022
2023
Variance
15,033
11,553
3,480
14,421
13,168
1,253
$81.05
$84.31
($3.26)
$80.54
$96.67
($16.13)
$60.77
$65.05
($4.28)
$60.21
$74.71
($14.50)
Total Opex and Transportation
$10.85
$13.09
($2.24)
$7.00
$5.49
$1.51
$5.82
$9.00
$6.66
($0.84)
$11.15
($2.15)
Net Operating Income(1,2)
$42.92
$46.47
($3.55)
$45.39
$56.90
($11.51)
G&A
EBITDA
Net Income
Free Funds Flow(1,3)
$6.21
$6.92
($0.71)
$5.33
$4.14
$1.19
$36.71
$39.55
($2.84)
$40.05
$52.77
($12.72)
$15.57
$5.87
$23.86
$34.76
($8.29)
($28.89)
$20.99
$17.23
$39.22
$33.68
($18.23)
($16.45)
Q4 2023 Financial Variance Commentary
• Weaker contracted Brent price of $81.05/bbl compared to the preceding quarter of $84.31/bbl,
•
resulting in a 7% lower realized price of $60.77/bbl.
Lower operating expenses per bbl resulting from higher sales volumes in Q4 2023 compared to Q3
2023. Q4 2023 operating expenses included additional floating storage costs caused by longer than
usual barge travel times during the final months of the dry season.
• Capital spending in the quarter was $32 million compared to $17 million in Q3 2023 driven by the
drilling commencement of well 16H and continued investment in water handling facilities. This
resulting in a decrease in Q4 2023 free funds flow(1,3) dollar figure to approximately $8.1 million
compared to $37 million in Q3 2023.
Liquidity was flat in Q4 2023 compared to Q3 2023, with total cash decreasing by $1.5 million to $111
million driven by favorable working capital timing.
Strong balance sheet position in Q4 2023 with no debt and a net surplus (1,4) of $57 million now
inclusive of a $42 million net deferred tax liability.
•
•
1. See “Selected Financial Measures”
2. Net operating income represents revenues less royalties, operating expenses, and direct transportation.
3. Free funds flow is defined as adjusted EBITDA less capital expenditures.
4. Net Surplus (Debt) = Total cash + all trade and net VAT receivables + short and long term net derivative balances – total current liabilities – long term debt
– non current lease liabilities – net deferred tax – other long term obligations.
5 Financial and Operating Updates Subsequent to December 31, 2023
Robust oil production. Production continues to trend ahead of 2024 guidance with the Company producing
20,453 bopd in January and 17,411 bopd in February 2024. March production to date has averaged 15,600
bopd with the Company’s most recently drilled well (16H) producing around 2,500 bopd and nearing full
investment payout. The field was shut down from March 6, 2024 until March 8, 2024 as a safety precaution
after an independently operated barging incident caused a small release of oil into the Puniuaha river
approximately 2km away from the field. No injuries were reported and the cleanup has been substantially
completed. The field downtime did not materially impact Q1 2024 production and the Company is still
expected to meet Q1 2024 production guidance of 18,500 bopd.
Well 17H update. The Company has completed drilling well 17H on time, materially on its $14 million budget,
and commenced production on March 1, 2024. The well has a total depth of approximately 4,960 meters
with a lateral section of 1,245 meters. Production since start up has averaged 3,300 bopd under natural flow
conditions allowing the well continuing to clean out drilling fluids and reach maximum initial production.
Well 18H drilling commencement. The Company commenced drilling well 18H on March 5, 2024 with an
estimated cost of $14 million. The well is expected to take approximately 60 days to drill and complete with
initial production estimated to occur by mid May 2024.
OCP pilot project. PetroTal is pleased to announce continued advancement on the OCP pilot oil shipment
with the signing of three key approvals. In early February 2024, the Company received approval letters from
the Ecuadorian Ministry of Environment and Ecuadorian Navy along with the successful signing of a use of
port agreement with Petroecuador. The Company is awaiting on a final letter from the Port Subsecretariate
to start the 100,000 bbl pilot. Pending success of the first pilot, the Company anticipates an additional pilot
in the second half of 2024 with recurring sales expected in Q4 2024.
2024 Budget guidance. On January 22, 2024, the Company released its 2024 guidance, forecasting an average
2024 production and sales target of 17,000 bopd, delivering an estimated 20% growth rate over 2023 average
production. If this forecast is acheived, PetroTal will generate approximately $200 million in EBITDA
underpinned by a total 2024 capex spend of $134 million and allowing for a stable return of capital program.
Should production and/or Brent price outperform the Company’s base case budget assumptions (Brent oil at
$77/bbl), liquidity sweep for shareholder return upside is possible. At March 15, 2024, the Company
estimates it is trending in line with budget expectations.
2023 year ended reserves. On February 12, 2024, PetroTal announced its updated reserves profile ending
December 31, 2023. The Company was able grow its 2P after tax per share reserves value to $1.80/share
with a $1.64 billion after tax net present value of reserves, discounted at 10% (“NPV10”) and associated 2P
reserves of 100 million bbls. The Company’s 2023 year ended 2P reserve replacement ratio is at 167%, with
an associated 2P reserve life index of 19 years. For the full text of this announcement, please refer to
PetroTal's press release dated February 12, 2024, filed on SEDAR+ (www.sedarplus.ca) and posted on
PetroTal's website (www.petrotalcorp.com). In addition to the summary information disclosed in this press
6 release, more detailed information will be included in the annual information form for the year ended
December 31, 2023, to be filed on SEDAR+ (www.sedarplus.ca) and posted on PetroTal's website
(www.petrotalcorp.com) on March 28, 2024.
Corporate presentation update. The Company has updated its Corporate Presentation, which is available
for download or viewing at www.petrotal-corp.com.
Q4 and 2023 full year webcast link for March 21, 2024
PetroTal will host a webcast for its Q4 2023 and 2023 full year results on March 21, 2024 at 9am CT
(Houston). Please see the link below to register.
https://stream.brrmedia.co.uk/broadcast/65d6373035af67d51a41b45b
ABOUT PETROTAL
PetroTal is a publicly traded, tri‐quoted (TSX: TAL, AIM: PTAL and OTCQX: PTALF) oil and gas development
and production Company domiciled in Calgary, Alberta, focused on the development of oil assets in Peru.
PetroTal's flagship asset is its 100% working interest in Bretana oil field in Peru's Block 95 where oil production
was initiated in June 2018. In early 2022, PetroTal became the largest crude oil producer in Peru. The
Company's management team has significant experience in developing and exploring for oil in Peru and is led
by a Board of Directors that is focused on safely and cost effectively developing the Bretana oil field. It is
actively building new initiatives to champion community sensitive energy production, benefiting all
stakeholders.
For further information, please see the Company's website at www.petrotal-corp.com, the Company's filed
documents at www.sedarplus.ca, or below:
Douglas Urch
Executive Vice President and Chief Financial Officer
Durch@PetroTal-Corp.com
T: (713) 609-9101
Manolo Zuniga
President and Chief Executive Officer
Mzuniga@PetroTal-Corp.com
T: (713) 609-9101
PetroTal Investor Relations
InvestorRelations@PetroTal-Corp.com
Celicourt Communications
Mark Antelme / Jimmy Lea
petrotal@celicourt.uk
7 T : 44 (0) 20 7770 6424
Strand Hanson Limited (Nominated & Financial Adviser)
Ritchie Balmer / James Spinney / Robert Collins
T: 44 (0) 207 409 3494
Stifel Nicolaus Europe Limited (Joint Broker)
Callum Stewart / Simon Mensley / Ashton Clanfield
T: +44 (0) 20 7710 7600
Peel Hunt LLP (Joint Broker)
Richard Crichton / David McKeown / Georgia Langoulant
T: +44 (0) 20 7418 8900
READER ADVISORIES
FORWARD-LOOKING STATEMENTS: This press release contains certain statements that may be deemed to be forward-
looking statements. Such statements relate to possible future events, including, but not limited to, oil production levels
and guidance. All statements other than statements of historical fact may be forward-looking statements. Forward-
looking statements are often, but not always, identified by the use of words such as "anticipate", "believe", "expect",
"plan", "estimate", "potential", "will", "should", "continue", "may", "objective" and similar expressions. Without
limitation, this press release contains forward-looking statements pertaining to: PetroTal's drilling, completions,
workovers and other activities; the Company's plans and expectations with respect to the OCP pilot oil shipment and its
continued advancement; anticipated future production and revenue; drilling plans including the timing of drilling,
commissioning, and startup; PetroTal’s 2024 guidance, including in respect of its production and sales target of 17,000
bopd and estimate that it will deliver a 20% growth rate over 2023 production and anticipated benefits thereof (i.e.,
that PetroTal will generate approximately $200 million in EBITDA as a result, underpinned by a total 2024 capex spend
of $134 million and allowing for a stable return of capital program and shareholder return upside); expectations with
respect to well 17H production; 2024 budget guidance; plans with respect to well 18H including in respect of anticipated
costs, completion and timing thereof including the Company’s plans to begin production at well 18H in May of 2024;
the Company’s expectation to meet Q1 2024 production guidance of 18,500 bopd; expectation that the Company will
continue to prioritize derisking oil sales so it can embark on new production growth projects; average 2024 production;
intentions with respect to return of capital and the 19 year 2P reserve life index. In addition, statements relating to
expected production, reserves, recovery, replacement, costs and valuation are deemed to be forward-looking
statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves
described can be profitably produced in the future. The forward-looking statements are based on certain key
expectations and assumptions made by the Company, including, but not limited to, expectations and assumptions
concerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated
therewith, the ability to obtain and maintain necessary permits and licenses, the ability of government groups to
effectively achieve objectives in respect of reducing social conflict and collaborating towards continued investment in
the energy sector, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the
actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and
performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labour, royalty regimes and exchange
rates, the impact of inflation on costs, the application of regulatory and licensing requirements, the accuracy of
PetroTal's geological interpretation of its drilling and land opportunities, current legislation, receipt of required
regulatory approval, the success of future drilling and development activities, the performance of new wells, future river
water levels, the Company's growth strategy, general economic conditions and availability of required equipment and
8 services. Although the Company believes that the expectations and assumptions on which the forward-looking
statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because
the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future
events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ
materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to,
risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and
production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and
expenses; and health, safety and environmental risks), commodity price volatility, price differentials and the actual
prices received for products, exchange rate fluctuations, legal, political and economic instability in Peru, access to
transportation routes and markets for the Company's production, changes in legislation affecting the oil and gas
industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; changes in the financial landscape both domestically and abroad,
including volatility in the stock market and financial system; and wars (including Russia's war in Ukraine and the Israeli-
Hamas conflict). Please refer to the risk factors identified in the Company's most recent annual information form and
MD&A which are available on SEDAR+ at www.sedarplus.ca. The forward-looking statements contained in this press
release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of new information, future events or otherwise, unless
so required by applicable securities laws.
OIL REFERENCES: All references to "oil" or "crude oil" production, revenue or sales in this press release mean "heavy
crude oil" as defined in NI 51-101. All references to Brent indicate Intercontinental Exchange ("ICE") Brent. Recovery
factor percentages include historical production.
RESERVES DISCLOSURE: All reserves values, future net revenue and ancillary information contained in this press release
are derived from from an independent reserves report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”)
effective December 31, 2023 unless otherwise noted. Estimates of reserves and future net revenue for individual
properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties,
due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by NSAI in
evaluating PetroTal's reserves will be attained and variances could be material. It should not be assumed that the
estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The
recovery and reserve estimates of PetroTal's oil reserves provided herein are estimates only and there is no guarantee
that the estimated reserves will be recovered. Actual oil reserves may be greater than or less than the estimates provided
herein. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash
flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only.
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.
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. Possible
reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g.,
when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the
requirements of the reserves category (proved, probable, possible) to which they are assigned. Certain terms used in
this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101,
Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the
9 COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff
Notice 51-324 and the COGEH, as the case may be.
SHORT TERM RESULTS: References in this press release to peak rates, production rates since inception, current
production rates, initial seven day production rates and other short-term production rates are useful in confirming the
presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence
production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While
encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of
PetroTal. The Company cautions that such results should be considered to be preliminary.
SPECIFIED FINANCIAL MEASURES: This press release includes various specified financial measures, including non-GAAP
financial measures, non-GAAP financial ratios and capital management measures as further described herein. These
measures do not have a standardized meaning prescribed by generally accepted accounting principles (“GAAP”) and,
therefore, may not be comparable with the calculation of similar measures by other companies. Management uses
these non- GAAP measures for its own performance measurement and to provide shareholders and investors with
additional measurements of the Company’s efficiency and its ability to fund a portion of its future capital expenditures.
“Adjusted EBITDA” (non-GAAP financial measure) is calculated as consolidated net income (loss) before interest and
financing expenses, income taxes, depletion, depreciation and amortization and adjusted for G&A impacts and certain
non-cash, extraordinary and non-recurring items primarily relating to unrealized gains and losses on financial
instruments and impairment losses, including derivative true-up settlements. PetroTal utilizes adjusted EBITDA as a
measure of operational performance and cash flow generating capability. Adjusted EBITDA impacts the level and extent
of funding for capital projects investments. Reference to EBITDA is calculated as net operating income less G&A. “Net
Operating Income” (non-GAAP financial measure) is calculated as revenues less royalties, operating expenses, and direct
transportation. The Company considers Net Operating Income measure as they demonstrate Company’s profitability
relative to current commodity prices. "Net surplus (debt)" (non-GAAP financial measure) is calculated by adding
together total cash, trade and VAT receivables, and short and long-term net derivative balances less total current
liabilities, long-term debt, non-current lease liabilities, deferred tax, and other long-term obligations. Net surplus (debt)
is used by management to provide a more complete understanding of the Company's capital structure and provides a
key measure to assess the Company's liquidity. “Free funds flow” (non-GAAP financial measure) is calculated as net
operating income less G&A less exploration and development capital expenditures less realized derivative gains/losses
and is calculated prior to all debt service, taxes, lease payments, hedge costs, factoring, and lease payments.
Management uses free funds flow to determine the amount of funds available to the Company for future capital
allocation decisions. Please refer to the MD&A for additional information relating to specified financial measures. “Free
cash flow” (non-GAAP financial measure) is calculated as EBITDA less G&A less Capex prior to the realization of any
derivative impacts.
OIL AND GAS MEASURES: This press release contains metrics commonly used in the oil and natural gas industry which
have been prepared by management, such as "reserves life index", “reserves replacement” and “per share reserves
value”. These terms do not have a standardized meaning and may not be comparable to similar measures presented by
other companies, and therefore should not be used to make such comparisons. "Reserve life index" is calculated as total
Company interest reserves divided by annual production. “Reserves replacement” is calculated as reserves in the
referenced category divided by estimated referenced production. “Reserves per share” or “per share reserves value” is
calculated as reserves in the referenced category divided by the number of shares of PetroTal’s common stock issued
and outstanding. These terms have been calculated by management and do not have a standardized meaning and may
not be comparable to similar measures presented by other companies, and therefore should not be used to make such
comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide
shareholders with measures to compare PetroTal's operations over time. Readers are cautioned that the information
10 provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied
upon for investment or other purposes.
FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information
(collectively, "FOFI") about PetroTal’s prospective results of operations and production results, free funds flow, cost
estimates, NPV10, tax rates, budget, EBITDA, 2024 capex, 2024 average production and production and sales targets,
balance sheet strength, shareholder returns and components thereof, all of which are subject to the same assumptions,
risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this press release was
approved by management as of the date of this press release and was included for the purpose of providing further
information about PetroTal's anticipated future business operations. PetroTal and its management believe that FOFI
has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, and represent, to
the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this
information is highly subjective, it should not be relied on as necessarily indicative of future results. PetroTal disclaims
any intention or obligation to update or revise any FOFI contained in this press release, whether as a result of new
information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the
FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein. All FOFI
contained in this press release complies with the requirements of Canadian securities legislation, including NI 51-101.
Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average
production estimates can have a significant impact on the key performance measures included in PetroTal's guidance.
The Company's actual results may differ materially from these estimates.
11 MANAGEMENT'S DISCUSSION AND ANALYSIS
For the years ended December 31, 2023 and 2022
TSX:TAL
AIM: PTAL
OTCQX: PTALF
TABLE OF CONTENTS
14
1. Corporate overview ……………………………………………………………………………………………………….……….
15
2. Overview and selected information...……………………………………………………………...……………………..
15
3. 2023 Highlights………………………………………………………………………………………………………………….......
16
4. Outlook and growth strategy ..…………………...………………..………………………………………………………..
18
5. Selected financial information………………………………………………………………………………………………...
29
6. 2023 Reserve Report ..…….........................…………………………………..……..………............................
31
7. Significant judgements and estimates ..…….........................…………………………………..……..………..
33
8. Disclosure pronouncements not yet adopted.......................…………………………………..…….………..
9. Related party transactions ..…….........................…………………………………..……..………................... 33
33
10. Taxes ..…….........................…………………………………..……..………....................................................
35
11. Contractual obligations and commitments………………………………………………………………………………
35
12. Forward-looking statements and business risks ………………………………………………………………………
13 MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) of the operating results and financial condition of PetroTal Corp. (“PetroTal”
or the “Company”) for the years ended December 31, 2023 and 2022, is dated March 19, 2024, and should be read in conjunction
with the Company’s unaudited Condensed Interim Consolidated Financial Statements (“Financial Statements”) for the years ended
December 31, 2023 and 2022. The Financial Statements were prepared by management in accordance with International Accounting
Standards (“IAS”) 34-Interim Financial Reporting as issued by the International Accounting Standards Board, which are also generally
accepted accounting principles (“GAAP”) for publicly accountable enterprises in Canada.
Financial figures throughout this MD&A are stated in thousands of United States dollars (“$” or “USD”) unless otherwise indicated.
This MD&A contains forward-looking statements that should be read in conjunction with the Company's disclosure under “Forward-
Looking Statements and Business Risks”.
1. CORPORATE OVERVIEW
PetroTal Corp. is a publicly-traded (TSX: TAL, AIM: PTAL, and OTCQX: PTALF) international oil and gas company incorporated and
domiciled in Canada, with management based in Houston, Texas and Lima, Peru. Through its two subsidiaries in Peru, the Company
is currently engaged in the ongoing development of hydrocarbons in Block 95 with a focus on the development of, and production
from the Bretana oil field. In addition to further leads in Block 95, the Company has exploration prospects and leads in Block 107.
The Bretana oil field is located in the Maranon Basin of northern Peru. To date, this basin has produced more than one billion barrels
of oil. Approximately 70% of the oil in the Maranon Basin has been produced from the Vivian formation and approximately 30%
from the Chonta formation. The Vivian formation is known as a quality oil reservoir with high permeabilities and strong aquifer
support. Generally, this type of reservoir achieves the highest oil recoveries. The Chonta formation is immediately below the Vivian
and typically produces medium to light oil; the Company is focused on the Vivian formation. The Company has a 100% working
interest in the Bretana oil field.
14 2. OVERVIEW AND SELECTED INFORMATION
The following table summarizes key financial and operating highlights associated with the Company’s performance for the years
ended December 31, 2023 and December 31, 2022, along with 2023 quarters.
RESULTS AT A GLANCE
Financial
Oil revenue
Royalties
Net operating income (1)
Commodity price derivatives (gain) loss
Net income
Basic earnings per share ($/share)
Capital expenditures
Operating
Average production (bopd)
Average sales (bopd)
Average Brent price ($/bbl)
Contracted sales price ($/bbl)
Netback ($/bbl) (1)
Funds flow provided by operations (2)
Balance Sheet
Cash and restricted cash
Working capital
Total assets
Current liabilities
Equity
Year Ended
Three Months Ended
December 31, 2023 December 31, 2022 December 31, 2023 September 30, 2023
June 30, 2023 March 31, 2023
$316,911
($30,648)
$238,854
$12,479
$110,505
$0.12
$108,453
14,248
14,421
81.53
80.54
45.39
$359,106
($31,991)
$273,539
($8,231)
$188,527
$0.22
$94,203
12,200
13,168
98.92
96.67
56.90
$84,046
($9,676)
$59,369
$11,662
$21,529
$0.02
$32,157
14,865
15,033
82.21
81.05
42.92
$69,142
($5,835)
$49,396
($12,701)
$25,359
$0.03
$17,010
10,909
11,553
84.65
84.31
46.47
$95,229
($8,899)
$76,573
$6,272
$46,635
$0.05
$26,367
19,031
18,483
77.29
77.88
45.53
$68,494
($6,238)
$53,515
$7,247
$16,979
$0.02
$32,919
12,193
12,618
82.51
80.32
47.12
$239,457
$172,020
$53,767
$86,124
$58,154
$41,412
$111,299
$121,649
$658,286
$81,533
$463,942
$119,969
$139,771
$602,880
$123,362
$399,331
$111,299
$121,649
$658,286
$81,533
$463,942
$112,827
$162,958
$618,200
$61,584
$462,557
$92,552
$155,990
$620,045
$81,959
$462,113
$71,635
$125,765
$565,891
$82,793
$421,229
(1)
(2)
Net operating income ("NOI") and Netback represent revenues less royalties, operating expenses and direct transportation.
Funds flow provided by operations does not have standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar
measures for other entities. See “Non-GAAP Measures” section.
3. 2023 HIGHLIGHTS
The Company reached several key operational and financial achievements as described below:
Q4 2023 Operational Highlights
-
Oil production of 1.4 million barrels ("mmbbls"), an average of 14,865 barrels of oil per day ("bopd"), an increase of 36%
from 10,909 bopd in Q3 2023, and a 43% increase from 10,374 bopd in Q4 2022. At December 31, 2023, the Company has
15 producing wells, 1 well awaiting completion and 3 water disposal wells;
Oil sales allocations were 85% as export through Brazil and 15% to the Iquitos refinery;
-
- With installation of the new L2 West Platform completed, the Company successfully drilled its first horizontal well 16H
("16H") on the new platform in December 2023. Well 16H was subsequently completed and started production in January
2024; and,
- Meetings continue between the communities, Perupetro, and the Puinahua District Municipality outlining executive
committee roles and controls towards finalizing the 2.5% community social trust fund's bylaws.
15
2023 Operational Highlights
-
-
-
-
Oil production of 5.2 mmbbls in 2023, representing an average of 14,248 bopd, an increase of 17% from 12,200 bopd (4.5
mmbbls realized) in 2022;
Oil sales allocations were 87% as export through Brazil and 13% sales to Iquitos refinery;
Annual independent reserve assessment, as prepared by Netherland Sewell and Associates, Inc. ("NSAI") shows increases in
all reserve categories:
•
•
•
Proved ("1P") reserves increased by 5% to 48.0 mmbbls. Net present value discounted at 10% ("NPV-10") after tax is
$888 million ($18.40/bbl, CAD $24.50/bbl);
Proved plus Probable ("2P") reserves increased by 4% to 100.2 mmbbls with NPV-10 after tax of $1.6 billion ($16.32/
bbl, CAD$21.73/bbl);
Proved plus Probable and Possible ("3P") reserves increased by 19% to 199.6 mmbbls with NPV-10 after tax of $2.5
billion ($12.54/bbl, CAD$16.70/bbl); and,
Original oil in place ("OOIP") remained consistent from 2022 levels. Currently at 326, 442 and 595 mmbbls respectively, for
the 1P, 2P and 3P cases.
2023 Financial Highlights
-
-
-
-
-
-
-
The Company generated revenue of $316.9 million (5.2 mmbbls sold, 14,421 bopd, $60.21/bbl) compared to $359.1 million
(4.8 mmbbls sold, 13,168 bopd, $74.71/bbl) in 2022;
Royalties paid to the Peruvian government were $23.4 million ($4.44/bbl, 7.4% of revenues) compared to $25.7 million
($5.35/bbl, 7.1% of revenues) in 2022. Contributions for the 2.5% community social trust fund, represented $7.3 million in
2023, as compared to $6.3 million in 2022;
Generated funds flow from operations of $239.5 million compared to $172.0 million in 2022;
Net operating income was $238.9 million ($45.39/bbl) compared to $273.5 million ($56.90/bbl) in 2022;
PetroTal repaid all $80 million of bond principal in Q1 2023, a year earlier than required;
The Company had cash and restricted cash of $111.3 million at year-end, compared to $119.9 million at year-end 2022; and,
PetroTal commenced its shareholder capital return policy in 2023 and paid dividends totaling $56 million, and repurchased
11,326,806 shares ($6.5 million).
December 31, 2023 Subsequent Events
- Well 16H produced at above expected level rates with a 26 day production average of approximately 4,850 bopd as at
-
-
February 11, 2024 with an estimated investment payback in Q2 2024;
PetroTal commenced drilling a new horizontal well (17H), with production by the end of Q1 2024; and,
On February 14, 2024, the Company declared a cash dividend of $0.02 per common share with a record date of February 29,
2024. The dividend was paid March 15, 2024.
4.
OUTLOOK AND GROWTH STRATEGY
Strategy Outlook
The capital program prioritizes management's strategy to maintain a strong balance sheet during the period of oil price volatility,
optimizing drilling activity to fit within cash flow. The Company's activity will focus on managing existing production and drilling new
wells during 2024. Base maintenance capital would require capital expenditures and additional activities included in the capital
program outlined as follows:
-
-
-
Completion of production facilities and infrastructure activities which includes optimization of existing facilities, wells and
some improvements aimed at lowering operating costs;
Drilling new wells focused on continuing development in the core area of Bretana oilfield; and,
Continued investment in environmental remediation and social initiatives as part of a sustained long-term effort to improve
the physical environment and to provide training programs and other community initiatives for the residents near the
Company’s operations.
The 2024 capital budget is based on an estimated average annual Brent oil price forecast of $77/bbl.
16
Growth Strategy
PetroTal’s strategy is focused on petroleum assets that have long-life reserves with production growth potential. Employing its
knowledge base and technical expertise, the Company is working to optimize its existing assets primarily through drilling new oil
wells to create long-term value for shareholders. This will be accomplished through the attainment of its main objectives: increasing
production, reserves, funds generated from operations, and net asset value ("NAV").
PetroTal’s strategic priorities are to:
Increase reserves and production;
-
- Maintain a strong balance sheet by controlling and managing capital expenditures;
-
-
-
-
Control costs through efficient management of operations;
Pursue new and proven technology applications to improve operations and assist exploration endeavors;
Expand infrastructure (pipelines, storage, treating capacity) to increase production capacity in a cost-effective manner; and,
Explore undeveloped acreage to identify and create development opportunities.
Throughout the period, PetroTal focused on achieving its priorities and implementing its capital programs in Peru. The Company will
fund its capital development program using funds generated from operations and existing cash. Strategic allocation of the work
program and budget is designated to provide additional recoverable reserves at the Peruvian oilfields and achieve production
growth.
Environmental and Social Governance (“ESG”) Strategy
PetroTal believes in creating long-term value for our shareholders, employees, suppliers, communities, customers, and the
government, as well as ensuring economic value, safety for people and the environment, and creating a better future for all.
Therefore, our sustainability strategy towards year 2030 rests on our shoulders. PetroTal's ESG vision is: “To create value and
generate more opportunities for the benefit of all”. The steps to measure our success are:
-
-
-
Develop measurable goals for 2025 and 2030 that will be built and reviewed with the participation of each department
throughout the Company;
Initiatives will be continually updated to achieve our goals;
The Sustainable Development Goals (“SDGs”) will be included, to which PetroTal contributes through its Sustainability Plan
to 2030;
- We are committed to reducing our carbon and water footprints, which means reducing emissions, waste, preventing oil
spills as much as possible, efficiently managing our use of water, focusing on the protection and conservation of biodiversity,
managing our impact positively, innovating where possible and doing all of the above safely;
- We are implementing an effective due diligence process to prevent possible human rights violations;
-
To materialize the aforementioned initiatives, we develop and promote talent in PetroTal, the community, and within our
suppliers; and,
- We maintain a constant and respectful dialogue with our stakeholders to inform and prevent conflicts.
Exploratory Block 107 – Osheki-Kametza
PetroTal has a 100% working interest in this 623,280 acre block. There are several prospective features, the largest being the Osheki-
Kametza prospect. Osheki-Kametza has the potential to contain in place volumes of 970.7 million barrels of oil equivalent ("mmboe")
according to the Company's independent reservoir engineers, NSAI. Resource estimates are based on maps generated from modern
seismic acquired in 2007 and 2014 and partially de-risked with a new 3D geologic model supporting Cretaceous age reservoirs with
high quality Permian source rocks. Additional reprocessing of existing seismic data and acquisition of new seismic data may be
required to enhance the structural configuration. The Company continues to work on the necessary permits and complete further
technical work for the Osheki-Kametza prospect which will allow PetroTal to consider progressing towards a drilling
recommendation. On January 6, 2023, Perupetro extended the Company's Block 107 exploratory license to April 2026.
17 5. SELECTED FINANCIAL INFORMATION
5.1 FINANCIAL SUMMARY
($ thousands)
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
2023
Q4-2023
Q3-2023
Q2-2023
Q1-2023
PRODUCTION:
Average Production (bopd)
SALES:
Average sales (bopd)
Total sales (bbls)
Average Brent price $81.53
Weighted contracted sales price, gross $80.54
LESS:
Tariffs, fees and differentials ($20.33)
Realized sales price, net $60.21
14,248
14,421
5,263,485
14,865
15,033
10,909
11,553
19,031
18,483
12,193
12,618
1,383,061
1,062,851
1,681,962
1,135,611
$82.21
$81.05
($20.28)
$60.77
$84.65
$84.31
($19.25)
$65.05
$77.29
$77.88
($21.26)
$56.61
$82.51
$80.32
($20.01)
$60.31
REVENUES:
LESS:
Oil revenue (1)
Royalties (2)
Operating expense
Direct Transportation:
Diluent
Barging
Diesel
Storage
Total Transportation
$60.21
$316,911
$60.77
$84,046 $65.05
$69,142 $56.61
$95,229 $60.31
$68,494
$5.82
$6.16
$1.30
$0.66
$0.10
$0.78
$2.84
$30,648
$7.00
$9,676 $5.49
$5,835 $5.29
$8,899 $5.49
$32,446
$7.24
$10,010 $8.45
$8,982 $4.22
$7,100 $5.60
$6,238
$6,354
$6,857
$1.46
$2,020 $1.72
$1,829 $0.98
$1,641 $1.20
$1,368
$3,475
$0.60
$828 $0.80
$845 $0.53
$896 $0.80
$516
$0.10
$142 $0.13
$141 $0.07
$120 $0.10
$4,115
$1.45
$2,001 $1.99
$2,114
$—
$—
$—
$906
$113
$—
$14,963
$3.61
$4,991 $4.64
$4,929 $1.58
$2,657 $2.10
$2,387
NET OPERATING INCOME
$45.39
$238,854
$42.92
$59,369 $46.47
$49,396 $45.53
$76,573 $47.12
$53,515
Netback as % of Revenue
75.4%
70.6%
71.4%
80.4%
General and administrative expense
Commodity price derivative loss (gain)
Financial expense
Income tax expense
Depletion, depreciation and amortization
$5.33
$2.37
$2.91
$6.27
$7.56
$28,049
$6.21
$8,588 $6.92
$7,355 $3.89
$6,548 $4.90
$12,479
$8.43
$11,662 ($11.95)
($12,701)
$3.73
$6,272 $6.38
$15,341
$2.28
$3,150 $1.12
$1,187 $1.22
$2,046 $7.89
$33,002
$2.95
$4,076 $18.30
$19,445 $1.64
$2,751 $5.93
$39,801
$8.33
$11,527 $7.49
$7,962 $7.23
$12,154 $7.18
Foreign exchange loss (gain)
($0.06)
($323)
($0.84)
($1,163)
$0.74
$789 $0.10
$167
($0.10)
NET INCOME
FUNDS FLOW PROVIDED BY OPERATIONS
$110,505
$239,457
$21,529
$53,767
$25,359
$86,124
$46,635
$58,154
78.1%
$5,559
$7,247
$8,958
$6,730
$8,158
($116)
$16,979
$41,412
(1) Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements.
(2) Royalties include 2.5% community social trust initiative.
18
($ thousands)
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
2022
Q4-2022
Q3-2022
Q2-2022
Q1-2022
PRODUCTION:
Average Production (bopd)
SALES:
Average sales (bopd)
Total sales (bbls)
Average Brent price $98.92
Weighted contracted sales price, gross $96.67
LESS:
Tariffs, fees and differentials ($21.96)
Realized sales price, net $74.71
12,200
13,168
4,806,431
10,374
10,420
958,624
12,229
12,186
14,467
14,616
11,746
15,518
1,121,132
1,330,026
1,396,648
$88.61
$88.22
($21.71)
$66.51
$97.89
$97.21
($22.14)
$75.07
$111.80
$111.39
($22.35)
$89.04
$97.49
$88.02
($21.61)
$66.41
REVENUES:
LESS:
Oil revenue (1)
Royalties
Operating expense
Direct Transportation:
Diluent
Barging
Diesel
Storage
Total Transportation
$74.71
$359,106
$66.51
$63,755 $75.07
$84,164 $89.04
$118,435 $66.41
$92,752
$6.66
$6.86
$1.96
$1.34
$0.23
$0.76
$4.29
$31,991
$6.08
$5,824 $10.43
$11,689 $6.09
$8,104 $4.56
$6,373
$32,954
$7.42
$7,115 $6.62
$7,423 $6.28
$8,355 $7.20
$10,061
$9,440
$1.33
$1,274 $1.23
$1,374 $1.45
$1,931 $3.48
$6,431
$0.86
$824 $1.05
$1,172 $0.71
$943 $2.50
$1,083
$0.15
$144 $0.10
$110 $0.05
$71 $0.54
$4,862
$3,493
$758
$3,668
$0.16
$152 $0.06
$63 $0.33
$442 $2.16
$3,011
$20,622
$2.50
$2,394 $2.44
$2,719 $2.54
$3,387 $8.68
$12,124
NET OPERATING INCOME
$56.90
$273,539
$50.51
$48,422 $55.60
$62,333 $74.13
$98,589 $45.97
$64,194
Netback as % of Revenue
76.2%
76.0%
74.1%
83.2%
General and administrative expense
$4.14
$19,891
$5.57
$5,339 $4.18
$4,689 $3.87
$5,143 $3.38
69.2%
$4,718
Commodity price derivative loss (gain)
($1.71)
($8,231)
($13.95)
($13,373)
$29.15
$32,686
($4.91)
($6,533)
($15.05)
($21,014)
Financial expense
Income tax expense (recovery)
Depletion, depreciation and amortization
Other expenses
Foreign exchange loss
NET INCOME
FUNDS FLOW PROVIDED BY OPERATIONS
$4.20
$3.62
$6.98
$0.20
$0.26
$20,169
$2.49
$2,387 $5.17
$5,792 $4.60
$6,113 $4.21
$17,390
$9.36
$8,975 $7.49
$8,392 $0.04
$53
($0.02)
$33,568
$7.42
$7,116 $7.06
$7,920 $6.90
$9,179 $6.70
$978
$1.02
$978
$—
$—
$—
$—
$—
$1,247
($0.18)
($176)
$0.23
$260 $0.29
$385 $0.56
$188,527
$172,022
$37,176
$59,383
$2,594
$46,207
$84,249
$60,688
$5,878
($29)
$9,353
$—
$777
$64,511
$5,743
Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements.
Royalties in Q3 2022 include the value since January 1, 2022 inception for the 2.5% community social trust initiative. Subsequent social trust contributions are
(1)
(2)
recorded in the corresponding quarter incurred.
19
EARNINGS STATEMENT INFORMATION
Revenue
Oil sales in 2023 increased by 10% to 5,263,485 barrels 14,421 bopd), compared to 4,806,431 barrels (13,168 bopd) in 2022. Sales
were 1,383,061 barrels (15,033 bopd) in Q4 2023 compared to 958,624 barrels (10,420 bopd) in Q4 2022.
The Company sells oil at three sales points: the local Iquitos refinery, exports through Brazil, and the Northern Peruvian Pipeline
("ONP"). In 2023, 87% of oil sales were through the Brazil export route and 13% to the Iquitos refinery. Sales to the ONP have been
curtailed since February 2022, pursuant to Petroperu's ability to fulfill terms of the sales agreement. Sales to the Iquitos refinery are
priced at the prevailing Brent oil price less a quality differential discount and barge transportation charges. Oil sales exported
through Brazil are on a freight on board ("FOB") Bretana basis, at the forecasted Brent oil price in three months, less a fixed amount
to cover all transportation and sales costs, including the quality differential. Sales to Petroperu at the Saramuro pump station for
transportation through the ONP and onward to the Bayovar port, are priced based on the forecasted Brent oil price in eight months,
less a quality differential, and is net of all pipeline and marketing fees. When the oil is ultimately sold by Petroperu at Bayovar,
PetroTal is subject to a valuation adjustment based on the actual price achieved by Petroperu, whether higher or lower than the
original forecasted price.
Royalties decreased to $30.6 million ($5.82/bbl) in 2023 from $32.0 million ($6.66/bbl) in 2022 and in Q4 2023 increased to $9.7
million ($7.00/bbl) from $5.8 million ($6.08/bbl) in Q4 2022. Beginning in Q3 2022, the 2.5% community social trust initiative is
included in royalties. Royalties for the Bretana oilfield are calculated on production, less transportation costs, starting at 5% based
on production of 5,000 bopd or less and 20% when production reaches 100,000 bopd or more, increasing on a straight-line basis.
Royalty determination in Peru is negotiated on an individual block basis, based either on production scales or on economic results.
Operating expenses in 2023 were $32.4 million ($6.16/bbl), as compared to $33.0 million ($6.86/bbl) in 2022 and in Q4 2023 were
$10.0 million ($7.24/bbl) versus $7.1 million ($7.42/bbl) in Q4 2022 . Higher oil production in Q4 2023 resulted in lower operating
costs per barrel due to fixed operating cost allocations.
20
Direct Transportation expenses in 2023 totaled $15.0 million ($2.84/bbl), representing barging and diluent blending costs, as
compared to $20.6 million ($4.29/bbl) in 2022 and in Q4 2023 totaled $5.0 million ($3.61/bbl) versus $2.4 million ($2.50/bbl) in Q4
2022. Direct transportation costs include $4.1 million ($0.78/bbl) in 2023 and $3.7 million ($0.76/bbl) in 2022 for storage and dry
season freight due to low river levels. Diluent costs fluctuate as a result of blending requirements for oil delivered to the Iquitos
refinery.
Diluent
Barging
Diesel
Dry season freight and storage
Total Direct Transportation
Year Ended
December 31
2023
December 31
2022
6,857
3,475
516
4,115
14,963
9,440
6,431
1,083
3,668
20,622
General and administrative ("G&A") expenses in 2023 were $28.0 million ($5.33/bbl), as compared to $19.9 million ($4.14/bbl) in
2022 and $8.6 million ($6.21/bbl) in Q4 2023 versus $5.3 million ($5.57/bbl) in Q4 2022. As production increases, per barrel G&A
costs will decrease.
Salaries and benefits
Legal, audit and consulting fees
Community support
Office rent and administrative
Share-based compensation plans
Costs directly attributable to PP&E and operating expenses
Total
Year Ended
December 31
2023
December 31
2022
14,065
9,459
3,100
4,350
4,364
(7,289)
28,049
10,994
4,830
2,372
2,870
4,089
(5,264)
19,891
Included in G&A are expenditures related to various community project initiatives for Bretana and neighboring communities.
PetroTal recognizes the importance of community alignment and support over the areas in which it operates.
The Company allocated $7.3 million of G&A in 2023 to capital projects and operating expenses, compared to $5.3 million in 2022.
Depletion, Depreciation and Amortization (“DD&A”) for 2023 was $39.8 million ($7.56/bbl) as compared to $33.6 million ($6.98/
bbl) in 2022 and in Q4 2023 totaled $11.5 million ($8.33/bbl) versus $7.1 million ($7.42/bbl) in Q4 2022. DD&A is determined using
the annual reserve report information prepared by NSAI at December 31, 2023. DD&A is calculated based on capital invested, future
capital, abandonment provision, production and 2P reserves.
Commodity price derivative loss of $12.5 million in 2023 is the net fair value change of outstanding embedded derivatives,
compared to $8.2 million derivative gain in 2022. The oil sales agreement with Petroperu for sales into the ONP are subject to oil
price variations when sold by Petroperu upon arrival at the Bayovar port.
Foreign exchange gain in 2023 was $323 thousand compared to a $1.2 million loss in 2022, and a $1.2 million gain in Q4 2023
compared to $176 thousand gain in Q4 2022 , due to fluctuations in relative currency positions and transactions.
Income tax expense of $33.0 million was recorded in 2023 compared to $17.4 million in 2022.
Financial expense was $15.3 million in 2023, mainly related to bond interest, and financial expense and accretion of
decommissioning obligation expense, as compared to $20.2 million in 2022.
21 BALANCE SHEET INFORMATION
5.2
BALANCE SHEET - SUMMARIZED
December 31, 2023
September 30, 2023
June 30, 2023
March 31, 2023
December 31, 2022
($ thousands)
Current Assets
Cash
Restricted cash
VAT receivable
Trade and other receivables
Inventory
Prepaid expenses
Derivative assets
Total Current Assets
Restricted cash
Trade Receivable long-term
VAT receivables and taxes
PPE and E&E, net
Derivative assets
Total Non-current Assets
Total Assets
Current Liabilities
Trade and other payables
Lease liabilities
Short-term debt
Total Current Liabilities
Leases and other long-term
Deferred income tax liabilities
Long-term debt
Long-term derivative liabilities
Decommissioning liabilities
Total Non-current Liabilities
Total Equity
Total Liabilities and Equity
$90,568
$14,731
$9,709
$58,602
$12,792
$7,462
$9,318
$203,182
$6,000
$20,370
$15,271
$408,537
$4,926
$455,104
$658,286
$79,328
$2,205
$—
$81,533
$28,723
$55,109
$—
$6,832
$22,147
$112,811
$463,942
$658,286
$94,109
$12,718
$9,634
$65,591
$16,028
$6,445
$20,017
$224,542
$6,000
$—
$8,436
$373,251
$5,971
$393,658
$618,200
$58,696
$2,888
$—
$61,584
$15,884
$51,548
$—
$6,914
$19,713
$94,059
$462,557
$618,200
$75,256
$11,296
$19,830
$100,806
$13,215
$7,036
$10,510
$237,949
$6,000
$—
$12,200
$361,230
$2,666
$382,096
$620,045
$59,302
$2,398
$20,259
$81,959
$16,459
$35,820
$—
$6,803
$16,891
$75,973
$462,113
$620,045
$56,390
$9,245
$14,953
$93,886
$11,397
$6,823
$15,864
$208,558
$6,000
$—
$3,213
$345,644
$2,476
$357,333
$565,891
$60,331
$2,328
$20,134
$82,793
$17,472
$24,222
$—
$5,217
$14,958
$61,869
$421,229
$565,891
$104,340
$9,629
$10,555
$107,275
$13,773
$5,475
$12,086
$263,133
$6,000
$—
$3,032
$319,252
$11,463
$339,747
$602,880
$67,195
$2,567
$53,600
$123,362
$18,384
$17,386
$27,845
$3,179
$13,393
$80,187
$399,331
$602,880
22 Cash and liquidity
At December 31, 2023, the Company held cash of $90.6 million and restricted cash of $20.7 million, totaling $111.3 million, a $8.7
million decrease from $120.0 million at December 31, 2022. Working capital was $121.6 million at December 31, 2023 as compared
to $139.8 million at December 31, 2022.
VAT receivable
VAT receivable - current
VAT receivable - non-current
Total VAT receivables
December 31, 2023 December 31, 2022
10,555
1,934
12,489
9,709
2,226
11,935
Valued Added Tax (“VAT”) in Peru is levied on the purchase of goods and services and is recoverable on contracted oil sales. As a
result of capital activity and oil sales during the period, the Company recovered $26.9 million during 2023 and expects to recover
$9.7 million in the short-term.
Trade and other receivables
Trade receivables
Other receivables
Total trade and other receivables
Represented as:
Current receivables
Non-current receivables
December 31, 2023 December 31, 2022
105,647
1,628
107,275
76,163
2,809
78,972
58,602
20,370
107,275
—
At December 31, 2023, trade receivables represent revenue related to the sale of oil. The balance is comprised of $26 million due
from Petroperu ($6 million is short term and $20 million is long term) and $50 million from export sales through Brazil (all of which
has been subsequently collected). No credit losses on the Company’s trade receivables have been incurred.
Capital expenditures
Drilling Program
Field Infrastructure
Fluid Handling Facilities (CPF)
Erosion Control
Abandonment
Block 95
Block 107
Other
Total
Year Ended
December 31, 2023 December 31, 2022
61,354
5,027
13,214
5,517
4,917
1,472
1,324
1,378
67,271
27,483
6,247
3,205
—
1,185
1,547
1,515
108,453
94,203
The Company’s primary focus is to increase oil production from existing wells, build on the success of drilling new wells and ensure
sufficient production facilities. The Company invested $108.5 million in capital programs in 2023, compared to $94.2 million in 2022.
The Company continues to invest in a variety of community, social and regulatory (“CSR”) initiatives. A strong emphasis on ESG is
prevalent throughout all areas of our operations.
At December 31, 2023, the Company has $9.0 million of exploration and evaluation assets related to Block 95 and Block 107.
23 Inventory
Oil inventory
Materials, parts and supplies
Total inventory
December 31, 2023
813
11,979
12,792
December 31, 2022
2,389
11,384
13,773
Oil inventory consists of stored oil barrels, which are valued at the lower of cost or net realizable value. Costs include operating
expenses, royalties, transportation, and depletion associated with production. Costs capitalized as inventory will be expensed when
the inventory is sold. At December 31, 2023, the oil inventory balance of $0.8 million consists of 35,320 barrels of oil valued at
$23.01/bbl (December 31, 2022: $2.4 million, based on 106,621 barrels of oil at $22.40/bbl). Materials, parts, and supplies, including
diluent, are expected to be consumed in the short-term.
Oil inventory at January 1, 2023
Production
Diluent added
Internal use (power generation) and other
Sales
Oil inventory at December 31, 2023
Trade and other payables
Trade payables
Accrued payables and other obligations
Total trade and other payables
Barrels
106,621
5,200,424
55,004
(63,244)
(5,263,485)
35,320
December 31, 2023 December 31, 2022
32,177
35,018
67,195
25,037
54,291
79,328
At December 31, 2023 and December 31, 2022, trade payables and other payables are primarily related to the drilling and
completion of wells and construction of production processing facilities. The other obligations are mainly related to the 2.5% social
fund for the benefit of local communities, which totaled to $12.2 million at December 31, 2023 ($5.1 million at December 31, 2022).
Commodity Price Derivatives
The derivative asset is classified as a Level 2 fair value measurement. The ONP Saramuro agreement, signed with Petroperu during
2021, includes a clause for the purchase price adjustment. The initial sales price is based on the arithmetic average of the ICE Brent
8-month forward price. The realized price is based on the tender price of the oil that is sold at the Bayovar terminal. The purchase
price adjustment represents the realized price less the initial sales price, and if negative, the Company will compensate Petroperu the
amount, multiplied by the volume sold or arranged by Petroperu. If the purchase price adjustment is positive, the Company will be
compensated by Petroperu in a similar manner.
The fair value change of the embedded derivative, considering an average future ICE Brent price marker differential, was recorded as
a loss on commodity price derivatives at December 31, 2023.
Net derivative asset at beginning of period
Cash settlements
Cash to be received
Realized gain (loss)
Unrealized gain (loss)
Net derivative asset at end of period
Year Ended December 31
2022
2023
20,370
(478)
—
(2,256)
(10,224)
7,412
36,724
3,585
(28,171)
17,488
(9,256)
20,370
24
Sales delivery /
Executed month
Expected
settlement month
Volume
mbbls
Price range
$/bbl
Hedged range
$/bbl
Net Derivative
Asset
Peru Embedded Derivatives (a)
Jan-21 to Feb-22
Feb-24 to Jun-26
2,422
a) Embedded derivative related to original Petroperu sales agreement.
55.32 to 85.26
70.85 to 78.39
Net Derivative Asset
7,412
7,412
During the year ended December 31, 2023, no barrels were sold by Petroperu and 2.4 million barrels remain in the pipeline or
storage tanks, awaiting final sale by Petroperu. A 1% change to the hedged range price would result in a $1.6 million change to the
net derivative asset.
Decommissioning liabilities
The undiscounted uninflated value of its estimated decommissioning liabilities is $39.0 million ($30.2 million in 2022). The present
value of the obligations was calculated using an average risk-free rate of 5.3% (December 31, 2022: 6.6%) to reflect the market
assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow
estimates. The inflation rate used in determining the cash flow estimate was 2.0%. The table below sets out the continuity of
decommissioning obligations.
Balance at January 1, 2022
Additions
Revisions to decommissioning liabilities
Expenditures
Accretion
Balance at December 31, 2022
Additions
Revisions to decommissioning liabilities
Accretion
Balance at December 31, 2023
22,101
1,916
(6,604)
(4,917)
897
13,393
5,390
2,370
994
22,147
25 Short and long-term debt
On February 16, 2023, in accordance with the terms of the bond agreement the company paid $25 million and on March 24, 2023,
the Company elected to repay the remaining $55 million bond principal, plus interest and fees of $2.9 million. The original bond
maturity was February 2024.
On March 2, 2023, the Company finalized a $20 million unsecured revolving loan with an interest rate of 8.97% with Banco de Credito
del Peru. The term of the loan is for two months with renewal options. No debt covenants were set forth by the lender in the loan
agreement. The funds were used to fund short-term working capital needs. On August 3, 2023, the Company repaid $20 million to
Banco de Credito del Peru for its revolving loan plus $0.7 million in accrued interest. At December 31, 2023, the $20 million revolving
loan remains fully available.
Leases
In prior years, PetroTal commenced a seven-year service lease arrangement with a supplier that provides turnkey power generation
equipment services. In Q4 2023, the Company signed an addendum to extend the lease to September 30, 2031 and lease additional
equipment in 2024, which resulted in a $12.4 million present value increase to lease assets and liabilities on the balance sheet. The
Company has the option to buy the equipment on April 30, 2031 for $3.0 million. The incremental borrowing rate used to measure
the lease liabilities was 8.5% for the dollar denominated lease.
The lease liabilities also include two office leases, one in Houston, Texas and one in Lima, Peru. The Houston lease is for a term of 6.2
years with an incremental borrowing rate of 6.5% and the Lima lease is for 5 years with an incremental borrowing rate of 8.5%.
Lease liabilities at January 1, 2022
Additions
Revisions
Payments
Interest on leases
Lease liabilities at December 31, 2022
Revisions
Payments
Interest on leases
Lease liabilities at December 31, 2023
Represented as:
Current liability
Non-current liability
As of December 31, 2023, total lease liabilities have the following minimum undiscounted payments per year:
Year
2024
2025
Thereafter
Total
17,661
7,263
(2,332)
(3,974)
1,024
19,642
12,389
(4,465)
1,304
28,870
2,205
26,665
5,014
5,043
26,272
36,329
26
Share capital
Authorized share capital consists of an unlimited number of common shares without nominal or par value. The holders of common
shares have one vote per share and are entitled to receive dividends as recommended by the Board. During 2023, all remaining
warrants were exercised, generating proceeds of $12.3 million.
As of March 19, 2024, PetroTal has the following securities outstanding (in thousands):
Common shares
Performance share units
Total
Dividends
915,449
20,802
936,251
98%
2%
100%
During the years ended December 31, 2023 and 2022, the Company paid dividends to shareholders in the amount of $55.6 million
and $0 million, respectively. The Company declared dividends per share in the amount of $0.015, $0.025 and $0.02 per quarter
beginning in Q2, respectively. The Company’s dividend policy is to pay dividends based on current liquidity exceeding $60 million.
Normal course issuer bid
On May 16, 2023, the Company announced that the Toronto Stock Exchange approved a notice of intention to commence a normal
course issuer bid ("NCIB"). The NCIB allows the Company to purchase up to 44,230,205 common shares (representing approximately
5% of outstanding common shares as at May 12, 2023) beginning May 18, 2023 and ending no later than May 17, 2024. Common
shares purchased under the NCIB will be cancelled.
During the years ended December 31, 2023 and 2022, the Company purchased 11,326,806 and zero common shares under the NCIB
for total consideration of $6.5 million and $0 million, respectively. The surplus between the total consideration and the carrying
value of the shares repurchased was recorded against retained earnings.
5.3
NON-GAAP TERMS
This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per
bbl, revenues and transportation expense adjusted, funds flow provided by operations, funds flow provided by operations per bbl,
funds flow netback per bbl, free funds flow and diluted funds flow per share that do not have any standardized meaning under GAAP
and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its
own performance measurement and to provide shareholders and investors with additional measurements of the Company’s
efficiency and its ability to fund a portion of its future capital expenditures.
NON-GAAP FINANCIAL MEASURES
Revenue and transportation expense adjustment
Revenue and transportation expense adjustment are a non-GAAP measure that includes transportation ONP pipeline tariff,
marketing fee, barging and diluent expenses. Tariff and marketing fees are expenses usually recorded by reducing revenues in the
financial statements.
27 Funds flow information
Funds flow provided by operations (“FFO”), is a non-GAAP measure that includes all cash generated from operating activities and
changes in non-cash working capital. The Company considers funds flow from operations to be a key measure as it demonstrates
Company’s profitability. A reconciliation from cash provided by operating activities to funds flow provided by operations is as
follows:
Cash flow from operating activities
Net income
Adjustments for:
Depletion, depreciation and amortization
Accretion of decommissioning obligation
Equity based compensation expense
Financial interest expense
Deferred income tax expense
Commodity price unrealized derivatives loss
Funds flow provided by operations before non-cash working capital
Settlement of abandonment liabilities
Changes in non-cash working capital:
Receivables and restricted cash
Advances and prepaid expenses
Inventory
Trade and other payables
Commodity price realized derivatives gain
Cash paid for income taxes
Net cash provided by operating activities
Three Months Ended
December 31
2023
2022
Year Ended
December 31
2023
2022
21,530
37,176
110,505
188,527
12,232
298
1,145
2,561
(3,160)
11,662
46,268
—
(15,760)
(906)
2,400
21,876
—
(111)
53,767
7,116
238
997
3,522
8,520
(13,375)
44,194
(2,868)
8,835
171
(2,120)
16,015
(3,492)
(1,352)
59,383
39,801
994
4,340
10,473
25,766
10,223
202,102
—
26,668
(746)
497
9,443
2,734
(1,241)
239,457
33,568
897
3,342
17,419
16,889
9,256
269,898
(4,917)
(114,318)
(1,204)
6,240
12,676
7,097
(3,453)
172,019
Free funds flow after investing activities is a non-GAAP measure and the Company considers free funds flow or free cash flow to be a
key measure as it demonstrates the Company’s ability to fund a return of capital without accessing outside funds and is calculated as
follows:
Cash flow from investing activities
Exploration and evaluation asset additions
Property, plant and equipment additions
Non-cash changes in working capital
Net cash used in investing activities
Net cash provided by operating and investing activities
Three Months Ended
December 31
2023
2022
Year Ended
December 31
2023
2022
(359)
(31,798)
(1,243)
(33,400)
20,367
(240)
(31,785)
563
(31,462)
27,921
(1,631)
(106,822)
2,700
(105,753)
133,704
(1,291)
(92,912)
(531)
(94,734)
77,285
28
CAPITAL MANAGEMENT MEASURES
Adjusted EBITDA
Adjusted EBITDA means earnings before interest, taxes, depreciation and amortization, and derivatives.
Net income
Adjustments to reconcile net income:
Depletion, depreciation and amortization
Financial expense
Income tax expense
Commodity price derivatives loss (gain)
EBITDA (non-GAAP)
Realized derivative instruments gain (loss)
Adjusted EBITDA (non-GAAP)
Capital expenditures
Free funds flow
Operating netback
Three Months Ended December 31
2023
2022
Year Ended December 31
2022
2023
21,530
37,176
110,505
188,527
11,527
3,150
4,076
11,662
51,946
(11,662)
40,284
(32,157)
8,127
7,116
2,387
8,974
(13,372)
42,280
(5,943)
36,338
(32,024)
4,314
39,801
15,341
33,002
12,479
211,128
(12,001)
199,127
(108,453)
90,674
33,568
20,169
17,390
(8,231)
251,423
4,647
256,070
(94,202)
161,868
The Company considers operating netbacks to be a key measure that demonstrates the Company’s profitability relative to current
commodity prices. Netback is calculated by dividing net operating income by total revenue.
6. 2023 RESERVE REPORT
Block 95 - Bretana oil field
Oil production commenced in Bretana in June 2018 via a long-term testing program of the single oil producer. In May 2019, the
Company received the approval of the Environmental Impact Assessment (“EIA”) to fully develop the Bretana field in Block 95. This
approval provided PetroTal with the necessary permits to execute its development strategy at Bretana.
The summary below sets forth PetroTal’s reserves at December 31, 2023, as presented by NSAI, a qualified independent reserves
evaluator. The figures in the following tables have been prepared in accordance with the standards contained in the most recent
publication of the Canadian Oil and Gas Evaluation Handbook (“COGE”) and the reserve definitions contained in National Instrument
51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). More detailed information will be included in PetroTal’s AIF
for the year ended December 31, 2023 to be posted on SEDAR (www.sedar.com) and on PetroTal’s website.
Summary of Oil Reserves and Net Present Values as of December 31, 2023
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved & Probable
Possible
Total Proved & Probable & Possible
Company Heavy Oil Reserves (mmbbl)
Future Net Revenue After Income Taxes Discounted at (in USD Million)
Gross
Net
0%
5%
10%
15%
20%
28.5
19.5
48.0
52.2
100.2
99.4
199.6
28.5
19.5
48.0
52.2
100.2
99.4
199.6
$673
$696
$1,369
$1,856
$3,225
$4,101
$7,326
$567
$517
$1,084
$1,151
$2,235
$1,779
$4,014
$487
$401
$888
$751
$1,639
$869
$2,508
$426
$321
$747
$510
$1,257
$471
$1,728
$378
$266
$644
$357
$1,001
$278
$1,279
29 Summary of Pricing and Inflation Rate Assumptions - Forecast Prices and Costs (US$/bbl)
Year-end Forecast
Brent January 1, 2023
Brent January 1, 2024
2024
$82.69
$78.00
2025
$81.03
$79.18
2026
$81.39
$80.36
2027
$82.65
$81.79
2028
$84.29
$83.41
2029
$85.98
$85.09
Year-end Crude Oil Reserves (mmbbl)
Category
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved plus Probable
Possible
Total Proved plus Probable & Possible
Year-end Net Present Value at 10% - After Income Tax ($ millions)
Category
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved plus Probable
Possible
Total Proved plus Probable & Possible
2023
28.5
19.5
48.0
52.2
100.2
99.4
199.6
2023
$487
$401
$888
$751
$1,639
$869
$2,508
2022
24.1
21.4
45.5
51.3
96.8
71.6
168.4
2022
$446
$339
$785
$724
$1,509
$959
$2,468
Change
18%
(9%)
5%
2%
4%
39%
19%
Change
9%
18%
13%
4%
9%
(9%)
2%
Year-end Net Asset Value ("NAV") per Share - After Tax
Category
Proved
Proved plus Probable
Proved plus Probable & Possible
US$/sh
$0.97
$1.80
$2.75
CAD$/sh
$1.29
$2.39
$3.65
US$/sh
$0.90
$1.75
$2.86
CAD$/sh
$1.23
$2.29
$3.47
December 31, 2023
December 31, 2022
Reserve Life Index ("RLI")
Category
Proved
Proved plus Probable
Proved plus Probable & Possible
December 31, 2023
9.2 years
19.3 years
38.4 years
30 Future Development Costs
The following information sets forth development and abandonment costs deducted in the estimation of PetroTal’s future net
revenue attributable to the reserve categories noted below:
Proved $125 million
Proved plus Probable $551 million
Proved plus Probable & Possible $768 million
The future development and abandonment costs are estimates of capital expenditures required in the future for PetroTal to convert
the corresponding reserves to proved developed producing reserves.
Bretana's reserve life index for 1P and 2P reserves is 9.2 years and 19.3 years, respectively. The cumulative capital invested
combined with all future development and abandonment costs represents total funding and development costs of $6.40/bbl for 1P
reserves, $7.69/bbl for 2P reserves and $4.49/bbl for 3P reserves.
Original Oil in Place (“OOIP”) largely flat from 2022 levels. Now at 326, 442, and 595 million bbls (“mmbbls”), respectively, for the 1P,
2P and 3P cases
In addition to ongoing development of the Bretana oilfield, there are other prospects within Block 95 and exploration opportunities
in Block 107.
7. SIGNIFICANT JUDGEMENTS AND ESTIMATES
Management is required to make judgments, assumptions and estimates that have a significant impact on the Company’s financial
results. Significant judgments in the Financial Statements include going concern, financing arrangements, impairment indicators,
assessment of transfers from Exploration and Evaluation (“E&E”) to Property, Plant and Equipment (“PP&E”), leases, derivatives,
asset acquisition and joint arrangements. Significant estimates in the Financial Statements include commitments, provision for
future decommissioning obligations, recoverable amounts for exploration and evaluation assets and accruals. In addition, the
Company uses estimates for numerous variables in the assessment of its assets for impairment purposes, including oil prices,
exchange rates, discount rates, cost estimates and production profiles. By their nature, all of these estimates are subject to
measurement uncertainty, may be beyond management’s control, and the effect on future Financial Statements from changes in
such estimates could be significant.
Critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Financial
Statements are included in the Financial Statements and the accompanying notes as of December 31, 2023 and 2022. Additional
information about significant judgements and estimates are included in PetroTal’s audited Financial Statements for the years ended
December 31, 2023 and 2022.
USES OF CRITICAL ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGEMENTS
The Company's critical estimates and associated assumptions are based on historical experience and other factors that are
considered relevant. Such estimates and assumptions affect the application of accounting policies and the reported amount of
assets, liabilities, income and expenses. Actual results may differ from estimates.
The critical estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognized in the same period if the revision affects only that period or in the period of the revision and future periods if the revision
affects current and future periods.
Critical estimates and judgements in applying accounting policies that have the most significant effect on the amounts recognized in
the Financial Statements are summarized below:
Functional Currency
The functional currency of each of the Company’s entities is the United States dollar, which is the currency of the primary economic
environment in which the entities operate.
31 Exploration and Evaluation Assets
The accounting for E&E assets requires management to make certain estimates and assumptions, including whether exploratory
wells have discovered economically recoverable quantities of reserves. Designations are sometimes revised as new information
becomes available. If an exploratory well encounters hydrocarbons, but further appraisal activity is required in order to conclude
whether the hydrocarbons are economically recoverable, the well costs remain capitalized as long as sufficient progress is being
made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of
the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and
regulatory matters. The concept of “sufficient progress” is an area of judgement, and it is possible to have exploratory costs remain
capitalized for several years while additional drilling is performed, or the Company seeks government, regulatory or partner approval
of development plans.
Petroleum and natural gas assets are grouped into cash generating units (“CGUs”) identified as having largely independent cash flows
and are geographically integrated. The determination of the CGUs was based on management’s interpretation and judgement.
Decommissioning Obligations
Decommissioning obligations will be incurred by the Company at the end of the operating life of wells or supporting infrastructure.
The ultimate asset decommissioning costs and timing are uncertain and cost estimates can vary in response to many factors including
changes to relevant legal and regulatory requirements, the emergence of new restoration techniques, and experience at other
production sites. As a result, there could be significant adjustments to the provisions established which would affect future financial
results. The expected amount of expenditure is estimated using a discounted cash flow calculation with a risk-free discount rate.
Liabilities for environmental costs are recognized in the period in which they are incurred, normally when the asset is developed, and
the associated costs can be estimated.
Deferred Tax Assets & Liabilities
The estimation of income taxes includes evaluating the recoverability of deferred tax assets based on an assessment of the
Company’s ability to utilize the underlying future tax deductions against future taxable income prior to the expiration of those
deductions. Management assesses whether it is probable that some or all of the deferred income tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon the generation of future taxable income, which in turn is dependent
upon the successful discovery, extraction, development and commercialization of oil and gas reserves. To the extent that
management’s assessment of the Company’s ability to utilize future tax deductions changes, the Company would be required to
recognize more or fewer deferred tax assets, and future income tax provisions or recoveries could be affected. The measurement of
deferred income tax provision is subject to uncertainty associated with the timing of future events and changes in legislation, tax
rates and interpretations by tax authorities.
Provisions, Commitments and Contingent Liabilities
Amounts recorded as provisions and amounts disclosed as commitments and contingent liabilities are estimated based on the terms
of the related contracts and management’s best knowledge at the time of issuing the Financial Statements. The actual results
ultimately may differ from those estimates as future confirming events occur.
The Company has one reportable business segment which did not have any critical accounting estimate changes during the past two
financial years.
32 8. DISCLOSURE PRONOUNCEMENTS NOT YET ADOPTED
Issuance of IFRS Sustainability Standards - IFRS S1 "General Requirements for Disclosure of Sustainability-related Financial
Information" and IFRS S2 "Climate-related Disclosures"
In June 2023 the International Sustainability Standards Board ("ISSB") issued its inaugural standards - IFRS S1 and IFRS S2. The ISSB
was formed as a new standard-setting board within the IFRS Foundation to issue standards that deliver a comprehensive global
baseline of sustainability-related financial disclosures, operating alongside the International Accounting Standards Board. IFRS S1
and IFRS S2 are effective for annual reporting periods beginning on or after January 1, 2024, with earlier application permitted, as
long as both standards are applied. IFRS S1 provides a set of disclosure requirements designed to enable companies to communicate
to investors about the sustainability-related risks and opportunities, while IFRS S2 sets out specific climate-related disclosures and is
designed to be used in conjunction with IFRS S1. The Company is currently reviewing the impact of the standards on its disclosures.
9. RELATED PARTY TRANSACTIONS
The Company had no related party transactions or off-balance sheet arrangements. The Company's key management includes the
Directors and Officers.
Salaries, incentives and short term benefits
Director's fees
Share-based compensation
Total
Year Ended December 31
2022
2023
1,846
1,014
2,430
5,290
1,785
1,050
1,615
4,450
Name
Manuel Pablo Zuniga-Pflucker (1)
Mark McComiskey (Chair)
Gary S. Guidry (2)
Ryan Ellson (2)
Gavin Wilson
Eleanor J. Barker
Roger M. Tucker
Jon Harris (3)
Felipe Arbelaez (6)
Emily Morris (4)
Luis Carranza (5)
Director Compensation
Compensation
Earned
Share-based
awards
Non-Equity
Incentive Plans
2023 Total
2022 Total
450,000
105,000
—
—
60,000
82,000
80,000
60,000
29,032
13,226
57,500
936,758
1,100,000
182,733
—
—
61,671
61,158
61,158
60,250
29,077
13,234
57,534
1,626,815
337,500
—
—
—
—
—
—
—
—
—
—
337,500
1,887,500
287,733
—
—
121,671
143,158
141,158
120,250
58,109
26,460
115,034
2,901,073
2,000,000
285,000
146,492
146,492
120,000
142,000
140,000
35,000
—
—
35,000
3,049,984
(1) Mr. Zuniga-Pflucker does not receive compensation fees or share-based awards for his role as a Director.
(2) Directors retired from the Board in September 2022.
(3) Directors joined the Board in September 2022.
(4) Director joined the Board in October 2023.
(5) Director retired from the Board in June 2023.
(6) Director joined the Board in July 2023.
10. TAXES
The Company’s effective tax rate is impacted each quarter by the relative pre-tax income earned by the Company’s operations in
Canada, U.S., and Peru. The Company is subject to statutory tax rates of 23% in Canada, 21% in the U.S. and 32% in Peru (activities of
the Company in Peru are subject to a 30% statutory tax rate plus 2% in accordance with Law 27343). The Company files federal
income tax returns and local income tax returns in the various jurisdictions.
33
The tax at the effective rate differed from the tax at the statutory rate as follows:
Earnings before income taxes
Canadian corporate tax rate
Expected income tax expense
Increase (decrease) in taxes resulting from:
Non-deductible expenses and other
Tax differential on foreign jurisdictions
Change in valuation allowance
Provision for income taxes
The deferred income tax balances are as follows:
Deferred income tax asset:
Property, plant, and equipment
Trade and other payables
Net operating loss carryover
Other tax pools
Deferred income tax asset
Deferred income tax liability:
Property, plant, and equipment
Derivative assets and liabilities
Preoperative expenses
Net operating loss carryover
Other tax pools
Deferred income tax liability
December 31, 2023 December 31, 2022
205,917
143,507
23.00 %
33,007
1,408
10,212
(11,625)
33,002
23.00 %
47,361
2,047
19,742
(51,760)
17,390
December 31, 2023 December 31, 2022
7
—
4,119
8,919
13,045
(58,554)
(2,372)
2,549
2,156
1,112
(55,109)
(11)
254
855
—
1,098
(46,886)
(5,643)
3,186
29,985
1,972
(17,386)
The Company recognized the net tax amount related to Net Operating Losses (“NOLs”) and deferred tax liabilities in Peru, Canada
and the US. As of December 31, 2023, the Company has $7 million in available tax losses in Peru (mainly related to Block 95), $21
million tax losses in Canada and $2 million in the US (December 31, 2022: $112 million, $69 million, and $1.7 million, respectively).
The Peruvian non-capital losses are expected to be used in 2024. The Canadian non-capital losses can be carried forward for twenty
years and there is generally no carryback period. The carryover period starts with the taxable year following the loss and continues
indefinitely. The US non-capital losses can be carried forward indefinitely.
The aggregate amount of temporary differences associated with investments in subsidiaries for which deferred tax liabilities have not
been recognized as of December 31, 2023 is approximately $29 million (December 31, 2022: $50 million).
34
11. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
GUARANTEES
As at December 31, 2023, the Company holds the following letters of credit guaranteeing its commitments for exploration blocks to
Perupetro S.A.:
Block
107
107
Beneficiary
Perupetro S.A.
Perupetro S.A.
Amount
$1,500
$1,500
$3,000
CONTRACTUAL OBLIGATIONS
Commitment
1st exploration well, minimum work 5th exploratory period
2nd exploration well, minimum work 5th exploratory period
Expiration
May 2026
May 2026
Refer to "Short and long-term debt" in section "5.2 Balance Sheet Information" for material changes to the Company's contractual
obligations.
12. FORWARD-LOOKING STATEMENTS AND BUSINESS RISKS
FOREIGN EXCHANGE RATE RISK
The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working
capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item.
Excluding the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss,
based on foreign currency balances held at December 31, 2023.
LIQUIDITY RISK
Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The
Company’s approach to managing liquidity risk is to have sufficient cash and/or credit facilities to meet its obligations when due.
Liquidity is managed through short and long-term cash, debt and equity management strategies. The Company’s liquidity risk is
impacted by current and future commodity prices. If required, the Company will also consider additional short-term financing or
issuing equity in order to meet its future liabilities. Declines in future commodity prices could affect the Company’s ability to fund
ongoing operations. The current economic environment and SARS-CoV-2 (“COVID-19”) has and may continue to have a significant
impact on the Company including, but not exclusively:
•
•
•
•
•
•
material declines in revenue and cash flows as a result of the decline in commodity prices;
declines in revenue and operating activities due to reduced capital programs and the shut-in of production;
inability to access financing sources;
increased risk of non-performance by the Company’s customers and suppliers;
interruptions in operations as the Company adjusts personnel to the dynamic environment; and,
delivery of oil at the Bayovar port and sale swap price risk.
The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on the
Company is not known at this time. Estimates and judgments made by management in the preparation of the financial statements
are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.
CREDIT RISK
Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial
loss to the Company. The Company’s VAT is primarily for sales tax credits on exploration and drilling expenses incurred in prior years.
These credits will be applied to future oil development activities or recovered as per the sales tax recovery legislation currently in
effect. The majority of the Company’s trade receivable balance relates to oil sales and purchase price adjustments to two customers,
being Petroperu, a state-owned company and Novum, an oil trading company. The Company has a long-term sales agreement for oil
exports through Brazil, whereby sales are FOB Bretana. Sales through the ONP pipeline are due and payable 240 days after the final
delivery of the oil to the Bayovar terminal. During Q4 2023, 82% of oil sales were to Novum (Brazil export route) and 18% were to
Petroperu (Iquitos refinery). The Company has not experienced any material credit losses in the collection of its trade receivables.
35 Impairment to a financial asset is only recorded when there is objective evidence of impairment and the loss event has an impact on
future cash flow and can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators
that the debtor may enter bankruptcy. Management believes that there is no risk on the recoverability and/or applicability of the
sales tax credits. Therefore, no impairment to the carrying value of these assets has been estimated. The Company has deposited its
cash and cash equivalents with reputable financial institutions, with which management believes the risk of loss to be remote. The
maximum credit exposure associated with financial assets is their carrying value. At December 31, 2023, the cash and cash
equivalents were held with six different institutions from three countries, mitigating the credit risk of a collapse of one particular
bank.
WORKFORCE MAY BE EXPOSED TO WIDESPREAD PANDEMIC
PetroTal’s operations are located in areas relatively remote from local towns and villages and represent a concentration of personnel
working and residing in close proximity to one another. Should an employee or visitor become infected with a serious illness that has
the potential to spread rapidly, this could place the workforce at risk. The 2020/2021 outbreak of the novel coronavirus in China and
other countries around the world is one example of such an illness. The Company takes every precaution to strictly follow industrial
hygiene and occupational health guidelines. There can be no assurance that this virus or another infectious illness will not impact the
Company’s personnel and ultimately its operations.
Additional information regarding risk factors including, but not limited to, risks related to political developments in Peru and
environmental risks is available in the Company’s Annual Information Form ("AIF"), a copy of which may be accessed through the
SEDAR website (www.sedar.com).
Certain statements contained in this MD&A may constitute forward-looking statements. These statements relate to future events or
the Company’s future performance, including, but not limited to: PetroTal's business strategy, objectives, strength, focus and
outlook, drilling, completions, workovers and other activities including expanding infrastructure and exploring undeveloped acreage
and the anticipated costs and results of such activities, environmental remediation and social initiatives, the ability of the Company
to achieve drilling success consistent with management's expectations, anticipated future production and revenue, oil production
levels, the 2024 capital program and budget, including drilling plans, balance sheet strength, COVID-19 surveillance and control
process, hedging program and the terms thereof, and future development and growth prospects. All statements other than
statements of historical fact may be forward-looking statements. In addition, statements relating to expected production, reserves,
prospective resources, recovery, costs and valuation are deemed to be forward-looking statements as they involve the implied
assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future.
Forward-looking statements are often, but not always, identified by the use of words such as “anticipate”, “plan”, “continue”,
“estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “intend”, “could”, “might”, “should”, “believe” and similar
expressions.
The forward-looking statements are based on certain key expectations and assumptions made by the Company, including, but not
limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver production and the anticipated
capital expenditures associated therewith, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices
and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance
of drilling rigs, facilities, pipelines, other oilfield services and skilled labor, royalty regimes and exchange rates, the application of
regulatory and licensing requirements, the accuracy of PetroTal's geological interpretation of its drilling and land opportunities,
current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance
of new wells, the Company's growth strategy, general economic conditions and availability of required equipment and services.
Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are
reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance
that they will prove to be correct. The Company believes that the expectations reflected in those forward-looking statements are
reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements
included in this MD&A should not be unduly relied upon by investors. These statements speak only as of the date of this MD&A and
are expressly qualified, in their entirety, by this cautionary statement.
These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ
materially from those anticipated in such forward-looking statements. These include, but are not limited to, risks associated with the
oil and gas industry in general (e.g., operational risks in development, exploration and production, delays or changes in plans with
respect to exploration or development projects or capital expenditures, the uncertainty of reserve estimates, the uncertainty of
estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price
volatility, price differentials and the actual prices received for products, exchange rate fluctuations, legal, political and economic
instability in Peru, access to transportation routes and markets for the Company's production, changes in legislation affecting the oil
36 and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development
projects or capital expenditures. In addition, the Company cautions that current global uncertainty with respect to the spread of the
COVID-19 virus and its effect on the broader global economy may have a significant negative effect on the Company. While the
precise impact of the COVID-19 virus on the Company remains unknown, rapid spread of the COVID-19 virus may continue to have a
material adverse effect on global economic activity, and may continue to result in volatility and disruption to global supply chains,
operations, mobility of people and the financial markets, which could affect interest rates, credit ratings, credit risk, inflation,
business, financial conditions, results of operations and other factors relevant to the Company. Please refer to the risk factors
identified in the AIF which is available on SEDAR at www.sedar.com.
Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, there can be no
assurance that such expectations will prove to be correct. The Company cannot guarantee future results, levels of activity,
performance, or achievements. The risks and other factors, some of which are beyond the Company’s control, could cause results to
differ materially from those expressed in the forward-looking statements contained in this MD&A.
The forward-looking statements contained in this MD&A are expressly qualified by the foregoing cautionary statement. Subject to
applicable securities laws, the Company is under no duty to update any of the forward-looking statements after the date hereof or to
compare such statements to actual results or changes in the Company’s expectations. Financial outlook information contained in this
MD&A about prospective results of operations, financial position or cash flows is based on assumptions about future events,
including economic conditions and proposed courses of action, based on management’s assessment of the relevant information
currently available. Readers are cautioned that such financial outlook information should not be used for purposes other than for
which it is disclosed herein.
Prospective resources are the quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered
accumulations by application of future development projects. Estimates of prospective resources included in this document relating
to the Osheki prospect are based upon an independent assessment completed by NSAI with an effective date of September 30, 2018
and prepared in accordance with Canadian Oil and Gas Evaluation Handbook ("COGE") and the standards established by NI 51-101.
For additional information about the Company’s prospective resources, see the Company’s website for the most current press
release.
37 ADDITIONAL INFORMATION
On February 16, 2023, the Company graduated from the TSX Venture Exchange to the Toronto Stock Exchange. The trading symbol
remains the same, "TAL".
Additional information about PetroTal Corp. and its business activities, including PetroTal’s audited Financial Statements for the years
ended December 31, 2022 and 2021 are available on the Company's website at www.petrotal-corp.com, and at www.sedarplus.ca, or
below:
DIRECTORS
Mark McComiskey (1)(4)
Chair of the Board
Felipe Arbelaez (3)(4)
Eleanor Barker (4)
Jon Harris (1)(2)
Emily Morris
Roger Tucker (2)(3)
Gavin Wilson (1)(2)(3)
Manuel Pablo Zuniga-Pflucker (2)
OFFICERS AND SENIOR EXECUTIVES
Manuel Pablo Zuniga-Pflucker
President and Chief Executive Officer
Douglas Urch
Executive VP and Chief Financial Officer
Jose Contreras
Senior VP of Operations
Glen Priestley
VP Finance and Treasurer
Guillermo Florez
General Manager Peru
CORPORATE HEADQUARTERS
PetroTal Corp.
16200 Park Row, Suite 310
Houston, Texas 77084
Office: 713.609.9101
info@petrotal-corp.com
www.petrotal-corp.com
LEGAL COUNSEL
Stikeman Elliott LLP
Calgary, Alberta, Canada
AUDITORS
Deloitte LLP
Calgary, Alberta, Canada
Lima, Peru
REGISTERED OFFICE
PetroTal Corp.
4200 Bankers Hall West, 888-3rd Street
Calgary, Alberta, Canada
NOMINATED & FINANCIAL ADVISER
Strand Hanson Limited
London, United Kingdom
OPERATING OFFICE
PetroTal Peru SRL
144 Dionisio Derteano, Suite 1200
San Isidro
Lima, Peru
JOINT BROKERS
Stifel Nicolaus Europe Limited
London, United Kingdom
Peel Hunt LLP
London, United Kingdom
STOCK EXCHANGES
TSX Exchange
Toronto, Ontario, Canada
TSX: TAL
AIM Stock Exchange
London, United Kingdom
AIM: PTAL
OTCQX Stock Exchange
New York, USA
OTCQX: PTALF
RESERVES EVALUATORS
Netherland, Sewell & Associates, Inc.
Dallas, Texas, USA
TRANSFER AGENT AND REGISTRAR
Computershare Trust Company of Canada
Calgary, Alberta, Canada
London, United Kingdom
Massachusetts, USA and New Jersey, USA
(1) Member of the Corporate Governance and Compensation Committee.
(2) Member of the Reserves Committee.
(3) Member of the HSES Committee.
(4) Member of the Audit Committee.
38
GLOSSARY / ABBREVIATIONS
1P
2P
3P
AIF
bbl
bopd
CGUs
COGE
COVID-19
CSR
DD&A
E&E
EIA
ESG
FOB
FFO
G&A
GAAP
IFRS
ISSB
MD&A
mmbbls
mmboe
NAV
NCIB
Netback
NI 51-101
NOI
NSAI
OCP
ONP
OOIP
PP&E
RLI
SDGs
VAT
Proved
Proved plus Probable
Proved plus Probable and Possible
Annual Information Form
Barrel
Barrels of Oil per Day
Cash Generating Units
Canadian Oil and Gas Evaluation Handbook
SARS-CoV-2
Community, Social and Regulatory
Depletion, Depreciation and Amortization
Exploration and Evaluation
Environmental Impact Assessment
Environmental and Social Governance
Freight on board
Funds Flow Provided by Operations
General and Administrative
Generally Accepted Accounting Principles
International Financial Reporting Standards
International Sustainability Standards Board
Management's Discussion and Analysis
Million Barrels
Million Barrels of Oil Equivalent
Net Asset Value
Normal Course Issuer Bid
Benchmark to assess the profitability based on revenues less royalties, operating and transportation costs
National Instruments - Standards of Disclosure for Oil and Gas Activities
Net Operating Income
Netherland Sewell and Associates, Inc.
OCP Ecuador Pipeline
Northern Peruvian Pipeline
Original Oil in Place
Property, Plant and Equipment
Reserve Life Index
Sustainable Development Goals
Value Added Tax
39
CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2023, and 2022
TSX: TAL
AIM: PTAL
OTCQX: PTALF
TABLE OF CONTENTS
1. Management’s report ........................................................................................................................................
2. Independent auditor’s report .............................................................................................................................
3. Consolidated balance sheets ..............................................................................................................................
4. Consolidated statements of earnings and other comprehensive income ........................................................
5. Consolidated statements of changes in equity ..................................................................................................
6. Consolidated statements of cash flows .............................................................................................................
7. Notes to the Consolidated Financial Statements ..............................................................................................
42
43
47
48
49
50
51
41 MANAGEMENT’S REPORT
The accompanying audited Consolidated Financial Statements and all information in the management’s discussion and analysis and
notes to the Consolidated Financial Statements are the responsibility of management. The Consolidated Financial Statements were
prepared by management in accordance with International Accounting Standards outlined in the notes to the Consolidated Financial
Statements. Other financial information appearing throughout the report is presented on a basis consistent with the Consolidated
Financial Statements.
Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance
that transactions are appropriately authorized, assets are safeguarded, and financial records properly maintained to provide reliable
information for the presentation of Consolidated Financial Statements.
The Audit Committee meets quarterly with management and the independent auditors to review auditing matters, financial
reporting issues, and to satisfy itself that all parties are properly discharging their responsibilities. The Audit Committee also reviews
the Consolidated Financial Statements, the management’s discussion and analysis of financial results, and the independent auditor’s
report. The Audit Committee reports its findings to the Board of Directors for its approval of the Consolidated Financial Statements
for issuance to the shareholders.
The Consolidated Financial Statements have been audited, on behalf of the shareholders, by the Company’s independent auditors, in
accordance with Canadian generally accepted auditing standards. Independent auditor has full and free access to the Audit
Committee.
Signed “Manuel Pablo Zuniga-Pflucker”
Signed “Douglas Urch”
Manuel Pablo Zuniga-Pflucker
Douglas Urch
President and Chief Executive Officer
Executive VP and Chief Financial Officer
March 19, 2024
42 Deloitte LLP
850 – 2nd Street SW
Suite 700
Calgary AB T2P 0R8
Canada
Phone: 403‐267‐1700
Fax: 403‐264‐2871
www.deloitte.ca
Independent Auditor's Report
To the Shareholders of
PetroTal Corp.
Opinion
We have audited the consolidated financial statements of PetroTal Corp. (the "Company"), which
comprise the consolidated balance sheets as at December 31, 2023 and 2022, and the consolidated
statements of earnings and other comprehensive income, changes in equity and cash flows for the years
then ended, and notes to the consolidated financial statements, including material accounting policy
information (collectively referred to as the "financial statements").
In our opinion, the accompanying financial statements present fairly, in all material respects, the financial
position of the Company as at December 31, 2023 and 2022, and its financial performance and its cash
flows for the years then ended in accordance with International Financial Reporting Standards ("IFRS").
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards
("Canadian GAAS"). Our responsibilities under those standards are further described in the Auditor’s
Responsibilities for the Audit of the Financial Statements section of our report. We are independent of the
Company in accordance with the ethical requirements that are relevant to our audit of the financial
statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these
requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to
provide a basis for our opinion.
Key Audit Matters
Key audit matters are those matters that, in our professional judgment, were of most significance in our
audit of the consolidated financial statements for the year ended December 31, 2023. These matters
were addressed in the context of our audit of the consolidated financial statements as a whole, and in
forming our opinion thereon, and we do not provide a separate opinion on these matters.
Derivative Assets and Derivate Liabilities (embedded derivative) — Refer to Note 9 to the
financial statements
Key Audit Matter Description
The company has an agreement for the sale of crude oil with Petroleos del Peru (PetroPeru S.A. a state
owned company based in Peru). Under the agreement, the Company has exposure to the volatility of oil
commodity prices until the crude oil is finally sold by PetroPeru to its customers at the Bayovar terminal
(i.e., final settlement date). The exposure to fluctuations of future commodity prices is an embedded
derivative and is measured at fair value at the end of the reporting period. The fair value of the derivative
is calculated using the future strip prices of Brent on the estimated final settlement dates for each
shipment that has not reached Bayovar terminal.
43
Determining the fair value of the embedded derivative required management to make significant
estimates and assumptions regarding future strip prices of Brent on the estimated final settlement dates.
Auditing these estimates and assumptions required a high degree of auditor judgment in applying audit
procedures and in evaluating the results of those procedures. This resulted in an increased extent of
audit effort.
How the Key Audit Matter Was Addressed in the Audit
Our audit procedures related to the fair value determination of the embedded derivative included the
following, among others:
Evaluated management’s ability to accurately estimate the final settlement dates by:
- Comparing historical sales settlement dates with management’s estimated final settlement dates;
- Obtaining corroborating evidence to support management’s estimate of the settlement date, as
well as assessing whether there was any evidence contradicting management’s estimates;
Evaluated the reasonableness of the prices used in the determination of the fair value of the
embedded derivative by independently assessing the price to future third‐party strip prices of Brent,
considering the estimated final settlement dates; and
Recalculated the fair value of the embedded derivative and compared it to the fair value determined
by management.
Property, Plant and Equipment – Petroleum interests ‐ Refer to Note 11 to the financial
statements
Key Audit Matter Description
The Company’s property, plant and equipment includes petroleum interests. Petroleum interests are
measured by depleting the assets on a unit‐of‐production method (“depletion”) based on total estimated
proved plus probable reserves. The Company engages independent reserve engineers to estimate the
proved plus probable reserves using estimates, assumptions, and engineering data. The development of
the Company’s reserves used to evaluate depletion requires management to make significant estimates
and assumptions related to future crude oil prices, reserves, and future operating and development costs.
Given the significant judgments made by management related to future crude oil prices, reserves, and
future operating and development costs, these estimates and assumptions are subject to a high degree of
estimation uncertainty. Auditing these estimates and assumptions required auditor judgement in applying
audit procedures, including the extent of reliance on management’s expert, and in evaluating the results
of those procedures. This resulted in an increased extent of audit effort.
How the Key Audit Matter Was Addressed in the Audit
Our audit procedures related to future crude oil prices, reserves, and future operating and development
costs used to determine depletion included the following, among others:
Evaluated future crude oil prices by independently developing a reasonable range of forecasts based
on reputable third‐party forecasts and market data and comparing those to the future crude oil
prices selected by management;
Evaluated the Company’s independent reserve engineers by examining reports and assessed their
scope of work and findings; and assessing the competence, capability, and objectivity by evaluating
their relevant professional qualifications and experience;
Evaluated the reasonableness of reserves by testing the source financial information underlying the
reserves and comparing the reserve volumes to historical production volumes;
44
Evaluated the reasonableness of future operating and development costs by testing the source
financial information underlying the estimate, comparing future operating and development costs to
historical results, and evaluating whether they are consistent with evidence obtained in other areas
of the audit.
Other Information
Management is responsible for the other information. The other information comprises:
Management's Discussion and Analysis
Our opinion on the financial statements does not cover the other information and we do not and will not
express any form of assurance conclusion thereon. In connection with our audit of the financial
statements, our responsibility is to read the other information identified above and, in doing so, consider
whether the other information is materially inconsistent with the financial statements or our knowledge
obtained in the audit, or otherwise appears to be materially misstated.
We obtained Management’s Discussion and Analysis prior to the date of this auditor’s report. If, based on
the work we have performed on this other information, we conclude that there is a material
misstatement of this other information, we are required to report that fact in this auditor’s report. We
have nothing to report in this regard.
Responsibilities of Management and Those Charged with Governance for the
Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in
accordance with IFRS, and for such internal control as management determines is necessary to enable the
preparation of financial statements that are free from material misstatement, whether due to fraud or
error.
In preparing the financial statements, management is responsible for assessing the Company’s ability to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the
going concern basis of accounting unless management either intends to liquidate the Company or to
cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company's financial reporting process.
Auditor's Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are
free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that
includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an
audit conducted in accordance with Canadian GAAS will always detect a material misstatement when it
exists. Misstatements can arise from fraud or error and are considered material if, individually or in the
aggregate, they could reasonably be expected to influence the economic decisions of users taken on the
basis of these financial statements.
As part of an audit in accordance with Canadian GAAS, we exercise professional judgment and maintain
professional skepticism throughout the audit. We also:
Identify and assess the risks of material misstatement of the financial statements, whether due to
fraud or error, design and perform audit procedures responsive to those risks, and obtain audit
evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting
a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal
control.
45 Obtain an understanding of internal control relevant to the audit in order to design audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by management.
Conclude on the appropriateness of management’s use of the going concern basis of accounting and,
based on the audit evidence obtained, whether a material uncertainty exists related to events or
conditions that may cast significant doubt on the Company's ability to continue as a going concern. If
we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s
report to the related disclosures in the financial statements or, if such disclosures are inadequate, to
modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our
auditor’s report. However, future events or conditions may cause the Company to cease to continue
as a going concern.
Evaluate the overall presentation, structure and content of the financial statements, including the
disclosures, and whether the financial statements represent the underlying transactions and events in
a manner that achieves fair presentation.
Obtain sufficient appropriate audit evidence regarding the financial information of the entities or
business activities within the Company to express an opinion on the financial statements. We are
responsible for the direction, supervision and performance of the group audit. We remain solely
responsible for our audit opinion.
We communicate with those charged with governance regarding, among other matters, the planned
scope and timing of the audit and significant audit findings, including any significant deficiencies in
internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant
ethical requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
From the matters communicated with those charged with governance, we determine those matters that
were of most significance in the audit of the consolidated financial statements of the current period and
are therefore the key audit matters. We describe these matters in our auditor's report unless law or
regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we
determine that a matter should not be communicated in our report because the adverse consequences
of doing so would reasonably be expected to outweigh the public interest benefits of such
communication.
The engagement partner on the audit resulting in this independent auditor’s report is Christopher Gill.
/s/ to be signed Deloitte LLP
Chartered Professional Accountants
March 19, 2024
46 CONSOLIDATED BALANCE SHEETS
($ thousands of US Dollars)
ASSETS
Current Assets
Cash
Restricted cash
VAT receivable
Trade and other receivables
Inventory
Prepaid expenses
Derivative assets
Total Current Assets
Non-current Assets
Restricted cash
Trade receivable long-term
Exploration and evaluation assets
Property, plant and equipment
Deferred income tax asset
VAT receivable
Derivative assets
Total Non-current Assets
Total Assets
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables
Lease liabilities
Short-term debt
Total Current Liabilities
Non-current Liabilities
Long-term debt
Long-term derivative liabilities
Lease liabilities
Decommissioning liabilities
Deferred income tax liabilities
Other long-term obligations
Total Non-current Liabilities
Total Liabilities
Equity
Share capital
Contributed surplus
Retained earnings
Total Equity
Total Liabilities and Equity
See accompanying notes to the Consolidated Financial Statements
Note
December 31
2023
December 31
2022
4
4
5
6
7
8
9
4
6
10
11
23
5
9
13
15
12
12
9
15
14
23
16
90,568
14,731
9,709
58,602
12,792
7,462
9,318
203,182
6,000
20,370
8,973
399,564
13,045
2,226
4,926
455,104
658,286
79,328
2,205
—
81,533
—
6,832
26,665
22,147
55,109
2,058
112,811
194,344
140,672
9,853
313,417
463,942
658,286
104,340
9,629
10,555
107,275
13,773
5,475
12,086
263,133
6,000
—
7,342
311,910
1,098
1,934
11,463
339,747
602,880
67,195
2,567
53,600
123,362
27,845
3,179
17,075
13,393
17,386
1,309
80,187
203,549
130,196
6,262
262,873
399,331
602,880
47 CONSOLIDATED STATEMENTS OF EARNINGS AND OTHER COMPREHENSIVE INCOME
($ thousands of US Dollars, except per share amounts)
For the years ended December 31
REVENUES
Oil revenues, net of royalties and social fund
Total revenue
EXPENSES
Operating
Direct transportation
General and administrative
Other expenses
Finance expense
Commodity price derivatives loss (gain)
Depletion, depreciation and amortization
Foreign exchange (gain) loss
Total expenses
Income before income taxes
Current income tax expense
Deferred income tax expense
Net income and comprehensive income
Basic earnings per share
Diluted earnings per share
Weighted average number of common shares outstanding (000's)
Basic
Diluted
See accompanying notes to the Consolidated Financial Statements
Note
2023
2022
17
20
18
19
9
23
23
286,263
286,263
32,446
14,963
28,049
—
15,341
12,479
39,801
(323)
142,756
143,507
7,236
25,766
110,505
0.12
0.12
900,075
920,899
327,115
327,115
32,954
20,622
19,891
978
20,169
(8,231)
33,568
1,247
121,198
205,917
501
16,889
188,527
0.22
0.21
845,761
906,710
48 CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
($ thousands of US Dollars)
For the years ended December 31
Share capital
Balance, beginning of year
Repurchase of shares
Exercise of warrants
Balance, end of period
Contributed surplus
Balance, beginning of year
Share-based compensation plan
Balance, end of period
Retained earnings
Balance, beginning of year
Dividends paid
Net income and comprehensive income
Repurchase of shares
Balance, end of period
Total Equity
See accompanying notes to the Consolidated Financial Statements
Note
2023
2022
16
16
16
16
130,196
(1,839)
12,315
140,672
6,262
3,591
9,853
262,873
(55,566)
110,505
(4,395)
313,417
463,942
126,696
—
3,500
130,196
3,215
3,047
6,262
74,346
—
188,527
—
262,873
399,331
49 CONSOLIDATED STATEMENTS OF CASH FLOWS
($ thousands of US Dollars)
For the years ended December 31
Cash flows from operating activities
Net income
Adjustments for:
Depletion, depreciation and amortization
Accretion of decommissioning obligations
Share-based compensation plan
Commodity price unrealized derivatives loss
Finance expenses
Deferred income tax expense
Settlement of decommissioning liabilities
Changes in working capital:
- Receivables and taxes
- Advances and prepaid expenses
- Inventory
- Trade and other payables
- Commodity price realized derivatives
Cash paid for income taxes
Net cash provided by operating activities
Cash flows from investing activities
Property, plant and equipment additions
Exploration and evaluation asset additions
Non-cash changes in working capital
Net cash used in investing activities
Cash flows from financing activities
Interest and fees paid
Net proceeds from exercise of warrants
Repayment of debt principal
Funds received from credit facility
Payments of dividends to shareholders
Repurchase of shares
Payment of current lease liabilities
Net cash used in financing activities
Increase (decrease) in cash
Cash, beginning of period
Restricted cash
Cash, end of the period
See accompanying notes to the Consolidated Financial Statements
Note
2023
2022
110,505
188,527
14
9
14
9
11
10
16
12
12
15
4
39,801
994
4,340
10,223
10,473
25,766
—
26,668
(746)
497
9,445
2,734
(1,241)
239,459
(106,822)
(1,631)
2,700
(105,753)
(8,426)
12,315
(100,000)
20,000
(55,566)
(6,234)
(4,465)
(142,376)
(8,670)
104,340
(5,102)
90,568
33,568
897
3,342
9,256
17,419
16,889
(4,917)
(114,318)
(1,204)
6,240
12,676
7,097
(3,453)
172,019
(92,912)
(1,291)
(531)
(94,734)
(11,300)
3,500
(20,000)
—
—
—
(3,974)
(31,774)
45,511
44,919
13,910
104,340
50 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2023 and 2022. All amounts are stated in thousands of United States Dollars ($) unless otherwise
indicated.
1. CORPORATE INFORMATION
PetroTal Corp. (the “Company” or “PetroTal”) is a publicly-traded energy company incorporated and domiciled in Canada. The
Company is engaged in the exploration, appraisal and development of oil and natural gas in Peru, South America. The Company’s
registered office is located at 4300 Bankers Hall West, 888 – 3rd Street S.W., Calgary, Alberta, Canada.
These Consolidated Financial Statements (the “Financial Statements”) have been prepared on a going concern basis, which assumes
that the Company will continue its operations for the foreseeable future and will be able to realize its assets and discharge its
liabilities in the normal course of business.
The Company evaluated subsequent events and transactions that occurred after the balance sheet date up to the date that the
Financial Statements were issued.
These Financial Statements were approved for issuance by the Company’s Board of Directors on March 19, 2024, on the
recommendation of the Audit Committee.
2. BASIS OF PREPARATION
STATEMENT OF COMPLIANCE
The Company prepares its annual Financial Statements in accordance with International Financial Reporting Standards (“IFRS”).
BASIS OF MEASUREMENT
These Financial Statements have been prepared on a historical cost basis except for certain financial instruments that have been
measured at fair value. In addition, these Financial Statements have been prepared using the accrual basis of accounting.
PRINCIPLES OF CONSOLIDATION
The Company’s Financial Statements include the accounts of the Company and its subsidiaries. The Financial Statements of the
subsidiaries are prepared for the same reporting period as the parent Company’s, using consistent accounting practices.
Inter-company balances and transactions, and any unrealized gains arising from inter-company transactions with the Company’s
subsidiaries, are eliminated on consolidation.
The entities included in the Company’s Financial Statements are PetroTal Corp. and its 100% owned subsidiaries PetroTal USA Corp.,
PetroTal LLC, PetroTal Energy International (Peru) Holdings B.V., PetroTal Peru B.V., Petrolifera Petroleum Del Peru S.R.L. and
PetroTal Peru S.R.L.
USES OF ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGEMENTS
The preparation of the Company’s Financial Statements requires management to make judgement, estimates, and assumptions that
affect the application of accounting policies and the reported amount of assets, liabilities, income and expenses. The estimates and
associated assumptions are based on historical experience and other factors that are considered relevant. Actual results may differ
from estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in
the same period if the revision affects only that period or in the period of the revision and future periods if the revision affects
current and future periods.
Estimates and critical judgements in applying accounting policies that have the most significant effect on the amounts recognized in
the Financial Statements are summarized below:
Functional Currency
The functional currency of each of the Company’s entities is the United States dollar, which is the currency of the primary economic
environment in which the entities operate.
51 Exploration and Evaluation Assets
The accounting for exploration and evaluation (“E&E”) assets requires management to make certain estimates and assumptions,
including whether exploratory wells have discovered economically recoverable quantities of reserves. Designations are sometimes
revised as new information becomes available. If an exploratory well encounters hydrocarbons, but further appraisal activity is
required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalized as long as
sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this
determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development
activities, commercial evaluation and regulatory matters. The concept of “sufficient progress” is an area of judgement, and it is
possible to have exploratory costs remain capitalized for several years while additional drilling is performed, or the Company seeks
government, regulatory or partner approval of development plans.
Petroleum and natural gas assets are grouped into cash generating units (“CGUs”) identified as having largely independent cash
flows and are geographically integrated. The determination of the CGUs was based on management’s interpretation and judgement.
Decommissioning Obligations
Decommissioning obligations will be incurred by the Company at the end of the operating life of wells or supporting infrastructure.
The ultimate asset decommissioning costs and timing are uncertain and cost estimates can vary in response to many factors
including changes to relevant legal and regulatory requirements, the emergence of new restoration techniques, and experience at
other production sites. As a result, there could be significant adjustments to the provisions established which would affect future
financial results. The expected amount of expenditure is estimated using a discounted cash flow calculation with a risk-free discount
rate. Liabilities for environmental costs are recognized in the period in which they are incurred, normally when the asset is
developed, and the associated costs can be estimated.
Deferred Tax Assets & Liabilities
The estimation of income taxes includes evaluating the recoverability of deferred tax assets based on an assessment of the
Company’s ability to utilize the underlying future tax deductions against future taxable income prior to the expiration of those
deductions. Management assesses whether it is probable that some or all of the deferred income tax assets will not be realized.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income, which in turn is
dependent upon the successful discovery, extraction, development and commercialization of oil and gas reserves. To the extent that
management’s assessment of the Company’s ability to utilize future tax deductions changes, the Company would be required to
recognize more or fewer deferred tax assets, and future income tax provisions or recoveries could be affected. The measurement of
deferred income tax provision is subject to uncertainty associated with the timing of future events and changes in legislation, tax
rates and interpretations by tax authorities.
Provisions, Commitments and Contingent Liabilities
Amounts recorded as provisions and amounts disclosed as commitments and contingent liabilities are estimated based on the terms
of the related contracts and management’s best knowledge at the time of issuing the Financial Statements. The actual results
ultimately may differ from those estimates as future confirming events occur.
MATERIAL ACCOUNTING POLICIES
a.
Cash and Restricted Cash
Cash includes deposits held with banks in Canada, the United States and Peru that are available on demand and highly
liquid. The Company’s restricted cash is cash reserved for letters of credit guaranteeing the Company’s commitments for
the exploration of Block 107, acquisition of qualified hydrocarbon assets, permitted hedging programs, and the 2.5% social
development trust fund (“social fund”) for the benefit of local communities. The restricted cash is not available for the
Company’s immediate or general business use.
b. Property, Plant and Equipment
Property, plant and equipment (“PP&E”) is recorded at cost less accumulated depreciation. Depreciation begins when the
asset is put into service and is calculated annually using the straight-line method. The cost of maintenance and repairs is
charged to expense as incurred. The cost of significant renewals and improvements is added to the carrying amount of the
respective asset. When assets are retired, or otherwise disposed of, the cost and related accumulated depreciation are
removed from the balance, and any resulting gain or loss is reflected in the consolidated statements of earnings and
comprehensive income.
When commercial production in an area has commenced, petroleum properties, excluding surface costs are depleted using
the unit-of-production method over their proved plus probable reserve life. Proved plus probable reserves are determined
annually by qualified independent reserve engineers. Changes in factors such as estimates of future crude oil prices,
52 reserves and future operating and development costs that affect unit-of-production calculations are accounted for on a
prospective basis.
c.
Leases
The Company assesses each new contract to determine whether it contains a lease. A specific asset is the subject of a lease
if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
The Company allocates contract consideration to the lease and non-lease components on the basis of their relative stand-
alone prices.
The right-of-use asset is initially measured at cost, which includes: (i) the amount of the initial measurement of the lease
liability, (ii) any lease payments made at or before the lease commencement date, less any lease incentives received, (iii)
any initial direct costs incurred, and (iv) an estimate of restoration costs.
The lease liability and initial right-of-use asset are recognized at the lease commencement date measured at the present
value of fixed lease payments (including in-substance fixed payments) plus the exercise price of a purchase option if the
lessee is reasonably certain to exercise that option, discounted at a rate the Company would be required to borrow over a
similar term.
Key judgements include whether a contract identifies an asset (or a portion of an asset), whether the lessee obtains
substantially all of the economic benefits of the asset over the contract term, whether the lessee has the right to direct the
asset’s use, which components are fixed or variable in nature and the discount rate. The Company applied its incremental
borrowing rate for leases where the implicit rate cannot be readily determined. Right-of-use assets are presented within
property, plant and equipment.
After initial recognition, the lease liability is accreted for the passage of time and reduced for lease settlements made during
each period. If the lease terms indicate that the Company will exercise a purchase option, the right-of-use asset is
depreciated from the lease commencement date to the end of the useful life of the underlying asset. Otherwise, the right-
of-use asset is depreciated to the earlier of the end of the useful life of the underlying asset or to the end of the lease term.
Additionally, the Company remeasures the lease liability (and makes a corresponding adjustment to the related right-of-use
asset) whenever:
(a) The lease term has changed or there is a significant event or change in circumstances resulting in a change in the
assessment of exercise of a purchase option, in which case the lease liability is remeasured by discounting the revised
lease payments using a revised discount rate.
(b) The lease payments change due to changes in an index or rate or a change in expected payment under a guaranteed
residual value, in which case the lease liability is remeasured by discounting the revised lease payments using an
unchanged discount rate (unless the lease payments change is due to a change in a floating interest rate, in which case
a revised discount rate is used).
(c) A lease contract is modified and the lease modification is not accounted for as a separate lease, in which case the
lease liability is remeasured based on the lease term of the modified lease by discounting the revised lease payments
using a revised discount rate at the effective date of the modification.
d.
Impairment
Financial assets carried at amortized cost
At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at
amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net earnings (loss).
Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an
event occurring after the impairment was recognized.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its
carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are
assessed collectively in groups that share similar credit risk characteristics.
Non-financial assets
At each reporting date, the carrying amounts of the Company’s non-financial assets are reviewed to determine whether
there is indication of impairment, except for E&E assets, which are reviewed when circumstances indicate impairment may
exist. If there is indication of impairment, the asset's recoverable amount is estimated and compared to its carrying value.
53 For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generate cash
inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash-
generating unit). The recoverable amount of an asset or a CGU is the greater of its value in use or its fair value less costs to
sell. The Company’s CGUs are not larger than a segment. In assessing both fair value less costs to sell and value in use, the
estimated future cash flows are discounted to their present value using an after-tax discount rate that reflects current
market assessments of the time value of money and the risks specific to the asset. An impairment loss is recognized if the
carrying amount of an asset or its CGU (Company has a single segment) exceeds its estimated recoverable amount.
Impairment losses are recognized in net earnings (loss). Fair value less costs to sell and value in use is generally computed
by reference to the present value of the future cash flows expected to be derived from production of proved and probable
reserves.
E&E assets are tested for impairment when they are transferred to petroleum properties and also if facts and circumstances
suggest that the carrying amount of E&E assets may exceed the recoverable amount. Impairment indicators are evaluated
at a CGU level. Indication of impairment includes:
•
•
•
•
Expiry or impending expiry of lease with no expectation of renewal;
Lack of budget or plans for substantive expenditures on further E&E;
Cessation of E&E activities due to a lack of commercially viable discoveries; and
Carrying amounts of E&E assets are unlikely to be recovered in full from a successful development project.
Impairment losses recognized in prior years are assessed at each reporting date for indication that the loss has decreased or
no longer exists. An impairment loss may be reversed if there has been a change in the estimates used to determine the
recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed
the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment
loss had been recognized.
Inventory
Inventory consists of crude oil and supplies to be used in the production and exploration activities, and is measured at the
lesser of cost and net realizable value. The cost of crude oil inventory includes all costs incurred in bringing the inventory to
its storage location. These costs, including operating expenses, royalties, transportation and depletion, are capitalized in
the ending inventory balance. The cost of the inventory is recognized using the weighted average method.
Financial Instruments
On initial recognition, financial instruments are measured at fair value. Measurement in subsequent periods depends on
the classification of the financial instrument:
e.
f.
•
•
•
Fair value through profit or loss - subsequently carried at fair value with changes recognized in net earnings (loss).
Financial instruments under this classification include cash and cash equivalents, and derivative commodity
contracts;
Fair value through other comprehensive income - transaction costs under this classification are expensed as
incurred. Financial instruments under this classification include derivative assets and liabilities where hedge
accounting is applied; and
Amortized cost - subsequently carried at amortized cost using the effective interest rate method. Financial
instruments under this classification includes accounts receivable, accounts payable and accrued liabilities and
long-term debt.
IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management.
Derivative instruments are not used for trading or speculative purposes. The Company does not designate financial
derivative contracts as effective accounting hedges, and thus does not apply hedge accounting. As a result, the Company's
policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the
Consolidated Balance Sheet at fair value with a corresponding gain or loss in net earnings (loss). Attributable transaction
costs are recognized in net earnings (loss) when incurred. The estimated fair value of all derivative instruments is based on
quoted market prices and/or third-party market indications and forecasts.
Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract
when their economic characteristics and risks are not closely related to those of the host contract; when the terms of the
embedded derivatives are the same as those of a freestanding derivative; and when the combined contract is not measured
at fair value through profit or loss. The timing of the expected delivery to the final point of sale drives the value of the
embedded derivative in the Petroperu contract, as the fair value of the derivative depends on the oil price at the time of the
54 expected sale date at the final point of sale. Refer to Note 9 for the classification and measurement of these financial
instruments.
The Company’s financial instruments consist of cash, trade and other receivables, derivative assets, trade and other
payables, derivative liabilities, and short and long-term debt and are included in the Company’s balance sheet. The
Company initially measures financial instruments at fair value.
g.
Exploration and Evaluation Assets
E&E costs are those expenditures for an area where technical feasibility and commercial viability have not yet been
determined. All costs directly associated with the exploration and evaluation of oil and natural gas reserves are initially
capitalized. These costs include acquisition costs, exploration costs, geological and geophysical costs, decommissioning
costs, E&E drilling, sampling and appraisals. Costs incurred prior to acquiring the legal rights to explore an area are
expensed as incurred.
At each reporting date, the carrying amounts of the Company’s exploration and evaluation assets are reviewed to
determine whether there is any indication that those assets are impaired. If any such indication exists, the recoverable
amount of the asset is estimated in order to determine the extent of the impairment, if any. The recoverable amount is the
greater of its value in use and its fair value less costs to sell. If the recoverable amount of an asset is estimated to be less
than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount and the impairment loss is
recognized in profit or loss for the year. The exploration and evaluation phase of a particular project is completed when
both the technical feasibility and commercial viability of extracting oil or gas are demonstrable for the project or there is no
prospect of a positive outcome for the project. Exploration and evaluation assets with commercial reserves will be
reclassified to development and production assets and the carrying amounts will be assessed for impairment and adjusted
(if appropriate) to their estimated recoverable amounts.
When an area is determined to be technically feasible and commercially viable the accumulated costs are transferred to
property, plant and equipment, where they are depleted. Exploration and evaluation assets are not amortized during the
exploration and evaluation stage. When an area is determined not to be technically feasible and commercially viable or the
Company decides not to continue with its activity, the unrecoverable costs are charged to comprehensive income (loss) as
impairment of exploration and evaluation assets.
h. Decommissioning Obligations
The Company recognizes a decommissioning liability in relation to the evaluation and exploration assets and to property,
plant and equipment, in the period in which a reasonable estimate of the fair value can be made of the statutory,
contractual, constructive or legal liabilities associated with the retirement of the oil and gas properties, facilities and
pipelines. The amount recognized is the estimated cost of decommissioning, discounted to its present value using a
discount rate. The estimates are reviewed periodically. Changes in the provision resulting from changes to the timing of
expenditures, climate-related matters, costs or risk-free rates are dealt with prospectively by recording an adjustment to
the provision and a corresponding adjustment to property, plant and equipment or exploration and evaluation assets. The
unwinding of the discount on the decommissioning provision is charged to the consolidated statements of earnings and
comprehensive income. Actual costs incurred upon settlement of the obligations are charged against the provision to the
extent of the liability recorded and the remaining balance of the actual costs is recorded in the consolidated income
statement.
i.
Income Taxes
Income tax expense is comprised of current and deferred tax. Current tax and deferred tax are recognized in net income or
loss except to the extent that it relates to a business combination or items recognized directly in equity or in other
comprehensive income or loss. Current income taxes are recognized for the estimated income taxes payable or receivable
on taxable income or loss for the current year and any adjustment to income taxes payable in respect of previous years.
Current income taxes are determined using tax rates and tax laws that have been enacted or substantively enacted by the
year-end date. Deferred tax assets and liabilities are recognized where the carrying amount of an asset or liability differs
from its tax base, except for taxable temporary differences arising on the initial recognition of goodwill and temporary
differences arising on the initial recognition of an asset or liability in a transaction which is not a business combination and
at the time of the transaction affects neither accounting nor taxable profit or loss. Recognition of deferred tax assets for
unused tax losses, tax credits and deductible temporary differences is restricted to those instances where it is probable that
future taxable profit will be available against which the deferred tax asset can be utilized. At the end of each reporting
period the Company reassesses unrecognized deferred tax assets. The Company recognizes a previously unrecognized
deferred tax asset to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be
recovered.
55 j.
Revenue Recognition
Under IFRS 15, revenue is recognized when a customer obtains control of the goods or services as stipulated in a
performance obligation. Determining whether the timing of the transfer of control is at a point in time or over time
requires judgement and can significantly affect when revenue is recognized. In addition, the entity must also determine the
transaction price and apply it correctly to the goods or services contained in the performance obligation.
The Company's revenue is derived exclusively from contracts with customers. Revenue associated with the sale of crude oil
and gas is measured based on the consideration specified in contracts with customers. Revenue from contracts with
customers is recognized when the Company satisfies a performance obligation by transferring a good or service to a
customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of
control of oil and gas usually coincides with title passing to the customer and the customer taking physical possession.
Company mainly satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to
performance obligations satisfied over time are not significant.
k.
l.
Revenues from the sale of crude oil and gas are recognized by reference to actual volumes delivered at contracted delivery
points and prices. Prices are determined by reference to quoted market prices in active markets, adjusted according to
specific terms and conditions applicable per the sales contracts. Revenues are recognized prior to the deduction of
transportation costs. Revenues are measured at the fair value of the consideration received.
Foreign Currency Translation
Transactions in foreign currencies are initially translated into the functional currency using the exchange rate on the
transaction date. Foreign exchange gains and losses resulting from the settlement of such transactions and from the
translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are
recognized in the consolidated statements of earnings and comprehensive income. Each subsidiary in the group is
measured using the currency of the primary economic environment in which the entity operates, which is its functional
currency.
Earnings per Share
The Company presents basic and diluted earnings per share (“EPS”) data for its common shares (the “Common Shares”).
Basic EPS is calculated by dividing the net profit or loss attributable to common shareholders of the Company by the
weighted average number of Common Shares outstanding during the period. Diluted EPS is determined by dividing the net
profit or loss attributable to common shareholders by the weighted average number of Common Shares outstanding during
the year, plus the weighted average number of Common Shares that would be issued on conversion of all dilutive potential
Common Shares into Common Shares. Those potential Common Shares comprise share options granted.
m. Fair Value Measurements
Financial instruments recorded at fair value in the consolidated balance sheet (or for which fair value is disclosed in the
notes to the Financial Statements) are categorized based on the fair value hierarchy of inputs. The three levels in the
hierarchy are described below:
Level I
Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are
those in which transactions occur in sufficient frequency and volume to provide continuous pricing information.
Level II
Pricing inputs are other than quoted prices in active markets included in Level I. Prices in Level II are either directly or
indirectly observable as of the reporting date. Level II valuations are based on inputs, including quoted forward for
commodities, time value, credit risk and volatility factors, which can be substantially observed or corroborated in the
marketplace.
Level III
Valuations are made using inputs for the asset or liability that are not based on observable market data. The Company uses
Level III inputs for fair value measurements in inputs such as commodity prices in impairment assessments.
56 3. NEW ACCOUNTING POLICIES, STANDARDS AND INTERPRETATIONS
NEW ACCOUNTING POLICIES
Share Capital
Shareholders’ capital represents the recognized amount for common shares issued (net of equity issuance costs) less the weighted-
average carrying value of shares repurchased. The price paid to repurchase common shares is compared to the carrying value of the
shares and the difference is recorded against retained earnings.
NEW ACCOUNTING STANDARDS ISSUED
New accounting standards and interpretations were issued and are mandatory for accounting periods after January 1, 2023. Certain
of the new accounting standards and interpretations, which did not have a significant impact on the Company’s Financial Statements
upon adoption, are as follows:
•
•
•
IAS 1 – Disclosure of Accounting Policies – Effective January 1, 2023, the amendments require an entity to disclose its
material accounting policies, instead of its significant accounting policies, while providing guidance on how entities can
identify material accounting policy information and examples of when accounting policy information is likely to be material.
IAS 1 – Presentation of Financial Statements – Effective January 1, 2023, the amendments clarify the requirements for the
presentation of liabilities as current or non-current in the balance sheet.
IAS 8 – Definition of Accounting Estimates – Effective January 1, 2023, the amendments distinguish how an entity should
present and disclose different types of accounting changes in its financial statements and provides updated definitions to
changes in accounting estimates to assist issuers in assessing between a change in accounting policy and a change in
accounting estimate.
NEW ACCOUNTING STANDARDS ISSUED BUT NOT EFFECTIVE
New accounting standards and interpretations were issued and are mandatory for accounting periods after January 1, 2024. The
new accounting standards and interpretations, which are not expected to have a significant impact on the Company’s Financial
Statements adoption, are as follows:
Classification of Liabilities as Current or Non-current – Amendments to IAS 1
In January 2020 and October 2022, the IASB issued amendments to paragraphs 69 to 76 of IAS 1 to specify the requirements
for classifying liabilities as current or non-current.
An Additional requirement has been introduced to require disclosure when a liability arising from a loan agreement is classified as
non-current and the entity’s right to defer settlement is contingent on compliance with future covenants within twelve months.
The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must be applied
retrospectively.
Lease Liability in a Sale and Leaseback - Amendments to IFRS 16
In September 2022, the IASB issued amendments to, Leases (“IFRS 16”) to specify the requirements that a seller-lessee uses
in measuring the lease liability arising in a sale and leaseback transaction, to ensure the seller-lessee does not recognize any
amount of the gain or loss that relates to the right of use it retains.
The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must applied
retrospectively to sale and leaseback transactions entered into after the date of initial application of IFRS 16.
Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7
In May 2023, the IASB issued amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures
to clarify the characteristics of supplier finance arrangements and require additional disclosure of such arrangements. The
disclosure requirements in the amendments are intended to assist users of financial statements in understanding the effects of
57 supplier finance arrangements on an entity’s liabilities, cash flows and exposure to liquidity risk.
The amendments will be effective for annual reporting periods beginning on or after January 1, 2024.
4. CASH AND RESTRICTED CASH
The following table sets out cash and restricted cash balances held in different currencies:
Balances held in:
US dollars
Peruvian soles
English pounds
Canadian dollars
Total
Represented as:
Cash
Restricted cash current
Restricted cash non-current
December 31
2023
December 31
2022
100,996
3,296
3,270
3,737
111,299
90,568
14,731
6,000
117,378
113
2,457
21
119,969
104,340
9,629
6,000
Current restricted cash of $14.7 million, is primarily related to the social fund, letters of credit bank guarantees, and hedge deposits.
The $6 million of non-current restricted cash is related to permitted hedging programs (see Note 9).
The social fund was formally recognized in 2022 where 2.5% of the value of the monthly oil produced in Bretana’s Block 95, less
transportation, is set aside for the benefit of local communities. In March 2023, Peru’s President signed the Supreme Decree
authorizing Perupetro S.A. (“Perupetro”) to execute the amendment incorporating the 2.5% social trust fund into the Block 95
license contract, effective and retroactive to January 1, 2022. For the years ended December 31, 2023 and 2022, the Company
accrued $7.3 million and $6.3 million, respectively, in social fund expense (see Note 17) of which $0 million and $1.2 million was paid
to the community, respectively.
5. VAT RECEIVABLES
VAT receivable - current
VAT receivable - non-current
Total VAT receivables
December 31
2023
December 31
2022
9,709
2,226
11,935
10,555
1,934
12,489
Valued Added Tax (“VAT”) in Peru is levied on the purchase of goods and services and is recoverable on sales of goods and services.
The Company recovered $26.9 million during the year ended December 31, 2023 and expects to recover $9.7 million in the short-
term.
6. TRADE AND OTHER RECEIVABLES SHORT AND LONG TERM
Trade receivables
Other receivables
Total trade and other receivables
Represented as:
Current receivables
Non-current receivables
December 31
2023
December 31
2022
76,163
2,809
78,972
58,602
20,370
105,647
1,628
107,275
107,275
—
58
At December 31, 2023, trade receivables represent revenue related to the sale of oil. The balance is comprised of $26 million due
from Petroperu ($6 million is short term and $20 million is long term) and $50 million from export sales through Brazil (all of which is
due short term). No credit losses on the Company’s trade receivables have been incurred and all short-term receivables are current.
7.
INVENTORY
Oil inventory
Materials, parts and supplies
Total inventory
December 31
2023
December 31
2022
813
11,979
12,792
2,389
11,384
13,773
Oil inventory consists of the Company's oil barrels, which are valued at the lower of cost or net realizable value. Costs include
operating expenses, royalties, transportation, and depletion associated with production. Costs capitalized as inventory will be
expensed when the inventory is sold. At December 31, 2023, the oil inventory balance of $0.8 million consists of 35,320 barrels of oil
valued at $23.01/bbl (December 31, 2022: $2.4 million, based on 106,621 barrels at $22.40/bbl). Materials, parts and supplies,
including diluent, are expected to be consumed in the short-term.
8. PREPAID EXPENSES
Advances to contractors
Prepaid expenses and other
Total advances and prepaid expenses
December 31
2023
December 31
2022
507
6,955
7,462
—
5,475
5,475
At December 31, 2023, prepaid expenses were comprised of $5.7 million in Peruvian income tax prepaid and $1.3 million in
insurance, prepaid services for consultants, and other related services.
9. RISK MANAGEMENT
Cash and restricted cash
Trade and other receivables
Short-term derivative assets
Trade receivable long-term
Long-term derivative assets
Short and long-term debt
Trade and other payables
Long-term derivative liabilities
December 31, 2023
December 31, 2022
Carrying Value
Fair Value
Carrying Value
Fair Value
111,299
58,602
9,318
20,370
4,926
—
79,328
6,832
111,299
58,602
9,318
20,370
4,926
—
79,328
6,832
119,969
107,275
12,086
—
11,463
81,445
67,195
3,179
119,969
107,275
12,086
—
11,463
82,000
67,195
3,179
The table above details the Company’s carrying value and fair value of financial instruments including cash and restricted cash, trade
and other receivables, derivatives, short and long-term debt, and trade and other payables, all of which are classified as financial
assets and liabilities and reported at amortized cost or fair value. The Company is exposed to various financial risks arising from
normal-course business exposure. These risks include market risks relating to foreign exchange rate fluctuations and commodity
price risk as well as liquidity.
COMMODITY PRICE DERIVATIVES
The derivative asset is classified as a Level 2 fair value measurement. The Petroperu Saramuro agreement, signed with Petroperu
during 2021, includes a clause for the purchase price adjustment. The initial sales price is based on the arithmetic average of the ICE
Brent Crude 8-month forward price. The realized price is based on the tender price of the oil that is sold at the Bayovar terminal.
59
The purchase price adjustment is the realized price less the initial sales price. If the purchase price adjustment is negative, the
Company will compensate Petroperu for the amount, multiplied by the volume sold or arranged by Petroperu. If the purchase price
adjustment is positive, the Company will be compensated by Petroperu.
The fair value of the embedded derivative, considering an average future Brent price marker differential, was recorded as a gain
(loss) on commodity price derivatives at December 31, 2023 and 2022.
Net derivative asset at beginning of period
Cash settlements
Cash to be received
Realized gain (loss)
Unrealized gain (loss)
Net derivative asset at end of period
December 31
2023
December 31
2022
20,370
(478)
—
(2,256)
(10,224)
7,412
36,724
3,585
(28,171)
17,488
(9,256)
20,370
Sales delivery /
Executed month
Expected
settlement month
Volume
mbbls
Price range
$/bbl
Hedged range
$/bbl
Net Derivative
Asset
Peru Embedded Derivatives (a)
Jan-21 to Feb-22
Feb-24 to Jun-26
2,422
a) Embedded derivative related to original Petroperu sales agreement.
55.32 to 85.26
70.85 to 78.39
Net Derivative Asset
7,412
7,412
During the year ended December 31, 2023, no oil was sold by Petroperu, and 2.4 million barrels remain in the pipeline or storage
tanks, awaiting final sale by Petroperu. A 1% change to the hedged range price would result in a $1.6 million change to the net
derivative asset.
FOREIGN EXCHANGE RATE RISK
The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working
capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item.
Excluding the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss,
based on foreign currency balances held at December 31, 2023.
LIQUIDITY RISK
Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The
Company’s liquidity risk is impacted by current and future commodity prices. If required, the Company will also consider additional
short-term financing or issuing equity in order to meet its future liabilities. Declines in future commodity prices could affect the
Company’s ability to fund ongoing operations. The current economic environment may have significant adverse impacts on the
Company including, but not exclusively:
• material declines in revenue and cash flows as a result of the decline in commodity prices;
•
•
•
•
•
declines in revenue and operating activities due to reduced capital programs and constrained oil production;
inability to access financing sources;
increased risk of non-performance by the Company’s customers and suppliers;
interruptions in operations as the Company adjusts personnel to the dynamic environment; and,
delivery of oil at Bayovar port and sale swap price risk.
Estimates and judgements made by management in the preparation of the financial statements are subject to a certain degree of
measurement uncertainty during this volatile period.
60
CREDIT RISK
Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial
loss to the Company. The Company’s VAT is primarily for sales tax credits on exploration and drilling expenses incurred in prior
years. These credits will be applied to future oil development activities or recovered as per the sales tax recovery legislation
currently in effect. The Company’s trade receivable balance relates to oil sales and purchase price adjustments to two customers,
being Petroperu, a state-owned company and Novum, an oil trading company. The Company has a long-term sales agreement for oil
exports through Brazil, whereby sales are FOB Bretana. Sales through the ONP pipeline are due and payable 240 days after the final
delivery of the oil to the Bayovar terminal. During 2023, 87% of oil sales were to Novum (Brazil export route) and 13% were to
Petroperu (Iquitos refinery). The Company has not experienced any material credit losses in the collection of its trade receivables.
The Company periodically assesses the recoverability of all trade receivables through discussions with its customers, review of credit
rating agency reports or review of other third-party information.
Impairment to a financial asset is only recorded when there is objective evidence of impairment and the loss event has an impact on
future cash flow and can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators
that the debtor may enter bankruptcy. Management believes that there is no risk on the recoverability and or applicability of the
sales tax credits. Therefore, no impairment to the carrying value of these assets has been estimated. The Company has deposited
its cash, cash equivalents and restricted cash with reputable financial institutions, with which management believes the risk of loss
to be remote. The maximum credit exposure associated with financial assets is their carrying value. At December 31, 2023, the
cash, cash equivalents and restricted cash were held with six different institutions from three countries, mitigating the credit risk of a
collapse of one particular bank.
61 10.EXPLORATION AND EVALUATION ASSETS
The following table sets out a continuity of Exploration and Evaluation Assets:
Balance at January 1, 2022
Additions
Balance at December 31, 2022
Additions
Balance at December 31, 2023
6,051
1,291
7,342
1,631
8,973
The Company determined there were no impairment indicators of the exploration and evaluation assets balance at December 31,
2023 and December 31, 2022.
11.PROPERTY, PLANT AND EQUIPMENT
Balance at January 1, 2022
Additions
Revisions to decommissioning obligations
Revisions to right of use asset
Depletion, depreciation and amortization
Balance at December 31, 2022
Additions
Additions and revisions to decommissioning obligations
Revisions to right of use asset
Depletion, depreciation and amortization
Balance at December 31, 2023
Petroleum
Interests
Right of Use
Asset
(Power Plant)
Other Assets
Total
231,009
91,348
(4,688)
—
(29,390)
288,279
105,151
7,760
—
(36,964)
364,226
20,188
5,894
—
(4,158)
(1,212)
20,712
—
—
12,389
(1,328)
31,773
633
2,933
—
—
(647)
2,919
1,671
—
—
(1,025)
3,565
251,830
100,175
(4,688)
(4,158)
(31,249)
311,910
106,822
7,760
12,389
(39,317)
399,564
At December 31, 2023, $0.3 million of the depreciation, depletion and amortization expense was recorded as inventory
(December 31, 2022: $0.7 million).
The Company determined there were no impairment indicators of the property, plant and equipment balance at December 31, 2023
and December 31, 2022.
12.SHORT AND LONG-TERM DEBT
On February 16, 2023, in accordance with the terms of the bond agreement the company paid $25 million and in March 24, 2023,
the Company elected to repay the remaining $55 million bond principal, plus interest and fees of $2.9 million. The original bond
maturity was February 2024.
On March 2, 2023, the Company finalized a $20 million unsecured revolving loan with an interest rate of 8.97% with Banco de
Credito del Peru. The term of the loan is for two months with renewal options. No debt covenants were set forth by the lender in
the loan agreement. The funds were used to fund short-term working capital needs. On August 3, 2023, the Company repaid $20
million to Banco de Credito del Peru for its revolving loan plus $0.7 million in accrued interest. At December 31, 2023, the $20
million revolving loan remains fully available.
62
13.TRADE AND OTHER PAYABLES
Trade payables
Accrued payables and other obligations
Total trade and other payables
December 31
2023
December 31
2022
25,037
54,291
79,328
32,177
35,018
67,195
At December 31, 2023 and December 31, 2022, trade payables and other payables are primarily related to the drilling and
completion of wells and construction of production processing facilities. The other obligations are mainly related to the 2.5% social
fund for the benefit of local communities, which totaled to $12.2 million at December 31, 2023 ($5.1 million at December 31, 2022).
14.DECOMMISSIONING LIABILITIES
Balance at January 1, 2022
Additions
Revisions to decommissioning liabilities
Expenditures
Accretion
Balance at December 31, 2022
Additions
Revisions to decommissioning liabilities
Accretion
Balance at December 31, 2023
22,101
1,916
(6,604)
(4,917)
897
13,393
5,390
2,370
994
22,147
The undiscounted uninflated value of estimated decommissioning liabilities is $39.0 million ($30.2 million in 2022). The present
value of the obligations was calculated using an average risk-free rate of 5.3% (December 31, 2022: 6.6%) to reflect the market
assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow
estimates. The inflation rate used in determining the cash flow estimate was 2.0%.
15.CURRENT AND NON-CURRENT LEASE LIABILITIES
In prior years, PetroTal commenced a seven-year service lease arrangement with a supplier that provides turnkey power generation
equipment services. In Q4 2023, the Company signed an addendum to extend the lease term to September 30, 2031 and lease
additional equipment in 2024, which resulted in a $12.4 million present value increase to lease assets and liabilities on the balance
sheet. The Company has the option to buy the equipment on April 30, 2031 for $3.0 million. The incremental borrowing rate used
to measure the lease liabilities was 8.5% for the dollar denominated lease.
The lease liabilities also includes two office leases, one in Houston, Texas and one in Lima, Peru. The Houston lease is for a term of
6.2 years with an incremental borrowing rate of 6.5% and the Lima lease is for 5 years with an incremental borrowing rate of 8.5%.
Lease liabilities at January 1, 2022
Additions
Revisions
Payments
Interest on leases
Lease liabilities at December 31, 2022
Revisions
Payments
Interest on leases
Lease liabilities at December 31, 2023
17,661
7,263
(2,332)
(3,974)
1,024
19,642
12,389
(4,465)
1,304
28,870
63
Represented as:
Current liability
Non-current liability
At December 31, 2023, total lease liabilities have the following minimum undiscounted annual payments:
Year
2024
2025
Thereafter
Total
16.SHARE CAPITAL
2,205
26,665
5,014
5,043
26,272
36,329
Authorized share capital consists of an unlimited number of common shares without nominal or par value. The holders of common
shares are entitled to one vote per share and are entitled to receive dividends as recommended by the Board of Directors.
Balance at January 1, 2022
Vesting of performance share units
Warrants exercised
Balance at December 31, 2022
Vesting of performance share units
Repurchase of shares
Warrants exercised
Balance at December 31, 2023
DIVIDENDS
Thousands of
Common
Shares
Share
Capital
828,197
8,050
25,962
862,209
1,557
(11,327)
59,875
912,314
126,696
—
3,500
130,196
—
(1,839)
12,315
140,672
During the years ended December 31, 2023 and 2022, the Company paid dividends to shareholders in the amount of $55.6 million
and $0 million, respectively. The Company declared dividends per share in the amount of $0.015, $0.025 and $0.02 per quarter
beginning in Q2, respectively. The Company’s dividend policy is to pay dividends based on current liquidity exceeding $60 million.
NORMAL COURSE ISSUER BID
On May 16, 2023, the Company announced that Toronto Stock Exchange approved the notice of intention to commence a normal
course issuer bid ("NCIB"). The NCIB allows the Company to purchase up to 44,230,205 common shares (representing approximately
5% of outstanding common shares at May 12, 2023) beginning May 18, 2023 and ending no later than May 17, 2024. Common
shares purchased under the NCIB will be cancelled.
During the years ended December 31, 2023 and 2022, the Company purchased 11,326,806 and 0 common shares under the NCIB
for total consideration of $6.5 million and $0 million, respectively. The surplus between the total consideration and the carrying
value of the shares repurchased was recorded against retained earnings.
64
PERFORMANCE AND INVESTORS’ WARRANTS
The investor warrants were granted in connection with the brokered private placement offering on June 18, 2020. Investors
received one common share and one half of one warrant allowing the subscriber to purchase additional shares until June 18, 2023,
at 16 pence/share upon presentation of a full warrant. The warrants were fully exercised on June 18, 2023 and $12.3 million in
proceeds was received. The following table sets out a continuity of the warrants:
Balance at January 1, 2022
Warrants exercised
Balance at December 31, 2022
Warrants exercised
Balance at December 31, 2023
SHARE-BASED COMPENSATION
Performance
Warrants
Investor
Warrants
22,546,350
(22,546,350)
—
—
—
66,749,005
(6,873,318)
59,875,687
(59,875,687)
—
The Company has granted performance share units (“PSUs”) to employees and deferred share units (“DSUs”) to directors. The grant
date fair value of PSUs granted to employees is recognized as share-based compensation expense with a corresponding increase in
contributed surplus over the vesting period. The Company granted PSUs to employees in accordance with the provisions of the
Company’s PSU plan. The PSUs either vest after three years or equally over three years and each PSU will entitle the holder to
acquire between zero and two common shares of the Company, subject to the achievement of performance conditions relating to
the Company’s total shareholder return, net asset value and certain production, environmental, safety and operational milestones.
The fair value of the PSUs is determined through a combination of Black-Scholes and probability weighted models. The following
table details the terms of the PSUs outstanding at December 31, 2023:
Vest date 3 years from grant date, exchangeable for up to 2 shares
Vests equally over 3 years from grant date, exchangeable for up to 2 shares
Vests equally over 3 years from grant date, exchangeable for up to 1-1.5 shares
Total units
The following assumptions were used for the Black-Scholes valuation of the PSUs granted:
Risk-free interest rate
Expected Life
Annualized volatility
2023 Plan
Share Units
2022 Plan
Share Units
4,283,897
520,500
1,987,367
6,791,764
3,169,560
457,728
1,422,331
5,049,619
2023 Plan
2022 Plan
3.8 %
1-3 years
50 %
2.0 %
1-3 years
50 %
For the year ended December 31, 2023, the Company recognized $4.4 million of share-based compensation expense in general and
administrative expense, capital expenditures and operating expense (December 31, 2022: $4.1 million).
The Company issued DSUs to directors of the Company, pursuant to the Company’s DSU plan and has 3,792,494 DSUs outstanding at
December 31, 2023. The DSUs are fully vested and are redeemable upon a holder ceasing to be a director of PetroTal. No common
shares will be issued under the DSU plan, as they are settled in cash at the prevailing market price and valued at the closing share
price on the reporting date. For the year ended December 31, 2023, the Company recognized $0.8 million of DSU expense in general
and administrative expense and contributed surplus (December 31, 2022: $1.0 million).
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The following table details the PSU and DSU activity:
Performance
Share Units
Balance at January 1, 2022
Additions
Issued
Forfeited
Exercised/settled
Balance at December 31, 2022
Additions
Issued
Forfeited
Exercised/settled
Balance at December 31, 2023
Deferred Share
Units
2,962,539
1,073,483
—
—
(1,384,268)
2,651,754
1,292,000
—
—
(151,260)
3,792,494
23,583,322
5,165,917
(7,594,067)
(1,428,004)
—
19,727,168
9,038,663
(7,707,440)
(256,471)
—
20,801,920
17.REVENUE NET OF ROYALTIES AND SOCIAL FUND
The Company’s oil revenue is determined pursuant to the terms of various sales agreements. The transaction price for crude is
based on the commodity price in the production month, adjusted for quality, allowable deductions and other factors. Commodity
prices are based on market indices.
Oil revenue
Royalty
Social fund (see Note 4)
Oil Revenue Net of Royalties and Social Fund
18.GENERAL AND ADMINISTRATIVE EXPENSES
Salaries and benefits
Legal, audit and consulting fees
Community support
Office rent and administrative
Share-based compensation plans
Costs directly attributable to PP&E and operating expenses
Total
Year Ended
December 31
2023
December 31
2022
316,911
(23,389)
(7,259)
286,263
359,106
(25,713)
(6,278)
327,115
Year Ended
December 31
2023
December 31
2022
14,065
9,459
3,100
4,350
4,364
(7,289)
28,049
10,994
4,830
2,372
2,870
4,089
(5,264)
19,891
The Company’s general and administrative expenses were $8.2 million higher in 2023 compared to 2022, due to an increase in
salaries and headcount, higher professional fees and Environmental, Social, and Governance (“ESG”) consulting expenses and an
increase in share-based compensation, partially offset by costs directly attributable to PP&E and operating expenses.
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19.FINANCE EXPENSE
Bond interest and fees amortization and other interest
Factoring costs
Lease interest
Accretion of decommissioning obligations
Interest income
Total
Year Ended
December 31
2023
December 31
2022
16,183
403
1,304
994
(3,543)
15,341
17,085
1,417
2,884
897
(2,114)
20,169
The Company’s finance expenses were $4.8 million lower in 2023 compared to 2022.
20.DIRECT TRANSPORTATION EXPENSE
Direct transportation is comprised of diluent, barging, diesel and storage expenses. Diluent costs are required for sales to the Iquitos
refinery.
Diluent
Barging
Diesel
Dry season freight and storage
Total Direct Transportation
21.RELATED PARTY TRANSACTIONS
Year Ended
December 31
2023
December 31
2022
6,857
3,475
516
4,115
14,963
9,440
6,431
1,083
3,668
20,622
The Company had no related party transactions or off-balance sheet arrangements. The Company’s key management includes the
Directors and Officers.
Salaries, incentives and short term benefits
Director's fees
Share-based compensation
Total
Year Ended
December 31
2023
December 31
2022
1,846
1,014
2,430
5,290
1,785
1,050
1,615
4,450
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22.CAPITAL STRUCTURE
The Company’s objective when managing capital is to ensure it has sufficient funds to maintain ongoing operations, to pursue the
acquisition of oil and gas properties, and to maintain a flexible capital structure that optimizes the cost of capital at an acceptable
risk. The Company manages its capital structure, which may include equity and debt, and adjusts it according to the funds available
to support the exploration and development of its interests in its existing oil and gas properties, and to pursue other opportunities
as they arise.
The Company defines its capital as follows:
Equity
Working capital (current assets less current liabilities)
Total
23.TAXES
December 31
2023
December 31
2022
463,942
(121,649)
342,293
399,331
(139,771)
259,560
The Company’s effective tax rate is impacted each quarter by the relative pre-tax income earned by the Company’s operations in
Canada, U.S., and Peru. The Company is subject to statutory tax rates of 23% in Canada, 21% in the U.S. and 32% in Peru (activities
of the Company in Peru are subject to a 30% statutory tax rate plus 2% in accordance with Law 27343). The Company files federal
income tax returns and local income tax returns in the various jurisdictions.
The tax at the effective rate differed from the tax at the statutory rate as follows:
Earnings before deferred income taxes
Canadian corporate tax rate
Expected income tax expense
Increase (decrease) in taxes resulting from:
Non-deductible expenses and other
Tax differential on foreign jurisdictions
Change in valuation allowance
Provision for income taxes
The deferred income tax balances are as follows:
Deferred income tax asset:
Property, plant, and equipment
Trade and other payables
Net operating loss carryover
Other tax pools
Deferred income tax asset
Deferred income tax liability:
Property, plant, and equipment
Derivative assets and liabilities
Preoperative expenses
Net operating loss carryover
Other tax pools
Deferred income tax liability
December 31, 2023 December 31, 2022
205,917
143,507
23.00 %
33,007
1,408
10,212
(11,625)
33,002
23.00 %
47,361
2,047
19,742
(51,760)
17,390
December 31, 2023 December 31, 2022
7
—
4,119
8,919
13,045
(58,554)
(2,372)
2,549
2,156
1,112
(55,109)
(11)
254
855
—
1,098
(46,886)
(5,643)
3,186
29,985
1,972
(17,386)
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The Company recognized the net tax amount related to Net Operating Losses (“NOLs”) and deferred tax liabilities in Peru, Canada
and the US. As of December 31, 2023, the Company has $7 million in available tax losses in Peru (mainly related to Block 95), $21
million tax losses in Canada and $2 million in the US (December 31, 2022: $112 million, $69 million, and $1.7 million, respectively).
The Peruvian non-capital losses are expected to be used in 2024. The Canadian non-capital losses can be carried forward for twenty
years and there is generally no carryback period. The carryover period starts with the taxable year following the loss and continues
indefinitely. The US non-capital losses can be carried forward indefinitely.
The aggregate amount of temporary differences associated with investments in subsidiaries for which deferred tax liabilities have
not been recognized as of December 31, 2023 is approximately $29 million (December 31, 2022: $50 million).
24.COMMITMENTS
At December 31, 2023, the Company holds the following letters of credit guaranteeing its commitments in exploration block 107:
Block
107
107
Beneficiary
Perupetro S.A.
Perupetro S.A.
Amount
$1,500
$1,500
$3,000
25. SUBSEQUENT EVENTS
Commitment
1st exploration well, minimum work 5th exploratory period
2nd exploration well, minimum work 5th exploratory period
Expiration
May 2026
May 2026
On February 14, 2024, the Company declared a cash dividend of $0.02 per common share with a record date of February 29, 2024.
The dividend was paid on March 15, 2024.
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