2020 YEAR END REPORTING PACKAGE
April 22, 2021
TSXV: TAL / AIM: PTAL / OTC: PTALF
PetroTal Announces 2020 Year-End Financial and Operating Results
PetroTal emerges stronger after a collapse in world oil prices and the COVID-19 pandemic
Calgary, AB and Houston, TX – April 22, 2021—PetroTal Corp. ("PetroTal" or the "Company") (TSXV:
TAL and AIM: PTAL) is pleased to announce its financial and operating results for the year and the three
months ("Q4") ended December 31, 2020.
Selected financial, reserves and operational information is outlined below and should be read in
conjunction with the Company's audited consolidated financial statements ("Financial Statements"),
management's discussion and analysis ("MD&A") and annual information form ("AIF") for the year ended
December 31, 2020, which are available on SEDAR at www.sedar.com and on the Company's website at
www.PetroTal‐Corp.com. Reserves numbers presented herein were derived from an independent
reserves report (the "NSAI Report") prepared by Netherland, Sewell & Associates, Inc. ("NSAI") effective
December 31, 2020. All amounts herein are in United States dollars ("USD") unless otherwise stated.
2020 Highlights
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Drilled and completed the 6H well on schedule and within budget achieving a 10-day flush
production average of approximately 4,500 bopd;
Successfully and seamlessly reopened the Bretana field in late September 2020 after COVID 19,
social, and Northern Oil Pipeline (“ONP”) maintenance related issues. There was no additional
downtime or related safety issues once startup commenced, with field production rising back to
approximately 11,000 bopd (pre shut down levels) ten days later;
Completed commissioning of the enhanced central production facilities ("CPF-1"), bringing overall
oil production capacity to between 16,000 and 18,000 bopd;
Optimized the 2020 capital program to maximize liquidity and operational performance due to
the COVID 19 pandemic, ongoing government social related issues, and shut down of the ONP;
Signed an extended oil sales contract with Petroperu outlining improved terms, including reduced
pipelined tariffs and fees during periods of low oil prices;
Raised approximately $18 million in equity to provide 2020 liquidity support;
Delivered a material lift in 2020 year ended 3P oil reserves with a lower 2P operating cost profile
based on positive technical revisions, historical well performance, and field cost reduction
initiatives;
Concluded historic collaboration between the local Bretana residents and communities, aligning
their goals and objectives with the Company's; and,
Executed a route to market diversification strategy through Brazil with comparable margins to the
ONP route.
Events Subsequent to December 31, 2020
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On January 19, 2021, the Company executed a final agreement with Petroperu, restructuring the
contingent derivative liability over three years. The amount of the contingent liability represented
$16.6 million (based on the November 30, 2020 valuation) and was subsequently paid out (along
2
with the $3 million Peruvian-government COVID emergency response loan), from the $100 million
bond offering referred to below. Since that time, the Company through Petroperu, has recently
placed hedges, solidifying approximately $30 million of true-up revenue on the 1.8 million barrels
in the ONP that originally caused the contingent liability;
On February 2, 2021, the Company announced completion of a 3-year $100 million senior secured
bond with an annual 12% coupon, issued at a 5% discount. The bonds issued by PetroTal are the
Company’s only interest bearing debt and the proceeds are for payout of the Petroperu derivative
liability with Petroperu and Reactiva loan, totaling $20 million, to support the Company’s crude oil
price hedging strategy ($15 million), to finance potential acquisitions ($20 million), with the
remainder for continued development of the Bretana oil field;
On February 18, 2021, the Company announced its 2021 capital development program of $100
million, to be funded from the bond proceeds and internally generated funds from operations,
along with existing cash resources;
The Company has hedged approximately 32% of expected April to December 2021 oil production.
Additionally, Petroperu has now hedged 100% of oil sales through the ONP. This robust hedging
program will ensure funding stability to support the 2021 capital development program, in the
event that Brent oil price drops materially; and,
Pursuant to the Company’s oil market diversification strategy, in Q1 2021 the Company completed
a second shipment of 225,000 barrels of oil through Brazil for export into the Atlantic region. The
oil sale was FOB Bretana and generated revenue of $8.8 million.
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Three months ended December 31, 2020 (“Q4”) Highlights
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PetroTal produced 6,410 bopd and sales volumes averaged 5,471 bopd, compared to sales of
2,327 bopd in Q3 2020;
Indigenous communities and government bodies reached agreements that will see increased
funding for the local communities, thereby allowing for the ONP to resume full operations;
The Company's stringent COVID-19 protocols continue to ensure that the camp remains safe;
The Company sold 397,000 barrels of oil to the Iquitos refinery and the ONP (at pump station #1
at Saramuro), thereby generating revenues of $12.4 million, net of transportation and fees;
PetroTal reached agreement with an international oil trader for an initial shipment to export
106,000 barrels through Brazil into the Atlantic region, via the Amazon river. The December 2020
shipment was sold FOB Bretana, priced at the forward month Brent ICE price, and paid within two
weeks of loading at Bretana. Importantly, there are no subsequent oil price adjustments;
Operating income of $5.9 million ($11.90/bbl) compared to $2.3 million ($10.86/bbl) in Q3 2020;
Funds flow provided by operations of $1.3 million compared to a deficiency of $0.5 million in Q3
2020; and,
Capital expenditures were $6.3 million compared to $3.4 million in Q3 2020.
2020 Operational Highlights
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Six producing wells and one water disposal well were operating during Q4 2020, inclusive of the
initial water disposal well that was converted to an oil producer;
Approximately $42 million incurred in capital expenditures to drill one oil well, build production
facilities and standby-related charges, compared to $89 million in 2019;
3
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PetroTal produced a total of 2.1 million barrels of oil in 2020, representing average oil production
of 5,675 bopd, an increase of 37% from the average production of 4,131 bopd realized in 2019;
Annual independent reserve assessment, as prepared by NSAI shows increases in all reserve
categories:
o Proved ("1P") reserves of 22.3 million barrels ("mmbbl"), an increase of 4% from the 21.5
mmbbl recorded at the end of 2019;
o Proved plus Probable ("2P") reserves of 51.0 mmbbl, an increase of 7% from the 47.7
mmbbl recorded at the end of 2019; and,
o Proved plus Probable and Possible ("3P") reserves of 106.1 mmbbl, an increase of 25%
from the 84.8 mmbbl recorded at the end of 2019;
Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories were unchanged from
2019 at 235, 364 and 579 mmbbls, respectively; and,
Net Present Value (after tax, discounted at 10%) ("NPV-10") represents $271 million ($12.15/bbl)
for 1P reserves, $621 million ($12.17/bbl) for 2P reserves and $1.2 billion ($11.03/bbl) for 3P
reserves based on the NSAI year end 2020 price deck.
2020 Financial Highlights
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Generated revenue in 2020 of $76.6 million ($36.71/bbl) compared to $82.8 million ($56.24/bbl)
in 2019;
Royalties to the Peruvian government were $2.9 million compared to $3.4 million for 2019;
Generated funds from operations of $16.6 million compared to $30.3 million in 2019, as a result
of the significant decrease in oil prices;
Operating and transportation costs, were $44.8 million ($21.49/bbl) compared to $37.7 million
($25.59/bbl) for 2019, an improvement of 21%, on a per barrel basis;
Net operating income (netback) was $28.9 million ($13.84/bbl) compared to $41.7 million
($28.34/bbl) in 2019;
Cash flow generated was $13.4 million compared to $51.1 million in 2019. Cash flow represents
netback inclusive of G&A costs, realized gain (losses) on commodity contracts and all other cash
transactions; and,
At December 31, 2020, the Company held cash of $9.6 million, compared to $21.1 million at the
end of 2019.
4
Selected Financial and Operating Highlights
(in thousands USD)
Financial
Crude oil revenues
Royalties
Net operating income
Commodity price derivatives loss (1)
Net income (loss)
Basic and diluted net income (loss) (US$/share)
Capital expenditures
Operating
Average production (bopd) (2)(3)
Average sales (bopd)
Average Brent oil price (US$/barrel)
Average realized price (US$/barrel)
Netback (US$/barrel) (4)
Funds flow provided by (used in) operations (4)
Balance sheet
Cash
Working Capital
Total assets
Current liabilities
Equity
Note:
Year-Ended
Quarter-Ended
December
31, 2020
December
31, 2019
December
31, 2020
September
30, 2020
June
30, 2020
March
31, 2020
$76,593
(2,877)
28,881
4,788
(1,524)
(0.00)
42,297
$82,790
(3,396)
41,719
367
$20,152
0.03
88,763
5,675
5,700
41.74
36.71
13.84
16,668
4,131
4,033
64.31
56.24
28.34
29,413
$17,374
(700)
5,992
(12,969)
10,675
0.01
6,315
$7,611
(248)
2,324
(4,399)
3,224
0.01
3,354
$9,839
(123)
2,756
(18,264)
16,029
0.02
8,756
$41,768
(1,806)
17,809
40,420
(31,452)
(0.05)
23,872
6,410
5,471
44.24
34.52
11.90
1,293
2,444
2,327
43.34
35.56
10.86
(548)
4,185
4,729
29.19
22.87
6.40
862
9,686
10,313
50.14
44.51
18.98
15,061
9,628
(22,157)
215,138
58,608
137,163
21,101
(11,762)
194,181
59,286
121,057
9,628
(22,157)
215,138
58,608
137,163
9,788
(30,407)
205,531
62,355
126,253
20,379
(31,845)
216,899
76,932
122,789
7,373
(61,025)
194,274
89,914
90,029
(1) Contingent liability will be paid over a three-year period.
(2)
(3)
The field was shut in on May 7, 2020; for the 37 producing days in Q2 2020, production averaged 11,500 bopd.
The field was shut in from July 1 to July 14 and from August 9 to September 27; for the 28 producing days in Q3 2020 constrained production
averaged 8,000 bopd.
Funds flow provided by (used in) operations and netback do not have any standardized meaning prescribed by GAAP and therefore may not
be comparable with the calculation of similar measures for other entities. See “Non-GAAP Measures”.
(4)
Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented
"2020 was an extremely challenging year for the global economy and PetroTal emerged from the
downturn in a position of strength, a testament to our team's dedication and resolve. Although our 2020
results were impacted by many one-time events, the Company's announcements over the last six months
have been overwhelmingly positive and will underpin our growth through 2021 and beyond. I am excited
to continue to deliver on our 2021 capital program, which we anticipate will generate value for our equity,
debt, and ESG stakeholders.
I would like to thank PetroTal's shareholders, directors, employees, and contractors for their continued
support and I look forward to keeping all our stakeholders updated on the Company's progress throughout
the remainder of 2021."
5
ABOUT PETROTAL
PetroTal is a publicly traded, dual‐quoted (TSXV: TAL and AIM: PTAL) 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, and in early 2020 became the second largest crude oil producer in
Peru. Additionally, the Company has large exploration prospects and is engaged in finding a partner to
drill the Osheki prospect in Block 107. 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.
For further information, please see the Company's website at www.petrotal-corp.com, the Company's
filed documents at www.sedar.com, 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
T : 44 (0) 208 434 2643
Strand Hanson Limited (Nominated & Financial Adviser)
James Spinney / Ritchie Balmer
T: 44 (0) 207 409 3494
Stifel Nicolaus Europe Limited (Joint Broker)
Callum Stewart / Simon Mensley / Ashton Clanfield
Tel: +44 (0) 20 7710 7600
Auctus Advisors LLP (Joint Broker)
Jonathan Wright / Rupert Holdsworth Hunt / Harry Baker
T: +44 (0) 7711 627449
6
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: PetroTal's business strategy, objectives,
strength and focus; drilling, completions, workovers and other activities and the anticipated costs and results of such activities;
the ability of the Company to achieve drilling success consistent with management's expectations; anticipated future production
and revenue; drilling plans including the timing of drilling; oil production levels, including average production and exit production
in 2021; the 2021 capital program and budget, including drilling plans; 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, 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", "believe", "expect", "plan", "estimate", "potential", "will", "should",
"continue", "may", "objective" 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 labour, 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.
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. 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 and the MD&A
which are available on SEDAR at www.sedar.com. 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.
PRESENTATION OF OIL AND GAS INFORMATION: The reserves information herein sets forth PetroTal's reserves as at December
31, 2020, as presented in the independent reserves report prepared by NSAI, a qualified reserves evaluator, in accordance with
the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook")
and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-
101"). In addition to the summary information disclosed in this announcement and the press release dated February 24, 2021,
more detailed information is included in the AIF. All oil and gas disclosure contained in this press release complies with the
7
requirements of NI 51-101. The term original oil in place (OOIP) is equivalent to total petroleum initially in place ("TPIIP"). TPIIP,
as defined in the COGE Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It
includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to
production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered
undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is
no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion
of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion
of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered.
OIL AND GAS INFORMATION: References in this press release 10-day flush production 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 for PetroTal. The
Company cautions that the such results should be considered to be preliminary.
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.
NON-GAAP MEASURES: This press release contains financial terms that are not considered measures under generally accepted
accounting principles ("GAAP") such as operating netback and funds flow provided by operations, 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. The Company
considers operating netbacks to be a key measure as they demonstrate Company’s profitability relative to current commodity
prices. Netback is calculated by dividing net operating income by barrels sold in the corresponding period. Funds flow provided by
operations, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in
non-cash working capital. A reconciliation from cash provided by operating activities to funds flow provided by operations is
included in the MD&A.
FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information (collectively,
"FOFI") about PetroTal's prospective results of operations, production and production capacity, NPV-10, 2021 capital program
and budget, cash flow profile, liquidity 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 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.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture
Exchange) accepts responsibility for the adequacy or accuracy of this press release.
8
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the years ended December 31, 2020 and 2019
TSXV: TAL / AIM: PTAL / OTC: PTALF
TABLE OF CONTENTS
1. Corporate overview ……………………………………………………………………………………………………….………
2. Overview and selected information...……………………………………………………………...…………………….
3. 2020 Highlights……………………………………………………………………………………………………………………….
4. Outlook and growth strategy ..…………………...………………..……………………………………………………….
5. Selected financial information………………………………………………………………………………………………..
6. 2020 Reserve Report………………………. ……………………………………………………………………..…….……….
7. Significant judgements and estimates ……………………………………………………………………..…….………
8. Related party transactions and taxes ……………………………………….……..……………………………………..
9. Contractual obligations and commitments………………………………………………………………………………
10. Forward-looking statements and business risks ………………………………………………………………………
3
4
4
6
7
14
16
16
16
17
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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, 2020 and 2019, is dated April 21, 2021, and should be read in conjunction with the
Company’s audited Consolidated Financial Statements (the “Financial Statements”) for the twelve months ended December 31, 2020
and 2019 and the Company’s annual information form (the “AIF”) for the year ended December 31, 2020. The audited Financial
Statements were prepared by management in accordance with International Financial Reporting Standards (“IFRS”) 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 is a publicly-traded (TSXV: TAL and AIM: PTAL), international oil and gas company incorporated and domiciled in Canada.
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
significant exploration prospects and leads in Block 107.
During 2017, the Company completed a plan of arrangement (the “Reverse Takeover “RTO”) with Sterling Resources Ltd. pursuant to
which Sterling acquired all of the shares of PetroTal LLC Ltd. and, once amalgamated, continued as one operation under the name of
Sterling Resources Ltd. The name of the Company was changed in June 2019 to PetroTal Corp. The Company acquired 100% of the
subsidiaries from of Gran Tierra Energy Inc. (“GTE”) that held the rights to the exploration blocks in Peru. GTE had 100% working
interest in five license contracts: Blocks 95, 107, 123, 129 and 133 with GTE retaining a 20% back-in option in Block 107. In 2019
PetroTal relinquished its rights to Blocks 123, 129 and 133. After the reverse takeover transaction In connection with closing of the
Reverse Takeover and the acquisition of the GTE Peruvian assets on December 18, 2017, the Company appointed an experienced Board
of Directors, retained the prior PetroTal Management team and raised $34 million gross proceeds through the issuance of subscription
receipts, which were subsequently converted into common shares.
11
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 crude 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.
2. OVERVIEW AND SELECTED INFORMATION
The following table summarizes key financial and operating highlights associated with the Company’s performance for the periods
ended December 31, 2020, September 30, 2020, June 30, 2020, March 31, 2020 and December 31, 2019. Note that the commodity
price derivative is a non-cash item.
RESULTS AT A GLANCE
(1)
(2)
(3)
Contingent liability will be paid over a three-year period.
The field was shut in on May 7, 2020, for the 37 producing days in Q2 2020, production averaged 11,500 bopd.
The field was shut in from July 1 to July 14 and from August 9 to September 27, for the 28 producing days in Q3 2020 constrained production averaged 8,000 bopd.
3. 2020 HIGHLIGHTS
The Company reached several key operational and financial achievements as described below:
Three months ended December 31, 2020 (“Q4”) Highlights
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PetroTal recommenced oil field operations on September 28, 2020 and has remained producing continuously since then. The
wells were quickly brought into operation averaging 6,410 bopd in Q4 2020, intentionally constrained to manage oil delivery
availability to the Iquitos refinery and the Northern Oil Pipeline (“ONP”). The indigenous communities and government bodies
reached agreements that will see increased funding for the local communities, thereby allowing for the ONP to resume full
operations;
The Company’s stringent COVID-19 protocols continue to ensure that the camp remains safe;
The Company sold 397,000 barrels of oil to the Iquitos refinery and the ONP at pump station #1, thereby generating revenues
of $12.4 million, net of transportation and fees;
PetroTal reached agreement with an international oil trader for an initial shipment to export 106,000 barrels through Brazil
into the Atlantic region, via the Amazon river. The December 2020 shipment was sold FOB Bretana, priced at the forward
month Brent ICE price, and paid within two weeks of loading at Bretana. Importantly, there are no subsequent oil price
adjustments;
Operating income of $5.9 million ($11.90/bbl) compared to $2.3 million (10.86/bbl) in Q3 2020;
The Company recognized funds flow provided by operations of $1.3 million compared to a deficiency of 0.5 million in Q3 2020;
PetroTal produced 6,410 bopd and sales volumes averaged 5,471 bopd, compared to sales of 2,327 bopd in Q3 2020; and,
Capital expenditures were $6.3 million compared to $3.4 million in Q3 2020.
12
2020 Operational Highlights
-
-
-
-
-
-
Six producing wells and one water disposal well were operating during Q 4 2020, inclusive of the initial water disposal
well that was converted to an oil producer;
The Company invested $42.3 million in capital expenditures to drill one oil well, build production facilities and standby-related
charges, compared to a total capital investment of $88.8 million in 2019;
PetroTal produced a total of 2.1 million barrels of oil in 2020, representing average production of 5,675 bopd, an increase
of 37% from the average production of 4,131 bopd realized in 2019;
Annual independent reserve assessment, as prepared by NSAI (“Netherland Sewell and Associates, Inc.”) shows increases in
all reserve categories:
o
o
o
Proved ("1P") reserves of 22.3 million barrels ("mmbbl"), an increase of 4% from the 21.5 mmbbl recorded at the
end of 2019;
Proved plus Probable ("2P") reserves of 51.0 mmbbl, an increase of 7% from the 47.7 mmbbl recorded at the end
of 2019; and,
Proved plus Probable and Possible ("3P") reserves of 106.1 mmbbl, an increase of 25% from the 84.8 mmbbl
recorded at the end of 2019;
Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories were unchanged from 2019 at 235, 364 and 579
mmbbls, respectively; and,
Net Present Value (after tax, discounted at 10%) (“NPV-10”) represents $271 million ($12.15/bbl) for 1P reserves, $621 million
($12.17/bbl) for 2P reserves and $1.2 billion ($11.03/bbl) for 3P reserves.
2020 Financial Highlights
-
-
-
-
-
-
-
Generated revenue in 2020 of $76.6 million ($36.71/bbl) compared to $82.8 million ($56.24/bbl) in 2019;
Royalties to the Peruvian government were $2.9 million compared to $3.4 million for 2019;
Generated funds from operations of $16.6 million compared to $30.3 million in 2019, as a result of the significant decrease of
oil prices;
Operating and transportation costs, were $44.8 million ($21.49/bbl) compared to $37.7 million ($25.59/bbl) for 2019,
an improvement of 21%, on a per barrel basis;
Net operating income (netback) was $28.9 million ($13.84/bbl) compared to $41.7 million ($28.34/bbl) in 2019;
Cash flow generated was $13.4 million compared to $51.1 million in 2019. Cash flow represents netback inclusive of G&A
costs, realized gain (losses) on commodity contracts and all other cash transactions; and,
At December 31, 2020, the Company had cash of $9.6 million, compared to $21.1 million at the end of 2019.
December 31, 2020 Subsequent events
-
-
-
-
-
On January 19, 2021, the Company executed final agreement with Petroperu, restructuring the contingent derivative liability
over three years and extending the oil sales contract with Petroperu for an additional two years. The amount of the contingent
liability represented $16.6 million (based on the November 30, 2020 valuation) and was subsequently paid out (along with
the $3 million Peruvian-government COVID emergency response loan), from the successful $100 million bond offering;
On February 2, 2021, the Company announced completion of a 3-year $100 million senior secured bond with an annual 12%
coupon, issued at a 5% discount. The bonds issued by PetroTal are the Company’s only interest bearing debt and the proceeds
are for payout of the Petroperu derivative liability with Petroperu and Reactiva loan, totaling $20 million, to support the
Company’s crude oil price hedging strategy ($15 million), to finance potential acquisitions ($20 million), with the remainder
for continued development of the Bretana oil field;
On February 18, 2021, the Company announced its 2021 capital development program of $100 million, to be funded from the
bond proceeds and internally generated funds from operations, along with existing cash resources;
The Company has hedged approximately 32% of expected April to December 2021 oil production. Additionally, Petroperu
has now hedged 100% of oil sales through the ONP. This robust hedging program will ensure funding stability to support the
2021 capital development program should Brent oil price drop materially; and,
Pursuant to the Company’s oil market diversification strategy, in Q1 2021 the Company completed a second shipment of
225,000 barrels of oil through Brazil for export into the Atlantic region. The oil sale was FOB Bretana and generated revenue
of $8.8 million.
13
4. OUTLOOK AND GROWTH
STRATEGY Outlook
The capital program prioritizes management's strategy to maintain a strong balance sheet during the period of low oil prices,
maximizing activity to fit within cash flow. The Company activity will focus on managing existing production and drilling new wells
during 2021. 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 include 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;
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 capital budget is based on the expected average annual Brent oil price forecast of $50/bbl. Additionally, the Company will continue
with an appropriate oil price hedging strategy for the future.
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 primary 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.
PetroTal’s strategic priorities are to:
Increase reserves and production;
-
- Maintain a strong balance sheet by controlling and managing capital expenditures;
-
-
-
-
- Maintain a strong focus on employee, contractor and community health and safety; and
- Manage environmental and social performance to minimize negative ecological impacts and ensure continued
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;
Explore undeveloped acreage to identify and create development opportunities;
stakeholder support.
Throughout the year, 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.
14
5. SELECTED FINANCIAL INFORMATION
5.1 QUARTERLY SUMMARY
The field was shut in on May 7, 2020, for the 37 producing days in Q2 2020, production averaged 11,500 bopd.
The field was shut in from July 1 to July 14 and from August 9 to September 27, for the 28 producing days in Q3 2020, production averaged 8,000 bopd.
EARNINGS STATEMENT INFORMATION
Revenue
Sales increased to 2,086,226 barrels (5,700 bopd) in 2020, an increase from 1,474,042 barrels (4,033 bopd) in 2019. Sales for Q4
2020 were 5,471 bopd as compared to Q3 2020 of 2,327 bopd and 9,509 bopd in Q4 2019.
The Company sells its oil at various sales points. Approximately 1,300 bopd is delivered to the Iquitos refinery priced at the prevailing
Brent oil price less a discount inclusive of barge transportation charges. The majority of the oil is delivered and sold to Petroperu at
the Saramuro pump station for transportation through the ONP and onward to the Bayovar Port. The price is based on the average
monthly Brent oil price, less approximately $4.00/bbl as 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
15
Petroperu, whether higher or lower. Annual revenue decreased to $76.6 million ($36.71/bbl) in 2020 from $82.8 million ($52.32/bbl)
in 2019. Similarly, sales volumes resulted in Q4 2020 revenue of $17.4 million ($34.52/bbl) compared to $50.5 million ($57.71/bbl) for
Q4 2019.
Fluctuations in oil sales volumes and revenues were impacted by the global oil price collapse, COVID-19 pandemic and temporary
oilfield closures as a result of the pandemic and community/government social issues.
Royalties remained consistent, and on a per barrel decreased (2020 -$1.38/bbl) on an absolute basis compared to 2019 ($2.31/bbl)
due to the reduction in global oil prices. Royalties on production from the Bretana oilfield are calculated on production, and range
between 5% and 20%. The royalty calculation is 5% based on production of 5,000 bopd or less and 20% when production reaches
100,000 bopd or more, with a straight-line calculation between. The royalty regime in Peru is negotiated on a block by block basis,
based either on production scales or on economic results.
Operating expense in 2020 were $15.7 million ($7.51/bbl), as compared $14.3 million ($9.73/bbl) in 2019. This 23% reduction, on a
per barrel basis, is reflective of the mostly fixed costs being allocated over increased oil production, along with negotiated cost
reductions. As production increases and oilfield operations are normalized, operating costs, on a per barrel basis, should be reduced
further.
Transportation expense in 2020 totaled $29.2 million ($13.98/bbl), representing barging, diluent blending and pipeline costs, as
compared to $23.4 million ($15.87/bbl) in 2019. Fluctuations are reflective of oil volumes, sales delivery point and transportation
timing.
General and administrative expense in 2020 was $10.6 million ($5.07/bbl), as compared to $10.8 million ($7.33/bbl) in 2019.
Compensation reductions for all employees, inclusive of 20% reductions for management and directors, offset increased costs related
to the COVID pandemic and enhanced community support efforts.
As production increases, the per barrel cost of G&A will continue to improve. Included in G&A is construction of a new pier for
community residents and additional COVID support to the Bretana and neighboring communities. PetroTal recognizes the importance
of community alignment and support over the areas in which it operates.
16
The Company capitalized and allocated $2.6 million of G&A compared to $3.1 million in 2019. For the year ended December 31, 2020,
non-cash share-based compensation pertaining to performance share units granted to employees was $0.9 million (2019: $0.4 million).
Depletion, Depreciation and Amortization (“DD&A”) for 2020 was $12.9 million ($6.22/bbl) as compared to $8.5 million ($5.79/bbl)
for 2019. DD&A was determined using the updated annual reserve report information prepared by NSAI at December 31, 2020. On a
quarterly basis, the Q4 DD&A is $3.1 million ($6.30/bbl) as compared to $3.8 million ($4.30/bbl) in Q4 2019. DD&A is calculated based
on capital invested, production and 2P reserves.
Derivative loss of $4.8 million in 2020 is the net fair value of outstanding embedded derivatives, compared to $0.4 million in 2019.
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.
Impairment and FX expenses mainly related to the relinquishment of exploratory Block 133 ($0.4 million) expensed during 2019,
compared to a $42 thousand foreign expense gain during 2020.
Deferred tax expense of $75 thousand was recorded in 2020 compared to $86 thousand in 2019.
Financial expense of $2.0 million is mainly related to accretion of decommissioning obligation expense, as compared to $0.4 million
accretion expensed during 2019.
Reclassification
The Company has reclassified its operating expenses to separate out the transportation component from operating expenses and
present it separately. The Company has made this change to reflect how management views the performance and disclosure of its
operations. The Company has reclassified these costs in the statements of earnings (loss) and comprehensive income (loss). Historical
results were reclassified to match the current period presentation. This change did not result in a change in income (loss) before taxes
or cash flows from operations. Management believes the reclassifications described below, now align with the nature of the costs
presented with the assessment of performance of the company.
5.2
BALANCE SHEET INFORMATION
17
Cash and liquidity
At December 31, 2020, the Company held cash of $9.6 million, an $11.5 million reduction from $21.1 million at year-end 2019. The
working capital deficiency was $22.2 million at December 31, 2020 as compared to a working capital deficiency of $11.8 million at
December 31, 2019. The variance resulted primarily from revenue reduction and increased derivative obligations, both associated with
lower global oil prices.
Expected oil production increases, as a result of the 2021 capital development program, in conjunction with higher oil prices,
establishes the basis for higher cash flow. PetroTal completed a $100 million bond issue in February 2021 that enhanced liquidity
significantly, and the Company maintains spending flexibility in all areas, with minimal capital expenditure commitments.
VAT receivable
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 $14.6 million during 2020 and expects to recover $10.2 million in the short term based on its estimated oil sales.
Trade and other receivables
As at December 31, 2020, trade receivables represent revenue related to the sale of crude oil and amounts to be received in the short
term. No credit losses on the Company’s trade accounts have been incurred.
Capital expenditures
The Company primary focus was to increase oil production and building on the success of reactivating the previously-drilled and shut-
in initial discovery wells in 2019. The Company incurred $42.3 million of capital expenditures in 2020 compared to $88.8 million in
2019. Early in 2020, one successful oil well was drilled and placed on production. The COVID pandemic curtailed any further drilling
in 2020, and the drilling rig and related equipment were placed on reduced standby rates, pursuant to the contracts. In 2019, four
successful oil wells were drilled, and the Company converted the initial water disposal well into a producing oil well. Also in 2019, a new
water disposal well was drilled into the lower flank of the field with the water being injected at this level supporting aquifer
maintenance and serving to enhance oil production.
The second focus was on ensuring the Company had adequate facilities to effectively and efficiently handle the increased production.
The Company opted for a modular construction format whereby contractors’ design and build the components at manufacturing
locations. The components are then transported to and fully assembled at the Bretana oil field. This enhances construction quality
and is a cost effective solution for such major infrastructure. The initial phase of the Central Production Facility (“CPF”) was completed
and commissioning commenced in early 2020. This CPF, along with the Long Term Testing (“LTT”) equipment, is expected to easily
handle 15,000 bopd and beyond. Additional production facilities will be added as needed when production from continued drilling
18
warrants.
Some investments were made in exploration Block 107 for permits and maintenance to ensure PetroTal will be in a position to bring
in a joint venture partner in the future. Along with the $0.8 million pier built and installed for residents of the Bretana community, the
Company continues to invest in a variety of community, social and regulatory (“CSR”) initiatives. An emphasis on environmental, social
and governance (“ESG”) is prevalent throughout all areas of our operations.
At year end 2020 and 2019, the Company has approximately $5 million of exploration and evaluation assets related to exploration
Block 107.
Trade and other payables
As at December 31, 2020, trade payables and accruals are primarily related to the drilling and completion of wells, along with
construction of production processing facilities. The overall payable amount decreased due to payments performed during the year.
The Company have secured accommodations with vendors to maintain commercial and extended payment terms.
Derivatives
(1) Sales have been completed
The embedded derivative liability is classified as Level 2 fair value measurement. The service contract for transport of liquid
hydrocarbons of the North-Peruvian Oil Pipeline (“ONP”) and Petroperu Saramuro agreements signed with Petroperu during 2020,
19
include a clause to adjust the risk of volatility of the international price of crude oil during the period in which Petroperu provides the
service of crude oil usage and until the Company returns the full amount of the volumes that were delivered in advance. The price
compensation is based on the 2 day average Brent oil price marker quotes (Brent Platts and Brent ICE) to the points of shipment and
returns. In case the average price shipment is greater than the average price return, the Company will compensate Petroperu an
amount equivalent to the difference between both averages, multiplied by the volume sold or arranged by Petroperu. If the average
price shipment is lower than the average price return, 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 loss on
commodity price derivatives at December 31, 2020. At year ended 2020, 1.8 million barrels were delivered to and sold into the ONP,
and remain in the pipeline or storage tanks, awaiting final sale by Petroperu and are subject to the same settlement terms as noted
above in the ONP contract.
Decommissioning obligations
The undiscounted uninflated value of its estimated decommissioning liabilities is $23.7 million which includes an addition of $0.7
million related to the drilling campaign of the Company in the Bretana oil field, liabilities settled of $0.3 million, and revisions to
decommissioning of $2.7 million. The present value of the obligations was calculated using an average risk-free rate of 2.8% (December
31, 2019: 3.3%) 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 estimates ranges from 1.9% to 2.0%. The
table below sets out the continuity of decommissioning obligations.
Share capital
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. On June
18, 2020, the Company completed an equity issue, raising gross proceeds of approximately $18 million (at 10 pence per unit) upon
issuance of 141.2 million of units. Each unit is comprised of one common share and one half of one warrant allowing the subscriber to
purchase additional shares within 36 months at 16 pence/share upon presentation of a full warrant. In June 2019, the Company issued
equity for gross proceeds of $25.5 million upon the issuance of 133.3 million of shares, and had agents warrants exercised and
converted into 1.1 million shares for net proceeds of $0.2 million. In December 2019, PetroTal declared a dividend of $0.9 million to
all shareholders which was paid in January 2020.
As of April 21, 2021, PetroTal has the following securities outstanding:
Common shares
Performance share units
Performance warrants
Total
816,667,379
21,889,414
96,351,946
934,908,739
88%
2%
10%
100%
20
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, transportation and revenues 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.
Revenue and transportation expense adjustment
Revenue and transportation expense adjustment are non-GAAP measure, that includes in 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. Management believes the reclassifications described below, now align with the nature of the costs presented with the
assessment of performance of the company.
Q4-2020
before
reclass
15,149
(5,021)
Q4-2020
after
reclass
17,374
(7,246)
FY 2020
before
reclass
FY 2020
after
reclass
61,740
(14,322)
76,593
(29,175)
Q4-2019
before
reclass
45,916
(9,702)
Q4-2019
after
reclass
FY 2019
before
reclass
FY 2019
after
reclass
50,483
(14,269)
77,024
(17,592)
82,789
(23,357)
Revenues
Transportation
Funds flow information
Funds flow provided by operations (“FFO”), is a non-GAAP measure that includes all cash generated from operating activities and is
calculated before changes in non-cash working capital. A reconciliation from cash provided by operating activities to funds flow
provided by operations is as follows:
Funds flow netback is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes
in non-cash working capital. The Company considers funds flow netback to be a key measure as it demonstrates Company’s profitability
after all cash costs relative to current commodity prices.
FFO 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 Company’s ability to fund a return of capital without accessing outside funds and is calculated as follows:
21
Operating netback
The Company considers operating netbacks to be a key measure as they demonstrate Company’s profitability relative to current
commodity prices. Netback is calculated by dividing net operating income by total revenue.
6. 2020 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 as at December 31, 2020, 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, 2020 posted on SEDAR (www.sedar.com) and on PetroTal’s website.
Summary of oil reserves and net present values as of December 31, 2020
Company Heavy Oil Reserves (mmbbl)
Future Net Revenue Before Income Taxes Discounted at (in USD Million)
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved & Probable
Possible
Total Proved & Probable &
Possible
Gross
12.0
10.3
22.3
28.7
51.0
55.1
Net
12.0
10.3
22.3
28.7
51.0
55.1
106.1
106.1
0%
133
316
5%
137
237
449 374
1,124
1,573
2,405
3,978
734
1,108
1,372
2,480
10%
15%
134
183
317
513
830
891
129
144
273
379
652
632
20%
123
115
238
292
530
477
1,721
1,284
1,007
Summary of Pricing and Inflation Rate Assumptions – Forecast Prices and Costs (US$/bbl)
Year-End Forecast:
Brent January 1, 2020
Brent January 1, 2019
2021
$49.42
$67.94
2022
$52.85
$70.06
2023
$56.04
$71.66
2024
$57.87
$73.27
2025
$59.00
$74.57
2026
$60.15
$76.22
Year-End Crude Oil Reserves (mmbbl)
Category
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved plus Probable
Possible
Total Proved plus Probable & Possible
2020
12.0
10.3
22.3
28.7
51.0
55.1
106.1
2019
11.2
10.3
21.5
26.2
47.7
37.1
84.8
Change
7%
0%
4%
10%
7%
49%
25%
22
Year-End Net Present Value at 10% - before income tax ($ millions)
Category
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved plus Probable
Possible
Total Proved plus Probable & Possible
2020
$135
$182
$317
$513
$830
$891
$1,721
2019
$202
$232
$434
$664
$1,098
$777
$1,875
Change
-33%
-22%
-27%
-23%
-24%
15%
-8%
Year-End Net Asset Value ("NAV") per Share – after tax
Category
Proved
Proved plus Probable
Proved plus Probable & Possible
Reserve Life Index (“RLI”)
Category
Proved
Proved plus Probable
Proved plus Probable & Possible
Future Development Costs
December 31, 2020
December 31, 2019
US$/sh
$0.33
$0.76
$1.50
CAD$/sh
$0.43
$0.98
$1.93
US$/sh
$0.44
$1.11
$1.90
CAD$/sh
$0.59
$1.48
$2.53
December 31, 2020
6.4 years
30.3 years
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:
$119 million
Proved
Proved & Probable
$193 million
Proved & Probable & Possible $297 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.
As a result of the Company’s successful drilling program 2020 Proved ("1P") reserves increased by 4%, to 22.3 million barrels ("mmbbl")
from 21.5 mmbbl, Proved plus Probable ("2P") reserves increased by 7% to 51.0 mmbbl from 47.7 mmbbl, and Proved plus Probable
and Possible ("3P") reserves increased by 25% to 106.1 mmbbl from 84.8 mmbbl. At year-end 2020, Net Present Value (before tax,
discounted at 10%) (“NPV-10”) represents $317 million ($14.21/bbl) for 1P reserves, $830 million ($16.27/bbl) for 2P reserves and $1.7
billion ($16.22/bbl) for 3P reserves. Net Present Value (after tax, discounted at 10%) (“NPV-10”) represents $271 million ($12.15/bbl)
for 1P reserves, $621 million ($12.17/bbl) for 2P reserves and $1.2 billion ($11.03/bbl) for 3P reserves.
Bretana's reserve life index for 1P and 2P reserves is 6.4 years and 14.6 years, respectively. The cumulative capital invested combined
with all future development and abandonment costs represents total finding and development costs of $5.32/bbl for 1P reserves,
$3.79/bbl for 2P reserves and $2.80/bbl for 3P reserves.
Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories were unchanged from 2019 at 235, 364 and 579 mmbbls,
respectively.
In addition to ongoing development of the Bretana oilfield, there are other prospects within Block 95 and exploration opportunities in
Block 107.
Exploratory Block 107 – Osheki
23
PetroTal has a 100% working interest in this 623,280 acre block, of which the Osheki prospect is estimated by NSAI to have 278.4 mmbbls
of best estimate prospective recoverable oil resources. This estimate is based on a recovery factor of 28.5% of the estimated 970.7
million barrels of best estimate prospective OOIP, using maps generated from seismic acquired in 2007 and 2014. The best estimate
risked prospective resources figure for the Osheki prospect is 44.0 mmbbls. The prospect was de-risked with a new 3D geologic model
supporting Cretaceous age reservoirs with high quality Permian source rocks. Block 107 has four additional leads that, inclusive of
Osheki, that could contain a total of 662 mmbbls barrels of recoverable resource in the high estimate case. One of them is the
Constitucion Sur which has been upgraded to a prospect. The best estimate unrisked prospective resources figure for Constitucion Sur
is 31.6 mmbbls. This estimate is based on a recovery factor of 29.1% of the 108.5 mmbbls best estimate OOIP. The best estimate of
risked prospective resources figure for the Constitucion prospect is 3.2 mmbbls. Drilling permits for the Osheki prospect have been
approved and the Company is working on the permits for Constitucion Sur which are expected in Q4 2021. PetroTal continues to seek
joint venture partners for the Osheki prospect and other Block 107 leads.
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”), 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, 2020 and 2019. Additional
information about significant judgements and estimates are included in PetroTal’s audited Financial Statements for the years ended
December 31, 2020 and 2019.
8. RELATED PARTY TRANSACTIONS AND TAXES
The Company had no related party transactions or off-balance sheet arrangements. The Company’s key management includes the
Directors and Officers.
Taxes
Peruvian law requires the Company to pay a 2% tax on gross revenue, which is booked as a deferred income tax asset and is
recoverable once the prior net operating losses of approximately $212 million are exhausted. Due to prior net operating losses
the Company does not anticipate having a significant tax liability for the next few years. At such time as there is a tax liability, the
amounts pre-paid through the 2% payment will reduce the amount of future tax to be paid. Corporate tax rates for the Company’s
license contracts in Peru are 32%.
9. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
As of December 31, 2020, 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
Commitment
1st exploration well, minimum work 5th exploratory period
2nd exploration well, minimum work 5th exploratory period
Expiration
December 2021
December 2021
24
10. FORWARD-LOOKING STATEMENTS AND 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, 2020.
LIQUIDITY RISK
Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. Company
has no debt or loans with financial institutions. While the decrease in commodity prices as a result of the COVID-19 pandemic will
negatively impact the Company’s financial performance and position, the subsequent events disclosed in Note 21 provides the Company
with financial flexibility and the ability to meet obligations as they become due. 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
challenging economic climate is having and may continue to 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 the shut-in of production;
inability to access financing sources;
increased risk of non-performance by the Company’s customers and suppliers; and
interruptions in operations as the Company adjusts personnel to the dynamic environment.
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 evaluation expenses incurred in prior
years. These credits will be applied to future oil development activities or recovered as per the sale tax recovery legislation currently
in effect. The majority of the Company’s trade receivable balances relate to crude oil sales to one customer, being Petroperu, a state
owned company. Recently, the Company signed a long term sales agreement and initiated exports through Brazil, with and oil trading
company, whereby sales are FOB Bretana, and secured by a letter of credit. The Company’s policy is to enter into agreements with
customers that are well established and well financed entities in the oil and gas industry, including Petroperu, such that the level of
risk is mitigated. The Company has not experienced any material credit losses in the collection of its trade receivables.
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, 2020, the cash and cash equivalents
were held with seven different institutions from three countries, mitigating the credit risk of a collapse of one particular bank.
WORKFORCE MAY BE EXPOSED TO WIDESPREAD PANDEMIC
PetroTal 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 workforce at risk. The 2019/2020 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 company’s
personnel and ultimately its operations.
25
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 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 2021
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
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
26
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 the COGE and the standards established by NI 51-101. For additional information about the
Company’s prospective resources, see the Company’s press release dated September 12, 2018.
27
ADDITIONAL INFORMATION
Additional information about PetroTal Corp. and its business activities, including PetroTal’s AIF and audited Financial Statements for the
years ended December 31, 2020 and 2019 are available on the Company's website at www.petrotal-corp.com, and at www.sedar.com, or
below:
DIRECTORS
Mark McComiskey
Chair of the Board
Eleanor Barker
Ryan Ellson
Gary Guidry
Roger Tucker
Gavin Wilson
Manuel Pablo Zuniga-Pflucker
OFFICERS AND SENIOR EXECUTIVES
Manuel Pablo Zuniga-Pflucker
President and Chief Executive Officer
Douglas Urch
EVP and Chief Financial Officer
Estuardo Alvarez-Calderon
VP Exploration and Production
Glen Priestley
VP Treasury and Planning
Ronald Egusquiza
Peru General Manager
CORPORATE HEADQUARTERS
PetroTal Corp.
11451 Katy Freeway, Suite 500
Houston, Texas 77079
Office: 713.609.9101
info@petrotal-corp.com
www.petrotal-corp.com
LEGAL COUNSEL
Stikeman Elliott LLP
Calgary, Alberta
AUDITORS
Deloitte LLP
Calgary, Alberta
REGISTERED OFFICE
PetroTal Corp.
4300 Bankers Hall West, 888-3rd Street
Calgary, Alberta
NOMINATED & FINANCIAL ADVISER
Strand Hanson Limited
London, United Kingdom
OPERATING OFFICE
PetroTal Peru SRL
Calle Andres Reyes 437, Piso 8
Edificio Platinum Plaza Torre 2 – San Isidro
Lima, Peru
JOINT BROKERS
Stifel Nicolaus Europe Limited
London, United Kingdom
Auctus Advisors LLP
London, United Kingdom
STOCK EXCHANGES
TSX Venture Exchange
Toronto, Canada
TSXV: TAL
AIM Stock Exchange
London, United Kingdom
AIM: PTAL
OTC Stock Exchange
New York, USA
OTC: PTALF
RESERVES EVALUATORS
Netherland, Sewell & Associates, Inc.
Dallas, Texas
TRANSFER AGENT AND REGISTRAR
Computershare Trust Company of Canada
Calgary, Alberta
London, United Kingdom
Equity Stock Transfer
New York, NY
GLOSSARY / ABBREVIATIONS
MD&A
IFRS
CPF
bbl(s)
mbbls
mmbbl
bopd
COGE
NI 51-101
AIF
ONP
Netback
LTT
OOIP
Management’s Discussion and Analysis
International Financial Reporting Standards
Central Production Facility
Barrel(s)
Thousand barrels
Million barrels
Barrels of oil per day
Canadian Oil and Gas Evaluation handbook
National Instruments - Standards of Disclosure for Oil and Gas Activities
Annual Information Form
North Peruvian Oil pipeline agreement
Benchmark to assess the profitability based on revenues less royalties, operating and transportation costs
Long Term Testing
Original Oil in Place
28
TSXV: TAL / AIM: PTAL / OTC : PTALF
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2020 and 2019
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2020 and 2019
TSXV: TAL / AIM: PTAL / OTC: PTALF
TABLE OF CONTENTS
1. Management’s report …………………………………………………………………………………………………….
2. Independent auditor’s report …………………………………………………………………………………………
3. Consolidated balance sheets…………………………………………………………………………………………..
4. Consolidated statements of earnings (loss) and comprehensive income (loss)………………..
5. Consolidated statements of changes in equity………………………………………………………………..
6. Consolidated statements of cash flows ………………………………….………………………………….…..
7. Notes to the Consolidated Financial Statements ………………….………………………………………..
3
4
6
7
8
9
10
30
MANAGEMENT’S REPORT
The accompanying audited Consolidated Financial Statements and all information in the management 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”
Manuel Pablo Zuniga-Pflucker
Chief Executive Officer
Signed “Douglas Urch”
Douglas Urch
Chief Financial Officer
April 21, 2021
31
Deloitte LLP
700, 850 2 Street SW
Calgary, AB T2P 0R8
Canada
Tel: 403-267-1700
Fax: 587-774-5379
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, 2020 and 2019, and the consolidated
statements of earnings (loss) and comprehensive income (loss), changes in equity and cash flows for the
years then ended, and notes to the consolidated financial statements, including a summary of significant
accounting policies (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, 2020 and 2019, 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.
Other Information
Management is responsible for the other information. The other information comprises of the
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.
32
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.
• 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
33
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.
The engagement partner on the audit resulting in this independent auditor’s report is David Langlois.
Chartered Professional Accountants
Calgary, Alberta
April 21, 2021
34
35
36
37
38
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2020 and 2019. 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 crude 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 (Note 22) and transactions that occurred after the balance sheet date up to the date that the
Financial Statements were issued. Management is currently evaluating the impact of the pandemic on the industry and has concluded
that while it is reasonably possible that the virus could have a negative effect of the Company’s financial position, results of its operations,
the specific impact is not readily determinable as of the date of these Financial Statements. The Financial Statements do not include any
adjustment that might result from the outcome of this uncertainty.
These Financial Statements were approved for issuance by the Company’s Board of Directors on April 21, 2021, 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, were 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.
RECLASSIFICATION
For 2019, the Company has reclassified its operating expenses to separate out the transportation component from operating expenses
and present it separately. The Company has made this change to reflect how management views the performance and disclosure of its
operations. The Company has reclassified these costs in the consolidated statements of earnings (loss) and comprehensive income (loss).
Historical results were reclassified to match the current period presentation. This change did not result in a change to income (loss) before
taxes or cash flows from operations. Management believes the reclassifications described below, now align with the nature of the costs
presented with the assessment of performance of the Company.
39
USES OF ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGMENTS
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.
Critical judgments 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.
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 hydrocarbon, 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 judgment, 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.
Impairment Indicators
The Company monitors internal and external indicators of impairment relating to the exploration and evaluation assets. Among others,
the following are the types of indicators used:
•
•
•
•
The entity’s right to explore in an area has expired during the period or will expire in the near future without renewal;
No further exploration or evaluation work is planned or budgeted in the specific area;
The decision to discontinue exploration and evaluation in an area because of the absence of commercial reserves; or
Sufficient data exists to indicate that the book value will not be fully recovered from future development and production.
The assessment of impairment indicators requires the exercise of judgment. If an impairment indicator exists, then the recoverable
amounts of individual assets are determined based on the higher of value-in-use and fair values less costs of disposal calculations. These
require the use of estimates and assumptions, such as future oil and natural gas prices, discount rates, operating costs, future capital
requirements, decommissioning costs, exploration potential, reserves and operating performance. These estimates and assumptions are
subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may
impact the recoverable amount of assets and/or CGUs.
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, 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.
40
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 expiry 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 Consolidated Financial Statements. The actual results
ultimately may differ from those estimates as future confirming events occur.
SIGNIFICANT ACCOUNTING POLICIES
a.
Cash
Cash includes deposits held with banks in Canada, the United States and Peru that are available on demand and highly liquid.
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 (loss) and comprehensive income (loss).
c.
d.
When commercial production in an area has commenced, PP&E 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 proved plus probable reserves that affect unit-
of-production calculations are accounted for on a prospective basis.
Leases
Effective January 1, 2020 the Company adopted IFRS 16 – Leases, using the modified retrospective approach, which requires the
cumulative effect of initial application to be recognized in retained earnings. IFRS 16 eliminates the distinction between operating
and financing leases and provides a single lessee accounting model that requires the lessee to recognize assets and liabilities for
all leases on its balance sheet. Leases to explore for or use oil or natural gas are specifically excluded from this scope.
The Company excludes initial direct costs when measuring the amount of right-of-use assets, and apply a single discount rate to
portfolios of leases with similar characteristics.
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.
41
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. 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 cash-generating unit ("CGU") is the greater of its value in use and 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:
1. Expiry or impending expiry of lease with no expectation of renewal
2. Lack of budget or plans for substantive expenditures on further E&E
3. Cessation of E&E activities due to a lack of commercially viable discoveries; and
4. Carrying amounts of E&E assets are unlikely to be recovered in full from a successful development project.
e.
f.
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 oil crude and supplies to be used in the production and exploration activities, and is measured at the lesser
of acquisition cost and net realizable value. The cost of oil crude 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
Effective January 1, 2020, the Company adopted IFRS 9 - Financial Instruments, which replaced IAS 39 Financial Instruments:
Recognition and Measurement. This standard introduced a single approach to determine whether a financial asset is measured at
amortized cost or fair value. The approach is based on how an entity manages its financial instruments in the context of its business
model and the contractual cash flow characteristics of its financial assets. For financial liabilities, IFRS 9 stipulates that where the
fair value option is applied, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive
income (loss) rather than net earnings (loss), unless this creates an accounting mismatch.
On initial recognition, financial instruments are measured at fair value. Measurement in subsequent periods depends on the
classification of the financial instrument:
• 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; 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.
42
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. Refer to Note 14 for the classification and measurement of these financial instruments. Company adopted
this standard using the modified retrospective approach, whereby the cumulative effect of initial adoption of the standard is
recognized as an adjustment to retained earnings. There was no effect on the Company's retained earnings or prior period amounts
as a result of adopting this standard.
The Company’s financial instruments consist of cash, trade and other receivables, trade and other payables, and derivative
obligations. These are included in current assets and current liabilities, respectively due to their short-term nature. 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 higher of fair value less
costs to sell and value in use. 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, 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
statement of loss and comprehensive loss. 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
43
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.
j.
Revenue Recognition
Effective January 1, 2019, Company adopted IFRS 15 Revenue from Contracts with Customers, which replaced IAS 18 Revenue, IAS
11 Construction Contracts and related interpretations. This standard established a comprehensive framework for determining
whether, how much and when revenue from contracts with customers is recognized. Under IFRS 15, revenue is recognized when
a customer obtains control of the good 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.
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.
Company adopted this standard using the modified retrospective approach, whereby the cumulative effect of initial adoption of
the standard is recognized as an adjustment to retained earnings. There was no effect on the Company's retained earnings or prior
period amounts as a result of adopting this standard.
k.
l.
Share Capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as
a deduction from equity.
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 income statement.
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.
m. 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.
n.
Fair Value Measurements
44
Financial instruments recorded at fair value in the consolidated balance sheet (or for which fair value is disclosed in the notes to
the Consolidated 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.
3. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
Amendments to IFRS 3 – “Business Combinations” – Definition of a Business (“IFRS 3”)
The Company elected to early adopt the amendments to IFRS 3 effective January 1, 2020, which will be applied prospectively to acquisitions
that occur on or after January 1, 2020. The amendments introduce an optional concentration test, narrow the definitions of a business
and outputs, and clarify that an acquired set of activities and assets must include an input and a substantive process that together
significantly contribute to the ability to create outputs. These amendments do not result in changes to the Company’s accounting policies
of applying the acquisition method.
NEW ACCOUNTING STANDARDS ISSUED BUT NOT EFFECTIVE
New accounting standards and interpretations were issued and are mandatory for accounting periods after December 31, 2020. Certain
of the new accounting standards and interpretations, which are not expected to have a significant impact on the Company’s Financial
Statements upon adoption, are as follows:
•
•
Conceptual framework for financial reporting, and
Amendments to IAS 1 – Presentation of Financial Statements and IAS 8 – Accounting policies changes in accounting estimates and
errors, definition of material.
4. CASH
The following table sets out cash balances held in different currencies:
As a part of the Peruvian government’s response to the hardships brought about by COVID-19, the Company received a government
guaranteed loan (Reactiva program) of $2.8 million. A requirement of that loan was to escrow 20% of the proceeds, $0.6 million, which is
presented as non-current restricted cash. The restriction on this cash should be lifted when 80% of the 36-month loan has been repaid.
5. EXPLORATION AND EVALUATION ASSETS
The following table sets out a continuity of the Exploration and Evaluation Assets:
45
The rights to explore and exploit Block 133 have been returned and accepted by Petroperu S.A. in August 2019. The net book value of
the Block 133 was fully expensed during the third quarter 2019 ($447).
6. PROPERTY, PLANT AND EQUIPMENT
For the year ended December 31, 2020, $1.1 million of the depreciation, depletion and amortization expense was recorded as inventory
(December 31, 2019: $0.5 million).
In the first quarter of 2020, indicators of impairment were presented due to global commodity price forecast deteriorating from decreases
in demand and an increase of supply around the world. As a result of the indicators of impairment, the Company performed an impairment
test on its Peru Cash Generating Unit (CGU) whereby the recoverable amount was compared against its carrying amount. The recoverable
amount was determined using value in use, after-tax cash flows for proved plus probable reserves and after-tax discount rate of 13.5%.
Based on the results of the impairment test completed, no impairment expense was recognized.
The Company determined there were no indicators of impairment of the property, plant and equipment balance at December 31, 2020.
7. VAT RECEIVABLE
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 $14.6 million during 2020 and expects to recover $10.2 million in the short term based on its estimated oil sales.
46
8. TRADE AND OTHER RECEIVABLES
As at December 31, 2020, trade receivables represent revenue related to the sale of crude oil and collections to be received in the short
term. No credit losses on the Company’s trade accounts have been incurred.
9. TRADE AND OTHER PAYABLES
As at December 31, 2020, trade payables and accruals are primarily related to the drilling and completion of wells, as well as construction
of production processing facilities.
10. PREPAID EXPENSES
As at December 31, 2020, prepaid expenses are comprised of rent, insurances and prepaid services (consultants and other services) related
to the Company’s activities to obtain credit facilities. In accordance with Petroperu agreement a prepaid amount of $4.3 million was paid
to offset the future settlement of the derivatives obligation.
11. DECOMMISSIONING OBLIGATIONS
The undiscounted uninflated value of its estimated decommissioning liabilities is $23.7 million which includes an addition of $0.7 million
related to the drilling campaign of the Company in the Bretana oil field, liabilities settled of $0.3 million, and revisions to decommissioning
of $2.7 million. The present value of the obligations was calculated using an average risk-free rate of 2.8% (December 31, 2019: 3.3%) 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
47
flow estimates. The inflation rate used in determining the cash flow estimates ranges from 1.9% to 2.0%. The table above sets out the
continuity of decommissioning obligations.
12. INVENTORY
Product inventory consists of the Company's crude oil barrels, which are valued at the lower of cost or net realizable value. Costs include
operating expenses, royalties, transportation and depletion associated with crude oil barrels. Costs capitalized as inventory will be
expensed when the inventory is sold. As at December 31, 2020, crude inventory balance of $4,134 consists of 167,222 barrels of crude oil
valued at $24.72 per barrel (December 31, 2019: $1,549 – 93,767 barrels at $16.52 per barrel). Materials and supplies, including diluent,
are expected to be consumed in the short-term.
13. REVENUES NET OF ROYALTY
The Company’s oil production revenue is determined pursuant to the terms of the revenue agreements. The transaction price for crude
is based on the commodity price in the month of production, adjusted for quality, allowable deductions and other factors. Commodity
prices are based on market indices.
14. FINANCIAL INSTRUMENTS
The table above details the Company’s carrying value and fair value of financial instruments including cash, trade and other receivables,
lease obligations, and trade and other payables, all of which are classified as financial assets and liabilities and reported at amortized cost.
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 embedded derivative liability is classified as Level 2 fair value measurement. The service contract for transport of liquid hydrocarbons
of the North-Peruvian Oil Pipeline (“ONP”) and Petroperu Saramuro agreements signed with Petroperu during 2020, include a clause to
adjust the risk of volatility of the international price of crude oil during the period in which Petroperu provides the service of crude oil
usage and until the Company returns the full amount of the volumes that were delivered in advance. The price compensation is based on
the 2 day average Brent oil price marker quotes (Brent Platts and Brent ICE) to the points of shipment and returns. In case the average
price shipment is greater than the average price return, the Company will compensate Petroperu an amount equivalent to the difference
between both averages, multiplied by the volume sold or arranged by Petroperu. If the average price shipment is lower than the average
price return, 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 loss on
commodity price derivatives at December 31, 2020.
48
As of December 31, 2020, 1.8 million barrels of oil have been delivered to and sold into the ONP, and remain in the pipeline or storage
tanks, awaiting final sale by Petroperu and are subject to the same settlement terms as noted above in the ONP contract.
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, 2020.
LIQUIDITY RISK
Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The Company
has no debt or loans with financial institutions. While the decrease in commodity prices as a result of the COVID-19 pandemic will negatively
impact the Company’s financial performance and position, the subsequent events disclosed in Note 22 provides the Company with financial
flexibility and the ability to meet obligations as they become due. 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 challenging economic
climate is having and may continue to 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 the shut-in of production;
inability to access financing sources;
increased risk of non-performance by the Company’s customers and suppliers; and
interruptions in operations as the Company adjusts personnel to the dynamic environment.
49
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 evaluation expenses incurred in prior years.
These credits will be applied to future oil development activities or recovered as per the sale tax recovery legislation currently in effect.
The majority of the Company’s trade receivable balances relate to crude oil sales to one customer, being Petroperu, a state owned
company. Recently, the Company signed a long term sales agreement and initiated exports through Brazil, with an oil trading company,
whereby sales are FOB Bretana, and secured by a letter of credit. The Company’s policy is to enter into agreements with customers that
are well established and well financed entities in the oil and gas industry such that the level of risk is mitigated. The Company has not
experienced any material credit losses in the collection of its trade receivables.
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, 2020, the cash and cash equivalents were held with
seven different institutions from three countries, mitigating the credit risk of a collapse of one particular bank.
15. SHARE CAPITAL
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. In June 2019, the
Company issued equity for gross proceeds of $25.5 million upon the issuance of 133.3 million of shares, and had agents warrants exercised
and converted into 1.1 million shares for net proceeds of $0.2 million. In December 2019, PetroTal declared a dividend of $0.9 million to
all shareholders which was paid in January 2020. In Q1 2020, the Company received $0.2 million from the exercise of warrants.
On June 18, 2020, the Company completed an equity issue, raising gross proceeds of approximately $18 million (at 10 pence per unit) upon
issuance of 141.2 million of units. Each unit is comprised of one common share and one half of one warrant allowing the subscriber to
purchase additional shares within 36 months at 16 pence/share upon presentation of a full warrant.
DIVIDEND DECLARED
On December 12, 2019, the Company declared an interim dividend of Canadian Dollars (“CAD$”) 0.0017 cash for each common share to
be paid to shareholders on January 20, 2020, representing in aggregate a total dividend payment of approximately CAD$1.1 million ($0.9
million). The dividend declared was paid in January 2020.
Due to the financial impact of the global oil price disruption, the Company has suspended declaration and payment of dividends in order
to manage cash for business operations.
50
PERFORMANCE WARRANTS
The performance warrants have an exercise price of $0.187 per share and vested upon achievement of certain oil production targets,
within a specified period. Each warrant will be adjusted as to the number of shares to be issued on the exercise date and the exercise
price of the warrant.
INVESTORS’ WARRANTS
In connection with the brokered private placement offering on June 12, 2020, investors received one common share and one half of one
warrant allowing the subscriber to purchase additional shares within 36 months at 16 pence/share upon presentation of a full warrant.
The following table sets out a continuity of outstanding warrants:
SHARE-BASED COMPENSATION
The Company granted performance share units (“PSUs”) to employees and deferred share units (“DSUs”) to directors of the Company.
The grant date fair value of performance share units (“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 of
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 and operational milestones. The company determined
the fair value of the PSUs through a combination of Black-Scholes and a probability weighted model. The following table details the terms
of the PSUs outstanding as at December 31, 2020:
The Board of Directors, after reviewing the Company’s total shareholder return, net asset value and certain production and operational
milestones, has determined that the 2020 units are exchangeable for 0.1 share per unit (2019 Plan: 1.575).
The following assumptions were used for the Black-Scholes valuation of the PSUs granted:
For the year ended December 31, 2020, the Company recognized $0.9 million of share-based compensation expense in general and
administrative expense (December 31, 2019: $0.4 million).
The Company issued an aggregate of 2,301,599 DSUs pursuant to the Company’s DSU plan to the directors of the Company. The DSUs vest
immediately and may only be redeemed upon a holder ceasing to be a director of PetroTal. No common shares will be issued under the
DSU plan; all DSUs granted are settled in cash. The DSUs are valued at the closing share price on the reporting date
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For the year ended December 31, 2020, the Company recognized $0.2 million of DSU expense in general and administrative expense and
contributed surplus (December 31, 2019: $0.3 million).
The following table details the PSU and DSU activity:
16. FINANCIAL EXPENSE
At December 31, 2020, the Company had a financial liability of $2.8 million pertaining to a Peruvian backed loan received in Q2 2020. The
loan has an interest rate of 1.12% and is payable over 36 months. The loan was paid in February 2021.
17. TAXES
The Company utilizes the liability method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities
are recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and
liabilities.
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the net deferred tax assets
will not be realized. The Company’s ability to realize deferred tax assets is assessed throughout the year and a valuation allowance is
established, if required. The Company recognizes the impact of a tax position only if it is more likely than not to be sustained upon
examination based on the technical merits of the position. The Company also routinely assesses potential uncertain tax positions and, if
required, establishes accruals for such amounts, including interest where appropriate. The Company recognizes a tax benefit from an
uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits
of the position.
The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations in Canada,
U.S., Peru and the rest of the world. The Company is subject to statutory tax rates of 21% in the U.S., 28% in Canada and 32% in Peru
(exploration 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 as well as local income tax returns in the various jurisdictions.
The movement in deferred income tax balances is as follows:
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The valuation allowance primarily relates to Canadian and Peruvian net operating loss carryforwards, which reduces the Company’s net
deferred tax asset to an amount that will more likely than not be realized within the carryforward period. In Peru the tax loss carry-forward
related to Block 95 will expire in four years for a total of $212.7 million losses. In Canada non-capital losses can be carried forward for
twenty years for a total of $47.0 million losses, $3.0 million for US losses. There is generally no carryback period, and the carryover period
starts with the taxable year following the loss and continues indefinitely.
The Company has a tax rate in each of the three license contracts of 32%; however, due to accumulated tax losses, the Company only
expects to pay the 2% tax on revenue that is recoverable against any future tax payable. The balance of the 2% tax that is recoverable
against any future tax payable at December 31, 2020 was $0.6 million (December 31, 2019: $0.2 million) and is included in other
receivables.
18. GENERAL AND ADMINISTRATIVE EXPENSES
The Company reduced salaries to employees due to the pandemic from May to November 2020, and continued support the oil field
community in Peru, providing infrastructure and medical supplies during 2020.
19. 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.
20. COMMITMENTS
As of December 31, 2020 lease liabilities recorded for $0.3 million has the following minimum year payments under its office lease:
Year
2021
2022
2023
Thereafter
Total
Amount
97
101
40
-
238
53
IFRS 16 was applied by the Company and as such, booked a right-of-use asset relating to the head office lease of $0.4 million (balance net
of amortization of $0.3 million at December 31, 2019) and included in property, plant and equipment, with a corresponding increase to
lease obligations. The lease obligation was calculated using an average risk-free rate of 4.69%.
As of December 31, 2020, the Company holds the following letters of credit guaranteeing its commitments in the exploration blocks:
Block
107
107
Beneficiary
Perupetro S.A.
Perupetro S.A.
Amount
$1,500
$1,500
$3,000
21. CAPITAL STRUCTURE
Commitment
1st exploration well, minimum work 5th exploratory period
2nd exploration well, minimum work 5th exploratory period
Expiration
December 2021
December 2021
The Company’s objective when managing its capital is to ensure it has sufficient funds to maintain its 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 and adjusts it according to the funds available to the Company, 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:
22. SUBSEQUENT EVENTS
On January 19, 2021, the Company executed final agreement with Petroperu, restructuring the contingent derivative liability over three
years and extending the oil sales contract with Petroperu for an additional two years. The amount of the contingent liability represented
$16.6 million (based on the November 30, 2020 valuation) and was subsequently paid out (along with the $3 million Peruvian-government
COVID emergency response loan), from the successful $100 million bond offering.
On February 2, 2021, the Company announced completion of a 3-year $100 million senior secured bond with an annual 12% coupon, issued
at a 5% discount. The bonds issued by PetroTal are the Company’s only interest bearing debt and the proceeds are for payout of the
Petroperu derivative liability with Petroperu and Reactiva loan, totaling $20 million, to support the Company’s crude oil price hedging
strategy ($15 million), to finance potential acquisitions ($20 million), with the remainder for continued development of the Bretana oil
field.
On February 18, 2021, the Company announced its 2021 capital development program of $100 million, to be funded from the bond
proceeds and internally generated funds from operations, along with existing cash resources.
The Company has hedged approximately 32% of expected April to December 2021 oil production. Additionally, Petroperu has now hedged
100% of oil sales through the ONP. This robust hedging program will ensure funding stability to support the 2021 capital development
program, in the event Brent oil price drop materially.
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