2021 YEAR END REPORTING PACKAGE
APRIL 27, 2022
TSXV: TAL / AIM: PTAL / OTCQX: PTALF
PetroTal Announces 2021 Year-End Financial and Operating Results
Calgary, AB and Houston, TX – April 28, 2022—PetroTal Corp. ("PetroTal" or the "Company") (TSX-V: TAL, AIM:
PTAL and OTCQX: PTALF) is pleased to announce its financial and operating results for the year and three months ("Q4")
ended December 31, 2021.
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, 2021, which are available on SEDAR
at www.sedar.com and on the Company's website at www.PetroTal-Corp.com. Reserve amounts presented herein
were derived from an independent reserves report (the "NSAI Report") prepared by Netherland, Sewell & Associates,
Inc. ("NSAI") effective December 31, 2021. All amounts herein are in United States dollars ("USD") unless otherwise
stated.
2021 Significant Milestones and Highlights
• Achieved production of 8,966 barrels of oil per day ("bopd") and sales of 8,449 bopd, up 58% and 48%,
respectively, from 2020;
• Recorded a 5th straight quarter of production growth; reaching 10,147 bopd in Q4 2021 from 9,508
bopd in Q3 2021;
• Achieved a four year Company target of 20,000 bopd in mid December 2021 underpinned by strong
production rates from the newly drilled 8H and 9H wells in late Q3 and Q4 2021 that each reached
over 8,500 bopd, respectively;
• Generated record net operating income ("NOI") and EBITDA(a) in 2021 of $105 million and $90 million,
up approximately 3.6x and 5x, respectively, from 2020;
• Generated record funds flow provided by operations(a), before changes in working capital of $86.7
million, up over 5x from 2020;
• Grew proved plus probable ("2P") and proved plus probable plus possible ("3P") reserves by 53% and
39%, respectively, to 78 and 147 million barrels of oil ("bbl");
• Material progression of 2P after tax net present value discounted at 10% ("NPV-10") reserve value per
share of $1.23, up 62% from 2020;
• Generated 2021 proved ("1P") and 2P reserve replacement ratios of 457% and 816%, respectively;
and,
• Created the framework for a social trust representing 2.5% of production, to create long standing
alignment between communities and government, with a view to minimizing social downtime,
maximizing social profitability, and developing community projects that will have a significant positive
impact near the Company’s Bretana oilfield.
2 Selected Financial and Operational Highlights
Three Months Ended
Twelve Months Ended
Dec 31, 2020
Dec 31, 2021
Dec 31, 2021
Sept 30, 2021
44,781
(2,604)
29,587
(293)
14,970
0.02
26,114
159,189
(8,962)
104,960
(13,036)
63,972
0.08
82,191
39,243
(2,304)
25,726
5,622
6,843
0.01
26,601
(in thousands USD)
Financial
Crude oil revenues
Royalties
Net operating income (1)
Commodity price derivative (income)/loss
Net income (loss)
Basic and diluted net income (loss) (US$/share)
Capital expenditures
Operating
Average production (bopd)
Average sales (bopd)
Average Brent price ($/bbl)
Contracted sales price, gross ($/bbl)
Netback ($/bbl)(1)
Funds flow provided by operations(2)
Balance sheet
Cash and restricted cash
Working capital
Total assets
Current liabilities
Equity
(1) Net operating income obtained from revenues less royalties, operating expenses, and direct transportation.
(2) Netback per barrel (“bbl”) and funds flow provided by operations do not have standardized meaning prescribed by GAAP and therefore may not be
10,147
7,242
79.79
77.46
38.61
34,714
76,593
(2,877)
28,881
4,788
(1,524)
(0.00)
42,297
9,508
9,142
73.21
71.06
35.18
18,648
5,675
5,700
43.20
43.02
13.84
13,341
8,966
8,449
70.82
68.22
34.03
77,456
9,628
(22,157)
215,138
58,608
137,163
74,459
47,319
398,288
84,767
204,257
74,459
47,319
398,288
84,767
204,257
57,655
56,455
373,261
69,785
195,572
comparable with the calculation of similar measures for other entities. See “Selected Financial Measures” section.
2021 Operational highlights
• Robust well results. Completed one deviated and two horizontal oil wells in 2021. Both horizontal
wells had the longest laterals ever drilled in Peru with production rates in excess of 8,500 bopd during
the first month, and both paying out in under two months. Well 7D, drilled as a deviated well in the
spring of 2021, had rates in excess of 4,000 bopd and has produced over 0.5 million bbl in under one
year.
•
Infrastructure achievements. Achieved significant infrastructure milestones in 2021 with the
completion of all major construction work on CPF-2 and the completion and coring of an additional
water disposal well, essentially doubling water disposal capacity to 100,000 barrels of water per day
and allowing the field to produce up to 26,000 bopd of oil.
• Material reserves increases. Delivered excellent 2021 reserve report upgrades with increases for 1P,
2P, and 3P reserves by 68%, 53%, and 39% to 37.4, 77.9 and 147.1 million barrels, respectively. In
addition, PetroTal was able to decrease 2P Finding and Development Costs (“F&D”) by 6% to $4.68/bbl
while adding seven 2P locations plus related infrastructure, leading to a record 2P after tax NPV-10 of
just over $1 billion.
•
Expanded Brazilian sales. Created a highly successful third sales route to market into the Atlantic
region through Brazil that has surpassed the Northern Peruvian Pipeline (“ONP”) as the Company’s
3 second most profitable sales route. The first pilot cargo, completed in December 2020 was 106,000
barrels, and during 2021 PetroTal built a strong trusted commercial relationship that will allow
Brazilian shipments of 400,000 barrel cargos (without the need for diluent blending), thereby
providing a safe and stable offtake of nearly 14,000 bopd at attractive netbacks.
•
•
Social alignment mechanism established. In an effort to facilitate long standing alignment between
the government and communities, PetroTal announced and submitted a proposal to the Peruvian
Ministry of Energy and Mines for creation of a new social trust aimed to promote direct investments
into the Loreto region. The fund will be based on 2.5% of crude oil production, payable over two week
periods and calculated using the same methodology as Perupetro applies for royalties. The fund
committee and investment legal entities are in the process of being created with full transparency
and auditability to the public.
2021 capital program executed and optimized. PetroTal’s 2021 Capex investment totaled $82 million
in 2021 compared to $42 million in 2020, which was significantly curtailed due to the COVID-19
pandemic.
2021 Financial highlights
•
Leverage to kickstart development. Successfully executed a $100 million senior secured bond issue
at the trough of the oil price commodity price cycle with payment terms and amortization optimized
to impact the Company in a much stronger oil macro backdrop, allowing PetroTal to commence its
2021 capital program in March 2021 with a sound liquidity injection.
• Record net revenue. Delivered net revenue after differentials and royalties of $150 million
($48.70/bbl) compared to 2020 of $74 million ($35.58/bbl).
• Record net operating income. Generated record NOI and EBITDA(a) of $105 million ($34.03/bbl) and
$90 million ($29.31/bbl), respectively, as compared to $28.9 million ($13.84/bbl) and $18.3 million
($8.77/bbl), respectively, in 2020.
•
Successful 2021 capital program. Executed an $82 million Capex program (originally budgeted at
$101 million), deferring some non-essential infrastructure projects into 2022 to match with higher
Brent pricing and more fluid labor movement.
• Positive 2021 free cash flow. Generated annual net positive free cash flow(a) before changes in non
cash working capital and debt service of $8.4 million, a first for PetroTal.
•
•
True up revenue realized. Received true-up payments from Petroperu of approximately $28.6 million
in 2021 from oil reaching the Bayovar port and being sold at a higher price than originally received at
pump station 1 of the ONP, enhancing financial metrics, and provided tailwind liquidity throughout
the year.
Scalable lifting costs. Maintained total lifting costs between $5.1 and $5.5 million per quarter in 2021
demonstrating significant scalability as production grew 60% from Q4 2020 to Q4 2021. On an
annualized basis lifting costs were $21.5 million ($6.99/bbl) for 2021 compared to $15.7 million
($7.51/bbl) in 2020.
4 • Variable costs impacted by higher Brent pricing. Diluent and barging costs were $23.7 million
($7.68/bbl) in 2021 as compared to approximately $14.3 million ($6.85/bbl) in 2020. Increased per
barrel metrics are attributed to higher barging diesel, diluent, and floating storage costs in 2021,
compared to 2020.
• Reduced G&A per barrel. 2021 G&A of $14.3 million ($4.63/bbl) compared to $10.6 million
($5.07/bbl) in 2020, demonstrating a per barrel reduction of 10% and less than a 10% burden on
adjusted EBITDA margins.
• Record 2021 net income. 2021 net income was a record $63.2 million ($0.08/share) compared to a
net loss of $1.5 million ($0.00/share) in 2020 driven by higher commodity prices, sales volumes and a
derivative gain related to sales volumes moving through the ONP valued at a higher Brent price
compared to initial entry into the ONP.
Operation and Financial Highlights Subsequent to December 31, 2021
•
•
•
•
•
•
Leverage reduction. Due to early robust 2022 free cash flow generation and strong liquidity, PetroTal
elected to repay $20 million of the original $100 million bond issue, on April 1, 2022, reducing its total
long term debt to $80 million, thereby lowering future interest costs.
Exceptional continued well performance. Achieved a 10 day record production level for well 10H of
10,050 bopd allowing the Company to set a new total production record of 20,891 bopd for February
2022, and well payout in under a month.
CPF-2 approved. Received approval by Peruvian regulators for full commissioning and fluid processing
of CPF-2 so that up to 26,000 bopd can be processed by PetroTal.
Free cash flow focused 2022 budget. On February 22, 2022, PetroTal announced a $120 million fully
funded capital program that could potentially generate up to $230 million of free cash flow in 2022,
allowing the Company the optionality to redeem the remaining $80 million in bonds early and
implement its return of capital to shareholders strategy in Q4 2022, subject to Board approval.
TSX-V award winner and OTCQX Best Market upgrade. PetroTal was recognized as a top TSX Venture
exchange performer for 2021 ranking 10th in the energy sector and in mid January 2022, PetroTal
upgraded to the OTCQX Best Market in the United States under the ticker symbol PTALF.
Establishment of the 2.5% social trust brings interim dispute. The establishment of the 2.5% social
trust brought some anticipated demands from a minority group wanting to control the trust capital
allocation process. This resulted in the Company’s oil loading dock been blocked for five weeks
requiring the intervention of Peru’s Prime Minister and the government’s full attention to the area’s
social disputes.
Operational and Financial Highlights for Q4 2021
• Continued production growth. PetroTal produced 10,147 bopd and averaged 7,242 bopd in sales,
which was impacted by social disruptions at the ONP, along with intermittent downtime leading to
5 constrained production schedules, compared to Q3 2021 production and sales of 9,508 bopd and
9,142 bopd, respectively.
•
20,000 bopd production target achieved. The Company, with boosts from well 8H and 9H, achieved
a five day trailing production rate of 20,000 bopd ending December 15, 2021, reaching its long
standing target only four years after commencing operations at the Bretana oil field.
• Completion of well 8H. Well 8H was completed in late Q3 2021 for under $12 million, had initial
production rates in excess of 8,500 bopd, paying out in Q4 2021 from realized netbacks of over
$38.00/bbl.
• Completion of well 9H. Well 9H, completed in early December 2021, achieved approximately 9,000
bopd in early testing, averaging 8,200 bopd for the subsequent ten-day period.
•
Strong net operating income despite constrained sales. PetroTal generated $25.7 million in net
operating income in Q4 2021, a decrease from $29.6 million in Q3 2021, driven by lower sales volumes
stemming from social protests in November and December 2021.
• Capex optimization. The Company invested $26.6 million in Q4 2021, up slightly from the prior
quarter due to ongoing consistent drilling activities in the second half of 2021.
• Continued and expanding Brazilian exports. PetroTal continued to utilize the Brazilian shipping route
in Q4 2021, exporting 320,000 barrels in November and December 2021 compared to only 106,000
barrels in Q4 2020.
• Opex and Transportation cost flexibility. Lifting expense and direct transportation costs were $11.2
million ($16.82/bbl) in Q4 2021 compared to $12.6 million ($14.97/bbl) in Q3 2021, and $10.7 million
($21.23/bbl) in Q4 2020. During Q4 2022, the Company effectively utilized barges for oil storage to
manage production and sales fluctuations during social disruptions.
•
Strong Q4 2021 exit liquidity. Exited 2021 with strong balance sheet liquidity of $75.0 million in total
cash and approximately $57.0 million of net debt which was approximately 0.63x net debt to 2021
EBITDA.
• Growing derivative asset. The exit Q4 2021 net derivative asset was $36.7 million, representing the
mark to market value of oil in the ONP, corporate hedges, and ONP hedges.
Operation and Financial Highlights Subsequent to December 31, 2021
•
•
•
Leverage reduction. Due to early robust 2022 free cash flow generation and strong liquidity, PetroTal
elected to repay $20 million of the original $100 million bond issue, on April 1, 2022, reducing its total
long term debt to $80 million, thereby lowering future interest costs.
Exceptional continued well performance. Achieved a 10 day record production level for well 10H of
10,050 bopd allowing the Company to set a new total production record of 20,891 bopd for February
2022, and well payout in under a month.
CPF-2 approved. Received approval by Peruvian regulators for full commissioning and fluid processing
of CPF-2 so that up to 26,000 bopd can be processed by PetroTal.
6 •
•
•
Free cash flow focused 2022 budget. On February 22, 2022, PetroTal announced a $120 million fully
funded capital program that could potentially generate up to $230 million of free cash flow in 2022,
allowing the Company the optionality to redeem the remaining $80 million in bonds early and
implement its return of capital to shareholders strategy in Q4 2022, subject to Board approval.
TSX-V award winner and OTCQX Best Market upgrade. PetroTal was recognized as a top TSX Venture
exchange performer for 2021 ranking 10th in the energy sector and in mid January 2022, PetroTal
upgraded to the OTCQX Best Market in the United States under the ticker symbol PTALF.
Establishment of the 2.5% social trust brings interim dispute. The establishment of the 2.5% social
trust brought some anticipated demands from a minority group wanting to control the trust capital
allocation process. This resulted in the Company’s oil loading dock been blocked for five weeks
requiring the intervention of Peru’s Prime Minister and the government’s full attention to the area’s
social disputes.
Current Operations
The Company’s loading dock was re-opened on April 7, 2022 and PetroTal has been producing approximately
18,200 bopd over the last 10 days with priority sales going to Iquitos and Brazil thereafter. Until the ONP
maintenance is completed, the Company will be managing production volumes to fit the Iquitos and Brazil
sales threshold of nearly 16,000 bopd.
PetroTal is currently preparing to drill well 11H in early May with a late June or early July completion, at an
estimated cost of $15.6 million.
Updated Corporate Presentation and upcoming investor update
PetroTal is excited to announce it will be hosting a virtual investor meeting on May 26, 2022 following the
release of Q1 2022 results. The objective of management will be to provide updates on certain aspects of
the Bretana asset and to communicate the Company’s short and long term strategy. The Company has
provided an updated corporate presentation with these 2021 results, on its website.
Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented
"2021 will be remembered for many significant operational, commercial and financial milestones achieved by
the PetroTal team. When unconstrained, PetroTal is the largest crude oil producer in Peru and our
management team is well aware of the responsibilities and deliverables that accompany that stature. Our
goals for 2022 are very clear, and given the tailwind of a robust commodity price environment aiding us, we
believe the Company can add tremendous value. Having met our original goal of 20,000 bopd, the team is
now focused on achieving a new production target of 25,000 bopd with minimal social downtime. I would
like to thank PetroTal's shareholders, directors, employees, and contractors for their continued support and I
look forward to keeping the market updated on the Company's progress throughout the remainder of 2022."
7 ABOUT PETROTAL
PetroTal is a publicly traded, tri-quoted (TSXV: TAL, AIM: PTAL and OTCQX: PTALF) oil and gas development and
production Company domiciled in Calgary, Alberta, focused on the development of oil assets in Peru. PetroTal's flagship
asset is its 100% working interest in Bretana oil field in Peru's Block 95 where oil production was initiated in June 2018.
In early 2020, Petrotal became the largest crude oil producer in Peru. The Company's management team has significant
experience in developing and exploring for oil in Peru and is led by a Board of Directors that is focused on safely and
cost effectively developing the Bretana oil field. It is actively building new initiatives to champion community sensitive
energy production, benefiting all stakeholders.
For further information, please see the Company's website at www.petrotal-corp.com, the Company's filed documents
at www.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)
Ritchie Balmer / James Spinney / Robert Collins
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
T: +44 (0) 7711 627449
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
READER ADVISORIES
Notes to Press Release
(a) See "Specified Financial Measures".
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; the impact
of social disruption on the Company's operations; drilling, completions, workovers and other activities and the anticipated costs and results of such
activities; PetroTal's anticipated operational results for 2022 including, but not limited to, estimated or anticipated production levels, capital
expenditures and drilling plans; the intention to redeem the outstanding bonds; PetroTal plans to deliver strong operational performance and to
generate free cash flow and growth; capital requirements; the ability of the Company to achieve drilling success consistent with management's
expectations; the ability of the Company to achieve near term production targets and operate at unrestricted levels; anticipated future production
and revenue; drilling plans including the timing of drilling, commissioning, and startup and the impact of delays thereon; oil production levels,
including average and exit production in 2022; sales expansion through alternative exports routes, including barging and trucking; the Company's
proposals for collaboration with local communities; 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.
Without limitation of the foregoing, future dividend payments, if any, and the level thereof, is uncertain, as the Company's dividend policy and the
funds available for the payment of dividends from time to time is dependent upon, among other things, free cash flow financial requirements for
the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital
expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of PetroTal to pay dividends will be
subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions
contained in the instruments governing its indebtedness. The forward-looking statements are based on certain key expectations and assumptions
made by the Company, including, but not limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver
production and the anticipated capital expenditures associated therewith, the ability of the Ministry of Energy to effectively achieve its objectives
in respect of reducing social conflict and collaborating towards continued investment in the energy sector, reservoir characteristics, recovery factor,
exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging
arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labour, royalty regimes and
exchange rates, impact of inflation on costs, the application of regulatory and licensing requirements, the accuracy of PetroTal's geological
interpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and
development activities, the performance of new wells, 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,
wars (including Russia's military actions in Ukraine), 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. Ongoing military actions between Russia and Ukraine have the potential to threaten the supply of
oil and gas from the region. The long-term impacts of the actions between these nations remains uncertain. 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, increased
9 operating and capital costs due to inflationary pressures, business, financial conditions, results of operations and other factors relevant to the
Company. Please refer to the risk factors identified in the AIF and 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, 2021, 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 15, 2022, more detailed information is included in the AIF. All oil and gas disclosure
contained in this press release complies with the requirements of NI 51-101.
OIL AND GAS MEASURES: This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by
management, such as "F&D costs". These terms do not have a standardized meaning and may not be comparable to similar measures presented
by other companies, and therefore should not be used to make such comparisons. ""Finding and development costs" or "F&D costs" are calculated
as the sum of field capital plus the change in future development costs for the period divided by the change in reserves that are characterized as
development for the period. Finding and development costs take into account reserves revisions during the year on a per bbl basis. The aggregate
of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs
generally will not reflect total finding and development costs related to reserves additions for that year. Management uses these oil and gas
metrics for its own performance measurements and to provide shareholders with measures to compare PetroTal's operations over time. Readers
are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not
be relied upon for investment or other purposes.
SHORT-TERM PRODUCTION RATES: References in this press release peak 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 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.
SPECIFIED FINANCIAL MEASURES: This press release includes various specified financial measures, including non-GAAP financial measures, non-
GAAP financial ratios and capital management measures as further described herein. These measures do not have a standardized meaning
prescribed by generally accepted accounting principles ("GAAP") and, therefore, may not be comparable with the calculation of similar measures
by other companies. Management uses these non- GAAP measures for its own performance measurement and to provide shareholders and
investors with additional measurements of the Company's efficiency and its ability to fund a portion of its future capital expenditures. "Netback"
(non-GAAP financial ratio) equals total petroleum sales less quality discount, lifting costs, transportation costs and royalty payments calculated
on a bbl basis. The Company considers netbacks to be a key measure as they demonstrate Company's profitability relative to current commodity
prices. "Funds flow provided by operations" (non-GAAP financial measure) includes all cash generated from operating activities and is calculated
before changes in non-cash working capital. "Adjusted EBITDA" (non-GAAP financial measure) is calculated as consolidated net income (loss)
before interest and financing expenses, income taxes, depletion, depreciation and amortization and adjusted for G&A impacts and certain non-
cash, extraordinary and non-recurring items primarily relating to unrealized gains and losses on financial instruments and impairment losses,
including derivative true-up settlements. PetroTal utilizes adjusted EBITDA as a measure of operational performance and cash flow generating
capability. Adjusted EBITDA impacts the level and extent of funding for capital projects investments. Reference to EBITDA is calculated as net
operating income less G&A. "Free cash flow" (non-GAAP financial measure) is calculated as net operating income less G&A less exploration and
development capital expenditures and is calculated prior to all debt service, taxes, lease payments, hedge costs, factoring, and lease payments.
Management uses free cash flow to determine the amount of funds available to the Company for future capital allocation decisions. Please refer
to the MD&A for additional information relating to specified financial measures.
10 FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about
PetroTal's budget and guidance, prospective results of operations, production and production capacity, free cash flow, revenue, adjusted EBITDA,
debt repayment, liquidity, shareholder returns and components thereof, all of which are subject to the same assumptions, risk factors, limitations
and qualifications as set forth in the above paragraphs. FOFI contained in this press release was approved by management as of the date of this
press release and was included for the purpose of providing further information about PetroTal's anticipated future business operations. PetroTal
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.
11 MANAGEMENT’S DISCUSSION AND ANALYSIS
For the years ended December 31, 2021 and 2020
TSXV: TAL / AIM: PTAL / OTCQX: PTALF
TABLE OF CONTENTS
1. Corporate overview ……………………………………………………………………………………………………….………
2. Overview and selected information...……………………………………………………………...…………………….
3. 2021 Highlights……………………………………………………………………………………………………………………….
4. Outlook and growth strategy ..…………………...………………..……………………………………………………….
5. Selected financial information………………………………………………………………………………………………..
6. 2021 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 ………………………………………………………………………
14
15
15
17
19
28
29
30
30
31
13 MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) of the operating results and financial condition of PetroTal Corp. (“PetroTal” or
the “Company”) for the years ended December 31, 2021 and 2020, is dated April 27, 2022, and should be read in conjunction with the
Company’s audited Consolidated Financial Statements (the “Financial Statements”) for the twelve months ended December 31, 2021
and 2020 and the Company’s Annual Information Form (the “AIF”) for the year ended December 31, 2021. 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, AIM: PTAL, and OTCQX: PTALF), 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.
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.
14 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, 2021, September 30, 2021, June 30, 2021, March 31, 2021 and December 31, 2020. Note that the commodity
price derivative is a non-cash item.
RESULTS AT A GLANCE
(1) Net operating income obtained from revenues less royalties, operating expenses and direct transportation.
(2)
Funds flow provided by operations does not have standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar
measures for other entities. See “Non-GAAP Measures” section.
Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements. The table above reclassifies these fees from revenue to
direct transportation by $14,853.
(3)
3. 2021 HIGHLIGHTS
The Company reached several key operational and financial achievements as described below:
Three months ended December 31, 2021 (“Q4”) Highlights
-
Oil production averaged 10,147 barrels of oil per day (“bopd”), an increase of 7% from 9,508 bopd in Q3 2021, and a 58%
increase as compared to 6,410 bopd in Q4 2020. At December 31, 2021, the Company has ten producing wells and two water
disposal wells;
- Well BN-8H (“8H”) and well 9H (“9H”) generated large initial production rates averaging over 10,000 bopd combined in Q4
2021, demonstrating production growth of 7% quarter on quarter;
Sales allocations were 25% as export through Brazil, 56% through the ONP pipeline and 19% to the Iquitos refinery; and,
-
- Work continued on phase two of PetroTal’s central processing facility (“CPF-2”) which was completed in January 2022.
15 2021 Operational Highlights
-
-
-
-
-
-
Ten producing wells and two water disposal wells were operating at year-end, inclusive of the initial water disposal well
that was converted to an oil producing well;
The Company invested $82.2 million in capital expenditures for the drilling campaign, building production facilities, and
drilling standby-related charges, compared to a total capital investment of $42.3 million in 2020;
PetroTal produced a total of 3.3 million barrels of oil in 2021, representing an average production of 8,966 bopd, increasing
58% from the average production of 5,675 bopd realized in 2020;
Annual independent reserve assessment, as prepared by Netherland Sewell and Associates, Inc. (“NSAI”) shows increases in
all reserve categories:
o
o
o
Proved ("1P") reserves of 37.4 million barrels ("mmbbl"), an increase of 68% from the 22.3 mmbbl recorded at the
end of 2020;
Proved plus Probable ("2P") reserves of 78.0 mmbbl, an increase of 53% from the 51.0 mmbbl recorded at the end
of 2020; and,
Proved plus Probable and Possible ("3P") reserves of 147.1 mmbbl, an increase of 39% from the 106.1 mmbbl
recorded at the end of 2020;
Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories increased from 2020 by 5% to 247 mmbbls, 7% to
389 mmbbls, and 7% to 618 mmbbls, respectively; and,
Net Present Value after tax, discounted at 10% (“NPV-10”) represents $570 million ($15.24/bbl) for 1P reserves, $1.0 billion
($13.10/bbl) for 2P reserves and $1.7 billion ($11.24/bbl) for 3P reserves.
2021 Financial Highlights
-
-
-
-
-
-
Generated revenue of $159.2 million ($51.62/bbl) compared to $76.6 million ($36.71/bbl) in 2020;
Royalties paid to the Peruvian government were $9.0 million compared to $2.9 million in 2020;
Generated funds flow from operations of $77.5 million compared to $13.3 million in 2020 as a result of increased oil prices and
higher crude oil production;
Net operating income was $105.0 million ($34.03/bbl) compared to $28.9 million ($13.84/bbl) in 2020;
The Company paid bond interest of $6.0 million in August 2021 and remains in compliance with the bond covenants; and,
On December 31, 2021, the Company had cash and restricted cash of $74.5 million, compared to $9.6 million at the end of
2020.
December 31, 2021 Subsequent Events
-
-
-
-
-
-
On February 10, 2022, PetroTal announced completion of well 10H (“10H”), which commenced production on January 30,
2022 and has set a new internal daily production record with an average standalone 10 day production level of 10,500 bopd;
As previously announced on March 3, 2022, the Petroperu operated Northern Peruvian Pipeline remains closed due to erosion
caused by the rainy season, with no firm timeline of maintenance completion provided by Petroperu. The Company is now
focusing all efforts to maximize sales to the Iquitos refinery and the Brazilian export route. Commercial and technical efforts
to eventually sell 400,000 barrel (13,000 bopd) monthly cargos through the Brazil route are being explored.
On April 1, 2022, the Company elected to repay $20 million to bondholders pursuant to the call option set out in the bond
agreement. In addition, the Company paid $0.5 million of interest and prepayment fees. The remaining bond principal
repayments are $25 million in February 2023, $25 million in August 2023 and $30 million in February 2024;
On April 6, 2022, Peruvian government officials reached an agreement with the Asociación Indigena de Desarrollo y
Conservación de Bajo Puinahua (“AIDECOBAP”), to end a social protest, which had been blocking PetroTal’s loading dock since
February 28, 2022. AIDECOBAP was protesting against the government on three core issues: prosecution of protesting rights,
allocation of the Basic Needs Trust capital to close the social gaps that exist in Peru, and that the government expedite the
formalization of the Bretana 2.5% social fund, offered by PetroTal, into the Block 95 license contract. Oil production at Bretana
recommenced on April 7, 2022;
Pursuant to the Company’s oil market diversification strategy, PetroTal continues to increase oil shipments through Brazil for
export into the Atlantic region; and,
PetroTal continues to use hedges to ensure sufficient liquidity for the capital development program.
16 4. OUTLOOK AND GROWTH STRATEGY
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 2022. 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 $60/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 primarily through drilling new oil wells
to create long- term value for shareholders. This will be accomplished through the attainment of its main objectives: increasing
production, reserves, funds generated from operations and net asset value.
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.
17 Environmental and Social Governance (“ESG”) Strategy
PetroTal believes in generating long-term value for our shareholders, employees, suppliers, communities, clients, government, as well
as ensuring economic value, safety for people and the environment and a better future for all. Therefore, our sustainability strategy
to 2030 rests on our shoulders. The PetroTal ESG vision is: “create value and generate more opportunities for the benefit of all”. The
steps to measure our success are:
Develop targets for 2023, 2025 and 2030 which will be built and reviewed with the participation of each Company’s department;
-
The initiatives will be continuously updated to achieve our objectives;
-
-
The Sustainable Development Goals (“SDG”), to which PetroTal contributes through its Sustainability Plan to 2030, will be included;
- We are committed to reducing our footprint which means reducing emissions, waste, oil spills, actively managing our water usage,
focusing on bio-diversity and managing our impact positively, innovating where possible and doing all the above safely; and,
To address the aforementioned initiatives, we want to develop talent at PetroTal, the community, and within our suppliers.
-
Exploratory Block 107 – Osheki-Kametza
PetroTal has a 100% working interest in this 623,280 acre block, of which the Osheki prospect has a best estimate of 278.4 million
barrels of prospective recoverable oil resources according to NSAI. This estimate is based on a recovery factor of 28.6% of the estimated
970.7 million barrels of best estimate prospective OOIP. Resource estimates are based on maps generated from modern seismic
acquired in 2007 and 2014 and de-risked with a new 3D geologic model supporting Cretaceous age reservoirs with high quality Permian
source rocks. A second prospect, Constitucion Sur, contains a best estimate of 31.6 million barrels of prospective recoverable oil
resources. These recoverable resources are based on a recovery factor of 29.1% of the 108.5 million barrels of best estimate
prospective OOIP. Block 107 has three additional leads that, inclusive of Osheki and Constitucion Sur, could contain a total of 662
million barrels of recoverable resource in the best estimate case. A new drilling permit for the Osheki-Kametza prospect is being
sought after which would allow testing the prospect from a much better location which would be less expensive and avoid entering a
forest reserve. The Company continues to work on permits for Constitucion Sur which are expected in Q4 2022.
18 5. SELECTED FINANCIAL INFORMATION
5.1 FINANCIAL SUMMARY
19 EARNINGS STATEMENT INFORMATION
Revenue
Sales increased to 3,084,033 barrels (8,449 bopd) in 2021, an increase from 2,086,226 barrels (5,700 bopd) in 2020. Sales for Q4
2021 were 7,242 bopd as compared to 5,471 bopd in Q4 2020.
The Company sells its oil at three sales points: the local Iquitos refinery, the ONP pipeline and exports through Brazil. During 2021,
56% of the oil sales were through the ONP, with 18% to the Iquitos refinery, and 26% through Brazil. Sales to the Iquitos refinery are
priced at the prevailing Brent oil price less a quality differential discount and barge transportation charges. Sales to Petroperu at the
Saramuro pump station for transportation through the ONP and onward to the Bayovar port, are priced based on the forecasted Brent
oil price in eight months, less a quality differential, and is net of all pipeline and marketing fees. When the oil is ultimately sold by
Petroperu at Bayovar, PetroTal is subject to a valuation adjustment based on the actual price achieved by Petroperu, whether higher
or lower than the original forecasted price. Using the future eight-month price and the sales basis minimizes the impact of oil price
fluctuations given it typically takes eight months for a barrel to be monetized from the time the oil enters the pipeline. Additionally,
Petroperu placed commodity price hedges on volumes in the pipeline network. Oil sales exported through Brazil are on an FOB Bretana
basis, at the forecasted Brent oil price in two months, less a fixed amount to cover all transportation and sales costs, including the
quality differential.
Fluctuations in oil sales volumes and revenues were impacted in 2020 by the global oil price collapse, COVID-19 pandemic and
temporary oil field closures as a result of the pandemic and community/government social issues.
Royalties increased to $9.0 million ($2.91/bbl) in 2021 from $2.9 million ($1.38/bbl) in 2020 and in Q4 2021 increased to $2.3 million
($3.46/bbl) from $0.7 million ($1.39/bbl) in Q4 2020. Royalties for the Bretana oilfield are calculated on production, ranging between
5% and 20%, less transportation costs. The royalty calculation is 5% based on production of 5,000 bopd or less and 20% when
production reaches 100,000 bopd or more, increasing on a straight-line basis. Royalty determination in Peru is negotiated on an
individual block basis, based either on production scales or on economic results.
Operating expenses in 2021 were $21.5 million ($6.99/bbl), as compared to $15.7 million ($7.51/bbl) in 2020 and in Q4 2021 were
$5.1 million ($7.60/bbl) as compared to $4.7 million ($9.34/bbl). As production and oil field operations increase, the fixed operating
cost allocations become more economic.
20 Direct Transportation expenses in 2021 totaled $23.7 million ($7.69/bbl), representing barging, diluent blending and pipeline costs, as
compared to $29.2 million ($13.98/bbl) in 2020 and in Q4 2021 totaled $6.2 million ($9.23/bbl) versus $6.0 million ($11.89/bbl) in Q4
2020. Fluctuations are reflective of oil volumes, diluent pricing, sales delivery point and transportation timing.
General and administrative expense in 2021 was $14.3 million ($4.63/bbl), as compared to $10.6 million ($5.07/bbl) in 2020. In 2020,
G&A expenses were significantly reduced as a result of corporate measures taken reflective of the pandemic. During 2021, some G&A
expenses (consulting and personnel costs and non-cash equity compensation charges) have recovered to pre-pandemic levels, along
with enhanced community support initiatives. As production increases, per barrel G&A costs will decrease.
Included in G&A are expenditures related to various community project initiatives for Bretana and neighboring communities. PetroTal
recognizes the importance of community alignment and support over the areas in which it operates.
The Company capitalized and allocated $3.8 million of G&A compared to $2.6 million in 2020. For the year ended December 31, 2021,
non-cash share-based compensation pertaining to performance share units granted to employees was $1.7 million (2020: $0.9 million).
Depletion, Depreciation and Amortization (“DD&A”) for 2021 was $21.6 million ($7.01/bbl) as compared to $12.9 million ($6.22/bbl)
for 2020. On a quarterly basis, the Q4 2021 DD&A was $4.8 million ($7.14/bbl) as compared to $3.2 million ($6.30/bbl) in Q4 2020.
DD&A was determined using the updated annual reserve report information prepared by NSAI at December 31, 2021. DD&A is
calculated based on capital invested, production and 2P reserves.
Derivative gain of $13.0 million in 2021 is the net fair value of outstanding embedded derivatives, compared to a $4.8 million loss in
2020. The oil sales agreement with Petroperu for sales into the ONP are subject to oil price variations when sold by Petroperu upon
arrival at the Bayovar port.
Foreign exchange loss in 2021 was $0.3 million compared to a $42 thousand foreign exchange gain in 2020, due to fluctuations in relative
currency positions and transactions.
Deferred tax recovery of $4 thousand was recorded in 2021 compared to a deferred tax expense of $75 thousand in 2020.
Financial expense of $17.8 million was mainly related to bond interest, factoring expense, and accretion of decommissioning obligation
expense, as compared to $2.0 million of financial expense in 2020. Interest on the bonds commenced on February 16, 2021, at
completion of the bond placement.
21 Reclassification (2020)
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.
5.2
BALANCE SHEET INFORMATION
Cash and liquidity
At December 31, 2021, the Company held cash of $74.5 million, an $64.9 million increase from $9.6 million at year-end 2020. The working
capital was $47.3 million at December 31, 2021 as compared to a working capital deficiency of $22.2 million at December 31, 2020.
The variance resulted primarily from revenue and derivative asset increase, both associated with higher 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.
22 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.
As a result of capital activity and oil sales during the year, the Company recovered $30.3 million during 2021 and expects to recover
$1.1 million in the short term based on its estimated oil sales.
Trade and other receivables
As of December 31, 2021, trade receivables represent revenue related to the sale of crude oil. No credit losses on the Company’s trade
receivables have been incurred. Other receivables are primarily related to a price differential to be recovered from Petroperu and a
Peruvian income tax receivable.
Capital expenditures
The Company’s primary focus was to increase oil production and build on the success of reactivating the previously-drilled and shut-in
initial discovery wells in 2020. The Company incurred $82.2 million of capital expenditures in 2021 compared to $42.3 million in 2020.
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.
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. The Company continues to invest in a variety of community, social and regulatory (“CSR”)
initiatives. An emphasis on ESG is prevalent throughout all areas of our operations.
At year-end 2021, the Company has approximately $6 million of exploration and evaluation assets related to exploration Block 107.
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 of December 31, 2021, crude inventory balance of $12.2 million consists of 432,075
23 barrels of crude oil valued at $28.29 per barrel (December 31, 2020: $4.1 million; 167,222 barrels at $24.72 per barrel). Materials and
supplies, including diluent, are expected to be consumed in the short-term.
Trade and other payables
As at December 31, 2021, trade payables and accruals are primarily related to the drilling and completion of wells, and construction of
production processing facilities.
Derivatives
The derivative asset 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 2021, includes a clause for the
purchase price adjustment. The initial sales price is based on the arithmetic average of the ICE Brent Crude 8-month forward price. The
realized price is based on the tender price of the crude oil that is sold at the Bayovar terminal. The purchase price adjustment is the
realized price less the initial sales price. In the case the purchase price adjustment is negative, the Company will compensate Petroperu
the amount, multiplied by the volume sold or arranged by Petroperu. If the purchase price adjustment is positive, the Company will
be compensated by Petroperu.
The fair value of the embedded derivative, considering an average future Brent price marker differential, was recorded as a gain on
commodity price derivatives at December 31, 2021.
a) Petroperu implemented a hedging program of oil sales through the ONP pipeline.
b) Embedded derivative related to original Petroperu sales agreement.
c) Corporate hedge program to cover a portion of 2022 oil production.
24 As of December 31, 2021, 2.5 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.
Decommissioning obligations
The undiscounted uninflated value of its estimated decommissioning liabilities is $23.2 million. The present value of the obligations
was calculated using an average risk-free rate of 3.6% (December 31, 2020: 2.8%) to reflect the market assessment of the time value
of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in
determining the cash flow estimate was 2.0%. The table below sets out the continuity of decommissioning obligations.
Short and long-term debt
On February 2, 2021, the Company completed a 3-year senior secured bond with a face value of $100 million issued at a 5% discount
for total consideration of $95 million. The bonds bear interest at 12% and interest is due semi-annually with repayments of $25 million
in February 2023, $25 million in August 2023 and $50 million in February 2024.
In accordance with the terms of the bond agreement, the bonds are secured by all assets of the Company, and the Company is required
to maintain the following financial ratios:
Covenant
a)
b)
c)
Ratio
Liquidity
Equity
Leverage
Description
Cash amount not less than interest payable for the next 12 months
Equity to total assets minimum rate of 40%
Net debt to EBITDA does not exceed the ratio of 3:1
The Company met all financial covenants as at December 31, 2021. No distributions to shareholders are permitted until the bonds are
relinquished.
Fair Value
The short-term and long-term debt of $98.2 million was comparable to third-party fair value estimates for similar issues or current
rates. The fair value of the Company’s debt on December 31, 2021, was determined by reference to valuation inputs under Level 2 of
the fair value hierarchy.
25 Leases
The Company commenced a seven-year service contract with a supplier, that provides turnkey power generation equipment services,
in Q1 2021. The Company has the option to buy the equipment in year five for $4.5 million. The incremental borrowing rate used to
measure the lease liabilities was 4.0% for the dollar denominated lease.
As of December 31, 2021 total lease liabilities have the following minimum undiscounted payments per year:
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. During
2021, 7,056,591 warrants were exercised, generating proceeds of $1.4 million. On June 18, 2020, the Company completed an equity
issue, raising gross proceeds of approximately $18 million 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.
As of April 27, 2022, PetroTal has the following securities outstanding:
Common shares
Performance share units
Performance warrants
Total
5.3
NON-GAAP TERMS
836,501,920
28,577,181
80,990,606
946,069,707
88%
3%
9%
100%
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.
NON-GAAP FINANCIAL MEASURES
Revenue and transportation expense adjustment
Revenue and transportation expense adjustment are a 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.
26 Funds flow information
Funds flow provided by operations (“FFO”), is a non-GAAP measure that includes all cash generated from operating activities and
changes in non-cash working capital. The Company considers funds flow from operations to be a key measure as it demonstrates
Company’s profitability. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows:
Funds flow after investing activities is a non-GAAP measure and the Company considers free funds flow or free cash flow to be a key
measure as it demonstrates Company’s ability to fund a return of capital without accessing outside funds and is calculated as follows:
CAPITAL MANAGEMENT MEASURES
Adjusted EBITDA
Adjusted EBITDA means earnings before interest, taxes, depreciation and amortization, and derivatives.
27 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. For debt covenant purposes, the Company
also looks at Adjusted EBITDA.
6.
2021 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, 2021, 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, 2021 posted on SEDAR (www.sedar.com) and on PetroTal’s website.
Summary of oil reserves and net present values as of December 31, 2021
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
16.2
21.2
37.4
40.5
77.9
69.1
Net
16.2
21.2
37.4
40.5
77.9
69.1
147.0
147.0
0%
294
782
1,076
1,646
2,722
2,940
5,662
5%
271
600
871
1,012
1,883
1,545
3,428
10%
15%
250
475
725
665
1,390
932
2,322
231
386
617
461
1,078
622
1,700
20%
215
321
536
334
870
445
1,315
Summary of Pricing and Inflation Rate Assumptions – Forecast Prices and Costs (US$/bbl)
Year-End Forecast:
Brent January 1, 2021
Brent January 1, 2022
2022
$52.85
$75.33
2023
$56.04
$71.46
2024
$57.87
$69.62
2025
$59.00
$71.01
2026
$60.15
$72.44
2027
$61.33
$73.88
Year-End Crude Oil Reserves (mmbbl)
Category
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved plus Probable
Possible
Total Proved plus Probable & Possible
2021
16.2
21.2
37.4
40.5
77.9
69.1
147.0
2020
12.0
10.3
22.3
28.7
51.0
55.1
106.1
Change
35%
106%
68%
41%
53%
25%
39%
28 Year-End Net Present Value at 10% - before income tax ($ millions)
Category
Proved Developed Producing
Proved Undeveloped
Total Proved
Probable
Total Proved plus Probable
Possible
Total Proved plus Probable & Possible
Year-End Net Asset Value ("NAV") per Share – after tax
2021
$250
$474
$724
$665
$1,389
$932
$2,321
2020
$135
$182
$317
$513
$830
$891
$1,721
Change
85%
160%
129%
30%
67%
5%
35%
Category
Proved
Proved plus Probable
Proved plus Probable & Possible
Reserve Life Index (“RLI”)
Category
Proved
Proved plus Probable
Proved plus Probable & Possible
Future Development Costs
December 31, 2021
December 31, 2020
US$/sh
$0.69
$1.23
$2.00
CAD$/sh
$0.88
$1.57
$2.54
US$/sh
$0.33
$0.76
$1.50
CAD$/sh
$0.43
$0.98
$1.93
December 31, 2021
13.8 years
28.9 years
54.5 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:
$141 million
Proved
Proved plus Probable
$289 million
Proved plus Probable & Possible $504 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, 2021 1P reserves increased by 68%, to 37.4 mmbbl from 22.3 mmbbl, 2P
reserves increased by 53% to 77.9 mmbbl from 51.0 mmbbl, and 3P reserves increased by 39% to 147.1 mmbbl from 106.1 mmbbl. At
year-end 2021, Net Present Value (before tax, discounted at 10%) represents $724 million ($19.35/bbl) for 1P reserves, $1.4 billion
($17.83/bbl) for 2P reserves and $2.3 billion ($15.77/bbl) for 3P reserves. Net Present Value (after tax, discounted at 10%) represents
$570 million ($15.24/bbl) for 1P reserves, $1.0 billion ($13.09/bbl) for 2P reserves and $1.7 billion ($11.23/bbl) for 3P reserves.
Bretana's reserve life index for 1P and 2P reserves is 13.8 years and 28.9 years, respectively. The cumulative capital invested combined
with all future development and abandonment costs represents total funding and development costs of $6.63/bbl for 1P reserves,
$4.68/bbl for 2P reserves and $3.85/bbl for 3P reserves.
OOIP estimates for 1P, 2P and 3P reserve categories increased in 2021 from 235 to 247 (5%), 364 to 389 (7%), and 579 to 618 (7%)
mmbbls, respectively.
In addition to ongoing development of the Bretana oilfield, there are other prospects within Block 95 and exploration opportunities in
Block 107.
7. SIGNIFICANT JUDGEMENTS AND ESTIMATES
Management is required to make judgments, assumptions and estimates that have a significant impact on the Company’s financial
29 results. Significant judgments in the Financial Statements include going concern, financing arrangements, impairment indicators,
assessment of transfers from Exploration and Evaluation (“E&E”) to Property, Plant and Equipment (“PP&E”), leases, derivatives, asset
acquisition and joint arrangements. Significant estimates in the Financial Statements include commitments, provision for future
decommissioning obligations, recoverable amounts for exploration and evaluation assets and accruals. In addition, the Company uses
estimates for numerous variables in the assessment of its assets for impairment purposes, including oil prices, exchange rates, discount
rates, cost estimates and production profiles. By their nature, all of these estimates are subject to measurement uncertainty, may be
beyond management’s control and the effect on future Financial Statements from changes in such estimates could be significant.
Critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Financial
Statements are included in the Financial Statements and the accompanying notes as of December 31, 2021 and 2020. Additional
information about significant judgements and estimates are included in PetroTal’s audited Financial Statements for the years ended
December 31, 2021 and 2020.
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.
The compensation paid to our non-executive directors during the year ended December 31, 2021 is set forth in the following table.
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 $276 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, 2021, 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 2023
December 2023
30 10. FORWARD-LOOKING STATEMENTS AND BUSINESS RISKS
FOREIGN EXCHANGE RATE RISK
The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working
capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item. Excluding
the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss, based on
foreign currency balances held at December 31, 2021.
LIQUIDITY RISK
Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The
Company’s approach to managing liquidity risk is to have sufficient cash and/or credit facilities to meet its obligations when due.
Liquidity is managed through short and long-term cash, debt and equity management strategies. The Company’s liquidity risk is
impacted by current and future commodity prices. If required, the Company will also consider additional short-term financing or
issuing equity in order to meet its future liabilities. Declines in future commodity prices could affect the Company’s ability to fund
ongoing operations. The current challenging economic climate has and may continue to have a significant impact on the Company
including, but not exclusively:
•
•
•
•
•
•
material declines in revenue and cash flows as a result of the decline in commodity prices;
declines in revenue and operating activities due to reduced capital programs and the shut-in of production;
inability to access financing sources;
increased risk of non-performance by the Company’s customers and suppliers;
interruptions in operations as the Company adjusts personnel to the dynamic environment; and,
delivery of crude oil at Bayovar port and sale swap price risk.
The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on the
Company is not known at this time. Estimates and judgments made by management in the preparation of the financial statements are
increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.
CREDIT RISK
Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial
loss to the Company. The Company’s VAT is primarily for sales tax credits on exploration and evaluation expenses incurred in prior
years. These credits will be applied to future oil development activities or recovered as per the sales tax recovery legislation currently
in effect. The majority of the Company’s trade receivable 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, 2021, the cash and cash equivalents
were held with six different institutions from three countries, mitigating the credit risk of a collapse of one particular bank.
WORKFORCE MAY BE EXPOSED TO WIDESPREAD PANDEMIC
PetroTal’s operations are located in areas relatively remote from local towns and villages and represent a concentration of personnel
working and residing in close proximity to one another. Should an employee or visitor become infected with a serious illness that has
the potential to spread rapidly, this could place the workforce at risk. The 2020/2021 outbreak of the novel coronavirus in China and
other countries around the world is one example of such an illness. The Company takes every precaution to strictly follow industrial
hygiene and occupational health guidelines. There can be no assurance that this virus or another infectious illness will not impact
company’s personnel and ultimately its operations.
31 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 2022
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
32 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 website for the most current press release.
33 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, 2021 and 2020 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
Dewi Jones
VP Exploration and Development
Glen Priestley
VP Treasury and Planning
Luis Pantoja
General Manager - Peru
Guillermo Florez
Deputy General Manager - Peru
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
Lima, Peru
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
OTCQX Stock Exchange
New York, USA
OTCQX: 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
34 GLOSSARY / ABBREVIATIONS
1P
2P
3P
AIDECOBAP
AIF
bbl(s)
bopd
COGE
CPF
CSR
DD&A
EIA
ESG
FFO
GAAP
IFRS
mbbls
MD&A
mmbbl
NAV
NSAI
Netback
NI 51-101
NPV-10
ONP
OOIP
RLI
PP&E
SDG
VAT
Proved
Proved plus Probable
Proved plus Probable & Possible
Asociación Indigena de Desarrollo y Conservación de Bajo Puinahua
Annual Information Form
Barrel(s)
Barrels of Oil per Day
Canadian Oil and Gas Evaluation Handbook
Central Production Facility
Community, Social and Regulatory
Depletion, Depreciation and Amortization
Environmental Impact Assessment
Environmental and Social Governance
Funds Flow Provided by Operations
Generally Accepted Accounting Principles
International Financial Reporting Standards
Thousand Barrels
Management’s Discussion and Analysis
Million Barrels
Net Asset Value
Netherland Sewell and Associates, Inc.
Benchmark to assess the profitability based on revenues less royalties, operating and transportation costs
National Instruments - Standards of Disclosure for Oil and Gas Activities
Net Present Value Discounted at 10%
North Peruvian Oil Pipeline Agreement
Original Oil in Place
Reserve Life Index
Property, Plant and Equipment
Sustainable Development Goals
Value Added Tax
35 AUDITED CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2021 and 2020
TSXV: TAL / AIM: PTAL / OTCQX: PTALF
TABLE OF CONTENTS
1. Management’s report …………………………………………………………………………………………………….
2. Independent auditor’s report …………………………………………………………………………………………
3. Consolidated balance sheets…………………………………………………………………………………………..
4. Consolidated statements of earnings (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 ………………….………………………………………..
38
39
42
43
44
45
46
37 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
President and Chief Executive Officer
Signed “Douglas Urch”
Douglas Urch
Executive VP and Chief Financial Officer
April 27, 2022
38 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, 2021 and 2020, and the consolidated
statements of earnings (loss) and other 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, 2021 and 2020, 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.
39
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
40
we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s
report to the related disclosures in the financial statements or, if such disclosures are inadequate, to
modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our
auditor’s report. However, future events or conditions may cause the Company to cease to continue
as a going concern.
• Evaluate the overall presentation, structure and content of the financial statements, including the
disclosures, and whether the financial statements represent the underlying transactions and events in
a manner that achieves fair presentation.
• Obtain sufficient appropriate audit evidence regarding the financial information of the entities or
business activities within the Company to express an opinion on the financial statements. We are
responsible for the direction, supervision and performance of the group audit. We remain solely
responsible for our audit opinion.
We communicate with those charged with governance regarding, among other matters, the planned
scope and timing of the audit and significant audit findings, including any significant deficiencies in
internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant
ethical requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
The engagement partner on the audit resulting in this independent auditor’s report is Christopher Gill.
/s/ Deloitte LLP
Chartered Professional Accountants
Calgary, Alberta
April 27, 2022
41
42 43 44 45 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2021 and 2020. 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 24) 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 27, 2022, 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.
USES OF ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGEMENTS
The preparation of the Company’s Financial Statements requires management to make judgement, estimates, and assumptions that affect
the application of accounting policies and the reported amount of assets, liabilities, income and expenses. The estimates and associated
assumptions are based on historical experience and other factors that are considered relevant. Actual results may differ from estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the
same period if the revision affects only that period or in the period of the revision and future periods if the revision affects current and
future periods.
46 Estimates and critical judgements in applying accounting policies that have the most significant effect on the amounts recognized in the
Financial Statements are summarized below:
Functional Currency
The functional currency of each of the Company’s entities is the United States dollar, which is the currency of the primary economic
environment in which the entities operate.
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 judgement, and it is possible to have exploratory costs remain capitalized for
several years while additional drilling is performed, or the Company seeks government, regulatory or partner approval of development
plans.
Petroleum and natural gas assets are grouped into cash generating units (“CGUs”) identified as having largely independent cash flows and
are geographically integrated. The determination of the CGUs was based on management’s interpretation and judgement.
Decommissioning Obligations
Decommissioning obligations will be incurred by the Company at the end of the operating life of wells or supporting infrastructure. The
ultimate asset decommissioning costs and timing are uncertain and cost estimates can vary in response to many factors including changes
to relevant legal and regulatory requirements, the emergence of new restoration techniques, experience at other production sites. As a
result, there could be significant adjustments to the provisions established which would affect future financial results. The expected
amount of expenditure is estimated using a discounted cash flow calculation with a risk-free discount rate. Liabilities for environmental
costs are recognized in the period in which they are incurred, normally when the asset is developed, and the associated costs can be
estimated.
Deferred Tax Assets & Liabilities
The estimation of income taxes includes evaluating the recoverability of deferred tax assets based on an assessment of the Company’s
ability to utilize the underlying future tax deductions against future taxable income prior to 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.
47 SIGNIFICANT ACCOUNTING POLICIES
a.
Cash and Restricted Cash
Cash includes deposits held with banks in Canada, the United States and Peru that are available on demand and highly liquid. The
Company’s restricted cash is cash reserved for letters of credit guaranteeing the Company’s commitments for the exploration of
Block 107, acquisition of qualified hydrocarbon assets, and permitted hedging programs. The restricted cash is not available for
the Company’s immediate or general business use.
b. Property, Plant and Equipment
Property, plant and equipment (“PP&E”) is recorded at cost less accumulated depreciation. Depreciation begins when the asset is
put into service and is calculated annually using the straight-line method. The cost of maintenance and repairs is charged to
expense as incurred. The cost of significant renewals and improvements is added to the carrying amount of the respective asset.
When assets are retired, or otherwise disposed of, the cost and related accumulated depreciation are removed from the balance,
and any resulting gain or loss is reflected in the consolidated statements of earnings (loss) and comprehensive income (loss).
When commercial production in an area has commenced, petroleum properties, excluding surface costs are depleted using the
unit-of-production method over their proved plus probable reserve life. Proved plus probable reserves are determined annually
by qualified independent reserve engineers. Changes in factors such as estimates of proved plus probable reserves that affect unit-
of-production calculations are accounted for on a prospective basis.
c.
Leases
The Company assesses each new contract to determine whether it contains a lease. A specific asset is the subject of a lease if the
contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Company
allocates contract consideration to the lease and non-lease components on the basis of their relative stand-alone prices.
The right-of-use asset is initially measured at cost, which includes: (i) the amount of the initial measurement of the lease liability,
(ii) any lease payments made at or before the lease commencement date, less any lease incentives received, (iii) any initial direct
costs incurred, and (iv) an estimate of restoration costs.
The lease liability and initial right-of-use asset are recognized at the lease commencement date measured at the present value of
fixed lease payments (including in-substance fixed payments) plus the exercise price of a purchase option if the lessee is reasonably
certain to exercise that option, discounted at a rate the Company would be required to borrow over a similar term.
Key judgements include whether a contract identifies an asset (or a portion of an asset), whether the lessee obtains substantially
all of the economic benefits of the asset over the contract term, whether the lessee has the right to direct the asset’s use, which
components are fixed or variable in nature and the discount rate. The Company applied its incremental borrowing rate for leases
where the implicit rate cannot be readily determined. Right-of-use assets are presented within property, plant and equipment.
After initial recognition, the lease liability is accreted for the passage of time and reduced for lease settlements made during each
period. If the lease term reflects that the Company will exercise a purchase option, the right-of-use asset is depreciated from the
lease commencement date to the end of the useful life of the underlying asset. Otherwise, the right-of-use asset is depreciated to
the earlier of the end of the useful life of the underlying asset or to the end of the lease term.
d.
Impairment
Financial assets carried at amortized cost
At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost
is impaired. If such evidence exists, the Company recognizes an impairment loss in net earnings (loss). Impairment losses are
reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the
impairment was recognized.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying
amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually
significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively
in groups that share similar credit risk characteristics.
48 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 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.
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.
e.
f.
Inventory
Inventory consists of oil crude and supplies to be used in the production and exploration activities, and is measured at the lesser
of cost and net realizable value. The cost of 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
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;
• Fair value through other comprehensive income - transaction costs under this classification are expensed as incurred. Financial
instruments under this classification include derivative assets and liabilities where hedge accounting is applied; and
• Amortized cost - subsequently carried at amortized cost using the effective interest rate method. Financial instruments under
this classification includes accounts receivable, accounts payable and accrued liabilities and long-term debt.
IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Derivative
instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as
effective accounting hedges, and thus does not apply hedge accounting. As a result, the Company's policy is to classify all financial
derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value with a
corresponding gain or loss in net earnings (loss). Attributable transaction costs are recognized in net earnings (loss) when incurred.
The estimated fair value of all derivative instruments is based on quoted market prices and/or third-party market indications and
forecasts.
Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when
their economic characteristics and risks are not closely related to those of the host contract; when the terms of the embedded
derivatives are the same as those of a freestanding derivative; and when the combined contract is not measured at fair value
49 through profit or loss. The timing of the expected delivery to the final point of sale drives the value of the embedded derivative in
the Petroperu contract, as the fair value of the derivative depends on the oil price at the time of the expected sale date at the final
point of sale. Refer to Note 9 for the classification and measurement of these financial instruments.
The Company’s financial instruments consist of cash, trade and other receivables, derivative assets, trade and other payables,
derivative liabilities, and short and long-term debt and are included in the Company’s balance sheet. The Company initially
measures financial instruments at fair value.
g.
Exploration and Evaluation Assets
E&E costs are those expenditures for an area where technical feasibility and commercial viability have not yet been determined.
All costs directly associated with the exploration and evaluation of oil and natural gas reserves are initially capitalized. These costs
include acquisition costs, exploration costs, geological and geophysical costs, decommissioning costs, E&E drilling, sampling and
appraisals. Costs incurred prior to acquiring the legal rights to explore an area are expensed as incurred.
At each reporting date, the carrying amounts of the Company’s exploration and evaluation assets are reviewed to determine
whether there is any indication that those assets are impaired. If any such indication exists, the recoverable amount of the asset
is estimated in order to determine the extent of the impairment, if any. The recoverable amount is the greater of its value in use
and its fair value less costs to sell. If the recoverable amount of an asset is estimated to be less than its carrying amount, the
carrying amount of the asset is reduced to its recoverable amount and the impairment loss is recognized in profit or loss for the
year. The exploration and evaluation phase of a particular project is completed when both the technical feasibility and commercial
viability of extracting oil or gas are demonstrable for the project or there is no prospect of a positive outcome for the project.
Exploration and evaluation assets with commercial reserves will be reclassified to development and production assets and the
carrying amounts will be assessed for impairment and adjusted (if appropriate) to their estimated recoverable amounts.
When an area is determined to be technically feasible and commercially viable the accumulated costs are transferred to property,
plant and equipment, where they are depleted. Exploration and evaluation assets are not amortized during the exploration and
evaluation stage. When an area is determined not to be technically feasible and commercially viable or the Company decides not
to continue with its activity, the unrecoverable costs are charged to comprehensive income (loss) as impairment of exploration
and evaluation assets.
h. Decommissioning Obligations
The Company recognizes a decommissioning liability in relation to the evaluation and exploration assets and to property, plant and
equipment, in the period in which a reasonable estimate of the fair value can be made of the statutory, contractual, constructive
or legal liabilities associated with the retirement of the oil and gas properties, facilities and pipelines. The amount recognized is
the estimated cost of decommissioning, discounted to its present value using a discount rate. The estimates are reviewed
periodically. Changes in the provision resulting from changes to the timing of expenditures, costs or risk-free rates are dealt with
prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment or
exploration and evaluation assets. The unwinding of the discount on the decommissioning provision is charged to the consolidated
statements of earnings (loss) and comprehensive income (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 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.
50 j.
Revenue Recognition
Under IFRS 15, revenue is recognized when a customer obtains control of the goods or services as stipulated in a performance
obligation. Determining whether the timing of the transfer of control is at a point in time or over time requires judgement and can
significantly affect when revenue is recognized. In addition, the entity must also determine the transaction price and apply it
correctly to the goods or services contained in the performance obligation.
The Company's revenue is derived exclusively from contracts with customers. Revenue associated with the sale of crude oil and
gas is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is
recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service
is transferred when the customer obtains control of the good or service. The transfer of control of oil and gas usually coincides
with title passing to the customer and the customer taking physical possession. Company mainly satisfies its performance
obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are
not significant.
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.
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 consolidated statements
of earnings (loss) and comprehensive income (loss). 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
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.
51 o. Business Combinations
The Company adopted the amendments to IFRS 3 – Business Combinations. The amendments introduced an optional
concentration test, narrowed the definitions of a business and outputs, and clarified 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.
3. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
NEW ACCOUNTING STANDARDS ISSUED BUT NOT EFFECTIVE
New accounting standards and interpretations were issued and are mandatory for accounting periods after December 31, 2021. 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:
•
•
•
IAS 16 – Property, Plant and Equipment – Effective January 1, 2022, the amendments prohibit a company from deducting from
the cost of PP&E amounts received from selling items produced while the company is preparing the asset for its intended use.
Instead, a company will recognize such sales proceeds and related cost in profit or loss.
IAS 37 – Provisions, Contingent Liabilities and Contingent Assets – Effective January 1, 2022, the amendments specify which costs
an entity includes in determining the cost of fulfilling a contract for the purpose of assessing whether the contract is onerous.
IAS 1 – Presentation of Financial Statements – Effective January 1, 2023, the amendments clarify the requirements for the
presentation of liabilities as current or non-current in the statement of financial position.
4. CASH AND RESTRICTED CASH
The following table sets out cash and restricted cash balances held in different currencies:
Current restricted cash of $23.5 million is primarily related to acquisitions of qualified hydrocarbon assets, and $6 million of non-current
restricted cash is related to permitted hedging programs (see Note 9). In 2020, as 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, and a
requirement of the loan was to escrow 20% of the proceeds, $0.6 million, which is presented as non-current restricted cash.
5. 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. As a
result of capital activity and oil sales during the year, the Company recovered $30.3 million during 2021 and expects to recover $1.1 million
in the short term based on its estimated oil sales.
52 6. TRADE AND OTHER RECEIVABLES
As of December 31, 2021, trade receivables represent revenue related to the sale of crude oil. No credit losses on the Company’s trade
receivables have been incurred. Other receivables are primarily related to a price differential to be recovered from Petroperu and a
Peruvian income tax receivable.
7. 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 of December 31, 2021, crude inventory balance of $12,222 consists of 432,075 barrels of crude
oil valued at $28.29 per barrel (December 31, 2020: $4,134, 167,222 barrels at $24.72 per barrel). Materials and supplies, including diluent,
are expected to be consumed in the short-term.
8. PREPAID EXPENSES
As of December 31, 2021, prepaid expenses are comprised of rent, insurance and other services. As at December 31, 2020, prepaid
expenses were comprised of rent, insurance, and prepaid services (consultants and other services) related to the Company’s activities to
obtain credit facilities. In accordance with the Petroperu agreement (Note 9), in 2020 a prepaid amount of $4.3 million was paid to offset
the future settlement of the derivatives obligation.
9. RISK MANAGEMENT
The table above details the Company’s carrying value and fair value of financial instruments including cash and restricted cash, trade and
other receivables, derivatives, short and long-term debt, and trade and other payables, all of which are classified as financial assets and
liabilities and reported at amortized cost or fair value. The Company is exposed to various financial risks arising from normal-course
business exposure. These risks include market risks relating to foreign exchange rate fluctuations and commodity price risk as well as
liquidity.
53 COMMODITY PRICE DERIVATIVES
The derivative asset 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 2021, includes a clause for the purchase
price adjustment. The initial sales price is based on the arithmetic average of the ICE Brent Crude 8-month forward price. The realized price
is based on the tender price of the crude oil that is sold at the Bayovar terminal. The purchase price adjustment is the realized price less
the initial sales price. In the case the purchase price adjustment is negative, the Company will compensate Petroperu the amount,
multiplied by the volume sold or arranged by Petroperu. If the purchase price adjustment is positive, the Company will be compensated
by Petroperu.
The fair value of the embedded derivative, considering an average future Brent price marker differential, was recorded as a gain on
commodity price derivatives at December 31, 2021.
a) Petroperu implemented a hedging program of oil sales through the ONP pipeline.
b) Embedded derivative related to original Petroperu sales agreement.
c) Corporate hedge program to cover a portion of 2022 oil production.
As of December 31, 2021, 2.5 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, 2021.
54 LIQUIDITY RISK
Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The Company’s
liquidity risk is impacted by current and future commodity prices. If required, the Company will also consider additional short-term financing
or issuing equity in order to meet its future liabilities. Declines in future commodity prices could affect the Company’s ability to fund ongoing
operations. The current challenging economic environment 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;
interruptions in operations as the Company adjusts personnel to the dynamic environment; and,
delivery of crude oil at Bayovar port and sale swap price risk.
Estimates and judgements made by management in the preparation of the financial statements are subject to a certain degree of
measurement uncertainty during this volatile period.
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 sales 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’s customer
sales for 2021 were 25% as export through Brazil, 56% through the ONP pipeline and 19% to the Iquitos refinery. 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, 2021, the cash and cash equivalents were held with six
different institutions from three countries, mitigating the credit risk of a collapse of one particular bank.
10. EXPLORATION AND EVALUATION ASSETS
The following table sets out a continuity of the Exploration and Evaluation Assets:
55 11. PROPERTY, PLANT AND EQUIPMENT
For the year ended December 31, 2021, $1.7 million of the depreciation, depletion and amortization expense was recorded as inventory
(December 31, 2020: $1.1 million).
The Company determined there were no impairment indicators of the property, plant and equipment balance at December 31, 2021 and
2020.
12. SHORT AND LONG-TERM DEBT
At December 31, 2020, the Company had a financial liability of $2.8 million pertaining to a Peruvian backed loan. The loan was paid in
February 2021.
On February 2, 2021, the Company completed a 3-year senior secured bond with a face value of $100 million issued at a 5% discount for
total consideration of $95 million. The bonds bear interest at 12% and interest is due semi-annually with principal repayments of $25
million in February 2023, $25 million in August 2023 and $50 million in February 2024. The Company incurred deferred financing costs of
$4.1 million, which are amortized using the effective interest method over the remaining term of the debt. The Company, at its option,
may redeem the bonds prior to maturity. Each bondholder shall have a right of prepayment and the issuer shall have a right of redemption,
in each case at a price of 101% of nominal amount (plus accrued but unpaid interest on the redeemed bonds) during a period of 30 calendar
days starting at the first anniversary of the issue date. According to the agreement, the net proceeds of $90.9 million from the bonds were
initially applied towards:
(i)
(ii)
(iii)
(iv)
(v)
$16.6 million plus accrued interest at 6.12%, for payment of all amounts outstanding under the Petroperu restructuring
agreement;
$2.9 million for repayment of the Peruvian Reactiva assistance program;
$20 million restricted for the acquisition of qualified hydrocarbon assets;
$15 million for the permitted hedging programs; and,
Remaining amount for the Bretana oil field development.
According to the agreement, if the Company has not acquired a new asset by February 2022, bondholders have the right to request
repayment of the $20 million or the remaining balance of the acquisition account. If the bondholders have not exercised their call option,
the Company has the right to repay (put option) the $20 million. If neither party exercises the option, the funds remain in the acquisition
account and remain available for hydrocarbon asset purchases. The $20 million is treated as restricted cash (see Note 4 and Note 24).
56 In accordance with the terms of the bond agreement, the bonds are secured by all assets of the Company, and the Company is required to
maintain the following financial ratios:
Covenant
Ratio
a)
b)
c)
Liquidity
Equity
Leverage
Description
Cash amount not less than interest payable for the next 12 months
Equity to Total Assets minimum rate of 40%
Net debt to EBITDA does not exceed the ratio of 3:1
The Company met all covenants as of December 31, 2021. No distributions to shareholders are permitted until the bonds are relinquished.
Fair Value
The long-term debt of $98.2 million was comparable to third-party fair value estimates for similar issues or current rates. The fair value of
the Company’s debt on December 31, 2021 (Note 9), was determined by reference to valuation inputs under Level 2 of the fair value
hierarchy.
13. 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., and Peru. 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 are as follows:
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 carryforward
related to Block 95 will expire in three years for a total of $276 million in losses. In Canada non-capital losses can be carried forward for
57 twenty years for a total of $42.9 million in losses, $1.9 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, 2021 was $1 million (December 31, 2020: $0.6 million) and is included in other receivables.
14. TRADE AND OTHER PAYABLES
As at December 31, 2021 and 2020, trade payables and accruals are primarily related to the drilling and completion of wells and
construction of production processing facilities.
15. DECOMMISSIONING OBLIGATIONS
The undiscounted uninflated value of its estimated decommissioning liabilities is $29.4 million. The present value of the obligations was
calculated using an average risk-free rate of 3.6% (December 31, 2020: 2.8%) to reflect the market assessment of the time value of money
as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the
cash flow estimate was 2.0%. The table above sets out the continuity of decommissioning obligations.
16. CURRENT AND NON-CURRENT LEASE LIABILITY
The Company commenced a seven-year service contract with a supplier, that provides turnkey power generation equipment services, in
Q1 2021. The Company has the option to buy the equipment on year five for $4.5 million. The incremental borrowing rate used to measure
the lease liabilities was 4.0% for the dollar denominated lease.
58 As of December 31, 2021, total lease liabilities have the following minimum undiscounted annual payments:
As of December 31, 2021, lease liabilities have the following minimum year payments under its office lease:
17. COMMITMENTS
As of December 31, 2021, 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
18. SHARE CAPITAL
Commitment
1st exploration well, minimum work 5th exploratory period
2nd exploration well, minimum work 5th exploratory period
Expiration
December 2023
December 2023
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 after satisfactory
payment of bonds.
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 Q1 2020, the Company received
$0.2 million from the exercise of warrants.
PERFORMANCE WARRANTS
The performance warrants have an exercise price of $0.187 per share and vest 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.
59 INVESTORS’ WARRANTS
In connection with the brokered private placement offering on June 18, 2020, investors received one common share and one half of one
warrant allowing the subscriber to purchase additional shares 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, 2021:
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 2021 units are exchangeable for 1.07 shares per unit (2020 Plan: 0.1).
The following assumptions were used for the Black-Scholes valuation of the PSUs granted:
For the year ended December 31, 2021, the Company recognized $2.5 million of share-based compensation expense in general and
administrative expense (December 31, 2020: $1 million).
The Company issued an aggregate of 2,962,539 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.
For the year ended December 31, 2021, the Company recognized $0.4 million of DSU expense in general and administrative expense and
contributed surplus (December 31, 2020: $0.2 million).
60 The following table details the PSU and DSU activity:
19. 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.
20. GENERAL AND ADMINISTRATIVE EXPENSES
The Company reduced salaries to employees due to the pandemic from May to November 2020, and continued supporting the oil field
community in Peru, providing infrastructure and medical supplies during 2021.
21. FINANCE EXPENSE
At December 31, 2021, the company completed a 3-year senior secured bond with a face value of $100 million issued at a 5% discount.
The bond bears interest at 12% and interest is due semi-annually. The Company also incurred financing costs which are amortized using
the effective interest method over the remaining term of the debt. In the prior year, the Company had a financial liability of $2.8 million
pertaining to a Peruvian backed loan received in Q2 2020. The loan had an interest rate of 1.12% and was payable over 36 months. The
loan was paid in February 2021.
61 22. 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.
23. CAPITAL STRUCTURE
The Company’s objective when managing capital is to ensure it has sufficient funds to maintain ongoing operations, to pursue the
acquisition of oil and gas properties, and to maintain a flexible capital structure that optimizes the cost of capital at an acceptable risk. The
Company manages its capital structure, which may include equity and debt, and adjusts it according to the funds available to support the
exploration and development of its interests in its existing oil and gas properties, and to pursue other opportunities as they arise.
The Company defines its capital as follows:
24. SUBSEQUENT EVENTS
On April 1, 2022, the Company elected to repay $20 million to bondholders pursuant to the call option set out in the bond agreement. In
addition, the Company paid $0.5 million of interest and prepayment fees. The remaining bond principal repayments are $25 million in
February 2023, $25 million in August 2023 and $30 million in February 2024.
62