Q2 2021 Results Analysts Meeting - 30 July 2021 - PTTEP
←
→
Page content transcription
If your browser does not render page correctly, please read the page content below
Q2 2021 Results
Analysts Meeting
30 July 2021
Disclaimer
Forward-looking Information
The information, statements, forecasts and projections contained herein reflect the Company’s current views with respect to future events and financial performance. These views are based
on assumptions subject to various risks. No assurance is given that these future events will occur, or that the Company’s assumptions are correct. Actual results may differ materially from
those projected.
Petroleum Reserves Information
In this presentation, the Company discloses petroleum reserves that are not included in the Securities Exchange and Commission of Thailand (SEC) Annual Registration Statement Form 56-
1 under “Supplemental Information on Petroleum Exploration and Production Activities”. The reserves data contained in this presentation reflects the Company’s best estimates of its
reserves. While the Company periodically obtains an independent audit of a portion of its proved reserves, no independent qualified reserves evaluator or auditor was involved in the
preparation of reserves data disclosed in this presentation. Unless stated otherwise, reserves are stated at the Company’s gross basis.
This presentation may contain the terms “proved reserves” and “probable reserves”. Unless stated otherwise, the Company adopts similar description as defined by the Society of Petroleum
Engineers.
Proved Reserves - Proved reserves are defined as those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be
commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations.
Probable Reserves - Probable reserves are defined as those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable.
2 Energy Partner of Choice
Q2/2021 Highlights
Khun Phongsthorn Thavisin
Chief Executive Officer
Energy Partner of Choice
Q2 2021 FINANCIAL PERFORMANCE FY 2021 OUTLOOK
Net Income Unit Cost Sales Volume Sales Volume
222 MMUSD 27.24 $/BOE 443 KBOED 412 KBOED
CHANGING ENERGY LANDSCAPE
- Energy Transition is reshaping the industry -
Climate change is Top Agenda Stakeholders demanding Shifting to low carbon energy Fossil Fuel demand will peak
lower carbon footprint
• Renewables growing at • Peak Oil: 2028–2040+
• GHG Reduction to sustain • New Policy & Incentives 10% CAGR from 2010- by speed of growth in EVs
E&P business for green investment 2040 • Peak Gas: 2037–2040+
Global • Gas is a transition fuel • Easy Access & Cheap • H2 Society becomes by growth in renewables
• Electrification is the future Funding from Investor aspiration for many
countries
• 2030 GHG reduction • Govt. plans to • Renewables growing at • Peak Oil: 2034
target 20% - Change fuel mix 2-3% CAGR (2019-2050) by clean energy & policy
• Net-zero emission year - Support goods from • H2 Symposium & H2 • Peak Gas: 2040+
Thailand being defined low-carbon processes Thailand Working Group by technology
• Climate Change Act - Encourage Carbon established among private development
being prepared Capture and Storage sectors Energy Partner of Choice
4 Source: Various Org. Consultant (IEA, McKinsey, WoodMac, BCG, Rystad, etc.) and PTT TTS#2 cloud scenario
PTTEP’s Position towards Energy Transition
Energy PTTEP’s Future Portfolio Mix
Last man Cautious Low-carbon transition
Strategy standing diversified adopter frontrunner NI from Non-EP Business 20%
(projected in certain year)
Minimal Commitment but Aggressive 100%
Emission Targets adhere to Net zero
not Net Zero target 2°C goal
regulations
Core Oil & Gas
Net Income
Business Focused Maintain Reduced Divested
+ Offset activities + Offset activities + Offset activities
New Year
Business Minimal Minor Increased Focused 2021 2025 2030
ARV, Tech. & Future Energy
• Growth Platform
Power Business
• Protection from Oil Price Fluctuation
Company E&P Business
Mapping
• Core and Foundation for Growth
* Average ROCE between 2020 – 2030
Source: McKinsey, Wood-Mackenzie 5 Energy Partner of Choice
PTTEP’s Directions and Long-Term Targets
Execute & Expand
Sustainable E&P Business Diversification to Resources
non-E&P Preparedness
• Production CAGR 5% in 2030, • GHG emission intensity • Net Income contribution 20% by • Resilient organization for
maintain @700 KBOED after 2030 reduced by 25% in 2030 2030 both E&P and non-E&P
• R/P > 5 years • PTTEP’s visibility as
• Unit Cost 25 $/BOE “Guardian of the Ocean”
Strategy: Strategy: Strategy: Strategy:
• Domestic gas sales to ensure gas ❑ GHG reduction initiatives e.g. ❑ ARV superior growth ❑ Efficient human resources and
supply continuity CCS in Thailand & Malaysia funding plan
❑ Power Business in Vietnam /
• Cost competitiveness of oil projects ❑ Ocean for life initiatives e.g. Myanmar ❑ Spin-off non-E&P businesses
in Thailand & Malaysia Ocean data platform, Rig to reef, ❑ In-house Tech Commercialization,
• Resources monetization of CSR around ocean CCU, Hydrogen
exploration and development assets
• “Go for Gas” growth in TMM & ME
• New LNG investment shift to
medium-long term
6 Energy Partner of Choice
Strategy Update
Khun Natruedee Khositaphai
EVP, Strategy & Business Development
Energy Partner of Choice
Strategy Focus
E&P Business Non-E&P Business
Growth in Core Area & Strategic Partnership Diversifying into Tech, Power and New Business
Technology
Oman and UAE Thailand
Business
• Monetize Discovered Coming • Ensure domestic gas
Resources Home supply continuity
• Accelerate • Accelerate resources
Exploration Campaign recovery from onshore
• Grow through assets
Strategic Partner Expand to • Find new growth
Middle East Power
opportunity from OCA
and bid round Business
Gas to Power Wind Solar
LNG to Power
Myanmar Malaysia Potential Business Opportunities
• Pursue growth in Western • Fully Explore and synergize
Corridor
• Unlock full potential of
existing assets
with existing facilities
• Focus on Lang Lebah (LLB)
Development
1CO2
Carbon Capture Utilization
CCU
Potential Products
e.g. Methanol, Carbon
Nanotube
2
Hydrogen New Biz
Opportunities
• Closely monitor political • Resources monetization from
situation exploration blocks • Low carbon Initiative by turning CO2 into • Studying alternative future
high-value products energy
• Support GHG reduction target
8 Energy Partner of Choice
Sustainability Development
Khun Natruedee Khositaphai
EVP, Strategy & Business Development
Energy Partner of Choice
SD Roadmap - GHG and Ocean for Life
GHG Reduction Roadmap for 2030 Target Ocean for Life
25% GHG Intensity Reduction (base year 2012) Guardian of the Ocean (via Ocean Data Platform)
16% 25%
GHG Reduction 2021 2030
Major Activities
Renewable in Renewable Use WHP Equipped with
at New WHP in S1 Solar Renewable in
Operation Domestic Domestic Clean and Friendly Operation
Efficiency Energy Wave Craft LNG Powered Offshore + Mid-Shore:
Improvement Optimization Production Fleet Ocean Health and Advanced Technology &
Biodiversity Monitoring Innovation
Flare Utilization Feasibility of FGRU Onshore +
Additional Installation in Zero Routine Flare Offshore:
Domestic Ramp up CSR around Ocean Nearshore:
FGRU Assets Collaboration Location Advantage
Network & CSR
Carbon Capture and Feasibility CCS Initiative in TH CO2
Storage (CCS) Study on CCS and MY Assets CCS
10 Energy Partner of ChoiceSD Progress & Highlights
2030 Targets
“Energy Partner of Choice”
through Competitive Performance and GHG Reduction Circular Model for E&P Ocean for Life
Innovation for Long-term Value Creation
25% ≥50% of main structures reuse
Net Positive Impact
of Biodiversity & Ecosystem Services
in Offshore Operations
Reduction of (2019 base year)
Zero
GHG emissions intensity
(2012 base year)
waste to landfill ≥50%
Increase in Community Income for
local community that participated
in our program
(before project implementation)
Q2/2021 Key Performance
Accumulative GHG Emissions Reduction Oil and Chemical Spill Rate
(Unit: Absolute (tonne CO2 equivalent) (Unit: Tonne per million tonne of petroleum production)
16% Reduction of GHG Emission Intensity as of June 2021 Towards Zero Spills Aspiration
(compared to 2012 base year) 8.9
8.0 8.3
1,982,215 2,149,958 6.6
6.0
1,410,502
4.3
833,010 3.3 IOGP
2.2 2.5 2.3 Benchmark
188,417 1.6 0.5 0.4 0.43 0.1 0.9 0.0 0.3 0.6 0.6 0.1 0.0
2010 2011 2012 2013 2014 2015 2016Energy
2017 2018 2019 2020
Partner 2021
of Choice
2013 2016 2018 2020 2021 11 (Q2)SD Progress & Highlights (Cont.)
GHG Reduction Circular Model for E&P Ocean for Life
Zero Waste to Landfill Marine Spatial Planning
Achieved zero hazardous waste to landfill and step up to On-going multi-spectrum drone survey (first time in SEA)
zero industrial waste to landfill by 2025 for aerial mapping of coral reef monitoring with KU at Koh
Mannai and Pala Beach, Rayong
Topside Reuse Project
On-going 1st Topside re-location at Arthit operation (started in
July 2021)
Ramp Up CSR around Ocean
• 6 Aquatic Animal Hatchery Learning Centers are planned
Flare Gas Recovery Upcycling High Volume Waste for construction by 2021
Completed GBN Flare Gas Recovery Unit feasibility study Sand to Zeolite: Completed prototype equipment setup in • 17,248.50 Kg of wastes
May 2021 and now preparing for production collected @ Songkhla
for proper disposal
CCUS Study
CCU: Carbon nanotube from flare gas:
100,000 scfd facility is under
engineering design for pilot project
CCS: Completed feasibility study
and on-going pre-FEED in GoT
12 Energy Partner of Choice
12Industry Outlook
Khun Natruedee Khositaphai
EVP, Strategy & Business Development
Energy Partner of ChoiceOil and LNG Market Update
Global Oil Market LNG Market
Prices Outlook LNG Spot Price Outlook
100 Dubai Brent Min-Max Consensus Quarterly Yearly
2020 actual 12 Strong demand from global
economic recovery and
80 Brent 41.84 US$/BBL WM: Global supply growth
Dubai 42.27 US$/BBL Analyst Consensus supply shortage from US slowdown while Asian
Spread -0.44 10 and Australia demand continues to Woodmac (Jul’21)
60 US$/BBL increase
US$/BBL
US$/MMBTU
40 8
2019 actual
20 Brent 64.0 US$/BBL 6 Supply issues Supply over demand FGE (May’21)
Dubai 63.0 US$/BBL 2021 consensus 2022 consensus recover Platts (May’21)
Spread 1.0 US$/BBL FY Brent 70.0 US$/BBL FY Brent 67.0 US$/BBL Global supply availability
0 outstripping demand
4
Q1'21 Q2'21 Q3'21 Q4'21 Q1'22 Q2'22 Q3'22 Q4'22 2023 2024 2025 2026 2027
Source: Refinitiv (Reuters), Monthly Poll on Oil Price as of Jun’21 Source: Information as of Jul 2021.
Demand & Supply Outlook Global LNG Demand & Supply Outlook
110 World Consumption World Production 450 LNG Demand LNG Supply
Million Barrels per Day
100 350
MTPA
90 250
80 150
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2021 2022
2019 2020 2021 2022
Source: EIA, Short-Term Energy Outlook as of Jul’21 Source: Wood Mackenzie, Short-Term LNG Demand & Supply Tracker as of Q2’21
Key Global COVID-19 Economic OPEC+ US Sanction LNG Market
factors Situation & Vaccine Recovery & Production Cuts Policy on Still Oversupply
to Monitor Distribution Stimulus Measures Agreement Iran & Venezuela 14 LNG
Energy Partner of ChoiceOperations Update
Khun Montri Rawanchaikul
President
Energy Partner of ChoiceCore E&P Business Update
Assets
Assets Transition Transition in Thailand
in Thailand Stronger foothold in Malaysia
SK410B Project SK438 Project
G1/61 • Under field development study reflecting • Evaluating petroleum potential at Mak
(Erawan) Delayed Starting producing Remediation Plan larger gas discovery volume and CO2 Yong-1, after gas discovery at Kulintang-1
st
Site Access below PSC volume (accelerate ramp-up and management as per GHG aspiration target (1 exploration well) in April 2021
uplift other fields)
• FID target on track PM407 Project
On track towards 1st gas in 2022 • Several petroleum prospects under study • Conducting 3D Seismic Reprocessing
with additional drilling planned in 2022 and preparing for exploration drilling
G2/61 campaign in 2022-2023
(Bongkot) WHP Construction Awarded GSA Finalized
and Installation drilling rig Potential Development Cluster in Sarawak, Malaysia
(complete in Nov) (ready to drill in Nov) Thailand
South Sarawak Cluster North Sarawak Cluster
SK309-311, SK314A, SK438, SK405B SK410B & SK417
Production boost in Oman New volume in Algeria
Arthit Block H
PFLNG2
Bongkot
Oman Block 61 Algeria HBR JDA
• Ramp up production to full • Construction and commissioning PM415 Block K
capacity from 27 June 2021 on progress
Sabah
SK410B SK417
Peninsular PM407
• Gas: 1,500 MMSCFD • 1st oil production expected in SK438
SK405B
SK314A
MLNG
Condensate: 69,000 BBL/D 2H/2021 with capacity 10-13KBPD Legend
Producing
SK309/311 complex
Sarawak
Explorations
Petroleum Discoveries
16 Energy Partner of ChoiceNew Business Update - ARV
HEALTHTECH
End-to-end AI-augmented Subsea One-stop Service for Smart Farming Cloud-based Asset Inspection and Mgmt. Thailand’s largest lifetime digital health
Inspection Repair and Maintenance (IRM) and Smart Forestry Solutions Platform via Drones & AI/ML services ecosystem for illness and good-health.
ROV
Inspection & repair IoT
Temp
Monitoring
Xplorer AUV
AiAng Sprayer Drone
Surveillance & inspection
Products AIM Platform
and
Services Nautilus
Repair & Maintenance ARVIC
by ARV
Software & Data
Analytics & Insights
VARUN Platform Drone Inspection Health Ecosystem Platform
• Delivered ROV support for pipeline • 1,120 sq.km Varuna analytics • AeroSky JV established • Delivered 2,000 units of IoT cold-chain
replacement to Mubadala performed in POC stage • MOU signed for power sector device for Covid-19 vaccine
• Awarded for Zawtika pipeline survey • 31 AiAang sprayer drone confirmed • Delivered POC for Telecom and • Ongoing development of COVID-19 risk
Business orders in Q2 (to be delivered in Q3) Construction sectors evaluator software (Thaisavefamily
• Awarded for ME ROV support project
Highlights platform) for Department of Health
• Ongoing discussion with 3 additional • Ongoing inspection services performed
• 5 sales opportunities in pipeline
AiAang distributors 2,000 km of PTT Pipeline • Ongoing health ecosystem platform
• Awarded for HMC long-term service development (ARVIC) with potential
• Awarded for 48 sq.km spraying service
1.5m users on board
• 14 sales opportunities in pipeline • 12 sales opportunities in pipeline
• Ongoing POC development of wellness
platform with BJC
Energy Partner of Choice
Note: ME = Middle East market (via Mermaid Subsea Services), ROV = Remotely Operated Underwater Vehicle, AUV = Autonomous Underwater Vehicle, POC = Proof of Concept, AIM = Asset Inspection ManagementFinancial Results
Khun Sumrid Sumneing
EVP, Finance & Accounting
Energy Partner of ChoiceResults - Net Income
Impressive recurring net income curbed by oil price hedging loss
Q2/21 on Q1/21 (QoQ) 6M2021 on 6M2020 (YTD)
Unit: million USD 376 Unit: million USD 598
222 450
94
250
409 450
282 349 631
418 250
50
50
Q1/21 Q2/21 -9 6M2020
-127 -150 6M2021 -33 -150
Recurring NI Non recurring NI Net Income Recurring NI Non recurring NI Net Income
Recurring (+67 MMUSD or +24%) Recurring (+213 MMUSD or +51%)
+16% +4% +20% +3%
Mainly from Oman Block 61 Average Higher liquid price Increase from Gulf of Thailand, Average Higher liquid price
Sales Volume and Sabah H Selling Price Sales Volume Sabah H, and Oman Block 61 Selling Price offset with
lower gas price
-3% -10%
Lower unit costs Lower unit costs
Non-recurring (-221 MMUSD or ->100%) Non-recurring (-24 MMUSD or ->100%)
Higher oil price hedging loss in Q2, and realization of gain from bargain Higher oil price hedging loss offset with a gain from bargain
purchase offset with exploration asset write-off in Q1 purchase in 2021
19 Energy Partner of ChoiceResults – Sales Volume and Average Selling Price
Solid volume addition from Oman Block 61 and Malaysia Sabah-H
UNIT: BOED 443,126 413,168
382,877 68,068
400,000 354,052 45,867 Volume Mix
23,420 327,004 345,207
19,323 20,443 Rest of World
85,215 102,239 24,790 93,774 Gas Liquid
300,000 85,248 82,692 Other SEA
80,401
29% 28%
200,000
Thailand &
249,481 274,242 272,819 273,527 242,072 MTJDA 72%
221,813 71%
100,000
0 Q1 2021 Q2 2021
Product Price 2020 Q1 21 Q2 21 Q2 20 6M 2021 6M 2020 Revenue Mix
Gas ($/MMBTU) 6.27 5.61 5.59 6.37 5.60 6.64
Liquid ($/BBL) 41.55 56.59 63.98 28.92 60.52 40.80
41% 43%
Weighted Avg. ($/BOE) 38.92 40.38 42.19 34.97 41.35 40.15
Avg. Dubai ($/BBL) 42.27 60.21 67.02 30.72 63.62 40.72 59% 57%
Avg. HSFO ($/BBL) 39.30 56.74 61.21 29.18 58.98 36.26
(High Sulphur Fuel Oil)
Q1 2021 Q2 2021
Note: Include sales volume from ADNOC Gas Processing (AGP)
Exclude Oman Block 61 deemed sales volume from tax payment by government
20 Energy Partner of ChoiceResults – Unit Cost
Consistent decline in unit cost to meet long-term aspiration cost target
Unit : $/BOE
40
30.50 30.25 30.62
30 27.96 27.24 27.57
Cash Cost
Unit Cost 20
14.40 11.62 13.88 11.84 14.33
12.10
10
-
2020 Q1 21 Q2 21 Q2 20 6M 2021 6M 2020
DD&A 16.10 15.86 15.62 16.37 15.73 16.29
Finance Cost 1.96 1.39 1.27 2.04 1.33 2.00
Royalties 3.17 3.41 3.42 2.63 3.42 3.20
G&A 2.33 2.12 1.97 2.02 2.03 1.98
Exploration Expenses 0.80 0.12 * 0.19 1.03 0.16 1.10
Operating Expenses 6.14 5.06 4.77 6.16 4.90 6.05
Lifting Cost 4.47 4.15 3.91 4.59 4.02 4.42
Note: * Exclude Exploration assets write-off in Brazil for Q1 21
All Unit Cost shown above exclude costs related to new business
The formulas for calculating ratios are provided in the supplementary section for your reference
21 Energy Partner of Choice
5Results – Cash flows and Financial Position
Robust operating cash flow with higher EBITDA margin
6M 2021 : Source and Use of Funds* Financial Position
75%
EBITDA Margin 2,098 4,052
Unit: million USD Unit: million USD
Others 22,493 23,230 Total Assets
278
Free
Cash flow from 730 CAPEX
operations 2,098
Cash flow
6,762 7,078 Other Liabilities
(Before tax payment) 410
680 Tax payment
Asset acquisition
(Oman Block 61)
3,932 4,131 Interest-bearing Debt
2,364
3,804
12,021
Equity
11,799
1,850
2020 Sources Uses Jun-21 2020 JUN-21
Note: * Include Short-term investment
Net of adjustment for the effect of exchange rate changes on cash and cash equivalents
Debt Profile
D/E ratio 0.33x 0.34x Weighted Average 14.08 12.86
Loan Life (Years)
Weighted Average 3.44 3.31 Fixed : Floating 82:18 78:22
Cost of Debt (%)
Note: Debt profile excludes Hybrid bonds
22 Energy Partner of ChoiceShareholders’ Return - Interim Dividend
Glimpse to 2021
Schedule for 1H2021 Dividend Payment THB per share
Guidance 2020 Credit Rating/Outlook
6.00
6.00
5.00
XD 4.25 4.25
Date
11 August 2021 4.00 3.75
3.25
3.25
2.75 2.75
2.00
2.00 2.50
Record 2.25 2.00
date
13 August 2021 0.75
1.50 1.75 1.50
0.00
2016 2017 2018 2019 2020 1H2021
1H 2H
Payout Ratio 98 88 55 49 77 40
Payment
Date
27 August 2021 (% of net income)
Payout Ratio 79 63 51 53 71 38
(% of recurring
net income)
23 Energy Partner of ChoiceFinancial Outlook
Glimpse to 2021
2021 Guidance
Guidance
Average Sales Volume* Average 2020**
Gas Price Unit Cost EBITDA Margin
KBOED USD/MMBTU USD/BOE % of Sales Revenue
Q3
~405 Q3 & Full year Q3 & Full year Q3 & Full year Note:
* Include sales volume from
~5.7
ADNOC Gas Processing (AGP)
Full year
~28-29 ~70-75% ** Based on average Dubai oil
~412
price in 2021 at 67.6 $/BBL
Credit Rating/Outlook
International National
BBB+ / Stable BBB+ / Stable Baa1 / Stable AAA / Stable
BBB stand-alone rating BBB stand-alone rating Baa2 stand-alone rating
24 Energy Partner of ChoiceThank you and Q&A
You can reach the Investor Relations
+66 2 537 4000 team for more information and inquiry
through the following channels
Please scan here to
take the survey
http://www.pttep.com
IR@pttep.com 25 Energy Partner of ChoiceSupplementary information
Financial Results Q2/2021 27-29
Industry and Thailand Energy Updates 30-32
Reserves at Year-end 2020 33
Key Project Highlights by Region 34-39
Project Details 40-44
Organization Structure 45
Ratio and Formula 46
Energy Partner of ChoiceResults – Net Income
Unit: million USD
Statements of Income Q2 21 Q1 21 %QoQ Q2 20 %YoY 6M21 6M20 %YTD
Total Revenues 1,768 1,779 (1%) 1,095 61% 3,546 2,779 28%
Sales (1) 1,729 1,391 24% 1,041 66% 3,120 2,523 24%
Sales Volume (BOED) (2) 443,126 382,877 16% 327,004 36% 413,168 345,207 20%
Sales Price (US$/BOE) 42.19 40.38 4% 34.97 21% 41.35 40.15 3%
Gain from a bargain purchase - 350 (100%) - - 350 - 100%
Others (3) 39 38 3% 54 (28%) 76 256 (70%)
Total Expenses 1,548 1,405 10% 959 61% 2,953 2,382 24%
Major Expenses:
Operating Expenses 193 174 11% 183 5% 367 380 (3%)
Exploration Expenses 7 149 (95%) 30 (77%) 156 69 >100%
G&A 83 75 11% 62 34% 158 128 23%
DD&A 629 547 15% 488 29% 1,176 1,024 15%
Loss on Financial Instruments 125 98 28% 78 60% 223 - 100%
Impairment Loss on Assets - - - 47 (100%) - 47 (100%)
Income Tax Expenses 321 192 67% (68) >100% 513 384 34%
Share of profit (loss) from associates and JV 2 2 - (2) >100% 5 12 (58%)
Net income 222 376 (41%) 134 66% 598 409 46%
Recurring Net Income 349 282 24% 128 >100% 631 418 51%
Non-recurring Net Income (127) 94 (>100%) 6 (>100%) (33) (9) (>100%)
Non-recurring Net income breakdown:
Oil Price Hedging (141) (107) (32%) (26) (>100%) (248) 140 (>100%)
Tax from Effect of FX - (9) 100% 122 (100%) (9) (103) 91%
Effect from FX and others 14 5 >100% (43) >100% 19 1 >100%
Impairment Loss on Assets - - - (47) >100% - (47) 100%
Exploration assets write-off - (145) 100% - - (145) - (100%)
Gain from a bargain purchase - 350 (100%) - - 350 - 100%
Note:
(1) Include Oman Block 61 deemed sales revenues from tax payment by government (28 MMUSD for Q2 21 and 6M21)
(2) Exclude Oman Block 61 deemed sales volume from tax payment by government 27 Energy Partner of Choice
(3) Consisted of Revenue from Pipeline, Gain from FX, Forward Contract, and Oil price HedgingFive –Year Plan : Sales Volume Figures have not yet reflected Oman block 61
Maximize value of existing assets, accelerate G1/G2 transitions & maintain key milestones for key projects
In KBOED CAGR +6%
500 436 446 466 462
375 Rest of World
400 354
300 Other SEA
Sales Volume
200 Thailand &
100 MTJDA
0
In MMUSD
2020 2021 2022 2023 2024 2025
6,000 5,617 4,779 4,934
4,196 686 73
34 4,111 OPEX
63 62 (Decommissioning)
4,000 2,900 1,896 1,771 1,778
OPEX
Investment 30 1,545 1,710 (exclude decommissioning)
554 768 819
2,000 1,480 493 481 CAPEX
(Dev & Pre-sanction projects (3))
233 2,095 2,481 2,206 2,264 1,858 CAPEX
1,157 (Producing projects (4))
0
5 Years (2021 – 2025) 2020 2021 2022 2023 2024 2025
CAPEX 14,020
OPEX 9,617 Algeria HBR
Block H: 1H G1/61: April (2) G2/61: March (2) Mozambique LNG: 1H (Full phase): 2H SK410B (1)
TOTAL 23,637 Capacity 270 MMSCFD Capacity 800 MMSCFD Capacity 700 MMSCFD Capacity 13 MTPA
Key Project Start-up Southwest Vietnam: 2H (1)
Capacity 50-60 KBPD Initial Capacity 600-800 MMSCFD
Algeria HBR (phase l): 2H G2/61: April (2) Capacity 490 MMSCFD
Capacity 10-13 KBPD Capacity 200 MMSCFD
Note: (3)(1) Subject to regulatory approval and FID timing (2) According to Production Sharing Contracts signed on 25 February(4) 2019 28 Energy Partner of Choice
Development & Pre-sanction projects include Mozambique LNG , Algeria HBR, SK410B, and Southwest Vietnam Includes exploration and appraisal in all projects and head office CAPEXDebt Maturity Profile
As of June 2021
700
650
600
600
500
500 480 490
USD Millions
400
349 350
300
200
200
100
-
Note: Excludes Hybrid bonds
Unit: USD Millions or equivalent after cross currency swap
29 Energy Partner of ChoiceThailand Updates
Higher gas volume with recovering demand constraint; THB fluctuation continues
Thailand Energy Overview Exchange Rate Movement
(THB/USD)
Natural Gas Supply
34
MMSCFD
FY 2019 FY 2020 5M 2021
33 32.7 33.0
Domestic Myanmar LNG 5,023 (Highest)
o Recovering energy demand, which 31.7 31.3
32.1
31.5
32
rebounded to the same level of pre COVID-19 (Average)
Domestic Myanmar LNG 4,699 31
o As of April 2021: Higher domestic supply, 30.9
30.7
(Lowest)
while LNG imports decreased slightly and 30
Domestic Myanmar LNG 5,017 30.2
a decline from Myanmar piped gas imports 29
30.0
0 1,000 2,000 3,000 4,000 5,000
due to natural decline 28
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Natural Gas Consumption Electricity Generation 2020 2021
MMSCFD GWH Consensus on the exchange rate mostly depends on
FY 2019 FY 2020 5M 2021
FY2019 FY2020 5M 2021
Electricity Industry GSP NGV 4,625 57% 2% 16% 14% 11% 87,190 o Efficacy of Covid-19 containment measures in Thailand and vaccine
procurement and distribution timeline
Electricity Industry GSP NGV 4,368 55% 2% 18% 14% 10% 205,995 o Thailand’s economic recovery which heavily depends on tourism recovery
o Sustained fiscal and monetary policy support in Thailand and Federal
Electricity Industry GSP NGV 4,762 57% 3% 17% 12% 10% 212,050 Reserve tapering timeline
0 1,000 2,000 3,000 4,000 5,000 0%
Source: Bank of Thailand, Bloomberg
Natural 20%
Gas 40%
Hydro60%
Electricity80% Coal
100%
& Lignite
Source: Energy Policy and Planning Office (EPPO) Forecast based on Bloomberg Consensus as of 12 July 2021
Imported Renewable Energy
30 Energy Partner of ChoiceThailand’s Energy Value Chain
PTTEP contributes over 1/3 of Thailand’s petroleum production
5M 2021 Thailand’s Oil and Gas Demand 6M 2021 Thailand Petroleum Production Midstream
Crude Oil &
% by Petroleum Type and Area Gas: operated by PTT
Condensate ~ 1.0m BOE/D Onshore 8%
8% Transmission Pipelines
Imports Gas Gas Separation Plants
74% Offshore
~ 83% 92%
Liquid Oil: PTT participates through
Domestic ~ 17% 26% subsidiaries
by Type by Area
Refineries
% Production by Company
Natural Gas ~ 0.9m BOE/D
Imports ~ 30%
PTTEP Downstream
Domestic 38%
Petrochemicals
~ 70% Others
62% Oil and gas marketing
Source: Energy Policy and Planning Office (EPPO) and Department of Mineral Fuels (DMF)
31 Energy Partner of ChoiceThailand’s Oil and Gas Balance
Oil Balance*** Natural Gas Balance****
Maintains stability supply through adequate refining capacity Main driver of the Thailand economy
Import (83%) Indigenous (17%) Gulf of Thailand (66%) Onshore(3%)
Onshore (2%) Import (31%)
917 KBD 189 KBD
SUPPLY
PTTEP
40% Myanmar
Others LNG 49%
60% 51%
Crude/ Crude/ 3.043 Bypass Gas 482 MMSCFD
Condensate Condensate MMSCFD
891 KBD 169 KBD
Total Refining Capacity in Thailand 6 Gas Separation Plants
PRODUCTION
1,242 KBD Total Capacity 2,870 MMSCFD
Imported @ Actual Heat
Refined Crude 113 1,426
Petroleum Export MMSCFD MMSCFD
Products 20 KBD
26 KBD PTT’s Associated Refineries 770 KBD (TOP, PTTGC, IRPC)
Other Refineries 472 KBD (SPRC, ESSO, BCP) Methane
1,603 MMSCFD
Refined Refined 958 MMSCFD
Products Products (21%)
992 KBD * 183 KBD
Domestic Export Petrochemical Ethane
Propane
Power (60%)
840 KBD ** 203 KBD Feedstock LPG
(13%) NGL
SALES
Industry (16%)
Industry
Household LPG NGV (3%)
Transportation NGL
(8%)
Source: PTT
Note: * Refined product from refineries = 919 KBD, including domestic supply of LPG from GSPs and Petrochemical Plants = 92 KBD
** Not included Inventory
*** Information as of 3M21
**** Information as of 3M21 32 Energy Partner of Choice
MMSCFD @ Heating Value 1,000 Btu/ft3Reserves at the Year-end 2020 (not including Oman Block 61)
Sustained reserve life at over 5 years target
MMBOE Reserves
Life* 2020 by Geography
1,800 1,647 1,622 Domestic International
10 Years
1,622
507 548 1,074 47%
1,200 1,028 7 Years 50%
53%
351 50%
600 1,140 P1 P1 + P2
1,074
677 2020 by Product Type
Gas Liquid
0
2018 2019 2020 1,622
Proved (P1) Probable (P2) 1,074 31%
27%
5-Year Average Proved Reserves Replacement Ratio (RRR) 69%
2018 2019 2020 73%
0.7x 1.5X 1.5X
P1 P1 + P2
• Based on total production of natural gas, condensate, and crude oil (including LPG) of 422 KBOED for the year ended December 31, 2020
• Figures include reserves from equity method
33 Energy Partner of ChoiceDiversified international portfolio
Central Asia Thailand
First presence in Kazakhstan: PTTEP’s primary operational base
• Production: Dunga onshore oil field Oil sands • 66% of total sales volume
from the acquisition of Partex in 2019 • Key producing assets include Bongkot,
Oil Arthit, Contract 4 and S1
• Transition of operations for G1/61 (Erawan)
and G2/61 (Bongkot) are in process to ensure
production continuity under new PSCs
North & South America Oil
Opportunities in an early phase: Southeast Asia
• Deepwater exploration in Brazil and Mexico Piped Gas
with prominent and prudent operators Second heartland to PTTEP
Oil Gas/LNG
• 23% of total sales volume, mainly from
Oil Malaysia and Myanmar
Oil GAS/LNG
• Recent multiple petroleum discoveries in
Malaysia formed fundamental for cluster
development potential
Book Value of Assets by region • Other producing assets in Vietnam (oil)
Total assets USD 23.23 billion and Indonesia (gas)
Others
3%
Middle East
16% Thailand Africa Middle East
Africa 38%
17% An area for growth, key projects include: Strong presence in UAE and Oman: Australia
Southeast Asia
• Production: Algeria’s Bir Seba oil field with • 3 offshore exploration blocks in UAE,
26% current flow rate of approximately 17 KBPD partnered with experienced operator Potential gas development
• Development : Algeria’s Hassi Bir Rakaiz • 4 onshore blocks in Oman including PDO • Sizable undeveloped gas resources in
with target 1st phase production in 2021 (Block 6), largest producing oil asset, and Timor Sea
As of Jun 2021 (including Oman Block 61) and Mozambique Area 1 with target first Block 61, largest tight gas development
cargo in 2024 • Stake in OLNG
34 Energy Partner of Choice
Information as of 30 June 2021Thailand, Myanmar and Malaysia
“Coming Home” strategy to maintain strong foundation and utilize expertise
Myanmar Malaysia
• 3 producing gas fields supplying gas to both Thailand Production
and Myanmar: Yadana, Yetagun and Zawtika Block K Project :
• Operate Zawtika project, brought online in March 2014 Kikeh(56% WI) , Siakap North-Petai (SNP) (22.4% WI) and
with current gas supply of 340 MMSCFD in 6M2021 Gumusut-Kakap (GK) (6.4% WI)
• Average production volume in 6M2021 was 25* KBPD
Project Status of crude oil and 25* MMSCFD of natural gas
• Zawtika (80% WI)
Production • Yadana (25.5% WI) SK309 and SK311 Project : (59.5% WI)
• Yetagun* (19.3% WI) For East Patricia field (42% WI)
Appraisal • M3 (80% WI) • Average production volume in 6M2021 was 173* MMSCFD
of natural gas and 17* KBPD of condensates and crude
Block H Project :
Rotan field (56% WI) Remaining Area (42% WI)
• First gas delivered in early February 2021 with average
Thailand production volume in 6M2021 at 142 MMSCFD of natural gas
• Full capacity at 270 MMSCFD
Production / Ramp-up Projects For Block K, gross production is net off utilization
Bongkot (66.6667% WI) Sabah H
Average natural gas and condensate sales volume of 919 Exploration
MMSCFD and 22 KBPD in 6M2021 Sarawak SK410B Project (42.5% WI)
S1 (100% WI) • Multi TCF significant discovery
The largest onshore crude oil production field in Thailand • Expected Final Investment Decision (FID) announcement by
end of 2022/beginning of 2023
with 6M2021 average crude oil sales volume of 28 KBPD Sarawak SK417 and Sarawak SK405B projects
Arthit (80% WI) SK309 & SK311 • New Petroleum discoveries with additional well drilling to
Average sales volume in 6M2021 was 243 MMSCFD of assess upside potential
natural gas and 12 KBPD of condensates Production phase
Contract 4 (60% WI) Exploration phase
Average sales rate of 395 MMSCFD for natural gas and Note: WI – working interest
16 KBPD for condensate in 6M2021
35 Energy Partner of ChoiceOther South East Asia countries
Expanding foothold in the region Vietnam
VIETNAM
Vietnam 16-1 (28.5% WI) Southwest Vietnam
• Average sales volume of crude oil was ● Vietnam B & 48/95 (8.5% WI)
12 KBPD in 6M2021 ● Vietnam 52/97 (7% WI)
• The project is preparing the drilling of • Field Development Plan was approved by Government
INDONESIA
additional development wells in order to • The project is currently in the negotiation process on
maintain the production level in 2021. commercial terms to put forward FID
• First production target by end of 2024, and ramp up to
full capacity of 490 MMSCFD
Indonesia
Natuna Sea A (11.5% WI)
• Average sales volume of natural gas
was 214 MMSCFD in 6M2021
Production projects
• The project is preparing the drilling of
Pre sanction projects
additional development wells in 2021.
36 Energy Partner of ChoiceThe Middle East
Building strategic presence and gaining access to Upstream oil & gas asset as well as Midstream Complex
UAE Oman
Mukhaizna (Block 53)
Abu Dhabi Offshore 1,2 and 3 PDO (Block 6) • Largest single onshore
producing field in Oman
• High potential prospective resources with significant sizeable • Largest asset covering around • Average oil production volume of
discoveries 1/3 of the country 96 KBPD in Q22021
• Located North-west of Abu Dhabi Emirates, United Arab Emirates Abu Dhabi offshore 3
• Long-life asset, produced only • Operated by Occidental
15% of reserves in-place Petroleum (47% interest)
• Granted the award for exploration in January 2019 - 2020
• Operated by Eni Abu Dhabi B.V. (70% interest) • Average oil production volume
of 627 KBPD in Q22021
• Operated by Petroleum Oman Block 61
ADNOC Gas Processing (AGP) Development of Oman
Block 61 (Joint Operating Company) • Largest tight gas development in
• One of the largest gas processing complexes in the world Middle East
(total capacity of 8 BCFD) • Gas and condensate production
JV: 3 plants with capacity of 1.2 BCFD Oman Onshore capacity of 1,500 MMSCFD and
block 12 Oman Onshore Block 12 69,000 BPD respectively
Adnoc: 2 plants with capacity of 6.9 BCFD
• Located onshore central part of • Operated by BP Exploration
• Essential to Abu Dhabi and UAE’s economy the Sultanate of Oman (Epsilon) Limited (40% interest)
• Sizeable volumes of Propane, Butane and Naphtha offtake *Block awarded in 2019 • Signed agreement with Oman’s
**Block awarded in 2020 Ministry of Oil and Gas (MOG) for Oman LNG
• Operated by ADNOC (68% interest) exploration and production rights
in February 2020 • The only LNG facility in Oman
• Operated by Total E&P Oman • Processing capacity 10.4 MTPA
Block 12 B.V. (80% interest) • Contracted LNG sales to
international buyers: Japan
and South Korea
Production phase • Government of Oman 51%
Exploration phase
(Operator)
Midstream
37 Energy Partner of ChoiceMozambique Area 1
On the path of unlocking value from world class LNG asset
Mozambique
Substantial recoverable resources of approximately 75 tcf
with scalable offshore development expending up to 50 MTPA
Location and Cost Advantage
MOZAMBIQUE • Close proximity to shore
• High quality reservoirs
capable of flow up to 200 mmcfd per well
• Access to Asian and European markets
Achievements FID Next milestones 1st Cargo expected 2024
Legal & Contractual Framework Project Finance (2/3 Project Financed)
Plan of Development Approved FID in June 2019 with initial 2 trains of
13.1 MTPA capacity Drilling & Completion
Onshore & Offshore Contractors Onshore Construction and
Awarded Offshore Installation
First Mover for the Marine Facility Operation Readiness
LNG SPAs ~11.1 MTPA LNG Shipping
38 Energy Partner of ChoiceAmerica: Mexico and Brazil
Entry into high potential petroleum province at exploration stage
Mexico Brazil
Deep-water with high petroleum potentials Deep Water
and attractive fiscal regime
Mexico block 12 (2.4) Barreirinhas AP1
• Non-operating partner with 20% participating interest • Farm-in 25% from BG Group in 2014
• Located in the Mexican Ridges, western Gulf of Mexico • Operated by Shell Brasil (65% interest)
•
Mexico block 12 (2.4) &
Currently evaluating petroleum potential and preparing for Mexico block 12 (2.4)
• Four offshore exploration blocks: BAR-M-215, BAR-M-217, BAR-M-252
MEXICO
an exploration well drilling in 2021 and BAR-M-254
Mexico block 29 (2.4) Barreirinhas • Currently waiting for exploration wells drilling permit from the
Basin
government
• Non-operating partner with 16.67% participating interest
• Located in the Campeche, southern Gulf of Mexico BRAZIL
BM-ES-23
Espirito Santo
• Made two successful deep-water oil discoverieswith good quality Basin
• Acquired 20% interest from Shell in Q3 2014
reservoirs in May 2020 • Partnered with Petrobras (65%, operator) and INPEX (15%)
• The appraisal plan and exploration plan were approved by • Currently evaluating the petroleum potential for further
the Mexican regulators (CNH) on 25 March 2021. development
• Preparing for exploration well and appraisal drilling.
Exploration phase
39 Energy Partner of ChoiceProject information 1/5
PTTEP’s Partners 6M2021 Average Sales Volume **
Project Status* Phase 2021 Key Activities
Share (as of April 2021) Gas (MMSCFD) Liquid (KBPD)
Thailand and JDA
Chevron 16% • Ensure gas deliverability level at DCQ***
1 Arthit OP Production 80% 243 12
MOECO 4% • Drill development wells
2 B6/27 OP Production 100% - - • Prepare for decommissioning activities
Chevron 51.66%
MOECO 16.71% • Ensure deliverability of production volumes as nominated from the buyer
3 B8/32 & 9A JV Production 25.001% 48 15
KrisEnergy 4.63% • Drill development wells
Palang Sophon 2%
• Drill development wells
• Maintain production level as planned
4 Bongkot OP Production 66.6667% TOTAL 33.3333% 919 22
• Carry out wells plug and abandonment, and prepare for non-transferred wellhead
platforms decommissioning
Contract 3 (Formerly JV Chevron 71.25%
5 Production 5% 501 27 • Prepare for decommissioning activities
Unocal III) MOECO 23.75%
• Ensure gas deliverability level at DCQ***
Contract 4 (Formerly JV Chevron 35%
6 Production 60% 395 16 • Drill development wells
Pailin) MOECO 5%
• Topside reuse
7 E5 JV Production 20% ExxonMobil 80% 8 - • Ensure gas deliverability level at DCQ***
Chevron 51%
JV • Deliver production volumes as nominated from the buyer and oil production as
8 G4/43 Production 21.375% MOECO 21.25% 1 3
planned
Palang Sophon 6.375%
JV Chevron 71.25%
9 G4/48 Production 5% 2 0.2 • Prepare for decommissioning activities
MOECO 23.75%
• Maintain production plateau
10 L53/43 & L54/43 OP Production 100% - - 1 • Explore for additional field potential i.e. new drilling well and EOR/IOR
• Prepare for decommissioning activities
• Maintain production plateau
11 PTTEP1 OP Production 100% - - 0.2 • Explore for additional field potential i.e. new drilling well and EOR/IOR
• Prepare for decommissioning activities
• Maximize crude production by fully implemented the business plan and work activities as
planned
Crude:28 KBPD
12 S1 OP Production 100% - 8 • 10 years strategy roadmap is being submitted to the management committee to ensure
LPG: 190 MTon/Day
all focused strategic areas will be set up in the long term until end of concession in year
2031
• Ensure gas deliverability
Apico**** 35% 0.3 • Drill development well
13 Sinphuhorm OP Production 55% 97
ExxonMobil 10% • Sinphuhorm new Gas Sales Agreement is under Government’s consideration and
approval process
* Status: OP = PTTEP operatorship / JOC = PTTEP joint operatorship / JV = PTTEP as Joint Venture Partner
** Sales volume stated at 100% basis.
*** DCQ = Daily Contractual Quantity
**** PTTEP holds indirectly and directly 80.48% participating interest in Sinphuhorm Project.
40 Energy Partner of Choice
APICO also holds 100% participating interest in Block L15/43 and Block L27/43.Project information 2/5
PTTEP’s Partners 6M 2021 Average Sales Volume ** 2021 Key Activities
Project Status* Phase
Share (as of April 2021) Gas (MMSCFD) Liquid (KBPD)
Thailand and JDA
• Study to explore additional field potential
14 L22/43 OP Production 100% - - -
• Prepare for decommissioning activities
15 MTJDA JOC Production 50% Petronas-Carigali 50% 263 8 • Ensure gas deliverability level at DCQ***
16 G9/43 OP Exploration 100% - - - • Activity suspended
• Awarded as an operator for Erawan field (Contract 1, 2 and 3) under PSC (after
concession-end in 2022)
17 G1/61 (Erawan) OP Exploration 60% MP G2 (Thailand) Limited 40% - - • Preparing all transitional works including construction of facilities, staff
recruitment, Gas Sales Agreement, and related procurement activities, aiming
for successful transition and gas production as per commitment.
• Awarded as a sole operator under PSC (after concession-end in 2022/2023)
• Drill appraisal and exploration wells
18 G2/61 (Bongkot) OP Exploration 100% - - -
• Installation new wellhead platforms and drill production wells
• Finalise Gas Sales Agreement and Prepare for seamless operation handover
Others SEA
SK309 and SK311**
OP • SK309 and SK311: Pemanis Gas Development Topside Installation and South
173 SK309 and SK311**
(except 6.4-80% Acis Satellite infill oil development drilling
Production/ Block K** 17
1 Malaysia Gumusut- (varied by Varied by permits • Block K: SNP Development Drilling
Exploration 25 Block K**
Kakap (GK) permits) • Block H: Maximize production at plateau 270MMSCFD after first gas in
Block H** 25
in Block K) February 2021
142
TOTAL 31.24%
JV • Drill 2nd production well
2 Yadana Production 25.5% Chevron 28.26% 767 -
• New DCQ*** proposal and negotiation with PTT
MOGE 15%
Petronas-Carigali 40.91018%
JV • Suspended the production due to the feed gas was not sufficient for the
3 Yetagun Production 19.3178% MOGE 20.4541% - -
minimum threshold level
Nippon Oil 19.3178%
Myanma Oil and
Zawtika • Some activities are delayed and process under difficulty due to the political
4 OP Production 80% Gas Enterprise 20% 340 -
(M9 & a part of M11) situation and COVID-19 in Myanmar
(MOGE)
• Waiting for approval of PSC Supplementary
5 Myanmar M3 OP Exploration 80% MOECO 20% - - • FEED & OE and survey activities
• Gas Sales Agreement negotiation
• Waiting for final termination document from MOGE
6 Myanmar M11 OP Exploration 100% - - - • Leftover material transferring to MOGE in progress (slow progress due to
current situation in Myanmar)
• Termination process in progress
7 Myanmar MD-7 OP Exploration 50% TOTAL 50% - - • Leftover material transferring to MOGE in progress (slow progress due to
current situation in Myanmar)
Palang Sophon 10% • Termination process in progress
8 Myanmar MOGE 3 OP Exploration 77.5% MOECO 10% - - • Leftover material transferring to MOGE in progress (slow progress due to
WinPreciousResources 2.5% current situation in Myanmar)
* Status: OP = PTTEP operatorship / JOC = PTTEP joint operatorship/ JV = PTTEP as Joint Venture Partner
** Sales volume stated at 100% basis/ For Malaysia project, gross production is net off unitization Energy Partner of Choice
*** DCQ = Daily Contractual Quantity 41Project information 3/5
Partners 6M 2021 Average Sales Volume ** 2021 Key Activities
Project Status* Phase PTTEP’s Share
(as of April 2021) Gas (MMSCFD) Liquid (KBPD)
Others SEA
PetroVietnam 50% 3 • Maintain production level
9 Vietnam 9-2 JOC Production 25% 15
SOCO 25% • Development drilling study support
PetroVietnam 41% • Maintain production level
10 Vietnam 16-1 JOC Production 28.5% SOCO 28.5% 8 12 • Drill development wells
OPECO 2% • Under procurement process for Equipment and Services
• Negotiation process on commercial terms in order to push forward the Final
PetroVietnam 65.88%
11 Vietnam B & 48/95 JV Exploration 8.5% - - Investment Decision (FID)
MOECO 25.62%
• The first production target at the end of 2024
73.4% • Negotiation process on commercial terms in order to push forward the Final
JV PetroVietnam
12 Vietnam 52/97 Exploration 7% 19.6% - - Investment Decision (FID)
MOECO
• The first production target at the end of 2024
Premier Oil 28.67%
JV KUFPEC 33.33%
13 Natuna Sea A Production 11.5% 214 2 • Drill development wells
Petronas 15%
Pertamina 11.5%
Middle East
• Being evaluated for petroleum potential to support future exploration, including G&G
1 Abu Dhabi Offshore 1 JV Exploration 30% Eni Abu Dhabi 70% - -
report
2 Abu Dhabi Offshore 2 JV Exploration 30% Eni Abu Dhabi 70% - - • Preparation for exploration well which to be drilled in Q3/2021
• Appraisal plan of Pre-existing discovery has been approved by ADNOC
3 Abu Dhabi Offshore 3 JV Exploration 30% Eni Abu Dhabi 70% - - • Project is on-going with G&G study.
Government of Oman 60%
4 PDO (Block 6) JOC Production 2% Shell 34% - 627** • Normal operations with daily production around 600 KBD
Total 4%
Occidental 47%
OOCEP 20%
5 Mukhaizna JV Production 1% - 96** • Normal operations with daily production around 95 KBD
Indian Oil 17%
Mubadala 15%
Oman Onshore Total E&P Oman Block 12 • 3D seismic reprocessing (original 3D) in progress
6 JV Exploration 20% 80% - -
Block 12 B.V. • Preparation of 3D seismic acquisition (new 3D)
BP 40%
Makarim Gas 30%
7 Oman Block 61 JV Production 20% Development LLC 647 31 • Completed production ramp up as planned
PC Oman Ventures 10%
Limited (PETRONAS)
* Status: OP = PTTEP operatorship / JOC = PTTEP joint operatorship / / JV = PTTEP as Joint Venture Partner
** Sales volume stated at 100% basis / For PDO (Block 6) and Mukhaizna projects, gross production is net off unitization
42 Energy Partner of ChoiceProject information 4/5
Partners 6M 2021 Average Sales Volume ** 2021 Key Activities
Project Status* Phase PTTEP’s Share
(as of April 2021) Gas (MMSCFD) Liquid (KBPD)
Other International
• AC/RL7 (Cash Maple) and Oliver (AC/RL12) Field : under way to define proper
PTTEP Australasia
1 OP Exploration 100% - - - direction in order to increase development opportunities
(PTTEP AA)
• Other exploration projects: G&G studies
• First Cargo is expected by 2024 (Under further assessment)
Total, Mitsui, • 1st Debt drawdown in project Finance
26.5%,20%
JV ENH, OVL • The Force Majeure has been declared by the operator for safety reason due to
2 Mozambique Area 1 Development 8.5% 15%, 10% - -
OVRL & Oil India , the security incident in Palma.
10%, 10%
Bharat • Project management under FM and study of impacts
• Plan to resume the project after safety security
• Drill development wells
Algeria 433a & 416b PetroVietnam 40%
3 JOC Production 35% - 3 • Existing wells intervention
(Bir Seba) Sonatrach 25%
• Production respect OPEC+ policy
• Drilling development wells
Algeria Hassi Bir CNOOC 24.5%
4 OP Development 24.5% - - • Expected first oil production for the initial phase of around 10,000-13,000 barrels
Rekaiz Sonatrach 51%
per day (BPD) in 2021
5 Mariana Oil Sands OP Exploration 100% - - - -
65%
Shell Brasil - • Waiting for exploration wells drilling permit from the government
6 Barreirinhas AP1 JV Exploration 25% 10% -
Mitsui E&P Brasil
JV Petrobras 65%
7 Brazil BM-ES-23 Exploration 20% - - • Evaluating the petroleum potential for development concept
INPEX 15%
• The geophysical survey processing and interpretation are in progress for further
JV PC Carigali Mexico 60% -
8 Mexico block 12 (2.4) Exploration 20% - petroleum potential evaluation
Ophir Mexico 20% • Drilling exploration wells
Repsol Mexico 30% • Completed drilling of 2 exploration wells in 2020 with successful result.
JV
9 Mexico block 29 (2.4) Exploration 16.67% PC Carigali Mexico 28.33% - - • The drilling operation for exploration well and appraisal drilling is ongoing, and it
Wintershal DEA 25% is expected to complete by Q4/2021.
* Status: OP = PTTEP operatorship / JOC = PTTEP joint operatorship/ JV = PTTEP as Joint Venture Partner
** Sales volume stated at 100% basis except for Algeria 433a & 416b (production volume)
43 Energy Partner of ChoiceProject information 5/5
Partners 6M 2021 Average Sales Volume **
Project Status* Phase PTTEP’s Share 2021 Key Activities
(as of April 2021) Gas (MMSCFD) Liquid (KBPD)
Other International
Total 30%
Sonangol 30%
Pre
10 Block 17/06 JV 2.5% SSI 27.5% - - • Completed Begonia FEED study (in-house)
development
Acrep 5%
Falcon Oil 5%
• Maintain production plateau
11 Potiguar OP Production 50% Petro reconcavo 50% - 0.2
• Continue to curb production per OPEC+ agreement to support price
Total 60% • Procurement process for designing of Compression, Separation upgrade and
12 Dunga JV Production 20% 2 11
OOCEP 20% Flare package
• Engineering of Sea water and Export Line
Midstream Project
Government of
Oman 51%
Shell 30%
Total 5.54%
1 Oman LNG Shareholder On line 2% - - • Normal operations
Korea LNG 5%
Mitsubishi 2.77%
Mitsui 2.77%
Itochu 0.92%
ADNOC 68% • Perform midstream operation activities
ADNOC Gas On line
2 JV 2% Shell 15% - -*** • Maintain production and plant integrity with maintenance work as planned
Processing (AGP)
Total 15% • Improving plant's efficiency and capacity with plant debottlenecking as planned
• Status: OP = PTTEP operatorship / JOC = PTTEP joint operatorship/ / JV = PTTEP as Joint Venture Partner
** Sales volume stated at 100% basis
*** Products are propane, butane and naphtha.
44 Energy Partner of ChoiceOrganization structure
Ensuring transparency, integrity and good corporate governance
Board of Directors
Nominating Committee
Corporate Governance and Remuneration Committee
Sustainable Development Committee
Audit Committee Risk Management Committee
Internal Audit CEO
Division
Safety, Security, Health and
Legal Division
Environment Division
President
Non-E&P Business Management Human
Department Geosciences,
Production Engineering, Strategy and Resources,
Subsurface Finance and
Asset New Business Development Operations and Business Corporate
and Accounting
Group Support Group Development Development Affairs and
Department Exploration Group
Group Group Assurance
Enterprise Mission Control Group Group
Department
45 Energy Partner of ChoiceSupplementary Index : Ratio & Formula
Ratio Formula
Lifting Cost ($/BOE) (Operating Exp. – Transportation Cost – Stock Variation – Other expenses not related to lifting) / Production Volume
Cash Cost ($/BOE) (Operating Exp. + Exploration Exp. + G&A + Royalties + Finance Cost) / Sales Volume
Unit Cost ($/BOE) (Operating Exp. + Exploration Exp. + G&A + Royalties + Finance Cost + DD&A) / Sales Volume
Reserves Replacement Ratio 5-Yr Additional Proved Reserves / 5-Yr Production Volume
Reserves Life Index (Year) Proved Reserves / Production Volume
Success Ratio Number of wells with petroleum discovery / Total number of exploration and appraisal wells
Sales Revenue Sales + Revenue from pipeline transportation
EBITDA (Sales + Revenue from pipeline transportation) - (Operating expenses + Exploration expenses + Administrative expenses + Petroleum royalties and remuneration +
Management's remuneration)
EBITDA Margin EBITDA / Sales Revenue
Return on Equity Trailing-12-month net income / Average shareholders' equity between the beginning and the end of the 12-month period
Return on Capital Employed (Trailing-12-month net income + Trailing-12-month Interest Expenses & Amortization of Bond Issuing Cost) / (Average shareholders' equity and average total debt
between the beginning and the end of the 12-month period)
Simple Effective Tax Rate Income tax expenses / Income before income taxes
Total debt Short-term loans from financial institution + Current portion of long-term debts + Bonds + Long-term loans from financial institution
Net debt Total debt – Liquidity
Debt to Equity Total debt / Shareholders' equity
Net Debt to Equity Net debt / Shareholders' equity
Total Debt to Capital Total debt / (Total debt + Shareholders' equity)
Total Debt to EBITDA Total debt / Trailing-12-month EBITDA
Net Debt to EBITDA Net debt / Trailing-12-month EBITDA
EBITDA Interest Coverage Ratio Trailing-12-month EBITDA / Trailing-12-month Interest Expenses & Amortization of Bond Issuing Cost
46 Energy Partner of ChoiceYou can also read
