Greenhouse gas emissions from petroleum production in Guyana: An examination of the implications for the country's net carbon sink status

Abstract

The emerging petroleum production sector has been positively impacting Guyana's economic prospects while contributing to an anticipated increase in the country's greenhouse gas emissions. This article presents a case study that adopts a convergent mixed methods approach. The methods selected for data collection consisted of in-depth interviews, document review and quantitative analysis to examine the implications of the GHG emissions from Guyana's emerging petroleum production sector for the country's net carbon sink status. The article explores measures to enable Guyana to remain a net carbon sink. The study reveals that fugitive emissions were the highest component of greenhouse gas emissions, mostly accounted for by flaring and venting from well testing and flaring from conventional petroleum production. The annual GHG emissions from petroleum production for 2025, 2027 and 2030 were 9034, 13,397 and 20,516 kilotons of CO2e, respectively. Moreover, the combination of the emissions from the oil and gas production and those from three scenarios of growth in Guyana's energy sector, the total annual GHG emissions could vary from 4445 kilotons of CO2e by 2025 to the largest amount of 24,888 kilotons of CO2e by 2030 across various scenarios and conditions. Further, the highest total GHG emissions for 2025 would be 11,015 kilotons CO2e compared to a sequestration rate of 154,060 kilotons CO2 (7%) for 2025. In 2027, the highest total GHG emissions would be 16,234 kilotons CO2e as compared to a sequestration rate of 153,860 kilotons CO2 (11%). No negative implication for Guyana's net carbon sink is projected. However, Guyana should review, update and implement policies to mitigate GHG emissions and offset unavoidable ones. This research highlights the efforts of Guyana to adopt a development path that seeks to fulfil obligations to the UNFCCC and the Paris Accord while improving the social and economic well-being of its citizens.

Introduction

Climate change is a global, existential threat to humanity due to the intended and unintended bio-physical and socio-economic impacts. Additionally, there are interconnected challenges that transcend environmental boundaries, such as threats to water security, rising pressures on food production, increased disaster risks and human well-being. ¹ Already, a large number of climatic changes, inclusive of an increase in the global area affected by drought, frequent heat waves, increased precipitation events and an increased incidence of extremely high sea levels have been observed worldwide. The World Meteorological Office (WMO) ² notes that greenhouse gas concentrations reached a new global high in 2020, with a concentration of carbon dioxide (CO₂) at 413.2 parts per million (ppm) globally, or 149% of the pre-industrial level. The global annual mean temperature in 2021 was approximately 1.11 ±0.13°C above the 1850–1900 pre-industrial average, which is less warm than some recent years. ²

Both the WMO ² and the Inter-Governmental Panel on Climate Change (IPCC) ³ warn that anthropogenic activities, particularly the burning of fossil fuels, are the drivers of these planetary-scale changes on land, in the ocean and in the atmosphere. These have harmful and long-lasting consequences for sustainable development and ecosystems. The reality is that there is an urgent need for collective actions to stabilise greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system ⁴ in an effort to curb temperature increases and avert potential catastrophic consequences. ³

In recognition of the need to operationalise the UNFCCC Parties to the Paris Agreement agreed to hold ‘the increase in the global average temperature to well below 2°C above pre-industrial levels’. Parties also agreed to pursue ‘efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognising that this would significantly reduce the risks and impacts of climate change’. ^{5, p. 3} The ultimate objective is to find and implement urgent solution-oriented policy measures to reduce the adverse impacts of climate change.^{5, p. 3} Thus, all Parties are urged to undertake and communicate ambitious efforts through their nationally determined contributions (NDCs), while reflecting the principle of its common but differentiated responsibilities and respective capabilities (CBDRC), in the light of different national circumstances. ⁵

Basically, there are two broad categories of responses, namely climate mitigation and climate adaptation. Regarding climate mitigation, there is a growing interest in the role of the energy sector (electricity, heat and transport), which accounts for 73.2% of the global greenhouse gas emissions (see Figure 1).

Figure 1.

Global greenhouse gas emissions by sector. ⁶

According to the IPCC Sixth Assessment Report-Summary for Policymakers, ³ limiting global warming requires major transitions in the energy sector. This includes a significant reduction in fossil fuel use, extensive electrification, improved energy efficiency and the use of alternative fuels (such as hydrogen). ³ Moreover, oil-producing countries, will need to develop, implement and enforce the requisite legislative and policy measures, coupled with innovation and technology. Such actions will reduce the climate impact of greenhouse gas emissions, ⁷ bearing in mind that stabilisation of global temperature is only possible when carbon dioxide emissions reach net zero. ³

Notwithstanding, climate-related policies will have intended and unintended consequences. ⁸ Thus, one must recall Decision 1/CP.27 ⁹ which emphasises that enhanced effective climate action should be just and inclusive, while also minimising negative social or economic impacts that may arise. While it is imperative to flatten the curve of emissions (both historical and current), a country must also be aware of the potential economic, financial and political risks associated with climate action. ¹⁰ Further, climate action (sustainable development goal [SDG] #13) should not compromise the achievement of other SDGs, such as no poverty (SDG #1) and affordable and clean energy (SDG #7).

At the twenty-seventh United Nations Climate Change Conference of Parties (COP 27), ⁹ a call was made to transition towards low-emission energy systems, including by rapidly scaling up the deployment of clean power generation and energy efficiency measures. In line with this, our article aims to answer the question: What are the implications of greenhouse gas emissions from petroleum production in Guyana for the country's net sink carbon status? The study has three objectives, namely: (i) to estimate the greenhouse gas (GHG) emissions of upstream and downstream activities of petroleum production in Guyana; (ii) to examine the implications of the GHG emissions of petroleum production for Guyana’s status as a net carbon sink country and (iii) to explore policy options to mitigate GHG emissions from petroleum production in Guyana. Our article is timely, as it highlights the efforts of a country that once was classified as a least developed country with an extremely high human capital flight to adopt a development path that seeks to fulfil obligations to the UNFCCC and the Paris Accord, while simultaneously improving the social and economic well-being of its citizens.

Guyana's physical and human geography – a summary

Guyana is a country located on the northern coast of South America, with a landmass of approximately 125,000 km squared. It shares boundaries with Suriname to the east, Brazil to the west and south, Venezuela to the west. The country's entire coastline is along the Atlantic Ocean to the north. Guyana is geographically divided into four natural regions: the coastal plain, the hilly sand and clay region, interior savannahs and the forested highlands (Figure 2).¹¹ The country has 10 administrative regions.

Figure 2.

The key natural regions in Guyana.^{11, p. 10}

The coastal zone is a relatively flat, narrow area that is the smallest natural region of the country. Situated at approximately 1.5 m below mean high tide level of the Ocean, the coast is vulnerable to flooding located immediately inland of the coastal plain, except in the northwest, is the hilly sand and clay region. This region is gently undulating and contains bauxite and some of the forest resources of the country. The forested highlands area is the largest natural region. It is densely forested with mountains and fast-flowing rivers that create deep gorges and waterfalls in the terrain. The interior savannahs are located west of the forested highlands. They are divided into the northern and southern savannahs by the Kanuku Mountains. ¹¹

Guyana is a country that has abundant natural resources, such as water, forests, mineral resources and land. ¹¹ In the context of this article, the country's forest resources are relevant. Guyana has primarily tropical moist forests, occupying an area of 17.99 million hectares, which accounts for approximately 85% of the country's total area. It is classified as one of the high forest, low deforestation developing countries (HFLD). According to the country's latest audit, the deforestation rate for the period between January 1, 2021, and December 31, 2021, was estimated to be 0.042%, which was lower than the previous year's rate. Guyana's deforestation rate is low compared to other South American countries. Alluvial gold mining caused the majority of deforestation (89%) in 2021. ¹²

Guyana has a small population for its area. According to the country's last census conducted in 2012, the population was recorded at 746,955 individuals, ¹³ and a recent report indicated a figure of 787,000. ¹⁴ The growth rate of Guyana's population has been ‘either negative or at less than 2% in the past decades’,^{14, p. 3} as the country has one of the highest emigration rates globally. ¹⁴ Among the administrative regions, Region 4, which includes the capital city of Georgetown on the coastal zone, has the highest population density of 311,563, while administrative regions 7, 8 and 9, mainly consist of the highland forested area, have the lowest population densities of 18,375, 11,077 and 24,238, respectively. ¹³ As a result, a significant portion of the population resides on the vulnerable coast, while the forested areas are not at serious risk from current population densities. The 2012 Census shows that the country has a young population, with over half (57%) of the population below 30 years of age. ¹⁵

Guyana's economic performance, including petroleum production

Guyana is classified as a middle-income country with a human development index (HDI) value of 0.682 in 2019. The country falls within the medium human development category, corresponding with notable improvements in life expectancy at birth, mean years of schooling and expected years of schooling since 1980. ¹⁶

Over the past 7 years, Guyana has experienced consistent economic growth of approximately 13.0% from 2015 to 2021. ¹⁷ Notably, despite the economic downturn experienced by most of Latin America and the Caribbean in 2020 on account of the pandemic, Guyana's gross domestic product (GDP) almost doubled, reaching 48.7% that year ¹⁸ (see Figure 3). This significant increase was largely attributed to activities within the oil and gas sector, which recorded its first full year of oil production, while real non-oil GDP contracted by 7.3% in 2020. ¹⁹

Figure 3.

Economic growth rate (2015–2021). ¹⁷

Prior to its debut as an oil-producing country in December 2019, Guyana's economy was traditionally based on services, agricultural production (mainly sugar and rice) and gold and bauxite mining. In 2021, the services and manufacturing sectors contributed 37.5% and 3.2%, respectively, to real GDP, agriculture, forestry and fishing contributed 13.4%. Moreover, the expanding oil and gas industry led to the mining and quarrying sector accounting for 40.3% of GDP in 2021^17,18 (see Figure 4).

Figure 4.

GDP composition by sector (2015–2021). ¹⁷

In 2020 and 2021, the oil and gas industry constituted 58.3% and 80.7% of the mining and quarrying component, respectively. ¹⁸ This sub-sector has now replaced the gold mining subsector as the primary contributor to the mining and quarrying GDP component as the latter contributed an average of 73.6% of the mining and quarrying GDP component from 2012 to 2019 ²⁰ (see Figure 4). Additionally, crude oil exports are currently a major source of exports, representing 68.3% of exports in 2021 at a value of US$2.98 billion. ²¹

The Guyanese economy is projected to record real oil GDP growth of 47.5% in 2022 because of higher oil output with the second floating production storage and offloading (FPSO) vessel (Liza Unity under Liza Phase 2) beginning operation. Meanwhile, the non-oil economy is estimated to grow by 7.7% for the year as the rice growing and gold mining sectors rebound from excess flooding in May/June 2021 and the impacts of the COVID-19 pandemic. Continued growth is also expected in construction activities along with the wholesale and retail trade and repairs sector. ¹⁸

The Guyanese economy is expected to experience significant growth within the next decade, with the oil and gas industry playing a major role in this growth. The GDP is set to expand from a growth rate of 5.4% in 2019 to US$15.5 billion, with per capita GDP reaching US$19,400. ²² The oil sector is projected to grow rapidly and contribute around 40% of GDP by 2024, which will allow for additional fiscal spending annually of 6.5% of non-oil GDP on average in the medium term. ²³

Methodology

Project summary

In 2008, Esso Exploration and Production Guyana Limited (EEPGL) is an indirectly owned affiliate of Exxon.

Mobil Corporation began its exploration campaign for oil and gas in Guyana. On May 20, 2015, EEPGL announced a significant discovery of light crude oil in the Stabroek Block, located 193 km offshore in the Guyana Basin ²⁴ (see Figure 5). There have been over 30 discoveries since then and the 6.6 million acres (26,800 km²) Stabroek Block is currently estimated to hold a recoverable resource exceeding 11 billion oil equivalent barrels. ²⁶ Guyana has the third largest crude oil reserves in Latin America and the Caribbean ²⁷ and the 17 highest oil reserves globally. ²⁸

Figure 5.

Discoveries within the stabroek block. ^{25 (p. 9)}

EEPGL (with a 45% interest in the Stabroek Block) and its co-venturers Hess Guyana Exploration Limited (30% interest) and CNOOC Petroleum Guyana Limited (25% interest) are parties to a Petroleum Agreement with the government of Guyana. ²⁹ Currently, there are four (4) sanctioned offshore projects that will reach production levels of 0.85 million barrels per day by 2025. These projects are Liza Phase 1, Liza Phase 2, Payara and Yellowtail, with the latter two currently under development (see Table 1 and Figure 6).

Table 1.

Overview of four sanctioned offshore projects in Guyana.^30–32

Projects	Production (barrels per day)	Floating production storage and offloading (FPSO) vessel	Date/year of commencement of production	Drill centres and wells
Liza Phase 1	120,000	Liza Destiny	December 20, 2019	4 drill centres 17 wells (8 oil-producing wells, 6 water injection wells, and 3 gas reinjection wells)
Liza Phase 2	220,000	Liza Unity	February 11, 2022	6 drill centres 30 wells (15 oil-producing wells, 9 water injection wells and 6 gas injection wells)
Payara	220,000	Prosperity	2023	45 wells (production wells, water injection wells and gas injection wells)
Yellowtail (See Figure 6)	250,000	One Guyana	2025	6 drill centres up to 26 production and 25 injection wells

Figure 6.

Location of the yellowtail project development area within stabroek block. ^{33 (p. EIS-7)}

The gas-to-energy project

The gas-to-energy project includes the construction and operation of a pipeline from the Liza Phase 1 and Liza Phase 2 FPSO vessels to an onshore natural gas liquids (NGL) and natural gas processing plant (NGL plant; see Figure 7).

Figure 7.

Project location for gas to energy project. ^{34 (p. EIS-8)}

Details on the major components of the project are as follows (Table 2).

Table 2.

Components of the gas to energy project. ³⁴

Offshore pipeline	- A 12″ pipeline that will transport up to 50 million standard cubic feet per day (mmscfd) of gas from Liza Phase 1 and Liza Phase 2 FPSOs to connection with an onshore pipeline. The maximum flow of the pipeline is approximately 120 mscfd. The offshore pipeline is approximately 220 km, extending from new subsea tie-ins at the Destiny and Unity FPSOs to a proposed shore landing, located approximately 3.5 km west of the mouth of the Demerara River.
Onshore pipeline	- A 12″ pipeline that will transport up to 50 MSCFD of gas from connection with an offshore pipeline to the NGL Plant. The maximum flow of the pipeline is approximately 120 mscfd. The onshore pipeline is a continuation of the offshore pipeline that extends linearly approximately 25 km from the shore landing to a proposed NGL Plant. The site lies approximately 23 km upriver on the west bank of the Demerara River on former sugarcane fields in Wales.
NGL plant	- An onshore plant that will remove propane, butane and pentanes plus liquids with the ability to be sold; and treat remaining gas to specifications required by the power plant, including dehydration and pressure let down of gas.
Temporary material offloading facility (MOF)	- An offloading facility may be established on the west bank of the Demerara River for offloading of heavy modules (use determination to be finalised pending detailed design study) and imported material or equipment.
Associated infrastructure Upgrades	- Some degree of construction access road development/improvement will likely be required along the onshore pipeline route. This will likely comprise a combination of soil stabilization and temporary hard-surfacing, with restoration following completion of construction.
Logistics support	- Marine vessels and helicopters throughout all stages with potential sharing among developments - Onshore infrastructure support, including shorebases, pipe yards, fabrication facilities, fuel supply facilities, and waste management facilities.

In 2021, output in the petroleum and gas and support services sector increased significantly by 46.5%. Crude oil production also grew by 56.9% to 42.7 million barrels, compared to the previous year's 27.2 million barrels. Daily production ranged from 36,081 barrels per day (due to a faulty gas compressor) to a peak of approximately 130,000 barrels per day in December 2021, bringing the average production to approximately 117,000 barrels per day. This repaired gas compressor played a significant role in this performance, as it allowed production to resume to full operational capacity.18 By the third quarter of 2022, production capacity had reached 360,000 barrels per day from the operation of the Liza Destiny and Liza Unity FPSOs, with the former expanding its capacity from 120,000 barrels per day to 140,000 barrels per day. Production is expected to increase to approximately 380,000 barrels per day at the end of the year, exceeding the initial 2022 target by 40,000 units. ³⁵ Guyana has received G$177.14 billion (US$849.63 million) from twelve lifts of profit oil and G$21.28 billion (US$102.06 million) from royalties, and revenue from an additional 10 oil cargoes is expected in 2022.^36,37

ExxonMobil has indicated that at least 6 projects offshore Guyana will be operational by 2027, ³⁸ with the possibility of up to 10 projects on the Stabroek Block to develop its recoverable resource. ³² Forecasts from Rystad Energy's Industry and Country Benchmarking Update 2022 ²⁵ show that in addition to the four approved projects, four more projects may be in operation by 2030. ² The details of these projects are shown in Table 3.

Table 3.

Current and projected oil production projects. ^{25 (p. 17),a}

	Asset	Facility type b	Discovery year	Approval year	Start-up year	Status
1	Liza Phase 1	FPSO	2015	2017	2019	Producing
2	Liza Phase 2	FPSO	2015	2019	2022	Producing
3	Payara	FPSO	2017	2020	2023	Under development
4	Yellow Tail	FPSO	2019	2022	2025	Under development
5	Uaru	FPSO	2020	2023	2027	Discovery c
6	Tripletail	FPSO	2019	2025	2028	Discovery
7	Longtail	FPSO	2018	2024	2028	Discovery
8	Snoek	FPSO	2017	2026	2029	Discovery

^aThe analysis considers available information up to September 30, 2022 and excludes the two most recent discoveries on October 26, 2022.

^bProjected facility type.

^cDiscoveries are to be confirmed and are not guarantees of future development.

In October 2022, the government made an announcement regarding its plans for the construction of a refinery that will have a capacity of 30,000 barrels per day. The refinery will be located near the Berbice River, in the vicinity of Crab Island. The construction is expected to commence in 2023, and the completion of the facility is expected by 2025. ³⁹

Research design

This case study of Guyana examines the implications of greenhouse gas emissions from petroleum production in Guyana for the country's net sink carbon status. The researchers have used the embedded mixed methodology that allowed for the simultaneous collection, analysis, incorporation and interpretation of quantitative and qualitative data.^40,41 This approach was necessary to provide a holistic understanding of the subject of investigation, given the sparse, fragmented, inconclusive and ambivalent nature of current available literature, as well as to enhance the acceptability of the findings of the study.

Primary qualitative data

Primary data were generated from in-depth qualitative interviews with key informants from entities that had a direct or indirect responsibility for petroleum production activities in Guyana, had a strong interest and/or influence in the decision-making process, and were easily accessible and convenient. ⁴² Thus, the non-random purposive sampling method was employed to select senior representatives of key stakeholder entities. These entities were categorised as academic, government, private sector, civil society, and international funding agencies. A semi-structured interview was prepared and pilot tested before it was administered to the key informants (Table 4).

Table 4.

Targeted entities that responded.

Category	Entities
Academia	- University of Guyana - University of the West Indies
Government	- Department of Environment and Climate Change - Environmental Protection Agency - Guyana Geology and Mines Commission - Guyana Forestry Commission - Ministry of Natural Resources - Office of the Prime Minister
Private sector	- Private Sector Commission - Georgetown Chamber of Commerce
Civil society/nongovernment organisations	- Conservation International-Guyana Country Office - Guyana Association of Professional Engineers - Guyana Policy Forum - Iwokrama International Centre for Rainforest Conservation and Development - World Wildlife Fund-Guyana Country Office
International unding agencies	- Food and Agriculture Organisation-Guyana Country Office

The semi-structured interview was selected as the data collection instrument to facilitate a more focused and in-depth exploration of the subject of investigation. As noted by De Jonckheere and Vaughn, ⁴³ (p. 2) ‘overall purpose of using semi-structured interviews for data collection is to gather information from key informants who have personal experiences, attitudes, perceptions and beliefs related to the topic of interest’. In order to operationalise the in-depth interviews, a semi-structured interview schedule was prepared in advance and piloted, using convenience sampling, then amended to avoid any potential problem arising from ambiguity and to increase the validity of the data collection instrument. Notably, the interview schedule comprised a set of pre-determined open ended questions that were prepared as the basis for the interview, though, deviations were made from the instrument, depending on each targeted interviewee.^42,44,45

The semi-structured interview schedule comprised two main sections: the first focused on the name of the institution and its responsibilities and/or interests in the petroleum production in Guyana, the interviewee's position at the institution and years of experience, as well as any shared details on any specific training and/or experience in oil and gas. The second section captured the various perspectives of the interviewees on several issues such as the implications (possible future effects or results) of the petroleum production in Guyana for the country's GHG emissions, activities of petroleum production should be given the highest attention with regard to GHG emissions, way/s would petroleum production affect Guyana's status as a net carbon sink, the effectiveness of the current policy/ies to offset GHG emissions from petroleum production, and policy options and/or measures that Guyana should implement to mitigate and offset GHG emissions associated with the country's petroleum production activities. All responses were audio recorded and transcribed to a master sheet before a thematic analysis was conducted.

Secondary data

Document review was utilised to obtain the country's contemporary policy decisions on the development of the energy and forestry sectors, and also collect the resultant secondary quantitative data on GHG emissions and sequestration rates associated with the two sectors. Specific documents reviewed included Guyana's Low Carbon Development Strategy 2030 ⁴⁶ and Guyana REDD + Monitoring Reporting & Verification System (MRVS): MRVS Report – Assessment Year 2021. ¹² The energy sector was selected because the majority of Guyana's current and historic GHG emissions originate from its energy sector. On the other hand, with the country's HFLD status, Guyana has a significant carbon stock that sequesters more carbon than that generated by the country's anthropogenic activities thus rendering the country a net carbon sink. ⁴⁷

The government of Guyana ⁴⁶ provided the estimated GHG emissions for three energy scenarios in Guyana for 2022 to 2030 – the first scenario was a baseline of continued use of fossil fuel; the second scenario was the transition to natural gas without renewable energy; and the third scenario was the transition to natural gas and renewable energy. The estimated GHG emissions for these energy scenarios were combined with the calculated GHG emissions for petroleum production activities and compared to the sequestration rates in order to explore the implications for Guyana's status as a net carbon sink country. The annual sequestration rates for 2022–2030 were estimated by using the average of the deforestation rates for the past five years obtained from Guyana Forestry Commission ¹² and its standard deviation and applying a method similar to that used by the government of Guyana. ⁴⁶

Additionally, the environmental impact assessment reports of the four approved oil production projects and the gas-to-energy project were reviewed. Also, socio-economic data was obtained from the Bank of Guyana's annual reports, data tables from the Bureau of Statistics and the United Nations Development Programme's Human Development Report 2020. ¹⁶ The key document that supported the estimation of greenhouse gas emissions was the IPCC's 2006 IPCC Guidelines for National Greenhouse Gas Inventories. ⁴⁸

Ethical issues

The researchers provided all interviewees with the background information on the study and requested their informed consent, prior to collecting any information, using audio recording technology, that is less intrusive or subject to the recollection or interpretation of the interviewer. Additionally, interviewees were assured of anonymity, confidentiality and veracity in the written report on the study.

Analytical framework of secondary quantitative data

The scope of this article was limited to the upstream sub-sector (specifically well drilling, well testing, well servicing and oil and gas production) and downstream sub-sector (specifically refining of crude oil and transmission, storage and processing of natural gas under the planned gas to gas-to-energy). The assessment focused on direct emissions (Scope 1) from power-generating units and diesel engines on drill ships and FPSOs, flaring and venting, and other fugitive emissions (excluding flaring and venting) from well drilling, well testing and well servicing, and gas production, processing and transmission and storage. Indirect emissions (Scope 2) from logistical support provided by helicopter services were also assessed. The categories and sources of emissions are shown in Figure 8.

Figure 8.

Categories and sources. ⁴⁸

The main types of GHGs relevant to the energy sector are carbon dioxide (CO₂), methane (CH₄) and nitrous oxide (N₂O). Emissions arise from these activities by combustion and as fugitive emissions or escape without combustion. For inventory purposes, fuel combustion is defined as the intentional oxidation of materials within an apparatus designed to provide heat or mechanical work to a process or for use away from the apparatus. ⁴⁸

Fugitive emissions refer to intentional or unintentional emissions from the extraction, processing, storage and transport of fuel to the point of final use. Fugitive emissions occur from the extraction, transformation and transportation of primary energy carriers, for example, leakage of natural gas and the emissions of methane during flaring during oil/gas extraction. The primary sources of fugitive emissions from oil and gas systems include equipment leaks, evaporation and flashing losses, venting, flaring and incineration and accidental releases. ⁴⁸

The Tier 1 approach was applied for all the sources of emissions, and data on the design parameters for the Liza 1, Liza 2, Payara and Yellowtail projects was obtained from published Environmental Impact Statements prepared by the developer, EEPGL.

• Equation for Tier 1 Approach: Emission = Activity Data (AD) × default Emission Factor (EF_D) from IPCC.

Historical data on average daily fuel consumption from the Liza Destiny and Liza Unity FPSOs and production numbers for oil and gas was obtained from the Environmental Protection Agency for the period December 20, 2019, to May 11, 2022. Extrapolations for Liza Destiny were made based on the design parameters for the period May 12, 2022, to June 30, 2022, where production was not at peak capacity and then peak capacity operation from July 1, 2022, to December 31, 2022. Extrapolations for Liza Unity were made based on the design parameters for the period February 11, 2022, to December 31, 2022, and then peak capacity operations from 2023. Also, emission projections from 2023 to 2030 for Liza 1 and Liza 2 were based on peak capacity operation, and emission projections from 2023 to 2030 for Payara and Yellowtail projects were based on the design parameters, which were assumed to remain constant during steady operation. The analysis considers available information up to September 30, 2022, and excludes the two most recent discoveries on October 26, 2022. The period of operation under consideration is December 20, 2019, to December 31, 2030, to align with the timeline of the updated low carbon development strategy. The total emissions estimated during this period were also translated into an annual figure to allow for comparability with mitigation measures.

Three scenarios were considered for petroleum production. The first scenario only looked at the four sanctioned projects. In comparison, the second scenario focused on six projects (including Uaru and Tripletail projects), which were assumed to be in operation by 2027. Under the third Scenario 3, eight FPSOs were assumed to be in operation by 2030 (including Uaru, Tripletail, Longtail and Snoek projects). Since only four projects have been sanctioned, extrapolations were made for potential projects that may be in operation during 2026–2030 to meet the 1.65 million bpd. Production was assumed to remain constant during steady operation. Additionally, a lower range of 50 mmscfd and an upper range of 120 mmscfd were applied to account for gas transport, storage and processing. It was assumed that the gas processing plant would be a sweet gas plant in operation by 2025. Marketable gas and raw gas were assumed to be equivalent to gas transport via offshore and onshore pipelines. Also, the operation of the 30,000 barrels per day refinery was assumed to commence operation in 2026.

Logistical support from helicopter services was only considered in the assessment, and operations related to marine support from supply vessels were excluded ³ (Table 5).

Table 5.

Design parameters for FPSOs.

No.	Project	Startup	Capacity (oil)	Capacity (gas production)	Gas reinjection	Fuel gas for FPSO	Gas transported to shore
			Bpd	MMscfd	MMscfd	MMscfd	MMscfd
1	Liza Phase 1	20 Dec 2019	140,000 a	180	160	20	Lower Range = 50 mmscfd Upper Range = 120 mmscfd
2	Liza Phase 2	11 Feb 2022	240,000 b	400	370	30
3	Payara	2023	220,000	395	365	30
4	Yellow Tail	2025	250,000	450	415	35
5	Uaru (estimated)	2027	200,000	348	320	28
6	Tripletail (estimated)	2028	200,000	348	320	28
7	Longtail (estimated)	2028	200,000	348	320	28
8	Snoek (estimated)	2029	200,000	348	320	28
Total			1,650,000	2817	2590	227
Refinery			30,000

^aFigure represents peak capacity from July 1, 2022. Liza 1 (Liza Destiny FPSO) had a capacity of 130,000 barrels per day from December 20, 2019 to June 30, 2022.

^bFigure represents peak capacity from July 1, 2022. Liza 2 (Liza Unity FPSO) had a capacity of 220,000 barrels per day from February 11, 2022 to December 30, 2022.

Activity data

The activity data used were: ⁴

Emission factors

For the fugitive emissions, the emission factors were derived from IPCC's 2006 IPCC Guidelines Volume 2 (Energy) of Chapter 4 (Fugitive Emissions) for oil and gas operations in developing countries and countries with economies in transition (from Table 4.2.5). Emission factors for oil refining were only available under Table 4.2.4 of Chapter 4 (Fugitive Emissions) for oil and gas operations in developed countries and these factors48 were used to derive estimates of fugitive emissions for oil refining. Considering the uncertainty levels of the emission factors, the median value was used in the main analysis ⁵ . Details on the emission factors used are shown in Tables 6 and 7.

Table 6.

Activity data.

Activity data	Unit	Calculations
Oil production	Cubic metres	Design capacity of FPSO for daily production (barrels per day) multiplied by days of operation from start-up to December 31, 2025, and December 31, 2030; converted from barrels to litres using a value of 158.9873; and then converted to cubic metres (m3) by diving by 1000.
Gas production	Million cubic metres	Design capacity of FPSO for daily production (millions of standard cubic feet per day) multiplied by days of operation from start-up to December 31, 2025, and December 31, 2030; and then converted to cubic metres by dividing by 35.315
Gas transmission	Million cubic metres	Design capacity of the pipeline to transport gas (millions of standard cubic feet per day) multiplied by days of operation from start-up to December 31, 2025, and December 31, 2030; and then converted to cubic metres by dividing by 35.315
Consumption of fuel gas from FPSOs	Million cubic metres	Difference between design gas production capacity of the FPSOs and planned gas reinjection (millions of standard cubic feet per day); multiplied by days of operation from start-up to December 31, 2025, and December 31, 2030; and then converted to cubic metres by dividing by 35.315
	Terajoules	Using a conservative value of 0.76 kg/m3 for density a , consumption of fuel gas from FPSOs was converted from cubic metres to gigagrams (Gg) and then converted to terajoules (TJ) using a net calorific value (NCV) of 48.0 TJ/Gg.
Consumption of diesel from FPSOs	Terajoules	Estimated diesel consumption (litres) converted to m3 by dividing by 1000 and then converted to gigagrams (Gg) using a value of 843.9 kg/m3 for density. Weight was converted to TJ using a net calorific value (NCV) of 43.0 TJ/Gg.
Aviation fuel consumption	Terajoules	Estimated aviation gasoline consumption (litres) b converted to m3 by dividing by 1000 and then converted to gigagrams (Gg) using a value of 707.0 kg/m3 for density. Weight was converted to TJ using a net calorific value (NCV) of 44.3 TJ/Gg.
Oil refining	Cubic metres	Design capacity of the refinery for daily production (30,000 barrels per day) multiplied by days of operation from January 1, 2026, to December 31, 2030; converted from barrels to litres using a value of 158.9873; and then converted to cubic metres (m3) by diving by 1000.

^ahttps://www.henergy.com/conversion.

^bEstimated round-trip flights per year multiplied by estimated consumption per flight. Assumption of 20 round-trip flights per week during drilling and installation for an average of 3 years and 5 round-trip flights per week during production operations and continued development drilling activities. The max fuel is 2085 l of the Leonardo LW139 with a range 832 nautical km (30 min reserve). The Liza 1 is approximately 193 km offshore which was assumed to accommodate 2 round-trip flights per 2085 l. https://www.bristowgroup.com/fleet/medium-twins/leonardo-aw139.

Table 7.

Emission factors.

Tier 1 emission factors for fugitive emissions
Category	Sub-category	Emission Source	CH4		CO2		N2O
			Range	Median value	Range	Median value	Range	Median value	Unit of Measure
Well Drilling	All	Flaring and Venting	3.3E-05 to 5.6E-04 a	3.0E-04	1.0E-04 to 1.7E-03 a	9.0E-04	ND b	-	Gg per 103 m3 total oil production
Well Testing	All	Flaring and Venting	5.1E-05 to 8.5E-04 a	4.5E-04	9.0E-03 to 1.5E-01 a	8.0E-02	6.8E-08 to 1.1E-06 c	5.8E-07	Gg per 103 m3 total oil production
Well Servicing	All	Flaring and Venting	1.1E-04 to 1.8E-03 a	9.6E-04	1.9E-06 to 3.2E-05 a	1.7E-05	ND b	-	Gg per 103 m3 total oil production
Oil Production	Conventional Oil	Fugitives Offshore	5.9E-07 a	5.9E-07	4.3E-08 a	4.3E-08	NA d	-	Gg per 103 m3 conventional oil
		Venting	7.2E-04 to 9.9E-04 e	8.6E-04	9.5E-05 to 1.3E-04 e	1.1E-04	NA d	-	Gg per 103 m3 conventional oil
		Flaring	2.5E-05 to 3.4E-05 e	3.0E-05	4.1E-02 to 5.6E-02 e	4.9E-02	6.4E-07 to 8.8E-07 c	7.6E-07	Gg per 103 m3 conventional oil
Oil Refining f	All	All	2.6 × 10−6 g	21.8 × 10−6	ND b	-	ND b	-	Gg per 103 m3 oil refined
Gas Production	All	Fugitives h	3.8E-04 to 2.4E-02 i	1.2E-02	1.4E-05 to 1.8E-04 i	9.7E-05	NA d	-	Gg per 106 m3 gas production
		Flaring j	7.6E-07 to 1.0E-06 e	8.8E-07	1.2E-03 to 1.6E-03 e	1.4E-03	2.1E-08 to 2.9E-08 c	2.5E-08	Gg per 106 m3 gas production
Gas Processing	Sweet Gas Plants	Fugitives	4.8E-04 to 1.1E-03 i	7.9E-04	1.5E-04 to 3.5E-04 i	2.5E-04	NA d	-	Gg per 106 m3 raw gas feed
		Flaring	1.2E-06 to 1.6E-06 e	1.4E-06	1.8E-03 to 2.5E-03 e	2.2E-03	2.5E-08 to 3.4E-08 c	3.0E-08	Gg per 106 m3 raw gas feed
Gas Transmission & Storage	Transmission	Fugitives k	16.6E-05 to 1.1E-03 i	6.3E-04	8.8E-07 to 2.0E-06 i	1.4E-06	NA d	-	Gg per 106 m3 of marketable gas
		Venting l	4.4E-05 to 7.4E-04 i	3.9E-04	3.1E-06 to 7.3E-06 i	5.2E-06	NA d	-	Gg per 106 m3 of marketable gas
	Storage	All	2.5E-05 to 5.8E-05 m	4.2E-05	1.1E-07 to 2.6E-07 m	1.9E-07	ND b	-	Gg per 106 m3 of marketable gas

^aUncertainty (% of value) = −12.5 to + 800%.

^bNot determined.

^cUncertainty (% of value) = −10 to + 1000%.

^dNot applicable.

^eUncertainty (% of value) = ±75%.

^fEmission factors for oil refining were only available under Table 4.2.4 from oil and gas operations in developed countries and these factors were used to derive estimates of fugitive emissions for oil refining.

^gUncertainty (% of value) = ±100%.

^h‘Fugitives’ denotes all fugitive emissions including those from fugitive equipment leaks, storage losses, use of natural gas as the supply medium for gas-operated devices (e.g., instrument control loops, chemical injection pumps, compressor starters, etc.), and venting of still-column off-gas from glycol dehydrators.

ⁱUncertainty (% of value) = −40 to + 250%.

^j‘Flaring’ denotes emissions from all continuous and emergency flare systems.

^kThe larger factor reflects the use of mostly reciprocating compressors on the system while the smaller factor reflects mostly centrifugal compressors.

^lVenting’ denotes reported venting of waste associated and solution gas at oil production facilities and waste gas volumes from blowdown, purging and emergency relief events at gas facilities.

^mUncertainty (% of value) = −20 to + 500%.

For the consumption of fuel gas for drill ships and FPSOs, the emission factors were derived from Volume 2 (Energy) of Chapter 2 (Stationary Combustion) in the Energy Industries of the IPCC (from Table 2.2). ⁴⁸ Details are as follows (Table 8).

Table 8.

Default emission factors for natural gas and diesel. ⁴⁸

	Default emission factors (tons of greenhouse gas per TJ on a net calorific basis)
Fuel	CO2	CH4	N2O
Natural gas	56.1	0.001	0.0001
Diesel	74.1	0.003	0.0006

For the consumption of aviation gasoline, the emission factors were derived from Volume 2 (Energy) of Chapter 3 (Mobile Combustion) of the IPCC (from Table 3.6.4 and Table 3.6.6). ⁴⁸ Details are as follows (Table 9).

Table 9.

Default emission factors for aviation gasoline. ⁴⁸

	Default emission factors (tons of greenhouse gas per TJ on a net calorific basis)
Fuel	CO2	CH4	N2O
Aviation Gasoline	70.0	0.0005	0.002

For stationary fuel combustion at the refinery, a ratio of 11.77 kg of CO₂ emissions per barrel of oil was used. This value was obtained from a study conducted on Estimation of CO₂ emissions from petroleum refineries based on the total operable capacity for carbon capture applications by Madugula et al. ⁴⁹ The lower value in the range for a medium consumption level of a refinery was used, considering that this will be a new operation (Table 10).

Table 10.

Emission factors used for stationary fuel combustion of the refinery. ⁴⁹

Ratio of the CO2 emissions from stationary fuel combustion of the refinery to the total operable capacity of the refinery
Range for medium ratio	kg/barrels
Lower bound	11.77
Upper bound	17.34

Analysis and discussion

Research objective 1: To estimate the GHG emissions of upstream and downstream activities of petroleum production, including the developing value chain in Guyana.

Scenario 1A considers the fugitive emissions from the operation of the four approved projects and the gas-to-energy project maintaining a 50 MMscfd pipeline and fuel combustion emissions from fuel gas, diesel and aviation gasoline consumption. Output numbers are provided in Table 11.

Table 11.

Output by 2025 (Scenario 1A).

No	Project	Days of Operation	Oil production	Gas production	Gas reinjection	Gas transport	Fuel Gas for FPSO	Diesel Use	Aviation fuel use
			103 m3	106 m3	106 m3	106 m3	TJ	TJ	TJ
1	Liza 1	2204	38,363.82	8766.07	7602.24	516.78	42,456.39	32,418.65	6195.69
2	Liza 2	1420	50,567.86	15,310.57	14,083.32		44,770.21
3	Payara	1096	38,335.02	12,258.81	11,327.76	-	33,964.67
4	Yellow Tail	365	14,507.59	4651.00	4289.25	-	13,196.43
Scenario 1A		Sub-total	136,195.42	40,986.45	37,302.58	516.78	134,387.71	32,418.65	6195.69

Scenario 2A considers the fugitive emissions from the operation of the six projects, a 30,000 barrels per day refinery and the gas to energy project maintaining a 50 MMscfd pipeline and fuel combustion emissions from fuel gas, diesel and aviation gasoline consumption. Output numbers are provided in Table 12.

Table 12.

Output by 2027 (Scenario 2A).

No	Project	Days of operation	Oil production	Gas production	Gas reinjection	Gas transport	Fuel Gas for FPSO	Diesel Use	Aviation fuel use
			103 m3	106 m3	106 m3	106 m3	TJ	TJ	TJ
1	Liza 1	2934	54,612.32	12,486.87	10,909.62	1550.33	57,538.03	43,156.22	7214.41
2	Liza 2	2150	78,422.44	23,579.01	21,731.62		67,392.67
3	Payara	1826	63,868.38	20,423.90	18,872.72	-	56,587.13
4	Yellow Tail	1095	43,522.77	13,952.99	12,867.76	-	39,589.30
5	Uaru	365	11,606.07	3592.23	3304.86	-	10,483.58
6	Tripletail	365	11,606.07	3592.23	3304.86	-	10,483.58
Scenario 2A		Sub-total	263,638.05	77,627.24	70,991.43	1550.33	242,074.27	43,156.22	7214.41
		Days of Operation	Oil Refined	Oil Refined	Oil Refined
			barrels per day	barrels	103 m3
Refinery		730	30,000	21,900,000	3481.82

Scenario 3A considers the fugitive emissions from the operation of the eight projects, a 30,000 barrels per day refinery and the gas to energy project maintaining a 50 MMscfd pipeline and fuel combustion emissions from fuel gas, diesel, and aviation gasoline consumption. Output numbers are provided in Table 13.

Table 13.

Output by 2030 (Scenario 3A).

No	Project	Days of operation	Oil production	Gas production	Gas reinjection	Gas transport	Fuel gas for FPSO	Diesel use	Aviation fuel use
			103 m3	106 m3	106 m3	106 m3	TJ	TJ	TJ
1	Liza 1	4030	79,007.33	18,078.26	15,879.75	3102.08	80,201.80	59,277.30	8743.88
2	Liza 2	3246	120,242.45	36,004.33	33,225.04		101,388.33
3	Payara	2922	102,203.40	32,682.71	30,200.48	-	90,551.80
4	Yellow Tail	2191	87,085.29	27,918.73	25,747.27	-	79,214.75
5	Uaru	1461	46,456.09	14,378.78	13,228.48	-	41,963.03
6	Tripletail	1461	46,456.09	14,378.78	13,228.48	-	41,963.03
7	Longtail	1096	34,850.02	10,786.54	9923.62	-	31,479.45
8	Snoek	730	23,212.15	7184.47	6609.71	-	20,967.15
Scenario 3A		Sub-total	539,512.81	161,412.60	148,042.83	3102.08	487,729.34	59,277.30	8743.88
		Days of operation	Oil refined	Oil refined	Oil refined
			barrels per day	barrels	103 m3
Refinery		1826	30,000	54,780,000	8709.32

Scenario 1B considers the fugitive emissions from the operation of the four approved projects and the gas-to-energy project, maximising the capacity of the 120 MMscfd pipeline and fuel combustion emissions from fuel gas, diesel and aviation gasoline consumption. Output numbers are provided in Table 14.

Table 14.

Output by 2025 (Scenario 1B).

No	Project	Days of operation	Oil production	Gas production	Gas reinjection	Gas transport	Fuel gas for FPSO	Diesel use	Aviation fuel use
			103 m3	106 m3	106 m3	106 m3	TJ	TJ	TJ
1	Liza 1	2204	38,363.82	8766.07	7602.24	1240.27	42,456.39	32,418.65	6195.69
2	Liza 2	1420	50,567.86	15,310.57	14,083.32		44,770.21
3	Payara	1096	38,335.02	12,258.81	11,327.76	-	33,964.67
4	Yellow Tail	365	14,507.59	4651.00	4289.25	-	13,196.43
Scenario 1B		Sub-total	136,195.42	40,986.45	37,302.58	1240.27	134,387.71	32,418.65	6195.69

Scenario 2B considers the fugitive emissions from the operation of the six approved projects, a 30,000 barrels per day refinery and the gas-to-energy project, maximising the capacity of the 120 MMscfd pipeline and fuel combustion emissions from fuel gas, diesel and aviation gasoline consumption. Output numbers are provided in Table 15.

Table 15.

Output by 2027 (Scenario 2B).

No	Project	Days of operation	Oil production	Gas production	Gas reinjection	Gas transport	Fuel gas for FPSO	Diesel use	Aviation fuel use
			103 m3	106 m3	106 m3	106 m3	TJ	TJ	TJ
1	Liza 1	2934	54,612.32	12,486.87	10,909.62	3720.80	57,538.03	43,156.22	7214.41
2	Liza 2	2150	78,422.44	23,579.01	21,731.62		67,392.67
3	Payara	1826	63,868.38	20,423.90	18,872.72	-	56,587.13
4	Yellow Tail	1095	43,522.77	13,952.99	12,867.76	-	39,589.30
5	Uaru	365	11,606.07	3592.23	3304.86	-	10,483.58
6	Tripletail	365	11,606.07	3592.23	3304.86	-	10,483.58
Scenario 2B		Sub-total	263,638.05	77,627.24	70,991.43	3720.80	242,074.27	43,156.22	7214.41
		Days of operation	Oil refined	Oil refined	Oil refined
			barrels per day	barrels	103 m3
Refinery		730	30,000	21,900,000	3481.82

Scenario 3B considers the fugitive emissions from the operation of the eight approved projects, a 30,000 barrels per day refinery and the gas-to-energy project, maximising the capacity of the 120 MMscfd pipeline and fuel combustion emissions from fuel gas, diesel and aviation gasoline consumption. Output numbers are provided in Table 16.

Table 16.

Output by 2030 (Scenario 3B).

No	Project	Days of operation	Oil production	Gas production	Gas reinjection	Gas transport	Fuel gas for FPSO	Diesel use	Aviation fuel use
			103 m3	106 m3	106 m3	106 m3	TJ	TJ	TJ
1	Liza 1	4030	79,007.33	18,078.26	15,879.75	7445.00	80,201.80	59,277.30	8743.88
2	Liza 2	3246	120,242.45	36,004.33	33,225.04		101,388.33
3	Payara	2922	102,203.40	32,682.71	30,200.48	-	90,551.80
4	Yellow Tail	2191	87,085.29	27,918.73	25,747.27	-	79,214.75
5	Uaru	1461	46,456.09	14,378.78	13,228.48	-	41,963.03
6	Tripletail	1461	46,456.09	14,378.78	13,228.48	-	41,963.03
7	Longtail	1096	34,850.02	10,786.54	9923.62	-	31,479.45
8	Snoek	730	23,212.15	7184.47	6609.71	-	20,967.15
Scenario 3B		Sub-total	539,512.81	161,412.60	148,042.83	7445.00	487,729.34	59,277.30	8743.88
		Days of operation	Oil refined	Oil refined	Oil refined
			Barrels per day	Barrels	103 m3
Refinery		1826	30,000	54,780,000	8709.32

Scenario A: Eight projects in operation, a 30,000 barrels per day refinery and a 50 MMscfd gas pipeline ⁶ (Table 17 and Figure 9).

Table 17.

Total estimated emissions from petroleum production during 2020–2030 (50 MMscfd gas pipeline).

Total emissions
Category	Sub-category	Unit	Scenario 1A 2025 (4 projects + 50 MMscfd gas pipeline)	Scenario 2A 2027 (6 projects + Refinery + 50 MMscfd gas pipeline)	Scenario 3A 2030 (8 projects + Refinery + 50 MMscfd gas pipeline)
Well Drilling	Flaring and Venting	Tons CO2e	169,632.93	315,442.93	676,892.10
Well Testing	Flaring and Venting	Tons CO2e	11,334,216.08	21,076,675.75	45,902,197.89
Well Servicing	Flaring and Venting	Tons CO2e	137,797.52	256,243.00	524,970.19
Oil Production (Conventional Oil)	Fugitives Offshore	Tons CO2e	89.74	166.88	343.01
	Venting	Tons CO2e	137,166.62	255,069.81	525,899.27
	Flaring	Tons CO2e	6,917,983.97	12,864,419.03	28,016,190.02
Oil Refining	All	Tons CO2e	-	75.90	189.86
Gas Production	Fugitives	Tons CO2e	503.60	953.81	2115.81
	Flaring	Tons CO2e	57.42	108.75	241.23
Gas Processing	Fugitives	Tons CO2e	0.54	1.61	3.23
	Flaring	Tons CO2e	1.11	3.34	6.67
Gas Transmission	Fugitives	Tons CO2e	0.33	0.98	1.97
	Venting	Tons CO2e	0.21	0.62	1.23
Gas Storage	All	Tons CO2e	0.02	0.06	0.13
Sub-total (Fugitive Emissions)		Tons CO2e	18,697,450.09	34,769,162.47	75,649,052.62
Petroleum Refining	Combustion for Oil Refining	Tons CO2e	-	257,763.00	644,760.60
Other Energy Industries	Fuel Gas for FPSO	Tons CO2e	7,539,298.12	13,580,632.85	29,128,152.92
	Diesel Use	Tons CO2e	2,402,338.69	3,198,031.63	4,392,661.03
Civil Aviation	Domestic Aviation a	Tons CO2e	433,713.77	505,026.55	612,093.40
Sub-total (Combustion Emissions)		Tons CO2e	10,375,350.58	17,541,454.02	34,777,667.95
Direct Emissions (Fugitive + Other Energy Industries)		Tons CO2e	28,639,086.90	51,805,589.94	109,814,627.17
Indirect Emissions a		Tons CO2e	433,713.77	505,026.55	612,093.40
Total Emissions		Tons CO2e	29,072,800.67	52,310,616.49	110,426,720.57
Annual Emissions		Tons CO2e/year	9,033,725.97	13,397,435.71	20,515,827.77
Annual Fugitive Emissions		Tons CO2e/year	6,149,090.70	9,310,083.28	14,444,772.28
Annual Combustion Emissions		Tons CO2e/year	2,884,635.27	4,087,352.43	6,071,055.49

^aHelicopter services.

Figure 9.

Emissions by type of gas.

The results indicate that by 2025 with four sanctioned projects and a 50 MMscfd gas pipeline in operation, approximately 29,073 kilotons of CO₂e emissions would be generated. Fugitive emissions constituted the highest component, with approximately 18,697 kilotons generated (or 64% of CO₂e emissions). Flaring and venting from well testing and flaring from conventional oil production were the major sub-categories of emissions, with approximately 11,334 kilotons (39% of CO₂e emissions) and 6918 kilotons (24% of CO₂e emissions), respectively. Fuel combustion accounted for approximately 10,375 kilotons (or 36%) of CO₂e emissions generated, primarily driven by the combustion of the fuel gas used in the FPSOs (7539 kilotons or 26% of CO₂e emissions).

Annual emissions generally translated to approximately 9034 kilotons of CO₂e emissions. Also, it was observed that fugitive emissions amounted to about 6149 kilotons, while fuel combustion emissions accounted for about 2885 kilotons annually.

Additionally, the results indicated that by 2027 with six projects, a 30,000 barrels per day refinery and a 50 MMscfd gas pipeline in operation, approximately 52,311 kilotons of CO₂e emissions would be generated. Fugitive emissions constituted the highest component, with approximately 34,769 kilotons generated (or 66% of CO₂e emissions). Flaring and venting from well testing and flaring from conventional oil production were the major sub-categories of emissions, with approximately 21,077 kilotons (40% of CO₂e emissions) and 12,864 kilotons (25% of CO₂e emissions), respectively. Fuel combustion accounted for approximately 17,541 kilotons (or 34%) of CO₂e emissions generated, primarily driven by the combustion of the fuel gas used in the FPSOs (13,581 kilotons or 26% of CO₂e emissions).

Annual emissions generally translated to approximately 13,397 kilotons of CO₂e emissions. Also, it was observed that fugitive emissions amounted to about 9310 kilotons, while fuel combustion emissions accounted for about 4087 kilotons annually.

Furthermore, the results indicated that by 2030 with eight projects, a 30,000 barrels per day refinery and a 50 MMscfd gas pipeline in operation, approximately 110,427 kilotons of CO₂e emissions would be generated. Fugitive emissions constituted the highest component, with approximately 75,649 kilotons generated (or 69% of CO₂e emissions). Flaring and venting from well testing and flaring from conventional petroleum production were the major sub-categories of emissions, with approximately 45,902 kilotons (42% of CO₂e emissions) and 28,016 kilotons (25% of CO₂e emissions), respectively. Fuel combustion accounted for approximately 34,778 kilotons (or 31%) of CO₂e emissions generated, primarily driven by the combustion of the fuel gas used in the FPSOs (29,128 kilotons or 26% of CO₂e emissions).

Annual emissions generally translated to approximately 20,516 kilotons of CO₂e emissions. Also, it was observed that fugitive emissions amounted to about 14,445 kilotons, while fuel combustion emissions accounted for about 6071 kilotons annually.

Scenario B: Eight projects in operation, a 30,000 barrels per day refinery and a 120 MMscfd gas pipeline ⁷ (Table 18).

Table 18.

Total estimated emissions from petroleum production during 2020–2030 (120 MMscfd gas pipeline).

Total emissions
Category	Sub-category	Unit	Scenario 1A 2025 (4 projects + 120 MMscfd gas pipeline)	Scenario 2A 2027 (6 projects + Refinery + 120 MMscfd gas pipeline)	Scenario 3A 2030 (8 projects + Refinery + 120 MMscfd gas pipeline)
Well Drilling	Flaring and Venting	Tons CO2e	169,632.93	315,442.93	676,892.10
Well Testing	Flaring and Venting	Tons CO2e	11,334,216.08	21,076,675.75	45,902,197.89
Well Servicing	Flaring and Venting	Tons CO2e	137,797.52	256,243.00	524,970.19
Oil Production (Conventional Oil)	Fugitives Offshore	Tons CO2e	89.74	166.88	343.01
	Venting	Tons CO2e	137,166.62	255,069.81	525,899.27
	Flaring	Tons CO2e	6,917,983.97	12,864,419.03	28,016,190.02
Oil Refining	All	Tons CO2e	-	75.90	189.86
Gas Production	Fugitives	Tons CO2e	503.60	953.81	2115.81
	Flaring	Tons CO2e	57.42	108.75	241.23
Gas Processing	Fugitives	Tons CO2e	1.29	3.87	7.74
	Flaring	Tons CO2e	2.67	8.01	16.02
Gas Transmission	Fugitives	Tons CO2e	0.79	2.36	4.72
	Venting	Tons CO2e	0.49	1.48	2.96
Gas Storage	All	Tons CO2e	0.05	0.16	0.31
Sub-total (Fugitive Emissions)		Tons CO2e	18,697,453.18	34,769,171.72	75,649,071.14
Petroleum Refining	Combustion for Oil Refining	Tons CO2e	-	257,763.00	644,760.60
Other Energy Industries	Fuel Gas for FPSO	Tons CO2e	7,539,298.12	13,580,632.85	29,128,152.92
	Diesel Use	Tons CO2e	2,402,338.69	3,198,031.63	4,392,661.03
Civil Aviation	Domestic Aviation a	Tons CO2e	433,713.77	505,026.55	612,093.40
Sub-total (Combustion Emissions)		Tons CO2e	10,375,350.58	17,541,454.02	34,777,667.95
Direct Emissions (Fugitive + Other Energy Industries)		Tons CO2e	28,639,089.99	51,805,599.20	109,814,645.69
Indirect Emissions a		Tons CO2e	433,713.77	505,026.55	612,093.40
Total Emissions		Tons CO2e	29,072,803.76	52,310,625.75	110,426,739.09
Annual Emissions		Tons CO2e/year	9,033,726.48	13,397,436.86	20,515,829.45
Annual Fugitive Emissions		Tons CO2e/year	6,149,091.21	9,310,084.43	14,444,773.96
Annual Combustion Emissions		Tons CO2e/year	2,884,635.27	4,087,352.43	6,071,055.49

^aHelicopter services.

A minor increase of 3.09 tons in total fugitive emissions was observed by 2025 due to the larger volume of gas being transmitted, processed, and stored when the scenario of the 120 mmscfd pipeline was considered. The difference in total fugitive emissions by 2027 was 9.25 tons CO₂e and 18.52 tons CO₂e by 2030. Additionally, the change in annual emissions amounted to 0.51 tons CO₂e by 2025, 1.15 tons CO₂e by 2027 and 1.68 tons CO₂e by 2030.

It was also observed that the addition of the refinery resulted in 258 kilotons more emissions by 2027. Moreover, the difference in emissions by 2030 owing to the refinery amounted to 645 kilotons. Additionally, the change in annual emissions stemming from the refinery translated to 128.92 kilotons CO₂e.

Research objective 2: To examine the implications of the GHG emissions of petroleum production for Guyana’s status as a net carbon sink country.

Climate Change Mitigation in Guyana in keeping with its obligations to the Paris Agreement, Guyana is mitigating climate change by focusing on the energy and forestry sectors. ⁴⁷

Energy

According to the government of Guyana, ⁴⁶ the demand for electricity will increase from 1388 GWh in 2022 to 6583 GWh in 2030. During the period 2019 to 2022, the majority of the demand (> 99%) would have been provided by heavy fuel oil (HFO) and diesel, with solar PV accounting for the remaining <1% in 2021 and 2022. The increased demand would be met by transitioning to renewable energy and low-carbon energy sources, inclusive of solar PV, hydropower, wind, biomass and natural gas (see Figure 10), which will also lower GHG emissions. Hydropower and wind will be introduced in 2023 and 2024, respectively. Natural gas will be introduced in 2025 via a gas-fired 300 MW power plant; however, its share of the demand will decrease in 2030, when the renewable energy share will account for almost 60%. ⁴⁶

Figure 10.

Energy mix for grids in Guyana over the period 2019–2030. ⁴⁶

There are approximately 6.5 MWp of roof-mounted solar photovoltaic (PV) systems to date and it is estimated that by 2030, there will be 100 MWp of solar PV capacity operational in the utility's main grid, comprising solar rooftops and utility-scale solar farms. ⁴⁶ There is also a plan to increase the renewable energy share to an average of 70% by 2030 on the regional grids, mainly through solar PV with battery storage.

Moreover, two utility-scale hydropower facilities will be established in the country and will provide a combined capacity of 515 MW to the main grid by 2030. Also, three small-scale hydropower projects (Kato, Kumu and Moco Moco) and a 25 MW wind energy facility are planned. With ongoing wind measurements and assessments, estimates are that 105 MW of wind energy capacity would be operational by 2030. ⁴⁶ Other renewable energy options, such as biofuels and biogas are being explored and Guyana has also embarked on implementing energy efficiency measures, including lighting replacement in residential, commercial and government buildings, and the installation of energy-efficient street lights, occupancy sensors and air-conditioning units ⁸ .

The estimated annual GHG emissions for three energy scenarios obtained from the government of Guyana ⁴⁶ are shown in Figure 11. The baseline scenario of continued use of fossil fuels would produce an almost fivefold increase in the GHGs over the period 2022–2030, that is, from 954 to 4372 kilotons of CO₂e emissions. In comparison, the second scenario of using natural gas without renewable energy would generate 3659 kilotons of CO₂e emissions in 2030. Further, the third scenario of the use of natural gas and renewable energy would release 1144 kilotons of CO₂e in 2030, which would approximate the 2023 emissions. Hence, despite a fivefold increase in demand for electricity over the period 2022–2030, a transition to a mix of natural gas and renewable energy would ensure the GHG emissions in 2030 would not increase similarly.

Figure 11.

Annual GHG emissions from the grids in Guyana over the period 2019–2030. ⁴⁶

Forestry

Guyana has mitigated climate change through sustainable forest management, which is supported by a framework of laws, regulations, forest policy statements and plans and codes of practice and guidelines for harvesting. Reduced impact logging, planning and forest monitoring by the state agency responsible for forestry are key aspects of sustainable forest management. Further, the country is progressing towards implementation of the European Union's Forest Law Enforcement, Governance and Trade (EU-FLEGT) Voluntary Partnership Agreement (VPA), which was concluded and initialed in 2018 and has also implemented a programme of actions to reduce emissions from deforestation and forest degradation (REDD+). It is likely that these actions, among others, have contributed to the low rates of deforestation recorded in Guyana over the period 2010–2021 by the Monitoring, Reporting and Verification System (MRVS) (Figure 12).

Figure 12.

Deforestation rates over the period 2010–2021. ¹²

According to the government of Guyana, ⁴⁶ Guyana's 18 million hectares of forest stores 19.5 Giga tons CO₂ sequestering 154 ⁹ million tons CO₂ annually from the atmosphere. The latter was obtained through the use of the average gross periodic annual increment of unlogged forest of 2.34 tons C per ha per year from Roopsind et al. ⁵⁰ The LCDS 2030 aims to conserve Guyana's forest, maintain the deforestation rate at 90% below the global average and restore about 200,000 hectares of previously forested areas. ⁴⁶

Considering the average of the deforestation rates for the past 5 years and its standard deviation, using a method similar to the government of Guyana, ⁴⁶ the annual sequestration rates for 2022–2030 were estimated and are provided in Figure 13. These are considered as the upper and lower limits of the baseline scenario for sequestration by Guyana's forests which do not incorporate measures proposed in the LCDS 2030. The results show a reduction of the sequestration rate to 154,060–154,196 kilotons CO₂ by 2025. The sequestration rate is estimated to reduce to 153,860–154,064 kilotons CO₂ by 2027, and to 153,561–153,867 kilotons CO₂ by 2030.

Figure 13.

Estimated annual sequestration rates for 2022–2030.

Potential mitigation measures for oil and gas activities

According to the environmental impact statements, a number of mitigation measures incorporated into the oil production projects will aid in reducing emissions of pollutants to the atmosphere, including embedded controls and avoiding routine flaring. This would result in a potential reduction in annual emissions of 5984 kilotons CO₂e by 2024, 9814 kilotons CO₂e by 2027 and 11,411 kilotons CO₂e by 2030 (see Table 19). This translated into emissions potentially amounting to 2885 kilotons CO₂e by 2025, 3369 kilotons CO₂e by 2027, and 8850 kilotons CO₂e by 2030 (see Table 20).

Table 19.

Potential mitigation measures from oil and gas activities.^31,33.

Mitigation measures		Reduction in annual GHG emissions (kilotons CO2e)
		2023–2024	2025–2027	2028–2044
Payara Project	Reduction due to avoidance of routine flaring	5727	5727	5727
	Additional reduction due to embedded controls	257	257	257
	Sub-total	5984	5984	5984
Yellowtail Project	Reduction due to avoidance of routine flaring	-	3064	5088
	Additional reduction due to embedded controls	-	766	339
	Sub-total	-	3830	5427
Total		5984	9814	11,411

Table 20.

Estimated annual GHG emissions after mitigation measures.

Estimated annual GHG emissions after mitigation measures (kilotons CO2e)
	2025	2027	2030
Estimated emissions before mitigation measures	9034	13,397	20,516
Mitigation measures	5984	9814	11,411
Emissions after mitigation measures	3050	3583	9105

Implications for Guyana's Status as a net carbon sink country

The total annual estimated GHG emissions from the energy and petroleum production for the years 2025, 2027 and 2030 for the three energy sector scenarios are indicated in Tables 21–23. The baseline energy scenario and petroleum production activities before mitigation measures would generate a total of 11,015 kilotons CO₂e by 2025, which would increase to 16,234 kilotons of CO₂e by 2027, and 24,888 kilotons of CO₂e by 2030 (see Table 21). Further, the utilisation of mitigation measures in petroleum production would result in lower emission levels of 5,031, 6420 and 13,477 kilotons of CO₂e by 2025, 2027 and 2030, respectively.

Table 21.

Total annual estimated GHG emissions for the baseline energy scenario and petroleum production activities.

Total annual estimated GHG emissions (kilotons CO2e)
Year	2025	2027	2030
Baseline emissions from energy sector	1981	2837	4372
Estimated emissions from petroleum production activities before mitigation measures	9034	13,397	20,516
Emissions from petroleum production activities after mitigation measures	3050	3583	9105
Total emissions	11,015	16,234	24,888
Total emissions after mitigation measures	5031	6420	13,477

Table 23.

Total annual estimated GHG emissions for the natural gas and renewable energy scenario and petroleum production activities.

Total annual estimated GHG emissions (kilotons CO2e)
Year	2025	2027	2030
Emission from NG&RE	1395	1253	1144
Estimated emissions from petroleum production activities before mitigation measures	9034	13,397	20,516
Emissions from petroleum production activities after mitigation measures	3050	3583	9105
Total emissions	10,429	14,650	21,660
Total emissions after mitigation measures	4445	4836	10,249

The total GHG emissions from the use of natural gas in the energy sector and the petroleum production activities before mitigation measures would amount to 10,596 kilotons CO₂e by 2025, 15,522 kilotons of CO₂e by 2027 and 24,175 kilotons of CO₂e by 2030 (see Table 22). Considering the application of mitigation measures in petroleum production, the GHG emissions would increase to the lower levels of 4612 kilotons of CO2e by 2025, 5708 kilotons of CO2e by 2027 and 12,764 kilotons of CO₂e by 2030.

Table 22.

Total annual estimated GHG emissions for the natural gas energy scenario and petroleum production activities.

Total annual estimated GHG emissions (kilotons CO2e)
Year	2025	2027	2030
Emissions from NG without RE	1562	2125	3659
Estimated emissions from oil and gas activities before mitigation measures	9034	13,397	20,516
Emissions from oil and gas activities after mitigation measures	3050	3583	9105
Total emissions	10,596	15,522	24,175
Total emissions after mitigation measures	4612	5708	12,764

A total of 10,429 kilotons CO₂e would be produced by 2025 from the utilisation of natural gas and renewable energy in the energy sector and petroleum production before mitigation measures. The GHG emissions would increase to 14,650 kilotons of CO₂e by 2027 and 21,660 kilotons of CO₂e by 2030 (see Table 23). Moreover, after the consideration of mitigation measures in petroleum production, the GHG emissions would be 4,445, 4836 and 10,249 kilotons of CO₂e by 2025, 2027 and 2030, respectively.

Across the various scenarios and conditions, the total annual GHG emissions could vary from 4445 kilotons of CO₂e by 2025 to the largest amount of 24,888 kilotons CO₂e by 2030. The latter would be generated by the baseline energy scenario and the petroleum production activities without consideration of mitigation measures. However, this level accounts for only 16% of the sequestration rate of 153,561 kilotons CO₂e for 2030. The highest total GHG emissions for 2025 would be 11,015 kilotons CO₂e compared to a sequestration rate of 154,060 kilotons CO₂ (7%) for that year, while for 2027, the highest total GHG emissions would be 16,234 kilotons CO₂e as compared to a sequestration rate of 153,860 kilotons CO₂ (11%). Consequently, Guyana's net carbon sink status is maintained in all scenarios.

This aligns with findings by Özkan, Alola and Adebayo ⁵¹ which found that non-renewable energy efficiency has a significant mitigation impact and Adebayo ⁵² which recommended increased renewable energy use in the short and medium term.

Objective 3: To explore policy options to mitigate and offset the GHG emissions from upstream and downstream activities of petroleum production in Guyana.

Although Guyana's net carbon sink status is predicted to be maintained, all stakeholders consulted agreed that it would be environmentally responsible for the government of Guyana to support and implement a set of policies that will unequivocally sustain the country's international standing in its fight against global climate change. Those recommended policies, in no particular order, are outlined below.

• Make available the requisite infrastructure, innovation and technology and reduce flaring by capturing natural gas and converting it into usable projects (other than the gas to energy project).

• Embark on a plan to transition electricity generation from heavy fuel oil in order to lower the country's emissions and increase Guyana's contribution to the global targets to limit a rapidly warming globe.

• Use the resources generated from petroleum production to accelerate the transformation to zero carbon status for the energy sector and climate-resilient Guyana through adaptation. The highest priority for using fossil fuels should be transforming the energy sector to achieve zero carbon status.

• Develop legislation and regulations for flaring and venting, and provide financial and non-financial incentives. Additionally, enhance national monitoring, measuring and enforcement capabilities of the country's Environmental Protection Agency.

• Institute carbon taxes and taxes on other gases used in petroleum production.

• Incentivise the use of technology that reduces GHG emissions and is generally environmentally friendly, for example, the use of energy-efficient technologies on the FPSOs. This recommendation coincides with existing research which found that energy efficiency significantly mitigated greenhouse gas emissions, particularly carbon dioxide emissions.^53,54 Özkan, Alola and Adebayo ⁵¹ purport that non-renewable energy efficiency as an effective mitigation measure has a larger GHG emission reduction potential compared to increasing renewable energy use in the USA and EU. Additionally, the authors recommended that policy measures for environmental sustainability account for the role of non-renewable energy efficiency bearing in mind that it was more environmentally sustainable than intensive renewable energy use.

• Explore the use of carbon capture at the point of production at any time during extraction.

• Promote and support effective monitoring and maintenance procedures to reduce leakage of methane.

• Support research on the potential use of renewables in the exploration, drilling and production processes. Increasing renewable energy participation has been found to be another effective mitigation measure.^52,53 Moreover, Özkan, Alola and Adebayo ⁵¹ found that renewable energy intensity had a negative correlation with GHG emissions in the EU and the USA from 1990 to 2019 and the associated environmental performance makes this measure more environmentally sustainable than environmental-related technologies.

• Review and update the EPA Act to incorporate climate change in environmental impact assessment in a structured manner.

• Apply Strategic Environmental Assessment (SEA) to the oil and gas industry to avoid trade-offs with sensitive ecological systems and public health and safety.

• Continue to promote and support sustainable forestry management at all levels by providing resources to meet financial, human, physical, and technological needs in the forestry sector.

Conclusion

Given Guyana's economic trajectory, demand for energy and energy services will increase to meet social and economic development needs. Moreover, the petroleum production sector has a significant role in Guyana's economic prospects, and expansions in the industry are likely to improve performances in other sectors, increaseforeign exchange earning potential and augmentper capita income.

With the anticipated growth in fiscal revenues, government spending can be channelled to areas to advance the mitigation and offset of greenhouse gas emissions, especially through renewable energy, national determined contributions. Such action is predicated on the fact that the global climate is changing rapidly, surpassing the mitigation response rate of governments. The time to act decisively is now. No country should assume the role of ‘free rider’, since climate change does not respect any boundaries. At the same time, however, climate actions should be informed by scientific data and not undermine the social and economic well-being of Guyana's citizens. This includes access to affordable and reliable energy to provide essential services for sustaining human development. Therefore, it is essential for Guyana to create that delicate balance between environmental protection and sustainable human development, while ensuring that decisions are robust, transparent and inclusive.

This article reveals that fugitive emissions were the highest component of greenhouse gas emissions, mostly accounted for by flaring and venting from well testing and flaring from conventional petroleum production. The annual GHG emissions from petroleum production for 2025, 2027 and 2030 were 9034, 13,397 and 20,516 kilotons of CO2e, respectively. The incorporation of mitigation measures detailed in the environmental impact assessment in the petroleum production operations would translate into emissions amounting to 2885 kilotons CO2e by 2025, 3369 kilotons CO2e by 2027, and 8850 kilotons CO2e by 2030. Moreover, when considering the emissions from petroleum production in combination with those amounting from three scenarios of growth in Guyana's energy sector, the total annual GHG emissions could vary from 4445 kilotons of CO2e by 2025 to the largest amount of 24,888 kilotons of CO2e by 2030 across various scenarios and conditions.

Further, the highest total GHG emissions for 2025 would be 11,015 kilotons CO2e compared to a sequestration rate of 154,060 kilotons CO2 (7%) for that year, while for 2027, the highest total GHG emissions would be 16,234 kilotons CO2e as compared to a sequestration rate of 153,860 kilotons CO2 (11%). Therefore, no negative implication for Guyana's net carbon sink status is projected since the country's status is maintained under all the scenarios. However, as a sign of goodwill and in respect of the NDC, the government of Guyana should review the LCDS 2030, and incorporate recommendations by stakeholders to ensure the mitigation of avoidable GHG emissions from petroleum production and offsetting those unavoidable ones. These recommendations are focused on target areas that include the application of innovation and technology; facilitation of research and development; implementation of stringent monitoring and maintenance procedures; revision, updating and implementation of legislation and regulations; and introduction of fiscal measures.

Limitations

The Tier 1 Approach utilises default values from the IPCC. ⁴⁸ Given the uncertainty values of the emission factors, it is possible that the emissions calculated can be over or underestimated. Additionally, the activity data based on the project design parameters may vary from actual output numbers in the future.

The analysis provided scenarios based on the sector's developments at the time when up to 8 projects could be in operation by 2030. The pace of development of these projects may be accelerated or decelerated in the future, which would affect the level of emissions. Moreover, since only four projects have been approved, there is no guarantee that any additional projects beyond 2025 will be sanctioned.

Estimates related to logistical support were limited to fuel use for helicopter services and did not include fuel combustion from marine support vessels due to data unavailability. Actual information on consumption at shore base facilities in Guyana would also provide a clearer sense of fuel combustion emissions. Additionally, considerations were excluded for the use of associated gas for other purposes (such as the production of petrochemicals or hydrogen) as no definitive positions have been made in this regard. Furthermore, the estimates did not account for the use of Carbon Capture and Storage (CCS) technology.

Finally, the assumptions applied in the generation of the energy scenarios and the GHG emissions from the government of Guyana ⁴⁶ are unknown and would influence the emissions provided. Additionally, the projected forest sequestration rates were calculated solely on the basis of the past verified deforestation rates from the Guyana Forestry Commission. ¹²

The use of purposive sampling as a non-probability sampling technique may limit the extent to which one can make generalisations from the information provided by the key informants.

Author biographies

Paulette Bynoe is the current Dean of the School of Graduate Studies and Research at the University of Guyana. She is an interdisciplinary trained Environmental Specialist.

Shevon Wood has over 10 years of experience in the energy sector in Guyana. She possesses a BSc in Economics and an MSc in Natural Resources Management.

Denise Simmons is a Senior Lecturer in the Department of Environmental Studies of the Faculty of Earth and Environmental Sciences at the University of Guyana.

Acronyms

UNFCCC

United Nations Framework Convention on Climate Change

HFLD

High forest, low deforestation developing countries

C

Celsius

CBDRC

Common but differentiated responsibilities and respective capabilities

CCS

Carbon capture and storage

CH₄

Methane

CO₂

Carbon dioxide

CO₂e

Carbon dioxide equivalent

COP

Conference of parties

EEPGL

Exploration and production Guyana limited

EF_D

Emission factor

EU-FLEGT

European Union's Forest Law Enforcement, Governance and Trade

FPSO

Floating production storage and offloading

GDP

Guyana's gross domestic product

Gg

Gigagrams

GHG

Greenhouse gas

HFO

Heavy fuel oil

IPCC

Intergovernmental Panel on Climate Change

km

Kilometres

LCDS

Low carbon development strategy

M

Metres

m³

Cubic metres

MRVS

Monitoring Reporting & Verification System

MSCFD

Standard cubic feet per day

N₂O

Nitrous oxide

NCV

Net calorific value

NDCs

Nationally determined contributions

NGL

Natural gas liquids

NLG

Natural liquid gas

Ppm

Parts per million

PV

Photovoltaic

REDD+

Reduce emissions from deforestation and forest degradation

SEA

Strategic Environmental Assessment

SURF

Subsea, umbilicals, risers, and flowlines

TJ

Terrajoules

UNFCCC

United Nations Framework Convention on Climate Change

VPA

Voluntary Partnership Agreement

WMO

World Meteorological Office

Appendix A: Sensitivity Analysis

Lower Range of the Emission Factors

Scenario A: Eight (8) Projects in operation, a 30,000 barrels per day refinery and a 50 MMscfd gas pipeline

Total Emissions
Category	Sub-category	Unit	Scenario 1A	Scenario 2A	Scenario 3A
			2025	2027	2030
			(4 projects + 50 MMscfd gas pipeline)	(6 projects + Refinery + 50 MMscfd gas pipeline)	(8 projects + Refinery + 50 MMscfd gas pipeline)
Well Drilling	Flaring and Venting	Tons CO2e	18,855.98	35,063.86	75,240.21
Well Testing	Flaring and Venting	Tons CO2e	1,283,199.05	2,386,187.99	5,196,780.62
Well Servicing	Flaring and Venting	Tons CO2e	15,864.54	29,501.10	60,437.70
Oil Production (Conventional Oil)	Fugitives Offshore	Tons CO2e	89.74	166.88	343.01
	Venting	Tons CO2e	115,546.04	214,865.01	443,013.69
	Flaring	Tons CO2e	5,848,279.98	10,875,238.30	23,684,121.80
Oil Refining	All	Tons CO2e	0	9.05	22.64
Gas	Fugitives	Tons CO2e	16.15	30.59	67.85
Production	Flaring	Tons CO2e	49.22	93.21	206.77
Gas Processing	Fugitives	Tons CO2e	0.33	0.98	1.95
	Flaring	Tons CO2e	0.93	2.79	5.59
Gas Transmission	Fugitives	Tons CO2e	0.09	0.26	0.52
	Venting	Tons CO2e	0.02	0.07	0.15
Gas Storage	All	Tons CO2e	0.01	0.04	0.08
Sub-total (Fugitive Emissions)		Tons CO2e	7,281,902.09	13,541,160.14	29,460,242.57
Petroleum Refining	Combustion for Oil Refining	Tons CO2e	0	257,763.00	644,760.60
Other Energy Industries	Fuel Gas for FPSO	Tons CO2e	7,539,298.12	13,580,632.85	29,128,152.92
	Diesel Use	Tons CO2e	2,402,338.69	3,198,031.63	4,392,661.03
Civil Aviation	Domestic Aviation	Tons CO2e	433,713.77	505,026.55	612,093.40
Sub-total (Combustion Emissions)		Tons CO2e	10,375,350.58	17,541,454.02	34,777,667.95
Direct Emissions (Fugitive + Other Energy Industries)		Tons CO2e	17,223,538.90	30,577,587.61	63,625,817.12
Indirect Emissions		Tons CO2e	433,713.77	505,026.55	612,093.40
Total Emissions		Tons CO2e	17,657,252.67	31,082,614.16	64,237,910.52
Annual Emissions		Tons CO2e/year	5,279,455.41	7,713,247.47	11,695,839.06
Annual Fugitive Emissions		Tons CO2e/year	2,394,820.14	3,625,895.04	5,624,783.57
Annual Combustion Emissions		Tons CO2e/year	2,884,635.27	4,087,352.43	6,071,055.49

Scenario B: Eight (8) Projects in operation, a 30,000 barrels per day refinery and a 120 MMscfd gas pipeline

Total Emissions
Category	Sub-category	Unit	Scenario 1B	Scenario 2B	Scenario 3B
			2025	2027	2030
			(4 projects + 120 MMscfd gas pipeline)	(6 projects + Refinery + 120 MMscfd gas pipeline)	(8 projects + Refinery + 120 MMscfd gas pipeline)
Well Drilling	Flaring and Venting	Tons CO2e	18,855.98	35,063.86	75,240.21
Well Testing	Flaring and Venting	Tons CO2e	1,283,199.05	2,386,187.99	5,196,780.62
Well Servicing	Flaring and Venting	Tons CO2e	15,864.54	29,501.10	60,437.70
Oil Production (Conventional Oil)	Fugitives Offshore	Tons CO2e	89.74	166.88	343.01
	Venting	Tons CO2e	115,546.04	214,865.01	443,013.69
	Flaring	Tons CO2e	5,848,279.98	10,875,238.30	23,684,121.80
Oil Refining	All	Tons CO2e	0	9.05	22.64
Gas	Fugitives	Tons CO2e	16.15	30.59	67.85
Production	Flaring	Tons CO2e	49.22	93.21	206.77
Gas Processing	Fugitives	Tons CO2e	0.78	2.34	4.69
	Flaring	Tons CO2e	2.23	6.70	13.41
Gas Transmission	Fugitives	Tons CO2e	0.21	0.62	1.24
	Venting	Tons CO2e	0.06	0.18	0.35
Gas Storage	All	Tons CO2e	0.03	0.09	0.19
Sub-total (Fugitive Emissions)		Tons CO2e	7,281,904.02	13,541,165.93	29,460,254.17
Petroleum Refining	Combustion for Oil Refining	Tons CO2e	0	257,763.00	644,760.60
Other Energy Industries	Fuel Gas for FPSO	Tons CO2e	7,539,298.12	13,580,632.85	29,128,152.92
	Diesel Use	Tons CO2e	2,402,338.69	3,198,031.63	4,392,661.03
Civil Aviation	Domestic Aviation	Tons CO2e	433,713.77	505,026.55	612,093.40
Sub-total (Combustion Emissions)		Tons CO2e	10,375,350.58	17,541,454.03	34,777,667.95
Direct Emissions (Fugitive + Other Energy Industries)		Tons CO2e	17,223,540.83	30,577,593.41	63,625,828.72
Indirect Emissions		Tons CO2e	433,713.77	505,026.55	612,093.40
Total Emissions		Tons CO2e	17,657,254.60	31,082,619.96	64,237,922.12
Annual Emissions		Tons CO2e/year	5,279,455.73	7,713,248.19	11,695,840.11
Annual Fugitive Emissions		Tons CO2e/year	2,394,820.46	3,625,895.76	5,624,784.62
Annual Combustion Emissions		Tons CO2e/year	2,884,635.27	4,087,352.43	6,071,055.49

Upper Range of the Emission Factors

Scenario A: Eight (8) Projects in operation, a 30,000 barrels per day refinery and a 50 MMscfd gas pipeline

Total Emissions
Category	Sub-category	Unit	Scenario 1A	Scenario 2A	Scenario 3A
			2025	2027	2030
			(4 projects + 50 MMscfd gas pipeline)	(6 projects + Refinery + 50 MMscfd gas pipeline)	(8 projects + Refinery + 50 MMscfd gas pipeline)
Well Drilling	Flaring and Venting	Tons CO2e	320,409.88	595,821.99	1,278,543.99
Well Testing	Flaring and Venting	Tons CO2e	21,385,233.12	39,767,163.50	86,607,615.17
Well Servicing	Flaring and Venting	Tons CO2e	259,730.49	482,984.91	989,502.67
Oil Production (Conventional Oil)	Fugitives Offshore	Tons CO2e	89.74	166.88	343.01
	Venting	Tons CO2e	158,787.20	295,274.62	608,784.85
	Flaring	Tons CO2e	7,987,687.97	14,853,599.75	32,348,258.24
Oil Refining	All	Tons CO2e	0	142.75	357.08
Gas	Fugitives	Tons CO2e	991.05	1,877.03	4,163.78
Production	Flaring	Tons CO2e	65.62	124.28	275.70
Gas Processing	Fugitives	Tons CO2e	0.75	2.25	4.50
	Flaring	Tons CO2e	1.29	3.88	7.76
Gas Transmission	Fugitives	Tons CO2e	0.57	1.71	3.42
	Venting	Tons CO2e	0.39	1.16	2.32
Gas Storage	All	Tons CO2e	0.03	0.09	0.18
Sub-total (Fugitive Emissions)		Tons CO2e	30,112,998.10	55,997,164.80	121,837,862.66
Petroleum Refining	Combustion for Oil Refining	Tons CO2e	0	257,763.00	644,760.60
Other Energy Industries	Fuel Gas for FPSO	Tons CO2e	7,539,298.12	13,580,632.85	29,128,152.92
	Diesel Use	Tons CO2e	2,402,338.69	3,198,031.63	4,392,661.03
Civil Aviation	Domestic Aviation	Tons CO2e	433,713.77	505,026.55	612,093.40
Sub-total (Combustion Emissions)		Tons CO2e	10,375,350.58	17,541,454.03	34,777,667.95
Direct Emissions (Fugitive + Other Energy Industries)		Tons CO2e	40,054,634.91	73,033,592.28	156,003,437.21
Indirect Emissions		Tons CO2e	433,713.77	505,026.55	612,093.40
Total Emissions		Tons CO2e	40,488,348.68	73,538,618.83	156,615,530.61
Annual Emissions		Tons CO2e/year	12,787,997.23	19,081,623.95	29,335,816.48
Annual Fugitive Emissions		Tons CO2e/year	9,903,361.96	14,994,271.52	23,264,760.99
Annual Combustion Emissions		Tons CO2e/year	2,884,635.27	4,087,352.43	6,071,055.49

Scenario B: Eight (8) Projects in operation, a 30,000 barrels per day refinery and a 120 MMscfd gas pipeline

Total Emissions
Category	Sub-category	Unit	Scenario 1B	Scenario 2B	Scenario 3B
			2025	2027	2030
			(4 projects + 120 MMscfd gas pipeline)	(6 projects + Refinery + 120 MMscfd gas pipeline)	(8 projects + Refinery + 120 MMscfd gas pipeline)
Well Drilling	Flaring and Venting	Tons CO2e	320,409.88	595,821.99	1,278,543.99
Well Testing	Flaring and Venting	Tons CO2e	21,385,233.12	39,767,163.50	86,607,615.17
Well Servicing	Flaring and Venting	Tons CO2e	259,730.49	482,984.91	989,502.67
Oil Production (Conventional Oil)	Fugitives Offshore	Tons CO2e	89.74	166.88	343.01
	Venting	Tons CO2e	158,787.20	295,274.62	608,784.85
	Flaring	Tons CO2e	7,987,687.97	14,853,599.75	32,348,258.24
Oil Refining	All	Tons CO2e	0	142.75	357.08
Gas	Fugitives	Tons CO2e	991.05	1,877.03	4,163.78
Production	Flaring	Tons CO2e	65.62	124.28	275.70
Gas Processing	Fugitives	Tons CO2e	1.80	5.40	10.80
	Flaring	Tons CO2e	3.10	9.31	18.62
Gas Transmission	Fugitives	Tons CO2e	1.37	4.10	8.20
	Venting	Tons CO2e	0.93	2.78	5.56
Gas Storage	All	Tons CO2e	0.07	0.22	0.43
Sub-total (Fugitive Emissions)		Tons CO2e	30,113,002.34	55,997,177.52	121,837,888.11
Petroleum Refining	Combustion for Oil Refining	Tons CO2e	0	257,763.00	644,760.60
Other Energy Industries	Fuel Gas for FPSO	Tons CO2e	7,539,298.12	13,580,632.85	29,128,152.92
	Diesel Use	Tons CO2e	2,402,338.69	3,198,031.63	4,392,661.03
Civil Aviation	Domestic Aviation	Tons CO2e	433,713.77	505,026.55	612,093.40
Sub-total (Combustion Emissions)		Tons CO2e	10,375,350.58	17,541,454.03	34,777,667.95
Direct Emissions (Fugitive + Other Energy Industries)		Tons CO2e	40,054,639.15	73,033,605.00	156,003,462.66
Indirect Emissions		Tons CO2e	433,713.77	505,026.55	612,093.40
Total Emissions		Tons CO2e	40,488,352.92	73,538,631.55	156,615,556.06
Annual Emissions		Tons CO2e/year	12,787,997.23	19,081,625.54	29,335,818.79
Annual Fugitive Emissions		Tons CO2e/year	9,903,361.96	14,994,273.10	23,264,763.30
Annual Combustion Emissions		Tons CO2e/year	2,884,635.27	4,087,352.43	6,071,055.49