GLOBAL SUMMARY OIL & GAS - Week Commencing 15th March MAR 2021 - Fitch Solutions
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MAR 2021 GLOBAL SUMMARY OIL & GAS Week Commencing 15th March
Global Summary Oil & Gas | 20210315
Contents
Global ................................................................................................................................................................................................. 4
Global Oil & Gas Projects Round-Up ..................................................................................................................................................................................... 4
Asia..................................................................................................................................................................................................... 6
Altona Closure To More Than Halve Australia's Refining Capacity By 2022.......................................................................................................... 6
PMB Phase II Expansion To Drive Another Leg Up In Brunei's Fuel Exports .......................................................................................................... 9
China's 14th Five-Year Plan: Climate Targets Underwhelm But Gas Outlook Constructive .........................................................................12
Europe .............................................................................................................................................................................................16
UK Natural Gas Self-Sufficiency To Deteriorate Over The Decade ........................................................................................................................16
Latin America................................................................................................................................................................................21
Colombia's Natural Gas Production Growth To Accelerate Over Medium-To-Long Term.............................................................................21
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THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 3Global Summary Oil & Gas | 20210315 Global Global Oil & Gas Projects Round-Up Week beginning February 15 - Major oil and gas project updates across the upstream, midstream, downstream, LNG and low carbon sectors. EXPLORATION India: Adani Welspun Exploration (AWEL) has announced its first ever gas discovery in offshore block MB-OSN-2005/2, which was awarded to AWEL in the NELP-VII bidding round. There were three potential hydrocarbon zones identified and two of these spudded had substantial gas and condensate flow to the surface. The block is located off India’s west coast, in the Mumbai basin, where early seismic data located the Mahuva and Daman formations as containing substantial quantities of gas and condensate. AWEL is a 65:35 joint venture between Adani Group and Welspun Enterprises. It is the operator of the block and holds 100% interest. Suriname: Tullow Oil reported that its Goliathberg-Voltzberg North exploration well has reached total depth and encountered good quality reservoir rocks, but minor hydrocarbon shows. The well, drilled by Stena Forth to a total depth of 5,060m in water depths of 1,856m, will now be plugged and abandoned. The well is located in Block 47, where Tullow is the operator (50%), with Petroandina Resources Corporation N.V. holding 30% and Ratio Suriname Limited the remaining 20%. Colombia: ExxonMobil has submitted a proposal to carry out a pilot fracking project in Colombia’s Valle Medio del Magdalena basin, according to Colombia’s national hydrocarbons agency (AHN). If approved, ExxonMobil would be the second company to start a fracking pilot project in the country, following Colombia’s majority state-owned oil company, Ecopetrol. Currently, commercial development of non-conventional hydrocarbon deposits such as shale gas and coal bed methane is prohibited. The project would seek to acquire data that would inform future decisions on the development of non-conventional deposits. Norway: Chrysaor Norge AS has found hydrocarbons from logs and cuttings upon entering the reservoir in the Jerv exploration well and coring will now be initiated. Operations at the well are at an early stage and final results are not yet ready. The well is operated by Chrysaor Norge AS (50%), with OKEA ASA (30%) and Petoro AS (20%) in the PL 973 license. Mexico: Pemex has reportedly discovered a new oil field, containing between 500-600mn boe, in the Southern Gulf of Mexico. The field has been compared to the recently discovered gas and condensate field Quesqui, which contained 900mn boe. UPSTREAM China: CNOOC announced that its Caofeidian 6-4 Oilfield has commenced production. The Caofeidian 6-4 Oilfield is located offshore in average water depths of 20m, in the mid-west of Bohai. In addition to utilising existing processing facilities of the nearby Nanpu 35-2 and Qinhuangdao 32-6 oilfields, a new central platform will be built. 42 development wells are planned which includes 30 production wells and the remaining 12 for water injection and water source wells. Peak production is not expected until 2023, where the field will produce 15,000b/d. UK: Serica Energy reported the spud of the Columbus 23/16f-CDev1 development well in the central UK North Sea. It will be drilled by the Maersk Resilient Heavy Duty Jack Up rig to a total depth of 5,360m, include a 1,700m horizontal section and take around 70 days. The Columbus development area is 35km of the Shearwater production facilities and will be drained by a single producing well, which will be tied back to Shearwater using the Arran pipeline. Production will reach 7,000boe/d, of which 70% is gas, and is expected to begin in Q4 2021. THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research. fitchsolutions.com 4
Global Summary Oil & Gas | 20210315 MIDSTREAM Uganda: Standard Bank has suspended its role in Uganda’s East African Crude Pipeline (EACOP), waiting for the results of an environmental and social impact study. The decision succeeds the publication of an open letter written by 263 NGOs, claiming that 14,000 households would lose land if EACOP followed the proposed route, water resources in the Lake Victoria basin and other biodiverse areas would be threatened. The project was expected by the end of March 2021. LOW CARBON UK: Eni announced that the Hynet North West project had received GBP33mn in funding from UK Research and Innovation (UKRI), which is aimed at decarbonising the UK’s North-West industrial cluster. The funding covers approximately 50% of the costs to finalise ongoing planning studies, with the aim of becoming operational by 2025. The intention of the site is to capture, transport and store carbon dioxide from existing industries or future sites producing blue hydrogen. It will be the first carbon capture and storage (CCS) infrastructure in the UK. Eni’s role, in the consortium operating the project, will be to transport and store the CO2 in its depleted hydrocarbon reservoirs, located around 18 miles offshore Liverpool Bay. Eni was awarded a carbon storage license by the UK Oil & Gas Authority (OGA) in October 2020. UK: bp is developing plans for the UK’s largest blue hydrogen production facility with aims to produce 1GW by 2030. The project, located in Teeside, would provide 20% of the UK’s hydrogen target and support development of the North-East region as the UK’s first hydrogen transport hub. The project is ideally located in close proximity to North Sea storage sites with plentiful existing infrastructure and would capture and send up to two million tonnes of CO2 per year for storage. The Teeside industrial cluster accounts for over 5% of the UK’s industrial emissions and also home to five of the UK’s top 25 carbon emitters. THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research. fitchsolutions.com 5
Global Summary Oil & Gas | 20210315
Asia
Altona Closure To More Than Halve Australia's Refining Capacity By 2022
Key View:
• Another oil refinery in Australia has been earmarked to shut after ExxonMobil determined that maintaining operations at its
Altona refinery will no longer be economically viable.
• As a consequence, Australia’s refining capacity stands to be more than halved over the next few quarters, and in the process,
leaves the country staring at the prospect of a significant increase in dependence on foreign fuel imports.
• The imminent sharp surge in Australia’s deficit in fuels will be most welcomed by the region’s net fuel exporters facing an
increasingly crowded market although crude suppliers stand to lose out.
Another oil refinery in Australia has been earmarked to shut after ExxonMobil determined that maintaining
operations at its Altona refinery will no longer be economically viable. In February 2021, ExxonMobil made public the
decision to permanently shut down its oil refinery in Altona, Victoria after having considered a multitude of factors including
competition from imports, declining domestic oil production and high capital cost structure of operating in the mature Australian
market. The 90,000b/d capacity Altona is the second Australian refinery to announce closure plans in the span of the past six
months, after BP’s earlier decision to close Australia’s largest refining facility in Kwinana, Perth.
Oil refinery closures have been a recurring feature in the Australian refining sector over the past decade, as refineries have had
especially hard times competing with larger, more-sophisticated refineries sprouting up across the region, due to high cost, logistics
and technological headwinds. For instance, before the Kwinana closure, BP also shut down its 102,000b/d capacity refinery in
Bulwer Island in the middle of 2015 citing poor margins and inability to compete with region’s mega-refineries, while Shell also
brought offline its 79,000b/d plant in Sydney back in October 2012.
Capacity Cuts To Drive-Up Import Dependence
Australia - Refining Capacity, Fuel Demand & Net Fuel Exports, 000b/d
Note: negative implies imports. f = Fitch Solutions forecast. Source: JODI, Fitch Solutions
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 6Global Summary Oil & Gas | 20210315
The closure of Altona and Kwinana leaves Australia with just two active refineries, although the fates of both also seemingly hang in
the balance. For instance, Ampol, formerly Caltex Australia, is undertaking a comprehensive review of its refining operations at
the 109,000b/d Lytton refinery over H1 2021. Following the review, the firm will decide whether to permanently close the facility,
continue operations as per normal or come up with an alternative operating model. Australia’s new largest remaining refinery the
120,000b/d capacity Geelong has averted closure for now, after financial intervention from the federal government. Financial
support, known as the interim refinery production payment (IRPP), will be paid out to domestic refiners over January to July 2021, to
help them maintain operations and improve fuel security. Funds will be collected from the Australian taxpayers via an additional levy
of AUD1.15 imposed on per liter of gasoline, diesel and jet fuel sold from domestic refineries. Geelong operator Viva Energy, which
previously mulled shutting down the facility in mid-2020, confirmed that it would require refining margins stay on an upward
trajectory, for it to be able to maintain refining operations once the IRPP concludes at the end of July.
Import Bill To Grow
Australia - Fuel Import Bill, USDbn (LHS) & Implied Import Dependence, % (RHS)
e = estimate based on 2020 average fuel import prices. Source: Trade Map ITC, Fitch Solutions
As a consequence, Australia’s refining capacity stands to be more than halved over the next few quarters, and in the
process, leaves the country staring at the prospect of a significant increase in dependence on foreign fuel imports.
The announced capacity closures will be fully reflected in our forecasts from 2022, at which point, Australia’s refining capacity is
expected to dwindle to a multi-decade low of 226,000b/d, down from 462,000b/d in 2020. This in turn, would see Australia’s fuel
import dependence surge to a new high, climbing from as low as 36% in 2013 and 56% in 2020 to 84% in 2022. The potential
closure of Lytton and/or Geelong risks further adding on to this figure, and should both refineries choose to shut down operations
in the coming quarters, Australia risks becoming fully dependent on fuel imports to meet demand like neighbor New Zealand has
recently become. This also implies a steeper import bill for Australia moving forward. Australia spent USD11.4bn on fuel imports in
2020, down from the pre-Covid level of USD17.6bn in 2019. Based on Australia’s averaged fuel import price in 2020 and our current
projections for refining capacity closures and demand growth over the coming years, Australia’s import bill could surpass the
USD19bn mark by 2026, which would mark the highest amount it has spent on fuel imports since 2018.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 7Global Summary Oil & Gas | 20210315
Crude Suppliers Stand To Lose Out
Australia - % Share Of Crude Oil & Refined Fuels Imports
Source: Trade Map ITC, Fitch Solutions
The imminent sharp surge in Australia’s deficit in fuels will be most welcomed by the region’s net fuel exporters
facing an increasingly crowded market although crude suppliers stand to lose out. The imminent drop off in crude
demand will come as a blow for Australia’s crude suppliers including Malaysia, the UAE and USA that together provide about 60% of
Australia’s annual crude needs, leaving them to compete to gain market shares in new crude markets such as Indonesia, Pakistan
and Vietnam. The loss in refining output will also leave Australia with large deficits in refined fuels including gasoline and diesel to fill
offering opportunities to several of the region’s net fuel exporters to boost market share. The four largest fuel exporters to Australia
include Singapore, South Korea, China and Malaysia, and all but Singapore have added refining capacities or have plans to expand
capacities over the coming years. Brunei has also been stepping up shipments to Australia buoyed by new output from its newbuild
refining complex at Pulau Muara Besar, and is also prepared to gain from the looming widening of the fuel deficit in Australia.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 8Global Summary Oil & Gas | 20210315
PMB Phase II Expansion To Drive Another Leg Up In Brunei's Fuel
Exports
Key View:
• Brunei’s upstream oil and gas sector remains in decline as existing fields mature and new investments slow.
• In contrast, the domestic downstream sector has seen a major positive shift.
• A second phase expansion of the PMB refinery would solidify Brunei’s newfound role as a net fuel exporter.
Brunei’s upstream oil and gas sector remains in decline as existing fields mature and new investments slow. Once a
sizable net exporter of crude oil, Brunei’s crude output has not been able to break out of a downward trend stretching back to 2006.
The government has set ambitious targets for exploration and output volumes in an effort to breathe life into the sector, but has
seen limited success to date. The latest target calls for domestic oil and gas production to reach 650,000boed in 2035, although the
scope of it being met remains low, absent significant new finds and/or influx of new FDIs. The target would require total output to
overshoot the previous output peak of 450,000boed in 2006 by more than 44%, and more than double from where production
currently stands at about 321,000boed. FDI interest looks to be on a falling trend, with Total and Murphy Oil among those have
exited or believed to be contemplating stake divestments. Shell, the largest oil and gas producer in the sector remains committed.
The firm identified Brunei as one of nine of its ‘core’ markets in its latest strategic announcement in 2020. However, given the
upstream-focused nature of its operations in Brunei, is unlikely to raise the amount of capex allocated to the market in near-term as
it focuses on tightening spending, lowering fossil fuels exposure and expanding decarbonisation efforts.
2035 Target Looks Out Of Reach
Brunei - Crude Oil & Natural Gas Production vs 2035 Target, boed
f = Fitch Solutions forecast. Source: JODI, Fitch Solutions
In contrast, the domestic downstream sector has seen a major positive shift. The start of private Chinese refiner Hengyi
Petrochemical’s 160,000b/d capacity Pulau Muara Besar (PMB) refinery at the end of 2019 has proven to be a game changer. It
has driven a massive 18-fold expansion in refining output adding onto singular output from Shell’s small-scale refinery at Seria. In
addition, nominal GDP contribution from the LNG and refined fuels manufacturing sector grew by 9% compared to a year ago, and
about 40% from 2016-2017 when Brunei’s LNG production is shown to have peaked. PMB has also driven an upsurge in demand,
due to improved consumer access to fuels. Even factoring in downside pressure from Covid-19, domestic fuel demand still grew by
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 9Global Summary Oil & Gas | 20210315
a robust 55% on year in 2020. The refinery also caused a profound shift in Brunei’s oil trade mix, effectively wiping out its historical
surplus in crude due to significant import requirements to feed the refinery, and instead, enabling fuel exports out to regional
markets.
PMB Bolsters Contribution From Non-Crude Oil Manufacturing
Brunei - Nominal GDP Contribution From LNG, Methanol & Refined Fuels, BNDmn (LHS) & % Of Total GDP (RHS)
Source: Department Of Economic Planning And Development, Fitch Solutions
A second phase expansion of the PMB refinery would solidify Brunei’s newfound role as a net fuel exporter. Lead
developer Hengyi has already committed to a second phase expansion of PMB, planning to more than double the refinery’s current
capacity to 455,000b/d, next to more than 7mtpa of petrochemicals manufacturing capacity. Added output from the planned
expansion will again be export-oriented, and will allow Brunei to offset the cost of importing crude via selling higher-value products
out to the region. There are obvious downside risks, as the plan may encounter delays or even be called off. A growing regional
refining capacity overhang also remains a concern, more so amid a softer demand growth outlook due new norm brought on by
the Covid-19 pandemic. This has already led to a number of smaller, less-modernised refineries across the region to announce
consolidation plans or permanent closures, and PMB Phase II will need to be sufficiently upscale to be competitive.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 10Global Summary Oil & Gas | 20210315
Sector Due For Further Expansion
Brunei - Refining Capacity, Refined Fuels Consumption & Net Refined Fuels Exports, 000b/d
f = Fitch Solutions forecast. Source: JODI, Fitch Solutions
In spite of these challenges, Hengyi’s intended expansion is factored into our forecasts. Brunei’s attraction as a regional fuel export
hub is clear, due to its strategic placement and favorable incentives including generous tax incentives for foreign investors. For
instance, Hengyi holds the ‘pioneer company’ status in Brunei, and is entitled to 11-years of exemption from corporate income tax
and import duties on machinery and raw materials. The ‘pioneer’ status is awarded to companies that operate in an industry that is
yet to reach commercial scale in Brunei, offers favorable further development prospects, particularly those with potential to
contribute to exports, and is deemed to be in the interest of the public. Establishing a position in Brunei is also aligned with the
strategic objectives of the Belt & Road Initiative (BRI), providing China with a footing to project influence across the regional through
control of a key trading route and physical infrastructure. The plan is to bring these online in 2023 for an estimated fee of
USD13.6bn. Even assuming a conservative 65% utilisation in first three years of PMB II’s operation, this would be sufficient to more
than double Brunei’s refining output and net fuel exports between 2022 and 2025.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 11Global Summary Oil & Gas | 20210315
China's 14th Five-Year Plan: Climate Targets Underwhelm But Gas
Outlook Constructive
Key View
• China’s 14 Five-Year Plan (FYP), which will run from 2021 to 2025, failed to meet expectations for Beijing to set more stringent
policies to tackle climate change and lay out clear paths to realising its de-carbonisation and energy transition ambitions.
• Instead, it confirmed that Beijing’s focus in the immediate future will lie in implementing President Xi Jinping’s ‘dual circulation’
macroeconomic framework and eradicating deficits in several key technologies, while further improving energy self-sufficiency.
• The 14th FYP is also light in offering concrete action plans to achieving China’s long-term climate targets, and carries limited
specific mentions of oil and gas sector in general. This makes it likely that the current status quo, where natural gas and lower-
sulphur refined fuels are taking on leading roles in the national energy mix, will be maintained for some time.
• All signs point to more ‘sector-specific’ goals and policies being made available towards the end of the current year or early next
year, when the central government is expected to hold another round of meetings.
China’s 14 Five-Year Plan (FYP) which will run from 2021 to 2025 failed to meet expectations for Beijing to set more
stringent policies to tackle climate change and lay out clear paths to realizing its de-carbonisation and energy
transition ambitions. Instead, it confirmed that Beijing’s focus in the immediate future will lie in implementing President Xi
Jinping’s ‘dual circulation’ macroeconomic framework and eradicating deficits in several key technologies, while further improving
energy self-sufficiency. Climate considerations had appeared to be at the forefront of Beijing’s policymaking agenda in the lead up
to the approval of the 14th FYP, more so after President Xi Jinping announced in 2020 the ambition to peak CO2 emissions before
2030 and reach net zero carbon emissions before 2060.
However, the 14th FYP carries only limited mentions about de-carbonising the energy sector specifically, apart from targets for
reducing energy intensity and carbon intensity per unit of GDP – both of which have already been established prior and were just
reaffirmed. The two reduction targets make up two of five ‘binding targets’ outlined for energy and climate change under the
broader ‘economic and social development’ umbrella. In spite of China’s history of overachieving its targets, the numbers are far
from ambitious, having been kept unchanged or set lower than those in the previous FYP.
Binding Reduction Targets Conservative
Select 14th Five-Year Plan Binding Targets - Carbon Emissions % Reduction Per Unit Of GDP (LHC) & Energy Consumption %
Reduction Per Unit Of GDP (RHC)
* Energy consumption reduction target for 13th FYP reportedly abandoned due to the Covid-19 pandemic. Source: China 14th Five-Year Plan, Fitch Solutions
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 12Global Summary Oil & Gas | 20210315
While this does not necessarily indicate diversion from China’s long-term commitment to achieving its climate aims, it does appear
to signal that its immediate interests will lie elsewhere, namely the aforementioned economic growth strategy and alleviating the
vulnerability in tech. With regard to overall energy supply, the FYP places strong emphasis on boosting the production of and self-
sufficiencies in emissions-heavy fossil fuels such as coal, petroleum and natural gas, which suggests that the pace of climate-related
reforms in China will be slower than previously thought. The other three binding targets include broad aims to improve qualities and
coverage rates of air, surface water and forests. While the target for non-fossil fuels' share in the energy mix is set higher than in
previous FYPs, it is no longer a binding target and therefore will be subject to less rigorous scrutiny.
The 14th FYP is also light in offering concrete action plans to achieving China’s long-term climate targets, and
carries limited specific mentions of oil & gas sector in general. This makes it likely that the current status quo, where
natural gas and lower-sulphur refined fuels are taking on leading roles in the national energy mix, will be maintained
for some time. The 14th FYP continues to place emphasis on improving domestic production and the development of fossil fuels
such as oil and gas, as well as coal, so as to safeguard national energy security. This indicates that much like its desire to address the
vulnerability in tech - namely the heavy dependence on imports - the immediate aim for China in the context of energy will also be
on reducing the currently large dependence on imports, before shifting focus to longer-term climate aims.
Gas Outlooks Continues To Be Constructive
China - Change In Gas Demand Over Five-Year Periods
Source: National sources, JODI, Fitch Solutions
The focus on growing fossil fuels production in turn, further supports the outlook for natural gas. China’s policies over the past five
years have led to a huge ramp up in domestic gas demand, as industries and households were pushed to make the switch from
coal, and to lesser extent, diesel, and opt for the cleaner burning gas. Gas demand saw a 55% jump during the duration of the 13th
FYP (2016-2020), equivalent to absolute volume growth of about 114.3bcm, the largest five-year increase on record, spurred on by
the government’s coal-to-gas switching policies. That period also coincided with China surpassing South Korea to become the
world’s second largest importer of LNG after Japan, and the largest importer of gas overall when also factoring in large pipeline gas
inflows. The period also saw the long-mulled creation of PipeChina finally come to fruition, putting in place a state-vehicle to
facilitate stronger, more efficient gas consumption, manage large national oil and gas pipeline assets and attract investments into
the midstream both from domestic and foreign origins.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 13Global Summary Oil & Gas | 20210315
LNG Prospers As Gas Embraced
Select Asia Markets - Net LNG Imports, bcm
f = Fitch Solutions forecast. Source: National sources, JODI, Fitch Solutions
The 14th FYP, while lacking in oil and gas mentions, did specifically highlight the need to accelerate the construction of natural gas
network pipelines, which suggests that expanding and developing the midstream sector still remains one of the government’s top
priorities for the oil & gas sector. This makes sense given the emphasis on improving production and the aggressive annual output
targets that have been set for unconventional gas. Even after missing out on 2020 targets, output targets for shale, tight gas and
CBM have been raised even higher for the coming five-year period and would require comparable investments and expansion
efforts in infrastructure to reach these targets. China is still has some way to go in terms of gas infrastructure, with total gas pipeline
length still lagging that of the US and Russia by a factor of 26.1 and 2.3 respectively. In addition, total storage capacity for gas of
about 13bcm is only sufficient for less than 15 days of forward cover, indicating that there is still room for growth in these areas. Oil-
fuel consumption will continue to grow in volume terms, although the pace of growth looks set to slow over the duration of the
14th FYP as China pursues higher-quality, lower-carbon growth. There is already bias being shown for low-sulphur, more efficient
grade fuels, a trend that has been playing out even before the approval of the 14th FYP and is expected to become more
pronounced over the coming years next to tightening environmental regulations and efforts to decarbonise.
All signs point to more sector-specific goals and policies being made available towards the end of the current year or
early next year, when the central government is expected to hold another round of meetings. As was the case after the
adoption of the 12th and 13th FYPs, more sector-specific targets for the coming five-year period are expected to be made available
later as different ministries meet to break down broad targets across provinces and administrative levels, before rolling out detailed
action plans for implementation and evaluation. The lack of specifics in the 14th FYP means there will be plenty to look forward
to, including the government’s stance towards coal and power generation mix targets; both of which stand to have significant
influence over the developments of gas and other renewable fuel sources, and instil confidence in national efforts to achieve long-
term climate aims. In addition, the forthcoming meetings will also be key in establishing the roadmap to meeting President Xi’s ‘peak
CO2 emissions 2035’ and ‘net zero 2060’ targets.
In the context of oil and gas, the stance against coal will be of particular interest. The FYP appears to express continued support for
the coal sector, albeit under the condition of clean and efficient utilisation, which will be achieved through the adoption of
emissions reduction tech across coal plants to minimise sulphur and particulate pollution. In addition, the amount of coal-fired
power generation capacity still in the pipeline even after years of robust coal-to-gas switching is substantial and enough to cast
doubts over China’s climate pledges. If China is serious about cutting CO2 emissions and energy transition efforts, a meaningful
number of these would likely need to be scrapped or converted to run on alternatives which would be at potentially large capital
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 14Global Summary Oil & Gas | 20210315 costs. It also remains to be seen how or if the government would look to impose carbon emission caps over pollutive sectors like autos, agriculture, infrastructure, households, mining as well as oil & gas. The FYP points to the need for such a cap to limit both the intensity of carbon emissions and total emissions in absolute volume terms although did not set ‘top-down’ targets for individual provinces to meet. A bottom-up approach under which local governments would be able to set own initiatives to control emissions is reportedly being mulled instead according to reports. China has also launched the national carbon emissions trading scheme for power producers in February 2021, raising the cost for emitters while incentivising upgrades, and the plan is to broaden the coverage to include firms from a total of eight pollutive sectors namely chemicals, construction, non-ferrous metals, oil, papermaking, power generation, shipping and steel. THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research. fitchsolutions.com 15
Global Summary Oil & Gas | 20210315 Europe UK Natural Gas Self-Sufficiency To Deteriorate Over The Decade Key View • The UK’s domestic gas production, after the peak of its resurgence in 2021, is to begin a steady decline to 28bcm by 2030, a drop of 33% from 2021. • Gas consumption growth is to peak at 3% in 2021, after which growth slows and then demand plateaus at around 86.6bcm by 2028. • The UK’s reliance on imports will increase from around 50% of consumption in 2020, to more than 75% by 2030. The UK’s domestic gas production, after the peak of its resurgence in 2021, is to begin a steady decline to 28bcm by 2030, a drop of 33% from 2021. In 2013, the UK’s domestic gas production increased for the first time since its peak in 2000, after 13 years of high decline rates at its ever-maturing fields. New gas field start-ups from 2013 onwards successfully reversed the state of decline to an average 1% y-o- y growth until a plateau in 2019-2020. Whilst the average growth rate over the period is small, the change in trend is significant considering the decline rates of the preceding years. The trend of decline returns in 2021, in which we forecast a 4.7% contraction. Gas production for 2021 represents 50% of the UK’s gas consumption at 39.6bcm, following the start-up of the Culzean field in 2019 and the Tolmount field which is expected to come online in H121. UK domestic production has hovered at around 50% of the UK’s demand requirements for the last decade, however this is set to worsen after 2021 when production is forecast to meet only around 33% of the UK’s growing demand by 2030, leaving the UK as a significant importer. Were it not for the production from the Culzean field and Tolmount field, the lack of exploration would be even more keenly felt in the 2020s, where decline would be much more pronounced and the UK would rely more heavily on imports. The poor outlook for production, post 2021, can be put down to the lack of exploration, which has declined over the previous five years. Whilst several successful discoveries have been developed, lower oil prices and high costs have stymied exploration and drilling in the UK’s North Sea. This has led to to only one active exploration well and one active appraisal well so far in early 2021, with plans for only two more this year. Whilst exploration looks bleak for 2021 and 2022, there exists some upside to the UK’s gas production, primarily in side-tracking and step-out developments from existing resource bases, which could offset the decline rates at some maturing fields. Also, the Glengorm discovery, similar in size to the Culzean field at around 250mn boe, would boost the UK’s production in the mid-2020s if developed. CNOOC, with partners Total and Energean, are spudding the Glengorm South 22/26d-3 appraisal well, which will take around 300 days. This will be followed by a second appraisal well in block 22/21c. We expect results from the wells in late 2021 or early 2022. THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research. fitchsolutions.com 16
Global Summary Oil & Gas | 20210315
UK's Gas Production Decline Accelerates Over The Medium-term
Gas Production (2019-2030f)
e/f = Fitch Solutions estimate/forecast. Source: EIA, JODI, Fitch Solutions
Gas consumption growth is to peak at 3% in 2021, after which growth slows and then plateaus at 82.4bcm by 2028.
The UK’s natural gas consumption profile has fluctuated significantly over the previous two decades, but declined substantially, by
around 27bcm, between 2010 and 2014. This decline was reversed up to 2016, supported by coal to gas switching in power
generation, where the UK turned to natural gas as a cleaner alternative to coal. Consumption remained somewhat stable until 2020,
when Covid-19 led to an estimated 4% drop in consumption. This was slightly more robust than our initial estimate for 2020, which
was for a 7% contraction and as a result has a smaller base effect for 2021. We maintain our forecast of 3% growth in 2021, due to
the UK’s success in rolling out the Covid-19 vaccine and expected economic recovery expected over 2021. This will mark the peak
growth rate for the 2020s, after which we forecast an average 1.6% growth between 2022-2024, where consumption plateaus at an
estimated 82.4bcm.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 17Global Summary Oil & Gas | 20210315
Domestic Users And Power Generation Dominate UK Gas Consumption
UK Gas Consumption Breakdown, %
Source: UK Department for Business, Energy & Industrial Strategy, Fitch Solutions
Gas demand in the UK is dominated by domestic use and power generation, which together form 68% of total UK gas
consumption. Power generation is the only sector in which we see some growth that will support the UK’s gas consumption until
2024. The first factor is the UK’s aging nuclear fleet, where power generation will fluctuate over the forecast period owing to plant
closures, plant life extensions and new projects coming online towards the end of the decade. Reserve gas fleet demand will remain
high in the UK, for security of supply should nuclear fall offline or renewables underperform. The scanty future plans to replace the
ageing fleet only leads to further upside risk for gas consumption in the UK. Another upside is intermittency in power demand, often
met by coal-gas switching in power generation. Whilst most coal-gas switching has already occurred, illustrated in 2020 where
several records for coal free streaks were broken, coal does still see a resurgence periods of cold weather and poor renewable
generation. This was evident during the recent cold snap in the UK, where coal made up 7% of power generation on January 8
2021. A huge increase from 2020, where coal made up just 1.6%. By 2024, the UK will shut all coal-fired power plants and this lends
upside for natural gas demand, however our Power Team note that the large increase in interconnectors with Europe will partially
mitigate this issue.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 18Global Summary Oil & Gas | 20210315
UK Consumption Grows Over Medium-term
Gas Consumption Forecast By Year (2019-2030f)
e = Fitch Solutions forecast. Source: JODI, Fitch Solutions
The UK’s reliance on imports will increase from around 50% of consumption in 2020, to more than 75% by 2030.
The UK was initially a gas importer until 1997, when booming production in the North Sea led to the UK becoming a net exporter
with exports peaking in 2000. Between 2000-2010, the UK transitioned from exporting 20bcm to importing 39bcm, a significant
swing. Over the decade since, a resurgence in gas production and fluctuating gas demand have seen imports stabilise to provide
around 50% of total UK consumption. Imports reached a nadir in 2020, where weak gas demand due to Covid-19 and firm
domestic gas production led to imports declining an estimated 6% in 2020 to 35bcm. However, gas imports will return to growth in
2021, where we forecast 2% growth and rise to a peak growth of 9% in 2023, then slowing over the rest of decade. By 2030, we
forecast imports to reach 58bcm, meeting over 75% of the UK’s forecasted demand. Other than the increasing import bill for UK gas
consumers, we see few risks associated with the increasing reliance on imports. The UK receives natural gas imports from a diverse
range of countries which are politically secure and have good diplomatic relations. Around half of imports are by pipeline from
Norway, just under half from LNG (primarily Qatar and the USA) and the rest by pipeline from continental Europe.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 19Global Summary Oil & Gas | 20210315
UK Reliance On Imports To Increase
UK Gas Net Exports By Year (2019-2030f)
Source: Fitch Solutions
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 20Global Summary Oil & Gas | 20210315 Latin America Colombia's Natural Gas Production Growth To Accelerate Over Medium- To-Long Term Key View • Increased capex allocation on natural gas assets announced by Ecopetrol supports our upward revision of natural gas production in Colombia, while the completion of Shell’s farm-in into the gas-rich offshore blocks constitutes an upside risk for the natural gas output in the medium-to-long term. • However, the near-term focus on oil production, likely further solidified by bullish oil price outlook, could potentially cap the natural gas production growth as key companies will prioritise gas reinjections to stimulate oil production from mature fields to benefit from the price environment. • The development of large-scale unconventional production is unlikely to materialise over our forecast period despite recent progress in fracking pilot projects. Increased capex allocation on natural gas assets announced by Ecopetrol supports our upward revision of natural gas production in Colombia, while the completion of Shell’s farm-in into the gas-rich offshore blocks constitutes an upside risk for the natural gas output in the medium-to-long term. We now expect Colombia to increase its natural gas output by 2.0% in 2022 and 2.1% in 2023, which marks an upward revision from our previous forecast of 1.5% in 2022 and 1.8% in 2023. The key driver behind our more bullish outlook is the adjustment in the strategy of the key natural gas producer in Colombia, Ecopetrol. In its latest strategic update from February 2021, Ecopetrol raised the allocation on conventional natural gas assets from USD780-870mn in 2020-2022 to approximately USD1,300mn over 2021-2023. The company has also extended the list of key focus basins for conventional natural gas development by adding Middle Magdalena Valley and Sinú-San Jacinto to the previously announced key targets of Piedemonte, Guajira and Colombia's offshore in the 2020-2022 Update. Ecopetrol has also recently announced that over the long term, the company plans to increase the share of natural gas in its overall production from approximately 20% currently to 35% in 2030. This announcement supports our long-term natural gas production forecast. THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research. fitchsolutions.com 21
Global Summary Oil & Gas | 20210315
Colombia's Natural Gas Output Set To Grow
Colombia - Natural Gas Production Forecast (2019-2030)
e/f - Fitch Solutions estimate/forecast. Source: ANH, Fitch Solutions
We maintain our view that Ecopetrol and its subsidiaries will remain key drivers behind natural gas production growth given the
state-led company’s share in Colombia's total gas production. As of January-November 2020, Ecopetrol with its subsidiaries,
including the most prominent – Hocol, delivered 83% of gross domestic natural gas production. That said, we recognise an upside
risk from the potential uptick in production from other producers. As of late December 2020, Shell completed the farm-in into gas-
rich offshore blocks. Shell, acting as operator, now owns a 50% interest in three blocks (Fuerte Sur, Purple Angel and COL-5) with
Ecopetrol holding the remaining interest. Companies plan to drill the appraisal well in late 2021. The deepwater offshore, where the
blocks are located, remains one of the most prominent plays in Colombia, after a series of gas discoveries in the Kronos, Purple
Angel and the Gorgon wells over 2015-2017.
However, the near-term focus on oil production, likely further solidified by bullish oil price outlook, could potentially
cap the natural gas production growth as key companies will prioritise gas reinjections to stimulate oil production
from mature fields to benefit from the price environment. Dry natural gas and reinjections make up a large chunk of total
natural gas production in Colombia. We have seen dry natural gas production accelerating over Q3-Q420 with volumes of reinjected
gas continuing their downward trend. However, we recognise a risk that the share of volume used for reinjections in total output
will grow. We highlight that Ecopetrol Group will likely continue to focus on crude oil production over the near term. Thus, the dry
natural gas production growth could potentially be capped by the growth in the volume of gas reinjected to stimulate oil production
from mature fields. Enhanced recovery methods remain key in Ecopetrol’s near-term strategy. At the end of 2020, the Ecopetrol
Group delivered 36% of production through secondary (reinjections of natural gas or water) or tertiary (reinjection of chemicals)
recovery methods. Although the company plans to lower the share of enhanced recovery production in its total output to 15-17%
for secondary method and 2-3% for tertiary method over 2020-2022, we see the risk for an uptick in gas reinjections to benefit
form growing crude oil prices over the short term. However, in our view, the risk of higher reinjections and lower dry natural gas
output is likely to be rather short-lived given Ecopetrol’s long-term strategy to increase the share of natural gas in its total
production as described above.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
fitchsolutions.com 22Global Summary Oil & Gas | 20210315
Risks Of Growing Reinjections On The Raise
Colombia - Share Of Volumes Used For Reinjections And Dry Natural Gas In Gross Natural Gas Production (%), 2015-2020
Source: National Hydrocarbon Agency
The development of large-scale unconventional production is unlikely to materialise over our forecast period
despite recent progress in fracking pilot projects. We maintain our view that the unconventional oil and natural gas projects
in Colombia will likely progress over the upcoming decade. However, it will fail to reach a material level of output over our forecast
period; the key reason for that is the opposition from the local groups and broader society, which led to a Supreme Court’s
moratorium on fracking imposed in 2019. That said, the recent progress in pilot projects constitutes an upside risk to our long-term
unconventional production forecast. In February 2021, the Colombian government has announced that four companies were
approved for the fracking pilots: Ecopetrol, ExxonMobil, Drumond Energy and Tecpetrol Colombia. The National Hydrocarbon
Agency, the Colombian market regulator, has extended the deadline to submit proposals for other potential companies interested in
participating in the fracking program until March 30 2021. The first exploratory wells are expected to be drilled over 2021. We note
that, although there has been progress in expanding unconventional developments in Colombia, the shale/tight market remains in
a nascent stage and will require time and investment to gain importance in Colombia.
THIS COMMENTARY IS PUBLISHED BY FITCH SOLUTIONS COUNTRY RISK & INDUSTRY RESEARCH and is NOT a comment on Fitch Ratings' Credit Ratings. Any comments or data included in the report are solely
derived from Fitch Solutions Country Risk & Industry Research and independent sources. Fitch Ratings analysts do not share data or information with Fitch Solutions Country Risk & Industry Research.
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