Strong demand, particularly from China, has seen oil and gas prices exceed expectations. Restrictions, enacted to control the spread of the Covid-19 have had an enormous impact on economic growth, lifting global GDP by 4.2% in 2021 after a fall of 4.2% in 2020. The oil and gas industry rebounded strongly, with oil and gas prices reaching record highs.

The 2021 year began with bullish ramp up of WTI and Brent prices from US$52/bbl and US$55/bbl respectively in January as demand rebounded while supply remained tight. Prices remained on a steady upward trajectory edging higher quarter on quarter, by October prices were up more than 60%, topping at US$81/bbl and US$84/bbl respectively.  The emergence of the new Omicron variant as well as a surge in Covid-19 cases in Europe and other regions in October raised concerns that the reinstatement of lockdown measures and mobility restrictions could dampen demand for transportation fuels. WTI and Brent prices reacted by retreating to US$70/bbl and US$73/bbl respectively by years end.

In the US, President Biden ordered a release of oil from its Strategic Petroleum Reserve in November, as part of a coordinated effort with five other countries to tamp down rising fuel prices. The US plans to tap 50 million barrels of crude oil in the coming months, while the other nations, the UK, India, Japan, Korea and China will release about 11 million barrels in total.  China’s participation was unprecedented, releasing crude oil from its strategic reserve for the first time. This action came amid surging energy costs in China, not just for oil but also for coal and natural gas, and electricity shortages in some provinces that forced some factories to cut production.

China’s factory-gate inflation accelerated to a 13-year high, and just a month after the White House publicly asked the OPEC oil cartel to pump more crude oil amid rising gasoline prices in the US. Together, the actions in Beijing and Washington suggest that the world’s two largest energy consumers see US$70-US$75/bbl as a red line for the price of oil. Hurricane Ida also eliminated a swath of US crude production, affecting supplies to China’s Unipec. Oil prices slumped in August. Brent crude fell as much as US$1.4/bbl to US$71.2/bbl, erasing earlier gains. WTI had a similar reversal.

Henry Hub natural gas prices surged during 2021, trading from US$3.6/MBtu at the start of the year to a high of US$5.9/MBtu in September as storage inventories trailed typical pre-winter levels and US natural gas production stumbled below 2.5Bcmpd. By year end Henry Hub prices had retreated to US$3.9/MBtu. The 2021-2022 winter could be a revelatory test of global energy markets. With natural gas prices hovering at record levels, the commodity has become too expensive for some importers, which will opt to burn oil products instead. Henry Hub is expected to remain high supported by strong growth in US LNG exports, but gas prices will remain volatile over the coming months, with winter temperatures to be a key driver of demand and prices.

Europe’s 2021 gas prices edged higher month on month on surging demand, then skyrocketed in the December quarter as the start to winter made unusually large inroads into the already meagre volume of gas in storage.  Any fix from the supply side had not arrived by years end, with exporters Russia piping only what it has to and Qatar producing what it can. The AME European Composite Gas Price started the year at US$7.4/MBtu, increasing rapidly to US$31.2/MBtu in October before surging to an average US$39.3/MBtu in December.

Imports and Exports

Global crude oil demand exceeded global oil supply in the first half of 2021 before supply and demand found a relative balance in the second half of 2021.  OPEC+ countries have shown flexibility in amending their quota arrangements. The early December OPEC+ agreement to increase the quota by a modest 0.4Mbpd each month, subject to conditions provided the headroom for more supply and was based on a recognition that the market remains fragile and is in need of careful adjustment.

Although demand recovered from its trough in 2020 it’s expected to remain low for longer, reflecting recently announced travel restrictions following reported outbreaks of the Omicron variant. Towards the end of the year worries about demand destruction weighed on Europe again as it become the epicentre of the pandemic, prompting some governments to consider reimposing lockdowns. Meanwhile China battled the spread of its biggest outbreak caused by the Delta variant and softer industrial production. The picture in OECD countries improved in 2021 with oil demand 2.5Mbpd higher than a year ago. 

Global oil demand rebounded 5.7% from 92.6Mbpd in 2020 to 97.9Mbpd in 2021, and is forecast to increase 3.5% to 101.3Mbpd in 2022 underpinned by the insatiable appetites of countries in North America, Asia and Europe.   Global oil supply was underpinned by the prolific US shale oil plays largely in the Permian Basin and oil sands in Canada, coupled with project expansions in offshore basins in Brazil. Going forward, global oil supply will increase 2.5% from 95.7Mbpd in 2020 to 98.2Mbpd in 2021, and is forecast to rebound 3.4% to 101.5Mbpd in 2022.

Global natural gas demand will increase 0.9% from 10.6Bcmpd in 2020 to 10.7Bcmpd in 2021, then lift a further 1.9% to 10.9Mbpd in 2022, most of the post-2021 growth takes place in Asia, led by China and India where gas benefits from strong policy support. On global natural gas supply, AME estimates this will decrease 0.9% from 10.9Bcmpd in 2020 to 10.8Bcmpd in 2021, then lift 1.8% to 11.0Bcmpd in 2022, the majority of incremental gas supply comes from US shale and large conventional projects in the Middle East and Russia. Liquefied natural gas is expected to remain the main driver behind global gas trade growth, but it faces the risk of prolonged overcapacity as the build-up in new export capacity from past investment decisions outpaces slower than expected demand growth.

OPEC+ countries agreed at their December meeting to stick to their existing plan to increase oil output by 0.4Mbpd in January 2022, rejecting calls from the US for extra supply to ease rising prices. Saudi Arabia cited economic headwinds in dismissing these calls. Russia will continue with the group's existing plan, as global oil demand is still under pressure from Covid-19. The US urged major G20 energy producers to increase production to ensure a stronger global economic recovery.  The US saw its production fall steeply last year, and supply this year has recovered much more slowly than expected. American shale drillers prioritised returns and paying down debt over growth, following a wave of bankruptcies last year.

In 2021 India looked to import crude oil from Guyana under a long-term deal as part of plans to diversify its imports away from top producer Saudi Arabia. India was seeking to initially buy one 1Mbbl cargo to test the crude in its refineries. The world's third largest crude consumer and importer reported a 25% rise in oil demand over the last seven years, more than any other country.  India opposed a decision by OPEC+ to extend production cuts that have lifted oil prices and state refiners plan to buy 36% less oil than usual from Saudi Arabia. Private Indian refiner HPCL-Mittal Energy Ltd purchased India's first-ever cargo from Guyana in April.

Closures and Production Cuts

Despite the high crude oil and gas prices this year, the most striking development to capture 2021’s themes for crude oil and natural gas across the globe was the US shale producers' decision to resist pumping more crude oil. US crude oil production declined 4.6% to 11.2Mbpd year-on-year as producers reduced capital budgets, curtail production and a substantial number sought protection from creditors in bankruptcy. US natural gas production on the other hand increased 2.3% to 2.8Bcmpd supported by strong LNG exports.

The reduced but still dominant crude oil output of the US continued to unsettled OPEC, leaving a question mark over the cartel’s future. OPEC's December cuts and Alberta’s takeaway restrictions combined to lower 2021 production, though by less than previously anticipated.

Meanwhile in Europe, the Danish government will cancel all new oil and gas exploration and production in the North Sea by 2050, as part of its plan to become carbon neutral by mid-century. Denmark is currently the largest oil producer in the EU, although it produces much less than non-EU members Norway or the UK. Denmark has one of the world's most ambitious climate targets, aiming to reduce greenhouse gas emissions from 1990 levels by 70% by 2030, as well as reach net zero emissions by 2050, both targets which have been passed into law.

New Fields, Restarts and Expansions

Guyana and Brazil came into focus this year with ExxonMobil announcing it expects to have five FPSOs in operation in Guyana by 2026 and see the potential for a total of 7 to 10 FPSOs. Development of the Stabroek block is one of Latin America's biggest offshore projects, with estimated recoverable resources of more than 8Bboe rivalling the largest offshore finds in Brazil's subsalt frontier. The company also expects to ramp up work in Brazil, where the company has a portfolio of 28 blocks in the Campos, Santos and Sergipe-Alagoas basins.

In the US the Baker Hughes US drilling rig count, an important barometer of expansion for the oil and gas industry and its suppliers, has risen dramatically in 2021, a trend that promises to continue into 2022. The country now has 471 oil rigs and 105 gas rigs, compared to this.

High energy prices have resulted in a dramatic change of fortunes for Canadian oil companies. In early 2020, they were curtailing production and laying off workers as lockdowns hammered oil demand. Now, Cenovus Energy is rapidly paying down debt following its acquisition of Husky Energy Inc., while Suncor Energy Inc. recently doubled its dividend and increased its share buyback program.

Alberta holds the world’s third-largest oil reserves; production of Canadian crude oil is expected to outpace 2019 levels by the end of this year and remain strong through 2022 as higher prices allow producers to drill new wells. Canada’s natural gas producers also benefited from higher prices over the summer as pipeline flows out of Western Canada rose and domestic demand was higher than in recent years. Natural gas production volumes were higher, although drilling activity remained steady as companies stayed focused on maximising cash flow.   

In Europe, the prompt restoration of Norway’s Troll and Oseberg gas fields production went unnoticed in the wake of escalating tensions between Russia and Ukraine, driving natural gas prices to all-time highs, reversing the price dynamic with Asia, and becoming the centre of attention for US LNG.  The already completed Nord Stream 2 pipeline was caught in a geopolitical crossfire, with concerns around further delays or even potential non-certification driving strong bullish sentiment in European prices, bolstered by accelerating withdrawals from storage that now stands at less than 63% capacity. Mixed weather signals continue to inject volatility with sporadic cold spells keeping European consumers ill at ease.

Russian gas giant Gazprom plans to invest US$24bn next year to fund new production and refining hubs, up from US$16bn this year. The company is developing new gas production deposits, including in the Arctic Yamal peninsula, which the government claims hold more than 20% of global gas reserves.

After a long period disruptive conflict, Libya has been being able to stabilise crude oil production above 1.2Mbpd for most of this year, three times the average level in 2020. The country’s National Oil Corporation (NOC) oil output has been rising steadily since the gradual lifting of an eight-month blockade by eastern forces in September 2019. Libya is targeting 1.45Mbpd by the end of 2021, production exceeding this will be difficult because repeated shutdowns since a civil war erupted in 2011 and limited investment in infrastructure has curtailed its production capacity.

In Australia – the Federal government urged upstream gas companies to be ready to make final investment decisions (FIDs) on their respective projects in the onshore Beetaloo Basin in the Northern Territory following the unveiling of “The Beetaloo Strategic Basin Plan”, which includes further state funding of AUD$224 million for infrastructure-related projects as well as ensuring there are no delays to development from regulations governing the sector. The Beetaloo shale resources could be Australia's richest undiscovered gas resources, which could supply the east Australia market or be used as feed for the two LNG projects at Darwin.

BHP and Woodside approved the US$12bn development of the Scarborough upstream project in Western Australia, which will supply gas to an expanded Pluto LNG project.

Meanwhile – Santos received the go-ahead to its US$3.6bn Barossa gas project off the northern coast of Australia. The final investment decision also kicks off a separate US$600m investment to extend the life of the 3.7Mtpa Darwin LNG facility by about 20yrs. Barossa is the largest upstream project to be sanctioned in Australia since 2012, and will help meet rising LNG demand across Asia Pacific over the next two decades. The project, which will supply Darwin LNG with feed gas when the Bayu-Undan field stops producing, will comprise a floating production, storage and offloading vessel, subsea production wells and a gas export pipeline tied into the existing Bayu-Undan to Darwin pipeline.

In October 2021 the NSW Land and Environment Court rejected an appeal into the approval of the multi-billion-dollar Narrabri Gas Project in the state's north-west. Santos's plans to drill 850 coal seam gas wells in the Pilliga region were approved last year by the Independent Planning Commission.

Mergers & Acquisitions

The global oil and gas markets were awash with deals as oil and gas players alike scrambled to rebalance their portfolios in light of national climate goals. While the market was not as active in the second half of 2021, as commodity prices began to stabilise toward pre-Covid levels, there were still a number of significant M&As that added much needed liquidity to the markets.

North America - much of the activity will continue to focus on shale plays in the southern US. While deal activity has been strong in the Permian, there is increased interest in the Eagle Ford and Haynesville shales as well. Higher natural gas demand in Europe and Asia post-pandemic will likely drive asset (and even strategic) investments in both natural gas production and LNG.

• ConocoPhillips completed the Shell Deal (US$9.5bn) assets include around 225,000 net acres and producing properties located entirely in the Permian Basin, Texas.
• EQT. Corp purchased Alta Resources (US$2.9bn) northeast Marcellus Shale gas assets.
• Grayson Mill Energy purchase of Equinor Energy (US$0.9bn) Bakken Shale assets in North Dakota/Montana.

Europe’s North Sea has been a contentious region, as high barrel costs and maturing assets have left some companies unsure about their future in the area. Despite this, there have been some bold acquisitions over the US$500m mark, especially by NEO Energy and PGNiG. ExxonMobil was keen to let go of ageing assets and their carbon burden, turning toward more ‘local’ projects in the Americas and their monopoly in the exciting Guyanese gas fields. Meanwhile, INEOS disposed of their last assets in the Norwegian North Sea as they too seek greater diversification within their portfolio.

• NEO Energy purchased ExxonMobil (US$1.3bn) agreed to the largest acquisition in the North Sea this year.
• NEO Energy and Zennor Petroleum Limited (US$625m) were soon to follow suit to complete the sale of Zennor’s North Sea assets.
• PGNiG Upstream Norway AS and INEOS (US$615m) saw the end of INEOS’s presence in Norwegian Continental Shelf as they look to ‘rebalance’ their oil and gas portfolio.

Natural gas deals were the popular asset for sale, as Middle Eastern markets saw some of biggest deals this year. The most notable of which was by Thailand’s PTTEP purchasing a stake from BP in Oman’s block 6, one of the largest gas developments in the Middle East. Once more, climate concerns and portfolio balancing led to a large sale of Egyptian gas fields by Shell to a consortium of Cairn Energy and Chevron.

• PTTEP and BP (US$2.7bn) was a sale for BP’s 20% stake in Oman’s block 6, responsible for 35% of Oman’s gas production output.
• Cairn Energy, Chevron and Royal Dutch Shell (US$646m).
• Mubadala Petroleum and Delek Drilling (US$1.1bn) saw the UAE’s national oil company take a 22% non-operated stake in the Israeli offshore gas field, Tamar.

Following a subdued start to the year, Latin American oil and gas assets began to pique the interest of a number of buyers and resulting in three significant deals over US$100m. Equinor is said to be actively searching for buyers for two deep-water blocks offshore Mexico, that could see the value of regional deals for the year increase still.

• PJSC Lukoil and ‘undisclosed’ (US$435m) is a deal that sees PJSC Lukoil acquire a 50% stake in the Area 4 project in Mexico, to work alongside Mexican operator, PetroBal. 
• Petro+ and Petrobras (US$300m) is likely to be the first of Petrobras’ divesture strategy, in-line with government instituted liberalisation of the Brazilian oil and gas sector.
• 3R Petroleum Offshore S.A. and Petrobras (US$105.6m) saw the Brazilian NOC sell their 62.5% stake in the Papa-Terra field, in the Campos Basin.

It was a particularly quiet year for African M&A activity, as a reluctance by oil majors and investors were discouraged by the difficult operating and regulatory environments, together with the carbon intensity of low-grade assets.

• Panoro Energy ASA and Tullow Oil (US$180m) is the biggest deal to occur this year on the continent. Tullow has been a mainstay in the Equatorial Guinea oil and gas sector for the past 18 years, but like many producers must reassess their portfolios with the energy transition in mind.
• Qatar Petroleum and TotalEnergies (US$ - ) was an anticipated sale as TotalEnergies reconsidered their position in Southern Africa following a traumatic turn of events in Mozambique, as ISIS-linked militia advanced on the region.

The Asia Pacific region has not seen too much M&A activity in recent times, as asset owners who were able to weather the Covid demand slump were unwilling to sell for below market value. There were five noteworthy sales completed over US$100 million in 2021.

• In Australia, Woodside Petroleum completed its US$28.9bn merger with BHP's oil and gas portfolio to create one of the world's biggest independent energy companies by production. The merged Woodside-BHP Petroleum will have production of about 200Mboe.
• Korean steelmaker POSCO will buy out Senex for the equivalent of US$612 million via a scheme of arrangement to be completed late March 2022. POSCO has announced its intention that, if successful in its acquisition, Gina Rinehart’s Hancock Energy will acquire 49.9% indirect interest in Senex. 
• The US6.2bn merger of Santos and Oil Search became effective in December following approval of Oil Search’s Scheme of Arrangement by the National Court of PNG. The merger creates a regional champion of size and scale, with a market capitalisation of approximately US$15.8bn. Santos expects the merger to unlock pre-tax synergies of US$90-115 million per annum.
• Udenna Corporation and Royal Dutch Shell (US$460m) was another divesture as a part of Shell’s global reconsideration of assets, part of a court-ordered emissions reduction mandate.
• Hibiscus Petroleum and Repsol (US$212.5m) saw another regional divesture from a European major, as Repsol sold off their remaining assets in Malaysia and Vietnam to Hibiscus.