Analysis on M&A so far in 2021 and what to expect now
Published 1st September 2021
by David Stent, Content Manager, Energy Council
The global oil and gas markets have been awash with deals as oil and gas players alike scramble to rebalance their portfolios in light of supranational climate goals. While the market has not been 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 mergers and acquisitions that will add much needed liquidity to the markets.
The Energy Council has taken a look at the biggest deals on ERCE's M&A quarterly trackers, and looks at how M&A markets may shift into 2022.
For our highlights of the North American sector in 2021, please read our “Deep dive into the US M&A Market”.
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 $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.
How the European and North Sea M&A markets will develop in 2022 is difficult to predict prior to September’s OPEC+ meeting and the COP26 conference in November – the likelihood being that European nations continue to further their climate goals. The age of North Sea assets is often a concern, but the advances in electrification of rigs, EOR and improving well decommissioning costs could make these assets attractive once more to ambitious mid-sized producers.
NEO Energy purchased ExxonMobil ($1.3bn) agreed to the largest acquisition in the North Sea so far this year, purchasing ExxonMobil’s non-operated upstream assets in the United Kingdom’s Central and Northern North Sea. HitecVision has backed NEO Energy to rapidly grow their presence in the region, seeking to achieve a near-term target of 120,000 boe/d. Exxon’s fields will contribute heftily to that by adding close to 40,000 boe/d and 140 million boe of reserves.
The deal is structured to net ExxonMobil with $1 billion, with potential for an additional $300 million in contingency payments based-on potential increases in commodity prices.
NEO Energy and Zennor Petroleum Limited ($625m) were soon to follow suit to complete the sale of Zennor’s North Sea assets and “an experienced with a strong operational track-record”. NEO’s second move in the market this year added 80,000 boe/d to their production capacity, expecting to grow to 100,000 boe/d by 2026. This provides an additional 40 million boe of reserves and 90 million boe of un-risked resource to NEO’s portfolio.
PGNiG Upstream Norway AS and INEOS ($615m) saw the end of INEOS’s presence in Norwegian Continental Shelf as they look to ‘rebalance’ their oil and gas portfolio. The deal included “all interests in production, licenses, fields, facilities and pipelines”, comprising of 3 non-operated assets, 22 offshore licences (6 operated) and 8% equity in the Nyhamna Terminal.
“INEOS announced that it had reached an agreement to sell its Oil and Gas business in Norway to PGNiG for a consideration of US$615MM. This deal includes 3 non-operated fields, 22 offshore licenses, of which 6 are operated, and 8% equity in the Nyhamna Terminal.” All 52 employees of INEOS E&P will transfer to the Norwegian subsidiary of Polish oil and gas company, PGNiG.
Waldorf Production and Cairn Energy ($460m) saw Cairn sell their interests in the producing Catcher (20%) and Kraken (29.5%) fields to Waldorf, that will see them team up with Premier and EnQuest in their production efforts.
The deal is initially valued at $460m with contingency payments of up to $175 million, dependent on rising Brent prices to $65/b and based on Cairn’s expected production profiles. Catcher was producing an average of 52,000 boe/d in 2020, while Kraken averaged 37,600 b/d and growing Waldorf’s production to 22,000-25,000 boe/d.
EnQuest and Suncor Energy ($325m) deal will immediately add 10,000 boe/d, 18 million barrels of 2P reserves and 5 million barrels of 2C reserves to EnQuest’s North Sea portfolio, by purchasing Suncor’s entire 26.69% equity interest in the Golden Eagle area.
EnQuest will enter into a joint venture with CNOOC, NEO Energy and ONE DYAS that they believe has a life of field operating and capital expenditure of $20/boe.
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 Cheiron.
The regional M&A market is unlike most others, with NOCs able to control and operate large fields with less outside operators. The OPEC+ strategy of seeking to maintain production volumes may hinder the volume of deals, however the exceptional cost efficiencies and value of Middle Eastern assets will continue to make them attractive purchases for a range of buyers.
PTTEP and bp ($2.7bn) was a sale for bp’s 20% stake in Oman’s block 6, responsible for 35% of Oman’s gas production output. Covering 3,950 km² in central Oman, the field has a daily production capacity of 1,5bcf of gas and 65,000 b/d of condensate among total gas resources of 10.5 trillion cubic feet.
Bp will continue to “hold a 40% participating interest while other partners including OQ (Omani national oil company), Oman’s national oil company; PTTEP MENA; and PC Oman Ventures Limited, a subsidiary of PETRONAS, will hold 30%, 20% and 10% participating interests, respectively.”
Cairn Energy, Cheiron and Royal Dutch Shell ($646m) was for 113mmboe of 2P reserves and a working interest in 49mm boe of 2C contingent resources for Shell’s Western Desert onshore gas fields in Egypt. A consortium of Cairn Energy and Cheiron will pay $646m for an equal share in the assets, adding 83,000 boe/d to the portfolio.
The deal will be structured via a “joint acquisition reserve-based lending facility of up to $350m, joint junior debt facility of US$100 million and existing cash on balance sheet”. There exists potential for further contingent payments of up to $280m.
Mubadala Petroleum and Delek Drilling ($1.1bn) saw the UAE’s national oil company take a 22% non-operated stake in the Israeli offshore gas field, Tamar. In a deal that will reflect $1.1bn in an unconditional payment, with another $100m of contingency payments based-on rising commodity prices.
The Tamar offshore field was sold as part of a natural gas sector agreement with the Israeli government, due to their 45% ownership in the (slightly larger) Leviathan gas field. The Tamar field produces 11 billion cubic meters of gas each year, has already produced 69bcm of gas, and there is a remaining 2P reserves of some 300 Bcm.
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. Only two sales were completed over $100m so far in 2021. However, as we see the normalisation of commodity prices, these actors may consider it an appropriate time to engage in a sale.
Once again, Shell has sought to divest itself as the engage in their mission to reduce emissions by 45% and focus operations in nine core regions, selling their stake in the project producing 20% of the Philippines electricity from indigenous natural gas. Repsol was another oil major that has been selling a range of assets, a result of severe cash constraints caused by Covid on their downstream operations.
Regional producers will be keeping a keen eye on the movements and divestures of IOCs, who will continue to face shareholder pressures to change and divest from carbon-intensive operations. Pressures that are unlikely to burden APAC players nearly as much.
Down under, there are signals that a $16bn merger between Oil Search and Santos is still on the cards, as Mubadala exited their position as an ‘anchor investor’. While also BHP may follow through with a sale of their high-carbon assets in the coming year.
Udenna Corporation and Royal Dutch Shell ($460m) was another divesture as a part of Shell’s global reconsideration of assets, part of a court-ordered emissions reduction mandate. Shell will let go of a 45% stake in the Philippine Malampaya gas field, to Udenna Corporation – a Philippine conglomerate seeking to take advantage of Shell’s precarious position.
The Malampaya project has large infrastructure assets attached, including, “subsea wells and flow lines, a shallow water platform and a depletion completion platform to process natural gas, a catenary anchored leg mooring-buoy for the export of liquid condensate, a 504-kilometer long gas export pipeline on the seabed, an onshore gas plant and pipeline in Batangas City.”
Hibiscus Petroleum and Repsol ($212.5m) saw another regional divesture from a European major, as Repsol sold off their remaining assets in Malaysia and Vietnam to Hibiscus. The $212.5m deal will include “a 35% interest in PM3 CAA PSC, 60% in 2012 Kinabalu Oil PSC, 60% in PM305 PSC, 60% in PM314 PSC, 70% in Block 46 CN”.
Repsol has announced a reconsideration of their portfolio diversity, and chosen 14 core projects to devote their production efforts towards (down from 25). Hibiscus is anticipating a double-up of their production output capacity in 2022, taking their output from 9,000 boe/d to 18,500 boe/d.
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 $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.
Mexican assets may increasingly enter the market due to a reversal of liberalisation policies, creating a regulatory landscape that may be too cumbersome to extract necessary value.
The sale of Brazilian assets by Petrobras to Petro+ may be just the first in a wave of divesture by the Brazilian NOC, as the liberalisation of the oil and gas sectors as Petrobras looks to recover from a difficult 2021. Elsewhere, gas and infrastructure assets will be attractive to buyers as the region looks to supply the international export market.
PJSC Lukoil and ‘undisclosed’ ($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. The sale will include two offshore blocks, 59km² in total size, which include the Ichalkil and Pokoch oil fields. It is believed that there are reserves of over 564 million boe, of which more than 80% is crude oil.
Lukoil expects to have production of first oil in late 2021, seeking to achieve a ‘peak daily production rate’ of 115,000 boe/d.
Petro+ and Petrobras ($300m) is likely to be the first of Petrobras’ divesture strategy, in-line with government instituted liberalisation of the Brazilian oil and gas sector. The deal will be structured with a $60m upfront payment, followed by the $240m on completion of the deal.
The Algoas Cluster deal includes seven onshore production concessions and on shallow water field, producing 1,900 b/d of oil and condensate and 602,000 cubic meters/day of gas.
3R Petroleum Offshore S.A. and Petrobras ($105.6m) saw the Brazilian NOC sell their 62.5% stake in the Papa-Terra field, in the Campos Basin. 3R Petroleum Resources will take control of the field for an upfront payment of $6m, $9.6m on closing the deal and a further $90m in contingency payments linked to projected production levels and rising commodity prices.
3R Petroleum will join forces with Chevron to take operational control of the 17,900 boe/d production output across the wellhead platform and FPSO unit.
Looking to 2022, the two companies are in talks for a much larger, billion-dollar deal that will see Petrobras divest from their Potiguar Cluster assets of 23 onshore fields and three offshore. We will keep a close eye on developments here.
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.
Further questions arose around the stability of operations following a number of internal disruptions and conflicts, such as the emergence of ISIS in northern Mozambique that seriously threatened Total’s production schedule. The uncertainty and need for portfolio restructuring has led to an undisclosed sale by Total to Qatar Petroleum for stakes in South Africa’s offshore gas fields.
The next year may see a slight increase in African M&A activity, as the force majeure that delayed many developments across the continent are overcome, commodity prices stabilise and projects begin to reveal their true value.
Panoro Energy ASA and Tullow Oil ($180m) is the biggest deal to occur so far this year on the continent. Tullow has been a mainstay in the Equatorial Guinea oil and gas sector for the past 18 years, but like many producers must reassess their portfolios with the energy transition in mind.
Tullow Oil will maintain financial links to the Ceiba and Okume fields, however their operational presence in-country will cease. Panoro is also taking control of Tullow’s Gabonese Dussafu asset. Panoro will take over seven non-operated oil production fields, with “combined additional net production of 6,900 b/d and net 2P reserves of 25 million barrels. The Dussafu site currently produces 15,000 b/d, with an expected increase to 20,000 b/d when two wells in the Tortue field are added.
Qatar Petroleum and TotalEnergies ($–) 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. Fortunately, the threats have subsided somewhat, but the additional pressure of the Covid demand slump and emissions targets has led to a divesture in the exploration assets off South Africa’s southern coast gas fields.
The total amount has not been released, but it is an unsurprising partner as Qatar Petroleum has been working together with Total in the region for some years now.