Another tumultuous year for the global economy draws to a close. War reached Europe’s doorsteps as Russia ordered its troops and tanks into Ukraine, sending policymakers and markets scrambling to assess the impact as supply routes in place for decades for essential commodities such as energy and food got disrupted. Along with details from the battlefront and the humanitarian toll, news headlines were dominated by the possibility of rolling blackouts and rationing – terms that modern day Europe had perhaps only read about in history books. As the war drags on, supply chains remain disrupted, in part keeping prices of food and other essential items elevated as many traditional buyers of grains from Ukraine, particularly in north Africa, report shortages. Energy markets, however, have settled into a new equilibrium, to a large extent on account of a central role played by the US. Europe was able to plug a big chunk of the gap in gas supplies, as Russian volumes were chocked off, thanks to the US, helping the region get ready for winter with nearly full gas storage tanks. For oil as well, record high volumes shipped from the Gulf coast played a major role in keeping global markets in balance.

Energy markets grappled with several other headwinds this year. An uncertain demand growth outlook amid concerns of a recession on account of successive interest rate increases by the US Federal Reserve, and other central banks around the world, to curb a surge in inflation to multi-decade highs. Uncertainty in China as the economic powerhouse continuously extended its zero-Covid-19 policy with strict lockdown measures, only to lift them swiftly following a surge in protests across cities as citizens fed up with enduring months of hardship and shortages took to the streets. And last but not least – as oil and gas prices surged through the first half of the year, energy companies raked in billions in profits, drawing flak from politicians and leaders for profiting while households struggled to balance their budgets, triggering talk of windfall tax.

It was not all bad news, though. The energy transition story got a shot in the arm as President Joe Biden managed to secure enough support, after months of negotiations, to pass through Congress a signature legislature – the Inflation Reduction Act – that seek to bolster the renewables and clean energy industry. As the end of the year approaches, this issue of Rystad Energy’s REview looks at the various wins and losses through 2022 – and more importantly, the way forward in 2023 – for major segments of the energy industry in North America. 

Renewables
Geoffrey Hebertson and Marcelo Ortega

For the renewables industry, 2022 was a turbulent year with policy impacting development like never before. The year began with a red-hot, excited industry coming off the heels of a record-breaking 2021 in terms of installed capacity. However, excitement quickly deteriorated, reaching a low in the first half of the year with many solar PV developers wondering how the industry will move forward following a complete halt on solar panel imports due to an anti-dumping and countervailing (ADCV) investigation. Despite being at an all-time-low, with projections of installed capacity to be less than 2020 levels (approximately 10 GW – utility scale solar), spirits lifted as President Joe Biden signed a 2-year moratorium on solar panel import tariffs, allowing developers and suppliers time to de-risk any potential sanctions.  

The biggest news of the year came in August as President Biden signed the Inflation Reduction Act (IRA), handing the renewables industry and the democratic party a decisive victory, providing stability and ensuring vital tax credits had been extended until 2034. The IRA has provided certainty for an industry aching to meet its full potential. At Rystad Energy, we expect the IRA to add over 150 GW of new solar and wind, capacity by 2030.

Next year will be pivotal for the renewables industry. Armed with the new capital and supported by the IRA, developers will look to ramp up capacity installations to make up for lost time in the first half of 2022. We’ve already observed an influx of new projects added to interconnection queues and developers greenlighting a number of projects. We expect this trend to continue through 2023. Furthermore, we expect commodity price inflation to taper down in 2023, easing concerns on new development and lowering capital required. 

While there are many positives to look for in 2023, we note several headwinds that would be worth monitoring. First, the final result of the ADCV investigation will be released in May. An analysis of the preliminary results shows that companies have indeed circumvented tariffs. Companies involved will be able to comment and plead their case ahead of the final decision, but if found guilty, will need to secure new supply chains to have a presence in the US. To follow suit, the US will need to reduce its reliance on Chinese imports and decouple its dependency on imports of panels and lithium. Some suppliers have announced new manufacturing in the US, but that will take 2-5 years to reach the market, not in time for the influx of new projects today. Lastly, the inflation act might face pressure as allies in Europe have pointed to the bill as being inequitable as it has incentivized foreign investment in the US renewables sector, diminishing efforts to decarbonize domestically. There are additional concerns that with a Republican House the act might be overturned, although that is unlikely as Democrats will have a 51-49 majority in the Senate come January. 

Despite some concerns, the US is well poised to capitalize on the favorable policies set forth by the current administration. Moreover, we expect the US to maintain its lead as a renewable energy leader as the world transitions to cleaner energy. In 2022, renewable energy – solar and wind – accounted for 22% of the power generated in the country and we expect renewables will account for nearly a quarter of the mix in 2023. We forecast 2023 to be a year of stability as the industry establishes itself with favorable policy for the next decade.

Gas markets
Emily McClain

Global gas and LNG markets were rocked this year with the war and its impact on European supplies. Truly dramatic changes were made to the global LNG landscape as a result, and these changes will undoubtedly impact gas markets in the coming years. We saw a jump in LNG imports into Europe, on track to reach 119 MT by year end, 70% more than last year, and we expect these levels to continue this decade. On the other hand, we saw the opposite impact on Asian LNG demand. That’s on account of several reasons but the key are: 1) More competition in the spot market (Europe kept prices high all year discouraging other buyers); 2) Improved domestic production; 3) Much lower demand due to Covid-19 lockdowns and muted economic growth, and 4) Milder weather, which prevented Asia from pulling storage and increased its injection volumes at the same time. Still, this year’s negative year-over-year change was in a way a silver lining for Europe. 

We must consider the improvements in LNG demand that we will see not only in Europe, but also in Asia next year. Considering our outlook for global natural gas demand in 2023, our post- invasion demand forecast anticipates a 5% growth in European LNG demand, while Asian LNG demand growth will hold steady, near 253 MT. As such, the two regions will increase demand next year by 2%. That points to a tight global gas and LNG market environment until new supplies can enter the market, but that is several years out. 

And who will meet the call for LNG? The same top contenders – Qatar, the US, and Australia – will continue to dominate the market, but we forecast the US will return to take the crown next year as the country is expected to grow its LNG production 11%, while Australia and Qatar will grow 2.7% and 1.5%, respectively. This strong improvement in the US is due in part to the lowered production the country experienced this year. Still, we predict the US will outpace Qatar and Australia by over 10 MT next year. 

In the first half of the year, the US was in the lead and on track to deliver approximately 86 MT of gas overseas this year. However, with the explosion at the Freeport export facility triggering an extended outage for the rest of the year, US exports fell into second place, behind Qatar. Still, US LNG has been clawing its way back since the time Freeport LNG went cold, thanks to a ramp up in dry gas output through the year – growing 3% to date – and over 16 MT in extra capacity from Sabine Pass’s Train 6 and Calcasieu Pass coming online with a swift advance. Apart from Freeport LNG, very few unprecedented events occurred. Gas infrastructure in the Gulf coast dodged the hurricane season and the winter, so far, appears to be taking its time –allowing gas storage inventories to build ahead of peak mid-winter demand. 

There is a large supply gap left to be filled with planned projects (those yet to start construction) in the short term and no projects are expected to start up next year. In addition, Russian assets, producing and under construction could be at risk – this would be a scenario in which Russia is unable to meet contract terms or if buyers back out on faulty relations. 

There are numerous pre-FID projects that could go forward next year, based on contracting activity and project ‘momentum’ but not likely to start in 2023. So, without any newly built LNG facilities in 2023, a tight global market next year is inevitable given the undersupply situation. However, we still anticipate about 14 MT (1.84 Bcfd) in global LNG supply growth next year, coming from 2022 startups including Sabine Pass Train 6 (5 MT), Calcasieu Pass (11.3 MT), Portovaya LNG (1.5 MT), and Coral South FLNG (3.4 MT). In comparison, 2022 saw a growth of 16 MT – so not bad for a year with zero new facilities. 

US Gulf Coast projects have dominated the contracting activity for LNG, as opposed to other expansions around the globe. On the supply side, most deals have been by US sellers and indexed to Henry Hub on a free-on-board (FOB) basis. Most contract periods range from 15-25 years, reflecting an increasing preference for longer-period contracts as importers look to secure supplies. From an exporting country perspective, most SPAs this year have been signed by US companies, making up 70% of global contracted volumes. It is clear the US has ample opportunities in the gas and LNG space. Now the question is: can supplies and infrastructure keep up the pace and enable the feedgas needed for these projects to deliver? 

A lot has happened this year, but we maintain our view that Europe will continue to build its energy resilience and the Asian economy will undoubtedly continue to grow – and gas will be required for that. US natural gas supply is well positioned for growth and capable of providing the gas required for global market needs but some turbulence is to be expected.

US onshore
Alexandre Ramos-Peon

The US onshore upstream industry, dominated by shale oil operations in the Permian and gas extraction in the Haynesville and Appalachia, broke several records in 2022. Perhaps the most remarkable was the profitability surprise: Rystad Energy expects all operators in aggregate to generate over $150 billion in free cash flow during 2022 from projects in US shale oil and gas plays alone. This comes despite headwinds in the form of service cost escalations and innumerable supply chain complications. To put this into context, free cash flow was around $90 billion in 2021, $15 billion in 2020, and had been in a negative range of $10 billion to $80 billion per year in the previous decade. Energy stocks, particularly companies exposed to or exclusively dedicated to shale, have unsurprisingly become the darlings of Wall Street for much of the year. The industry had been overspending for years, chasing growth at all costs, with exorbitant capital expenditures and a battle against the rapid onset of production declines that characterize low-permeability reservoirs.

The extraordinary capital discipline exhibited by operators, reluctant to increase activity levels and therefore capex even in a favorable commodity price environment surprised many market participants. Boardrooms across the US had already adopted a new philosophy: less focus on growth, with the goal now being generation of cash flow, return of capital to shareholders via dividends and buybacks, and reduction of corporate debt. However, there were serious doubts that many companies would resist the temptation to unleash fresh capital into the field when a barrel would fetch triple digits. The strategy has worked remarkably well to the dismay of those that had hoped US frackers would once again surprise the world and flood the market with shale barrels. This oversupply would have been perfectly possible with the current state of infrastructure and, had E&Ps paid upfront to re-activate drilling and pumping equipment stacked by service providers (see below details on capital discipline from the services industry).

Crude production has nevertheless increased substantially throughout 2022. Reported numbers for the fourth quarter are not available yet, but we expect the growth story to accelerate in the final months of the year, with US oil and condensate exiting 2022 at about 12.7 million bpd, over a million bpd more than in December 2021. Indeed, guidance from public producers does suggest a backloaded production profile, and growth can also be inferred from private, non-listed companies, based on strong drilling and fracking activity on their leases. Most of the growth this year is attributable to privately held companies. For various reasons, these operators have not displayed the same discipline as their public peers. In fact, since March 2022, private companies have controlled over half the rigs drilling horizontally onshore, for the first time in history, while only accounting for roughly a quarter of the nationwide output. 

As we head into 2023, opportunities in the unconventional space abound. While breakeven prices are expected to increase further due to reasons stated below, American shale oil is one of the most affordable sources of supply in the world, with the US enjoying ample export capacity. Availability of services is also set to increase, as will pipeline takeaway capacity from key basins, opening the door to additional activity. However, there are plenty of risks ahead, of which we highlight three, Besides the obvious risk associated to weaker commodity prices – caused by either weak demand in the case of a recession or excess supply from OPEC+ etc. The first is financial. Companies that have been increasing their dividends will face pressure from investors to keep doing so, as decreases in dividend yields would be punished by the market. Therefore, further substantial increases in interest rates, escalations in costs for drilling and completions (now expected at 15% for 2023, on top of 25% in 2022), poor hedging strategies could risk raising costs even further. That would mean operators would need to reduce the number of wells they bring on production, decreasing supply, revenue, employment, and service contracts.

A second risk is inventory and a continued degradation in well productivity: This year was the first in which the average well underperformed from a year prior. Indeed, productivity has been increasing for years, and a plateau is now being reached. We highlight that this is not related to so-called subsurface risks, as most of this degradation can be attributed to portfolio effects, with many private companies now drilling in sub-prime acreage, which remain nevertheless very profitable in today’s commodity price environment. While this degradation is not structural and does not impact most well-established companies with Tier 1 locations, it does negatively impact well economics at a regional level. Risks on general inventory, at a regional level, are not considered to be immediate and certainly won’t be a talking point in 2023. 

A third risk relates to regulatory environment as it pertains to flaring of excess gas: the Permian, largely an oil field, but with significant volumes of associated gas, is at absolute full takeaway capacity for gas. Any malfunction, maintenance or outage will translate to an immediate spike in flared gas, as we have seen on several occasions already in recent months, with gas prices at local hub Waha dipping once again into negative territory. Permits to flare are granted with great ease both in New Mexico and Texas. Should this change, operators would be forced to shut-in wells, and reduce their overall activity. The situation would be exacerbated should flows of Permian gas to Mexico fail to increase, as we currently expect, or if a milder winter keeps local demand in check, stressing the already overwhelmed pipelines. We believe most of the impact would be felt by smaller, private companies, as majors and public independents are subject to more stringent reporting standards. Therefore, these companies have largely secured their outbound flows and stand out as having the basin’s cleanest operations in this respect. Other regulatory risks, such as permitting for new wells on federal lands, do not pose immediate threats to the industry in the short term, despite being a popular topic in news outlets. Yet regulations around sourcing and disposal of water, in particular with mounting concerns around extraordinary seismic events in West Texas, could pose a further set of challenges.

US oil and gas supply chain
Thomas Parambil Jacob

For oilfield services companies, 2022 has been a phenomenal year as they have been able to increase prices, boost margins and strengthen their balance sheets by paying down debt, and increase shareholder value. A sold-out oilfield services market in North America meant that operators had to increase their capital budgets for 2022 just to meet their drilling and completion goals. Consolidation in the services space has helped shape the supplier landscape and give pricing power more to service companies after being beat down for several years and this will be a continuing theme in 2023, too.

Rystad Energy expects service price inflation to remain in place well into the first half of 2023 and stabilize after the summer of 2023. Service companies are now comfortable in investing where they can in newer equipment and upgrading their existing assets to next gen equipment. There have been a few announcements on new rig builds from drilling contractors despite the market still having a sizable inventory of cold-stacked rigs. Pressure pumpers are also investing in new electric fleets and upgrading their existing fleets to be natural gas capable through dual-fuel or DGB upgrades. Lead times for new builds are now well into a year and hence service companies must take a call on where energy markets would be a year from now before deciding to increase capacity. This presents both risks and opportunities as service companies that believe in a multi-year super oil cycle will need to take those decisions today if they want to ride the wave in the coming years. The flip side would be the tremendous uncertainties in oil and gas markets as can be seen with the volatility in prices. After accounting for inflation, a $70 per barrel WTI could become the new $50 per barrel. Private operators will ramp down drilling and completions programs quickly if oil prices get below $70 per barrel and this could affect service companies since private operators now account for over half of the market in the US.

Canada
Thomas Liles

It was clear from the beginning that 2022 would be a consequential year for Canadian climate policy and – by extension – the country’s oil and gas sector, which accounted for more than a quarter of Canada’s 2019 emissions. Indeed, in 2021 the federal government had not only reiterated Canada’s commitment to the 2015 Paris Agreement; it also revised its greenhouse gas (GHG) emissions reduction targets to the most ambitious in Canada’s history, with a new 2030 national emissions goal set at between 40% and 45% below 2005 levels. Moreover, this reduction target was formally enshrined in legislation through the Canadian Net-Zero Emissions Accountability Act.

As such, Canadian climate policy entered 2022 in somewhat uncharted waters, with industry players scratching their heads over the practical considerations of achieving Ottawa’s increasingly aggressive – and legally bolstered – emissions goals. The onus would clearly fall on Alberta’s oil sands sector, whose emissions-intensive upstream operations have long drawn scrutiny and ultimately compelled producers to establish the Pathways Alliance in mid-2021 with the goal of net zero by 2050. As 2022 progressed, a number of sticks and carrots emerged around climate policy. In March, the Canadian government formally unveiled its 2030 Emissions Reduction Plan (ERP) – which envisioned an ambitious 42% reduction in oil and gas sector emissions by 2030 in comparison to 2019 levels – and announced plans to enforce more stringent guidelines for future oil and gas projects to ensure ‘best-in-class’ emissions performance. The Department of Finance followed up with a policy carrot in its 2022 federal budget in April, which put forth a slew of investment tax credits for carbon capture and storage (CCS). The move was lauded by the industry, as Pathways had previously identified CCS as the anchor for long-term decarbonization of the oil sands.

Producers perceived another shot across the bow in July, when the government released a discussion paper on regulatory approaches to capping oil and gas sector emissions, including a sector-specific cap-and-trade system and stricter pollution pricing. More detailed draft guidance around ’best-in-class’ GHG emissions emerged in early October and underlined the government’s commitment to rapid decarbonization, as the guidance would effectively require future oil sands projects to compete with the lowest-emitting onshore oil production projects globally from an emissions perspective. On the flipside, provincial regulators in Alberta approved plans for Pathways’ massive carbon sequestration scheme. Pathways subsequently announced its intention to invest C$16.5 billion in CCS by 2030, the first time the consortium had attached a concrete dollar amount to the scheme.

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Authors: 

Claudio Galimberti  

Senior Vice President of Oil Markets, Head of Americas Research 
claudio.galimberti@rystadenergy.com

Emily McClain

Vice President, Gas Markets
emily.mcclain@rystadenergy.com 

Geoffrey Hebertson

Analyst, Renewables
geoffrey.hebertson@rystadenergy.com 

Marcelo Ortega

Analyst, Renewables
marcelo.ortega@rystadenergy.com 

Alexandre Ramos-Peon

Vice President, Shale
alexandre.ramos-peon@rystadenergy.com 

Thomas Parambil Jacob

Senior Vice President, Onshore Supply Chain
thomas.jacob@rystadenergy.com 

Thomas Liles

Senior Vice President, Upstream
thomas.liles@rystadenergy.com 

(The data and forecasts contained in this column are Rystad Energy’s and the opinions are of the authors.)