Global energy market outlook 2023 review

In 2022, global crude prices were volatile due to various factors, including the Eastern conflict, inflation, monetary policy restrictions, OPEC+ output cuts, and uncertainties related to China's recovery from Covid-19 restrictions. However, reduced consumer activity associated with recession risks stabilized the balance of supply and demand. The positive demand drivers, such as China reopening, have the potential to sustain elevated crude prices. Record crude production from the US, Canada, and other producers came online due to years of underinvestment and supply volatility from sanctions on Russian crude, which resulted in elevated crude prices reaching above $100 US per barrel. However, further Russian crude production cuts stemming from the implementation of a price cap may drive additional supply risk.

Several sanctions, including an international payment system ban (SWIFT) and the ban of Russian oil imports, have been imposed due to the Eastern conflict. G7, EU, and Australia set a price cap on Russian crude (effective December 5th at $US 60 per bbl). Russia's proposed 7% cut to oil output and halt of sales to price cap supporting nations may materially tighten crude markets. However, China and India have stepped in to support Russian crude, benefiting from steep discounts on sanctioned barrels. Russia's ability to market discounted barrels through China and India may partially limit the efficacy of the imposed price cap, but it will not completely relieve the impact on global crude trade flows.

LTO producers have increased CAPEX guidance upwards throughout the year, reflective of high rig day rates and increased casing, cement, and other costs. Reinvestment into the drill bit remains well within producer cash from operations, favoring free cash flow generation. Efforts to re-supply the SPR may limit flows of U.S. LTO onto the market over the short term. Growth for U.S. production will be limited as drilling activity focuses on Tier 2 and Tier 3 inventory.

Despite elevated crude prices, many producers remain hesitant to materially increase capital budgets, adhering to a strategic shift toward increased capital discipline and return of capital to shareholders. Capital spending has struggled to translate into meaningful production growth given record rig day rates, material costs, and direct labor costs. The trend of an increasing portion of capital spending from producers being allocated to energy transition related investments is predicted to continue. However, this still only represented 5% of overall capital spend allocated by upstream players in 2022.

OPEC+ fell short of production quotas over August by 3.3 mmbbl. The resulting 2 mmbbl/d cut announced for November affirms OPEC's preference for a tight market, managing the market narrative of recession risk and countering the direct request of the Biden administration to postpone the OPEC decision.

The production of OPEC+ has faced difficulties in 2023 due to shortfalls in Nigeria and Angola. Inflationary pressures and flooding in Nigeria have further worsened the situation. OPEC+ has not yet responded proactively to the potential increase in oil demand from China's reopening. OPEC's production targets are unchanged and are not expected to increase without sustained improvement in demand from China.

The Strategic Petroleum Reserves (SPR) are likely depleted, which has led to lower disruption on sour crude differentials. The volatility in the spread between Brent and North American crudes has increased due to the release of 182 mmbbl of sour and 84 mmbbl of sweet crude from January 2021 to January 2023. The Brent crude differential to WTI has widened because of SPR releases flooding the U.S. market and a tight physical market in Europe. The wider differential has notably impacted Western Canadian Select (WCS), but refinery outages and sour crude production growth have also contributed to this.

Despite high-interest rates, consumer habits have remained strong. China's removal of COVID-19 restrictions and increased refinery capacity are expected to be a significant positive demand driver. China has already added 520,000 bbl/d in refining capacity in 2023 and is expected to reach 11.8 mmbbl/d in crude import. However, a key uncertainty is how much of this demand growth will be met using sanctioned Russian crude. Petroleum product consumption has remained stable despite high-interest rates, although growth in jet fuel consumption has been limited due to a longer road to recovery for airline travel.

High rates have driven greater capital discipline and limited production growth. The Weighted Average Cost of Capital (WACC) for several companies has increased by over 2.5% following the rate hike cycle from 2004 to 2007. Historically, high-interest rates have led to either no growth or a decline in crude supply. Despite high-interest rates, demand has continued to demonstrate low price elasticity consistent with previous cycles, indicating a tighter crude market in the latter part of the rate cycle.

The increase in global inventories and recessionary pressures has reduced the near-term pricing outlook. Limited availability of clean tankers and EU sanctions on Russian oil may put pressure on the global oil supply. Russian production cuts, coupled with OPEC+ struggling to meet production quotas, may result in a tight physical market with no clear relief path. US LTO is unlikely to provide any additional support due to record rig day rates, staffing shortages, and high material costs. Despite recession risks, resilient liquids product demand and consumer activity, as well as increased consumption from China, will support demand.

Increased capital allocation to energy transition investments have limited the project pipeline for megaprojects. However, incremental production from Guyana's deepwater Liza oil field and Norway's recent start-up of the offshore Johan Sverdrup Phase 2 expansion project, increased upstream investment remains crucial to meet demand growth despite volatile economic conditions. The global crude price is expected to be supported within the mid-$80s range for 2023 to 2025.

According to a report, Canadian crude production is expected to increase and compete with U.S. LTO plays. The Transmountain pipeline expansion (TMX) project, which is scheduled to be fully operational in 2024, will increase the supply of Canadian crude to global markets by providing additional pipeline capacity of 590,000 bbl/d. The differential between WCS and WTI has widened due to refinery outages and major petroleum strategic releases occurring in the United States, but additional Venezuelan sour crude supply has not yet materialized. This could occupy a portion of U.S. sour refinery capacity otherwise used by Canadian crude. With Russian gas unavailable to fill storage, Europe may face high volatility in gas prices while refilling storage for winter 2023. The report suggests that without the reliance on Russian gas for a baseload storage fill, Europe will continue to dominate LNG activity going forward. Increased global LNG activity is expected to continue as a reliable storage fill option for Europe in the coming winters. The global LNG project pipeline is robust over the long term, and fairly limited liquefaction capacity additions in 2023 and 2024 will keep LNG markets tight.

The energy transition is expected to increase the demand for natural gas in the medium term. Although decreased manufacturing activity and increased renewable capacity may lead to a decline in natural gas prices at the Henry Hub, natural gas is still important in the transition to cleaner energy and is expected to replace coal power plants. However, there may be limited production growth due to rising rig day rates, supply chain constraints, and regulatory challenges associated with developing new midstream infrastructure.

AECO's seasonal volatility is expected to continue, although the Coastal GasLink capacity is expected to alleviate this issue in 2025+. In 2022, AECO experienced significant differentials to Henry Hub due to NGTL system upgrades, with East Gate driving most of the capacity limitations. Relief from Coastal GasLink is expected in 2024, which should provide additional takeaway capacity as Asia demand continues to recover.

The expansion of natural gas plays in the U.S. is expected to be driven primarily by the expansion of LNG facility capacity and exports. The outlook at Henry Hub is $4.25 US per MMBtu from 2025+, with an escalation of 2.0% thereafter. Near term, Canadian gas at AECO will continue to be marginalized, and the AECO differential is expected to normalize to a $1.00 USD/MMBtu differential to Henry Hub by 2025, once LNG Canada is fully operational and NGTL system upgrades have been completed.

Uncertainty in the European natural gas price outlook is driven by supply concerns due to the Eastern conflict. European gas prices are expected to stabilize towards higher cost LNG as Europe builds out regasification infrastructure, with NBP trading at $15.00 US per MMBtu and TTF trading at $16.00 US per MMBtu by 2025.