S&P Global Ratings raised its average price assumptions for Brent and West Texas Intermediate (WTI) crude oil for the remainder of 2018 by $5 a barrel (bbl) to $70/bbl and $65/bbl, respectively, and for 2019 by $5/bbl to $65/bbl and $60/bbl. We also raised our Brent price assumption for 2020 by $5/bbl to $60/bbl, while our WTI assumption for 2020 is unchanged at $55/bbl. Our Henry Hub natural gas price assumptions are unchanged at $3 per million Btu through 2020. In addition, we added price assumptions for 2021 to our price deck (see table 1). These revisions are effective immediately.

We use this price deck to assess sovereign and corporate credit quality, in particular for exploration and production (E&P) companies, in accordance with the ratings methodology set forth in "Methodology For Crude Oil And Natural Gas Price Assumptions For Corporates And Sovereigns," published Nov. 19, 2013.

Despite the increase in our price deck assumptions, we anticipate relatively few rating actions resulting solely from these revisions. Widening negative price differentials will limit the benefit from improved near-term pricing for some North American regions, particularly the Permian basin in West Texas and in Canada, where pipeline takeaway capacity hasn't kept pace with production growth. In addition, for many companies we believe incremental cash flow generated from higher oil prices will either be absorbed by higher oilfield service costs, especially in North America, or returned to investors through share repurchases or dividends. Some of the largest integrated oil companies are only now showing last 12-month-trailing credit metrics just in line with our lower thresholds for our respective ratings on them. These circumstances are likely to hinder widespread positive rating actions despite improving near-term earnings and cash flow.

Our near-term oil and natural gas price decks broadly reflect our assessment of futures prices. We recognize the typical volatility of these market indicators as demonstrated during 2017 and 2018 to date. We also expect the $5/bbl differential between Brent and WTI to persist through 2020, although we expect it to contract thereafter as new pipeline capacity comes on line in the Permian, allowing additional U.S. oil volumes to reach the coast for export. We base our long-term price assumptions mostly on fundamental supply-demand analysis, but also include assessments of the marginal cost of oil and gas production.

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Oil Demand Continues To Rise, Led By Developing Economies

We expect overall oil and oil product demand to remain robust over the next three years, underscored by the solid macroeconomic environment. S&P Global economists project global GDP to increase by 3.9% in 2018, 3.9% in 2019, and 3.6% in 2020, which supports our view that oil demand will continue to rise. Although the pace of growth slowed slightly in the second quarter this year due to weaker demand in the member countries of the Organization for Economic Cooperation and Development (OECD) and Asia and the impact of higher U.S. gasoline prices, the International Energy Agency (IEA) continues to forecast global oil demand growth of 1.4 million barrels per day (mmbbls/d) in 2018 and 1.5 mmbbls/d in 2019. Demand growth is being driven largely by China and India; therefore, a key risk to the demand picture through 2020 is the potential escalation of U.S.-China trade disputes.

These near-term dynamics are in contrast to multi-decade pressures on oil demand because of environmental concerns and resulting policies. We believe the adoption rate of electric vehicles and the speed of the broader energy transition are critical factors in this respect. While the rate of change is uncertain, with every year that passes, they play an increasingly larger role in both demand scenarios and company strategies.

U.S. Shale Leads Global Production Growth

According to the U.S. Energy Information Administration (EIA), global oil supply will continue to grow by about 2% each year in 2018 and 2019. This reflects net increases in production especially from non-OPEC countries.

In June 2018, OPEC, Russia, and others agreed to start unwinding 1.0 mmbbls/d of production cuts, out of a combined total cut of 1.8 mmbbls/d initiated at the start of last year. However, these increased volumes are essentially offsetting structural production declines in Venezuela, lower production from Mexico, uncertainties about the resilience of the rebound in Libya, and reducing Iranian exports as a result of U.S. sanctions restarting in November.

The U.S. continues to lead non-OPEC supply growth over the next two years, with Canada and likely a greater contribution from Brazil contributing volumes in 2019. Tight oil production, in particular, is driving the 14% U.S. growth to 10.7 mmbbls/d in 2018, estimated by the EIA, with an additional 7% increase next year. The EIA recently lowered its 2019 projection due to infrastructure constraints and a slower pace of growth in the Permian, where production of 3.4 mmbbls/d has nearly reached crude takeaway capacity. The insufficient infrastructure has led to a sharp increase in the number of drilled but uncompleted (DUC) wells and wide oil price differentials for production in the basin. A number of additional pipelines should be operational by the end of next year, which we believe will lead to narrower differentials and increased production.

This situation is also reflected in the significant differentials between the Brent and WTI benchmarks, as U.S. stocks build at Cushing, Okla. We assume a $5/bbl Brent-WTI differential for the remainder of 2018, 2019, and 2020, with the benchmarks converging in 2021 as infrastructure constraints ease.

OECD stocks of oil and oil products are reported just below the five-year average, despite modest recent increases, implying support for prices. In addition, some market participants are focusing on the rate at which Saudi Arabia and others could use their spare production capacity in the event of a supply shortfall or shock relating to Iran or otherwise.

Our Long-Term Oil Price Assumptions Remain Unchanged, Based Largely On Our View Of The Marginal Cost Of Supply

Our long-term price deck assumptions of $55/bbl for both Brent and WTI mostly reflect our view of the pronounced industry cost deflation that has taken place over the past few years. We also recognize that oil demand growth over the next few years is likely to remain positive, albeit moderating over time.

After a decade of inflationary pressure prior to 2015, marginal production costs have declined significantly due to engineering optimization, improved drilling efficiencies, and cost reductions, especially in higher-cost U.S. shale formations. Drillers, forced to improvise because of the low prices, have introduced new drilling, fracking, and well-completion techniques that have resulted in more permanent cost reductions.

While we've seen some upward pricing pressure recently from oilfield service companies, particularly for onshore U.S. completions, many operators are targeting at least flat or lower unit costs through ongoing improvements in efficiency, digitization, or closer cooperation with service companies and drillers.

We have yet to see a significant impact from lower investment levels since 2015 on the net global supply of oil. Part of the reason for the progressive rise in production has been the start-up of large deepwater or greenfield projects that were sanctioned before 2014 but took several years to come online. These types of projects have taken a back seat since 2014 to shorter-cycle shale projects, so we believe natural field declines combined with a lower level of major new field developments are likely to have an increasingly negative impact on supply.

Robust Natural Gas Supply Will Likely Meet Demand Growth

We continue to see a fundamental shift occurring in the U.S. natural gas production profile; production has veered from the Southwest and Rockies to the prolific Marcellus and Utica shale plays in the Northeast. We don't believe Marcellus and Utica have reached their full production potential given the wide, but narrowing, price differentials in those areas. However, we expect that the significant build-out of takeaway capacity occurring over the next 12-18 months will narrow the differentials and lead to ongoing increases in production.

The boom in U.S. oil shale drilling in recent years has also produced natural gas as a by-product of liquids extraction, with a significant ramp-up in natural gas production from the Permian basin and other oil regions. However, similar to the Northeast, natural gas production has exceeded existing processing and takeaway capacity, resulting in wide natural gas basis differentials in the Permian. Several new pipelines are under construction, which should alleviate this bottleneck over the next two years.

Once the takeaway capacity constraints are relieved, we believe these low-cost plays will be able to quickly meet any uptick in demand (e.g., from increased power generation, industrial production, or liquefied natural gas exports) effectively creating a cap on prices.