The final set of financial numbers for 2019, and for an interesting decade in terms of oil prices, came to an end as a tale of two parts. With the quarter characterised by stubborn crude prices despite OPEC+’s efforts and slumping gas prices amid a global glut, it was always going to be a challenging quarter. Most numbers from supermajors and majors came in as disappointing, but there were several bright spots where even the most optimistic expectations were exceed.
Shell, the first to report, set the tone for the cycle, showing a 48% fall in net profits from a 19% y-o-y drop in revenue. Citing weaker refining and chemical margins from slowing global growth with China and the US still locked in a trade war, the weaker results led Shell to scale back the pace of its US$25 billion share buyback programme. With only US$1 billion of shares to be bought back in Q12020 – down from the regular US$2.75 billion per quarter. Shell warned that the programme’s schedule was still at risk due to the softening global economy. It is likely that Shell will miss its deadline of completing the buyback by end-2020; investors were not impressed, and sent Shell’s share prices down to a two-year low in response.
The US supermajors came next, with both ExxonMobil and Chevron failing to meet market expectations. For ExxonMobil, revenue and net profits were both down by 5%, with the company blaming the ‘tough environment’ and depressed margins for its oil, gas, refining and chemicals businesses that will spill into 2020. Its financials, however, were boosted by the sale of its non-strategic assets in Norway, and noted that its oil extraction in Guyana was going ahead of schedule and could have a positive impact on Q1 financials. Unlike ExxonMobil, Chevron did not have strategic asset sales to fall back on. In fact, it went the opposite way. Having warned investors that it was preparing to take a major write-down on a collection of assets, including shale gas production in Appalachia and deepwater projects in the Gulf of Mexico, the final charge came in at US$10.4 billion. That wiped Chevron’s profits out, reporting a net loss of US$6.6 billion for Q419. Segment performance was stable, beating analyst expectations in some cases. But the pressure of low oil and gas prices will persist.
Things then got better. In the final results for retiring CEO Bob Dudley, who will be replaced by Bernard Looney, BP reported net profits of US$2.57 billion, exceeding even then highest analyst estimate. With a solid upstream performance and boosted by its in-house trading arm, BP bucked the negative trend, allowing it to raise its dividend level, a notion that it had rejected in the last quarter, while also completing a US$1.5 billion share buyback programme. Rounding off the quintet, Total also exceed the expectations of the market. Although the French company was also affected by slumping natural gas prices, along with strikes at its French refineries, record production boosted net profits to US$3.17 billion, almost unchanged y-o-y. The ramp-up of key natural gas projects, Yamal in Russia and Ichthys in Australia, along with the start of the Egina and Kaombo crude oil projects in West Africa, raised upstream output by 9% over a quarter where all other rivals saw their production decline.
When the decade started in 2010, crude oil prices were riding high at US$80/b. It would soon peak at nearly US$120/b in 2011, stay elevated for 3 years, halving by end-2014, slumping down to US$30/b in 2016 before beginning a gradual recovery. This 10-year see-saw ride has been mirrored in the financial performance of the energy supermajors. With a new decade starting with plenty of uncertainty, the fiscal discipline adopted since 2015 by the supermajors will be key to supporting their business activities going forward in troubled times.
Supermajor Financials Q4 2019:
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This winter, natural gas prices have been at their lowest levels in decades. On Monday, February 10, the near-month natural gas futures price at the New York Mercantile Exchange (NYMEX) closed at $1.77 per million British thermal units (MMBtu). This price was the lowest February closing price for the near-month contract since at least 2001, in real terms, and the lowest near-month futures price in any month since March 8, 2016, according to Bloomberg, L.P. and FRED data.
In addition, according to Natural Gas Intelligence data, the daily spot price at the Henry Hub national benchmark was $1.81/MMBtu on February 10, 2020, the lowest price in real terms since March 9, 2016. Henry Hub spot prices have ranged between $1.81/MMBtu and $2.84/MMBtu this winter heating season (since November 1, 2019), generally because relatively warm winter weather has reduced demand for natural gas for heating. Natural gas production growth has outpaced demand growth, reducing the need to withdraw natural gas from underground storage.
Dry natural gas production in January 2020 averaged about 95.0 billion cubic feet per day (Bcf/d), according to IHS Markit data. IHS Markit also estimates that in January 2020 the United States saw the third-highest monthly U.S. natural gas production on record, down slightly from the previous two months.
IHS Markit estimates that U.S. natural gas consumption by residential, commercial, industrial, and electric power sectors averaged 96 Bcf/d for January, which was about 4.4 Bcf/d less than the average for January 2019, largely because of decreases in residential and commercial consumption as a result of warmer temperatures.
However, IHS Markit estimates that overall consumption of natural gas (including feed gas to liquefied natural gas (LNG) export facilities, pipeline fuel losses, and net exports by pipeline to Mexico) averaged about 117.5 Bcf/d in January 2020, an increase of about 0.2 Bcf/d from last year. This overall increase is largely a result of an almost doubling of LNG feed gas to about 8.5 Bcf/d.
Because supply growth has outpaced demand growth, less natural gas has been withdrawn from storage withdrawals this winter. Despite starting the 2019–20 heating season with the third-lowest level of natural gas inventory since 2009, by January 17, 2020, working natural gas inventories reached relatively high levels for mid-winter. The U.S. Energy Information Administration’s (EIA) data on natural gas inventories for the Lower 48 states as of February 7, 2020, reflect a 215 Bcf surplus to the five-year average. In EIA’s latest short-term forecast, more natural gas remains in storage levels than the previous five-year average through the remainder of the winter.
According to the National Oceanic and Atmospheric Administration (NOAA), January 2020 was the fifth-warmest in its 126-year climate record. Heating degree days (HDDs), a temperature-based metric for heating demand, have been relatively low this winter, which is consistent with a warmer winter. During some weeks in late December and early January, the United States saw 25% to 30% fewer HDDs than the 30-year average. This winter, through February 8, residential natural gas customers in the United States have seen 11% fewer HDDs than the 30-year average.
Source: U.S. Energy Information Administration, based on National Oceanic and Atmospheric Administration Climate Prediction Center data
Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b
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