Non‐OPEC production under pressure

• Published date: 01 September 2020
• Date: 01 September 2020
• DOI: http://doi.org/10.1111/oet.12816

LOOKING AHEAD

Non-OPEC production under pressure

North American oil producers have brought back part of

the output they shut-in due to low prices earlier this year,

but a sustained rise will take more time and higher

prices, while reduced revenue, environmental concerns

and weaker anticipated long-term prices are leading to

sharp capex cuts among listed oil companies, which will

mean lower future non-OPEC output than had been

expected.

US production fell sharply through the spring

months, especially from onshore wells, with total output

down to about 10.5 mn bpd in May, from a high of just

over 13 mn bpd in late 2019. Since then output has recov-

ered slightly and is expected to rise to around 11.25 mn

bpd by October. Looking at 2020 as a whole, the US

Energy Information Agency (EIA) slashed its 2020 fore-

cast on August 11th by 370 000 bpd from July's outlook

to 11.26 mn bpd, based on more extensive curtailments

than had been previously estimated, given the continued

high US COVID-19 contagion rates and on-going demand

disruption.

However, the EIA also raised its 2021 outlook for US

production by 130 000 bpd to an average 11.14 mn bpd,

although this was still below 2020's figure, and well

below the 2019 average of 12.25 mn bpd. The forecasts

assume WTI crude prices of $38.50/bbl in 2020 and

$45.53/bbl in 2021, with Brent averaging $41.42/bbl in

2020 and $49.53/bbl in 2021—so not far off current levels.

The EIA also assumes Energy Transfer's 570 000 bpd

Dakota Access Pipeline (without which Bakken produc-

tion would be constrained) will continue operating after

an appeals court overturned a district judge's earlier order

to shut the system—however, in general, with a possible

Democrat victory in the US Presidential elections in

November, political or legal constraints on output could

become more of an issue.

Among those bringing back onshore US production,

Chevron said in early August that it had returned all

curtailed output as a result of improving price levels—

reversing cuts of 200 000-300 000 boe/d in May and in

June—mostly from the Permian Basin of West Texas/

New Mexico. This represents about half the company's

global curtailments, with the remainder outside the

United States expected to last longer. ExxonMobil said it

had brought back about 40%, with just 200 000 boe/d

now shut-in—most of which is associated with OPEC-

plus cuts. Independent shale producers are also bringing

back output. For example, EOG Resources restored crude

output of 73 000 bpd in Q2 and expects only 25 000 bpd

to be shut in on average in Q3, with nearly all wells

restarting by end-September. However, some companies

expect some wells to be shut-in for good.

Cuts under the wider OPEC-plus agreement have also

affected some countries not normally associated with

OPEC-plus—notably Norway and Brazil, although they

will be able to quickly bring production back online as

agreed cuts are eased.

Apart from that, most of the non-OPEC swing pro-

duction is in the US onshore, where activity is particu-

larly weak, decline rates high and rig numbers still near

record lows of about 250. Looking further ahead capex

cuts are likely to cut future output unless prices rise.

Exxon is expected to cut its end-June rig count of 30 in

the Permian by another 15 before the end of the year.

Chevron expects second-half spending in the Permian to

be about 75% lower than in Q1, which would mean a pro-

duction decline of 6% to 7% in 2021. And a number of

independents have said they will not boost activity until

prices recover to the $50/bbl, with the focus for most

firmly on cash flow. The lack of drilling activity could

tighten supply and push oil prices up to $60/bbl at some

point next year unless output creeps up beforehand. S&P

Global Platts Analytics expects total US oil production to

decline around 2 mn bpd by 2022, as opposed to a rise of

1.3 mn bpd predicted in pre-price collapse forecasts.

1|WEAKER OUTLOOK

FROM MAJORS

Most big oil companies have cut their capex budgets and

oil price forecasts, which will mean fewer oil and gas pro-

jects get built more widely—resulting in lower future

non-OPEC output. For example, Chevron's 2020 capex

was reduced earlier this year to $14 bn from $20 bn, and

others have cut by similar amounts. Already there have

been project delays and cancelations announced, while

doubt now surround a number of more marginal or fron-

tier provinces, such as offshore Senegal/Mauritania,

where BP and others had plans for significant gas

investment.

New emissions targets and higher anticipated carbon

prices are also leading projects to be dropped. Total has

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