On the 30th of November, OPEC in its 171st meeting in Vienna, Austria, reached its milestone decision to reduce the cartel’s production to 32.5Mbpd, equating to a drop of around 1.2Mbpd from its record October output of almost 34Mbpd. This resulted in an instantaneous surge in the Brent, which rose 8.8% from the previous day to November’s closing price of US$50.47/bbl. However, on a monthly basis, the November Brent marker average was down 8.4% month on month to an average of US$47.08/bbl.
Prior to OPEC arrangements, combined members of the cartel
were producing at their highest production rate in over ten years, up 0.5% from
September. Saudi oil supply reduced only slightly by 0.2% from 10.6Mbpd in
September, to 10.58Mbpd in October, but Iraq’s output increased by 1.1% month
on month to an all-time high of 4.59Mbpd in October. Iran increased its output
by 1.4%, to 3.68Mbpd in October—its highest rate since the 2011 sanctions. The
surprise production increase came from Libya, following the opening of the
country’s eastern oil ports; its oil supply grew 53% month on month to its
highest levels in October at 520kbpd.
In the implementation of OPEC’s new production target, Saudi
has agreed to make the largest cut from its November output, estimated to be
between 10.56Mbpd and 10.6Mbpd to 10.06Mbpd. Iraq is required to cut production
to 4.351Mbpd. Qatar, Kuwait and the United Arab Emirates will cut output by a
combined total of 300kbpd. Though Iran, Nigeria and Libya were granted special
dispensation, Iran’s production ceiling is set at 3.797Mbpd. Non-OPEC
countries, including Russia, have also committed to cutting output by 600kbpd.
Indonesia, unable to cut output since it became a net importer of oil, was
suspended from the cartel only 12 months since it was last admitted.
Earlier this month, Shell announced that it is reconsidering
its position in Iraq and its assets in the country could become part of its
global US$30bn asset disposal programme. Shell has a 45% interest in the giant
12.85Bbbl Majnoon oil field, which produced at around 210kbpd in 2015, and has
a 15–20% stake in the 8.7Bbbl West Qurna-1 field, which produced at around
500kbpd in 2015.
AME maintains its demand growth forecast for 2016, which is
expected to rise 1.35%, or 1.3Mbpd, to 94.94Mbpd from 93.68Mbpd in 2015. Growth
in 2017 is forecast to remain flat at 1.3Mbpd (1.4%). Asia will be the
strongest driver of demand growth in both 2016 and 2017, with demand forecast
to grow at 3.1% and 3%, respectively. Africa is forecast to see the second
highest growth in demand in 2016 and 2017, forecast at 2.2% and 2.4%,
Other operational highlights for the month include:
- Gulfport Energy remaining as one of the more active E&P companies since the late 2014 decline in oil price, owing in large part to its strong position in the core of the prolific Utica Shale of Ohio, US. The operator released its 2016–2017 guidance, in which it made clear of its plans to complete 39 Utica wells, put-into-production (PIP) 41 wells, and produce ~20Mcmpd. In 2017, it expects to operate six drilling rigs with the objective to expand output to 24–26Mcmpd.
- Total’s Moho Nord project, located offshore the Republic of Congo, is set to add 100kboepd of production after its 2017 start-up.
- Chevron achieved first oil at its US$5.6bn, 300Mboe Mafumeira Sul field, offshore Angola. Production is expected to ramp up from current levels of around 10kbpd to 110kbpd by 2018.
- Statoil and its JV partners are expected to come to decision in December regarding the potential for progressing the US$3–3.3bn expansion plan for the Snorre oil field in the North Sea, Norway. In February 2016, Statoil scrapped the previous platform concept for the project and focused on a subsea tieback solution to reduce costs in the low-oil price environment. Statoil and its partners have been working on the 200–300Mbbl Snorre’s expansion project, also known as ‘Snorre 2040’, for more than a decade without any agreement on the development concept.