Beware the Dip: oil prices could go lower without an actual geopolitical disruption
The spike in oil prices since August provides US producers an attractive opportunity to hedge their 2018 capital program. With a typical lag, it will likely result in acceleration in US oil production growth from 2Q18. Coupled with a seasonal dip in global demand in 1Q18, which will cause sizable excess oil inventories to persist, a correction in oil prices is likely. Surplus oil inventories are likely to remain through 2018, taking the steam out of the upward momentum in prices without an actual supply disruption. Inventories will still be above the 5 year average in 4Q18, but smaller.
WTI is $56/B in response to increased geopolitical anxiety, up from an average of $49.33/B for the first 9 months in 2017. Without high geopolitical risk or an actual supply reduction, oil prices have downside risk. Fundamentals alone suggest an average near $53/B as a working number over the next 12 months until greater clarity emerges, with a varying geopolitical risk premium additive.
Brent is $62/B, selling at a $6.47/B premium over WTI. The wide spread encourages US exports and discourages imports. Through August, the 2017 Brent premium over WTI was $2.01/B. Plentiful crude at Cushing OK, the NYMEX pricing point, will drain with the addition of new pipeline takeaway capacity. Crude stocks along the US Gulf, East, and West Coasts are well below last year’s levels. Tanker tracking data indicates Asia is set to ramp up crude oil imports from the US in late 2017 and early 2018, while US crude imports declined significantly since August. The Brent premium will likely slowly contract.
Oil prices and the Brent premium widened dramatically in the aftermath of seasonal maintenance in the North Sea, September hurricanes, the Kurdish vote for independence, the threat of increased militant activity in Nigeria, the imminent possibility of Venezuela’s bankruptcy, the Saudi crackdown on corruption in the Kingdom, and increased tension between Saudi Arabia and Iran.
In response to the Kurdish vote for independence, Turkey threatened to choke off crude oil exports through Turkey which were 575 MBD in September. Iraq subsequently took control of the Kirkuk oil field and related export pipelines in mid October but exports from northern Iraq are still offline. Iraq’s October production was 4.38 MMBD with exports entirely from the south. Its oil minister said it plans to increase production from Kirkuk oil fields to 1 MMBD. He also said Kurdish authorities are not cooperating.
Venezuela’s worsening economic and political crisis is speeding a decline in production which will likely continue for some time. October production of 1.86 MMBD was down 257 MBD Y/Y. A similar if not greater decline is anticipated in 2018. It will likely continue to decline in 2019 and beyond due to extensive deterioration in equipment and the loss of skilled labor which are expected to take several years to repair. Little if any investment is being made upstream.
State owned PDVSA is in disarray, unable to pay workers, make repairs to aging infrastructure, or buy diluent to pump its extra heavy crude, which is also used to provide retail diesel and gasoline for the domestic market. Many of its refineries run at reduced capacity. Its crude exports are declining.
Earlier this month it proposed a $60 bn debt restructuring to bondholders, which was widely seen as a signal of possible default that could affect other debt. In addition to bonds, it owes $26 bn to creditors, and $24 bn in commercial loans. Three of the largest oil service companies, who are owed $1 bn combined, are no longer seeking new work in the country for lack of payment.
Its October production was worth less than $30 bn in today’s market before expenses and the cost of social programs. Large volumes of export crude do not generate cash but are committed to supply agreements with China, Cuba, and other nations in exchange for loans or goods and services.
The quality of its crude exports has deteriorated noticeably this year, with some cargoes rejected due to high salt content, excess water, and contaminants. Export cargoes sit for days awaiting inspectors hired by refiners to verify its crude meets specifications.
Nigeria produced 1.74 MMBD in October. Its oil minister said its production would not rise above 1.8 MMBD. Militants in the oil rich Niger Delta region have issued new threats to disrupt production to obtain a greater share of oil revenues. Nigerian production fell as low as 1.39 MMBD in 1Q17.
Even Saudi Arabia is under growing pressure. The World Bank estimates its reserves are down 26% from the $547 bn peak in 2016. The IMF estimates it needs $70/B oil price to balance its 2018 budget. It plans to sell 5% of Saudi Aramco in 2H18 which it hopes will raise $100 bn. Low oil prices would make that difficult. Its purge of corrupt members of the royal family and others seeks to recover $100 bn stolen through graft. It produced 10.01 MMBD in October, 10% of world oil supply.
Libya continues to face ongoing security challenges. October production was 962 MBD, up from a low of 310 MBD in 3Q16.
A 100 MBD change in production from any of them changes global oil inventories quarterly by 9 MMB.
Total October OPEC production was 32.53 MMBD, down 817 MBD from 4Q16. The recovery in Libya and Nigeria, who were exempted from the OPEC agreement to cut from January 1, added a combined 670 MBD since 4Q16, offsetting over half the impact of the cut by other producers. Other OPEC compliance with the agreement remains high. Expectations the cut will be extended to the end of 2018 from an end of March expiration is widespread. OPEC is scheduled to meet in Vienna on November 30.
Without an actual geopolitical supply disruption, latest fundamentals indicate surplus oil inventories will remain high through 2018. This assumes OPEC production remains near October levels adjusted for a steady decline in Venezuela. A 200 MBD Y/Y decline in total OPEC production in 4Q18 is indicated.
When OPEC announced its production cut a year ago, it believed elimination of the surplus in OECD inventories to the 5 year average would increase oil prices to $60-65/B. In September, the surplus was still 154 MMB larger, but down from a 318 MMB surplus earlier in the year. The surplus reached a record high in 1Q16 at 380 MMB above the 5 year average. The OECD accounts for 48% of total world oil demand.
Current data indicates a decline in OECD inventories of 16 MMB in 4Q17 followed by a seasonal increase of 28 MMB in 1Q18. By 4Q18, OECD inventories are projected to be 28 MMB smaller than September 2017 but still significantly above the 5 year average.
US producers are poised to accelerate production growth in 2018. Latest data indicates US liquids production will average 13.24 MMBD in 4Q17, up 940 MBD Y/Y. A preliminary estimate indicates even faster growth over the next 12 months, up by 1.32 MMBD to reach 14.56 MMBD in 4Q18, maybe more. The outlook will become more definitive in coming weeks after 2018 capital budgets are announced.
US e&p companies issued $3.6 bn high yield bonds in October, the most since December 2016, which points to a ramp up in 2018 drilling activity.
While the current US oil directed rig count of 738 is down from a July peak of 768, a rig count this low is sufficient to support sequential oil production growth in the 4 major resource plays of 83 MBD per quarter, 332 MBD annually, despite an increase in the production decline rate from legacy wells. 4Q17 production from these plays is up 806 MBD from 4Q16. Oil field inflation has eased since the July rig count peak.
Production from the Gulf of Mexico in 4Q17 is 1.63 MMBD, down 40 MBD Y/Y after the impact of September hurricanes. With normal production and the ramp up of new projects sanctioned prior to the downturn, it is expected to increase 160 MBD by 4Q18.
US natural gas liquids production has grown steadily, up 400 MBD Y/Y to 3.72 MMBD in 4Q17. Another increase of 530 MBD, largely from the major resource plays, is expected by 4Q18.
The rate of total US liquids production growth is likely to accelerate from 2Q18 with a recovery in drilling activity. The recent spike in WTI oil prices to $58/B provides producers an attractive opportunity to hedge 2018 production. Reflecting a typical 6 month lag in the oil rig count to changes in oil prices, the July 2017 rig count peak likely reflected January-February oil prices of $53/B. 3Q17 production from these plays grew by 287 MBD Q/Q. The decline in the rig count since the peak and slower production growth since is also likely a response to the $42/B June low in WTI.
In addition, fewer rigs are now required to grow production. Wells are now drilled faster due to drilling efficiency gains and wells have become even more productive and profitable. As an illustration, Continental Resources’ (CLR) latest Bakken wells have an estimated ultimate recovery of 1100 MBOE, up from an EUR of 800 MBOE in 2015 and 603 MBOE in 2014. They generate an 82% rate of return at a $50/B oil price, compared to a 5% ROR with 2014 well productivity. Production costs are now less than $7/BOE.
In its recent earnings call, CLR said `the entire Bakken Field has been uplifted to a new level in the last 12 months from a breakthrough provided by a new completion design.’ Total Bakken oil production is 1.10 MMBD in 4Q17. CLR is the largest producer in the Bakken accounting for 11% of production.
In the Permian Basin, OXY, Chevron, and Pioneer, among others, recently confirmed their intention to grow liquids resource production over 30% in 2018. The breakeven oil price in the basin is under $33/B. Their primary constraint will be the build out of adequate pipeline takeaway capacity. Total 4Q17 Permian oil production is 2.64 MMBD. OXY, CVX, and PXD alone account for over 21% of production.
Outside the US, the outlook for production growth is also improved. The major oils, who operate globally, have also adjusted to a world of $50 oil. BP is able to breakeven at $49/B and is guiding toward cash breakeven at $35-40/B in 2021. Exxon plans to increase its 2018 capital spending 18%.
Lower steel and rig costs, an ample supply of skilled labor, and the impact of digital `big data’ technology in reservoir evaluation is driving improvement. Russia, the North Sea, and the Middle East are expected to lead the international recovery going forward.
Russia produced 11.31 MMBD in October, down 270 MBD from 4Q16 with its participation in the OPEC cut. It produced 11.3 MMBD for all of 2016. Its energy ministry expects a production increase up to 80 MBD early next year if the agreement with OPEC is not extended beyond March. Russia’s production costs range between $2/B for some mature fields and $50/B for fields in Arctic water, with an average between $10/B and $15/B.
Other non OPEC production outside the US and Russia was 32.40 MMBD in October, up 410 MMBD from 4Q16. Latest estimates indicate a 510 MBD increase by 4Q18. Growth in Canada, Brazil, and Kazakhstan is partly offset by declines in Mexico, China, and Azerbaijan.
Since 2015, global oil demand has grown about 5 MMBD, twice as fast as the previous 3 years, supported by strong global economic growth, particularly in the OECD. In 4Q17, it will be up 1.44 MMBD Y/Y to 98.20 MMBD, which is well above trend-line.
The latest IEA estimate anticipates a 540 MBD seasonal dip in demand in 1Q18. It is then projected to increase to 99.90 MMBD in 4Q18, up 1.66 MMBD Y/Y. China, India, and Africa lead the expansion.
Beyond 2018, the risk of an oil shortage remains. 2016 discoveries added less than 5 bn B to global reserves versus produced volumes over 30 bn B. The 2017 e&p spend on the global production base outside the Middle East, Russia, and US land, which still accounts for 50 MMBD of world oil supply, will be down 50% from 2014. As a result, decline rates for conventional onshore fields exceeded 7% last year, up from less than 3% in 2014.
Mature offshore fields are declining at an 8% rate, or about 1 MMBD annually, up from a 5% decline rate in 2014. While US shale oil production is growing, it is only 8% of world oil supply. OPEC spare capacity is only 3 MMBD. In a shortage, an oil price spike over $100/B would not be surprising.
Contact Paul Kuklinski at email@example.com for more detailed discussion including risks to the outlook.
Paul Kuklinski has selected equity investments in the energy sector for major institutional investors for over 30 years. In his experience, the future price of oil is the dominant investment variable. He founded Boston Energy Research in 1992 to provide independent research to large financial institutions. He was previously a Partner at Cowen & Company and a founding Partner of Harvard Management Company, which in the 1970s built a weighting over 50% in the energy sector in the Harvard Endowment equity portfolio. It generated substantial realized gains.