$60/B or More In 2019

By Paul Kuklinski

Oil prices are likely to remain relatively stable into mid 2018 as surplus inventories remain high. The growth in Permian production and the recovery in Libya and Nigeria are preventing OPEC from achieving the goal of its production cut.  The outlook changes thereafter. Without higher prices, world oil supply is then unlikely to keep up with continuing growth in global demand. In 2020 and beyond, the risk of an oil shortage is high.

WTI is $50.50/B. Without a geopolitical event, WTI is expected to remain near $53/B well into 2018 before increasing in 2H18 with a decline surplus inventories related to the seasonal ramp up in demand. It is expected to average $50/B for all of 2017 compared with $43/B in 2016.

Brent is $56/B, $5.80/B above WTI, but down from a recent premium over $7/B. Through August, the 2017 Brent premium over WTI was $2.01/B. It widened dramatically in the aftermath of seasonal maintenance in the North Sea, hurricane Harvey, and the Kurdish vote for independence. Brent reached a 2 year closing high of $59.02/B on September 25.

Geopolitical uncertainty added a risk premium to oil prices since the overwhelming in favor of independence in Kurdistan on September 25 including the partly Kurdish Kirkuk region of Iraq. In response, Turkey threatened to choke off crude oil exports through Turkey which were 575 MBD in September. The primary issue is control over the super giant Kirkuk Field, which accounts for nearly half of exports through Turkey. If implemented, the quarterly impact on world oil supply would be a reduction of 52 MMB, which would accelerate the return to a market balance and likely result in higher oil prices in response.

Otherwise, excess global crude oil inventories are likely to remain high over the next 12 months. A 57 MMB increase is even indicated in 1Q18 with the seasonal decline in demand, posing a temporary downside risk to oil prices as it occurs.

When it announced its production cut in 4Q16, OPEC believed elimination of the surplus in OECD inventories to the 5 year average would increase oil prices to $60-65/B. In August, the surplus was still 170 MMB larger, but down from a 318 MMB surplus earlier in the year. The OECD accounts for 48% of total world oil demand.

Production growth in the Permian Basin and the recovery in Libya and Nigeria are the primary reasons. Their combined production will likely be adequate to meet the growth in world oil demand into mid 2018. The outlook changes thereafter.

Despite robust growth even with low oil prices in 2017, annual production increases in the Permian Basin will likely be smaller in coming years. September production was 2.58 MMBD. It is projected to increase to 2.75 MMBD in December, up 640 MBD Y/Y, and grow more slowly thereafter. The basin still has 60-70 bn B of technically recoverable crude.

Current estimates of the future peak in Permian oil production vary, with a range of 5.0 to 5.5 MMBD in the early to mid 2020s. With a 5.5 MMBD peak in 2022, trendline growth near 500 MBD annually is indicated the next couple of years. With a 5.0 MMBD peak in 2025, trendline growth about 220 MBD annually is indicated. Both are less than the increase this year.

There is downside risk to these forecasts. In addition to low oil prices and oil field service cost inflation (up 10% YTD), which could negatively impact drilling activity, they also include geology and pipeline takeaway capacity.

Increasingly closer spacing of wells to drain reservoirs may result in a reduction in productivity of later infill wells by as much as 20-30% compared to the productivity of initial wells drilled. A much lower (maybe 3.5 MMBD) near term peak in Permian production would result as sweet spots are depleted. The productivity of newly drilled wells in the Permian peaked in April at 662 BD and is now 572 BD in October. Sweet spots in the Eagle Ford shale play ended up much smaller than originally modeled. Technology is a wild card that could change everything; in 2011, new well production in the Permian was 306 BD.

The pace of the build-out of adequate pipeline takeaway capacity might also constrain the growth in production. In August 2014, the Midland price blew out to a $12.10/B discount to WTI, penalizing Permian producers because of a lack of pipeline capacity. The WTI-Midland differential recently was $.35/B. There is currently 300 MBD of excess capacity, indicating the next pinch could occur in 1Q18!

Midstream companies are careful not to overbuild. Potentially there will be 2.14 MMBD of new takeaway capacity starting in stages from late 2019/ early 2020.

Outside the Permian, the increase in all other US crude and liquids production in response to 2017 oil prices is smaller. In 4Q17, it will be up 466 MBD Y/Y, with a Y/Y increase in crude of 56 MBD and a 410 MBD in natural gas liquids.

Total 3Q17 US crude and liquids production was 12.85 MMBD. It is projected to increase to 13.41 MMBD in 4Q17, up 1.11 MMBD Y/Y.

The growth in the US oil directed rig count flattened and reversed in recent weeks which will slow the growth in US land production 6-8 months later, about 2Q18. At 748, the latest US oil rig count is down 20 rigs from its August peak of 768. After hitting bottom at 333 rigs in 2Q16 it reached 507 the end of December 2016. The Permian rig count reached a high of 386 rigs in September and is now 383.

Pioneer Natural Resources, a leading producer in the Midland sub basin, believes “$50 oil isn’t going to get it done” because it doesn’t generate enough cash flow and the industry has too much debt. “US production may grow for 2-3 years and a few independents may grow, but we are in a $60 long term price environment.”

Outside the US, other non OPEC production is expected to remain relatively flat through 2018. It was 45.3 MMBD in 3Q17 and 45.1 MMBD in 2016. Russia produced 11.3 MMBD in 3Q17, fully compliant with its agreement with OPEC to cut production. It produced 11.3 MMBD in 2016. Outside the US and Canada, the global rig count was 931 in September compared with 948 in 1H17 and 956 for all of 2016. The current level of international drilling activity, if it persists, suggests a downward production bias in other non OPEC production in coming months.

Going forward, OPEC production will likely remain near current levels for the foreseeable future, with volatility, primarily related to Libya. OPEC’s September production was 32.65 MMBD. It averaged 32.38 MMBD for 9 months in 2017 and 32.65 MMBD in 2016. OPEC estimates demand for its crude will average 32.80 MMBD in 2017. Latest OPEC `talk’ is only about extending its cut past its March expiration date to the end of 2018. It is scheduled to meet next on November 30 in Vienna.

Compliance with its cut was 88% in September and 86% YTD. Iraq is OPEC’s biggest problem, consistently exceeding its quota. It produced 4.48 MMBD in September; its quota is 4.35 MMBD.

Saudi Arabia remains dedicated to the OPEC agreement to cut production, together with Russia and 9 other non OPEC producers. The IMF estimates its fiscal breakeven requires an oil price of $84/B! It is also planning an IPO for Saudi Aramco in 2018. Higher oil prices would be helpful. It produced 9.98 MMBD in September. Its quota is 10.06 MMBD.

More recently, Saudi Arabia has also committed to a reduction in its crude oil exports. In November, it plans to supply 7.15 MMBD which it says will be 621 MBD less than demand for its crude. September exports were 6.7 MMBD. In 4Q16, they were nearly 8 MMBD.

Nigeria’s crude oil production in September was 1.86 MMBD, up from 1.46 MMBD in 4Q16 when it was exempted from participation in the OPEC cut. Its oil minister recently said its production would not exceed 1.8 MMBD in sympathy with the OPEC agreement.

In Libya, most of the underlying issues behind recent production disruptions have not been addressed, which indicates they are likely to recur. It produced 923 MBD in September, down from 1010 MBD in July but up from 570 MBD in 4Q16 when it was also exempted from the OPEC cut. With resolution of its domestic conflicts, its goal is to raise production to 1.25 MMBD by December.

The outlook for world oil demand continues to increase, supported by strong global economic growth, particularly in the OECD. Relatively low and stable oil prices are supportive. In its latest estimate, the IEA expects an increase of 1.6 MMBD this year to 97.7 MMBD and 1.4 MMBD in 2018. 4Q18 demand is expected to reach 100 MMBD. China, India, and Africa are leading the expansion. Demand grew 1.1 MMBD in 2016.

A potential oil shortage looms in 2019-2020. 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. While US shale oil production is growing, it is only 8% of world oil supply.

Schlumberger recently said: “The longer the current underinvestment carries on, the more severe the cliff-like decline trend will likely be when producers run out of short term options to maintain production.”

Production has been supported primarily by producing wells at a higher rate than in the past, which is depleting their reserves faster. There is still little in the way of confirmation in the latest data.


Contact Paul Kuklinski at bostonenergyresearch@msn.com for more detailed discussion including risks to the outlook.


About Boston Energy Research

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.