Oil Price Stability: Fragile
Barring a geopolitical event, latest data indicates a market balance will endure in coming months, keeping oil prices near current levels. Long term, the bias is higher, with growing evidence a supply gap will emerge before 2025.
by Paul Kuklinski
WTI crude is $67/B, compared to a 1H18 average just over $65/B and a 2017 average of $51/B. It is expected to average around $68/B the rest of the year and in 2019, absent a geopolitical disruption. WTI spiked to a high over $75/B in early July.
Brent hit a peak of $81/B in May and is now $73/B. The Brent premium exceeded $11/B in May, compared to a 2017 average of $3.10/B. It is now $5/B and is expected to approximate $5/B the rest of the year. Brent has greater geopolitical sensitivity. Saudi Arabia and its allies appear to be targeting a $70-75/B Brent price.
Spot Gulf Coast gasoline prices were $2.04/gal in July, up 25% from 3Q17. Low sulfur diesel prices were $2.09/gal, up 29%. WTI was up 46% from 2Q17, squeezing refining margins compared to last year. Gulf Coast refining margins in July were an attractive $10.40/B, but less than 3Q17 margins of $12.39/B.
In the latest week, U.S. gasoline inventories were 4% above the 5 year average. Distillate inventories were 10% below, but that is an improvement from 23% below the end of June. Weekly refinery runs have averaged 94% of capacity and higher since late May to keep up with strong seasonal demand. U.S. crude oil inventories in the latest week were right in line with the 5 year average, but stocks at Cushing, Okla., the NYMEX pricing point for WTI on which many traders focus, were 67% below. Restricted supply of western Canadian imports is part of the problem. Permian production largely bypasses Cushing.
Consensus view on Iran and a stable Libya indicates a stable inventory outlook
In June, OECD oil inventories fell to 32 MMB less than the 5 year average from a peak surplus of 380 MMBD in 1Q16, which caused oil prices to crash to a low of $27/B then from an average over $90/B in 2014.
Without a geopolitical disruption, latest data indicates inventories will remain relatively unchanged into mid 2019. The production response of Saudi Arabia and its allies since June to potential shortages from the continuing decline in Venezuela and the impact of sanctions on Iran is in line with indicated market demand.
And they are expected to remain proactive going forward. Upside pressure on oil prices will be strongest in 2Q19 when world oil demand increases seasonally by an expected 1.10 MMBD Q/Q, sanctions on Iran will have been in full effect for several months, Venezuelan production is expected to be even lower, and Permian growth will still be constrained. Based on current trends, a 33 MMB decline in OECD inventories in the quarter is indicated. Inventories in 1Q19 will benefit from a sequential seasonal decline of 800 MBD which would result in a quarterly build in OECD inventories of 28 MMB.
OPEC produced 32.18 MMBD crude oil in July, 280 MBD more than the 1H18 average of 31.90 MMBD despite the disruption in Libya and the continuing decline in Venezuela.
With the increase, OPEC’s spare capacity was reduced to 3.44 MMBD which supports a bullish view on oil prices but several OPEC producers are adding 4.8 MMBD additional capacity from 3Q18 to 2025.
In late June, the U.S. announced it expects Iran oil buyers to cut imports to 0 by November in response to renewed sanctions. China is imports about 635 MBD, India 650 MBD, Japan 165 MBD, South Korea 245 MBD, Europe 650 MBD, about 2.35 MMBD in total. Iran also exports about 300 MBD of condensate. Its crude exports were just 1.13 MMBD in 2015 when sanctions were previously in place.
Zero oil exports from Iran would reduce OPEC spare capacity to a too small 1.09 MMBD if the rest of OPEC makes up the difference. Oil prices would jump higher. Strategic reserves are an alternative. Iran’s Supreme Leader has ruled out a military conflict with the US. He blames Iran’s government for mismanagement. The rial has lost ½ its value since April.
Iran produced 3.75 MMBD crude oil in July compared to a 1H18 average of 3.81 MMBD, but up from 2.91 MMBD in 2015. Consensus expectations anticipate sanctions will steadily reduce Iran’s exports and production by 1 MMBD to 2.81 MMBD in early 2019. The IEA warns of a 1.2 MMBD reduction. The loss of 1 MMBD supply is equivalent to a sizable quarterly reduction in OECD inventories of 80 MMB.
Venezuela produced 1.28 MMBD in July, down from a 1H18 average of 1.45 MMBD and a 2017 average of 1.97 MMBD. Production is expected to decline to 1 MMBD in December and 700 MBD the end of 2019. Venezuela suffers from a lack of maintenance, spare parts, and electrical failures. Skilled employees have left the country. Its’ 1.6 MMBD refining capacity is unable to meet demand. Utilization is 21% due to a lack of crude and inoperable equipment. Further deterioration is expected.
Libya’s output fell to 665 MBD in July from a 1H18 average of 950 MBD after a brief closure of its 5 eastern ports by a local militia in conflict with the UN backed government in Tripoli. Libya is scheduled to hold an election `late’ this year. Rivalry between factions and militias continue to periodically disrupt its production.
OPEC capacity will increase
Saudi Arabia produced 10.35 MMBD in July, compared with a 1H18 average 10.05 MMBD. It produced 9.96 MMBD in 2017, and 10.55 MMBD in 4Q16 when the OPEC cut was announced. Its capacity is 12.04 MMBD.
Angola produced 1.46 MMBD in July. Its capacity is 1.58 MMBD. The start up of the deepwater Kaombo Field this summer will ramp up to capacity of 230 MBD over an 18 month period.
Kuwait produced 2.79 MMBD in July. Its capacity is 2.83 MMBD. It is reactivating the 300 MBD offshore Khafji Field in the Partitioned Neutral Zone it shares with Saudi Arabia where production has been shut since October 2014. The 200 MBD onshore Wafra Field in the PNZ has been closed since May 2015. Restarts in both fields are expected to take months. Kuwait is planning to increase its crude production capacity to 4 MMBD by 2020.
Iraq produced 4.56 MMBD in July. Its current capacity is 4.80 MMBD and expansion of the West Qurna Field will add 150 MBD by the end of 2019 and 1.6 MMBD by 2025. Iraq aims to have 8 MMBD capacity in 2025 with 6 MMBD from its southern Basra province, the rest in the north. A political dispute with Kurdistan inhibits the export of Kirkuk crude in the north. Recent Kirkuk production was as much as 230 MBD, much less than its capacity of 500 MBD. Iraq has a contract with BP to study expansion of the field to 2 MMBD.
Russia produced 11.61 MMBD in July compared to 1H18 production of 11.36 MMBD. It produced 11.58 MMBD in 4Q16 when it agreed to join OPEC in cutting production. A large number of new greenfield projects will raise Russia’s capacity to about 12 MMBD by 2020.
US production growth to slow the next 12 months before accelerating
Total U.S. crude and liquids production was 15.20 MMBD in July. It is expected to average 15.03 MMBD for the year, up 15% or 1.86 MMBD over 2017, and grow 1.50 MMBD in 2019. Substantially all of the increase will come from unconventional onshore plays. 2018 oil production from the Gulf of Mexico is expected to increase 49 MBD to 1.70 MMBD, with an additional 160 MBD increase in 2019.
The primary growth engine is the Permian Basin, which accounts for 1/3 of U.S. liquids production. Permian oil production in July was 3.33 MMBD, with additional gas liquids around 1.68 MMBD, plus 10.66 BCFD of associated natural gas. For the year Permian oil production is expected to average 3.23 MMBD, up 810 MBD over 2017, while NGLs increase 211 MBD over 2017.
Because takeaway pipeline capacity is full, production is expected to flatten over the next 12 months. The addition of 2.3 MMBD new pipeline capacity beginning in 2H19 which will allow production to surge after that. And another 1.6 MMBD takeaway capacity will come on line in 2020-2021. As a result, smaller annual 495 MBD increase in Permian crude and liquids production is anticipated in 2019 before growth accelerates again in 2020 with the full year availability of new pipelines.
Outside the Permian and the Gulf of Mexico, all other U.S. liquids production is expected to increase 790 MBD this year, with a 220 MBD increase in Bakken oil production and a 130 MBD oil increase in the Eagle Ford.
As a possible indicator of next year’s industry fundamentals, a look at the outlook and economics of leading onshore U.S. producers driving this years’ growth in non OPEC supply may be helpful.
17 of the largest independent U.S. onshore producers at mid year are guiding a combined 8% production increase in 2018 liquids or about 410 MBD for the year. They accounted for 24% of total 2017 U.S. liquids production, or 3.19 MMBD. Their 2018 increase over 2017 is not adjusted for significant asset sales and restructuring which continue ongoing since 2016.
Their combined 2018 revenue is projected to increase 24% over 2017, which is less than the expected 33% increase in WTI to a $68/B average. 2018 NYMEX gas prices are expected to average $2.95/MCF, down 5% this year which diminishes their revenue growth. Their average 2017 U.S. production mix was 49% crude oil, 15% gas liquids, and 36% natural gas. A meaningful increase in natural gas prices is not expected anytime soon except for the possibility of distortions caused by weather.
But with an improved production mix to 67% liquids in 2018, modest service cost inflation this year, and significant increases in well productivity, their guidance indicates their 2018 cash margin after production costs and severance taxes will increase 39%, or close to $8/BOE, to approximate $29/B. Operating costs are expected to increase just $1.15/BOE this year to $13.70/BOE. Recent wells now breakeven below $40/B WTI. Because of asset sales, write-offs, and more productive new wells, DD&A charges are expected to decline nearly $3/BOE this year to just under $13/BOE.
Their increased 2018 cash flow from higher oil prices, modest 2018 oil field inflation, and a large increase in cash margins, along with growing volumes, could have supported even stronger U.S. production growth this year in other shale plays outside the Permian Basin.
Instead, these 17 onshore producers reduced their combined long term debt by 10% year to date with an additional reduction indicated over the balance of the year. At mid year, their debt/ debt + equity ratio was a still high 42%, modestly improved from 44% at year end 2017. Their full year 2018 capital spending budgets are up a combined 14% over 2017. Without debt reduction, capex could have increased much more.
Without a geopolitical event to drive oil prices significantly higher, 2019 is not likely to be as good for them or U.S. onshore producers in general. They are not likely to have the benefit of the $17/B increase in 2018 oil prices, while service cost inflation is widely expected to escalate to the 5-10% range.
In that environment, they are likely to continue to prudently balance their allocation of 2019 cash flow between further debt reduction and spending on their most economic, lowest cost, opportunities to support growth, as in 2018.
Canada is expected to produce 4.92 MMBD in 3Q18, down from a 1H18 average of 5.02 MMBD. Production at the 360 MBD Syncrude oil sands upgrader, closed by an electrical outage in June, is expected to be fully restored in September. The start of the Hebron Field off Newfoundland last November will add 150 MBD at peak in early 2019. After increasing 348 MBD last year to 4.82 MMBD, Canada’s production is expected to average 5.12 MMBD this year and increase 320 MBD to 5.44 MMBD in 2019.
Canadian producers are dealing with pipeline constraints as well. Western Canada’s 4.2 MMBD pipeline network is full, with crude by rail moving another 150 MBD. Western Canadian Select heavy sour crude sold at a discount of $23/B to WTI in July, out from a $12/B discount in 2017.
The startup of Enbridge’ 760 MBD Line 3 replacement for a 380 MBD line to Wisconsin in late 2019 and the start of the 890 MBD Transmountain replacement for a 300 MBD line to British Columbia and the 870 MBD Keystone XL pipeline to the Midwest and Texas later are expected to restore the discount to the $10-14/B range. They will increase combined takeaway capacity of 1.84 MMBD.
Outside North America and Russia, latest data indicates other non OPEC production will remain relatively unchanged in 2018 and 2019 from 28.81 MMBD in 2017. Growing production in Brazil is being offset by declines in Mexico and elsewhere. At 997 in July, the international rig count is up 3% from 969 in the first half. It was 948 last year and 1337 at the peak in 2014.
World oil demand estimates remain unchanged. After an increase of 1.49 MMBD in 2017, the IEA is estimating an increase of 1.40 MMBD in 2018 to average 99.13 MMBD, and a further 1.35 MMBD increase in 2019. It anticipates a 500 MBD sequential increase in 3Q18 from 98.80 MMBD in 2Q18 followed by 700 MMBD increase in 4Q18 before a seasonal decline of 800 MMBD in 1Q19. Its forecast then anticipates an 1100 MBD seasonal increase in 2Q19 followed by a 600 MBD increase in 3Q19.
Its estimates have downside risk related to trade tensions which could impact global economic growth, especially in 2019. In China, demand growth slowed sharply in 2Q18. Its demand grew 600 MBD in 2017 to 12.4 MMBD. The IEA currently estimates China’s demand will increase 500 MBD this year and 400 MBD in 2019. China also imports about 635 MBD of Iranian crude.
Increased evidence of a global supply gap before 2025
Anxiety remains as to the adequacy of global upstream spending to provide ample oil supply beyond 2019. Schlumberger, which works projects everywhere, identifies 15 conventional oil producing regions outside the Middle East and Russia that are in decline. They accounted for 27% of global oil supply last year, or about 26 MMBD. Decline rates in these basins have increased in recent years from 5% to 7%, about 1.8 MMBD annually. Global demand has been growing 1.4-1.5 MMBD annually. SLB believes it is “not realistic to expect new projects coming on line the next few years to reverse the production decline outside the U.S. and Middle East”.
Since 2015, there has been a clear trend in the type of projects being sanctioned toward smaller brownfield projects. In the aggregate, SLB estimates they will not reach peak production until 2025. Schlumberger concludes “we will face a supply gap sometime before then.” It also observes the market has been moving toward short cycle E&P activity that is more averse to risk than in the past.
Marine drillers have reason to be more optimistic. About 100 offshore oil and gas projects are expected to be approved this year, compared to 60 sanctioned in 2017 and less than 40 in 2016. The average breakeven price for long cycle deepwater development has been reduced to $45/B, with some projects significantly lower. The breakeven for shallow water projects is now close to $30/B which is very competitive with the best onshore unconventional plays.
The jack-up market is in full scale recovery, led by the North Sea and Middle East, and rig rates are improving. The floating rig market is still sluggish and a recovery is not expected before mid 2019.
The 7 major oil companies, which account for 70% of all deep-water activity, have the same need to restore their balance sheets as do leading onshore U.S. producers. Without higher oil prices, they are likely to continue to cautiously balance the allocation of their cash flow this year and next between further debt reduction and capital spending including U.S. onshore and offshore exploration and development
When it begins, the recovery in deep-water activity will likely proceed at a measured pace for a couple of years, fueling Schlumberger’s concern of a supply gap emerging before 2025. Long term, oil prices have an upward bias.
About Boston Energy Research: Boston Energy Research selects equity investments in the oil and gas sector for major financial institutions.
Paul Kuklinski, founder of independent research firm Boston Energy Research, typically publishes over 30 common stock recommendations annually from a universe comprising the five super major integrated oils, 17 of the largest exploration and production companies, and nine of the leading oil service providers including marine drillers, a total of 31 of the most important energy stocks in all. His comprehensive coverage provides a unique vantage point to observe industry trends not generally available.