EIA forecasts that total U.S. crude oil production will average 9.3 million barrels per day (b/d) in 2017, up 0.5 million b/d from 2016. In 2018, crude oil production is expected to reach an average of 9.9 million b/d, which would surpass the previous record of 9.6 million b/d set in 1970. Most of the growth in U.S. crude oil production from June 2017 through the end of next year is expected to come from tight rock formations within the Permian region in Texas and from the Federal Offshore Gulf of Mexico (GOM) (Figure 1).
The Permian region is expected to produce 2.9 million b/d of crude oil by the end of 2018, about 0.5 million b/d above the estimated June 2017 production level, representing nearly 30% of total U.S. crude oil production in 2018. The Permian region predominately spans the Permian Basin of western Texas and southeastern New Mexico, covering 53 million acres. Within the Permian Basin are smaller sub-basins, including the Midland Basin and the Delaware Basin, all of which contain historically prolific non-tight formations as well as multiple prolific tight formations such as the Wolfcamp, Spraberry, and Bone Spring. With the large geographic area of the Permian region and stacked plays, operators can continue to drill through several tight oil layers and increase production even with sustained West Texas Intermediate (WTI) prices below $50 per barrel (b).
According to the June monthly average rig count from Baker Hughes, 366 of the 915 onshore rigs in the Lower 48 states are operating within the Permian region. EIA estimates that this number will fall slightly during the second half of 2017 to 345 at the end of 2017 and then grow to 370 by the end of 2018.
In addition to responding to changes in WTI price, increases in rig counts are also related to cash flow. In the Permian, operators have been able to maintain positive cash flow because of lower costs, higher productivity, and increased hedging activity by producers, many of whom have sold future production at prices higher than $50/b. Available cash flows could potentially contribute to the growth of rigs in this region notwithstanding relatively flat prices since December 2016.
Based on EIA’s Drilling Productivity Report">Drilling Productivity Report, productivity in the Permian, as measured by new-well oil production per rig in barrels per day, is forecast to decrease month-over-month for the 10th consecutive month in June (Figure 2). Output per rig is likely decreasing because operators are drilling more wells than they are completing. Completing a well is the process of casing, cementing, perforating, and hydraulically fracturing a well to make it ready for producing. When operators drill a well but do not complete it, the inventory of drilled but uncompleted wells (DUCs) increases, which tends to lower output per drilling rig. Oil flows only after a well is completed. The trend of operators drilling more wells than they are completing does not have a clear cause, but a widening of theWTI-Midland crude oil price discount to WTI-Cushing since the beginning of 2017 suggests the possibility of some minor transportation constraints. Lags in well completion may also reflect implementation of strategies that drill more wells from a single pad, with completion equipment not deployed until all wells are drilled.
Average output per well shows that productivity based on initial production rates continues to increase in the Permian region (Figure 3). Initial production based on average output per well year-to-date is higher than the 2016 annual average. Many operators are continuing to experiment with completion techniques to maximize output per well, suggesting the 2017 annual average initial production rate could continue to increase.
The dynamics related to drilling in the GOM differ from those in Lower 48 onshore regions. Because of the length of time needed to complete large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than Lower 48 onshore production. In 2016, eight projects came online in the GOM, contributing to production growth. Another seven projects are anticipated to come online by the end of 2018. Based on anticipated production at both new and existing fields, crude oil production in the GOM is expected to increase to an average of 1.7 million b/d in 2017 and 1.9 million b/d in 2018.
U.S. average regular gasoline falls and diesel retail prices climb
The U.S. average regular gasoline retail price fell two cents from the previous week to $2.28 per gallon on July 17, up five cents from the same time last year. The Midwest price fell over four cents to $2.18 per gallon, the West Coast, Rocky Mountain, and East Coast prices each fell one cent to $2.81 per gallon, $2.33 per gallon, and $2.21 per gallon, respectively, and the Gulf Coast price fell less than one cent, remaining at $2.03 per gallon.
The U.S. average diesel fuel price rose one cent to $2.49 per gallon on July 17, nine cents higher than a year ago. The Midwest price increased two cents to $2.44 per gallon, the East Coast and Gulf Coast prices each increased one cent to $2.53 per gallon and $2.32 per gallon, respectively, and the Rocky Mountain price increased less than one cent to $2.59 per gallon. The West Coast price remained unchanged at $2.77 per gallon.
Propane inventories gain
U.S. propane stocks increased by 3.5 million barrels last week to 65.7 million barrels as of July 14, 2017, 21.7 million barrels (24.8%) lower than a year ago. Gulf Coast, Midwest, and East Coast inventories increased by 2.3 million barrels, 0.8 million barrels, and 0.6 million barrels, respectively, while Rocky Mountain/West Coast inventories decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 4.4% of total propane inventories.
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It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.
This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.
The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.
It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.
The Abadi LNG Project:
Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b
Headlines of the week
Midstream & Downstream
A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.
That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.
That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.
Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.
Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?
Expectations at the 176th OPEC Conference