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Last Updated: July 20, 2017
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U.S. crude oil production forecast to average 9.9 million barrels per day in 2018


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).

Figure 1. Monthly U.S. crude oil production by region

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.

Figure 2. Permain region drilling and production per rig

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.

Figure 3. Permain region average production per well

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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Natural gas and wind forecast to be fastest growing sources of U.S. electricity generation

In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.

The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.

This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.

These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.

PJM annual electric power sector generation

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.

ERCOT annual electric power sector generation

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.

September, 18 2019
Your Weekly Update: 9 - 13 September 2019

Market Watch  

Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b

  • Hope reigns as the market banks on signs that the US and China could reach a trade deal would eliminate one of the largest risks to current oil prices: a full-blown global recession
  • However, this is merely the latest in a series of dashed hopes that has seen the trade war between the US and China – using tariffs as weapons – escalate dramatically over the year; new tariffs entered play September 1 and more could come, with both sides already feeling the pinch
  • But crude prices did get a lift from EIA data showing that US crude stockpiles fell far more than expected, down by 4.8 million barrels to its lowest level since October 2018 – an indication of strong demand, with US refinery utilisation at 94.8%
  • However, there are fissures appearing on the supply side that could trigger some risk premiums; in Venezuela, the upstream crisis continues with the latest blow being a Chinese contractor halting work over claims over non payment
  • More importantly, Saudi Oil Minister – or rather former Saudi Oil Minister Khalid al-Falih – was dismissed from the government; after initial reports suggested that al-Falih would focus on energy policy after the oil ministry was split, a royal decree issued days later confirmed his sacking
  • Saudi Arabia and its allies have been at pains to re-assure the market that the dismissal of al-Falih – who is respected around the world – will not impact Saudi production or the current OPEC+ supply pact
  • This will be confirmed at the upcoming OPEC+ meeting this week, which will be the first under Saudi Arabia’s new Energy Minister, one of the King’s sons Prince Abdulaziz bin Salman
  • Against this backdrop of turmoil, the active US rig count fell yet again; after two weeks of double-digit losses, US drillers lost four oil and two gas rigs, with losses seen once again in the Permian
  • Power moves within Saudi Arabia may have sent some tremors to the market, but it is likely that OPEC+ will stick to its commitments; with no signs that the US and China were doing anymore more than talking about talking, crude prices will remain rangebound – US$59-61/b for Brent and US$54-56/b for WTI

Headlines of the week

Upstream

  • Total has suspended plans for the US$3.5 billion crude export pipeline that would connect Ugandan oilfield to port facilities in Tanzania after a failure to buy a stake in Tullow Oil’s upstream assets in Uganda linked to tax negotiations; this will require a complete restart for the Uganda project
  • With other supermajors pulling out, Total remains committed to the North Sea, with CEO Patrick Pouyanne looking to invest up to US$10 billion over the next five years but cautions that Total maintain strict cost discipline
  • The Norwegian Petroleum Directorate (NPD) has consented to the startup of the giant Johan Sverdrup field, a potential 660,000 b/d resource that has been called the North Sea’s ‘last hurrah’
  • Permian-focused player Concho Resource has agreed to sell its assets in the New Mexico Shelf to Spur Energy Partners for US$925 million, continuing a wave of consolidation in the US shale arena
  • Shell has announced plans to start drilling in the offshore Saturno field in Brazil, becoming one of the first private players tapping the pre-salt Santos Basin

Midstream/Downstream

  • Sinopec’s new 160 kb/d Yangzi refinery has begun production of Europe-standard gasoline, providing an outlet for Chinese fuel products amid a domestic glut that has seen refiners look overseas for sales
  • Petrobras is extending the deadline for interested parties for its four refineries on sale from September 16 to September 27, citing high investor interest for the refining assets that represent 37% of Brazilian capacity
  • Saudi Aramco continues its downstream push in China, signing an MoU with the Zhejiang Free Trade Zone that could pave the way for further investments beyond current plans to acquire 9% of the Zhejiang Petrochemical refinery
  • Russia’s Sibur will be cutting back LPG exports to Europe to some 2 million tons from a typical 3.5-4 million tons per year, redirecting the LPG to be used as feedstock for its ZapSibNefteKhim petrochemicals plant in Western Siberia

Natural Gas/LNG

  • Months of uncertainty have been put to rest as the government of Papua New Guinea endorsed the US$13 billion Papua LNG project, following some new commitments by project leader Total – primarily on local content
  • Also in PNG, the government has approved Australian independent Twinza Oil’s Pasca gas/condensate project - the country’s first offshore gas project
  • ExxonMobil and its partners have sanctioned plans for the 6.2 mtpa Sakhalin 1 LNG plant on Sakhalin Island in Russia’s far east, with easy access to Japan
  • Argentina’s YPF is pushing ahead with plans to build a US$5 billion LNG export terminal – tapping into the Vaca Muerta shale basin – despite continued domestic political and financial chaos hanging over the project
  • Petronas has agreed to purchase natural gas that is set to produced from the Gorek, Larak and Bakong fields in the SK408 area in Sarawak, jointly operated by SapuraOMV Upstream, Petronas Carigali and Shell
  • Qatar Petroleum has booked 100% of regasification capacity at the Fluxys Zeebrugge LNG terminal until 2044, consolidating Qatar’s hold on one of Northwest Europe’s important gas entry nodes
  • Equinor has brought the Snefrid Nord gas field online, which is the first of several planned projects related to the Aasta Hansteen field to begin production, with an initial output of 4 mcm/d
September, 13 2019
Global gas and LNG outlook to 2035
Expansion in the gas and LNG markets continues, with LNG demand expected to increase 3.6 percent per year to 2035.

Detailed market research and continuous tracking of market developments—as well as deep, on-the-ground expertise across the globe—informs our outlook on global gas and liquefied natural gas (LNG). We forecast gas demand and then use our infrastructure and contract models to forecast supply-and-demand balances, corresponding gas flows, and pricing implications to 2035.

Executive summary

The past year saw the natural-gas market grow at its fastest rate in almost a decade, supported by booming domestic markets in China and the United States and an expanding global gas trade to serve Asian markets. While the pace of growth is set to slow, gas remains the fastest-growing fossil fuel and the only fossil fuel expected to grow beyond 2035.

Global gas: Demand expected to grow 0.9 percent per annum to 2035

While we expect coal demand to peak before 2025 and oil demand to peak around 2033, gas demand will continue to grow until 2035, albeit at a slower rate than seen previously. The power-generation and industrial sectors in Asia and North America and the residential and commercial sectors in Southeast Asia, including China, will drive the expected gas-demand growth. Strong growth from these regions will more than offset the demand declines from the mature gas markets of Europe and Northeast Asia.

Gas supply to meet this demand will come mainly from Africa, China, Russia, and the shale-gas-rich United States. China will double its conventional gas production from 2018 to 2035. Gas production in Europe will decline rapidly.

LNG: Demand expected to grow 3.6 percent per annum to 2035, with market rebalancing expected in 2027–28

We expect LNG demand to outpace overall gas demand as Asian markets rely on more distant supplies, Europe increases its gas-import dependence, and US producers seek overseas markets for their gas (both pipe and LNG). China will be a major driver of LNG-demand growth, as its domestic supply and pipeline flows will be insufficient to meet rising demand. Similarly, Bangladesh, Pakistan, and South Asia will rely on LNG to meet the growing demand to replace declining domestic supplies. We also expect Europe to increase LNG imports to help offset declining domestic supply.

Demand growth by the middle of next decade should balance the excess LNG capacity in the current market and planned capacity additions. We expect that further capacity growth of around 250 billion cubic meters will be necessary to meet demand to 2035.

With growing shale-gas production in the United States, the country is in a position to join Australia and Qatar as a top global LNG exporter. A number of competing US projects represent the long-run marginal LNG-supply capacity.

Key themes uncovered

Over the course of our analysis, we uncovered five key themes to watch for in the global gas market:

  1. Global LNG-price indicators have partially converged with the differentials among Asia, Europe, and the United States, falling to the smallest they have been in longer than a decade.
  2. Asia is leading a third wave of market liberalization after those in the United States and Europe, likely bringing fundamental changes to Asian markets.
  3. Long-term contract-pricing mechanisms are evolving in indexation and slope as gas and oil markets diverge, placing pressure on buyers to reshape their contract portfolios, with up to $15 billion per year at stake.
  4. Substantial new investment is necessary to deliver the infrastructure required to meet demand growth.
  5. Traditional, bilateral business models for LNG are being challenged today, and new business models with an increased focus on commercial and trading capabilities are emerging.
September, 13 2019