“Despite oil price downturns, the shale revolution and OPEC market share wars, offshore continues to thrive and has much to offer the future,” Audun Martinsen, head of oilfield services research at Rystad Energy, said in May, commenting on the independent energy research and consultancy’s findings that the offshore oil and gas sector has tremendous room for further growth.
Offshore exploration, greenfield and brownfield development, decommissioning, and maintenance and operations are all set to create trillions of U.S. dollars of opportunities for the services sector in the future, according to Rystad Energy.
Following a muted offshore market in 2015 and 2016 after the 2014 oil price crash, offshore project sanctioning has recently started to pick up, and may be on track for a bumper year this year, Rystad said in an analysis in January. Back then, the consultancy forecast that offshore sanctioning could reach US$123 billion in project commitments in 2019, with the Middle East leading in shallow-water project sanctioning and South America leading in deepwater projects.
More recently, in July, Rystad Energy said that this year’s offshore oil and gas project sanctioning had already exceeded US$50 billion in commitments, signalling that the industry has the potential to reach US$123 billion in project commitments, surpassing the US$78-billion worth of projects sanctioned in 2014, when the price of oil started to crumble.
“With offshore free cash flows at nearly record highs, E&P’s are betting big on new projects. Offshore project sanctioning in 2019 looks ready to reach heights not seen since the $100 barrel of oil,” Matthew Fitzsimmons, VP of Oilfield Service Research at Rystad Energy, said in July.
The consultancy ranked the top ten offshore projects in terms of capital commitments sanctioned between 2014—when oil prices were still at US$100 a barrel in the first half of that year—and 2019. Here they are ranked in descending order:1. Saudi Aramco’s Marjan expansion offshore Saudi Arabia
The Marjan increment programme is an integrated development project for oil, associated gas, non-associated gas, and cap gas from the Marjan offshore field, worth a total of US$12 billion. The development aims to boost the Marjan Field production by 300,000 barrels of oil per day (bpd) of Arabian Medium Crude Oil, process 2.5 BSCFD of gas, and produce an additional 360 MBCD of C2+NGL. The development will entail a new offshore gas oil separation plant and 24 offshore oil, gas, and water injection platforms.2. Equinor’s Johan Sverdrup Phase 1 offshore Norway
Next on Rystad’s rankings comes the Johan Sverdrup Phase 1 development project in Norway’s section of the North Sea. Johan Sverdrup is one of the five largest oil fields ever to be discovered on the Norwegian Continental Shelf (NCS). The project—with expected resources estimated at 2.7 billion barrels of oil equivalent—is also one of the most important industrial projects in Norway for the next 50 years.
Production start-up is scheduled for November 2019, and daily production during Phase 1 is estimated at 440,000 bpd, with peak production expected to reach 660,000 bpd. Investment in Phase 1 is estimated at 86 billion Norwegian crowns, according to Equinor, or around US$11 billion as estimated by Rystad.3. BP’s Argos (Mad Dog Phase 2) in the US Gulf of Mexico
The operator BP and co-owners BHP and Union Oil Company of California, an affiliate of Chevron, approved the US$9 billion final investment decision on the Mad Dog 2 Phase offshore project in early 2017. BP has worked with co-owners and contractors to bring down the originally estimated cost of US$20 billion and slashed costs by 60 percent. The Mad Dog 2 project includes the Argos platform with the capacity to produce up to 140,000 gross barrels of crude oil per day through a subsea production system from up to 14 production wells and eight water injection wells. Oil production from the new floating production platform is expected to begin in late 2021.4. Equinor’s Johan Castberg in the Barents Sea
Equinor’s development plan for the Johan Castberg field in the Barents Sea was approved in 2018. The US$6-billion project has recoverable resources estimated at 450-650 million barrels of oil equivalent, while Equinor and partners have changed the concept to halve expenditures and make it a profitable development.
The field—currently the largest subsea field under development in the world, according to Equinor—consists of a production vessel and a comprehensive subsea system, including a total of 30 wells distributed on 10 templates and 2 satellite structures. Johan Castberg is scheduled for first oil in 2022 and it’s profitable even at an oil price below US$35 a barrel, Equinor says.5. Saudi Aramco’s Berri expansion project offshore Saudi Arabia
Aramco’s Berri increment programme worth around US$6 billion aims to raise the offshore field’s production by 250,000 barrels of Arabian Light Crude per day. Once completed, the planned facilities will include a new gas oil separation plant in Abu Ali Island to process 500,000 bpd of Arabian Light Crude Oil, and additional gas processing facilities at the Khursaniyah gas plant to process 40,000 barrels of associated hydrocarbon condensate. The expansion project includes a new water injection facility, two drilling islands, 11 oil and water offshore platforms, and nine onshore oil production and water supply drill sites.
In early July, Saudi Aramco awarded 34 contracts worth a total of US$18 billion for the engineering, procurement and construction of the Marjan and Berri increment programmes.6. Equinor’s Johan Sverdrup Phase 2 in the North Sea
Norwegian authorities approved in May 2019 Equinor and partners’ development plan for the second phase of the Johan Sverdrup field development. Capital expenditure is around US$5 billion and start-up is planned for the fourth quarter of 2022. In addition to the construction of a new processing platform (P2), phase 2 development will also include modifications of the riser platform, five subsea systems, and preparations for power supply from shore to the Utsira High in 2022.7. Shell’s Appomatox in the US Gulf of Mexico
Shell’s Appomatox development in the Norphlet formation in deepwater Gulf of Mexico was not only sanctioned but also brought to production between 2014 and 2019. The estimated US$5-billion development was the first-ever Jurassic play to start production in the US Gulf of Mexico in May this year, with an expected production of 175,000 barrels of oil equivalent per day (boed).
The Shell-operated Appomattox floating production system opens a new frontier in the deepwater US Gulf of Mexico, Shell says, adding that Appomattox has realised cost reductions of more than 40 percent since taking FID in 2015. “Appomattox creates a core long-term hub for Shell in the Norphlet through which we can tie back several already discovered fields as well as future discoveries,” said Andy Brown, Upstream Director, Royal Dutch Shell.
The next two offshore projects in Rystad Energy’s rankings are located offshore the United Arab Emirates (UAE), each worth some US$5 billion for development of sour gas, and expected to take FID in 2019.8. ADNOC’s Hail (Sour Gas) project offshore the UAE
At the beginning of 2019, the Abu Dhabi National Oil Company (ADNOC) awarded work for the dredging, land reclamation, and marine construction to build multiple artificial islands in the first phase of development of the Ghasha Concession. The Ghasha Concession consists of the Hail, Ghasha, Dalma, Nasr, and Mubarraz offshore sour gas fields. The project is expected to take 38 months to complete and will provide the infrastructure required to further develop, drill, and produce gas from the sour gas fields in the Ghasha Concession.9. ADNOC’s Ghasha (Sour Gas) project offshore the UAE
Commenting on the initial work on the projects, UAE Minister of State and ADNOC Group CEO, Dr. Sultan Ahmed Al Jaber, said:
“This award accelerates the development of the Hail, Ghasha and Dalma sour gas offshore mega-project, which is an integral part of ADNOC’s 2030 smart growth strategy. As one of the world’s largest sour gas projects it will make a significant contribution to the UAE’s objective to become gas self-sufficient and transition to a potential net gas exporter.”10. Total’s Gindungo offshore Angola
Total, operator of Kaombo, currently the biggest deep offshore development in Angola, started up in July 2018 production from Kaombo Norte, the first Floating Production Storage, and Offloading (FPSO) unit. Kaombo Norte and the other FPSO, Kaombo Sul, are developing the resources from six different fields—Gengibre, Gindungo, Caril, Canela, Mostarda, and Louro—offshore Angola.
In April 2019, Total started up production from Kaombo Sul, bringing the overall production capacity to 230,000 bopd, equivalent to 15 percent of Angola’s production. The associated gas from Kaombo Sul will be exported to the Angola LNG plant as part of Total’s commitment to stop routine flaring.
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Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b
Headlines of the week
Forecast growth in demand for U.S. petroleum and other liquids is not driven by transportation and not supplied by refineries
The U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO) forecasts that in 2021, U.S. consumption (as measured by product supplied) of total petroleum and other liquid fuels will average 20.71 million barrels per day (b/d), surpassing the 2007 pre-recession level of 20.68 million b/d. However, the drivers of this consumption growth have changed. Since the 2007–09 recession, U.S. consumption growth has shifted toward liquid fuels that are used primarily outside the transportation sector and are supplied mostly from non-refinery sources. Despite this shift away from domestic demand for refinery-produced fuels, U.S. refinery runs have increased, and the excess products have been exported, greatly contributing to the United States becoming a net exporter of petroleum in September 2019. EIA expects these trends to continue for at least the next 10 years.
Hydrocarbon gas liquids (HGL) have been the main driver of U.S. petroleum and other liquids demand growth since 2007 (Figure 1). U.S. production and consumption of HGLs—a group of products that include ethane, propane, normal butane and isobutane, natural gasoline, and refinery olefins—have risen with increased natural gas production and demand from an expanding petrochemical sector. As a result, EIA forecasts U.S. HGL consumption will be 1.27 million b/d more in 2021 than in 2007, and will average 3.45 million b/d.
With the exception of jet fuel, EIA expects less U.S. consumption of refinery-produced products in 2021 than in 2007. Since 2007, increases in U.S. vehicle miles traveled, which normally increases total motor gasoline consumption, have been countered to some extent by increases in vehicle fuel efficiency. In addition, although U.S. total motor gasoline consumption exceeded 2007 levels for the first time in 2016, increased blending of ethanol into finished motor gasoline has displaced some of the petroleum-based, or refinery-produced, portion of gasoline consumption. Therefore, EIA forecasts 570,000 b/d less consumption of refinery-produced gasoline in the United States in 2021 than in 2007, while ethanol will be 0.5 million b/d higher. Ethanol is almost exclusively produced at non-petroleum refinery sites.
Some HGLs can be produced by both refineries and natural gas processing plants. Natural gas plant liquids (NGPLs)—a subset of HGLs that includes ethane, propane, normal butanes and isobutanes, and natural gasoline—can be extracted from natural gas production streams or produced at refineries that process crude oil. However, as U.S. natural gas production increased from 55.3 billion cubic feet per day (Bcf/d) in 2007 to 98.9 Bcf/d in 2019, the amount of HGLs extracted from natural gas production increased from 1.78 million b/d in 2007 to 4.83 million b/d in 2019. EIA expects HGL production from natural gas processing plants to continue to increase to 5.47 million b/d in 2021. Meanwhile, refinery HGL production has been flat at about 600,000 b/d (Figure 2).
Although HGLs have several different end uses, such as propane for space heating and normal butane for blending with motor gasoline, most of the growth in consumption stems from the use of HGLs as feedstock for petrochemical processes. The large increase in U.S. production of HGLs, and the resulting low prices, led to large investments in U.S. infrastructure to extract and transport HGLs to market, as well as investments in petrochemical facilities to consume it. Many of these facilities consume ethane, and to a lesser degree propane and normal butane, as feedstocks to produce intermediate building blocks for plastics, resins, and other materials with nonenergy uses. EIA forecasts that U.S. ethane consumption will reach 1.96 million b/d in 2021, up from 743,000 b/d in 2007, which represents 96% of the increase in U.S. HGL consumption between 2007 and 2021.
Removing HGL and ethanol consumption from the total demand for U.S. petroleum and other liquids indicates that EIA’s 2021 forecast U.S. demand for principally refinery-produced products is about 16.31 million b/d, on par with the 1997 level (Figure 3).
Despite domestic demand shifting away from traditionally refinery-produced products, U.S. refinery capacity has increased 1.7 million b/d between 2007 and 2019. U.S. refineries have adapted to falling domestic demand for certain products, such as residual fuel, by investing in downstream coking capacity to upgrade it into more valuable products. More importantly, international demand for refinery-produced products has increased since 2007, allowing U.S. refineries to increase runs and utilization beyond what the domestic market demanded to supply products to export markets. As a result, the United States became a net exporter on an annual basis of distillate and residual fuel in 2008, of jet fuel in 2011, and of motor gasoline in 2016.
Similarly, demand for HGLs outside of the United States has increased and caused U.S exports of HGLs to increase from 70,000 b/d in 2007 to 2.07 million b/d in November 2019. Between 2013 and 2016, exports of HGLs were the largest contributor to the increase in U.S. exports of petroleum products. U.S. exports of HGLs are mostly of propane and ethane to markets in Asia and Europe, where they are also displacing refinery-produced naphtha as a petrochemical feedstock.
EIA projects that these trends of increasing U.S. production of HGLs, increasing domestic consumption of HGLs, and increasing exports of HGLs will continue beyond 2021. EIA’s Annual Energy Outlook 2020 (AEO2020), released in January, shows projections for further growth in HGL production at natural gas processing plants from 4.91 million b/d in 2019 to a peak of 6.58 million b/d in 2029 and then slowly decline to 6.17 million b/d by 2050. Domestic consumption of HGLs will also increase, driven by continued petrochemical demand for feedstock, which rises from about 3.14 million b/d in 2019 to more than 4.0 million b/d in 2029. Meanwhile, in the AEO2020 Reference case, U.S. consumption of motor gasoline declines until 2042, distillate consumption declines until 2040, and residual fuel consumption continues declining out to 2050.
U.S. average regular gasoline prices rise, diesel prices decline
The U.S. average regular gasoline retail price increased nearly 1 cent from the previous week to $2.43 per gallon on February 17, 11 cents higher than the same time last year. The Midwest price rose nearly 5 cents to $2.31 per gallon. The Rocky Mountain price fell more than 3 cents to $2.47 per gallon, the West Coast price fell 1 cent to $3.14 per gallon, the East Coast price fell nearly 1 cent to $2.36 per gallon, and the Gulf Coast price declined by less than 1 cent to $2.08 per gallon.
The U.S. average diesel fuel price fell 2 cents from the previous week to $2.89 per gallon on February 17, 12 cents lower than a year ago. The Rocky Mountain price fell nearly 4 cents to $2.86 per gallon, the East Coast price fell more than 2 cents to $2.94 per gallon, the Midwest and Gulf Coast prices each fell nearly 2 cents to $2.76 per gallon and $2.66 per gallon, respectively, and the West Coast price fell more than 1 cent to $3.47 per gallon.
Residential heating oil prices increase, propane prices decrease
As of February 17, 2020, residential heating oil prices averaged more than $2.91 per gallon, almost 1 cent per gallon above last week’s price but more than 31 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged $1.80 per gallon, more than 5 cents per gallon above last week’s price but 34 cents per gallon lower than a year ago.
Residential propane prices averaged more than $1.98 per gallon, less than 1 cent per gallon below last week’s price and nearly 45 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.56 per gallon, more than 1 cent per gallon higher than last week’s price but almost 27 cents per gallon below last year’s price.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 3.0 million barrels last week to 74.3 million barrels as of February 14, 2020, 18.4 million barrels (32.9%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories decreased by 1.1 million barrels, 1.0 million barrels, 0.6 million barrels, and 0.4 million barrels, respectively. Propylene non-fuel-use inventories represented 7.5% of total propane/propylene inventories.
According to projections published in the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook 2020 (AEO2020), total dry natural gas production in the United States will continue to increase until 2050 in most of the AEO2020 cases, primarily to support growing U.S. exports of natural gas to global markets. The United States began exporting more natural gas than it imports on an annual basis in 2017, driven by increased liquefied natural gas (LNG) exports, increased pipeline exports to Mexico, and reduced imports from Canada. In most of the AEO2020 cases, net natural gas exports continue to increase through 2050, and most of the increase is in the near term.
The AEO2020 Reference case represents EIA’s best assessment of how U.S. and world energy markets will operate through 2050, assuming no significant changes in energy policy occur. Side cases show the effects of changing model assumptions: the High and Low Oil Price cases simulate international conditions that could drive crude oil prices higher or lower, and the High and Low Oil and Gas Supply cases vary production costs and resource recoverability within the United States.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2020
EIA expects dry natural gas production to total 34 trillion cubic feet (Tcf) in 2019 once the final data is in. In the AEO2020 Reference case, EIA projects that U.S. dry natural gas production will reach 45 Tcf by 2050. Production growth results largely from continued development of tight and shale resources in the East, Gulf Coast, and Southwest regions, which more than offsets production declines in other regions. Dry natural gas production from these three regions accounted for 68% of total U.S. dry natural gas production in 2019 and, in the Reference case, 78% of dry natural gas production in 2050.
Most of the increase in dry natural gas production is coming from natural gas formations such as the Marcellus and Utica in the East region and the Haynesville in the Gulf Coast region. A smaller but still significant portion of the growth is from natural gas production in oil formations (also known as associated gas), especially in the Permian Basin in the Southwest region.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2020
In the Reference case, both U.S. natural gas exports by pipeline and U.S. LNG exports continue to grow through 2030. LNG exports account for most of the export growth because more LNG export facilities are becoming operational and more projects are under construction. In the Reference case, EIA projects that LNG exports will almost triple, from 1.7 Tcf in 2019 to 5.8 Tcf in 2030, the equivalent of nearly 16 billion cubic feet per day (Bcf/d). LNG exports remain at this level through 2050 as U.S.-sourced LNG becomes less competitive in world markets and as more countries become global LNG suppliers.
U.S. LNG exports are more competitive when oil prices are high (as in the High Oil Price case) and U.S. natural gas prices are low (as in the High Oil and Gas Supply case) because of pricing structures that link Brent crude oil prices to LNG prices in many world markets. In the High Oil Price case, U.S. natural gas net exports reach nearly 13 Tcf by the late 2030s, most of which is LNG. Conversely, in the Low Oil Price case and Low Oil and Gas Supply case, U.S. LNG is less competitive globally and remains lower than 5 Tcf per year through 2050.
By comparison, pipeline trade of U.S. natural gas is less sensitive to changes in assumptions about domestic natural gas supply and world oil prices. Pipeline trade of natural gas is highest in the High Oil and Gas Supply case because low domestic natural gas prices reduce U.S. natural gas imports from Canada.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2020