Much has been made of the recent confidence tumble in America’s Permian Basin, the low cost and prodigious shale play that straddles Texas and New Mexico. It began when Pioneer Natural Resources announced its second-quarter financial results – reporting net income of US$233 million, compared to a net loss of US$268 million the same quarter last year. But the positive results weren’t what investors focused on – it was expected, given the recovery in crude prices this year. Instead, they zoomed in on Pioneer’s decision to slash US$100 million from its 2017 capital budget, as well as anomalies within its production data – an unexpected drop in oil production that was somewhat offset by higher natural gas output (though from new wells, unusually), accompanied by higher costs. Pioneer’s stock took a tumble, down by 16% at one point, and it dragged all other Permian-related stocks with it – spooking investors that held shares of EOG Resources and RSP. Editorials and analytical notes were written furiously, warning that enthusiasm in the Permian was waning.
Meanwhile, the weekly rig count data released by Baker Hughes-GE fell by one the week Pioneer released its results. Within the topline number, active rigs in the Permian basin were flat week on week, having been the main source of rig count growth over the past year together with the Eagle Ford basin. The week after, active rig counts fell by 5, with the Permian and Eagle Ford losing 2 and 3 sites, respectively. On a macro scale, the market would cheer this as a sign that US oil production is finding a new plateau at the current level of crude prices, stuck around US$50/b. On a micro level, it is causing some jitters among Permian producers – many of whom have trimmed their spending targets for 2017 and 2018, including heavyweights Diamondback Energy and Devon Energy, in anticipation of a slowdown.
Are we about to see a collapse in the Permian? Absolutely not. After a period of rapid growth in early 2017, in response to crude prices jumping on the OPEC supply freeze pact, the Permian is merely hitting a wall of marginal gains. Permian producers raised production rapidly earlier this year, anticipating that prices would maintain at US$60/b, thereby unleashing supply that moderated prices again. With the outlook now pointing towards prices stubbornly sticking to the US$50/b level, producers are now adjusting their approach. The Petroleum Economist reports that "oil bulls and OPEC ministers who are looking for cracks in the shale recovery due to recent announcements by Anadarko, Hess and Whiting Petroleum are cutting their 2017 budgets, will be disappointed. It may just be too soon claim any victory that US shale is shutting down. EIA reports that DUCs (Drilled but Uncompleted Wells) have nearly doubled from this time last year to around 2,250. If oil remains at sub-$50, companies could start pulling rigs, and start shifting to cheaper and quicker options of completing their DUCs. This will power production growth for at least several months."
Growth in the Permian will continue through 2017 and 2018, but at a slower pace. The Permian region is projected to represent about 30 percent of total U.S. crude oil production in the coming year. Wood Mackenzie is predicting the Permain output will rise by 300,000 b/d by the end of 2017, pushing past the 2.7 mmb/d level. Meanwhile, supermajors ExxonMobil and Chevron are both increasing their presence in the Permian attracted by lower costs – the average wellhead breakeven presence in the Permian hovers around US$35/b – aiming to raise production there by 20% and 35%, respectively, from low bases. Meanwhile, Falcon Seaboard Resources just announced a US$145 million Permian fund.
Interest in the Permian isn’t waning. The ride is just slowing down, because the industry in the Permian has moved past the short, sweet period when prices rise faster than costs, and is now adjusting to that. And even the furore around Pioneer is misplaced; the company has said that the unexpected drop in oil production was short term and would be fixed in the next quarter. Pumping more natural gas isn’t a huge problem either – Permian player Parsley boosted its gas production forecast for the year in fact – since it diversifies output and total resources are still expanding. Now, in fact, might be a good time to cherry pick Permian stocks – the valuations remain good, while the stock prices have taken a beating. With OPEC, mainly Saudi Arabia attempt manoeuvring again to support prices, the Permian basin phenomenon is far from over.
P.S. for continuity of investments in the energy industry, making the right choices are key for future success. Read more about Scenario planning and the so what question a recent blog post by Henk Krijnen. Henk Krijnen will be in Kuala Lumpur this October 2017, presenting a very timely "Masterclass on Scenario Planning for Decision Making in the Energy Industry". Find out more https://goo.gl/tauq5x. If you are too busy during this period, check out our training series on “Training to Navigate Uncertainty in Oil & Gas”
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Pioneering technology expert tells ADIPEC Energy Dialogue up to 80 per cent of plant shutdowns could be mitigated through combination of advanced electrification, automation and digitalisation technologies
Greater use of renewables in power management processes offers oil and gas companies opportunities to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects
Abu Dhabi, UAE – XX August 2020 – Leveraging the synergies created by the convergence of electrification, automation and digitalisation, can create significant cost savings for oil and gas companies when making both operational and capital investment decisions, according to Dr Peter Terwiesch, President of Industrial Automation at ABB, a Swiss-Swedish multinational company, operating mainly in robotics, power, heavy electrical equipment, and automation technology areas.
Participating in the latest ADIPEC Energy Dialogue, Dr Terwiesch said up to 80 per cent of energy industry plant shutdowns, caused by human error, or rotating machinery or power outages, could be mitigated through a combination of electrification, automation and digitalisation.
“Savings are clearly possible not only on the operation side but also, using the same synergies between dimensions, you can bring down the cost schedule and risk of capital investment, especially in a time when making projects work economically is harder,” explained Dr Terwiesch.
A pioneering technology leader, who works closely with utility, industry, transportation and infrastructure customers, Dr Terwiesch said despite the increasing investment by oil and gas companies in renewables and the growing use of renewables to generate electricity, both for individual and industrial uses, hydrocarbons will continue to have an important role in creating energy, in the short to medium term.
“If you look at the energy density constraints, clearly electricity is gaining share but electricity is not the source of energy; it is a conduit of energy. The energy has to come from somewhere and that can be hydrocarbons, or nuclear, or renewables.” he said.
Nevertheless, he added, the greater use of renewables to generate electricity offers oil and gas companies the option of integrating a higher share of renewables into power management processes to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects.
The ADIPEC Energy Dialogue is a series of online thought leadership events created by dmg events, organisers of the annual Abu Dhabi International Exhibition and Conference. Featuring key stakeholders and decision-makers in the oil and gas industry, the dialogues focus on how the industry is evolving and transforming in response to the rapidly changing energy market.
With this year’s in person ADIPEC exhibition and conference postponed to November 2021, the ADIPEC Energy Dialogue, along with insightful webinars, podcasts and on line panels continue to connect the oil and gas industry, with the challenges and opportunities shaping energy markets in the run up to, and following, a planned three-day live stream virtual ADIPEC conference taking place from November 9-11.
An industry first of its kind, the online conference will bring together energy leaders, ministers and global oil and gas CEOs to assess the collective measures the industry needs to put in place to fast-track recovery, post COVID-19.
To watch the full ADIPEC Energy Dialogue series go to: https://www.youtube.com/watch?v=QZzUd32n3_s&t=6s
Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.
Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.
Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.
In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.
Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.
Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.
Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.