Permian Basin expected to drive fourth quarter U.S crude oil production increases
In its Short-Term Energy Outlook (STEO) update released this week, EIA forecasts that U.S crude oil production will average 9.4 million barrels per day (b/d) in the second half of 2017, 340,000 b/d more than in the first half of 2017.
EIA’s close monitoring of current rig activity in several producing regions shows continued production growth from tight-oil formations, such as shale in the Permian region, driving overall production increases (Figure 1).
The STEO projects that the most significant production growth in the second half of 2017 will be in the Permian region. Permian production is forecast to grow to 2.6 million b/d in the second half of 2017, a 260,000 b/d increase from the first half of 2017. Production in the Permian continues to increase, in part as a result of West Texas Intermediate (WTI) crude oil average monthly prices that have remained higher than $45 per barrel (b) since the second half of 2016.
Extending across western Texas and southeastern New Mexico, the Permian region has developed into one of the more active drilling regions in the United States because its large geographic size and favorable geology contain many prolific tight formations such as the Wolfcamp, Spraberry, and Bonespring. Increases in proppant intensity, lateral lengths, and changes to slick-water completions are also among the factors that have allowed the Permian to remain one of the most economic regions for oil production despite the low-oil-price environment. WTI spot prices averaged $50/b in the first half of 2017, spurring deployment of more rigs to the Permian, which rose steadily from 276 rigs in January to 380 rigs in September. The STEO projects that the Permian region rig count will continue to grow from an average of 341 rigs in 2017 to 371 rigs in 2018, and the WTI price is forecast to average $49/b for the second half of 2017 and $51/b in 2018.
The STEO forecasts Niobrara and Anadarko production to grow by 75,000 b/d and 42,000 b/d, respectively, averaging 500,000 b/d and 460,000 b/d, respectively, for the second half of 2017. This growth makes these two regions the second- and third-largest contributors to the STEO’s projected growth between the first and second half of 2017. Production in the Niobrara and Anadarko regions has grown continuously since January 2017 in response to increasing rig activity and a monthly WTI price range from $45/b to $53/b during the year. With an expectation that prices will continue to be near this range, rig activity and production are expected to continue to grow.
In the STEO forecast, the Bakken region is expected to maintain production at slightly less than 1.1 million b/d through 2017, increasing by 31,000 b/d between the first and second half of the year. The Bakken region predominately spans the Williston Basin, which contains the Bakken and the Three Forks formations. Although the Bakken region is large in geographic size (23 million acres), it contains fewer identified prolific formations than the Permian. In addition, operators in this region are affected by winter weather and have greater transportation constraints in moving oil to refineries and markets. Rigs in the Bakken region grew from 35 in January to 44 in May of this year, increasing further to 51 in September.
The STEO forecasts production in the Eagle Ford region to remain relatively flat in the second half of 2017 at 1.2 million b/d, a 5,000 b/d increase from the first half of 2017. Compared with the Permian, the Eagle Ford region has a significantly smaller geographic area with fewer prolific stacked formations and fewer opportunities to drill. Rigs in the Eagle Ford region grew from 57 to 98 from January through May of this year, but declined to 83 in September, in part as a result of a lagged response to lower WTI prices in the second quarter of 2017. More recently, the Eagle Ford region experienced temporary outages in production and rig activity in August and September because of Hurricane Harvey.
EIA expects Alaska production to remain relatively flat, averaging 460,000 b/d in the second half of 2017, a 22,000 b/d decrease from the first half of 2017, because of seasonal maintenance on the Trans-Alaska Pipeline System during the third quarter.
Production in the rest of the United States is expected to remain fairly constant, with relatively modest production declines in California (30,000 b/d) and the Federal Offshore Gulf of Mexico (7,000 b/d) in the second half of 2017.
In the Lower 48 states, observed rig counts typically follow changes in the WTI price with an approximate four-month lag (Figure 2). In addition to responding to the WTI price, rig counts are related to cash flow and profitability. If returns are positive at a given price level, an operator could choose to add rigs. In that scenario, prices do not have to continually rise to support increases in rig counts. For most predominately tight-oil regions to see continued growth in production, rig activity must continue to increase because of the well dynamics, which on average have high initial production rates but very fast declines (e.g., 60% over the first 12 months of production). However, with the number of rigs continuing to increase, especially in the Permian, EIA has assessed that new wells are being drilled at a pace sufficient to maintain and increase production levels. If that trend changes, EIA will continue its process of adjusting its forecast in regular monthly STEO updates.
EIA models oil production monthly in the STEO at the state and regional levels. The STEO forecast is based on recent trends in drilling and production and on anticipated future changes, driven largely by the WTI price. EIA evaluates past production trends on a well-by-well basis for all production documented since 2014 and uses that history to estimate future well performance and decline rates at the state and regional levels.
As indicated above, EIA has observed that changes in the WTI price affect the number of active drilling rigs within about four months. Changes in the number of active rigs lead to changes in production volumes within about two months. Consequently, the STEO oil production forecast is based on the historical observation that changes in production volumes typically occur about six months after a change in the price of crude oil. The forecast is also influenced by estimates of cash flow and production costs, which vary by region and over time. In addition, the STEO makes assumptions regarding how the inventory of drilled but uncompleted wells responds to price and how that response affects production at the state and regional levels.
All historical production data are benchmarked monthly to the EIA-914 survey data and to EIA’s Petroleum Supply Monthly (PSM) estimates at the state level. The October STEO forecast for oil production is benchmarked to the PSM data for July 2017.
Since it started in 2016, the Dallas Fed Energy Survey quarterly business indicator of the share of exploration and production firms that think oil production will increase or decrease has moved consistently with EIA’s 914 survey of oil production. Consistent with the updated STEO forecast for U.S. oil production, the recently released 2017 third-quarter report from the Dallas Fed survey (July–September) shows expectations of an increase in oil production in Texas, New Mexico, and northern Louisiana from an index of 10.2 in the second quarter to 19.3 in the third quarter.
Forecasting crude oil production is a dynamic process because of many uncertainties. Not all operators respond to price movements at the same time, which leads to uncertainty in the timing and degree of change in the production trend. Constantly evolving drilling practices within the industry, changes in well performance, pipeline infrastructure, and weather events can also have significant influence on the short-term outlook for crude oil production in the Lower 48 states. Production estimates have shifted (and are likely to continue to shift) as new geological information is gained, long-term well productivity is observed, and technological advances and better operational practices improve well productivity and reduce costs. Potential changes in market dynamics, such as recent indications that investors may require companies to focus more on returns and less on production growth, also add uncertainty to the pace and level of future production.
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell over 6 cents from the previous week to $2.50 per gallon on October 9, up 23 cents from the same time last year. The East Coast and Midwest prices each fell seven cents to $2.52 per gallon and $2.33 per gallon, respectively, the Gulf Coast price fell over six cents to $2.32 per gallon, and the West Coast and Rocky Mountain prices each fell three cents to $2.95 per gallon and $2.54 per gallon, respectively.
The U.S. average diesel fuel price fell nearly 2 cents to $2.78 per gallon on October 9, 33 cents higher than a year ago. The East Coast price fell three cents to $2.79 per gallon, the West Coast and Gulf Coast prices each fell two cents to $3.09 per gallon and $2.60 per gallon, respectively, the Midwest price fell one cent to $2.74 per gallon, and the Rocky Mountain price fell less than one cent, remaining at $2.86 per gallon.
Propane inventories gain
U.S. propane stocks increased by 0.9 million barrels last week to 78.9 million barrels as of October 6, 2017, 25.0 million barrels (24.1%) lower than a year ago. Midwest, Gulf Coast and Rocky Mountain/West Coast inventories increased by 0.5, 0.4 and 0.1 million barrels, respectively, while East Coast inventories dipped slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 3.8% of total propane inventories.
Residential heating oil price decreases, propane price increases
As of October 9, 2017, residential heating oil prices averaged $2.65 per gallon, 2 cents per gallon less than last week but 28 cents per gallon more than last year’s price at this time. The average wholesale heating oil price for this week is $1.83 per gallon, almost 7 cents per gallon less than last week but nearly 19 cents per gallon higher than a year ago.
Residential propane prices averaged almost $2.26 per gallon, nearly 3 cents per gallon more than last week and 21 cents per gallon more than a year ago. Wholesale propane prices averaged $1.02 per gallon, 2 cents per gallon higher than last week and over 33 cents per gallon more than last year’s price.
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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.