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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It seems to have been a topic that has been discussed for years, but a decision could finally be made. The Philippines has short-listed three different groups who are in the running to build the country’s first LNG import terminal, whittling them down from an initial 18 that submitted project proposals. The final three consist of the Philippines National Oil Company (PNOC), a joint venture between Tokyo Gas and domestic firm First Gen Corp and China’s CNOOC. The Philippines hopes to choose the final group by the end of November – an optimistic decision that belies that many, many complications that have come before. And those still to come.
First of all, the make-up of only one of the groups has been finalised. A local partner is a requirement for this project; CNOOC has yet to officially tie-up, although it has been talking to Manila-based Phoenix Petroleum, while state oil firm PNOC does not have a (deep-pocketed) partner yet. Firms including Chevron, Dubai’s Lloyds Energy Group and Japan’s JERA have reportedly contacted PNOC to express their interest, but a month before the Philippines wants to make a decision, its own home-grown hero hasn’t yet got its ducks lined up in a row.
And time is of essence. The once giant Malampaya gas field is running out of resources. Supplying piped natural gas to three power plants that feeds some 45% of Luzon’s electricity requirements, the Shell-operated field is expected to be completely depleted by 2024. With the country aiming to move away from burning coal or (imported) gasoil for power, gas is needed to replace gas. Even though the Philippines is pushing for a bilateral agreement with China to pave to way for joint exploration activities in disputed areas of the South China Sea – to the consternation of its citizens – any discovery in the Palawan basin or Scarborough Shoal will be years from commercialisation.
So LNG is the answer. And LNG has been the answer since 2008, when the need for an LNG import terminal was first identified. And it is not like no projects have been proposed – Australia’s Energy World Corp (EWC) has been wanting to build an LNG receiving terminal and power station in the Quezon province near Manila for years, but the project has been described as ‘trapped in a bureaucratic quagmire’ due to hurdles from various government agencies, or stymied by groups with competing interests.
PNOC itself has been wanting to build its own terminal in Batangas, within range of existing gas and power transmission facilities currently drawing Malampaya gas. But, just like Pertamina in Indonesia, it is cash-strapped and unable to drive the project on its own, hence the requirement for a partner/s. First Gen Corp and Phoenix Petroleum are both private players, with First Gen already operating four of the country’s five gas-fired plants while Phoenix Petroleum has close ties with CNOOC Gas.
Many announcements have been made and gone, but with this shortlist of three groups, it does finally look like the Philippines will be able to get its LNG ambitions of the ground. And it is thinking even bigger; wanting the terminal to become a LNG trading hub for the region – capitalising on the existing habit of ship-to-ship transfers of LNG cargoes into smaller parcels in the Philippine waters for delivery into southern China – challenging existing ambitions in Japan, South Korea and Singapore. But perhaps that is getting a bit ahead of themselves. Getting a project – any LNG project – off the ground is the first priority. And the rest can come after that.
Other Proposed LNG Projects In The Philippines:
Headline crude prices for the week beginning 5 November 2018 – Brent: US$72/b; WTI: US$62/b
Headlines of the week
It is a well-known fact that the oil and gas industry has a lot to offer in terms of opportunities - paycheck, lifestyle, and work-life balance. However, like everything else in life, it has a flip side as well. If you are planning to make a career in oil and gas industry, it is important to know the cons as well. Here is a list of risks associated with working in oil and gas industry that you must know to make an informed decision.
Highly competitive: survival of the fittest
Oil and gas industry is highly competitive and dynamic in nature. The job requires high level of expertise and productivity. With digitization and automation of the industry, the work functions are changing rapidly. The employees who cannot cope up and upskill with changing time and need will be automatically pushed out of the system. The foremost challenge in oil and gas industry is to stay relevant and keep upskilling.
Long work hours
Some job functions in oil industry like offshore rig workers have to work in 12-hours shift, seven days a week and for seven to 28 days in one stretch. Sometimes, overtime is also expected due to emergency or to manage the project deadlines. However, the oil companies do give equal amount of resting period to the rig workers to compensate for the long working hours. Even then, the continuous long hours is strenuous for the workforce.
The accident-prone work environment
Although rigorous safety trainings are provided to the workforce along with numerous safety measures and laws in place; accidents do occur. Sometimes, these accidents can be life-threatening. Here is quick overview of the possible accidents that you might encounter:
Risk of confined space and fall- The line workers in oil and gas industry sometimes work in confined spaces like mud pits, reserve pits, storage tanks, sand storage, and other excavated areas, where they are exposed to potential risk of ignition of inflammable vapors, exposure to harmful chemicals, and asphyxiation. Additionally, these kinds of workplaces involve risk of falls, slips and trips too which can cause severe injuries and can even turn fatal. Though the companies are extremely careful and take all safety precautions, but the risk cannot be ruled out.
Additionally, frequent exposure to chemicals used in refineries and drilling operations can impact long-term health. To offset these dangers, oil and gas companies provide comprehensive training to employees to ensure safety protocols and site-specific features.
Working in remote location
The oil and gas professionals have to work on remote location for exploration, offshore duties, pumping stations, gas plants and more. The workers in remote location often feel isolated and they are on their own to cope up with numerous work-related accidents and health hazards.
Working in oil and gas industry is extremely rewarding in terms of career growth, travelling opportunities and compensation. However, the above points must also be considered before stepping into this industry. It is important to mention here that majority of oil and gas companies are aware of the risks associated and thus have sound safety measures in place to avoid any contingency. Moreover, the government and regulatory bodies also impose strict regulations for safety and security of the workforce. Therefore, in many cases, the risk associated is considerably reduced. So, before you accept any offer from any oil and gas companies, you must carefully verify the safety measures and policies of the company. Once, you are assured, your career in oil and gas will be highly rewarding.
If you are looking for relevant opportunities, check out NrgEdge.com to kickstart your career in oil and gas industry.