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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Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline
In 2018, U.S. exports of crude oil continued to increase to 2.0 million barrels per day (b/d), up 846,000 b/d (73%) from 2017 (Figure 1). The number of destinations for U.S. crude oil exports also increased from 37 to 42. Volumes by destination changed significantly between the first and second halves of 2018.
The increase in U.S. crude oil exports was the result of increasing U.S. crude oil production and infrastructure changes. U.S. crude oil production increased 1.6 million b/d from 2017 to 10.9 million b/d in 2018, with the U.S. Gulf Coast—where more than 90% of U.S. crude oil exports depart from—producing 7.1 million b/d. The increased production is mostly of light, sweet crude oils, but U.S. Gulf Coast refineries are configured mostly to process heavy, sour crude oils. This increasing production and mismatch between crude oil type and refinery configuration causes more of the increasing U.S. crude oil production to be exported.
In early 2018, modifications were made at the Louisiana Offshore Oil Port (LOOP) in the Gulf of Mexico to enable the loading of vessels for crude oil exports. LOOP is currently the only U.S. facility capable of accommodating fully loaded Very Large Crude Carriers (VLCC), vessels capable of carrying approximately 2 million barrels of crude oil. After LOOP was modified to also allow exports, the increase in cargo scale led U.S. crude oil exports to surpass 2 million b/d for 25 weeks in 2018 compared with just 1 week in 2017. In addition to LOOP, other U.S Gulf Coast export facilities in and around Houston and Corpus Christi, Texas, have been investing in increasing the scale of U.S. crude oil export cargos.
In 2018, Asia was the largest regional destination for U.S. crude oil exports, followed by Europe, and, as in previous years, Canada was the largest single destination for U.S. crude oil exports. Canada received 378,000 b/d of U.S. crude oil exports, representing 19% of total U.S. crude oil exports in 2018. South Korea surpassed China to become the second-largest single destination for U.S. crude oil exports in 2018, receiving 236,000 b/d compared with China’s 228,000 b/d (Figure 2).
However, the distribution of U.S. crude oil exports by destination varied significantly from the first half of 2018 to the second half. In the first half of 2018, the United States exported 376,000 b/d of crude oil to China, which made China the largest single destination for U.S. crude oil exports for that period. However, in August, September, and October of 2018, the United States exported no crude oil to China, and then in November and December it exported significantly less than in earlier months. In the second half of 2018, the United States exported 83,000 b/d of crude oil to China, a decrease of 294,000 b/d from the first half (Figure 3).
In the summer of 2018, as part of ongoing trade negotiations between the United States and China, China temporarily included U.S. crude oil on a list of goods potentially subject to an increase in import tariffs. At the same time, the difference between the international crude oil benchmark Brent and the U.S. domestic price West Texas Intermediate (WTI) futures prices narrowed rapidly between June and July 2018. Brent prices went from $9 per barrel (b) higher than WTI in June to $6/b higher than WTI in July. The rapidly narrowing price discount of U.S. crude oils versus international crude oils and the potential for higher import tariffs caused Chinese buying of U.S. crude oil to slow.
Although U.S. crude oil exports to China slowed in the second half of 2018, exports to South Korea, Taiwan, Canada, and India increased significantly. U.S. crude oil exports to South Korea increased 247,000 b/d (222%) between the first and second half of 2018. U.S. crude oil exports to other destinations in Asia also increased, particularly to Taiwan, which rose 111,000 b/d (168%) in the second half of 2018 compared with the first half, and to India, which increased 86,000 b/d (97%) during the same period.
Despite the volume changes in U.S. crude oil destination between the first and second halves of 2018, the list of destinations has remained consistent over the past three years. Of the 27 destinations that took U.S. crude oil in 2016, the first year of unrestricted U.S. crude oil exports, 22 destinations did so again in 2017 and again in 2018 (Figure 4). Furthermore, few destinations appear to be one-time recipients of U.S. crude oil, other than those such as the Marshall Islands that were listed because of data collection methods and ship-to-ship transfers.
U.S. average regular gasoline price increases, diesel price falls
The U.S. average regular gasoline retail price rose nearly 8 cents from the previous week to $2.55 per gallon on March 18, down 5 cents from the same time last year. The East Coast price rose nearly 9 cents to $2.52 per gallon, the Gulf Coast price rose over 8 cents to $2.30 per gallon, the Midwest price rose nearly 8 cents to $2.48 per gallon, the Rocky Mountain price rose nearly 7 cents to $2.32 per gallon, and the West Coast price rose nearly 5 cents to $3.03 per gallon.
The U.S. average diesel fuel price fell nearly 1 cent to $3.07 per gallon on March 18, nearly 10 cents higher than a year ago. The Midwest price fell nearly 2 cents to $2.99 per gallon, the Gulf Coast price fell over 1 cent to $2.87 per gallon, and the West Coast price fell nearly 1 cent to $3.50 per gallon. The Rocky Mountain price increased nearly 1 cent, remaining at $2.94 per gallon, and the East Coast price rose less than 1 cent, remaining at $3.12 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.0 million barrels last week to 51.1 million barrels as of March 15, 2019, 6.3 million barrels (14.0%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories increased by 1.2 million barrels, 0.4 million barrels, and 0.1 million barrels, respectively, while Midwest inventories decreased by 0.7 million barrels. Propylene non-fuel-use inventories represented 12.1% of total propane/propylene inventories.
Residential heating fuel prices decrease
As of March 18, 2019, residential heating oil prices averaged nearly $3.22 per gallon, 1 cent per gallon below last week’s price but 16 cents per gallon above last year’s price at this time. Wholesale heating oil prices averaged $2.09 per gallon, nearly 4 cents per gallon less than last week’s price but 8 cents per gallon more than a year ago.
Residential propane prices averaged $2.41 per gallon, less than 1 cent per gallon lower than last week’s price and almost 8 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.84 per gallon, less than 1 cent per gallon above last week’s price but 3 cents per gallon below last year’s price.
Source: U.S. Energy Information Administration, Electric Power Monthly
Renewable generation provided a new record of 742 million megawatthours (MWh) of electricity in 2018, nearly double the 382 million MWh produced in 2008. Renewables provided 17.6% of electricity generation in the United States in 2018.
Nearly 90% of the increase in U.S. renewable electricity between 2008 and 2018 came from wind and solar generation. Wind generation rose from 55 million MWh in 2008 to 275 million MWh in 2018 (6.5% of total electricity generation), exceeded only by conventional hydroelectric at 292 million MWh (6.9% of total generation).
U.S. solar generation has increased from 2 million MWh in 2008 to 96 million MWh in 2018. Solar generation accounted for 2.3% of electricity generation in 2018. Solar generation is generally categorized as small-scale (customer-sited or rooftop) solar installations or utility-scale installations. In 2018, 69% of solar generation, or 67 million MWh, was utility-scale solar.
Source: U.S. Energy Information Administration, Electric Power Monthly
Increases in U.S. wind and solar generation are driven largely by capacity additions. In 2008, the United States had 25 gigawatts (GW) of wind generating capacity. By the end of 2018, 94 GW of wind generating capacity was operating on the electric grid. Almost all of this capacity is onshore; one offshore wind plant, located on Block Island, off the coast of Rhode Island, has a capacity of 30 megawatts. Similarly, installed solar capacity grew from an estimated less than 1 GW in 2008 to 51 GW in 2018. In 2018, 1.8 GW of this solar capacity was solar thermal, 30 GW was utility-scale solar photovoltaics (PV), and the remaining 20 GW was small-scale solar PV.
Growth in renewable technologies in the United States, particularly in wind and solar, has been driven by federal and state policies and declining costs. Federal policies such as the American Reinvestment and Recovery Act of 2009 and the Production Tax Credit and Investment Tax Credits for wind and solar have spurred project development.
In addition, state-level policies, such as renewable portfolio standards, which require a certain share of electricity to come from renewable sources, have increasing targets over time. As more wind and solar projects have come online, economies of scale have led to more efficient project development and financing mechanisms, which has led to continued cost declines.
Conventional hydroelectric capacity has remained relatively unchanged in the United States, increasing by 2% since 2008. Changes in hydroelectric generation year-over-year typically reflect changes in precipitation and drought conditions. Between 2008 and 2018, annual U.S. hydroelectric generation was as low as 249 million MWh and as high as 319 million MWh, with hydroelectric generation in 2018 totaling 292 million MWh. Generation from other renewable resources, including biomass and geothermal, increased from 70 million MWh to 79 million MWh in the United States between 2008 and 2018, and it collectively represented 1.9% of total generation in 2018.