In the first part of this double feature, Katherine Dunn investigates an emerging security risk for the shipping industry, as maritime authorities report a rising number of GPS failures
Early one Sunday in mid-March, a ship in Port Said, the northern gateway to Egypt’s Suez Canal, suddenly and inexplicably lost all connection to GPS on board.
“All of them affected,” the vessel’s crew wrote in a March 18 report to the US Navigation Centre of Excellence (NAVCEN), after a total of seven receivers lost connection to GPS. “Disturbance still continuous.”
The cause of disruption, after an investigation by NAVCEN, was listed as “unknown interference.”
In the following days, vessels in and around Port Said and the Suez Canal reported sudden and unexplainable outages in their GPS, some lasting days, and referenced dozens of vessels in the area experiencing the same problem.
The disruptions were concentrated around the Canal, but also extended north along a strip of sea, from just east of Cyprus to the Lebanese coast. NATO has also reported disruptions off the south coast of Turkey. While the GPS mostly just disappeared, the reports noted, sometimes it placed the vessels somewhere they were not: in one case, a vessel in Port Said appeared on GPS to be west of Alexandria, more than 150 nautical miles to the west.
US and NATO officials were paying attention, with good reason. The region has seen military tensions escalate in recent years, particularly off the coast of Syria. It is also a vital trade route: in March, 1,450 vessels of all sizes transited the waterway, about a third of which were oil tankers or LNG ships, according to data from the Suez Canal Authority. Those vessels were carrying about 61 million barrels of crude oil alone, or nearly 2 million b/d.
By March 23, just five days after the first report, the US Maritime Authority (MARAD) released an alert warning vessels of possible GPS interference in the East Mediterranean. By the summer, the incidents had drawn an alert from NATO’s Allied Maritime Command (MARCOM).
“In recent months, several electronic interferences have been detected, particularly GPS and AIS interference, as well as possible GPS jamming in the East Mediterranean,” a July 31 advisory warned.
Altogether, 16 individual reports of GPS interruptions were made between March 18 and November 4, all with the cause listed as unknown. In October, a NATO official from MARCOM said they were still investigating.
The Global Positioning System, or GPS, underpins most of the world’s digital systems for determining location, time, and communication — on everything from your mobile phone, to the world’s largest commercial vessels.
“For so many years we were used to using [only] GPS,” says Chronis Kapalidis, an expert in maritime security and the East Mediterranean at Chatham House.
It has always been possible to disrupt GPS, but doing so is now easier and cheaper than ever, experts say.
That has meant an explosion of both GPS “jamming” — when GPS is interrupted — and “spoofing” — when a receptor is tricked into believing it is somewhere it is not.
Disruption can come from civilians, who can now buy cheap jammers on the internet. It also comes from states, appearing in geopolitical hot spots alongside a new wave of cyber conflict.
Experts say many large vessels have no back-up to GPS, and crew often lack awareness that it is even vulnerable to disruption. Without back-up, an increasingly digital generation of commercial vessels risks getting caught in the crosshairs.
States or rogue elements?
There is no official explanation for why GPS is being disrupted in the East Mediterranean, but a patchwork of military operations in the region is likely to be a major cause of the interruptions. That itself is a result of rapidly rising tensions north of Egypt and off the coast of Syria.
“The eastern Mediterranean is extremely busy militarily,” MARCOM officials wrote in a report in October. “There are numerous warships operating in the region all with high powered transmitting devices.”
In fact, the East Med disruptions began before March, according to a specialist on the region, citing NATO intelligence.
Reports of disruption were heard in 2017, says Hans Tino Hansen, the CEO of Copenhagen-based maritime risk consulting firm Risk Intelligence, who published a report on GPS disruptions based on anecdotal reports from clients.
Those disruptions are likely a result of both military operations by the Egyptian army, who are fighting militants in the Sinai, and Russian warships off the coast of Syria.
“The GPS spoofing and jamming in [Port] Said and Suez is a byproduct … from a military operation that has nothing to do with the ships,” says Hansen.
GPS jamming technology is now accessible enough for jamming to be the work of “rogue” individuals, says Todd Humphreys, director of the Radionavigation Laboratory at the University of Texas at Austin.
But experts agree that in the East Med, the location and sheer scale of the interruptions points towards the work of nation states.
As a result, the potential risks of a vessel losing the ability to navigate, or drifting off course without realizing, are countless.
“The political situation in the East Med is so tense, everyone is at each other’s throats,” says Sebastian Bruns, head of the Center for Maritime Strategy and Security at the University of Kiel. “Just imagine if a Turkish freighter ran aground and spilled oil all over the Israeli coast.”
The Eastern Mediterranean is just one of the latest hot spots in an expanding list of regions that have seen interruptions rise alongside geopolitical tension.
Last year, the US-based Resilient Navigation and Timing Foundation reported that hundreds of vessels in the Black Sea saw their GPS locations disrupted. Many saw their locations at an inland Russian airport. Anecdotal reports of interruptions in the Black Sea date to at least 2016, multiple experts say.
Recurring, large scale disruptions have been reported off the Korean peninsula, in Lapland in northern Finland, and on the northern Norwegian border with Russia during NATO military drills, which Norway’s Foreign Ministry blamed on Russian forces in a comment to the Associated Press. Russian officials denied involvement.
In October, one report was logged in the Strait of Hormuz, off Iran, and two more were logged at the Saudi Arabian port of Jeddah, in the Red Sea, prompting another advisory from MARAD.
GPS disturbances are just one element in an expanding list of threats to cyber infrastructure, affecting everything from banks to social media websites and consumer utility grids. Cyberattacks have already affected the shipping industry. Last year, Maersk suffered an attack to its central networks that disabled the company for 10 days and cost the company an estimated $250-$300 million.
Meanwhile, GPS interruptions have continued in the East Med. In November, interruptions were reported at the Israeli port of Haifa, and from near the eastern tip of Cyprus.
“We have encountered more severe than normal GPS interference tonight,” read the November 4 report. “Thank goodness for paper charts.”
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Missouri S&T Petroleum Engineering students in the American Association of Drilling Engineers (AADE) along with drilling engineer instructor Dr. Rickey Hendrix received an amazing tour of the Ulterra bit manufacturing facility recently. @MissouriSandT @U
Missouri S&T Petroleum Engineering students in the American Association of Drilling Engineers (AADE), along with drilling engineer instructor Dr. Rickey Hendrix, received an amazing tour of the Ulterra bit manufacturing facility recently. @MissouriSandT @UlterraBits #ulterra pic.twitter.com/pikrSxzXsj
CME Group and Intercontinental Exchange are several weeks into the debuts of their basis-Houston West Texas Intermediate futures contracts, but the latter this week becomes the first to face the test of an expiry day and contract roll to a new front-month trading cycle.
The December 2018 contract for ICE Permian WTI Futures expires Monday, and the front-month will become January on Tuesday, which is in line with the typical US Gulf Coast pipeline trading schedule. The contract itself launched October 22.
CME launched November 5 its WTI Houston Crude Oil Futures contract, with January as the front-month. For now, there has been a disconnect between front-month CME WTI Houston (January) and front-month CME WTI Crude Oil Futures, which is WTI at Cushing, Oklahoma, (December); however, from Tuesday, both will be aligned.
Both companies see an opportunity to capture a new Gulf Coast light crude benchmark amid the shifting landscape borne out of ever-increasing US crude production and exports. S&P Global Platts competes with both companies in providing pricing benchmarks to commodities markets.
Comparatively, CME WTI Houston Crude Oil Futures had 563 average daily volume, and 108 lots of OI out to April 2019. Each lot represents 1,000 barrels.
CME VS ICE, ENTERPRISE VS MAGELLAN
The exchanges have sided with two major regional midstream outfits, each with its own strengths: ICE with Magellan and CME with Enterprise. The ICE contract reflects physical WTI deliveries at Magellan East Houston. CME reflects WTI into Enterprise terminals ECHO, Genoa Junction, and Houston Ship Channel.
Magellan East Houston currently has 8.5 million barrels of crude capacity with a total of 9.2 million barrels expected before the end of 2019. By comparison, Enterprise HSC and ECHO have 34 million barrels of storage combined.
Magellan representatives said in a Friday interview with Platts that MEH and nearby terminals’ storage capacity can be built out as liquidity increases in the ICE contract.
While Enterprise may have the edge on storage tied to contracts, WTI MEH is far and away the most actively traded regional barrel so far. However, brokers and traders on occasion report bids, offers and trades for WTI at other Houston-area terminals.
UNDERLYING PHYSICAL MARKET BUBBLES TO SURFACE WITH BUILD-OUT
More US crudes will be bound for export as Permian production of light, sweet crude increases. Export activity on the Gulf Coast is picking up and S&P Global Platts has received bids, offers and trade data linked to export activity at docks linked to both the CME and ICE contracts.
A 600,000-barrel cargo of WTI crude for December loading in Seabrook, Texas, was heard offered late last week at the equivalent of a $7.05/b premium to cash WTI at Cushing, or about a 20-cents/b premium to WTI MEH at the time.
Seabrook is home to Seabrook Logistics, a crude oil and condensate storage facility linked by a 24-inch pipeline to the Magellan East Houston terminal. The facility is a 50/50 joint venture between Magellan Midstream and LBC Tank Terminals. Seabrook currently has one dock with a 45-foot draft and the ability to load up to 700,000 barrels onto Aframax-sized vessels. A second dock, which will have the ability to fill partially loaded Suezmax vessels is under construction and is expected to be operational by late 2019, Magellan said.
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Oil and gas majors have brushed themselves off after the industrywide downturn and are back on their feet trying to mimic the success of smaller companies in US shale. But many doubters still question whether Big Oil is up to the task after failing at earlier attempts in such plays.
The setbacks to global majors’ shale efforts earlier in the decade were well-publicized. Several invested heavily in shale gas before prices collapsed, as more nimble rivals charged into liquids-rich plays.
Shell shared in the pain with a $2 billion write-down in 2013 and is among the majors persisting in shale plays. The company plans to more than double its Permian Basin output by 2020 to 200,000 b/d of oil equivalent, with just a third of production being crude and the rest lower-value gas and gas liquids.
Upstream director Andy Brown said in August that Shell had the ability to be a “top shales player.”
Other majors recently made investments to grow their shale footprint.
BP CEO Bob Dudley said last month his company’s Lower 48 unit, focused on shale, would “work magic” on the assets it bought from miner BHP for $10.5 billion, and ExxonMobil has also declared lofty goals after buying new acreage in January aimed at invigorating a shale unit widely seen as a disappointment.
But skeptics argue the majors’ strengths in operating big, long-term projects–preferably offshore and away from population centers–don’t equate to success in shale, where winning depends on speed, adaptability and local knowledge.
Other challenges include logistical complications, such as dealing with large quantities of water produced in shale operations. Trucking water from shale sites — some of it contaminated or even radioactive — is also becoming a big issue as traffic accidents and pollution take their toll.
Some say the majors may also struggle with the business of buying and selling land to refine their portfolios, a skill synonymous with American Energy Partners’ former CEO Aubrey McClendon.
Several majors have tried giving their shale units arm’s-length independence to handle such specific challenges, but those moves were not fruitful.
Shell shut its “unconventional resources directorate” in 2016 after unsuccessfully trying to transplant shale capability overseas, and ExxonMobil has re-integrated its XTO shale unit, acquired in a $41 billion deal in 2009.
Scott Sheffield, Pioneer Natural Resources chairman, told S&P Global Platts in August that he questioned the majors’ ability to compete in shale. He said Shell had not been producing from shale plays long enough to be able to determine if it was successful, and other majors’ activity is still lagging the smaller, more experienced shale producers.
“If the majors start drilling wells much faster than the independents, we should be able to see that in the data, but, so far, we’re not seeing it,” Sheffield said.
But there has been progress.
ExxonMobil says it increased its Permian and Bakken oil and gas output by 34% on the year in the third quarter, with Permian production reaching 170,000 boe/d.
Sheffield said Norway’s Equinor seemed to be doing a “decent” job with its Marcellus and Utica shale gas, despite an $860 million write-down last year relating to issues with well spacing and productivity at its Eagle Ford assets.
Sheffield also praised the development of BP’s Lower 48 unit under David Lawler, brother of Chesapeake Energy CEO Doug Lawler, but added BP may still need to buy more acreage.
Shell’s shale goals reach beyond the US and encompass Canada’s Montney tight gas, which will supply its LNG Canada project, and Argentina’s Vaca Muerta, where Brown said it was beating the competition.
Bernard Duroc-Danner, former head of service company Weatherford, said that the majors should benefit from their scientific approach, or what he called the “purposeful pursuit of information,” but were still struggling to define themselves in the face of the twin challenges of shale and resource nationalism.
He likened their shale efforts to teaching an elephant to dance, saying “they are the wrong owners because of their mass, the way they do things.”
Duroc-Danner also highlighted the reputational risks of shale production, saying that in the “local towns in Oklahoma, Texas, Colorado, people are going to be really upset about the accidents and the [number] of trucks going back and forth.”
The majors will also need to learn how to manage a rising stock of depleted wells producing a trickle of oil in their “nursing home” phase as they near the end of their lives, he said.
“The decline rate in a normal well in the Middle East or places in Latin America is just a gentle decline,” he said. But in shale, “every year you drill, you expand production, [and] 18 months later, it joins the nursing home. What happens when these fine companies end up with a huge stock of these?”
“Yes, they will run the completion and fracking business more efficiently, if they allow people in the field to get their way. For the rest, they will inherit the liability, potentially the political exposure; they will inherit the nursing homes.”
Some executives shared the doubts.
ENI CEO Claudio Descalzi has dismissed shale as beyond his company’s competence.
Total CEO Patrick Pouyanne has suggested that his company was still bruised by its shale forays. In August, he said the challenge was not just the cost of investing, at this point, but in recruiting the right people.
“My peers who are investing [in shale] have a right to do it,” Pouyanne said. “It’s more a question of competitive advantage. It’s clearly capital intensive, and it’s a question of human resources.”
The post Big Oil’s shale revival prompts industry doubts: Fuel for Thought appeared first on The Barrel Blog.
After being at a six-year high in July, the spread between Central Appalachia (CAPP) thermal coal and thermal coal delivered into Northern Europe fell to its lowest level in nearly four years Wednesday.
CIF ARA 6,000 kcal/kg coal, for delivery in the next 15 to 60 days to Amsterdam, Rotterdam or Antwerp, was assessed Wednesday by S&P Global Platts at a six-month low of $85.95/mt, while rail-delivered (CSX) CAPP coal for December delivery was assessed at $77.75/st.
The spread between the two grades of coal Wednesday was at 22 cents on a short-ton adjusted basis, the lowest since January 2015.
CAPP rail (CSX) coal, which is roughly 6,700 kcal/kg, has long been valued by Europe for its relatively high heat content and low sulfur. But because of the significant transportation costs to ship CAPP rail coal from mines in southern West Virginia and eastern Kentucky to ports in Virginia’s Hampton Roads region and then across the ocean, the export window for CAPP rail coal can frequently swing shut.
For instance, in July, CIF ARA peaked at $103.70/mt, its highest level since January 2012, and CAPP rail coal was assessed at $63.40/st, a spread of $30.67 on a short ton-adjusted basis, the highest since April 9, 2012.
The wide spread this summer likely led to an increase in booking for CAPP coal, but that additional demand has also pushed up pricing for CAPP coal through the fall, as the region’s production remains constrained as thermal producers hold back on adding new capacity out of fear that the recent market rally is not sustainable.
Production in Central Appalachia was at 19.48 million st in Q3, down 6.9% from Q2 but up 3.3% from 18.85 million st produced in the year-ago quarter, according to preliminary data from the US Mine Safety and Health Administration.
The CAPP region is also home to the US’ metallurgical coal sector, where demand has also shot higher this year due to high seaborne prices. Arguably, much of the additional production last quarter was met coal rather than thermal.
Since July, prompt prices for CAPP rail thermal coal have climbed from a near-term low of $56.50/st on May 11 to a high of $78/st on November 2.
While short supply has helped push up CAPP rail pricing, CIF ARA prices have dropped by 16% in the last month on concerns northern Europe is now oversupplied.
History tells us that when the CIF ARA price declines, so does the CAPP rail price.
The last two times CIF ARA had big declines, of 29.4% between late December 2016 and late March 2017, and 21.7% between early January and late March 2018, CAPP rail coal fell 22.9% and 12.7%, respectively.
CAPP rail coal prices have so far held steady, though the spread between the two coals will be watched more closely if the CIF ARA price continues to drop, as one would have to go back to Fall 2008 for the last time the CIF ARA price dropped below the CAPP rail price.
The post Spread between CAPP coal, ARA coal tightest in nearly four years appeared first on The Barrel Blog.
From ballot measures to statehouses, what do the results of the US midterm elections mean for oil, gas and power markets? Kate Winston and Maya Weber report
On November 6, US voters shied away from key statewide environmental initiatives that would have imposed near-term costs on oil, gas and traditional utility interests. But they backed candidates, including nine new Democratic governors, with aggressive renewable energy and environmental goals. Advocates may now look to states fully under Democratic control – such as Nevada, New Mexico and Colorado – to take quick action on clean energy, since divided government at the federal level lowers prospects for this in Washington.
Several green ballot initiatives offered critical test cases, and their defeat could discourage other states from pursuing similar measures. Washington’s carbon fee and Colorado’s drilling setback were seen as bookending what is politically possible at the moment.
Washington Initiative 1631 would have been the first carbon fee in the US. If passed, it would have set a carbon fee of $15/mt starting in 2020 and boosted costs for oil refineries, gas-fired power plants and other large users of fossil fuels.
Colorado Proposition 112 would have increased oil and gas drilling setbacks on non-federal land from 500 feet to 2,500 feet. The measure, strongly opposed by the oil and gas sector, could have reduced oil production in some basins by more than 50% by 2023.
If the Colorado measure had passed in a state that leans heavily on industry revenue, it could have been copied elsewhere. The failure of the Washington measure in a state with low carbon intensity suggests it could be a heavy lift elsewhere.
“We viewed both states as litmus tests for potential policy contagion,” ClearView Energy Partners said in a post-election note. “In Colorado, where proceeds from a fast-growing oil and gas industry fund schools and local governments, voter support for a de facto drilling ban could have pointed towards emulation by other, less-revenue-reliant producer states,” the note said.
Scott Segal of Bracewell said Washington state has a balance of urban and rural voters, and of conservative and liberal voters. As a result, there were two well-funded sides battling over a fairly aggressive carbon tax. “It in many respects was a test case for the politics of the carbon tax on what I would call neutral ground,” he said in a post-election webinar.
But Tom Steyer, founder of the nonprofit NextGen Climate Action, pushed back against the narrative that the failure of the Washington initiative means a carbon fee would be politically infeasible at the national level. “I don’t think that for a second because obviously the largest, most populous state in the United States is California and we have a comprehensive plan,” Steyer said at a post-election event.
Environmental advocates blamed the defeat of some initiatives on industry spending. Advocates spent $15 million backing the Washington initiative while opponents spent about $30 million to defeat it. Proponents of the Colorado initiative spent $1 million and opponents spent $30 million.
Industry groups countered that some initiatives failed when put to the test by voters. “Where energy bans were on the ballots, many of them failed when it was put to a vote of the people,” said Benjamin Marter, communications director for the American Petroleum Institute.
Elsewhere, Alaska voters also shot down Ballot Measure 1, which would have strengthened permitting regulations for any activity that could affect salmon habitats. Oil and gas producers said the rules could delay projects and increase costs, potentially prohibiting developments on the state’s North Slope and elsewhere.
While several high-profile ballot initiatives disappointed environmental groups, their policy goals gained ground in governors’ mansions. Seven switched to Democratic hands.
The League of Conservation Voters tallied nine new governors who committed to move their states toward 100% clean energy: Tony Evers of Wisconsin, Gretchen Whitmer of Michigan, J.B. Pritzker of Illinois, Janet Mills of Maine, Jared Polis of Colorado, Kate Brown of Oregon, Gavin Newsom of California, Steve Sisolak of Nevada and Ned Lamont of Connecticut.
Michelle Lujan Grisham in New Mexico, another Democratic governor pickup, is expected to tighten venting and flaring requirements for oil and gas production, in addition to backing 50% renewables by 2030 and 80% by 2040.
Governor-elect support for clean energy goals overlaps with six states in which Democrats moved from divided control to holding the governorship and both chambers of the state legislature: Colorado, Illinois, Maine, New Mexico, New York and Nevada. The combination increases the likelihood of measures advancing.
That makes a difference in places like Colorado, where Senate Democratic control combined with the election of a governor who has backed 100% renewable energy by 2040 and favors tighter regulation of the oil and gas industry.
The New York state Senate flip to Democratic hands also could give life to more ambitious renewables goals than embraced by Democratic Governor Andrew Cuomo. The push for a higher concentration of renewables “will be baked into the nationwide platform approaching 2020 and beyond” in the Democratic Party, said Rob Rains of Washington Analysis.
Dan Lashof, director of the World Resources Institute–United States, said after the election he sees Colorado, Nevada and New Mexico as poised for quick action on renewable standards. Wisconsin experienced the biggest ideological shift, Lashof said, with Democrat Tony Evers unseating Republican Governor Scott Walker, while Michigan and Illinois governors-elect could strengthen the existing goals on renewables.
With no action on climate legislation at the federal level, many environmental groups are focusing on state-level and sector-specific progress, Michael Brune, executive director of the Sierra Club said. “The commitments on 100% clean energy coming from these governors, we feel will be deeply transformative.”
Going in a different direction, Ohio elected Republican Attorney General Mike DeWine, improving prospects for efforts to relax renewable mandates.
Results were mixed for ballot initiatives to raise renewable energy targets. Arizonans rejected a ballot initiative to require electric utilities to get 50% of their power from renewables by 2030. Arizona Public Service fought the measure, saying it could force the 3.9 GW Palo Verde nuclear plant to retire early.
A Nevada initiative to increase the state’s renewable portfolio standard to 50% by 2030 won easily with 60% of the vote, despite the state’s utility remaining neutral on the issue. While the initiative needs to pass again in 2020 to go into effect, environmental groups hope the state legislature will pass a law making that mandate binding even sooner. Prospects are improved by the election to governor of Sisolak, who ran as a clean energy advocate combating climate change.
The post Insight: US voters give boost to clean energy policies but stop short of carbon tax appeared first on The Barrel Blog.
Louisiana’s crude imports in the third quarter of 2018 fell 15.616 million barrels year on year despite higher regional refinery runs for the same period amid a wider year-on-year Brent/WTI swap spread.
Louisiana refineries and buyers brought in 62.389 million barrels of crude in Q3 2018, according to data from US Customs and Border Protection and S&P Global Platts Analytics.
Of that amount, 22.341 million barrels were imported from Iraq, Saudi Arabia and Kuwait. This represents a year-on-year decrease of 2.405 million barrels of crude sourced from Middle East producers.
Imports going specifically to Morgan City, Louisiana, the delivery point for the Louisiana Offshore Oil Port, in Q3 fell 10.612 million barrels year on year to 20.893 million barrels.
Despite the year-on-year decrease in total Q3 imports, October saw Louisiana buyers bring in 5.636 million barrels more crude than in October 2017, the data show.
The number of barrels imported via Morgan City in October also rose 4.287 million barrels year on year to 10.915 million barrels.
Unlike overall Q3 volumes, October imports in Louisiana included 7.012 million more barrels of crude sourced from Middle East producers than the year-ago period for a total of 12.597 million barrels purchased from Iraq, Saudi Arabia and Kuwait.
Even as Q3 imports fell, US Gulf Coast refinery input levels averaged 9.246 million b/d in the period, an increase of 659,000 b/d year on year. October’s input also increased year on year, rising 793,000 b/d to 9.238 million barrels.
The decrease in Q3 import levels coincided with a wider Brent/WTI swap spread. In Q3, the Brent/WTI swap spread averaged $6.33/b, about $2.30/b wider than in the year-ago period. In October, the Brent/WTI swap spread averaged $9.85/b, about $3.80/b wider than the year-ago period. As Brent’s premium over WTI increases, WTI-based domestic grades become more economic to run than Brent-based imported grades, including those from the Middle East.
Kuwait Export Crude, along with Basrah Light and Arab Medium, are delivered into LOOP’s Segregation 17 crude blend. Segregation 17 is blended with Mars and Poseidon to form the LOOP Sour crude stream.
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http://blogs.platts.com/2018/11/12/us-bakken-crude-takeaway-constraints/?utm_source=twitter&utm_medium=social&utm_content=barrelblog&utm_term=we-oilOil produced in North Dakota’s Williston Basin is the latest North American crude grade to experience plummeting values because of what many in the industry say is rising output and tightening pipeline takeaway capacity combined with regional refinery maintenance.
Bakken crude values began experiencing a rather sharp decline at the start of October when a combination of factors began to weigh on values.
Midcontinent crude traders have spoken about Bakken differentials being pressured by pipeline-constrained Canadian grades, as well as ongoing refinery maintenance in the Midwest.
More than 800,000 b/d of Midwestern refining capacity was offline in October, but planned work started to wrap up at the end of the month.
But one of the region’s largest refineries — BP in Whiting, Indiana — extended its maintenance to mid- to late November. There also were reported issues at Phillips 66 at the Wood River refinery in Roxana, Illinois, recently after the coker and crude sections were shut.
Bakken grades have dropped sharply since the beginning of October when a combination of factors began to weigh on values.
Prices for Bakken at terminals near the oil producing Williston Basin decreased nearly 70% from September to October, according to S&P Global Platts data. Average price differentials in the Williston Basin fell from a $2.75/b discount to the NYMEX light sweet crude calendar-month average in September to a WTI CMA minus $8.45/b in October. So far in November, Bakken Williston has averaged about WTI CMA minus $17/b.
Bakken in the Clearbrook, Minnesota, hub has followed a similar trajectory.
BAKKEN PRODUCTION RISING
In addition to seasonal maintenance, rising output is filling available pipeline space out of the Williston Basin, and that is leading to some in the industry to search for trucks and rail cars to move the crude to desirable markets. But trucks and trains also are in short supply, traders have said, as much of that rail capacity has been “re-positioned” because of new pipelines.
Sending Bakken crude to the Gulf Coast by rail has become a desirable option for some traders, if they can manage to secure railcars. The spread between Bakken in the Williston Basin and in Nederland or Beaumont, Texas has grown to around $26/b.
Bakken oil producers are close to maxing out available pipeline space and rail out of North Dakota, even though on paper the basin roughly has 300,000 b/d of spare takeaway capacity, the state’s pipeline regulator said in an interview last week.
Justin Kringstad, the director of the North Dakota Pipeline Authority, said the Basin has 1.37 million b/d in pipeline capacity, with another 250,000-275,000 b/d of crude leaving by rail. It’s unclear if more railcars are available in the region, but sources have said they have had a hard time securing railspace.
North Dakota recently reached a record 1.29 million b/d in oil production and that is expected to rise. Kringstad said that despite new wellsite requirements for natural gas capture, he expects Williston Basin output to reach 1.34 million sometime next year.
While there seems to be enough pipeline takeaway capacity on paper, in reality it’s a slightly different story, Kringstad said. Several lines are idled or running at very low volumes because it is undesirable to ship on them, such as Enbridge’s BEP line from North Dakota to Cromer, Manitoba, in Canada.
Other options also are not ideal for many, Kringstad said.
The Enbridge mainline that takes crude from North Dakota to Clearbrook, Minnesota, also is not shippers’ top choice because differentials in Clearbrook are hurting due to downward pressure from depressed Canadian grades, and refinery maintenance.
“[DAPL] is the obvious choice,” Kringstad said. “Those routes that get you to Clearbrook are the last resort.” Kringstad said that DAPL is by far the top choice for many shippers to move Bakken crude to the Gulf Coast, where differentials, refinery demand, and the opportunity to export is much stronger.
OTHER CRUDES CONSTRAINED BY PIPES
Extremely depressed values for North American crude near production fields have been a familiar trend this year, with output outpacing pipeline takeaway options as the main reason behind those low differentials.
Prices for WTI Midland crude reached record-low levels of WTI cash minus $17.50/b in August, when production in the Permian Basin continued to outpace available pipeline space. WTI Midland has found some support after it was announced a pipeline expansion project would start up by the end of the year.
But major relief for takeaway issues will not be available until new pipelines are completed next year.
A lack of pipeline takeaway capacity out of Canada, combined with refinery maintenance in the US Midwest, has widened Canadian crude price discounts and has pushed some producers to cut output. The dynamic has depressed values for both Canadian heavy and light grades, which compete with Bakken crude and often initiate price movements.
Syncrude Sweet Premium, the light benchmark, was last assessed at a discount of $32/b to the WTI CMA, the weakest differential on record. Mixed Sweet and condensate differentials at Edmonton also fell to record lows Thursday.
On the heavy side, S&P Global Platts assessed Western Canadian Select crude at an average $27.78/b discount to WTI CMA during Q3, out from an $18.15/b average in Q2. The discount has since widened to average $45.84/b so far in Q4.
S&P Global Platts Analytics expects total Canadian production losses to be limited to roughly 100,000-200,000 b/d by the middle of 2019.
The post US Bakken crude latest to suffer from takeaway constraints: Fuel for Thought appeared first on The Barrel Blog.
US energy abundance underpinned the Trump administration’s case for rolling back federal vehicle fuel economy standards, a policy the government aims to adopt by March.
The US is producing enough oil “to satisfy nearly all of its energy needs and is projected to continue to do so,” the administration argued in the proposal that would freeze fuel efficiency for cars and light trucks at the 2020 target of 43.7 miles per gallon. Booming domestic output has “added new stable supply to the global oil market and reduced the urgency of the US to conserve energy,” it said.
However, this newly abundant supply has not shielded US drivers from global price risks, as recent volatility has shown. And the US has not become less exposed to global market forces as it pumps more crude and exports it around the world.
“The idea that the imperative on conservation is gone because you have abundance is just exceedingly short-sighted and not strategic,” said Sarah Ladislaw, director of the Center for Strategic & International Studies’ energy and national security program.
“That’s where people really take issue with an articulation of that position, because it seems to fundamentally misunderstand the history of oil markets,” she said. “You can have all the supply that you want, but if it can’t get to where it’s going, your reliance on it is still a strategic vulnerability.”
US oil import dependence has fallen sharply from a peak of 60% in 2005 to 21% in 2017, according to the Energy Information Administration. The EIA projects it will average 17.5% for 2018 and keep falling steadily until 2029, when total crude and refined product exports will overtake imports for the first time.
This figure – which EIA calls the net import share of product supplied – reflects the dramatic shift toward US energy abundance that the Trump administration rightly praises. The fact that this figure is on a clear path toward zero does not mean the US is “producing enough oil to satisfy nearly all of its energy needs.”
The US still imports about 7.9 million b/d of crude and 2.2 million b/d of refined products. Those volumes are projected to fall, while US exports of crude and products keep rising.
Even when the US becomes a net oil exporter, US producers will still rely on export markets to find the best home for their particular crude, while US refiners will rely on imports for feedstock. Gulf Coast refineries were built to process heavy crudes from Saudi Arabia and Venezuela. Some of this capacity will be reconfigured to take advantage of the light sweet crude streaming out of West Texas, but not enough to say the US can become self-sufficient when it comes to producing and refining all the oil it consumes.
“The idea that the amount that you’re producing equals self-sufficiency is wrong,” Ladislaw said. “If you look at what’s happening in the US oil market, we’re getting more deeply integrated into global oil markets because we’re trading and we need to trade to make sure we can optimize our own energy system from the upstream all the way to a downstream perspective.”
Congress created the first US fuel economy standards in 1975 to protect against price shocks and supply shortages like those seen during the 1973 oil embargo. The first rule aimed to double the average fuel economy of the new car fleet to 27.5 mpg by model year 1985. Fast forward to the Obama administration adopting standards for 2012−25 model years to get the fleet-wide average to an equivalent of 54.5 mpg, which would have been 49.6 mpg in actual efficiency gains plus offsets.
The Trump administration said the US no longer needed such ambitious targets because of rising domestic oil production and the US consuming a smaller share of global supply. In addition, a greater diversity of both suppliers and consumers in the oil market since the 1970s had made it less likely a single actor or group like OPEC could harm consumers. “The global oil market can, to a large extent, compensate for any producer that chooses not to sell to a given buyer by shifting other supply toward that buyer,” the administration said in the August proposal.
Despite this line of reasoning by his administration, President Donald Trump has spent much of 2018 blaming OPEC for high US gasoline prices. “The OPEC monopoly must get prices down now!” he said September 20 in one of half a dozen tweets devoted to high gasoline prices and OPEC.
Easing the vehicle efficiency standards is expected to increase US oil demand by 500,000 b/d. The proposal says the economic impact of this extra 2−3% of oil demand is dwarfed by cost savings for auto buyers.
The proposal acknowledges that rising US production and falling import dependence cannot entirely insulate consumers from the effects of price shocks. “But it appears that domestic supply may dampen the magnitude, frequency, and duration of price shocks,” it said. “As global per-barrel oil prices rise, US production is now much better able to (and does) ramp up in response, pulling those prices back down. Corresponding per-gallon gas prices may not fall overnight, but it is foreseeable that they could moderate over time, and likely respond faster than prior to the shale revolution.”
The post Insight from Washington: US energy conservation gets lost in the drive for oil abundance appeared first on The Barrel Blog.
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