US tight oil production is expected to reach 4 million b/d by the end of the year, making up the bulk of global supply, but the tight oil trend will move beyond North America rapidly in the coming years, a consultant told a US Energy Information Administration conference Tuesday.
By 2020, roughly 10% of tight oil output will be produced in locations outside of North America, according to Jamie Webster, a senior director with IHS Energy. “The United States is not going to be the only home for tight oil production,” Webster said. “Tight oil is not a US phenomenon, it is going to go global.” This production shift could lessen OPEC’s hold on the global oil market, but could also create more price volatility, he said.
Webster said that non-US companies will likely be coming to the US to learn tight oil production techniques while US-based companies will likely be expanding their tight oil operations into new markets. “The US focused on natural gas first, then switched to oil as gas prices fell,” Webster said. “The opposite is likely to occur in many other countries.”
Tight oil production, however, still faces numerous challenges, in particular its relatively low recovery rates, according to Robert Kleinberg, a Schlumberger Fellow. Tight oil wells have a recovery rate of only 5%, compared with an average of 50% for conventional wells, he said.
Still, Sam Gorgen, an operations research analyst with EIA, said tight oil production will make up roughly half of the 9 million b/d the agency projects the US will be producing by the end of 2015. But Gorgen cautioned against the unpredictability of production forecasts, which can be affected by state data lags, shifting geographic definitions of plays and weather events and regulations that are often outside the EIA’s methodology.
A recent Supreme Court of Canada ruling, granting for the first time land title rights to a First Nations band in British Columbia, is unlikely to have any major impact on LNG and crude oil pipeline facilities planned in the province, sources said Tuesday.
Ravina Bains, associate director with the Center for Aboriginal Policy at the Vancouver-based Fraser Institute, said although the verdict recognizes an aboriginal title outside of an Indian Reserve, the federal government can still “push through” a development. “[A push through] will be possible if the government is able to demonstrate a compelling and substantial public purpose for the proposed activity,” she said in a research note.
However, Bains added that the verdict has clarified that provincial laws like the Environmental Sustainability Act and the Forestry Act will still be applicable for oil and gas projects in a First Nations area in British Columbia.
In late June, the Supreme Court issued a verdict favoring the Tsilhot’In Nation for a case the band filed in 1989 against the British Columbia government over a commercial logging license in its traditional territory. “This was a long process and the trial entailed a cost of some C$40 million ($36.8 million) in lawyer fees and court proceedings. In the end, the court granted the community 1,700 sq kms [1,054 sq miles] of land titles to its traditional area in interior [British Columbia],” Bains said. Terming the verdict “historic” and a “game changer,” Bains said the verdict stipulated that, along with consultations, community consent will also be required from the Tsilhot’In Nation.
“We will now have the rights to decide how our traditional lands will be used and what will be the best way forward to derive economic benefits from oil and gas projects in our province,” Chief Williams of the Tsilhot’In Nation band said Tuesday.
The judgment clearly stated that consent from First Nations is applicable to all future aboriginal title lands, and if there is a project on that land that the First Nation does not support, then the government may be required to cancel the project, Williams said.
The Supreme Court said its verdict will be retroactive, implying there could be an opportunity to re-assess an LNG or a crude oil pipeline facility in the province, Williams noted. The National Energy Board has granted export licenses for seven LNG export projects in British Columbia, while it has also approved the Enbridge-backed 525,000 b/d Northern Gateway crude oil export pipeline.
Libya’s oil production has jumped to 600,000 b/d as of late Tuesday after the major Sharara oil field in the southwest of the country ramped up to a new high, state-owned National Oil Corp. said.
The sudden increase, from an average of around 470,000 b/d on Monday, came after production was further ramped up at Sharara. “Oil production is close to 600,000 b/d as of this afternoon,” an NOC spokesman said. “Production increased as there was increased output from the Sharara field. Oil production will increase as long as there are no more blockades on the oil fields and terminals,” he said.
Sharara has a capacity of 340,000 b/d, so could be close to capacity as Libya was producing just shy of 300,000 b/d before Sharara returned. The Sharara field is operated by a joint venture between NOC and Spain’s Repsol. The market is, though, still awaiting first exports of Sharara out of Zawiya.
The NOC spokesman said there were around 10 million barrels of crude “ready for exports at storage facilities now.” Libyan production is ramping up from lows of just 150,000 b/d last month, though it remains well below the 1.5 million-1.6 million b/d Libya was producing before the current spate of unrest began in May 2013.
UK Prime Minister David Cameron appointed his fourth energy minister in less than two years Tuesday, prompting a warning from the upstream industry that the government must remain focused on its reforms to the sector.
Matthew Hancock, previously minister of state for skills and enterprise, takes over as minister of state at the Department of Energy and Climate Change as well as minister of state at the Department for Business, Innovation and Skills, replacing Michael Fallon, who held both posts from March last year, Cameron’s office said.
Cameron has also announced a change of Treasury minister responsible for oil and gas, moving Nicky Morgan to another role. Her replacement had still to be named.
“Today marks the appointment of the fourth energy minister in less than two years and Nicky Morgan’s promotion means we will also have the fifth Treasury minister with responsibility for oil and gas in less than three years,” said Malcolm Webb, chief executive of lobby group Oil and Gas UK. “This change in government leadership comes at a critical time for our industry and must be managed to result in the least disruption to the conduct of policy initiatives now in train.”
The government Monday launched a public consultation on its review of the country’s upstream oil and gas tax regime, intended to boost flagging investment. It is also setting up a new upstream regulator outside DECC. “OGUK calls on thegovernment to maintain its focus on the oil and gas industry through continued collaboration,” it said.
US, EU differences on cross-border rules risk permanent liquidity drain: O'Malia
Washington (Platts)--15Jul2014/507 pm EDT/2107 GMT
US and European regulators must quickly come together to harmonize international derivatives trading rules before market fragmentation and low liquidity become lasting fixtures of the swaps and futures markets, Commissioner Scott O'Malia of the US Commodity Futures Trading Commission said Tuesday.
In a keynote address before a quadrilateral meeting of financial lawyers groups at the Federal Reserve Bank of New York, O'Malia renewed calls for the European Commission and the CFTC to declare that the US regulatory regime is equivalent under the European Market Infrastructure Regulation.
"It is critically important that international regulators continue to work together to harmonize swap data reporting, exchange trading and [central counterparties] clearing before market fragmentation and contraction of liquidity hardens and becomes permanent," O'Malia said.
As a consequence of the slow-moving negotiations, a decision by the EC to consider all contracts executed on non-EU equivalent exchanges -- such as US futures products -- over-the-counter derivatives has impacted energy market liquidity, recent media reports have indicated.
For instance, Kim Taylor, head of clearing at CME Group, recently told Risk.net that energy futures volume has fallen as a result of European companies avoiding US-executed futures products which would be counted towards the so-called non-financial corporate calculation, or NFC+.
If US rules were considered equivalent to EU rules, US-executed futures would not be counted toward Europe's NFC+ designation. Companies like to avoid transactions that count against the NFC+, because reaching a certain threshold would trigger more onerous reporting requirements, among other issues.
"We're seeing some customers shift from exchange-traded products to alternatives that won't count toward their NFC+ threshold," said Taylor.
CME, which reported June volumes earlier in the month, said NYMEX natural gas futures volume was down 13.5% from June 2013, while year-to-date volume was down 16.8%. Likewise, volume in the NYMEX light sweet crude contract was down 13% in June compared with a year earlier, and year-to-date volume is off 11.4%.
While many products have seen decreased volumes and liquidity amid historically low volatility, CME on Monday said there was record trading volume and open interest for its NYMEX Brent crude oil contract on July 11.
So while derivatives rules could have a large impact on overall market liquidity, it might potentially be a mixed bag when looking at individual product offerings.
In March, CME received regulatory approval from the UK's Financial Conduct Authority for its London-based derivatives exchange CME Europe, a clear signal that exchanges are maneuvering to continue offering risk management products internationally and curtail regulatory uncertainty over cross-border rules.
While not offering any significant energy products, yet, the exchange was created in an effort to help Europe-based customers "access liquidity in a location jurisdiction" and to "better serve our customers in the region as we expand our business with relevant products," according to Terry Duffy, CME executive chairman and president.
O'Malia, meanwhile, said the importance of well-functioning markets "cannot be overstated" and that he was "deeply concerned by continuing reports of market fragmentation and fracturing of liquidity between US and non-US markets as a result of diverging regulatory approaches to implementation of the G20 principles."
G20 members committed to coordinating regulatory approaches at a summit in Pittsburgh, Pennsylvania, in 2009.
O'Malia added that he hoped the CFTC and EC could come to an agreement on accepting US rules as comparable before a December 15 deadline when higher capital standards would be imposed on third-country CCPs that are not recognized under EMIR equivalency.
"As I have stated before, it is my firm belief that the key to effective and efficient cross-border regulation of the swaps market is through an outcomes-based approach where regulators would defer to the other jurisdiction when it is justified by the quality of their respective regulation and enforcement regimes," O'Malia said.
The CFTC said it could not comment on the ongoing negotiations with the EC.
--Christopher Tremulis, christopher.tremulis@platts.com
--Edited by Lisa Miller, lisa.miller@platts.com
Europe's TAL crude oil pipeline still pumping at record levels: chief
London (Platts)--15Jul2014/657 am EDT/1057 GMT
The TAL crude pipeline, which supplies refineries in southern Germany, Austria and the Czech Republic, continues to pump at record high levels, with no let-up in the flows expected, the head of the TAL pipeline company said late Monday.
In 2013, a total of 41 million mt (825,000 b/d) of crude flowed through the line, bringing in crude from the Italian port of Trieste to central Europe.
"There is continuous high throughput in TAL -- similar to 2013 -- which is expected to continue," TAL general manager Ulrike Andres told Platts.
The volume pumped through the line last year is close to the pipeline's nominal capacity of 43 million mt/year.
However, Andres said there were "no specific further expansion plans at this moment."
TAL began operating in 1967 and the EU has urged the pipeline operator to look at plans to expand its capacity.
At the end of 2012, TAL said it planned to invest Eur150 million ($195 million) in the pipeline through 2016 "to ensure its long-term and safe operation in the future."
TAL's high volumes resulted from two significant events in late 2012 -- Gunvor restarting the previously idled 100,000 b/d Ingolstadt refinery and the 310,000 b/d MiRo refinery near Karlsruhe stopping use of the French SPSE pipeline in favor of importing all its crude needs through TAL.
In the final quarter of 2012, when Ingolstadt restarted, MiRo upped its purchases and the Czech Republic asked for more crude, throughput hit a then record high of 820,000 b/d.
But a lack of additional capacity meant TAL had to suspend supplies to the Czech Republic for about 10 days in October 2012.
Since then, Czech pipeline operator MERO has bought a 5% stake in the TAL pipeline and Gunvor a 10% stake, meaning they have a say in supplies to their respective refineries.
But if you add together the capacity of the four German refineries (around 900,000 b/d), Austria's entire 208,000 b/d of capacity and most of the Czech Republic's refining capacity, that is a total of around 1.26 million b/d, which TAL cannot meet.
The EU has urged the Czech Republic and Germany to build an interconnector between their oil pipeline networks that would enable the Czechs to import from Baltic Sea import terminals.
--Stuart Elliott, stuart.elliott@platts.com
--Edited by Jonathan Fox, jonathan.fox@platts.com
Legal tussle over Chevron Nigerian oil blocks shifts to Supreme Court
Lagos (Platts)--15Jul2014/654 am EDT/1054 GMT
The legal dispute between two Nigerian oil companies over a bid to purchase a Chevron asset, is continuing after one of them, Brittania-U, filed an appeal with the Nigerian Supreme Court to stop the auction of the oil blocks proceeding further, Brittania's lawyers said Tuesday.
In January, Nigerian independent Seplat Petroleum became the preferred bidder for Chevron's Oil Mining Leases 52, 53 and 55, but the process has yet to be completed due to legal proceedings brought by Brittania-U, which said Chevron had reneged on an agreement entered into by both parties last November, for the transfer of Chevron's 40% equity in the blocks.
Brittania-U's lawyers, Ricky Tarfa and Abiodun Owonikoko, however, said in the court papers said they approached the Supreme Court to overrule an order by a lower court last month, which exempted Nigeria's oil minister and state oil company NNPC from being included in the court case.
"The transactions concerning OMLs 52, 53 and 55 are sub judice and no steps are permissible or lawful to be taken by the minister and NNPC to consent to any adverse transaction or in any other way to prejudice the suit until the suit/appeals relating to same are finally disposed of or the court otherwise directs/orders," the lawyers said.
Seplat Managing Director Austin Avuru told Platts last week that his company remained confident it would win its case.
Brittania-U said in January that it had won the bidding for the assets for at total of $1.015 billion.
The Chevron acreages are believed to be prolific, with one of the blocks, OML 52, estimated to hold over 500 million barrels in reserves, according to official data.
--Staff, newsdesk@platts.com
--Edited by Jonathan Dart, jonathan.dart@platts.com
Qatari Al Shaheen crude oil at discount to Dubai on higher availability, weak demand
Singapore (Platts)--15Jul2014/611 am EDT/1011 GMT
Qatar's medium heavy sour crude oil Al Shaheen is trading at discounts to benchmark Dubai for September-loading cargoes on a combination of weak demand from refiners and increased availability, trading sources said Tuesday.
The grade has traded at discounts as deep as 80 cents/barrel to September cash Dubai assessments, traders said.
It was last assessed at a discount to Dubai on August 15, 2011, at 10 cents/b below Dubai benchmark.
The lower differentials for the grade comes as the Dubai structure has also weakened in recent days, weighed down by ICE Brent crude's recent flip into contango from backwardation.
Traders however, noted the level at which Oman -- a comparative grade to Al Shaheen -- was trading as indicative of weak demand for Al Shaheen itself.
Platts on Monday assessed Oman at a premium of 36 cents/b to Dubai.
"Demand is poor and this month saw eight cargoes in the tender [offered by Qatar's Tasweeq], buyers were quite relaxed," a trader said.
Tasweeq's tender offering the eight cargoes for September loading closed on Monday, and bids are to remain valid until Wednesday.
In contrast, Tasweeq sold five cargoes for August through tender at an average premium of 78 cents/b premium to Dubai.
"Considering Oman price was 20-30 [cents/b over Dubai], the tender price will be much lower than pre-tender [spot sales] levels," he added.
Traders noted China's Unipec as selling a 600,000-barrel cargo of Al Shaheen for September loading at a discount of around 80 cents/b to Dubai.
In addition, grade operator Maersk was heard to have sold two cargoes at starkly different prices.
In unconfirmed trades, one cargo was heard sold at a premium of around 25 cents/b to Dubai, while the other cargo was heard sold at a discount of 55 cents/b to Dubai.
Overall demand for Middle East sour crudes was seen sluggish given months of weak refinery margins and low run rates, hitting requirements for crude from refiners.
"The problem is no refiners in their right mind will rush out [and buy crude]. They will just sit back and wait ... there are run cuts all over the place," a trader said.
For Dubai, the premium of first (September) month and third (November) month cash Dubai has narrowed significantly in recent days, to be assessed at 36 cents/b on Monday, down 23 cents/b from Friday.
Part of the narrowing in the Dubai structure reflects the deepening contango in the ICE Brent crude contract. The spread between August and September contracts was minus 73 cents/b at Monday's settlement.
In contrast, the contract was at a contango of 6 cents/b last week.
As Libyan crude production has come back from being shut in, and blockades on some ports being lifted, this has eased the pressure on the Western crude benchmark, traders noted.
The Al Shaheen field produces around 300,000 b/d and is operated by Maersk under a production sharing contract with Qatar Petroleum.
--Daniel Colover, daniel.colover@platts.com
--Edited by Irene Tang, irene.tang@platts.com
Russia's Gazprom eyes oil, gas exploration JV with Bangladesh's Bapex
Dhaka (Platts)--15Jul2014/633 am EDT/1033 GMT
Russia's state-owned Gazprom is interested in setting up a joint venture with Bangladesh Petroleum Exploration and Production Company, or Bapex, to jointly carry out oil and gas exploration in either of the countries or others, Petrobangla Chairman Hussain Monsur said Tuesday.
Gazprom, which is increasingly more focused on strengthening relations with Asia, currently operates in Bangladesh on a contract basis, as a drilling contractor.
Gazprom International CEO Valeriy Gulev late last week expressed the company's interest during a meeting in Dhaka between Bangladesh Prime Minister Sheikh Hasina and a Gazprom delegation.
The proposed JV between Gazprom and Bangladesh's sole oil and gas exploration company could be used to identify and implement new projects in Bangladesh, Russia or any third countries, the chairman of Bangladesh Oil, Gas & Mineral Corporation, or Petrobangla, said.
The Russian side has expressed its strong interest in this initiative and its readiness to carry out comprehensive analysis and the required consultations at the earliest opportunity, he added. A timeline for setting up the proposed JV was not disclosed.
In addition to carrying out joint exploration onshore and offshore Bangladesh, Gulev also proposed joint exploration for hydrocarbons in Myanmar under the proposed JV, the Bangladesh prime minister's press secretary AKM Shamim Chowdhury said.
Officials said the Gazprom CEO's visit to Bangladesh follows a series of meetings between representatives of both countries on gas exploration.
Bangladesh in September last year sought a $2 billion loan from Russia, at an interest rate of less than 2%, to fund development of its onshore gas fields. It has not received the loan as yet. The funds were for drilling 41 wells -- comprising 13 development, 8 appraisal, 13 workover and 7 exploratory wells -- in the Titas, Bankhrabad, Kamta, Bhola, Horipur, Koilashtila, Biani Bazar, Chittagong and Rashidpur gas fields.
Bangladesh also wanted to build 12 gas processing plants at the fields operated by state-owned Bangladesh Gas Fields Company.
In addition, it was also planning to carry out 2,570 km of 2-D and 3-D seismic surveys in several onshore areas and build 511 km (317 miles) of natural gas pipelines to link fields to domestic markets. It expects these developments, if completed, to increase natural gas output by 1.06 Bcf/d.
In September last year, Gazprom had expressed interest in drilling four new wells -- two in the Shahbazpur gas field and one each in the Haripur and Jaldi gas fields, Monsur said. It was also interested in building a natural gas pipeline from Shahbazpur to Khulna in the south, where there is currently no gas available, he added. There seems to be no progress in most of these plans as yet.
Gazprom is currently carrying out a 10-well drilling program costing around $193.5 million in state-run gas fields owned by three gas subsidiaries of Petrobangla.
Gazprom had produced its first gas in Bangladesh on May 21, 2013, while testing the Srikail-3 onshore well in the Comilla field. Gazprom has completed drilling at seven wells -- Srikail-3, Titas-19, Titas-20, Titas-21, Titas-22, Begumganj-3 and Semutang-6. Drilling work is underway on Shahbazpur-3. Some of these wells are already supplying natural gas to Bangladesh's national gas grid.
Bangladesh is currently grappling with an acute gas crisis, with supply hovering around 2.31 Bcf/d against demand for around 3.0 Bcf/d.
--Mohammad Azizur Rahman, newsdesk@platts.com
--Edited by Geetha Narayanasamy, geetha.narayanasamy@platts.com
Similar stories appear in International Gas Report See more information at http://www.platts.com/Products/internationalgasreport
US shale drillers becoming immune to oil and gas prices: Raymond James
Washington (Platts)--14Jul2014/316 pm EDT/1916 GMT
US exploration and production companies will become the long-promised "factories" with positive cash flow starting this year as growing production efficiencies make them relatively immune to flat commodity prices, investment bank Raymond James said Monday.
"With rising US production and falling costs per unit of production, US E&P companies are now poised to actually grow cash flows even in a flat or modestly lower energy price environment," Raymond James' top oil and gas analyst Marshall Adkins said in a note to clients.
"We now think the US oil and gas business can be viewed as more of a sustainable growth industry rather than a pure commodity call," Adkins said.
After a decade of spending roughly 40% more than it took in in revenues during the shale land grab, E&Ps have driven per barrel and per Mcf costs down to a point where in a flat price environment profits are made by expanding production volumes, Raymond James said.
"In 2013, the over-spending gap closed to only 20% above operating cash flows (versus 60% in 2012)," Adkins said. "More importantly this gap should be relatively nonexistent in 2014 (assuming year-over-year US E&P capex growth of 12.5%). In 2015 and 2016, assuming 7.5% capex growth, we expect E&Ps to actually be cash flow positive despite modestly lower oil and gas prices!"
Getting to positive cash flow in Raymond James' model came early because of the bitter 2014 winter, which boosted natural gas prices at least 16% using the NYMEX strip.
Looking at the same strip, Raymond James projected average natural gas prices will be flat at roughly $4/MMBtu in the next two years, while natural gas liquids and crude oil prices see modest 3-5% declines.
"The reason for the improved capital efficiency is oil and gas volumes have been increasing at a rapid clip," Adkins said. "Initial oil and gas production from three key horizontal plays [Bakken, Eagle Ford, and Marcellus] has increased an incredible 10-fold since 2007."
"The key point is that improved efficiencies have allowed US E&P production per unit of capex to scream higher over the past decade," Adkins said. "We expect this trend to continue over the next few years. That means even in a flat or backwardated commodity price environment, E&P cash flows can still improve."
"We now think E&Ps are capable of growing cash flows solely through volume growth and cost efficiencies and in spite of a backwardated oil curve. This is a massive paradigm shift in the energy sector," Adkins said.
Freed from commodity prices, US E&Ps will obtain stock market multiples in line with manufacturers, Raymond James said, with drillers that currently see stock prices at 5 to 7 times their earnings moving up to multiples of 8 to 10.5 times earnings.
In a separate note to clients, Bernstein Research analyst Bob Brackett said the market is rewarding E&P companies for volume growth first with larger profit margins (lower costs) second.
"We looked at the last four years of equity performance for 49 North American E&Ps and found that above-average production growth and above-average margin expansion yielded 8.4% cumulative annual growth rate returns to share price," Brackett said Monday.
Despite the emphasis on lower costs and increased margins, drilling stocks that have increased production growth with below-average profit margins saw 4.4% gains in value while those with below-average production growth but increased profit margins had their value trimmed 6.3%, Bernstein said.
--Bill Holland, bill.holland@platts.com
By Nidaa Bakhsh and Marco Bertacche Jul 16, 2014 6:00 AM GMT+0700
Former Eni SpA (ENI) Chief Executive Officer Paolo Scaroni promised Italian unions he wouldn’t shut the company’s money-losing oil refineries until 2014. Now the new boss looks ready to wield the ax.
Italy’s biggest oil company has begun negotiations to close as much as half its 774,000 barrel-a-day capacity and put more than 3,500 jobs at risk, according to the industry’s main union, which started a strike at one plant yesterday. Eni’s biggest program of closures would be a radical attempt by new CEO Claudio Descalzi to deal with overcapacity in Europe’s refining sector, where the region’s economic slump and competition from Asia has forced shutdowns and caused bankruptcies.
Descalzi, who headed the profitable exploration and production unit before his promotion in May, will probably get backing, at least tacitly, from his largest shareholder: the Italian government. While closing the plants would cause job losses as unemployment stands at 12.6 percent, Prime Minister Matteo Renzi supports change at state-backed companies and has sought to weaken union power within his Democratic Party.
“Renzi’s message to make companies more efficient is very clear,” said Nicolo Sartori, an energy analyst at Rome’s Institute for International Affairs. “If Eni wants to cut costs and tackle inefficiencies, probably Descalzi will touch” the refining part of the business.
An Eni official declined to comment on any potential closures, saying a new strategic plan that includes the refining and marketing unit will be announced on July 31.
Sicily Plant
Workers are striking at Eni’s Gela plant in Sicily, Filctem-CGIL’s regional secretary-general, Giuseppe D’Aquila, said by phone. Gela may not get a 700 million-euro ($950 million) upgrade, unions said after meeting Descalzi in Rome last week.
Closing the plants would cut Eni’s Italian workforce by about 13 percent, based on data in the company’s fact book.
“Eni’s new CEO may emerge as a male Italian version of Margaret Thatcher by going up against the unions,” analysts at Sanford C. Bernstein & Co. led by Oswald Clint, said in a note. While investors thought plant closures could never happen, “Italian press suggests such a plan is brewing and being discussed with unions, which is remarkable.”
Thatcher’s government sought to reduce union power in the U.K. during the 1980s, forcing through a program of coal-mine closures in the face of a year-long strike.
Export Market
European refiners have struggled to turn a profit as recession curbed demand for fuel, more efficient plants opened in Asia and the Middle East and the boom in U.S. oil production closed a major export market. That led to more than a dozen plants shutting, the biggest wave of closures since the 1980s.
The now-bankrupt Petroplus Holdings AG closed sites across the region after struggling to find buyers, while France’s Total SA (FP) accepted union demands, promising not to shut any sites until next year.
Refining margins are likely to remain weak for the next one to two years, Fitch Ratings Ltd. said in a July 8 note. The agency may downgrade Eni from its A+ rating if its restructuring efforts aren’t successful, it said.
“Refining closures are not a ‘should we’ but a ‘we must’ given declining Italian demand and consistent earnings losses,” Clint wrote. “Eni’s decision to close the refineries is bold but necessary.”
Kuwait Petroleum
Eni told the union at least three of its six refineries were at risk of closing, according to a statement from the labor union last week. It guaranteed continued operations at the 190,000 barrel-a-day Sannazzaro refinery, which got a new diesel-producing unit in 2012, and at Milazzo, a joint venture with Kuwait Petroleum Corp., according to the statement. The two plants represent half of its capacity in the country.
The company said at the meeting it won’t go ahead with investment at Gela, while the Taranto facility, the second stage of the Venice plant conversion, and the chemicals site at Priolo were at risk. The Livorno refinery, with a capacity of 84,000 barrels a day, wasn’t mentioned in the statement.
Eni is 30 percent owned by the state, giving the prime minister power to appoint the CEO. Renzi, Italy’s youngest-ever premier and an advocate of labor-market deregulation, picked a fight with CGIL union leader Susanna Camusso to win party backing for a tax cut for lowincome workers.
“The unions have to understand the music has changed,” Renzi said in a television interview earlier this year.
Loss Deepened
Eni’s refining and marketing division’s loss deepened to 159 million euros in the first quarter from 51 million euros a year earlier. Eni said April 29 it saw “continuing weak conditions” and that it would persist with measures including cost cuts, renegotiation of long-term gas-supply contracts, and capacity restructuring to help support its mid- and downstream businesses.
European refining margins averaged $3.30 a barrel in the first half of 2014, according to Fitch. That compares with $4 a barrel in 2013 and $6.80 a barrel in 2012. Total consumption of fuels in Italy fell 6 percent in May from a year earlier, according to data by the Ministry of Economic Development.
Eni’s six refineries process 774,000 barrels of oil a day, according to data compiled by Bloomberg. That’s about half of Italy’s total capacity. Eni had an agreement with the labor union not to shut Italian refineries permanently until this year, Scaroni said in 2012.
To contact the reporters on this story: Nidaa Bakhsh in London at nbakhsh@bloomberg.net; Marco Bertacche in Milan at mbertacche@bloomberg.net
To contact the editors responsible for this story: Will Kennedy at wkennedy3@bloomberg.net Alex Devine
By Lynn Doan Jul 15, 2014 9:08 PM GMT+0700
Enterprise Products Partners LP (EPD) and Pioneer Natural Resources Co. (PXD), two of the first fuel suppliers to win approval to send U.S. condensates abroad, may be about to get some company.
Less than a month after Enterprise and Pioneer said they received approval to export processed condensate, others are seeking the same permission, said Jacob Dweck, a partner at the law firm Sutherland Asbill & Brennan LLP, who represented Enterprise in its request to the U.S. Commerce Department. Dweck declined to identify the companies or say how many there were. The U.S. has prohibited most crude exports since 1975. Exports of products such as gasoline and diesel are legal.
Condensates are ultra-light hydrocarbons that are gaseous when extracted from oil and natural gas reservoirs. Exports may ease a glut of crude created by a boom in output from hydraulic fracturing and horizontal drilling in shale formations. U.S. crude production rose to 8.5 million barrels a day in the week to July 4, the highest since 1986, according to Energy Information Administration data. Crude stockpiles climbed to a record on the U.S. Gulf Coast earlier this year.
The Commerce Department confirmed that condensate, “once distilled, is no longer crude oil” and can be exported, Dweck said at the 2014 EIA Energy Conference in Washington yesterday.
West Texas Intermediate crude, the U.S. benchmark, climbed as much as 1.4 percent on June 25 after Pioneer and Enterprise said they won approval for the exports. WTI’s discount to European benchmark Brent crude narrowed to $5.49 a barrel on the ICE Futures Europe exchange in London at 9:56 a.m. New York time, from $8.43 a barrel on June 24.
The market overreacted “in viewing these rulings as a significant policy change” by the Obama administration, Dweck said.
‘We Asked’
“The ruling was issued because we asked for it, and we happened to ask first,” he said. The agency “made its decision with a full deck.”
The Commerce Department will probably keep considering requests on a case-by-case basis, Dweck said, because it must study each company’s distillation processes and condensate streams.
“It would be hard to issue guidelines that somehow cover all these condensates and processing methodologies,” he said.
About 750,000 barrels a day of oil produced from U.S. shale plays is condensate, according to Wood Mackenzie Ltd.
Condensate exports from the U.S. may shrink the discount for Light Louisiana Sweet crude in the Gulf Coast by $1 to $2 a barrel versus Brent, John Auers, executive vice president at Turner, Mason & Co., said at the conference yesterday.
“I can’t see, with that kind of environment, that domestic-international discounts can blow out like one time I thought they could have,” Auers said.
Asia will probably be the biggest market for U.S. condensates, Auers said, and South America may want them to blend with heavy bitumen.
To contact the reporter on this story: Lynn Doan in San Francisco at ldoan6@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Richard Stubbe
Ban on Oil Exports Won’t Be Lifted This Year, Upton Says
By Lynn Doan Jul 16, 2014 4:49 AM GMT+0700
A four-decade-old ban on crude exports from the U.S. will survive another year, the chairman of the U.S. House’s Energy and Commerce Committee said.
Federal policy makers need time to decide whether the ban on exporting most crude imposed since 1975 should be lifted, “and that won’t happen this year,” Fred Upton, a Michigan Republican, said at an energy conference in Washington today. The U.S. only allows the shipments of refined products including gasoline and diesel abroad.
Lifting the prohibition on exports would help alleviate a glut of oil building up along the U.S. coasts as hydraulic fracturing and horizontal drilling help producers pull record volumes of crude out of shale formations across the middle of the country. The boom has propelled domestic production to the highest level since 1986 and sent stockpiles of the feedstock to a record on the Gulf Coast earlier this year.
“We need to ask a lot of questions, and I don’t think anyone expects us to move on it this year,” Upton told the 2014 EIA Energy Conference organized by the Energy Information Administration in Washington. “The president of course could do so, but we’re not anticipating any movement this year.”
The House passed legislation last month to expedite the approval of requests to export liquefied natural gas, known as LNG. Upton said he doesn’t know how long it will take for legislature to take up crude exports.
“With LNG, we asked a lot of questions, and we moved it in regular order,” Upton said. “The proof is in the pudding that we ended up with a bipartisan bill.”
Pioneer, Enterprise
Pioneer Natural Resources Ltd. and Enterprise Products Partners LP (EPD) said last month that the U.S. Commerce Department had approved their plans to export ultra-light crude known as condensate. The product is heated in stabilizers and distillation towers which qualifies it as a refined fuel eligible for shipping abroad, they said.
Senator Lisa Murkowski, ranking Republican member of the Senate Energy and Natural Resources Committee, is scheduled to meet tomorrow with Commerce Secretary Penny Pritzker to discuss easing restrictions on oil exports.
U.S. production of crude oil, along with liquids separated from natural gas, surpassed all other countries this year with daily output exceeding 11 million barrels in the first quarter, Bank of America Corp. said in a report July 4. The nation became the world’s largest natural gas producer in 2010.
To contact the reporter on this story: Lynn Doan in San Francisco at ldoan6@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Stephen Cunningham, Richard Stubbe
China's Local Governments Pile On Stimulus Undeterred by $3 Trillion Debt
By Bloomberg News Jul 15, 2014 11:21 AM GMT+0700
China’s regional governments are starting to pull out their own stimulus cards to shore up growth as central authorities limit aid for the economy.
Northern Hebei province, whose 4.2 percent first-quarter expansion pace was less than half that of a year earlier, will invest 1.2 trillion yuan ($193 billion) in areas including railways, energy and housing. Heilongjiang province in the northeast, with 2.9 percent growth that was China’s lowest in the first quarter, will spend more than 300 billion yuan over two years in areas including infrastructure and mining.
Any borrowing to fund the investment risks exacerbating financial dangers from local-government debt that swelled to about $3 trillion as of June 2013. While Premier Li Keqiang is trying to expedite spending from existing budgets and avoid broad stimulus, provinces such as Hebei are facing bigger shortfalls on their own growth goals than the national government, which has a target of about 7.5 percent.
“The motivation is there -- currently GDP is still the key performance indicator for local officials,” said Shen Jianguang, chief Asia economist at Mizuho Securities Asia Ltd. in Hong Kong, who previously worked at the European Central Bank.
Figures today from the People’s Bank of China showed that the broadest measure of financing, new yuan loans and money supply all topped estimates in June, signaling policy makers’ shift toward supporting economic growth over reining in shadow banking.
Growth Steady
The world’s second-largest economy probably expanded 7.4 percent in the April-June period from a year earlier, based on the median estimate of analysts surveyed by Bloomberg News ahead of tomorrow’s report from the National Bureau of Statistics. That would be the same pace as the previous period, which was the weakest in 18 months.
Industrial production may have increased 9 percent in June from a year earlier, up from 8.8 percent in May, economists estimated ahead of data also due tomorrow. First-half growth in fixed-asset investment, excluding rural households, probably maintained the same 17.2 percent pace as in January-to-May.
Li said yesterday that economic growth is in a reasonable range and he’s confident it can remain at a medium-to-high level, according to a central government statement.
“Debt growth can indeed possibly increase risks, but if the economy collapsed, the problem would be even bigger,” said Chang Jian, chief China economist at Barclays Plc in Hong Kong. Authorities are balancing short-term and long-term issues, with the result of “maintaining the current growth pace and gradually paying off the old debts,” Chang said.
Investment Gains
Hebei’s plan is designed to curb an investment slowdown and aid the economy, according to an article in the official Hebei Daily posted June 26 on the central government’s website. The amount would be equivalent to 42 percent of 2013 GDP in the region, where the government is cutting steelmaking capacity.
The article didn’t indicate how much of an increase the 1.2 trillion yuan represents over previous plans. Hebei Daily said the province would strive to complete 450 billion yuan of investment in city infrastructure this year. In 2012, the most recent data available, Hebei’s fixed-asset investment was 272 billion yuan for the categories that include transportation and public facilities.
Oilfield Slump
Heilongjiang’s plan, described in a June 23 government statement, is also aimed at boosting an economy that’s slumped on lower output from a major oilfield. Heilongjiang said it will “step up the construction of important infrastructure projects,” listing 83 billion yuan of railway, road and airport plans over two years. The province’s fixed-asset investment in transportation was 49.9 billion yuan in 2012.
Hebei’s 2014 growth target is 8 percent, while Heilongjiang’s is 8.5 percent.
Neither government specified how it would finance the spending. Heilongjiang said it will open some projects to market bids and make full use of funds from the central and regional governments to support agriculture.
“There is no other way” to fund projects other than through local-government financing vehicles, said Xu Gao, chief economist at Everbright Securities Co. in Beijing. While typical returns are half the cost of financing, indicating “there are certainly risks,” repayment depends ultimately on China’s financial sustainability, which is strong, Xu said.
Another province outlining spending plans is Guangxi in the south, which will spend 630 billion yuan over three years on 166 infrastructure projects, according to a July 4 statement.Home Purchases
Investment spending isn’t the only form of local stimulus. Hohhot in Inner Mongolia province and the eastern city of Jinan have eased home-purchase restrictions amid a nationwide property slump.
The local investment plans are relatively small compared with nationwide totals and it’s hard to judge whether the spending was already planned, Wang Tao, chief China economist at UBS AG in Hong Kong, told reporters in a conference call yesterday.
At the same time, Wang said in a report that “as the most direct way to boost investment and growth, increased investment in infrastructure and public services will be an indispensable part of the policy mix.”
To contact Bloomberg News staff for this story: Xiaoqing Pi in Beijing at xpi1@bloomberg.net; Josh Zhang in Beijing at jzhang185@bloomberg.net
To contact the editors responsible for this story: Chris Anstey at canstey@bloomberg.net Scott Lanman, Greg Ahlstrand
By Dan Murtaugh Jul 15, 2014 8:18 PM GMT+0700
North Dakota, the second-largest oil-producing state in the U.S., expects output to surge through the summer as more benign weather gives roughnecks extra time to work in the field.
Output rose about 3.6 percent to 1.04 million barrels a day in May, the state’s Department of Mineral Resources reported yesterday. It was the largest increase since August.
The growth came even as rain and high winds kept well-completion crews out of the fields for several days during the month. Better summer weather will lead to production growth in the region of 5 to 6 percent a month in June, July and August, said Lynn Helms, director of the state’s Department of Mineral Resources.
“We still expect the big surge to come in June, July and August in terms of completions and some really rapid production increases,” Helms said on a conference call with reporters yesterday.
North Dakota is home to the majority of the Bakken shale formation, an underground layer of oil-and-gas-rich rock. High oil prices and improvements in horizontal drilling and hydraulic fracturing technologies have helped output from the state’s portion of the Bakken rise fivefold over the past five years.
Texas, which extracts more than 3 million barrels a day, is the only state producing more crude. North Dakota pumped more oil than three OPEC member nations in May.
Faster Declines
Shale wells like those in the Bakken tend to have faster declines in output than traditional wells so it’s necessary for crews to bring more and more wells online each month to make up for the drop and keep production growing.
Creating wells in the Bakken is a two-step process. Drillers make horizontal bores along the shale, and then completion teams inject a high-pressure mixture of water, chemicals and sand to create micro-fissures in the rock through which gas and oil can seep. Bad weather can slow the completion process, curbing production growth.
“During most years you’re going to see a certain amount of seasonality, whether it be weather delays due to cold temperatures in the winter, or when spring rolls around and you see high winds,” Jonathan Garrett, an upstream analyst for Wood Mackenzie Ltd., said by phone from Houston. “When you get to June, July and August you’ll see this acceleration that makes up for the dips earlier in the year.”
Global Partners
Bakken oil production will continue to rise to reach 2 million barrels a day, said Eric Slifka, chief executive officer of midstream company Global Partners LP (GLP), which ships Bakken by rail to U.S. East and West Coast refineries.
“Bakken’s got a long way to run in terms of increases,” Slifka said in an interview at the 2014 EIA Energy Conference in Washington yesterday.
About 34 percent of North Dakota’s oil left the state by pipeline and 59 percent by rail in May, according to the state’s pipeline authority. That’s the lowest rail percentage since November 2012.
It costs $9 to $10 a barrel to transport oil by train to East Coast refineries, and $6 to $7 a barrel to ship crude by rail to Washington plants, Tesoro Corp. (TSO) said in a February presentation to investors.
Railed crude competes with foreign imports on tankers, which cost about $1 to $2 a barrel. When foreign prices weaken to smaller premiums to U.S. prices, it becomes less economic to ship by rail.
Pipeline Shift
The premium for European Brent over U.S. West Texas Intermediate averaged $6 to $9 a barrel in the months since February, after averaging $10.65 in 2013 and $17.47 in 2012. Brent’s premium shrank 58 cents to $5.49 at 9:04 a.m. in New York today.
“When you see that Brent-WTI spread narrow, typically you see barrels shift to pipeline and head to more traditional markets than rail,” Justin Kringstad, director of the North Dakota Pipeline Authority, said yesterday on a conference call with reporters.
Bakken oil from North Dakota, priced at Enbridge Inc. (ENB)’s pipeline hub at Clearbrook, Minnesota, strengthened by 5 cents to $7.20 a barrel below WTI yesterday after earlier weakening to the largest discount since Dec. 31.
The discount of Bakken crude priced at the wellhead to Brent, the benchmark for overseas crude shipped to the U.S., was $17.80 a barrel at 7:07 a.m. New York time, according to data compiled by Bloomberg.
To contact the reporter on this story: Dan Murtaugh in Houston at dmurtaugh@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Stephen Cunningham
RIYADH: ARAB NEWS
Published — Wednesday 16 July 2014
Saudi Arabia exported nearly 1.38 billion barrels of oil in the first six months of the current year (2014) that yielded SR565 billion, an economic expert was quoted by the local media.
Local consumption is projected to hit 395 million barrels, or 22 percent of the total production, during the same period, Fahad bin Jumaa told Al-Riyadh Arabic daily.
The figures come at a time when OPEC (Organization of Petroleum Exporting Countries) is poised to shrink its share of the global market for the third consecutive year by 2015 for a number of reasons, including boom of shale oil in the United States despite acceleration of global demand on oil, he said.
OPEC has expected that demand on oil would rebound next year with the acceleration of global economic growth and, accordingly, oil consumption will increase by 1.21 million barrels per day (mbpd) compared to 1.13 mbpd in the current year, the paper said. However, non-OPEC countries will pump an additional of 1.31 mbpd next year.
According to Jumaa, oil prices witnessed record rates in June where Brent grade flew over $114 per barrel and, likewise, price of West Texas oil exceeded $ 106 as a result of political developments in Iraq.
He expected that the third quarter of the current year would witness prices averaging $ 107 and $102 for Brent and West Texas, respectively, due to the advent of summer season and increased local consumption in some of exporting and importing countries.
It is to be recalled that the Saudis exported some 1.17 billion barrels in the first five months 2014, with proceeds amounting to SR472.8 billion. Domestic consumption stood at nearly 317 million barrels or 21 percent of the total output of the same period.
WASHINGTON, DC, July 15
By Nick Snow
OGJ Washington Editor
The US could find its light crude oil production growth stymied if it doesn’t allow more of it to be exported, speakers warned during the US Energy Information Administration’s 2014 energy conference’s first day.
John R. Auers, executive vice-president of Turner, Mason & Co. Consulting Engineers in Dallas, described what he termed “a day of reckoning” during a July 14 morning session. This day would come, he said, when US crude production exceeds refining capacity to a point that prices become so heavily discounted to comparable overseas grades that producers decide not to increase production further.
IHS Vice-Chairman Daniel Yergin agreed. “The rationales for a crude oil export ban are gone, but the ban is still in place,” he said during his luncheon remarks. “We see a risk of a $15-25/bbl domestic light crude discount being locked in during the next couple of years, potentially limiting additional investment.”
During the crude export discussion in which Auers participated, Jason Bordoff, who directs the Center on Global Energy Policy at Columbia University’s School of International and Public Affairs, said, “Many people are concerned that if more US crude exports aren’t allowed, refineries will be so overwhelmed with domestic light crude that they’ll deeply discount the prices they’re willing to pay. This is a matter of crude quality, not adequate supplies like LNG exports. Recent experience suggests a lot of the US crude oil production growth forecasts have been conservative. We’re learning more as we produce more.”
Mixed message
Yergin maintained, “Lifting the ban on crude oil exports would signal the US government’s commitment to global markets and energy security. The US has preached to other countries for decades about the need for free flow of resources. How can we say to Japan that it can’t import any of our LNG but must not buy Iran’s oil?”
Meanwhile, US petroleum product exports have surged in recent years because they are not restricted. Questions arose over what constitutes a petroleum product after the US Department of Commerce’s Bureau of Industry and Security (BIS) gave Pioneer Natural Resources Co. and Enterprise Products Partners LP (EPP) permission on June 24 to export condensates (OGJ Online, June 25, 2014).
US Sen. Edward J. Markey (D-Mass.) characterized condensate as “ultralight crude oil” a day later and said the BIS approvals should not have been granted before Congress revised the crude export ban and allowed public comment. US Sen. Lisa Murkowski (R-Alas.) said on July 9 that DOC should align itself with other federal agencies and departments’ treatment of condensate, and allow more of it to be exported.
“Any solutions to the crude export paradigm must be implemented through laws and statutes,” said a third member of the EIA conference’s crude export panel, Jacob Dweck, a partner at Sutherland, Absill & Brennan in Washington who represented EPP before the agency. “By law, BIS must operate under strict confidentiality. But while its rulings are confidential, they can be relied upon by any exporter.”
Its decision that condensate is a product eligible to be exported apparently is based on an idea that crude becomes a product once it’s processed through distillation towers, Bordoff suggested. Continuing the crude export ban doesn’t make sense because the US has spent decades fighting resource nationalism in other countries and promoting free trade, he said.
Targeted investments
“The Saudis have been pricing their crude for US customers below what they might get in the Far East because they want to stay in the US market,” said Auers. “Industry is already making significant investments—mostly in refineries, but also midstream and upstream—to handle specific crudes.”
Many of these outlays will be for facilities with immediate paybacks so problems can be solved quickly, Auers said. A 100 million b/d distillate hydroskimmer costing $600 million isn’t as expensive as a light crude refining unit with more capacity, Auers said.
Yergin noted, “Because of regulatory uncertainty, people are building toppers and splitters, but they’re not spending a lot of money on them because they don’t want to possibly be stuck with surplus equipment.”
Antoine Halff, who heads the International Energy Agency’s Oil Industry and Markets Division, said IEA’s latest midterm Oil Market Report found trade shifting from crude to products globally. It forecasts “a very dramatic refining transformation in the next 5 years” with “very significant growth in Asia, particularly east of Suez, and relatively minor growth in Latin America,” he said during an afternoon discussion of changing global product market flows at the EIA conference.
“We expect 95% of this growth to come outside the US,” Halff said. “It will increasingly compete not just with its weak European partners, but also with exports from India and the Middle East. We also expect overcapacity as oil products compete increasingly with products like biofuels and [natural gas liquids] that bypass refineries.”
Contact Nick Snow at nicks@pennwell.com.
WASHINGTON, DC, July 15
By Nick Snow
OGJ Washington Editor
US refiners continue to respond to a changed competitive environment with additional investments and aggressive oil product export deals, speakers said during the US Energy Information Administration’s 2014 energy conference’s opening day.
Flat US demand has made exports more attractive, but feedstocks and regulations continue to matter, “and the industry is deintegrating,” Joanne M. Shore, chief industry analyst at the American Fuel & Petrochemical Manufacturers, said during a July 14 session on changing global product trade flows.
“Our surplus has allowed the US to change from a net product importer to a net exporter,” Shore said. “Rail has been a tremendous boon in moving crude to refineries. So have pipelines.”
Not every US refinery has access to discounted crude, Shore said. Plants in the Midwest and Rocky Mountains have ample supplies, but situations for East Coast, Gulf Coast, and West Coast refineries have not changed much, she said.
Russian competition
US refiners should expect competition as other countries also plan to increase product exports, according to a second panelist, Antoine Halff, who heads the International Energy Agency’s Oil Industry and Markets Division.
“We see a very large increase in Atlantic Basin product trade,” Halff said, adding, “European demand is contracting, but its refining capacity is contracting faster.” Looking forward, IEA sees major growth in Russian product exports to Europe—largely residual and bunker fuel now, but growing into other products—competing with US refiners.
A third panelist, Terrence S. Higgins, executive director of global refining and special projects at Hart Energy, said condensate and NGL exports have grown more quickly worldwide than other products.
“The future in the export market is in the distillate streams,” he observed. “Gasoline won’t be as strong.” Higgins also said he sees a need for US refiners to export 250,000-300,000 b/d of naphtha by 2020. “There is a home for it: Asia, which is increasing its stream cracker capacity,” he said.
Higgins also said decisions to build more refining capacity in the Middle East and Latin America could be made for social, as well as economic, reasons.
Shore said most US refiners use a mixture of heavy, medium, and light crude. “We’re seeing more capacity to use light sweet crude,” she said. As for US light, sweet crude production possibly exceeding US capacity to refine it sometime soon, which speakers at the EIA conference raised earlier that day (OGJ Online, July 15, 2014), the AFPM official declared: “We’re not at the day of reckoning yet.”
Contact Nick Snow at nicks@pennwell.com.
HOUSTON, July 14
07/14/2014
By OGJ editors
Iran’s Pars Oil & Gas Co. (POGC) reported that construction on Phases 15 and 16 at its third gas processing plant serving South Pars gas field has reach 95% completion. The plant will come online in August, POGC said.
The three-plant complex processes sour gas from Phases 6, 7, and 8 of the gas field. The first and second plants of Phases 15 and 16 are to process 25 million cu m/day of sour gas while the third plant is undergoing precommissioning.
POGC said the three gas processing plants will process at least 40 million cu m/d of gas in winter.
Development of South Pars gas field Phases 15 and 16 aims at producing 56.6 million cu m/day of gas, 75,000 b/d of condensate, and 400 tons/day of sulfur, POGC said. The two phases also will yield 1.05 million tons/day of LPG, propane, and butane as well as 1 million tons/day of ethane mainly for use as petrochemical plant feedstock.
Offshore and onshore installations of the two phases include two drilling platforms (each with 11 wells), two 32-in., and two 71-mile, 4-in. gas pipelines, along with sweetening and related services.
HOUSTON, July 15
By Rachael Seeley
OGJ Special Projects
North Dakota production continued to climb in May but new requirements in the state’s flaring reduction plan slowed permitting activity in June and may lead to production curtailments for some operators early next year.
About 75% of permit applications required an extra 2-7 days of processing time while the state contacted operators to obtain additional information on gas processing plans, Lynn Helms, director, North Dakota Department of Mineral Resources, told reporters during a July 14 conference call.
“At least 75% of the permits are missing one or more pieces of information,” Helms said.
The state began requiring operators to submit gas capture plans with permit applications on June 1. Plans include information on area gas-gathering system connections and processing plants; the rate and duration of planned flowback; current system capacity; a timeline for connecting the well; and a signed affidavit verifying that the plan has been shared with area midstream companies.
The next deadline for the flaring reduction plan is fast approaching. The state expects to capture 74% of gas production by Oct. 1, rising to 90% by Oct. 1, 2020 (OGJ Online, July 2, 2014).Operators will submit their October production numbers to the state on Dec. 1 and those that fail to capture and utilize at least 74% of gas production can expect to receive letters from the in December.
“There will be operators who likely will receive letters in December saying ‘In January, you have to curtail production at a list of wells,’” Helms said.
About 72% of statewide gas production was captured in May. The remaining 28% was flared.
The implementation of the flaring reduction policy has not yet impacted production. The state’s Department of Mineral Resources reported July 14 that oil production rose 3.6% to 1.04 million b/d in May—the largest production increase since August. Gas production increased 8.5% to 1.19 bcfd.
North Dakota recently surpassed Alaska to become the second-largest oil-producing state in the US.
The statewide rig count held steady at 191, but completion work was slowed by heavy rains and windstorms near Dickinson and Minot in Stark and Ward counties, respectively. The number of wells awaiting completion increased by 10 to 610.
A surge in completion activity is expected in coming months as operators work to clear backlogs before winter. This should result in production growth of 5-6% in June, July, and August.
Concerns addressed
The state will conduct a meeting with operators next week to answer questions regarding the enforcement of the flaring policy, Helms said. A list of about 60 questions has been compiled so far. “It appears their number one concern is outages on the part of [gas] gatherers and midstream companies that they don’t have any control over,” Helms said.
One large midstream company plans to temporarily take offline compressor plants across southern North Dakota in coming weeks as it works to upgrade their capacity. The rolling maintenance is expected to occur during a 45-day period.
“That’s going to result in some increased flaring and [operators] are very concerned,” Helms said.
The North Dakota Industrial Commission has not revealed how it will respond to the increased flaring but, Helms said, the state will be selective about granting exemptions.
“This policy is only going to make a difference if we’re very strict about granting exceptions to it,” he said.
Contact Rachael Seeley at rachaels@ogjonline.com.
by Kostis Geropoulos
15.07.2014 - 21:09
The period of strong growth in Russian oil production is over and the country is likely to try to sustain its current production levels of 10.5 million barrels per day for the years to come.
Russia is pumping at near capacity with western Siberia still accounting for the bulk of Russia’s total crude output.
Russian oil and gas condensate output reversed a downward trend in June, rising 0.2% from May to 10.55 million barrels per day, thanks to privately owned firms LUKoil and Bashneft, Russian Energy Ministry data showed.
Chris Weafer, founding partner of Macro-Advisory, a Moscow-based business and investment consulting group, told New Europe that Russian oil output is still up year-on-year.
“There’s still growth in production, except the pace of growth has slowed down. So we are coming in to a period where we will see more stable production rather than continuously rising production. But there are new fields in East Siberia that are being developed,” Weafer said, mentioning LUKoil.
Russian oil production has been rising steadily for many years, Weafer said. “We now entered a period where we can see more stability,” he said. “Production might be volatile within maybe 100,000 to 200,000 barrels per day. But I don’t see any significant change either on the increase or on the decrease,” Weafer said, forecasting a stable production of about 10.4 million barrels a day for the next several years as some fields step up under early stage development which should be available to compensate for the brown fields around that time.
He reminded that Russian President Vladimir Putin has given a very specific order that Russia was to sustain at least 10 million barrels of oil per day for at least the next 10 years for economic reasons as well as geopolitical reasons. “So there is no incentive to ratchet up to 11 million barrels or something like that. But we don’t have any concerns about production falling towards 10 million or below that,” Weafer said. “But the period of strong growth that’s definitely over because all those fields are now in production,” he added.
Weafer also said that there would be enough oil from the fields in East Siberia for exports through the Eastern Siberia–Pacific Ocean oil pipeline (ESPO ). He noted, however, that there might be some diversion of Russian oil flow from the west to the east. “Oil going east instead of into Novorossiysk because Kazakhstan is quite likely to want to pump some extra oil from the Kashagan field - whenever it finally starts - up to Novorossiysk. Obviously the Bosporus capacity is pretty much full.
He said that Russia may fulfill its commitments and strategy to send more oil to the East Pacific by taking oil out of Novorossiysk for that pipeline. “But then that capacity in Novorossiysk and then the Bosporus would likely be taken up by Kazakhstan and the Kashagan field,” Weafer said.
Shale Revolution Will Go Global, Analyst Says
By Randy Leonard Posted at 2:53 p.m. on July 15, 2014
British Prime Minister David Cameron visits the Total Oil Depot shale drilling site in Gainsborough, Lincolnshire, on Jan. 13.
A new era of global oil and gas production will emerge as other countries adopt the technology that has led to a shale boom in the United States, according to an industry researcher.
“This is not just a U.S. play,” said Jamie Webster, a director at research firm IHS, speaking at an Energy Information Administration conference Monday. “In the future you are going to see tight oil production become more global.”
While a number of factors allowed the United States to lead the hydro-fracturing revolution, other nations will catch on, working through barriers such as the lack of mineral property rights in some countries, he said.
The global rate of shale oil production is expected to increase to about 8 million barrels per day around 2032, about seven years after a peak in the United States, and then taper through 2040, according to recent analysis from his group.
While conventional oil will continue to prove the majority of global supply in coming years, the ability of shale producers to readily respond to price increases will be pronounced, offering the type of market valve that the Organization of Petroleum Producing Counties has controlled for decades, Webster said.
“This actually has the potential to dramatically change how the market is balanced going forward,” he said.
The result could lessen OPEC control or could lead to greater market volatility, depending on how OPEC responds, he said, adding that global tight oil development will also bring global security implications, export balance changes and new electric production potential.
An Economist Group Business. Copyright ©2014 CQ-Roll Call, Inc. All right reserved
SANTIAGO, July 15 Tue Jul 15, 2014 1:10pm EDT
(Reuters) - Chile's state oil company ENAP said on Tuesday it would start using U.S. shale gas during the first half of 2016 via an ongoing supply contract with Britain's BG Group Plc.
Energy Minister Maximo Pacheco was quoted by local media last week as saying that ENAP had signed a long-term deal with Centrica-owned British Gas, Britain's largest energy supplier, to import shale gas from the United States at the end of next year.
ENAP, in a statement on Tuesday, specified that it is oil and gas firm BG Group that "will be in conditions to supply the fuel once the (U.S. LNG) Sabine Pass terminal starts operating at the end of 2015 or beginning of 2016."
The company said a potential future arrival of U.S. shale gas could diversify Chile's liquefied natural gas supplies and added that it can be imported without tariffs, thanks to the free trade agreement between the two countries.
BG Group has long-running LNG contracts with the Andean country's Endesa Chile, local natural gas distributor Metrogas and ENAP.
A surge in shale gas production in the United States is transforming the global energy market. Once a regular LNG importer, the United States is now set to export significant volumes by the end of the decade. Chile, the leading copper producer, has long viewed gas as a way to alleviate a looming power crunch.
(Reporting by Fabian Cambero; Writing by Alexandra Ulmer; Editing by Dan Grebler)
MEXICO CITY, July 15 Tue Jul 15, 2014 3:07pm EDT
(Reuters) - Mexican Senate committees gave approval on Tuesday to a law at the heart of a package that will implement the opening of the oil and gas industry to outside investment.
The Senate committees passed the hydrocarbons law, which sets out key elements of the energy reform, including contracts, fines and the ownership of Mexican oil and gas.
The legislation is part of the package of regulations known as secondary laws, which are meant to flesh out an historic overhaul of Mexico's oil and gas sector.
The committees will also vote on other aspects of the secondary laws, which will then pass on to the Senate for a vote, and from there to the lower house of Congress.
Pledging to reverse a decade of falling oil and gas output, President Enrique Pena Nieto pushed through a reform in December 2013 ending state oil company Pemex's 75-year oil and gas monopoly, and opening the industry up to private capital. (Reporting by Elinor Comlay and Noe Torres. Editing by Andre Grenon)
NEW YORK Mon Jul 14, 2014 1:31pm EDT
(Reuters) - U.S. oil production from the fastest-growing shale plays is set to rise by some 72,000 barrels per day (bpd) in August, according to Energy Information Administration data issued on Monday.
Bakken oil production for August will rise by about 17,000 bpd to 1.11 million bpd compared to the month prior, according to the EIA's drilling productivity report. Meanwhile, south Texas Eagle Ford shale production will increase 25,000 bpd to 1.45 million bpd.
Production from the Permian Basin in West Texas and New Mexico should increase 30,000 bpd to 1.63 million bpd.
Meanwhile, gas production in the major shale plays will rise 0.425 billion cubic feet per day month-over-month in August, from 39.7 bcfd to 40.1 bcfd.
Gas production increases were driven by output from the Marcellus shale centered under Pennsylvania, which will rise to 15.5 bcfd from 15.2 bcfd in July, EIA data showed.
Haynesville gas production will hold at about 6.7 bcfd and Eagle Ford will rise to 6.5 bcfd from 6.4 bcfd in July.
The report is based on drilling rigs data and estimates of changes in production from existing wells. Oil output figures include condensate production.
(Reporting By Catherine Ngai and Scott DiSavino; Editing by Tom Brown)
WASHINGTON, July 14 Mon Jul 14, 2014 11:58am EDT
(Reuters) - The head of the International Energy Agency urged U.S. policymakers on Monday to look closely at their country's low gasoline taxes, saying that the resulting cheap prices may lead to fuel squandering even in the midst of a drilling boom.
"From a global perspective, I urge you to take a hard look," said Maria van der Hoeven, the head of the Paris-based IEA, the energy watchdog for developed countries.
"You may find that with your tax structure on gasoline, you ... may be encouraging wasteful consumption," she said at a conference held by the Energy Information Administration, the statistics arm of the U.S. Energy Department.
The United States has the lowest gasoline prices in the IEA, which has 29 country members, with taxes making up about 15 percent of that price. In comparison, taxes account for 60 percent of the cost of motor fuel in many European countries including Norway, the Netherlands and Italy, according to the IEA.
Van der Hoeven did not call for a U.S. gasoline tax hike. She said such increases are a tough sell in Washington, particularly ahead of congressional elections in November, and noted that the Obama administration has pushed through advances in vehicle fuel economy.
But the United States and other consuming countries must "challenge ourselves with tough questions" in times of abundance, she said.
Thanks to hydraulic fracturing and other technologies, the United States has already become the world's top natural gas producer and is on track to take the same spot in oil output.
But IEA forecasts show production of U.S. light oil reaching a plateau next decade. And violence in Iraq, home to some of the world's most abundant and inexpensively-produced oil, is making long-term investment decisions there "an exceedingly difficult task," she said. (Reporting by Timothy Gardner; Editing by Paul Simao)
WASHINGTON, July 14 Mon Jul 14, 2014 11:58am EDT
(Reuters) - The head of the International Energy Agency urged U.S. policymakers on Monday to look closely at their country's low gasoline taxes, saying that the resulting cheap prices may lead to fuel squandering even in the midst of a drilling boom.
"From a global perspective, I urge you to take a hard look," said Maria van der Hoeven, the head of the Paris-based IEA, the energy watchdog for developed countries.
"You may find that with your tax structure on gasoline, you ... may be encouraging wasteful consumption," she said at a conference held by the Energy Information Administration, the statistics arm of the U.S. Energy Department.
The United States has the lowest gasoline prices in the IEA, which has 29 country members, with taxes making up about 15 percent of that price. In comparison, taxes account for 60 percent of the cost of motor fuel in many European countries including Norway, the Netherlands and Italy, according to the IEA.
Van der Hoeven did not call for a U.S. gasoline tax hike. She said such increases are a tough sell in Washington, particularly ahead of congressional elections in November, and noted that the Obama administration has pushed through advances in vehicle fuel economy.
But the United States and other consuming countries must "challenge ourselves with tough questions" in times of abundance, she said.
Thanks to hydraulic fracturing and other technologies, the United States has already become the world's top natural gas producer and is on track to take the same spot in oil output.
But IEA forecasts show production of U.S. light oil reaching a plateau next decade. And violence in Iraq, home to some of the world's most abundant and inexpensively-produced oil, is making long-term investment decisions there "an exceedingly difficult task," she said. (Reporting by Timothy Gardner; Editing by Paul Simao)
By Judy Hua and Chen Aizhu
BEIJING Mon Jul 14, 2014 2:21am EDT
(Reuters) - China and the United States have signed a preliminary agreement to cooperate on strategic petroleum reserves (SPR), China's National Energy Administration (NEA) said, marking the first such effort between the world's top two oil consumers.
Under the agreement, the U.S. Energy Department and NEA will share information on technical, management and policy issues related to oil stockpiles, the Energy Department said in a statement on Friday.
The pact was forged during a visit to Beijing this week by U.S. Energy Secretary Ernest Moniz with NEA head Wu Xinxiong, the NEA said on its website late on Thursday.
The agencies will hold annual technical meetings held alternately in each of the two countries.
"These activities will allow the two countries to understand each other’s systems and decision-making, which will facilitate effective response to disruptions in the global petroleum supply," the Energy Department said.
Ensuring a sufficient emergency oil stockpile means more to China after it surpassed the United States late last year as the world's largest net oil importer. Overseas purchases help meet around 57 percent of China's total crude oil requirement.
The International Energy Agency (IEA), the energy watchdog for developed nations, has long pushed for China to be more transparent in sharing its stockpile data, even though China is not an IEA member.
China aims to eventually meet the OECD standard of stockpiling enough to cover 90 days of net oil imports.
By the end of 2013, China had a total of 141 million barrels reserve space, a research arm of the country's top oil and gas producer CNPC estimated in January, which would be equivalent to about 22 days of the country's net oil imports.
China filled its first batch of SPR tanks totaling 102 million barrels by early 2009 and began building phase-two tanks later in the same year.
China finished construction of two reserve bases for the second phase - Lanzhou and Dushanzi in landlocked northwest - in late 2011 and pumped oil into them in the first half of 2012, industry sources have said.
Beijing has not disclosed second-phase details such as location, individual capacity, investment or construction schedule. Both the government and oil firms have guarded the details on stock levels amid worries that giving away data would put China at a disadvantage in the market.
In the first half of 2014, Chinese crude imports rose 10.2 percent versus a year earlier, more than double the rate in 2013 despite subdued demand growth for oil. Analysts have said such high imports could suggest stockpiling in commercial storages or even SPR tanks.
Barclays predicted in May that China could add up to a total of 58 million barrels this year of new SPR capacity.
(Reporting by Judy Hua and Chen Aizhu; Additional reporting by Ayesha Rascoe in Washington; Editing by Himani Sarkar and Bernadette Baum)
