OPEC Pumps Least Crude in More Than 2 Years as Saudi Cuts

OPEC reduced crude production in November to the lowest level in more than two years as output dropped below the organization’s 30 million barrel-a-day ceiling for a third month.

The Organization of Petroleum Exporting Countries pumped 29.63 million barrels last month compared with 29.83 million in October, OPEC said in its monthly oil market report today, citing data from secondary sources. That’s the lowest since May 2011. The group decided to maintain its output limit of 30 million at a meeting in Vienna last week because members were “all satisfied,” Ali al-Naimi, Saudi Arabia’s oil minister, told reporters on Dec. 4.

“In taking this decision, member countries reconfirmed their readiness to promptly respond to unforeseen developments that could have an adverse impact on an orderly and balanced oil market,” OPEC said in today’s report.

Analysts at banks including BNP Paribas SA, Citigroup Inc. and Deutsche Bank AG predict that some members of OPEC, notably Saudi Arabia, will probably need to reduce output in 2014 to prevent a global glut. The U.S. is producing the most oil in a quarter-century, while Iraq, Libya and Iran have said they plan to increase exports in the next several months.

Libyan Ports

Today’s OPEC report was published before the head of Libya’s Petroleum Facilities Guard, Brigadier Idris Bukhamada, said that three oil ports in eastern Libya will reopen on Dec. 15. The Al Magharba tribe, which held a meeting today, forced former PFG leaders to lift their blockade, Bukhamada said by phone from Ajdabiya. The ports, including Es Sider, the largest, had been closed since late July.

Output from Saudi Arabia, OPEC’s biggest producer, fell to a five-month low of 9.63 million barrels a day last month from 9.71 million in October, according to OPEC’s monthly report. Production also dropped in Libya, Nigeria, the United Arab Emirates, Algeria, and Kuwait, while supplies climbed in Iraq, Iran, and Angola.

“Downside risks to the oil price may require OPEC to cut production to defend oil prices,”Michael Lewis, head of commodities research at Deutsche Bank in London, said in an e-mailed report today. “Given our upbeat outlook for world growth we would view any attempt by OPEC to defend the oil price as likely to be successful.”

Brent crude for delivery in January fell 17 cents to $109.22 a barrel at 1:49 p.m. in London on the ICE Futures Europe exchange, after rising as much as $1.06 earlier today, before the news on Libyan ports emerged. The North Sea grade, which is the benchmark for more than half the world’s oil, has dropped 1.7 percent in 2013.

Spread Narrows

OPEC has pumped below its 30 million barrel-a-day target since September, reports for this month and last showed.

The spread between U.S. West Texas Intermediate and Brent crudes will narrow in the coming year, according to the group. “As additional pipeline capacity to the U.S. Gulf coast becomes available,” a glut will ease at WTI’s delivery point in Cushing, Oklahoma, OPEC said. The gap traded at about $10.81 a barrel today after narrowing from $19.01 on Nov. 27, the widest on a closing basis in eight months.

World oil consumption is expected to gain by 1 million barrels a day next year to 90.84 million barrels, according to the report, little changed from last month’s estimate. Demand for OPEC’s crude is forecast to drop to 29.6 million barrels a day, or a decline of 300,000 barrels from this year.

Production from nations outside of OPEC will increase 1.2 million barrels a day next year to average 55.32 million barrels a day, with gains from the U.S., Canada and Russia, OPEC said. That’s little changed from last month’s estimate.

The International Energy Agency, the Paris-based adviser to oil-consuming nations, will release its monthly report tomorrow.

OPEC’s 12 members are Algeria, Angola, Ecuador, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the U.A.E. and Venezuela.

Fracking puts U.S. first in shale gas production

The United States, followed by Canada, leads the world in producing natural gas from shale formations as the controversial practice of fracking spreads, the U.S. government reports Wednesday.

Shale gas accounted for 39% of all natural gas produced last year in the United States, compared to 15% of that in Canada and less than 1% in China, according to data from the Energy Information Administration, the statistical arm of the Department of Energy.

"There's no commercially-viable shale gas production outside the United States and Canada," although about a dozen other countries have done exploratory testing, says Aloulou Fawzi, an EIA industry economist. He says China's production, as estimated by independent Chinese energy analysts, is quite small in comparison.

The main reason for the recent U.S. boom in natural gas production -- up more than a third since 2005 -- is the cost-effective combination of horizontal drilling and hydraulic fracturing or fracking. This process typically blasts huge quantities of water, mixed with sand and chemicals, underground to break apart rock and allow the natural gas to flow from the shale into the well.

Many environmentalists oppose fracking, because it can use a lot of water in parched areas, create waste water, trigger small earthquakes and contaminate groundwater. They also worry that the low cost of natural gas reduces demand for carbon-free renewable energy sources such as solar and wind.

Natural gas is already cutting into the share of U.S. electricity provided by coal-fired power plants, which has fallen from 53% in 1993 to 42% in 2011. During that period, EIA says natural gas' share nearly doubled -- from 13% to 25% -- and is projected to hit 30% by 2040.

The agency expects U.S. natural gas production will increase 44% between 2011 and 2040, saying almost all this growth will be due to shale gas. Yet It says there are long-term uncertainties about the productivity of shale formations, because many are so large that only limited portions have been widely tested for production.

Fracking has brought economic revival to areas with the largest shale formations, including the Barnett in central Texas, the Eagle Ford in southern Texas, the Bakken in North Dakota and the Marcellus in Pennsylvania and several neighboring states.

Earlier this week, the agency attributed part of the recent U.S. decline in heat-trapping carbon dioxide emissions to the nation's switch from coal to natural gas, which emits about half as much CO2 as coal per unit of electricity.

Something Big Happened Last Month for first time nearly two decades (US CRUDE OIL NET IMPORTS)

 © 2013, US Energy Information Agency.

Brazil's Giant Libra pre-salt oil discovery: Shell, Petrobras, Total, CNPC and CNOOC won Sharing Contract.

A consortium of companies, including Royal Dutch Shell plc (“Shell”), Petrobras, Total, CNPC and CNOOC, won today a 35-year production sharing contract to develop the giant Libra pre-salt oil discovery located in the Santos Basin, offshore Brazil. The Brazilian regulator, Agência Nacional do Petróleo (ANP), estimates Libra’s recoverable resources of between 8 to 12 billion barrels of oil.

“The Libra oil discovery in Brazil is one of the largest deep water oil accumulations in the world. We look forward to applying Shell’s global deep water experience and technology, to support the profitable development of this exciting opportunity,” said Peter Voser, Chief Executive Officer, Royal Dutch Shell.

Shell holds 20% in the consortium, with Petrobras 40% as operator, Total 20%, CNPC 10% and CNOOC 10%. The consortium will work together in an integrated fashion to support Petrobras, the most experienced operator in the Brazilian pre-salt, and will incorporate each company’s deep water skills, people and technology for the success of the venture.

“Libra offers a unique opportunity to participate in the development of a super-giant deep-offshore oil discovery with strategic partners. Reinforcing our position in the pre-salt Santos basin strengthens and diversifies our upstream portfolio and fits with our strategy to sustain post-2017 production over the next decade. We look forward to participating in the development of these vast resources, and we are confident that the combined deep-offshore expertise represented within the consortium will be a valuable contribution to the growth of Brazil’s oil and gas production”, said Christophe de Margerie, Chairman and Chief Executive Officer of Total.

The production sharing contract is expected to be signed in November 2013. As part of the winning bid, Shell will pay its 20-percent share of the total signing bonus of USD $1.4 billion [3.0 billion reais], and fulfill the minimum work program no later than end 2017.

The ultra-deep water Libra accumulation is located in Santos Basin, approximately 170 kilometers (105 miles) off the coast of Rio de Janeiro. The block covers approximately 1,550 square kilometers in water depths of around 2,000 meters (6,500 feet). The reservoir depth is around 3,500 meters below the sea floor (11,500 feet). The ANP estimates that total gross peak oil production could reach 1.4 million barrels per day. Further appraisal is required to firm up this estimate, the development concept and a first oil date.

Brazil: A massive oil discovery offshore in Sergipe.

Brazil's government will announce a massive oil discovery off the country's northeast coast later this month, according to acting Sergipe state Gov. Jackson Barreto.

Mines and Energy Minister Edison Lobao will travel to Sergipe's capital, Aracaju, on Oct. 23 to officially announce "the world's largest oil discovery of 2013," Mr. Barreto told Sergipe state's official news agency Friday. The event is also expected to include Magda Chambriard, director of the country's National Petroleum Agency, or ANP, Mr. Barreto said.

The two government agencies, however, downplayed prospects for an announcement. The Mines and Energy Ministry could not confirm Mr. Lobao's visit. In a statement, the ministry added that it "has no knowledge of any new oil discovery in the country other than those already announced by Petrobras."

The ANP, meanwhile, said that Ms. Chambriard would visit Sergipe on Oct. 23 to discuss the upcoming 12th-round auction of oil and natural gas exploration blocks. Ms. Chambriard's visit, though, was not related to any impending announcement of a major oil discovery, a spokeswoman said.

Last week, Brazilian state-run oil company Petroleo Brasileiro (PBR, PETR4.BR), or Petrobras, confirmed it had made a "relevant" discovery off Sergipe's coast that would start production of 100,000 barrels a day in 2018, Chief Executive Maria das Gracas Foster said. The executive declined to give any volume estimates for the oil fields.

Petrobras first announced a series of discoveries in late 2012, saying the finds had opened a "new oil frontier" in the country. The discoveries are closer to shore and could be much cheaper to develop than larger oil fields, known as the presalt, found buried under a thick layer of salt deep under water off Brazil's southeast coast. Billions of barrels of crude have been discovered in the region, and the government plans to auction off a field there known as Libra under new production-sharing agreements later this month. Libra is estimated to hold recoverable reserves of between 8 billion and 12 billion barrels of oil.

The Sergipe discoveries have geologists rethinking their models of the area, where the unexplored shallow-water areas of what's known as the Sergipe-Alagoas Basin were thought to hold between 500 million and 1.5 billion barrels of recoverable reserves. Petrobras's discoveries were made in water 2,500 meters deep.

Petrobras operates the exploration blocks containing the new discoveries with a 60% stake. The remaining 40% stake belongs to IBV-Brasil, a joint venture between Indian companies Bharat Petroleum Corp. (500547.BY) and Videocon Industries Ltd. (511389.BY).

Brazil's state-led oil company, Petroleo Brasileiro SA, and its Indian partners have made a "beautiful" oil discovery off Brazil's northeast coast and it will produce a minimum 100,000 barrels of petroleum a day starting in 2018, the company's chief executive officer said on Friday.

Maria das Graças Foster, the chief executive, declined to say how big the discovery is but said it was an important new oil "province" for Brazil and that its large potential reserves would create a rush of jobs and activity to the area that will need to be managed carefully.

On Thursday, Reuters exclusively reported that the discovery, centered on the SEAL-11 offshore exploration block, likely holds more than 1 billion barrels of oil and that the region will soon become Brazil's biggest new oil frontier.

The SEAL-11 block is 60 percent-owned by Petrobras and 40 percent-owned by IBV Brasil, a 50-50 joint venture between India's Bharat Petroleum Corp (BPCL) and Videocon Industries Ltd.

"In 2008 we decided to do a very extensive investigation of the area, and the results we have got have been very good," Foster told reporters at company headquarters in Rio de Janeiro. "This is a beautiful discovery, beautiful discoveries."

In addition to light, high-quality crude oil, the region has important quantities of gas, she added.

Two prospects in the area, known as Farfan and Muriu, are expected to be developed as a single or integrated unit, with at least one floating production, storage and offloading ship (FPSO) producing oil and gas from the area in 2018, Foster said.

Foster said that was the minimum outlook for the area based on spending in the company's $237 billion 2013-2017 investment plan drawn up before the latest drilling and tests in the area.

If confirmed, the new find could make the region the country's biggest new oil frontier since the government unveiled the massive subsalt discoveries off the coast of Rio de Janeiro and Sao Paulo states in 2007.

REFINERY PLANS

Foster also said that Petrobras is totally reforming its plans to build two low-sulfur diesel refineries in Brazil's northeast. The so-called premium refineries planned for the states of Maranhao and Ceara were showing signs they would not be profitable.

The Maranhao refinery is expected to cost about $20 billion to build.

Petrobras, however, has reworked the projects with the help of U.S. based consultants, Foster said, and those projects are now looking stronger. The company hopes to start putting the refineries out to tender as early as March, she said.

The company is also in talks with a Chinese company to take a stake in the Maranhao project, Foster said. The project could lead to the Chinese partner taking a majority stake, she added.

UK to encourage hydrofracking of natural gas.

Proposed U.K. government policies to encourage hydrofracking of natural gas ignited a firestorm of protest this summer, with critics complaining that they were not consulted and that rules will restrict local planners’ authority. But the country appears to have few other options. The United Kingdom is in an energy quagmire that is forcing it to turn to shale gas.

The country’s aggressive carbon emissions goals call for the U.K.’s power supply to be virtually carbon-free by 2030. But the government had been planning to slash emissions with low-carbon power strategies—new nuclear reactors and carbon capture and storage systems on existing power plants—that remain too expensive to build. And conventional natural gas from the North Sea that could buy time for the scale-up of renewable power is dwindling.

Cost matters to U.K. voters. Nearly three-quarters of its citizens are worried about climate change, according to a national poll released by the London-basedU.K. Energy Research Centre in July. But more than four-fifths told the researchers that they are “fairly or very concerned” that both electricity and gas will become unaffordable in the next 10 to 20 years.

If the U.K. can’t find an affordable supply of natural gas via hydrofracking of its shale deposits, it might have to restart mothballed coal-fired power plants to keep the lights on in future decades. “One way or another, we’ll muddle through,” says George Day, economic strategy manager at the Loughborough-based Energy Technologies Institute, a partnership between industrial firms and the U.K. government. “Whether we’ll hit our carbon targets is another question,” says Day.

Those targets would slash greenhouse gas emissions 80 percent by 2050 from 1990 levels. For the country to get there, the U.K. power industry would have to slash its carbon intensity from more than 500 to 50 grams of carbon dioxide per kilowatt-hour by 2030, according to the quasi-independent Committee on Climate Change. Under that committee’s roadmap, 60 percent of new cars sold in 2030 should be electric, rising to 100 percent by 2035.

Day and other government advisors project that such ambitious targets are well beyond what renewable energy alone can deliver, however. Britain’s solar potential pales in comparison to even Germany’s lackluster supply of sunlight, leaving wind power—principally from offshore farms—to carry the burden. “Do we actually have the industrial capacity to deliver 50-plus gigawatts of offshore wind within the next decade or two?” says Day. “That would be very difficult.”

Even some renewables advocates agree that the U.K. must pursue nuclear and carbon-capture technology as well. “It seems likely that you’re going to need all of the above,” says Briony Worthington, shadow minister for energy and climate change for Labour in the House of Lords. At the very least, says Worthington, the U.K. should seek new reactors to maintain nuclear’s 20 percent share of the power supply as a source of low-carbon energy.

The problem for the government is that investment in CCS and nuclear is, at present, nonexistent. To a large extent that is a failure of the European Trading System, which was intended to render low-carbon technologies competitive with fossil fuels. With the collapse of Europe’s carbon market, that incentive is missing.

To attract CCS and nuclear investment, the U.K. established its own carbon prices that are set to rise to £30 per ton by 2020 and £70 per ton a decade later. It has also proposed floor prices for low-carbon power, with the government topping up a generator’s revenues if the market price falls below a fixed threshold. To support CCS it has set aside £1 billion to defray the cost of building early CCS projects.

Still, investors are moving cautiously. Only two CCS projects are eyeing the government’s financing. A consortium led by Shell proposes to capture carbon dioxide from the Peterhead power station in Scotland and pipe it out to the North Sea for sequestration in a depleted oil and gas field. A second project would send carbon dioxide to the North Sea from a coal plant in North Yorkshire. Final investment decisions for those projects are not likely before 2014 or 2015.

Nuclear reactor construction is lagging further. While the government wants to see 16 gigawatts of new nuclear capacity operating by 2025, only one project is getting serious attention: a proposal by French power generator Electricité de France to build a 1,600-megawatt EPR reactor at the Hinkley Point nuclear station, whose 1970s-era reactors are scheduled to shut down in 2023.

Bakken Shale: North Dakota Fracking

Though North Dakota has historically had lower unemployment rates than the rest of the country, it barely felt a hiccup with the onset of the Great Recession. Not only have the number of jobs increased steadily in the region over the past decade, but the average take-home pay has increased at a healthy clip as well.

A big part of that is due to the fact that drilling in the Bakken Shale -- with its enormous oil deposits beneath North Dakota's soil -- has become a very profitable endeavor. In fact, in 2006, North Dakota ranked ninth in daily production of oil in the United States. In just seven years, it shot all the way up to second, behind only Texas. The state currently produces 821,000 barrels of oil per day. 

The big playersTwo players account for a large portion of business in North Dakota's oil fields. Continental Resources leases the most land of any oil company in the state, and stated last year that it plans to triple its oil output by 2017, with the Bakken shale accounting for most of this growth. Hess  also made a big splash in 2010 with a $1 billion land purchase.

At the same time, several smaller players are also turning a profit to the benefit of North Dakotans and shareholders alike. As Foolish colleague Matt DiLallo recently pointed out,Kodiak Oil & Gas and Oasis Petroleum have combined to go from producing about 4,500 barrels of oil per day in 2010 to more than 60,000 by the end of this year.

And even though the Bakken has been active for years now, the land grab continues. Just last month, Whiting Petroleum announced that it was buying 40,000 acres of land for roughly a quarter of a billion dollars.

Telling Washington to stay awayGiven the vested interest North Dakota citizens, politicians, and oil companies have in seeing the Bakken shale continue to produce profits, it's no surprise that the state is wary of the Obama administration's plans to institute nationwide regulations regarding the fracking process, which made this oil boom possible in the first place.

Expected to be released sometime in early 2014, these regulations will likely require disclosures of materials used in the fracking process, specifications to ensure safe well construction, and rules for the management and disposal of wastewater.

Though only 5% of oil in the United States comes from public lands, both sides of the aisle in North Dakota are fighting against intrusion from D.C. politicians. In May, a bipartisan delegation from the state claimed that these federal regulations were completely unnecessary.

"We believe we already have substantial regulations in place that allow for continued oil and gas production while protecting the environment and the health and safety of our citizens," Sen. Heidi Heitkamp (D-N.D.) said.  These regulations include the fact that fracking chemicals are already disclosed via the industry-standard website, Fracfocus.org.

Continental Resources CEO Harold Hamm also claims that while it only takes 30 days to get a drilling permit through North Dakota authorities, doing so through the federal government would take close to nine months. That kind of delay, he argues, inhibits efficient economic development in the region.  

No matter how the regulations play out, finding the right investments while historic amounts of capital expenditures are flooding the industry is crucial to padding your nest egg. You can get a comprehensive look at three energy companies set to soar during this transformation in the energy industry.