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Deepwater Horizon ripples help sink US Arctic drilling: Regulation and Environment

In this week’s Oilgram News, Regulation and Environment, Gary Gentile looks at the after-effects of Deepwater Horizon on offshore production elsewhere and has a bonus segment about the future of the Renewable Fuels Standard in the US, which could impact both the oil industry and biofuels producers.

Investigators into the 2010 Deepwater Horizon disaster in the US Gulf of Mexico often lament the failure of Congress to pass any meaningful safety-related measures informed by the lessons learned from the tragedy.
But make no mistake — the ripples of Deepwater Horizon have been felt by the industry and can be clearly seen in the decision of Shell to abandon its offshore Alaska exploration as well as the canceling of Arctic lease sales for the remainder of the current US five-year leasing plan.
The Macondo Effect, if you will, can also be seen in more subtle ways, as a close reading of the recent 300-plus page final consent decree between BP and federal and state governments reveals.
Shell’s decision to indefinitely suspend exploration offshore Alaska may have been sparked mainly by the disappointing results from the one well spud in the Chukchi Sea. But the company made it clear that regulatory uncertainty as well as the safety requirements that forced it to spend millions of dollars and launch a flotilla of ships to drill only one well were also to blame.
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Those requirements were a direct result of the ordeal that BP and US responders had bringing the gushing blown-out Macondo well under control in 2010. From April to July, BP experimented with untried technologies, inventing on the spot (with the enormous assistance of government scientists) containment domes, capping stacks and other equipment before finally halting the flow.
That experience informed the decision by US regulators to require Shell to have a containment dome on site and to have a backup rig available to drill a relief well in the case of a blowout in the harsh Arctic seas.
Shell, to its credit, complied with all that was asked. But as a result, it became economically impossible to carry out a robust exploration program offshore Alaska. That reality led the Interior Department to cancel the remaining lease sales.
Whether future lease sales in the Chukchi and Beaufort Seas remain in the 2017-2022 leasing plan remains to be seen. But if they are removed, it will be easy to connect the dots between the April 20, 2010 Macondo blowout and the reluctance to risk a similar fate in Arctic waters.
There are some interesting bits in the consent decree worth noting.
BP will pay $82.6 million to the US, which consists mainly of the 75% share of royalties owed by BP and its partner MOEX on the 3.19 million barrels of crude that leaked from Macondo into the Gulf. The US is still litigating its claim that the third partner, Anadarko, owes royalties on the remaining 25%.
The decree mentions the previous criminal plea agreement from 2013 that requires BP to initiate, in conjunction with industry and government, at least four pilot projects “to evaluate technology enhancements intended to improve operational safety with respect to deep water drilling.” The results are to be shared with others “on commercially reasonable terms.” No word yet from BP on whether these projects have been launched.
Is it RIP for the RFS in the United States?
The never-ending debate over the US Renewable Fuels Standard flared up again recently, with the announcement that the Environmental Protection Agency’s own auditor will examine the issue.
One of the main questions that the EPA’s inspector general will examine is the lifecycle impacts of the biofuels mandate. The details of the current probe were well laid out in a story written by Platts reporter Herman Wang in the October 20 Oilgram News.
The narrow issue is whether the EPA has full considered research on the carbon intensity of biofuel sources, including corn ethanol. The larger issue is whether the RFS has acted to boost the interests of the corn lobby at the expense of advanced biofuels.
The debate goes back to the earliest efforts by the EPA to implement the Congressional biofuels blending mandate.
Early on, the EPA proposed using the concept of “Indirect Land Use Change,” which considers the impact of growing demand for corn ethanol on old growth forests in the Amazon and other places.
This approach actually assigns to corn ethanol the consequences of land use decisions abroad. In 2009, the EPA threatened to classify ethanol as having a worse greenhouse gas profile than gasoline because of the ILUC calculations.
The EPA backed off that position and now the agency’s inspector general is going to examine it fresh. Stay tuned.
Changes coming to The Column
Starting next week, we will introduce a new version of the weekly column titled “Fuel for Thought.” The new format will allow us to feature original Platts analysis and thinking on a wider variety of global topics. Let us know what you think at pon@platts.com. — Gary Gentile

Rio Tinto steals Vale’s iron ore crown ahead of Q4 decider

Iron ore miners Rio Tinto and Vale remain nose to nose in claiming industry leadership for 2015.
Rio Tinto’s new-found leadership status was confirmed by iron ore shipments stretching to a record 91.3 million mt in the third quarter, around 5 million mt more than Vale’s quarterly total for its fines, run-of-mine ores and pellet sales, latest company data show.
Vale, however, had something to brag about.
“We have the lowest cost in the world,” Vale CFO Luciano Siani exclaimed as the company unveiled its Q3 figures this week.
The outcome of lower costs aided by a weaker real, however, may result in prolonged and even weaker global iron ore prices.
A selloff in the real came as a result of political infighting, and slower Brazilian growth and with it steel demand, leaving Vale more exposed as its largest customers, China and Europe, fight over steel trade.
Vale is trailing faster growth from Australian majors, who this year posted stronger increases to volumes from new capacity ramp-ups. Vale faced delays in expansions.
The Rio de Janeiro-based company is still a year or more from making a bigger mark when it opens further new sections at its Carajas mine in northeast Brazil.
Vale’s Q3 shipment total of 86 million mt compares to shipments of 83.6 million mt in the second quarter — when Rio Tinto shipped 81.43 million mt — and 73.6 million mt in Q1, as iron ore operations in Brazil recovered from seasonal lows.
Rio’s iron ore production of 86.1 million mt in Q3 fell short of Vale’s quarterly record at 88.2 million mt for the period.
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In the ring, judged blow by blow alone on output and shipments of iron ore and pellets each quarter this year, Vale would lead Rio Tinto 4-2.
For the first nine-months of 2015, Vale’s production overall is around 8 million mt higher than Rio Tinto’s at 248 million mt, while Vale’s shipments are just over 3 million mt higher.
In terms of cash costs, the weak Brazilian real and cost improvements took Vale’s FOB costs down to $12.70/mt in Q3.
However, with Rio Tinto last guiding FOB cash costs just a few dollars higher, Australian miners still have an advantage in delivered costs to China, the main importer.
Based on standard Capesizes, the voyage from Tubarao to Qingdao averaged at $12.433/wet mt in September, compared to $5.503/wmt from Western Australia to the Chinese port last month, based on Platts assessments.
Lower costs may depress iron ore prices, analysts fear.
As cost curves drop further, led by the real’s weakness and soft Aussie dollar, and iron ore demand limps, Vale believes seaborne miners need to replace some 80 million mt of production elsewhere. Around half of the estimated volumes are still to come out from China, it expects.

ource: http://blogs.platts.com/

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Mixed signals: Weighing the fate of US shale oil supply

Aside from a brief blip, oil prices have remained stubbornly below $50/b in recent weeks despite fresh concern over global demand and rising geopolitical tensions. On the supply side, the market’s gaze has gravitated to that most closely watched of oil market variables — the response of US shale output to weaker oil prices.

Optimism over the “resilience” of US shale due to falling costs and rising well efficiency earlier this year gave way to scare stories in August as shale producers faced losing credit lines under scheduled October loan reviews.

But warnings that great swaths of debt-laden US shale producers could fall off a cliff due to liquidity constraints have proved largely overdone.

Calling such concern over the impact of lower prices on access to funding “exaggerated,” Wood Mackenzie recently said it was upbeat that US independent E&P companies will emerge largely unscathed from the current round of reserves-based-lending reviews by their creditors.

Contrary to fears of the sector’s “implosion” from debt, the research group said at least two-thirds of Lower 48 production being pumped by producers had either no exposure to RBL at all or have no redeterminations until next year.

As a result, just 30,000-40,000 b/d of production — the amount of base decline associated with those operators lacking sufficient liquidity — could be at risk from redeterminations, it said.

That assessment does little to change the facts on the ground that US light, tight oil output is in retreat on the back of a sharp drop in spending and correspondingly lower drilling rates.

Next month, US shale output declines are expected to accelerate to their highest since levels began dropping in April, according to the US Energy Information Administration.

Until now the impact of sliding shale output has been offset by growing deepwater flows from the Gulf of Mexico, but this is set to change soon. Total US oil and liquids production is widely expected to stall this month and begin to decline from early next year.

According to Mark Papa, the former head of US shale oil pioneer EOG Resources, this is just the beginning of the downturn in North America. Speaking at the annual Oil and Money conference in London earlier this month, Papa predicted “a pretty dramatic decline in US production growth.”

Papa is forecasting falling US oil production from early next year with an annual fall in 2016 averaging 700,000 b/d on the year.

Also speaking in London, EIA administrator Adam Sieminski said that while the US oil industry had reacted to lower prices by improving its productivity, this process could not continue forever.

“Now we are seeing the limits, at least in the near term, and it is beginning to impact production,” Sieminski said.

Indeed, the EIA predicts that productivity per rig will be flat in November at a rig-weighted average of 465 b/d.

Storm clouds also linger in the form of hedging implications for the US’ highly-leveraged independents and may also prove to be more of a cash flow squeeze in the short term. As production hedges are renewed over the coming weeks on a lower forward price for 2016, cash flow from hedging for the top 26 independents will dive from $9.1 billion in 2015 to just $2.2 billion in 2016, according to Wood Mac.

Interestingly, some market watchers are already looking beyond the short term fate of US shale to focus on the pace of a recovery when prices do strengthen. BP’s chief economist recently noted that — as the majority of shale oil lies in the middle of the cost curve — the short-run development characteristics of shale should actually dampen oil price volatility.

Unlike conventional projects such as deepwater, the billions of barrels of unconventional oil lying in the ground are accessible physically and economically at prices above $50/b, some point out.

Indeed, Sieminski believes that in the near future there is ample supply of shale for sustained US production growth of some 500,000 b/d if oil prices recover to $75/b.

The only hurdle, then, is the continued exposure of US shale producers to the financial system and whether creditors will be willing to continue bank-rolling the drilling. So far, at least, that’s a potential risk that has yet to materialize.

ource: http://blogs.platts.com/

Met Coke World Summit: Less minutiae, more macro

As conferences go, this US event may be the most cerebral in the steel raw materials calendar.

At the annual Met Coke World Summit in Pittsburgh this week, some of the presentations maybe far too technical for the commercial attendees and market analysts gathered for the largest metallurgical coke event worldwide.

At Smithers’ tightly managed series, with its European counterpart held every spring, papers from leading coke proponents worldwide share new advancements, with handpicked analysts serving up views before a critical audience. Futurists are well catered to. Long-range scenario planning-like discussions feature.

The presentations provide a rare chance to learn and gain expertise from technicians and others at the forefront of optimizing inputs into the blast furnace, without first gaining a doctorate and joining a major steel group like ThyssenKrupp or Erdemir.

But what the industry is urgently looking for is better steel demand; the lower costs and efficiencies these advancements could promise may help survival, but every steel executive is searching for drivers to boost volumes and prices as well as signs the cycle will shift upward.

Using even more PCI to reduce coke use, and with it coking coal demand, may less appeal with the Appalachian industry gripped over the next mine shutdown and competing harder than ever before to move domestic coking coal tons.

Technicians and furnace operators may have tweaked coke blends towards optimum value in use coals with the best logistics.

With steel prices depressed, and coke, met coal and iron ore prices low, this event cannot escape the funk grabbing the headlines for all the wrong reasons, just as participants faced earlier this month at Coaltrans in Barcelona.

Demand for US coke is looking weaker on idling North American blast furnaces and lower capacity utilization.

Take-or-pay agreements under long-term supply deals with mills may help tide coke producers’ finances over, but the repercussion is lower met coal demand. In the short term, that may mean lower prices before a likely forced further adjustment in supply.

For now, the macro focus will lead the micro. The long-range outlook discussions are, therefore, crucial.

ource: http://blogs.platts.com/

A very refined irony: Switzerland dips into emergency oil stocks as main refinery shuts

Global refined product markets are very well supplied at the moment, as evidenced by the steep spot price falls seen for diesel, jet fuel and gasoline over the last few weeks.

Partly, this is the result of the huge drop in crude oil prices witnessed since the summer of 2014, which has incentivized refiners to run as hard as they can.

We are also no doubt still witnessing the effect of the large investments in new refinery capacity undertaken several years ago in Russia, the Middle East and Asia.

But, even as Europe is swimming in oil products, it was revealed Oct 27 that one country, Switzerland, has had to dip into its emergency stocks of diesel and gasoline to guarantee supplies.

The situation may have struck some as ironic given that the country is home to the majority of Europe’s oil traders and suppliers, including well-known industry names such as Gunvor, Mercuria, Total and Vitol.

But in Switzerland’s case, supply shortages are real after the country’s last operating refinery, Cressier, was forced to close for unplanned maintenance last week, and because of low water levels.

Tamoil closed its Collombey plant in the country earlier this year, leaving Switzerland with just one refinery.

It’s easy to forget it if, like me, you live in the UK, but Continental Europe has had a hot, dry summer, and water levels on the Rhine have been below normal since July. For Switzerland, which is landlocked and tends to be supplied largely (albeit not only) by barge, this has made resupply more problematic.

For European governments safe in the idea that oil prices have fallen in the past 18 months, this latest episode is a painful reminder that a lot of European refinery capacity has closed over the last few years.

With fewer refineries in operation, Europe will in the future be more open to internal and external supply shocks, as well as to the vagaries of Mother Nature.

European summers will likely get hotter and drier into the future because of climate change, making situations like today’s on the Rhine only more common, and exposing Switzerland to long periods when the most realistic supply option is by pipeline from France, train from Germany, or, indeed, by its last standing refinery in Cressier.

ource: http://blogs.platts.com/

Petrochemical implications of easing sanctions on Iran

Earlier this month, the US and its negotiating partners announced steps to move ahead on what is known as “adoption day,” intended to show readiness for sanctions relief for Iran. However, relief will only begin on “implementation day,” the day when the International Atomic Energy Agency certifies that Iran lived up to its commitments according to the nuclear deal completed in July.

According to the US CIA’s The World Factbook, Iran has the world’s second largest supply of conventional natural gas reserves, much of which is rich in ethane. Given that the rest of the Middle Eastern countries are experiencing limited supplies in ethane, this presents a huge opportunity for the Iranian petrochemical sector as sanctions are eased.

Investing in Iran includes enormous political risks, but there are major advantages for international petrochemical investors, including low-cost steam cracker feedstocks and access to the European and Asian markets.

The value of Iran’s petrochemical exports is forecast to increase 20-25% within two years after the sanctions are lifted, according to Iran’s Petrochemical Commercial Company’s Managing Director Mehdi Sharifi Niknafs. Lifting of the sanctions will barriers from petrochemical exports related to banking, insurance, transportation, and brokering, said Niknafs.

Additionally, sanctions removal will also attract foreign investment to expedite the completion of petrochemical projects. Roughly $30 billion of investment opportunities have been identified in Iran’s petrochemical sector, according to National Iranian Petrochemical Company’s Managing Director Abbas She’ri Moqaddam.

Platts reported last month that one Dubai-based analyst said, “Everyone wants to be prepared. Iran has a range of [petrochemicals] investments opportunities to offer. They range from upstream to downstream.”

Takahisa Miyauchi, member of the board and senior executive vice president of Mitsubishi’s chemicals group, said in a meeting in Tehran with Moqaddam that the company is ready to invest in Iran’s petrochemical projects. It is an interest that Iran’s petrochemical sector is keen to court, not only for direct investment in petrochemical plants but also licensing of technology that could improve production.

The Middle East currently has a total of 30.2 million mt of ethylene capacity, of which roughly 6.5 million mt is produced by Iran. Saudi Arabia produces 15.7 million mt of ethylene, more than half of the ethylene produced in the region. Iran currently ranks second in the region in terms of total production with a 22% share.
However, with the increase in production capacity coming online within the next five years, Iran will produce approximately 30% of the region’s ethylene capacity by 2020. As shown in the table below, a total of 6.2 million mt of ethylene is expected to come online by 2020 in Iran.
gonzalez-iran-ethylene
Polyethylene typically represents 50-60% of ethylene demand. Ethylbenzene, ethylene oxide, ethylene dichloride, and alpha olefins make up the rest of ethylene demand, while a small percentage is used for other applications.
Polyethylene plants
Total polyethylene capacity in the Middle East for 2015 is 18.7 million mt. Saudi Arabia and Iran are the two top polyethylene producers in the region, producing 42% and 26%, respectively. Total polyethylene capacity in Iran is currently 3.1 million mt, most of which is HDPE. New capacity expected to come online within the next three years will total nearly 3 million mt, bringing the total polyethylene capacity in Iran to 6.1 million mt. By 2020, Iran’s share of polyethylene capacity in the Middle East is expected to increase to 32% with a total of 7.8 million mt.
gonzalez-iran-polyethylene
Outlook
Platts Analytics does not expect a sharp elevation in ethylene or polyethylene leaving Iran this year. However, as more PE plants come into operation along the country’s western coastline in 2016, supplies are expected to increase, particularly to Turkey, with which the country shares a border to its northwest. We expect a rise in exports to destinations in the Middle East, Africa and South America — all markets that Iran has tried to develop over the past four years as it grappled with sanctions. Iran’s nuclear negotiator Abbas Araqchi said on October 19 that he expected sanctions relief to be implemented by year-end. However, Germany’s foreign minister indicated that the EU sanctions were likely to remain at least until January, reports Reuters. As a result, we won’t see a surge in Iranian petrochemical exports until 2016.

ource: http://blogs.platts.com/

Why US natural gas prices hit multi-year lows this week

On Oct. 29, 2015, the NYMEX November natural gas futures contract settled at $2.033/MMBtu.

For comparison, the November contract closed at $3.649/MMBtu in 2014, $1.61 higher or 79 percent higher than Oct. 29. The last time the prompt-month contract closed lower than Oct. 29 was April 24, 2012 at $1.975/MMBtu.

So how did we get here? Why is gas trading at such a discount today? There are six key variables that, together, have played a massive role in pushing the price of natural gas to its current level:

1. Total natural gas supply

Simply put, the US has more gas to work with this year. In regards to production, 2015 has been a very strong year. Despite relatively low prices throughout the year, Platts data shows US production has averaged 72 Bcf/d year-to-date, a 3.6 Bcf/d increase from a year ago. Canadian imports are also up this year, averaging 5.4 Bcf/d this year, a 300 MMcf/d increase from a year ago. Lastly, the US has imported on average 300 MMcf/d of gas from LNG cargoes, primarily during the winter months in the Northeast. In total, the US has averaged a total supply of 77.7 Bcf/d in 2015, a 4.1 Bcf/d increase from a year ago.

2. Lower industrial demand

For all the talk about a recovering economy, the numbers for industrial demand tell a different story. Year-to-date industrial demand has averaged 20 Bcf/d, a 400 MMcf/d decline from a year ago. Declines are spread across most regions with the most significant drops in the Midcontinent, down 197 MMcf/d, where fertilizer demand continues to be weak. Other regions with notable declines have been Texas and the Southeast, down 81 MMcf/d and 65 MMcf/d, respectively.

3. Lower residential/commercial demand

Residential/commercial demand is also lagging, down 1 Bcf/d from a year ago to average 23.9 Bcf/d, mainly due to weather. When the US has a total gas supply increase of 4.1 Bcf/d year-over-year, these declines place significant downward pressure on prices.

4. Weather

As we enter November, this winter is shaping up to be a light one. The latest weather forecasts predict that the eastern half of the US will have above-average temperatures for the next two weeks. This is painful for natural gas prices because the Upper-Midwest and Northeast are some of the largest consumers of natural gas for heating. Cold weather, particularly in densely populated areas, will be absolutely crucial in moving prices out of today’s range.

5. Storage

Heading into winter, a key variable in determining the price of natural gas is the amount of gas in storage underground. Today the US has extraordinarily high levels of storage and is on track to set a new record on storage levels heading into withdrawal season (winter).

The most recent data from the US Energy Information Administration shows natural gas in storage at 3.877 Tcf for the week that ended Oct. 23. As a result, the US now has a 409 Bcf storage surplus compared to a year ago and a 153-Bcf surplus compared to the five-year average.

6. Infrastructure constraints

The fastest growing region for natural gas is by far the Northeast. The largest producing basin in the region, the Marcellus, which produced less than 2 Bcf/d in 2009, is now averaging 16.25 Bcf/d in 2015.

The Utica basin, underneath part of the Marcellus, began ramping up production around 2012 and is already producing almost 2 Bcf/d. Some see even the Utica as the basin with the most potential.

“A year ago, it would have been hard to imagine a more prolific play than the Marcellus. However, if the deep Utica works, it is likely to be larger than the Marcellus over time,” David Porges, chief executive of EQT, a major player in the Northeast, said in a call Monday.

With the Northeast now producing over 20 Bcf/d, the nation’s cheapest natural gas trading hubs can be found above the producing basins in the region. Cash prices on Oct. 29 at Millennium, East receipts were assessed by Platts at 99.5 cents/MMBtu, and Transco Leidy Line receipts were at $1.065/MMBtu. The average national average cash price for the same day was assessed by Platts at $2.170/MMBtu.

The Northeast Gas Association gives a great overview of the many natural gas pipeline projects taking place in the region that are expected to come online between now and 2018 and could take the gas to new markets. But as long as large amounts of production remain constrained, prices will have a hard time making significant long-term gains because of the fear of new gas supplies coming online.

Winter prices?

I invite all readers to share their thoughts on what is pushing down today’s natural gas prices, as well as put yourself out there and take a stab at where you think prices are headed. Leave a comment on what you expect will happen to prices, and we’ll be tracking the markets here

ource: http://blogs.platts.com/

Halloween comes early to ERCOT

Two days before Halloween and as most of the New York Mets’ bats continued to show lifelessness in the World Series, news of a rabies-infected bat brought a timely dose of fear and humor to Electric Reliability Council of Texas stakeholders.

ERCOT is headquartered outside Austin, Texas, and has a significant office, the Met Center, in Austin, which famously has a large colony of bats.

At Thursday’s ERCOT Technical Advisory Committee, Kenan Ogelman, newly appointed vice president for commercial operations, said he had “a health announcement to make as my first time speaking to y’all.”

“On October 14, they found a dead bat outside the Met Center, and it tested positive for rabies, so we just want to share with all the stakeholders that, I guess, you know, stay away from bats, but also, if you on October 14 came in contact with the dead bat, you might need to get yourself checked out,” Ogelman said.

It might not be too late for that. Treatment after exposure can prevent the disease if administered within 10 days of infection. Rabies is almost always fatal to humans after neurological symptoms develop, but symptoms can take two to 12 weeks to appear in humans.

Ogelman had previously served on various stakeholder committees as CPS Energy’s director of energy market policy, so was well known to the stakeholders present.

Randa Stephenson, TAC chairwoman, joked, “Are you going to send out a market notice?”

Laughter ensued. Eric Goff, Citi Energy director for regulatory affairs, asked, “Are you the bat guy now?”

“It appears that I am,” Ogelman said.

ource: http://blogs.platts.com/

How the shale boom strengthens US diplomatic clout: Fuel for Thought

US Secretary of State John Kerry’s declaration last month that the US shale boom has been a “game-changer” in global diplomacy was surprising not for its underlying truth but for his frank realpolitik.

Diplomats, after all, like to keep their cards close to the vest, and furthermore, the Obama administration has not always thumped its chest over surging US oil and gas production, given its international advocacy on global warming.

But no doubt the shale revolution — and the US’ new role as the world’s swing oil producer — has enabled the US to flex its diplomatic muscle in ways unimaginable just a few years ago, when declining domestic production and seemingly ever-increasing demand made American consumers more dependent on crude imports.

Consider that since 2008, the US has increased its oil production by 4.1 million b/d, or 81%, while imports as a percentage of consumption shrank from about 60% in 2006 to 27% in 2014, according to the US Energy Information Administration.

“It’s hard to overstate how for several decades with regards to energy, most of our news with regards to oil was bad and the United States looked weak,” said Bob McNally, a former energy adviser to President George W. Bush. “Energy is now a source of strength and vitality. We’ve turned this thing around in a surprising way. It gives a whole new view of America as a power.”

No wonder, then, that Kerry felt emboldened to declare at a Harvard University forum that the shale boom has “created incredible new possibilities” in diplomacy and “has had a profound impact on the budgets and choices of countries that have been creating some problems.”

Of course, he was referring to states like Iran and Russia.

US production helped create a global glut of crude that experts say played a key role in convincing China, South Korea, India and other buyers of Iranian crude that alternate supplies were plentiful, even with some 3 million b/d of unplanned disruptions in war-torn places like Libya.

With respect to Russia, with whom the US has feuded over the separatist uprising in Ukraine, US shale gas production likewise helped fuel an LNG glut that drove down prices and forced competition into the European market that Russian suppliers had long dominated.

“By reducing those revenue streams, we forced harsher choices between guns and butter on countries like Russia and Iran,” said David Goldwyn, the State Department’s former top energy diplomat from 2009 to 2011. “Unless the US is a significant importer of oil from a country, the more our conversations about their internal policies are liberated from the position that we’re in demand for their resources.”

Could the US export ban stunt shale’s growth?

The energy diplomacy extends to allies, as well. For example, the US has been able to share its shale fracking technology with countries like Poland and Argentina that hold large unconventional resources, opening up the possibility of greater energy security and diversified energy supplies.

The boom has also changed the US’ relationship with Saudi Arabia, with the US less reliant on Saudi crude.

“The surge in US oil production probably puts the Saudis and Americans on more equal footing for the first time since 1970,” said Matthew Reed, a vice president with Washington-based consulting firm Foreign Reports. “It means presidents won’t be asking kings to adjust their oil policies soon, which was a regular and awkward occurrence until recently.”

The next potential game-changer would be a dropping of the US’ long-standing restrictions on crude exports.

Many US producers and their allies in Congress have been heavily lobbying the Obama administration to change the policy, citing the additional diplomatic leverage that would provide.

The European Commission last month dispatched its energy head, Vice President Maros Sefcovic, to press the administration on crude exports in the name of energy security, and Japanese government officials told Platts last week that they are hopeful the restrictions will be lifted.

McNally, now a consultant, said leaving the export restrictions in place could damage US diplomatic interests in the long-term. Already, rig counts are falling and production growth has tapered off, due to low oil prices that could be exacerbated if production remains land-locked.

“If oil prices go back up — and they eventually will — that ban is going to come back and bite the shale oil sector. It’s going to prevent maximum investment in shale,” he said. “If we don’t lift the ban, it looks like we’re taking risks with our shale boom.” — Herman Wang

ource: http://blogs.platts.com/

OPEC’s big favor to the world of oil

OPEC’s spare production capacity is estimated by the US Energy Information Administration at 1.54 million b/d, a mere 180,000 b/d above the level reached in 2008 when oil prices hit their record high. But don’t panic! Oil inventories are at very high levels. The International Energy Agency puts global oil stocks at 147 million barrels, which it notes could notionally deliver 1.6 million b/d for just over 90 days in the event of a major supply disruption.

Meanwhile, the North Dakota Department of Mineral Resources reports that the number of drilled but uncompleted wells in the state hit 993 in August. According to Platts unit Bentek Energy, these wells if brought on-stream would add 591,000 b/d to Bakken crude production (again, notionally).

This represents a major change in the oil market. Spare capacity is no longer solely held by OPEC, but is split between the Middle East, principally Saudi Arabia, and the drilled but uncompleted wells in US shale plays. Moreover, this is backed by the growth in oil inventories, which is not just a function of the market’s current oversupply, but also structural, represented by the construction and filling of storage capacity in China, which the IEA says accounts for 60 million barrels of the 147 million barrel total.

It is an important change. OPEC’s spare capacity has a number of functions. It demonstrates visibly that the organization has the means to change output levels at short notice i.e. that its market interventions are effective. It acts as a disincentive to non-OPEC investment and to some extent helps to protect OPEC’s market share. And it provides OPEC with legitimacy. OPEC has invested — at considerable cost — in assets that could be used in the event of a supply disruption. OPEC was doing the world a favor, even if its spare capacity was also one of the tools in the cartel took kit.

OPEC’s current course, if taken to its logical conclusion, is that it runs down its spare capacity to zero, in the process taking market share from non-OPEC producers. The US’ uncompleted wells are a temporary phenomenon. How and when this spare capacity is used is no longer the strategic decision of a cartel, but a direct function of price. Over the longer-term private companies have no incentive to invest in non-productive assets.

Assuming that the market eventually rebalances — that investment and then supply falls causing prices to rise — it is the uncompleted wells that will come on-stream first. Restoring the investment momentum behind deepwater drilling or Canadian oil sands to a point where supply starts to rise again will take years, just as those modes of oil production are taking time to slow down in the face of low prices.

But where will the spare capacity be then? Where will be the buffer that protects the world’s oil supply from events like the Iran-Iraq war, the rise of Islamic State or implosion of Libya?

Better keep building storage because while OPEC may have been serving its own interests, it really was doing the world a favor. And better keep investing in shale unless the market wants the volatility implied by an industry where the majority of production is still victim to the boom and bust of a long and slow investment cycle. Few will rue the end of OPEC’s cartel behavior, but they might also miss its spare capacity.

ource: http://blogs.platts.com/