The Midwest WTI cracking margin averaged $21.82/barrel the first six business days of the month, up from a January average of $15.17/b, according to Platts data and Turner, Mason & Co. yield formulas.
]]> That's around $10/b shy from the $31.40/b third quarter 2011 average, when the WTI cracking margin briefly peaked at $42/b, but still strong considering that US refined product demand has been far less-than-stellar.Current Midwest margins are being primarily driven by relatively weak crude prices, rather than product strength. The Midwest -- Group 3 and Chicago -- refined product markets are currently the lowest priced in the country. Chicago ULSD, for instance, was assessed at 17.85 cents/gal below the Gulf Coast February 8, and 23 cents/gal below the Atlantic Coast.
Chicago conventional gasoline was assessed 30 cents/gal below the Atlantic Coast.
These low Midwest product prices would be more of a concern to area refiners if they were processing the same crudes being run through Atlantic Coast and Gulf Coast refiners.
For instance, netback for West African Bonny Light crude in the Midwest was $121.05/b February 8, a slight premium to the WTI netback at $119.44/b.
But a Midwest refiner would pay a steep premium for Bonny Light crude, which is priced off the North Sea Brent benchmark, resulting in a cracking margin of just $3.07/b February 8, compared to $20.46/b for WTI. Processing Light Louisiana Sweet crude from the Gulf Coast would be an improvement, but only slightly, netting a Midwest cracking margin of $5.38/b.
The growing supply of local and Canadian crudes has largely shielded Midwest refiners from the price impacts of dwindling North Sea output, and various other supply concerns.
Brent and Urals crude prices may jump if Iranian exports dry up, but with Canadian exports at a record high Midwest refiners have little to worry about.
Even during the fourth quarter of 2011, when margins sank around the world, spawning a string of refinery closures, Midwest margins held up.
The Midwest cracking margin for Canadian Syncrude, for instance, averaged $14/b in the quarter, compared to an Atlantic Coast Bonny Light margin of $5.31/b, or, much worse, a Cabinda coking margin in the Caribbean of minus $1.69/b.
You have to go back to the first quarter of 2010 to find negative margins for WTI in the Midwest. That was back before WTI was "broken" and trading at a premium to Brent.
The highest cracking margins in the Midwest are currently for Canadian crudes. The Syncrude cracking margin was at $44/b February 8.
But there's a hitch. That margin is inflated by a severely depressed spot crude price, the result of a backlog of barrels in Canada.
Midwest refiners have been cutting runs, and importing less crude, the past couple of weeks, likely in response to high product inventories in the region. Refiners processed 3.404 million b/d of crude the week ending February 3, 102,000 b/d from the week ending January 20, according to US Energy Information Administration data. That left Midwest refiners operating at 91.8% of capacity, down from 94.5% January 20.
As a result, the product surplus has deteriorated somewhat. Midwest ULSD stocks at 31.937 million barrels the week ending February 3 were 7.36% above the five-year average, down from a 17.21% surplus in mid-January.
But, assuming there is physical storage available, refiners likely won't worry too much about product inventories growing, as long as the crude supply holds out.
]]>Some of the US' biggest upstream names have raved about the economics of the Eagle Ford, which offers a trio of "windows" yielding gas, oil and condensate. For example, Marathon Oil, which split off its refining arm in mid-2011, said it will spend $1.35-$1.65 billion yearly, or about 30% of its total $4.5-$5.5 billion company-wide capital allocation this year in the Eagle Ford.
Marathon says the economics for condensate can exceed 100% for condensate and anywhere from 22% to 50% on oil.
From its production there last year which averaged less just over 9,000 boe/d in the fourth quarter (although the company was producing 15,000 boe/d net in early February), Marathon expects to average 30,000 barrels of equivalent liquids there this year, growing to nearly 60,000 boe/d in 2013 and as much as 100,000 boe/d in 2016.
Big independent Pioneer Natural Resources says in its latest investor presentation that its pre-tax rate of return in the Eagle Ford is 70%, based on an oil price of $100/b and gas price of $4/Mcf. Pioneer said it will spend just $130 million of its own money in the Eagle Ford this year, but that is apart from $879 million in total future drilling costs that Reliance Industries Limited is paying as part of a 2010 joint Eagle Ford venture with Pioneer.
EOG Resources -- a giant US shale player that also claims to be the largest Eagle Ford producer at 53,000 boe/d net at the end of September 2011 -- called the play's return rates "likely the highest in industry for a large oil or gas project." The company is targeting a return rate close to 80% in the field this year.
EOG said in a recent presentation that a single one of its wells there throws off more than $1.8 million/month in revenues, about $300,000 more than its closest peer.
Then there's Australia's BHP Billiton, which in a move that reverberated throughout industry put a ring on Petrohawk's finger and acquired it last August at a relatively handsome $12.1 billion, excluding debt. Industry had suspected Petrohawk wouldn't remain an independent bachelorette forever; the question was who the lucky suitor would be. BHP will almost double its rig count there to 26 rigs in 2013 from 14 in November.
But it isn't just the big names that are lured to the Eagle Ford. Small upstream operator
Magnum Hunter Resources in a recent presentation cited investment bank Credit Suisse which in October ranked the Eagle Ford as the highest single rate-of-return shale play in the US at 51%, edging out even the Marcellus (47%) liquids play in Southwest Pennsylvania (although the Marcellus overall is mostly gassy), and North Dakota's Bakken/Three Forks (34%) oil play.
Rosetta Resources, another small upstream operator, also has ramped up spending there both dollar-wise and percentage-wise. The company plans to spend $595 million in the Eagle Ford in 2012, or 93% of its $640 million capital budget for 2012 in the play, up from about $404 million or 85% of the $475 million spent last year.
The Eagle Ford has become so core for Rosetta that it accounted for 91% of the company's 970 Bcf of equivalent gas reserves in first-half 2011, against 66% in 2010 and about 12% in 2009. Not only that, but Rosetta said it has 10 years worth of drilling inventory remaining in its 50,000 net acres in the liquids window. Moreover, the independent has aother 15,000 net acres in the gas window.
]]>President Barack Obama has a Valentine's Day date with China's leader-in-waiting, Vice President Xi Jinping. Xi is expected to resume a conversation he started back home with a visiting US Treasury Secretary Tim Geithner: why his country has resisted US and European pressure to curtail its 543,000 b/d imports of Iranian crude.
If oil analyst and National Petroleum Council member Philip Verleger were Xi, he would make the White House an offer that hurts Iran's treasury without punishing its customers. "If I were China, what I'd do is come in and say, 'We understand what you're doing on the sanctions and we want to do what we can,'" he said. "'Help us by selling us some oil from the reserves.'"
Verleger's recent paper, "Strengthening Sanctions on Iran with Strategic Reserves," argues the US has as much as 300 million surplus barrels in the Strategic Petroleum Reserve. Because membership in the International Energy Agency requires the US to store 90 days of net oil imports, the volume needed to meet that commitment keeps dropping along with the country's import dependence. Verleger estimated the 90-day requirement peaked in May 2008 at 785 million barrels.
Selling 500,000 b/d of stockpiled US crude to Iranian oil buyers would slash Iran's oil export revenues from $40 billion to $50 billion last year to less than $20 billion in 2012, Verleger argued. "It would allow stricter application of the sanctions," he wrote. "At the same time, it would ease the risk of trade friction (or an outright trade war) by reducing the likelihood of a significant oil price increase and the attendant threat of a recession."
Acknowledging it as an unusual solution, Verleger said preemptively opening emergency stockpiles would take the pressure off Saudi Arabia to ramp up production and rile its neighbor. Verleger, who worked for the Ford and Carter administrations, said the White House could make it happen and tap into the rare bipartisan agreement in Congress to increase pressure on Iran.
"This is an issue that a lot of people are very worried about and this is a way of really putting the screws to Iran," he said. "Somebody from Treasury said we want to cut off the cash. This is one heck of a good way to do it."
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To the International Energy Agency, the idea is a non-starter.
Deputy Executive Director Richard Jones said Iran can do the arithmetic to know how much consumer countries have socked away for emergencies. If Iran exports 2.5 million b/d, he said, the global stockpiles of about 1.6 billion b/d could flow for nearly two years.
"We could do without Iran for 640 days, in theory," Jones said. "You wouldn't want to, of course. You don't need to talk about that kind of preemptive stuff. It was serendipitous, but the fact that we showed we were willing to do a release for Libya may be something that the Iranians will take into account."
Former IEA Director Nobuo Tanaka has made a similar case since leaving the helm that oil reserves should be managed proactively rather than solely in response to physical supply disruptions. He said in October that stockpiles should be tapped more liberally to prevent economic downturn. "If $100/b prices continue, it will be as bad as 2008," he said at Singapore International Energy Week.
Jones dismissed that idea too. He compared it to countries using monetary policies to smooth out price spikes. "To be honest, member countries wouldn't buy that," he said. "We've got some pretty conservative governments when it comes to intervening in markets. They wouldn't allow that."
Not to mention, once you start proactive stockpile management, how do you know when to stop?
"'Well this isn't quite as big as the last one, but it's still important,'" Jones said, imagining a scenario. "I think it's one of those things that maybe the first time you did it, if you surprise people it might work. But I think its effectiveness would decline because the market would learn to discount it. That's what we saw in monetary policy in the past, so I wouldn't recommend it."
Jones said of Tanaka: "But I think if he really thought about it, he'd know that that's not going to happen."
Bob McNally, a top energy adviser to former President George W. Bush, said in a Council on Foreign Relations paper last week that conducting a test sale from strategic stocks could have the unintended consequence of "scaring rather than reassuring the market, depending on prior perceptions of risk."
"So far, the Obama administration has astutely countered panicky press reports and belligerent Iranian threats with calm reassurance and factual denials," McNally wrote in "Managing Oil Market Disruption in a Confrontation with Iran."
McNally added that IEA must do a better job of forging unity about how and when to use reserves. "There was an unusual amount of public dissent among IEA members during the June 2011 stock release that IEA leaders should not wish to repeat," he wrote.
--Meghan Gordon in Washington
One state regulator is throwing down a big glove, the Constitution, in what reads like a profoundly felt fist-shaking against efforts to plan and pay for power systems more centrally.
]]> Brad Molnar, a member of the Montana Public Service Commission, has introduced a resolution for state regulators to take up when they meet in Washington next week. It has a litany of pain points, a number of them involving the Federal Energy Regulatory Commission.Some of the resolution is specific, and some resorts to almost inchoate anger. Molnar's resolution is so broad and far-reaching -- the Constitution's Commerce Clause figures prominently -- that it probably won't get far. But some of it will resonate with other state regulators. Federal-state tensions remain lively in the power arena.
This is at a time when lots of people in industry call for comprehensive national energy policy so they know what to invest in, yet at the same time object when the federal government tries to define one. For better or worse, in the power sector, state decisions drive industry investment (though federal environmental regulations constitute a big exception.) That investment may involve a need for transmission lines that involve other states, which may not want them.
One "whereas" in the resolution drafted for consideration at the National Association of Regulatory Utility Commissioners says: "Top-down, heavy-handed, centralized planning has been shown to be a failure wherever in the world it has been practiced." But there's not really much central planning in the power sector, because of the legal foundation for regulation; maybe that's why any hint of it stirs the blood.
Molnar objects to FERC's granting of "excessively generous incentives" for construction programs, which include transmission projects, where more and more states are protesting incentive rates.
In fact, NARUC has another resolution--this one could well pass--that laments FERC's incentive-rate policy and calls for reform. The incentives theoretically aim to reward companies for taking risks or using modern technology; states and others complain that there's usually not a lot of risk or exceptional technology involved.
The resolution also cites the "multi-value projects" that the Midwest Independent Transmission System Operator is designating that would have FERC's approval to spread costs broadly. But sometimes customers get "nothing in the form of tangible benefits" for those costs, the resolution says. Illinois and Ohio regulators, among others, have such objections.
In a grand gesture, the resolution calls on NARUC's staff to review the laws that established FERC and its programs "and report back regarding the programs that usurp the rightful powers and prerogatives of state governments." Then NARUC should recommend law changes to Congress "to return power to the states that belongs to the states under the US Constitution."
But states are actually unlikely to want Congress to start messing with the seminal Federal Power Act. It never goes well. There's the herding-cats problem; some states want something, others do not. Some states are in FERC-sanctioned regional transmission organizations (voluntary, of course), while others are doctrinally determined never to form RTOs.
The angst out there about federal-state conflict remains a staple of the power dynamic; this NARUC session will be just one more forum to air it.
]]>However, the financial results for the fourth quarter of 2011 of many of these Saudi companies reveal a very different picture indeed. While petrochemical giant like Sabic showed a drop in net income Q4 2011, others, like Saudi Kayan and Petrochem, in fact showed net losses.
Saudi Arabia's petrochemical industries index dropped 1.65%, or 103.12 basis points year-on-year on December 31, 2011 to 6232.93.
]]> This index, which largely sets the direction of pointers at the Saudi stock exchange, or Tadawul, has been bearish for most of January as the results of the Kingdom's petrochemical companies were gradually declared. While results more or less followed the global cues on a low demand and low price environment in Q4, 2011, many industry sources and analysts seem united in their opinion that despite this, the financial performance of some Saudi companies should have been far better.Saudi petrochemical companies' woes
There were two reasons why the Saudi Arabian government decided to promote its petrochemicals industry way back in 1976. One was to enhance the netback on its hydrocarbon produce. The other was to generate employment opportunities for its burgeoning population. In the past 35 years, the two objectives were largely met.
But as the Saudi petrochemical industry becomes increasingly global, and tries to attract foreign investments to its new projects, it is struggling to maintain high margins, and there are clearly obstacles to further growth that it needs to deal with.
Firstly, there is news that the Saudi government may raise the prices at which it supplies gas to local petrochemical industry. If this indeed happens, then Saudi petrochemical manufacturers may find themselves with far deeper problems.
Taxation issues are also at the forefront. In the set of financial results released recently, three Saudi petrochemical manufacturers -- Saudi Kayan, Petrochem and Saudi Industrial Investment Group, or SIIG -- cited 'Zakat' donations as one of the reasons for their drop in Q4, 2011 net income.
Zakat, a form of obligatory religious tax imposed on companies in Saudi Arabia, is calculated on several factors including the total value of its assets. "Companies like Saudi Kayan have made huge investments but it will take time before their commercial production reaches a stage where they begin to make substantial profits," a Dubai based petrochemicals analyst said. "The Saudi government needs to allow a new producer to generate substantial profits before beginning to tax it on its profits and not on the value of its assets," the analyst added.
Saudi Arabia will have also have to delicately balance their downstream ambitions with the more attractive margins provided by upstream products.
Although the Saudi government has been promoting downstream investments to generate employment opportunities for its burgeoning population, some see issues with this strategy. "It makes more economic sense to produce upstream products in Saudi Arabia and set up labor intensive downstream industries in China where wages are cheap," said Sriharsha Pappu a petrochemicals analyst with HSBC.
Also, over the past ten years, the EBITDA (Earnings before interest, taxes, depreciation and amortization) margins in Saudi Arabia of commodity chemicals, pure ethane and mixed feedstock have been higher than specialty chemicals -- an area in which Saudi petchems have increasing come to focus on.
Downstream converters have repeatedly raised concerns over their financial situations, but so far feel their anxieties have been greeted with some measure of indifference by both the government and larger players like Sabic. Sooner, rather than later, these concerns will need to be addressed.
]]>Who will be OPEC's next secretary general after Abdalla el-Badri, who will finish his second three-year term in the job at the end of this year? OPEC kingpin Saudi Arabia has nominated its former OPEC governor Majid Moneef but it's unlikely that he will be the only candidate.
You might think that choosing a secretary general to run the Vienna secretariat would be a fairly simple affair. But it's not. Politics and geopolitics tend to spill over from crude output policy into the process of filling the group's top job.
]]> Although the post is primarily an administrative one, the secretary general is often a key figure in negotiating and resolving conflicting points of view within OPEC.Members rotated the post in the distant past, but when that method became overshadowed by politics, it was decided to make the appointment on the basis of merit. When the merit principle is used, ministers must agree unanimously on the candidate.
US-educated Moneef knows OPEC well. He has been a member of Saudi Arabia's ministerial delegation to OPEC since 1988. He has served as Saudi Arabia's OPEC governor and as the kingdom's national representative on OPEC's Economic Commission Board. He has also served as an adviser to the minister.
Undoubtedly other member countries will make a bid for the job and Iran will almost certainly be among them.
But, mindful of the need for unanimity among ministers, what are the chances of Iran accepting a Saudi candidate or of Saudi Arabia accepting an Iranian?
Nil is probably the answer, given the current state of relations between Tehran and Riyadh.
Saudi Arabia and Iran have competed for the post in the past, opposing
the appointment of their respective candidates. But what was at the time rather a gentlemanly argument between the OPEC heavyweight and cartel number two Iran is likely to be slightly more intense this time around.
Relations between Riyadh and Tehran have always been testy but the past year saw the relationship between the two leading Persian Gulf powers sink to a new low as Saudi Arabia and its Arab allies in the region saw Iran's hand in the unrest that rocked predominantly Shi'ite Bahrain and awakened the disgruntled dormant Shi'ite population of Saudi Arabia's eastern province, the kingdom's main oil hub and achilles heel of the Sunni Muslim bastion in the Persian Gulf. Matters came to a head when the US revealed details of an alleged Iranian-backed plot to assassinate the Saudi ambassador to Washington.
Nor did Saudi Arabia take kindly to Iran's recent warning to Riyadh and other Arab oil producers against taking Iran's market share when an EU embargo on the import of Iranian crude oil comes into effect on July 1.
Indeed, one senior Iranian official recently called on OPEC to take disciplinary action against Saudi Arabia and expel the world's biggest oil exporter from the 12-member cartel, a radical idea that did not gain traction even within the Islamic Republic.
So, taking all of this into account, OPEC's top diplomats are going to have their work cut out for them over the next few months.
]]>LNG is a boom industry in Australia, with eight new projects currently under construction, worth a total of more than $175 billion. The new projects will add capacity of nearly 70 million mt/year to Australia's existing LNG industry, which comprises the Woodside Petroleum-led 16.3 million mt/year North West Shelf joint venture and the 3.6 million mt/year Darwin LNG
plant, operated by ConocoPhillips.
In the Northern Territory, Japan's Inpex has approved the 8.4 million mt/year Ichthys project, and on the east coast, three coalseam gas-based LNG facilities are under construction on Curtis Island in the Queensland city of Gladstone. Those plants are being built by UK-based BG Group (8.5 million mt/year); a consortium led by Santos and including Petronas, Total and Korea Gas Corporation (7.8 million mt/year); and the Australia Pacific LNG joint venture between local partner Origin Energy, ConocoPhillips and China's Sinopec (9 million mt/year).
Australia's federal and state governments have been at the front of the cheer squad for the massive investment in LNG, citing the 30,000 thousand or so local jobs and billions of dollars of revenue expected to flow from the projects.
Domestic gas users, however, are not exactly waving pom poms.
"In our rush to overtake Qatar as the world's biggest LNG exporter, we have lost sight of the big picture -- that Australia's manufacturing sector and 1 million jobs depend on a competitive advantage in energy," Gavin Goh, executive director of Western Australia-based lobby group DomGas Alliance, wrote in a letter to the Australian Financial Review Wednesday.
"This advantage is being lost as gas producers focus on maximizing LNG exports. As a result, gas prices have tripled in Western Australia and doubled in Queensland," he added.
Australia has two separate major domestic gas markets, on the western and eastern seaboards, and has historically enjoyed some of the lowest prices in the world.
According to the latest figures from local industry consultancy EnergyQuest, the average price for Australian LNG exports in the quarter ended September 30, 2011 was A$11.37/gigajoule, with Woodside achieving an average price of A$11.68/GJ. Woodside's return from export LNG was nearly three times its average domestic gas price in Western Australia for the quarter of A$3.87/GJ.
But cheap gas is no longer available for new long-term domestic contracts in the west. Those prices are now running at between A$7/GJ and more than A$8/GJ, and are increasingly linked to oil prices, according to EnergyQuest.
In the eastern part of Australia, domestic gas prices are mostly around A$3-4/GJ. "But gas producer expectations [for new contracts] are at A$6-9/GJ, which is pretty consistent with LNG net backs," EnergyQuest CEO Graeme Bethune said Wednesday.
The target level has repeatedly been cited over recent years by Santos, a major east coast producer, which is aiming for oil-linked international price parity. Santos says a doubling in the domestic price is a necessity for the gas to be developed, and can easily be absorbed by the big local consumers like miners BHP Billiton, Rio Tinto and Xstrata, which have enjoyed ten-fold increases in prices for their own export commodities over the past decade.
Santos also claims that household customers can absorb what would be a phased 20% increase in prices from around $21/GJ to about A$25/GJ at the stove top.
According to DomGas Alliance's Goh, the answer is a domestic gas reservation policy, similar to the one applied in Western Australia, where the state government requires 15% of the gas resources developed for export LNG projects to be put aside for use in the home market. "It is time we applied this same strategic thinking to Australia's natural gas," he wrote.
"Australia needs big LNG projects for the investment they generate and as a source of energy," Goh said. "However, the massive increase in gas production in recent years has not delivered a better outcome for local industry. With the right policies, Australia can have a successful LNG industry and a vibrant manufacturing sector."
The home team's calls are so far being drowned out by the hurrahs. "I'm not about a domestic gas reservation policy," federal Minister for Resources and Energy Martin Ferguson told Platts in a doorstop interview last year.
That position was confirmed in the government's draft Energy White Paper, released in December 2011.
"The historical separation of international and domestic markets is changing, with international demand putting pressure on domestic prices and contract terms," the paper acknowledged. "This has resulted in a period of uncertainty for all market participants, especially major buyers of domestic gas, although it is unclear the extent to which current market tightness is transitional or may ease in the future."
The paper recognized that "current market conditions are particularly challenging for some large gas users," but said the Australian government "believes that policy intervention at the present time to force domestic gas outcomes is unwarranted." But, "there is a need to monitor market dynamics to assess whether policy settings deliver the required outcomes given the growing domestic use of gas."
It seems for now the referee is not blowing the whistle.
When NATO looks at Iran it would seem reasonable to expect that it was looking at how the western world's warships are cramming into the Strait of Hormuz amidst charge and counter-charge that the strait faces the prospect of an Iranian blockade.
But when NATO invites its partners in the region -- countries such as Saudi Arabia, the UAE, Iraq, Jordan and Egypt are all members of NATO's Partnership for Peace program -- for an informal symposium on issues of mutual interest, it's not just energy security that's up for discussion, but cyber security, water and the problems posed by declining military budgets.
]]> The Middle East did provide a context for discussion. After all, as one guest lecturer, Professor Malcolm Chalmers, noted in a reference to current tensions in the Middle East, "A crisis in the region may involve the military forces of a lot of the countries represented here." In addition, lurking in the background, was the concern -- even in the wake of its air intervention in Libya -- that no matter what it does, NATO will somehow be seen as an anti-Muslim alliance.The alliance officials hosting the annual Partnership for Peace symposium at the NATO school in Oberammergau, Germany, earlier this month remained silent on the Hormuz issue. After all, although such NATO members as the US, the UK and France all have ships on station in or near the Gulf in the event of any deterioration in the current crisis, they are not operating as part of any NATO-structured operation.
In talking with its partners, NATO adopts an approach that is both open and circumspect. It calls on analysts to expound upon what they think are the problems the alliance faces.
So this year, the Gulf of Hormuz crisis naturally came to the fore, not least the argument as to whether international sanctions might so damage the Iranian economy that it would prompt Iran's government to think it had nothing much more to lose by attempting to close the strait. So, too, did the question of whether the intervention by NATO member states in various global crises--from the Iraq wars of 1991 and 2003 through the Kosovo intervention, the war in Afghanistan and the aerial assaults on Colonel Qadhafi's forces In Libya--might be considered anti-Muslim.
One analyst, Dr. Carlo Masala of the Bundeswehr (German Army) University, specifically appealed to the partner states gathered at Oberammergau, saying: "I would like to hear partners speak up for NATO to dispel the idea that NATO is this Christian alliance that suppresses Muslims."
The symposium drew senior officers and defense officials from around three quarters of the 50-odd members of the Partnership for Peace, including at least 10 Arab League members as well as contingents from Russia, Central Asia and as far afield as Japan, Australia and New Zealand.
There was concern at events in Syria. While there was widespread understanding that it was an issue of key concern to NATO member Turkey, Oberammergau showed there was no NATO appetite to get embroiled in Syrian affairs. As regards a diplomatic approach to the crisis, the most widespread view was that NATO should take its lead from Ankara.
On Hormuz, the partner states present at Oberammergau listened intently to details of tanker traffic through the straits -- 19,368 tankers in 2010 carrying around 17 millions b/d -- and their particular importance for Chinese and Japanese customers. But they asked no questions.
One theme underpinned much of the discussion: the impact of diminishing defense budgets on NATO's operational abilities. Professor Malcolm Chalmers, who heads the British think tank the Royal United Services Institute, said: "We may now be reaching a turning point in US and NATO defense strategy" with defense budgets on both sides of the Atlantic starting to contract. Moreover, Professor Chalmers added, "China's national income could reach the level of the US as early as 2018 if current growth rates continue," indicating that an equivalence in defense spending between the two titans might not be far off.
Already, Chalmers noted, there was a new US military doctrine based on "low cost, innovative and small footprint" interventions. This had implications for NATO's partners, he argued.
Partnership in prospective future interventions would become ever more crucial, while goals would need to be more limited. "Working with local partners (is) going to be vital, not seeing them as auxiliary forces, as in Iraq and Afghanistan," but as allies in their own right, said Chalmers.
There were military fuel concerns. Basic fuel costs for frontline troops even outside war zones could often reach the $500 a barrel mark, while the final cost for getting gasoline or diesel to outposts in Afghanistan was often a lot higher than that. RUSI has previously addressed both the financial and human cost of fuel deliveries in war: at one stage in Afghanistan, the UK lost some 160 troops in attacks on fuel convoys and delivery vehicles in a two-year period.
But while such energy issues do exercise the minds of the NATO hosts, the issues raised by their partners were somewhat different. Would future wars be fought over water, not oil? What kind of bilateral arrangements could partner states secure with NATO? Could they gain its assistance in building up their own defenses against cyber attack?
The analysts asked to address the water question were skeptical. They noted that the vexed issue of the sharing of waters of the Tigris and Euphrates rivers involved one NATO member (Turkey) one NATO partner (Iraq) and one country from whom little might be expected on this issue until its had sorted out its present problems (Syria.) But on the whole they thought this was a matter to be resolved by the countries most directly concerned, rather than a subject in which the alliance should get embroiled.
But cyber security was a different issue. The ability to disrupt infrastructure installations is naturally a matter of interest to energy producers. Cyber attacks are constant, with Oberammergau participants told that Microsoft's systems come under attack literally every single day.
]]>In February, a government-imposed moratorium on exploration for shale gas in South Africa expires and although it is not expected to be extended, there remains uncertainty that work will proceed in the country as normal.
Over the last two years, the subject of developing shale gas resources in the semi-arid Karoo region, thought to contain trillions of cubic feet of shale gas, has stirred emotional debate throughout South Africa.
Public concerns have focused on hydraulic fracturing, in which drillers blast millions of liters of water, sand and chemicals into shale formations to release natural gas. Critics say the process could lead to contamination of water supplies in the sensitive Karoo environment.
Opponents include Treasure the Karoo Action Group (TKAG), Greenpeace and local farmers who want to know whether fracking can work without damaging the environment, where the massive amount of water needed will come from and what investment opportunities are there.
The biggest critic, TKAG, says most people in the small towns and farms of the Karoo have not been informed of the dramatic effect fracking for gas could have on their livelihoods and health.
Proponents believe it is a potential game-changer in South Africa's desperate search for energy sources. The International Energy Agency, which estimates the Karoo might hold reserves of 485 Tcf, says shale gas could not only improve energy security but also would reduce greenhouse gas emissions.
Shell, which has submitted an application for rights to explore 80,000 sq km of the region, says shale gas in the Karoo would make South Africa energy self-sufficient for decades.
South Africa has very limited oil reserves, and imports from the Middle East and Africa meet about 95% of the country's oil requirements. Excessive dependence on imported oil from high-risk regions makes the country vulnerable to both economic and national security problems, and high oil prices are a major threat to the country's overall energy security.
The country is looking at ways to shift its dependency on coal. A government plan proposes nearly halving the share of coal in the country's energy mix to 48% by 2030 from about 90% today, using renewable energy such as wind and solar. In November last year, state-utility group Eskom received a loan from the World Bank to finance the building of the country's largest solar energy and wind power generation projects.
The country was rocked by power cuts in 2008, sparking one of worst crises in its history with the national grid brought to near collapse.
With the help of outside funding, Eskom has been recommissioning older power stations that had been mothballed but it also warns that domestic demand will exceed supply until at least 2013 when the first new power stations will be brought online.
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Aside from Shell, other companies interested in exploring in the Karoo include the US' Falcon Oil & Gas and Australia's Sunset Energy.
The government has imposed a moratorium on exploration in the area until February 2012 and set up a task force to research the full implications of fracking.
South African petrochemical giant Sasol, which led a consortium with Norway's Statoil and the US' Chesapeake Energy, has shelved its exploration plans in an 88,000 sq km area cross southern KwaZulu Natal and parts of the Free State.
The moratorium has halted Shell's plans but industry officials say it is unlikely to be imposed again when it expires in February.
Environmentalists though argue the moratorium should be maintained indefinitely pending the conclusion of scientific studies into the evolving technology and its levels of risks to the environment.
Shell accepts that confusion and misinformation about the link between gas drilling and water supplies contribute to public concern about drilling in the Karoo. It says it supports regulation that aims to reduce risks to the environment and insists it will be applying appropriate operating standards, and contamination of water would not occur.
But TKAG's national coordinator, Jonathan Deal, says fracking will involve boring through aquifers to get to greater depths, which carries the risk of chemicals leaking into groundwater.
Greenpeace Africa says that instead of fracking and jeopardizing precious water supplies in the process, the government should be focusing on clean, renewable energy solutions. South Africans need a new energy system that replaces dirty fossil fuels with power it can use sustainably. Shale gas, Greenpeace says, is not that.
Shell argues the gas in some cases lies thousands of meters below aquifers, and that it is virtually impossible for liquid or indeed gas to reach drinking water. Given the controversy and public anxiety around the issue of fracking in the Karoo, a transparent and open approach is not only essential for good governance but may help dispel what the industry believes are the significant misconceptions about shale gas.
--Jacinta Moran, in Cape Town
]]>"My administration will take every possible action to safely develop this energy," Obama said Tuesday night.
But by the time the White House released the details of his plans in the days after the speech, analysts and industry officials said the proposals were largely a restatement of already-introduced policies, with only a handful of truly new ideas.
Houston-based Tudor, Pickering, Holt & Co., an energy investment bank, said in a note to its clients that the "only real takeaway" from Obama's embrace of natural gas is that it "necessarily takes some of the target off the back of hydraulic fracturing."
For natural gas, the phrase "every possible action" has been limited to Obama calling for a new tax incentive to boost use of natural gas as a transportation fuel for commercial trucks, and requesting more funding to build out natural gas fueling infrastructure. Obama proposed those initiatives Thursday in Las Vegas, speaking at a UPS facility that is converting its gasoline-powered trucks to a gas-powered fleet.
Senior administration officials said the proposed tax credit would be similar to one that expired at the end of last year, which provided 50% of the difference between a conventional and natural gas-fueled vehicle, up to a maximum of $20,000.
Kevin Book, a managing director of ClearView Energy Partners, a Washington-based consulting group, said reinstating the expired credit would not make a major difference in the development of natural gas vehicles, or NGVs.
It "wouldn't necessarily promote rapid uptake," Book wrote in a research note to ClearView's clients. "Augmenting the credit to...$40,000 or $64,000 however, could increase vehicle diffusion."
The story on Obama's oil comments were much the same. In the State of the Union speech, Obama said he was directing the Department of the Interior to "open more than 75% of our potential offshore oil and gas resources."
But as Platts reporter Gary Gentile reported, and senior administration officials later confirmed, the 75% figure referred to estimates in the administration's 2012-2017 OCS leasing plan, already proposed in November. "The point the President was making last night is he was directing the department to finalize that plan," an administration official said.
Obama's State of the Union pronouncement that he was "directing my administration to allow the development of clean energy on enough public land to power 3 million homes" was also a rehash of existing policies. That directive referred to Obama's goal of 10,000 MW of renewable energy projects on public lands by the end of 2012, not any action to open new areas to solar or wind development.
The natural gas industry was glad, however, that Obama's call to disclose chemicals used in hydraulic fracturing had also been long-expected, with work on those rules underway at the Interior Department for more than a year.
Clear View's Book has long predicted that states will rush to get ahead of what they perceive as any new regulation on shale extraction coming down from the federal government. Already this year, Colorado, Texas and Wyoming have added rules requiring fluid disclosures, and the industry has established its own online well-by-well database.
Speaking to reporters last week, a senior administration official said those rules will also require disclosure of shale-gas producers' water-management plans, among other steps.
The official stressed that currently, most regulations governing fracking fall under state -- not federal--jurisdiction. "The president specifically focused on the disclosure issues because that's an area where the federal government can show leadership here," the official said.
The Tudor Pickering analysts, for their part, were nonplussed by Obama's call for new rules covering drilling for shale gas or oil on federal leases. "Disclosure of chemicals and tweaks to the process aren't a big deal," they said. "Production growth from either commodity isn't happening without fracturing."
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