Sometimes it is a worldview, such as when a government minister of a certain Latin American country assured a group of journalists that vastly increasing its oil production was just a few weeks away as all they had to do was “turn on” some non-producing wells. This was the same minister who gulped down brackish water from a lake to “prove” that an oil spill there had been cleaned up. He said it tasted just fine.

Not that politicians anywhere on the planet are immune from this, but Venezuela’s officials must have swallowed a lot of this magical water. A recent comparison of figures purportedly recording Venezuela’s total crude and fuel oil exports to China, which in part pay for some $36 billion in loans from the Asian country, show this to be particularly true.

This doesn’t come as much of a surprise, as Venezuela’s overall oil production figures have long been far above any independent estimates. Platts news stories that include Venezuela’s government production figures always run with the tagline that their usual count of about 3 million b/d is “a number rejected by most oil industry analysts,” who mostly put it in the mid- to low 2 million b/d range. Platts says it’s 2.32 million b/d.

For Venezuela’s crude and fuel oil exports to China, there seems to be four sets of numbers: one from a PDVSA annual report, one from a separate PDVSA audited financial report, another given in verbal comments by oil minister and PDVSA President Rafael Ramirez, and another from China.

The figures from China roughly line up with that of the PDVSA financial report, although the metric tons-to-barrels conversion, which is always problematic no matter where you’re talking about, makes it hard to be too exact.

The PDVSA annual report figures may be OK, if you add in some export figures going to China but possibly through Singapore…but officials haven’t made that clear. And Ramirez’s verbal figures are generally off the charts.

The PDVSA annual report says that it exported 353,000 b/d of crude and other products to China in 2012, comprising 269,000 b/d of crude and 84,000 b/d of products. The separate PDVSA financial statement audited by the US firm KPMG, also recently released, shows that PDVSA in fact sent higher volumes, some 451,000 b/d of crude and products to China in 2012, or 22% more than claimed by the annual report. The statement did not give a breakdown of the volumes.

Our China staff found that numbers there show the country imported 4.77 million mt of fuel oil and 15.29 million mt of crude oil from Venezuela in 2012. Using a conversion factor of 6.7 for both fuels, the fuel oil imports averaged 87,500 b/d while crude volumes were about 280,000 b/d.  That would add up to a total of about 367,500 b/d, so roughly in line with the annual report.

Ramirez has said this year that oil volumes to China have reached 450,000 b/d, or even 640,000 b/d. Perhaps that is on one single day, but he isn’t clear. The first number would line up with the financial report, but not if he was only discussing crude oil volumes, as he seemed to be at the time.

Whoops, a ministry employee later said off the record to our Venezuela correspondent, he was probably talking about fuel oil, too. What the ultimate total is, at least about 230,000 b/d go specifically for debt repayment.

A fairly exact figure is important because it would show whether Venezuela might be even more in the hole with the Chinese than it appears to be. Venezuela says it has paid off about $16 billion of the loan, but the Chinese seemed to have reined in their loan program. China’s vice president signed no new big loan deals during a recent trip to Caracas, and looked quite cheerful throughout the visit while Venezuela’s officials seemed a bit glum, Platts’ correspondent there said.

Sources have said the Chinese are becoming wary of getting as much return as they had hoped for these cash-for-crude deals, partially because of possible political instability after the dominating Hugo Chavez died in March. His anointed successor in the “Bolivarian Revolution,” Nicolas Maduro, won the April elections, it appears, but faces high inflation, crime, a fragmented political base and a deficit of Chavista charisma.

Maduro will, however, apparently continue the beyond-belief policy approach. Maduro earlier this year–as the presidential election to replace Chavez heated up against opposition leader Henrique Capriles–claimed that the spirit of Chavez appeared to him in the form of a “little bird” and whistled into his ear. (Maybe Chavez missed his own prodigious Tweeting.)

The latest is that the recent toilet paper shortage in Venezuela is the fault of the media and speculation, and has nothing to do with government currency and price controls that seem to lead to a lack of many household goods on store shelves. Maybe a little bird can help them with that — just hopefully not like those in in the realismo mágico of Colombian writer Gabriel García Márquez. Those birds were usually bad news.

“In that Macondo forgotten even by the birds, where the dust and the heat had become so strong that it was difficult to breathe, secluded by solitude and love and by the solitude of love in a house where it was almost impossible to sleep because of the noise of the red ants … “ – “One Hundred Years of Solitude”

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Some of the companies building massive new coalseam gas-to-LNG projects in the eastern Australian state of Queensland have gone on the front foot to counter what they describe as anti-development activism.

BG subsidiary QGC has been particularly vocal among the players, who are fighting back against criticism in social and traditional media of the rapidly expanding industry’s environmental footprint.

QGC is building the $20.4 billion Queensland Curtis LNG project on Curtis Island in Gladstone. The 8.5 million mt/year facility will be the world’s first CSG-based LNG plant when it starts up in 2014.

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Two other LNG plants are being constructed on Curtis Island. All three will be fed with CSG from thousands of wells in Queensland’s Bowen and Surat basins.

Origin Energy and ConocoPhillips are developing the $24.7 billion Australia Pacific LNG project, with a capacity of 9 million mt/year, and a Santos-led group is working on the 7.8 million mt/year Gladstone LNG plant. Those two facilities will start up over 2015-2016.

In recent weeks, QGC has railed against federal government plans to regulate CSG projects which impact water resources, and to monitor fugitive emissions from CSG wells.

BG Group Australia Chairman Catherine Tanna, at a recent speech to the American Chamber of Commerce in Australia, criticized increasing regulation of the industry, pointing at the federal government’s planned changes to its Environment Protection and Biodiversity Conservation Act to include a so-called “water trigger.”

That move took the industry by surprise, coming as an additional layer of regulation on top of the requirements of the state governments.

The EPBC Act amendments, proposed by the Labor government of Prime Minister Julia Gillard, were debated in the Senate on May 14 and look set to be passed with support from the Green party and unaligned parliamentarians. The opposition Liberal National Party Coalition opposes the bill.

“The gas industry has been criticized on many fronts,” Tanna told the AmCham event. “Very occasionally that criticism is warranted and the industry has been quick to remediate. A lot of what is said, though, is highly questionable, and propagated without challenge to the point where activism determines public policy; where the tail wags the dog.”

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Tanna argued that rather than “poisoning” aquifers, and “alienating” farm land, the CSG industry reduced the pressure on stressed aquifers by purifying salty coalseam water and providing it to farmers and local towns.

“It is water that otherwise would not be available for any use,” she said. “If these proposals were, therefore, designed to protect Australia’s water resources, they fail on this logic alone. They were clearly not introduced to deal with an environmental problem. They were introduced to appease activists.”

QCLNG will add $32 billion to the Queensland economy in its first 10 years. “That is a measure of what is at stake when we have decision making on this basis; when green activists and their supporters deliberately misinform; and when motives and charges go unquestioned and unchallenged,” Tanna said. “Just as it is right that our industry be scrutinized and held to account, so, too, should our critics.”

QGC has also hit out at proposed federal regulations to measure fugitive emissions of CSG from gas production, saying the costs of implementation outweigh any environmental or revenue gain. The regulations, to be introduced from July 2013, have been applied after nearly a year of public consultation during which the government received only 17 submissions, with gas companies given just a month to comment, QGC said.

Santos has also pitched into the debate, running newspaper advertisements last month in response to a critical report on high-profile Australian Broadcasting Corporation television program 4 Corners.

“The Santos GLNG project in Queensland was subject to an extremely comprehensive environmental approval process,” CEO David Knox said in the advertisement. “Rather than being rushed, as claimed by 4 Corners, this process took over four years to complete between 2007 and 2010, involved 20,000 pages of environmental submission and resulted in 1,200 specific environmental conditions.”

The upstream peak industry body is also campaigning hard, releasing a steady stream of statements refuting the environmental lobby’s claims, including its “shameful scare campaign” on the human health impacts of the CSG industry.

But the industry might soon get its wish, with a return to a streamlined approvals process concentrated in the hands of the states. That is the system backed by the federal LNP opposition, widely tipped to oust the minority Gillard government in a general election scheduled for September 14 this year.  

–Christine Forster in Sydney

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The region is study in contrasts in a matter of a few short years. A couple of years ago, it seemed three major plants might close: the then Sunoco-owned refineries in Marcus Hook and Philadelphia, Pennsylvania, and the then ConocoPhillips-owned Trainer, Pennsylvania, refinery. All that came amid Hess and partner PDVSA initially scaling back operations of the Hovensa refinery on St. Croix, which exported to the US Atlantic Coast, to 350,000 b/d in 2011 before shutting it in January 2012.

The US Energy Information Administration focused on the potential problem in an initial report in late 2011 that was updated in the spring of last year. One thrust was EIA noting that if the Philadelphia, Marcus Hook and Trainer plants went offline, that would result in the loss of 50% of East Coast refining capacity (as of August 2011).

But, Philadelphia Energy Solutions now runs the 330,000 b/d Philadelphia refinery while a subsidiary of Delta Airlines runs the 185,000 b/d Trainer refinery, having bought it in June 2012 to recalibrate the plant to produce more jet fuel. Trainer also supplies refined products to Phillips 66 and BP. The 175,000 b/d Marcus Hook refinery was idled at the end of 2011 and now serves as a Sunoco Logistics tank farm storing gasoline and middle distillates.

While some refineries have stopped producing fuel in the region — Hess’ 70,000 FCC plant in Port Reading, New Jersey, Sunoco’s 140,000 b/d Eagle Point refinery in Westville, N.J., and the then Western Refining-owned 128,000 b/d Yorktown, Virginia, refinery (all three now serve as terminals) — the net result has hardly been devastating, given that the two Philly biggies stayed online.

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The most recent EIA weekly oil data recorded a record-utilization rate for East Coast refining capacity at 93.8%. And, the total crude processing capacity was 1.293 million b/d. Compare that with the 1.397 million b/d for the week ended July 16, 2010, when the prior utilization rate record was hit at 93.2%. (2010 was the first year this regional utilization data point was tracked in the weekly report.). So, instead of losing half its capacity, the region saw its capacity notch down by all of 100,000 b/d.

East Coast net imports of refined products averaged 1.055 million b/d over the four weeks ending May 10, nearly flat to the comparable period last year. Three years ago that number was around 1.5 million b/d.

Of course, the key indicator for adequacy of supply is inventory. East Coast total motor gasoline stocks rose by 1.805 million barrels to 63.348 million barrels over the reporting week ending May 10, comfortably well above the five-year average. East Coast distillates stocks slipped that week to 35 million barrels, staying in the low-end of their five-year average.

Demand, meanwhile, just isn’t what it used to be. EIA’s latest monthly stats for the East Coast show finished motor gasoline demand in February registered at 2.775 million b/d, which is down 9.28% year on year.

The other key change is the availability of so-called advantaged crude, the domestic supply being railed in from the Bakken. For instance, PBF said earlier this year that it expects to enjoy strong margins from running Bakken and Canadian heavy crudes at its 180,000 b/d refinery in Paulsboro, New Jersey, and its 190,000 b/d refinery in Delaware City, Delaware. Other major regional refineries are preparing to bring in Bakken crude.

All these factors combined in relatively short order to upend the picture. Back when EIA was looking at the East Coast refining sector concerns, there was a fair amount of uncertainty at play, recalls Joanne Shore, the chief industry analyst at the American Fuel & Petrochemicals Manufacturers trade group and a former EIA analyst. The growth of Bakken oil production is exceeding past anticipations and the speed with which rail facilities can be put in place on the East Coast may not have been previously appreciated, she said in an interview earlier this week.

Asked if the companies that chose to stick with or hook into the East Coast refining sector were prescient, she said “they may have been,” adding “these are all sharp business people.”

“This whole situation was evolving rapidly at that time,” Shore added. “It wasn’t clear as to how these East Coast facilities might be able to take advantage of discounted crude and different companies may have seen it differently at that time. It was a time of great uncertainty.”

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At the heart of the latest issue is a plan by Vermont Gas, the state’s natural gas utility, to add a 41-mile extension to its existing 750 miles of natural gas pipelines in the state. The new line would extend service to Middlebury, home of Middlebury College. And that’s where Bill McKibben works.

McKibben is a Schumann Distinguished Scholar at Middlebury. But more importantly, he has become the spiritual and organizational leader of several key anti-fossil fuel movements, including those to stop the approval of the Keystone XL Pipeline, and a push to have colleges divest from their endowments the stocks of any fossil fuel companies. And now, here would come steel in the ground to his place of business, a delivery mechanism built to be long-term, not temporary.

According to this story from a Vermont alternative newspaper (with the usual double entendre play on the word “frack”; aren’t headline writers tired of this infantile behavior?), McKibben and others have not been quiet. They are urging Middlebury to come out in opposition to the project. But instead, the college has backed the expansion known as the Addison Natural Gas Project.

Earlier this month, in a formal statement, the school’s president Ron Liebowitz said Middlebury would support the pipeline expansion. He cited a long list of reasons: lower costs for a big local employer, a supply for a bio-methane project the college is planning, reduced heating bills for local residents,  and so on.

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One interesting aspect to all this is a FAQ page on Vermont Gas’ website which seeks to answer a range of questions. One of the questions regards where Vermont Gas sources its natural gas; all of it is from Canada, according to the answer.

That means it’s coming off the Trans-Canada mainline that runs west to east. It is a line that has seen its throughput drop significantly, as eastern customers both in the US and parts of Canada are being supplied to an increasing degree by natural gas from the Marcellus Shale.

As a result, TransCanada is looking to convert all or some of that line to the transportation of crude. It launched an open season to gauge interest last month. That sets up the possibility that Vermont Gas may ultimately need to deliver to local customers natural gas that increasingly is produced in the Marcellus, whose development has been made possibly only through fracking.

And fracking, of course, is banned in Vermont. However, it needs to be noted that there are not believed to be shale deposits in the state that would be the site of any drilling, so it may be an empty gesture in practical terms. But the move still represents the state’s verdict on the safety of fracking.

To add to the head-scratching, there’s a second extension on the line that would shoot under Lake Champlain to a paper mill in New York state, where the mill’s owners are eyeing millions in energy savings. So an employer in New York state would benefit from the pipeline and the fracking-produced gas carried in it. New York, of course, has a temporary ban on fracking that Gov. Andrew Cuomo appears in no rush to lift.

The Vermont Gas Q&A does address the fracking issue, noting that some of its gas indeed may have been produced from fracking. Fracking isn’t unique only to shale plays; conventional wells can be fracked, and the technology has been around since the 1940′s. What the Q&A doesn’t say, but what almost certainly is the case, is that the percentage of natural gas Vermont Gas will deliver that comes as a result of fracking from shale plays, displacing Canadian crude, is going to rise.

Oh, what a tangled web we weave.

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They are thinking about getting rid of the controversial production tax credit for wind and also thinking about keeping it for a very long time. They might take up a carbon tax, they might not and they might raise the federal gasoline tax, or lower it. It’s really unclear at this point.

While it’s far from certain that Congress will even take a serious crack at tax reform in the near term, it’s certain that many energy-related changes will face heavy criticism and extensive lobbying. In fact, some proposals, such as a carbon tax or elimination of oil and gas tax breaks, may face such staunch opposition that it’s a safe bet they’ll never even come before Congress for a vote.

But if you read all the details on the initial proposals that the House and Senate committees charged with tax policy are considering for the upcoming tax reform debate, it’s clear that pretty much all options for energy tax policy will be considered in some way.

In a 15-page paper released by the Senate Finance Committee late last month, dozens of options for revamping tax policies that have long applied to electricity generators, oil and gas drillers and other players in the energy sector were kept on the table.

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Recommendations called as giving businesses more regulatory “certainty” and making federal subsidies “fairer and more efficient,” but there were few specifics on how the more than 40 energy-related provisions in the US tax code would be changed.

For example, one option outlined in the paper calls for the elimination of all existing tax credits for the entire US energy sector, including the expensing of intangible drilling costs for oil and gas companies, as well as the investment and production tax credits that renewable-energy developers currently enjoy. Another calls for making certain energy tax credits, such as the alternative electricity production tax credit and credits for energy efficient home retrofits, permanent. Another calls for repealing the wind PTC and solar ITC and replacing them with credits for expensing or accelerated depreciation.

Richard Caperton of the Center for American Progress, a left-leaning Washington think tank that has strong ties to the Obama administration, said the purpose of the paper was clearly to let Congress know what options they had for reforms going forward. “I think Congress is laying out the options for what they can do, and then they’re going to decide what they want to do,” said Richard Caperton, the think tank’s managing director for energy.

The Senate Finance Committee is chaired by Max Baucus, a Montana Democrat, who has announced he will not seek reelection in 2014. Baucus has identified tax reform as a priority before leaving the Senate.

Earlier this month, the House Ways and Means Committee released a 558-page report which summarized current tax laws and suggestions for reforms, outlines dozens of potential changes to the federal tax code for oil and gas production, credits for wind and solar productions and tax structures for renewable energy projects.

The report examines suggestions made to 11 separate working groups, including the Working Group on Energy, which is chaired by Representatives Kevin Brady, a Texas Republican, and Mike Thompson, a California Democrat.

These suggestions include keeping various tax preferences for oil and gas companies such as the enhanced oil recovery credit, the deduction for intangible drilling costs and the percentage depletion deduction in place. Other comments suggest eliminating these preferences entirely. Other suggestions include eliminating or extending the production tax credit for renewables, including wind and solar. Others called for extending this PTC to cover waste heat, biogas, renewable chemicals and other bio-based products.

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Commodities trading, it seems – and in particular oil – is not for the faint of heart. The field is littered with failed ventures and prison sentences.

International sanctions on exporting countries such as Iran can make trading crude an even more dangerous game. On May 9, the US Treasury said it was penalizing Sambouk Shipping for contravening these sanctions. Sambouk is allegedly associated with Dimitris Cambis, who, along with a network of front companies, was executing ship-to-ship transfers of Iranian oil to obscure its origin.

Getting access to less-than-transparent sources of oil, metals, grains and other commodities has become more hazardous as the US Department of Justice and Securities and Exchange Commission begins to aggressively enforce the Foreign Corrupt Practices Act (FCPA). Archer Daniels Midland became the first commodities trading house to suffer under it.

Because of the global importance of commodities such as oil and foodstuffs, the commodities markets have become a target for public criticism regarding manipulation, bribery and corruption.

So much so that Switzerland, the go-to location for commodities trading houses over the past ten years, is fretting that it will suffer reputational damage because of its newish role as a trading hub. Switzerland is home to the world’s biggest oil and other commodity trading houses, including oil traders Vitol, Glencore, Trafigura, Mercuria and Gunvor.

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In a world where deep knowledge, hands-on experience and extensive personal contacts are necessary to do a deal, even those at the top of their game can get into hot water or lose money.

So it is not surprising when Wall Street and City of London hedge funds miss the boat. Trading paper contracts, such as energy futures and derivatives, can be difficult when you don’t have an insider’s view into the physical movements of oil.

What is surprising, perhaps, is that some of the mega-importers of oil have not succeeded in entering the oil trading game. After all, purchasing vast quantities of crude oil and products should theoretically teach importers some of the tricks of the trade.

But many new entrants apparently fail to grasp the basics of the oil trading culture. One recent example is PetroChina. It hired a small staff of traders and operations people in Houston in 2008, with the aim of increasing the Chinese company’s US trading volumes and growing the Houston office.

Last week, a team of six of its Houston oil traders (and reportedly some support staff) left the Chinese oil company en masse, allegedly because promised bonuses were not paid.

The oil trading game is difficult, dangerous and often loss-making. But there is one caveat that remains true: If a company wants its staff to take the risks involved, it should be prepared to make it worth their while.

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–David Fyfe, the head of market research & analysis at Gunvor Group, said he didn’t want to be a downer. And he did say that he thought the shale revolution was a “game changer.”

But in a panel about the US shale industry (full disclosure: I moderated the panel), Fyfe said there are a “cluster of factors that could limit the pace of growth over the next five to seven years from light, tight oil.”

None of the factors Fyfe cited are particularly new. They’ve all been discussed in one form or the other. But laid end-to-end, as Fyfe did, presents the hurdles all in one place.

His primary focus was on what might be likened to having grabbed all the low-hanging fruit. “This is not a source of supply that is heavily capital-intensive at the front end,” Fyfe said. “But it is a new source of supply that requires continuous spending to keep drilling, keep drilling, keep drilling, thousands and thousands of wells every year.”

It’s the unique characteristics of shale plays that have been well-known: drill a hole in the ground, frack it, and copious amounts of natural gas and petroleum liquids are going to come to the surface if a company has drilled in the right spot. But it doesn’t last; the decline rate is about as steep as the drop in Lance Armstrong’s reputation. “Whether it’s the Eagle Ford or the Bakken, you lost 60-70% productive capacity in the first year,” Fyfe said. “And if we’re in an environment where WTI risks dropping below $70/barrel, it starts to get sort of interesting for light tight oil.”

Many of the best spots already have been drilled, Fyfe said. “The highest yield and easiest to tap resources have been prioritized,” he said. There are technologies that could help lower costs, but still, Fyfe said, it’s inevitable that lower-yielding plays are going to start coming online. “You have sort of an offset where drilling costs per barrel actually go up to a certain extent.”

Another panel member, Amrita Sen, chief oil analyst at Energy Aspects, also issued some caution, noting that geologic data for shale plays is far less reliable than those for conventional plays.

“Generally even the geologists do not know the composition of these rocks,” she said. “We cannot think of tight oils in the same way as we do about any conventional basin. So to come up with predictions that yes, production growth is going to be 5-6 million b/d, we need to be a little cautious with that.”

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Continuing in the same vein — production is on the way up, but that doesn’t mean it doesn’t come without issues — the problems that Iraq will face as it ramps up output were the focus of the comments of the two members of a separate panel.

Chaired by Platts Director of Oil Dave Ernsberger, the panel appeared to assume that while the most optimistic projections of Iraqi output, which exceeds 10 million b/d, were probably overly optimistic, production rising to the 6-8 million b/d level by 2020 was possible. (Platts estimates that Iraq produced 3.15 million b/d in April.)

Shawki Nuruddin al-Khalisi, senior adviser to the Organization of Arab Petroleum Exporting Countries and a former consultant to Iraq’s oil ministry, ran through his list of possible stumbles. As Iraqi production rises, its medium-gravity API for current output will certainly get heavier, he said. Some sort of blending or upgrading that might take a 10 gravity crude up to a 30 would be economically justified by the differentials the market would give to that much of a difference, he said. Another issue: with the northern pipeline to Ceyhan the target of frequent bombings, the only reliable route is through the port of Basra, which means shipments are all vulnerable to the problems of the Persian Gulf. (And infrastructure at Basra is inadequate.)

The other panelist, Luay al-Khatteeb, CEO and founder of the Iraq Energy Institute, discussed the problem of the huge amount of gas that Iraq is required to flare, as 75% of the country’s natural gas output is from associated gas produced with crude oil. He estimated the amount at 1 Bcf/d, so $2 billion to $3 billion day was being wasted, a figure that doesn’t begin to approach the value of the natural gas as a component or fuel for a higher level of manufacturing.

But for the both of them, where Iraq will sit in OPEC as its output rises is the key issue. No country in OPEC has a published individual quota; it’s now a group target. But unless the call on OPEC crude rises, which virtually no analysts sees happening to any significant degree for at least a year, rising Iraqi output will put stress on the group.

If Iraq output gets to 8 million b/d, Khatteeb said, “the only way to market that much is to pressure other OPEC members to cut their production.” The alternative is to keep production at about 5 million b/d as spare capacity, “which would be suicidal.” And with the Iraqi regime desperate for funds, if OPEC needs to cut output, Khalisi said, “if Iraq feels it needs the money, it may not apply” to be part of that output-cutting effort.

One extra note: a separate panel on exploration “hot spots” came to the conclusion that not a lot of these so-called hot plays were actually yielding much in terms of significant new output, save the US. Tying it to the Iraqi discussion, it may be that the world is going to need enough OPEC output down the road that making room for Iraq won’t be as big a problem as the Iraq panel warned.

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Crude coming off the Eastern Siberia Pipeline may not become the next big benchmark in oil markets, according to Arsenije Dusanic, an energy market analyst with JBC Energy. ecause while Russia has indicated it wants ESPO crude to be a benchmark, it may not want to put enough crude into the market to make it happen. China’s a better market than exporting it through the Pacific port of Kozmino.

The ESPO line has gone from an initial 600,000 b/d to 900,000 b/d, Dusanic said. But eastern Siberian production hasn’t kept pace, he added, so shipments on the line are only up to 700,000 b/d.

But eastern Siberian output will hit 1.2 million b/d by 2020 from 800,000 b/d now, he said, yet he still expects a lot of that growth to go to China through a spur into that country. The netbacks are better. By depriving the Kozmino export port of some portion of that supply, Dusanic said, it hinders the ability of ESPO to become a regional benchmark for Asia.

There’s another reason, he said: Russia itself. Traders will always be reluctant to tie a crude formula to a Russian benchmark that can suddenly be jerked around by political decisions in the Kremlin. Besides, he added, Dated Brent has become enough of a global oil benchmark for transactions far from the North Sea that another benchmark may not be necessary.

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It’s an enviable position for a state’s government — not only to be rolling in dough but having more dough to roll in than your wildest dreams.

The state of North Dakota, which began contributing to its newly-created Legacy Trust Fund from oil and gas taxes in July 2011, has already exceeded by 63% its initial target of having $618 million in its coffers by mid-2013 — thanks to the state’s seemingly bottomless Bakken Shale oil field.

The Fund, which collects 30% of the state’s oil and gas revenues, is now tilting toward a revised target of $1.2 billion by this July. As of February 28, the Fund contained $1,005,676,512, Darren Schulz, interim chief investment officer of the North Dakota Retirement and Investment Office, said.

“Our cup runneth full right now,” Schulz said. “It’s a good problem to have.”

Although companies seem to want nothing more than to continue drilling and producing oil from the Bakken, where the gift that keeps on giving registered 779,000 b/d of production for February, the state’s revised revenue target stems from a slightly raised oil price forecast, Joe Morrissette, management and fiscal analyst at the North Dakota Office of Management and Budget, said.

“There’s a commission on revenue forecasting and they’re pretty conservative,” Morrissette said. “They’d rather have revenues come in higher than be short.”

From the projected $1.2 billion target as of June 30, 2013, state officials now project the Fund to contain $2.983 billion exactly two years later, he said.

Commission forecasters based the original $618 million target on $67/barrel oil for July 2011 and targeted a price of $75/b by June 30, 2013, at the end of the biennium, Morrissette said. For the next two years, “our new forecast is still pretty conservative—about $75/b for the first year and ends the next biennium at $80/b” on June 30, 2015, he said.

That is the North Dakota crude price, which Morrissette said is a “little lower” than the West Texas Intermediate price. The Bakken Ex-Clearbrook price was $91.42/b on May 9, while WTI was $95.96/b, according to Platts assessments.

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What’s a state to do with all that money? North Dakota officials say the fund cannot be touched until 2017, after which its interest can be tapped each year, along with up to 15% of the principal if the state legislature permits.

The state in recent years has seen a huge revenue boon from the Bakken Shale, one of the US’ largest oil deposits, and the Legacy Fund should continue to grow in lockstep with Bakken production, state officials say.

However, a bill has been passed to have a state legislative team study an assortment of proposals for spending the money, said Schulz. “It’s currently undefined,” he said. “There’s an initiative underway to try to develop a formal target for spending in the future.”

He said the team will likely look at how other states with similar “rainy day funds” have used their monies, such as devoting it to higher education, public works projects or social programs.

From its inception until now, Schulz said, the Legacy Fund has earned annualized return of 1.62% on its money, which is invested in short-term bonds with JP Morgan and Babson Capital as managers. But last month, Schulz’ office approved a new asset allocation policy, based on the recommendation of an independent consultant, that should bring in a higher yield.

Now the investments will be split between fixed income assets, domestic and non-US equities, diversified real assets like infrastructure and timber and Treasury Inflation Protected Securities and real estate. The Retirement and Investment Office will start phasing that in during the next month, said Schulz.

“Given the long-term nature of the fund, it’s a sensible…allocation that would protect and grow” it, he said.

North Dakota’s 779,000 b/d of oil on average in February 2013 was a 39% jump from its 559,000 b/d of average production in the same month in 2012, according to the US Energy Information Administration, the research and statistics arm of the US Department of Energy.

The state’s oil production should be at 1 million b/d by April 2014, and by January 2020 should be at 1.553 million b/d, according to projections supplied by Bentek, a unit of Platts.

Meanwhile, for trivia-lovers, here are some fun facts on North Dakota’s Bakken Shale, straight from the state’s Department of Mineral Resources.

A typical 2012 Bakken well will produce for 45 years. In those years the well will:

• Produce about 665,000 barrels of oil
• Generate over $23 million net profit
• Pay nearly $4.3 million in taxes
• Pay royalties of $8.2 million to mineral owners
• Pay salaries and wages of $2.1 million
• Pay operating expenses of $2.3 million
• Cost about $9 million to drill and complete

–Starr Spencer in Houston

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