Sometimes a news item informs us about much more than the event in question. I think the recent announcements of new petrochemical projects in the US fall into that category. Both Shell and Dow Chemical are planning new ethylene crackers in the US, a market in which established ethylene facilities were being shut down only a few years ago, as part of the demand destruction necessary to balance natural gas demand with shrinking US supplies. Anyone looking for further indications of the game-changing nature of shale gas need look no further than these projects. Yet they also give us intriguing hints about two other situations of great interest: global oil prices and US economic growth.

The Shell project is of particular interest, because of its location. The company is apparently planning to locate it in Appalachia, where it will depend on the byproducts of natural gas produced from the giant Marcellus shale deposit. Considering that most of the other ethylene crackers in the US are located on or near the Gulf Coast, where gas can be supplied from numerous onshore and offshore fields, that’s a remarkable endorsement of the potential of the Marcellus. You just wouldn’t leave such a facility dependent on one gas field if that field weren’t both very large and likely to be producing for a very long time. Anyone suggesting that shale gas is a flash in the pan should look long and hard at this project, as I’m sure Shell has done.

It’s also worth pausing to recall the way Shell approaches projects like this. Shell is one of the pioneers of scenario planning, and its business plans are all based on its periodic, carefully developed views of different potential futures. I wouldn’t assign some notion of infallibility to this; Shell has made its share of mistakes in the last decade, too. However, it does suggest that the company’s decision to invest in this project wasn’t just based on a straight-line extrapolation of current conditions. Deciding to build an ethylene cracker, a facility that turns the heavier components of natural gas into one of the basic building blocks of the petrochemical and plastics industry, in such a location is a big vote of confidence. It suggests that Shell has concluded that the current uncertainties facing shale gas development are very likely be resolved without undermining shale’s capacity to produce large quantities of gas at relatively low cost, and that shale developers will find ways to resolve concerns about fracking, methane emissions, and other issues both with the affected communities and with state and national regulators.

These projects also suggest at least two other things. First, as the Reuters article noted, they represent sizable wagers on the relationship between the global price of oil and the US price of natural gas. I’ve commented before on the extraordinary divergence between the two, with oil bouncing around the $100 per barrel mark and US natural gas selling for the energy equivalent of $25 per barrel. A company would be unlikely to make a long-term investment like this if it thought gas and oil were likely to move back into parity any time soon. Even if gas prices eventually recover to around $6 per million BTU, as suggested by current long-dated gas futures, that’s still the equivalent of less than $40/bbl–an oil price we haven’t seen since the worst stretch of the global recession and financial crisis in early 2009.

And that leads to the last implication I draw from this news: these investments are bets on the health of the US economy. If the economy were headed for a protracted period of slow or no growth, adding petrochemical capacity here would be too risky, rather than putting it in the Middle East, where gas is even cheaper and the growing markets in Asia are much closer. That doesn’t’ mean that our problems of high unemployment, high indebtedness, and gaping federal, state and local budget deficits aren’t extremely challenging, but it provides at least one modestly positive sign among the many ominous ones that are routinely amplified by the basic nature of the news media business.

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What New Ethylene Crackers Tell Us is news story from: News and Stories from Energy Editor

I see that the administration has decided to release 30 million barrels of oil from the US Strategic Petroleum Reserve, in coordination with a matched release from the strategic stocks of other OECD member countries of the International Energy Agency (IEA.) The release will be spaced over the next month, though it’s not clear how soon it can begin, since it should take at least a few days to line up the requisite buyers, sign contracts, and schedule pipeline space. Politicians who have been calling for such a release to punish speculation in oil futures and alleviate pressure on consumers are crowing, and the oil markets have responded by dropping $5-6 dollars per barrel. As welcome as this will be for consumers, it is simultaneously a drop in the bucket and an unwelcome precedent for the future stewardship of these emergency reserves.

As I noted when I assessed the outcome of the recent OPEC meeting, oil inventories aren’t unusually low, and the current shortfall in global production compared to demand will take a while to develop into a problem. I suspect the main concern behind the IEA’s decision to release stocks now, rather than waiting for a true physical shortfall to materialize, is the mismatch between the quality of the Libyan and Middle Eastern oil that has been taken off the market as a result of the ongoing turmoil of the ” Arab Spring” and that of the OPEC spare capacity available to fill in for it, mainly in Saudi Arabia. In this context, the US SPR release looks more like an expression of solidarity with its EU partners, for whom the Libyan shortfall is much more significant, than a direct assault on the market.

Nevertheless, the concerns I expressed in my posting of June 2nd regarding a smaller ” operational” release from the SPR apply to this release, as well. The SPR doesn’t exist to game the market, especially not for political purposes. It’s there in case of a serious interruption in supply, the scenarios for which are numerous and unfortunately not very hard to imagine for either us or the potential perpetrators.

Perhaps an extra 2 million barrels per day will alter the psychology of the futures markets and catalyze a larger price drop than we’ve seen today. By itself, that seems unlikely. Because it’s a temporary measure, the market will want to know what comes next, and that’s the real problem. Unless the designers of this program have made a lucky choice and timed their release to coincide with a further easing of prices due to weakening demand, the calls for another release will start in a month, if prices remain at a level deemed high enough to threaten the economic recovery. Selling off 4% of the SPR in the absence of a real emergency–and with no clear plan for replacing it–might not be a big problem, but additional releases that added up to a substantial portion of the reserve would be. Let’s hope we don’t have cause to regret this.

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SPR Release Catches Market Napping is news story from: News and Stories from Energy Editor

Despite its frequent use in policy and other discussions, ” energy security” lacks a single, fixed meaning, and the consensus on its definition seems to be in flux. As an outgrowth of the oil crises of the 1970s, it has usually been associated with the economic, defense and geopolitical implications of imported oil and petroleum products, focused mainly on security of supply. It was often seen as a more nuanced term than energy independence. Over time, it has taken on other connotations, including the financial impact of imported energy. However, an even more recent trend to incorporate climate change and other sustainability concerns into energy security bears careful consideration, because it can sometimes lead to a direct conflict with energy security’s most basic aspects. When I see advocates of a renewable electricity technology like solar power touting its energy security benefits, I can’t help wondering how carefully they’ve thought through that claim, especially in light of the significant energy changes arising from the shale gas revolution.

A blogger conference call hosted by the American Petroleum Institute last week got me thinking about this topic again. Based on API’s analysis, increased access to US oil resources that are currently off limits for exploration and development, together with approval of the Keystone XL pipeline to bring in more Canadian crude–including synthetic crude from new oil-sands projects–could dramatically reduce US oil imports. Imports from countries other than Canada could fall from 38% of our supply in 2010 to just 8% by 2030. Their assessment builds on a US Department of Energy forecast that already incorporates improvements in vehicle fuel economy and the expected contribution of oil shale resources such as the Bakken Shale in North Dakota and Montana. In API’s resulting scenario, US oil production would increase by 4.8 million barrels per day (bpd) and domestic biofuels output would grow by 1.9 million bpd, along with an extra million bpd of imports from Canada. That combination would shrink our net non-Canadian imports of crude and petroleum products from 7.2 million bpd last year to just 1.8 million bpd in under 20 years.

However one views the potential environmental consequences of the steps necessary to achieve such an outcome, that would be a stellar result under the most commonly used definition of energy security. That’s because these actions would directly replace imported oil and products, barrel for barrel, with supplies from more stable and dependable countries–including our own–as an extension of one of the main energy security strategies we’ve employed since the 1970s. Assessing the energy security benefits of some of our other options is less clear-cut, particularly when it comes to the generation of electricity from renewable sources.

Consider today’s most familiar renewable energy projects, wind farms and rooftop solar installations. Both reduce greenhouse gas emissions, but do they also enhance energy security? The answer depends on where they are installed and how their output is used. If the venue is Europe, which imports large quantities of natural gas, or Japan, where the post-Fukushima electricity shortage is leading to significant increases in imports of fuel oil and liquefied natural gas (LNG), it’s clear that they do. But the answer isn’t as obvious in the US, where the generation they displace is mainly fueled by coal–a domestic resource–or natural gas. Prior to the explosion of domestic gas production from shale resources, it was much easier to argue that displacement of gas from a peaking gas turbine power plant backed out imported LNG somewhere and thus bolstered energy security. Today, with most gas coming from domestic wells and with most renewables relying on gas-fired backup power, that assertion is becoming a stretch.

Making the case for energy security benefits from wind and solar on the basis that they can back out oil imports by powering electric vehicles looks like even more of a stretch. This notion might be true in the 2030 time frame of the API scenario described above, by which time I’d expect to see many more EVs on the road, along with a smarter power grid capable of channeling the output of renewable power generation into EV recharging. In the nearer term, however, there simply won’t be enough EVs on the road to substantiate such a claim. In fact, it would take more than 23 million EVs like the Nissan Leaf to consume the output of the wind and solar installations already in place last year. And in most locations, the EVs coming to market will be recharged mainly with average grid electricity, which includes a significant contribution from coal, even in California, thanks to that state’s sizable electricity imports from neighboring states.

Resorting to such contingent and indirect claims of enhanced energy security sets up a debate that only liquid biofuels are currently positioned to win. However, it seems equally unrealistic to adhere to a definition of energy security that ignores the many ways in which our perspective on the world has changed in the last decade. I wasn’t surprised to find a definition of energy security from within the US military incorporating sustainability along with sufficiency and surety. In effect, sustainability represents a new, albeit self-imposed, risk on the security of supply for conventional fuels that we’re less accustomed to considering. It can also cut both ways, leaving some renewables, such as food-based biofuels, vulnerable under a definition of energy security that includes this metric.

Our notions of energy security are moving into a 21st century context, as they begin to recognize factors beyond supply and demand. That seems appropriate. At the same time, the term should still convey the pragmatism that gave rise to this concept in the first place. The traditional view of energy security never constituted a trumping argument in US energy policy, or else we wouldn’t be sitting here with so many billions of barrels of technically recoverable resources off-limits to exploitation because of worries about the possible effect on beaches, tourism, wildlife and a myriad other concerns, broad and narrow. Similarly, a greater inclusion of sustainability aspects into our view of energy security should not be expected to disqualify efforts like the Keystone XL pipeline or expanded access to hydrocarbon resources. Even if such endeavors must also demonstrate their soundness on other criteria, they would unquestionably leave the US more secure in its energy sources. Instead of pitting one view of energy security against another, I’d prefer to see a scenario for 2030 that incorporates more access to North America’s liquid fuel resources, together with expanded efforts on energy efficiency, transportation energy diversification, and creative capitalization on our new-found natural gas wealth–all of which would enhance US energy security.

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How Do Renewables and Oil Sands Affect Energy Security? is news story from: News and Stories from Energy Editor

A poll reported in this morning’s Wall St. Journal (subscription) indicated that more Americans are significantly affected by high gas prices than by rising food prices, falling home values, unemployment or foreclosures. That’s a surprising result, considering that transportation fuel only accounts for about 5% of average household expenses. However, gasoline has one of the most visible prices in our society, and the scale of our fuel use is such that price increases of the recent magnitude aggregate to a very large total. Based on year-to-date prices and compared to a more typical year like 2006, the drag on the US economy is running between $100 and $150 billion for 2011, reversing any ” gasoline stimulus” we received in 2009.

As of the latest price report from the Department of Energy’s Energy Information Agency, the national average price for unleaded regular gasoline has dropped back to $3.71 per gallon from its May peak of just under $4. Despite that, it’s still more than a buck higher than this time last year. In fact, until a couple of weeks ago gas prices were trending well above their path in 2008, when prices reached an all-time high of $4.11/gal. that July. (See above chart.) When I compared this year’s prices to those in 2006, which averaged only about 20 cents per gallon lower than last year’s but exhibited more normal seasonality, and then multiplied by the more than 137 billion gallons of gasoline the US is likely to consume this year, the total drag on the economy worked out to between $100 and $150 billion on a full-year basis. (See chart below.) If these prices persisted, that would be enough to negate the effect of the entire 2% cut in Social Security taxes for 2011.

Fortunately, barring an escalation of the current supply disruptions in the Middle East, a major hurricane affecting Gulf Coast refinery operations, or an unexpected surge in economic growth, we’ve probably either already seen the peak gasoline price for the year or are within a few weeks of it. The outcome of last week’s OPEC meeting, while not as bearish for prices as an agreement to increase quotas and output would have been, has had little lasting effect on oil prices, which are running at a level consistent with this week’s US average pump price or a bit less. However, no one should confuse a seasonal easing in prices with a permanent return to cheaper gas. Short of another global economic crisis, global oil supply and demand remain closely enough matched that any hiccup will quickly translate into higher prices at the pump. I feel safe in predicting that we’ll be flirting with $4 again before long, and the consequences of that should be factored into any forecasts of future economic growth.

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Gasoline Could Cost Consumers an Extra $150 Billion in 2011 is news story from: News and Stories from Energy Editor

A Turkish developer recently announced that it would build a new power plant using technology from GE that matches wind and solar generation to the output of a highly responsive natural gas turbine, all integrated in one package with the hardware and software to mesh its output with the grid. GE is apparently calling this scheme IRCC, for ” integrated renewables combined cycle” , adding yet another acronym to our growing list of energy choices. This development looks interesting from a technical perspective, but also for what it suggests about GE’s view of the future market for generating equipment and power delivery.

The International Energy Agency’s ” Golden Age of Natural Gas” scenario remains a question mark, rather than a certainty, but if gas is to serve as the key fuel for bridging between our high-emission present and the low-emission future, then we’re likely to see more installations like the one in Turkey emphasizing the synergies between gas and renewables, rather than the tough competition gas is giving renewables in some markets. The IRCC–not to be confused with an IGCC or the IPCC–is interesting because it goes well beyond the idea of using gas-fired power plants to back up the naturally variable output of wind farms and utility-scale solar arrays.

The IRCC concept is built around a new combined cycle gas turbine, the Flex-Efficiency 50, with an impressive capability to ramp up and down, as needed, with minimal loss of either efficiency or emissions performance. And thanks to the energy technology portfolio the company has built up over the last decade, GE is able to offer one-stop shopping with GE wind turbines and a solar thermal generating module from eSolar, in which GE has recently invested. The gas turbine/solar thermal hybridization looks especially useful in maximizing plant efficiency and incorporating solar thermal power into the grid at the lowest possible cost, by avoiding the expense of an extra steam turbine and generator. If all this works as advertised, the grid operator shouldn’t know or care whether the power being dispatched was generated using wind, sun, or gas.

Before you confuse this posting for a GE ad, I should note that at least in the configuration chosen for the Turkish site most of the power from this integrated plant would still be generated by the gas turbine, which has 10 times the peak output of the concentrated solar power module and more than 20 times the rated power of the small wind farm tied into it. By the time you account for the capability of the gas turbine to run 24/7 when necessary, compared to typical capacity factors of 25-40% for wind and up to 25% for solar, the proportion of the IRCC’s annual megawatt-hours generated from gas could exceed 95%. Nor is GE the only firm bringing turbines like this to market. So it’s an impressive step, though more of an incremental than revolutionary one. However, with its inherent flexibility, I wouldn’t be surprised if this type of gas turbine could effectively integrate a much larger quantity of renewable generation on the grid outside the IRCC’s fence, particularly after the operating experience of the first few installations has been absorbed.

GE’s timing in introducing its IRCC concept could prove especially apt. Not only does the Flex-Efficiency turbine look useful for helping to meet California’s aggressive new 33% renewable electricity target, but the 50-cycle version featured in GE’s marketing materials–likely minus the solar thermal module–could be just what Germany needs, now that its government has begun to come to grips with the quantity of new fossil generation that’s going to be required to make up for the post-Fukushima accelerated retirement of its nuclear power plants.

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Marrying Gas and Renewables is news story from: News and Stories from Energy Editor

Yesterday’s meeting of OPEC in Vienna attracted extra attention because of disagreements between Saudi Arabia and Iran that extend well beyond the oil fields. The resulting impasse over increasing production to stem high oil prices and support a weakening global economy produced a much-quoted assessment from the Saudi Oil minister, Ali Naimi, who described it as ” one of the worst meetings we ever had in OPEC.” Yet while the events in the Middle East were at the forefront for most commentators, the outcome of the meeting seems understandable purely in the context of OPEC’s own history and the current fundamentals of the market. I’m not sure why so many people appeared to expect OPEC to boost output in anticipation of demand that might not materialize.

I have followed OPEC meetings for nearly 30 years, though not always as closely as when I was trading oil and its products, the prices of which stood to rise or fall depending on what was decided in Vienna. My interest in this meeting went up significantly when I received a call inviting me to participate in a panel discussion about it on the Voice of Russia radio network yesterday afternoon. An hour or two of research revealed a global oil market that is currently well-supplied, with inventories in most developed countries running at fairly typical levels and inventories in the US actually on the high side of normal for this time of the year. That’s pretty much the argument that OPEC’s price hawks took into yesterday’s session.

However, the Saudis and others arguing for higher quotas were looking ahead to the effects of summer demand, especially in rapidly growing Asia, and the buildup of inventories for the fall and winter heating fuel season. They–along with the IEA–anticipated demand growing faster than supply, particularly when the impact of the curtailments from Libya and Yemen are factored in. Such events are important because of the quality difference between the oil that’s been shut in in those countries and the spare capacity elsewhere that’s available to make up for it.

OPEC’s main problem is that the outlook for the global economy has weakened in the last few weeks, and not just because oil has risen to above $115 per barrel, compared to its average of $80 or so last year. The stakes for them look even higher when you factor in a history that includes boosting production in the late 1990s to meet roaring demand in Asia-Pacific, only to see the Asian Economic Crisis slam demand growth in the region into reverse, sending crude prices tumbling from the $20s to single digits by the end of 1998. The doves within OPEC were focused on keeping prices below the level at which large chunks of demand were destroyed in 2008, while the hawks seemed willing to risk that outcome to avert a future price collapse and preserve the revenue they need to fund their national agendas.

The potential consequences for individual OPEC members are substantial. Consider Algeria, which exports about 1.8 million barrels per day. The difference between the current price and what they realized last year equates to more than $20 billion annually. That might sound small in the context of the current debate over trillion-dollar US deficits, but it’s nearly 15% of Algeria’s GDP. It’s no wonder that smaller producers and others with limited capacity to increase output–and thus revenue–would drag their feet on agreeing to raise quotas for countries with spare capacity.

If it sounds like I’m rationalizing cartel behavior that would be illegal in the US, that’s not my intent. It’s clear to me that oil prices are significantly higher than they would be, because OPEC has chosen to produce around 2 million barrels per day less than it did in 2008. In part they’ve had to do that to accommodate higher non-OPEC production–think Brazil and Russia–along with rising biofuel production, without weakening prices. The consequences for US consumers are equally clear: Gasoline prices are still more than $1 per gallon higher than a year ago, and even ignoring the impact on diesel or jet fuel that translates into an additional drain of $100-150 billion per year that can’t be spent on other goods and services that would contribute more to the recovery.

OPEC meetings do matter, because as long as OPEC possesses both spare production capacity and the discipline to withhold it from the market, it retains the power to control oil prices. If we want to understand the decision process of this group of countries that is always struggling to reconcile its own often-competing, but still broadly aligned self-interests, our assessment should focus on their issues more than ours, however much we are affected by the outcome. Yesterday we saw the price hawks stymie the efforts of those producers who are worried that if they squeeze consumers too hard, demand will fall back to the lows of 2009, costing them hundreds of billions of dollars per year in revenue. But if demand continues to grow, that was surely not the last word, and this debate must be revisited within a few months.

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Do OPEC Meetings Matter? is news story from: News and Stories from Energy Editor

A regular reader of this blog kindly sent me a link to the International Energy Agency’s new study on global natural gas, to which he contributed. The report, entitled, ” Are We Entering A Golden Age for Gas?” was launched with a press conference yesterday in London. It presents a scenario in which gas use grows rapidly due to faster demand growth, particularly in the developing world, increased supply from unconventional sources such as shale gas, and a slower expansion of nuclear power in the aftermath of the Fukushima Daichi accident. Its key findings envision gas providing 25% of world energy by 2035, up from 21% today, and eclipsing the share of coal before 2030, with corresponding benefits for global greenhouse gas emissions.

The IEA’s presenters were careful to point out that they are not proposing this view as the likeliest scenario, but as an offshoot of their primary World Energy Outlook scenario published last fall, which incorporated the commitments at the Copenhagen climate conference. The new gas scenario depends on a number of uncertainties, including the resolution of some of the concerns about the environmental impacts of unconventional gas production, along with the realization of carbon-intensity and gas-development targets in places like China. However, it doesn’t depend on new technology or dramatic changes such as a massive move to natural gas for vehicle use. (The latter is presented as a ” High Impact Low Probability” sensitivity.) Its big shifts occur in the big existing gas market segments, for power generation globally and for industry and buildings in the developing world.

I was struck by several elements of the scenario. First, although much of the focus on unconventional gas has been on North America, where many of the techniques were pioneered, this is very much a global story. The IEA shows estimated unconventional gas resources from shale, ” tight gas” and coal-bed methane that exceed conventional gas resources in Asia and Africa and rival them even in Eastern Europe/Eurasia. On the strength of its unconventional resources China could become the world’s third-largest gas producer by 2035, behind Russia and the US. So even if the US plaintiffs bar attempts to turn ” fracking” into the next tobacco or asbestos, unconventional gas exploitation will likely progress elsewhere. At the same time, increases in conventional gas production are expected to exceed those from unconventional sources, by 60/40 over the period studied. That requires big increases in LNG production in Australia and a substantial increase in pipeline capacity linking Russian and Central Asian gas to markets in Europe and Asia. It’s also worth noting that despite the shale gas bonanza, the IEA doesn’t envision the US becoming a net gas exporter.

As one of my mentors frequently reminded me, natural gas doesn’t get developed without a market, and in this scenario the biggest source of new demand is in power generation, where the combination of lower gas prices and the 60% thermal efficiency of combined cycle gas turbines makes gas highly competitive, even with coal. It’s less clear whether gas is taking market share from new nuclear based on price, or mainly filling the gap that the response to Fukushima is leaving in some markets. From what I heard on a power industry webinar yesterday, the former is a significant factor, at least in the US. The strong connection between gas and power is another reason why so much of the growth in gas demand–80% by the IEA’s estimate–is expected to occur in developing countries including China and India, where electricity demand is expanding at rates that the US and Europe haven’t experienced for years or decades. Perhaps the most startling forecast in the report is that China’s gas demand could grow from roughly matching Germany’s today to about the level of the entire EU in 25 years. That would be supported as much by additional imports as from domestic unconventional gas output.

As I’d have expected, the IEA provided a sober assessment of the environmental implications of their scenario. Increasing the share of gas in global energy demand reduces global GHG emissions by 160 million tons of CO2 equivalent by 2035–less than 1% of total emissions–by substituting for coal and some oil. That’s a lot less than if the extra gas didn’t also contribute to higher energy demand by keeping electricity prices lower, while outcompeting some lower-emission renewables and nuclear projects. The IEA states plainly that relying on more gas is not a silver bullet for climate change, although it is a positive step.

In addition to pointing out the need for safe handling of the fluids involved in hydraulic fracturing, the report also specifically addresses the critique of Howarth and others concerning the direct emissions from shale gas production. The IEA found that CO2-equivalent emissions for shale gas from well to burner exceed those for conventional gas by 3.5%-12%, depending on whether the methane liberated during well completion is captured, flared or vented to the atmosphere. Even at the high end, that does not negate gas’s emissions advantage over other fossil fuels, especially when power generation efficiencies are factored in. The report’s authors apparently see most of the excess emissions compared to conventional gas production as representing an opportunity that can be captured with current technology and best practices.

The IEA put a price tag on this shift to gas: a cumulative $8 trillion through 2035 , nearly $1 trillion higher than the gas infrastructure investment in their global energy scenario of last fall. Those figures aren’t as hard to fathom in the context of developed-country budget deficits and debt as they might seem, because they mainly reflect unsubsidized, economically attractive investments by publicly-traded and state-owned energy companies that are making healthy profits and have substantial cash flow on which to draw. Surprisingly, the IEA sees most of the incremental investment in gas coming at the expense of oil. Although they deliberately framed the title of their scenario as a question that hinges on a number of variables, the report comes across as a plausible and credible glimpse of our possible energy future.

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The Golden Age of Natural Gas is news story from: News and Stories from Energy Editor

I see that the administration has asked Congress to approve a non-emergency sale of oil from the US Strategic Petroleum Reserve (SPR), in order to allow a storage cavern to be repaired before it starts to leak. That’s fine, as far as it goes, though the article I read suggested this would be done as a net sale into the market, rather than an exchange for future oil, as has been done for many previous SPR releases. The distinction means that the government will either be exposed to buying the oil back at higher prices later, or would simply forgo refilling that portion of the reserve. The current shape of the oil futures market provides another alternative, though without the presumed political benefits of being seen to sell SPR oil when gasoline prices are high.

The sale in question was included in the administration’s annual budget request and identified 6 million barrels to be sold ” for operational purposes.” That amounts to less than 1% of the 727 million barrels of oil currently in the SPR, equating to a little more than one day of import disruption insurance at the SPR’s maximum output of 4.4 million barrels per day. Of course at current oil prices it would be worth over a half-billion bucks, so I can understand the appeal of doing this when federal finances are tight. However, the purpose of the reserve was never to speculate on the price of oil and harvest those gains when we came up short elsewhere; the oil is there to mitigate a serious disruption in the roughly 9 million barrels per day of oil imports on which our economy depends. Unless the administration now wants to undertake a comprehensive review of our SPR strategy–something I’ve advocated for several years–it is more or less obligated to replace the oil once the cavern has been fixed.

In that case, selling the oil, rather than offering it to refiners on a time-trade, will expose the government to a substantial amount of price risk while repairs are completed. For example, if they had sold this oil last fall and needed to buy it back now, the Department of Energy would have incurred a loss of up to $180 million, based on the increase in oil prices in general and the divergence of physical markets, which tend to track UK Brent Crude, from the futures market in West Texas Intermediate. Prices might fall in the meantime, but it is not the role of the DOE to bet on that prospect. The futures market offers a uniquely better alternative today.

Most of the time, the oil futures price curve is bent either up or down, in ” contango” or ” backwardation” in trader’s terms, with oil for delivery several months or more from now selling for considerably more or less than for prompt delivery. That’s usually an indication of expectations that the balance between supply and demand will be either tighter or looser in the months ahead, compared to today. The contango that prevailed until recently has flattened dramatically, so that if it acted quickly, the DOE could sell the oil from the caverns to refiners and lock in its future repurchase price on the futures market at only a dollar or two per barrel more than the sales price. Of course this would involve having the government participate in the dreaded futures market, even though it wouldn’t be for the purpose of manipulation or stabilization, but for simple hedging of the kind that producers and refiners do every day of the week. (Backwardation would offer an even better deal, and the Brent market is currently mildly backwardated, but I can only imagine the hullabaloo if the US government hedged SPR oil on a European exchange.)

We would argue all day about which approach is riskier: hedging the oil sold from the SPR with futures contracts or waiting to buy back at whatever price prevailed later. In the larger scheme of things, neither looks as risky as emptying the cavern and not refilling it at all. Based on my experience and at least in this special case, hedging seems like a good way to ensure that the SPR cavern repair doesn’t end up costing a lot more than the DOE expects, if its managers ignored oil-price risk.

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Hedging the Risks of Selling Oil from the Strategic Petroleum Reserve is news story from: News and Stories from Energy Editor

Today’s Wall St. Journal (subscription required) includes an op-ed calling for a stricter boycott of Iranian oil than the current one that prohibits importing it into the US. The proposal from Reuel Marc Gerecht and Mark Dubowitz of the Foundation for the Defense of Democracies would go even farther, barring the importation of petroleum products that contain any components processed from Iranian crude elsewhere. Before any fuels or petrochemical products could be brought to the US, exporters ” would have to certify that no Iranian oil was involved in its manufacture.” Yet while the authors have clearly thought about how to maximize the impact of such a rule on the government of Iran, I’m not sure they’ve examined the potential impact on the US carefully enough. If their arguments about how European refiners would adjust to such a boycott are correct, then U.S. gasoline prices would likely rise as a result of these restrictions.

The logic of the proposal is grounded in fact. The US imports significant quantities of gasoline from Europe, though lately most of it is in the form of gasoline blending components, rather than finished gasoline that is ready to be put into a pipeline or sold over a refinery’s or blending facility’s truck rack. Last year total US gasoline imports averaged almost 900,000 barrels per day, with 39% coming from EU countries led by the UK, Netherlands, Spain and France. It’s also true that many European refineries process some Iranian crude. In 2010, the EU imported 471,000 bbl/day of crude oil from Iran, comprising just over 4% of total EU oil imports of 11.1 million barrels per day. (Compare that to US oil imports in 2010 of 9.2 million bbl/day.) This amounts to roughly a fifth of total Iranian crude oil exports. At least on the surface, it looks like it shouldn’t be too hard for European refiners to forgo this small input, in order to be able to continue exporting gasoline and other oil-derived products to the USA.

In practice, I think it would be a bit more difficult for European refiners to make that adjustment than the authors imagine. For starters, those refineries capable of exporting gasoline to the US must generally be located near ports, rather than inland, and likely run more Iranian crude than the EU average, since this oil is delivered by large tankers. Then there’s the question of how much Iranian crude a refinery could run and still be able to certify its products to be Iran-free. If the standard were simply that you couldn’t export a larger proportion of your products than the proportion of non-Iranian oil in your crude slate, this probably wouldn’t change what any refiner is currently doing, since most of their output goes into the local market. Certifying that there were no molecules of Iranian origin in any products destined for the US would essentially require running no Iranian crude at all, because of the way that most refineries balance their crude slates and manage their inventories of crude and unfinished products.

I presume that’s what the authors have in mind, because it would certainly exert the greatest market pressure on the price of Iranian crude. However, substituting one crude oil for another in a refinery isn’t like substituting one brand of cola for another in a fast-food restaurant. We’ve seen a prime example of that recently with the disproportionately large disruption caused by the curtailment of exports of high-quality oil from Libya. Refineries tend to be optimized around certain proportions of well-known crudes, with shifts in those proportions mainly driven by changes in the value of the products they yield, within a range set by the capabilities of the specific hardware. In other words, if your refinery model is telling you to run x% of Iranian Light, then choosing something else in order to be able to sell into the US market comes at a cost.

That cost would be passed on to companies importing European gasoline into the US in two ways. First, it would require a higher price to make it worthwhile for the exporting refinery to produce a cargo to US specifications. Less directly but just as significantly, it would reduce the number of refineries competing for the export opportunity, because some would simply find the changes too onerous, unless the premium they collected was really large. The result would be a smaller pool of suppliers with slightly higher costs. That’s not what you want to face as a buyer.

Market dynamics might also amplify this effect. A portion of the gasoline exported from Europe to the US flows not under long-term contracts, but as ” spot” cargoes shipped in response to occasional wide price differences between there and here. That’s exactly the kind of trading I was involved in when I worked in London in the early ’90s. Such ” arbitrage opportunities” often result from supply problems such as refinery accidents and other unanticipated shutdowns, large weather events, or other situations leading to a local or regional price spike. As a result, much of the impact on the US from the authors’ proposal could be delivered when gas prices here are already rising, thus adding to the economic impact of a price spike.

Perhaps paying more at the pump to drive down the value of Iranian crude in the global market would be a price most Americans would be willing to accept. I’d gladly kick in a few cents per gallon for that purpose, since I remain extremely skeptical of Iranian assurances that their nuclear program is entirely for peaceful purposes. Nothing has materially changed my view of that since my detailed analysis in 2005. However, I suspect that the strong likelihood that such a boycott would entail a certain amount of ” blowback” at home would complicate the politics of passing the necessary legislation, particularly when gas prices are already quite high by US standards.

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The Cost of A Tougher Iranian Oil Boycott is news story from: News and Stories from Energy Editor

It’s rare to run across a novel form of renewable energy that hasn’t already been touted as the Next Big Thing and the potential savior of humanity. Work on harnessing salinity gradient power, one aspect of which is also known as ” osmotic power” , has proceeded in relative obscurity, with only one demonstration-scale installation that I’m aware of, in Norway. However, recent developments at Stanford University, as reported in Technology Review, hold the promise of extracting electricity directly from the difference in salt concentration between fresh water and seawater. If it can be scaled up as indicated, it could offer yet another renewable energy option for coastal communities, though as with most others, it is unlikely to be free of undesired consequences. So far as I know, the law of no free lunches has not yet been repealed.

Most forms of energy production, renewable or otherwise, depend on taking advantage of some kind of gradient–differences in temperature, pressure, or another characteristic between two locations. In some cases, these gradients are inherent in the primary energy source involved, such as the pressure gradients that produce the wind harnessed by wind turbines, or the temperature gradients that drive geothermal power plants. In other cases, the gradient is created by the process of energy conversion in some device, such as an internal combustion engine, gas turbine or nuclear reactor. For most of us, it’s probably easier to relate to the pressure and temperature gradients that drive such machines than to visualize the concentration gradients that Dr. Cui’s team at Stanford was investigating. Reading about their work dusted off the cobwebs from my chemical engineering mass transfer studies, long ago.

The ” mixing entropy battery” the researchers created uses electrodes chosen for their affinity for sodium and chloride ions, with surfaces optimized through the application of nanotechnology. By charging it from an external power source while immersed in fresh water and then discharging it while filled with salt water, they are able to extract more energy than they put into it. This is not perpetual motion, because the extra energy comes from exploiting the concentration difference between the two fluids. Impressively, they extracted 74% of that energy potential in their tests; few energy cycles recover more than 50% of the energy of their sources. The catch is that like any battery, the process stops when the electrodes are saturated. At that point, the battery must be recharged in freshwater. This cycle can be repeated many times.

Although this technique might be used to produce smaller-scale rechargeable batteries for consumer devices or perhaps even cars, the researchers apparently had in mind larger-scale applications that would exploit the differences in salinity where a river meets the sea. Not only are such locations quite common, but they also tend to be near centers of population, because of the historical relationship between waterborne commerce and settlements. They have apparently calculated that the global potential of the concentration gradients in estuaries could meet 13% of the world’s energy needs, or around 2 terawatts (2 million Megawatts.)

What’s not clear from what I’ve read of their work is how much of the salinity gradient in an estuary could be tapped without significantly affecting the local ecosystem. Even though the amount of salt returned to the estuary would match what was taken out, performing the relevant mixing somewhere else–inside a power plant–would alter the preexisting conditions. That might not be catastrophic, particularly if the scale of the plant were limited to the natural variation in water flow caused by seasonal rainfall patterns, but it would still count as an environmental impact. I don’t regard that as a reason not to pursue this technology, because everything we do at the scale of our global civilization has an environmental impact somewhere, but it’s at least cause to proceed cautiously. In the world in which we now live, anyone investing in this technology won’t have a choice about that, anyway.

So it seems we should add salinity power to the existing long list of renewable energy options, including wind, solar, geothermal, ocean thermal, wave and tidal power. If historical precedents concerning the interval from laboratory to commercial application are any guide, we might expect the first large-scale salinity power plant to appear sometime in the mid-to-late 2020s, assuming that it doesn’t encounter unexpected hurdles and can be scaled up economically. Even if it can’t supply all our needs, salinity power could make an important contribution to the low-emission energy mix we anticipate by mid-century. I’ll be watching developments with great interest.

Check out the original source here.

Tapping Salt Water’s Energy Potential is news story from: News and Stories from Energy Editor