Europe Raids 3 Companies in an Inquiry on Oil Prices

In what the commission termed ‘'unannounced inspections,'’ investigators descended on some European offices of BP, Royal Dutch Shell and Platts, a division of the McGraw-Hill Companies that specializes in providing pricing for the oil industry. The European authorities are looking into whether the companies may have ‘'colluded in reporting distorted prices'’ in an effort ‘'to manipulate the published prices of a number of oil and biofuel products.'’

All of the companies said they were cooperating with the inquiry.

Shell said it was “assisting the European Commission in an inquiry into trading activities.” A spokesman said that the company’s offices in Rotterdam and London were “visited.”

Platts said that the European Commission had “undertaken a review” at its offices, at Canary Wharf in London. The authorities also raided BP’s oil trading operations on the lower floors of the same building. BP said in a statement that the company was “subject to an investigation.”

Regulators in Europe and the United States have long been worried about the system by which oil and gas prices are set, which can affect the prices consumers pay as well as costs for airline and trucking companies. The concerns reached a frenzied pitch in 2008 when oil prices hit record highs and then quickly plunged. At the time, lawmakers in the United States and elsewhere questioned whether the prices were being distorted.

The authorities are focused in part on the price reporting system for oil and other petroleum products, which is dominated by a small group of companies like Platts. Such companies determine prices by polling traders and using other industry data.

In recent years, Platts has instituted a so-called electronic window through which a significant amount of oil is traded. At the end of each day, Platts determines prices based on the trades that go through this system, rather than by simply relying on polling companies.

There are concerns in the industry that companies could distort the prices through a blizzard of last-minute trades. “If you want access to liquidity you are forced to use the window,” said a senior oil trader. But he also said that the window, in theory, should be more accurate than prices determined just by polling traders because the prices were determined by actual trades.

The benchmarks, notably Brent crude, are enormously influential. Much of the world’s oil, particularly outside the United States, is priced in relation to Brent, which is made up of a basket of North Sea crudes. These benchmarks are also often used in the large derivatives markets.

As production in the North Sea has dwindled, the Brent price has been based on lower volumes of oil, prompting fears that it could be manipulated, possibly by major players in the region. The Brent price is determined through assessing prices of a blend of four North Sea crudes.

In recent years, various regulatory agencies have investigated price setting but seem to have come up with little evidence of manipulation. People in the industry say, however, that the controversy around oil and gas prices has made companies increasingly reluctant to supply prices for fear of becoming the targets of regulators or lawsuits.

In 2010, the Group of 20 economically most developed nations asked the International Organization of Securities Commissions to look into the potential for manipulation and whether tighter regulation was needed. After a two-year investigation, the price reporting agencies last fall agreed to adopt a series of principles to deal with conflicts of interests and other issues.

An 18-month trial period is under way. Compliance is to be monitored by an independent auditor. If the companies don’t go along, regulators may bar them from providing pricing benchmarks to exchanges, which is a source of revenue.
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Gas Raises Consumer Prices, but Inflation Remains Tame

The Labor Department reported on Tuesday that its Consumer Price Index increased 0.5 percent in June from May. Two-thirds of the gain came from a 6.3 percent jump in gas prices, the largest since February.

Excluding volatile food and energy costs, so-called core prices rose just 0.2 percent.

Consumer prices have been stable this year, giving the Federal Reserve room to continue efforts to stimulate the economy.

Over all, prices rose just 1.8 percent in the last 12 months. And core prices rose just 1.6 percent in that period — the smallest 12-month change in two years. Each measure was below 2 percent, the Fed’s inflation target.

Slow economic growth and high unemployment have kept wages from rising quickly. That has made it harder for retailers and other businesses to increase prices.

In June, prices for all energy products rose 3.4 percent, mostly because of the surge in gas costs. Other prices changed little.

The gas price surge was caused by a jump in global oil prices, which was influenced by the political turmoil in Egypt. Chris G. Christopher Jr., director of consumer economics at IHS Global Insight, predicted prices at the pump would fall once conditions stabilized in Egypt.

Food prices edged up 0.2 percent. New-car prices increased 0.3 percent but were up just 1.3 percent over the last year. Clothing prices rose 0.9 percent in June but were up just 0.8 percent over the last 12 months. Prices for used cars fell 0.4 percent and were down 2.3 percent over the last year.

The Federal Reserve reported on Tuesday that manufacturing production rose 0.3 percent in June from May, as factories made more business equipment, home electronics and cars. That followed a 0.2 percent gain in May. Still, the two consecutive gains barely offset declines in March and April.

Overall industrial production, which includes factories, mines and utilities, also rose 0.3 percent in June. Mining output increased 0.8 percent and utility output slid 0.1 percent.

Manufacturing is the most critical component of industrial production. The recent gains are a hopeful sign that factories could help the economy grow in the second half of the year.

The “report confirms the picture of a moderate recovery in the manufacturing sector,” Annalisa Piazza, senior economist at Newedge Strategy, wrote in a research note.

Manufacturers have struggled this year, providing little support to the economy. Their output was up just 1.8 percent in the last 12 months. And factories cut jobs in each of the last four months, shedding 24,000 since February.

Slower global growth has cut demand for American exports. Europe is still in a recession and China’s economy grew from April through June at the slowest pace in more than two decades.

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Wholesale Prices Fall Again

The producer price index, which measures price changes before they reach the consumer, fell a seasonally adjusted 0.7 percent in April from March, the Labor Department said Wednesday. It was the second straight monthly decline and the steepest since February 2010.

Lower inflation means the Federal Reserve has more leeway to continue its aggressive policies to bolster economic growth. If there were signs that inflation was picking up, the Fed might be forced to raise interest rates.

The index declined largely because gas prices dropped 6 percent, and the price of home heating oil fell by the most in almost four years.

Food prices also fell 0.8 percent, the most since May 2011. Half of the decline was because of lower vegetable prices, a highly volatile category. Meat prices dropped 2.3 percent.

Excluding the volatile food and energy categories, core prices ticked up 0.1 percent in April, from March. Pharmaceutical costs also rose 0.1 percent.

Prices for cars and pickup trucks, men’s clothing, tires and computers all declined.

Over all, wholesale prices have increased just 0.6 percent over the last 12 months. That is the smallest yearly gain since July and down from a 1.7 percent pace just two months ago.

Core prices have risen only 1.7 percent in the last 12 months and are just below the Fed’s 2 percent inflation target.

Paul Dales, an economist at Capital Economics, said wholesale prices may fall further as declining prices for many commodities work their way through the supply chain. Slowing manufacturing output could also weigh on prices.

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Crude Oil Inventories Decline at Record Rate (7/25/2013)

During the recent Tour de France bicycle race, fans saw that the steep descents were as challenging and interesting as the steep climbs. In oil markets, analysts have recently observed a steep decline in U.S. commercial crude oil inventories with close attention and interest.

Crude oil inventories, which had been above their five-year range all but one week since March 2012, fell by a record 27 million barrels over the past three weeks and are back within the five-year range (Figure 1). Despite the record draw over the past three weeks, average 2013 inventories through July 12 remain 6 percent above the same period last year and 11 percent above the five-year average. Robust total U.S. inventories have been largely the result of high inventories in the Midwest (PADD 2) which, despite recent declines, remains 22 percent above the 5-year average for the week ending July 12. Inventories declined for three reasons: (1) an increase in U.S. refinery runs; (2) a decrease in crude oil imports; and (3) an increase in backwardation (a reduction in price for future months) on the West Texas Intermediate (WTI) futures price curve that has encouraged reducing inventories rather than buying crude at current market prices.

The significant inventory draw was caused primarily by an increase in already high refinery demand for crude oil, including additional demand resulting from the restart of a 250,000 barrels per day (bbl/d) crude distillation unit at BP's Whiting, Indiana, refinery. Total U.S. refinery utilization increased 2.6 percentage points between June 21 and July 12, reaching 92.8 percent. Much of this increase is attributable to PADD 2, where utilization went from 87.9 percent to 94.6 percent over the same time, an increase of 6.7 percentage points. PADD 3 (Gulf Coast) utilization also rose over this period; at 95.4 percent for the week ending July 12, it was 2.3 percentage points above its June 21 level. Crude runs on the Gulf Coast have been buoyed by strong distillate margins. The 533,000 bbl/d increase in U.S. refinery net crude oil inputs pushed refinery runs to their highest level since 2005.

On the supply side, lower crude oil imports have increased the draw on stocks to meet demand from increased refinery runs. Crude oil imports into the United States for the weeks ending June 28 through July 12 averaged 649,000 bbl/d less than the three-week period ending June 21. Imports into the Gulf Coast and East Coast averaged 671,000 bbl/d and 219,000 bbl/d less, respectively, compared to the previous three-week period. Declines were led by lower imports from Saudi Arabia and Venezuela, which each dropped by about 25 percent over the three-week period ending July 12 compared to the prior three-week period, accounting for a 630,000-bbl/d decline. While year-to-date through July 12 U.S. imports of Canadian crude oil were 5 percent above 2012 levels, flooding in Alberta along with processing facility outages, have limited imports from Canada since June. As of July 12, Canadian imports are down 10 percent (278,000 bbl/d) from their 2013 high in mid-April. Lower Canadian supplies have a significant impact on PADD 2 inventory levels, since most Canadian crude comes to the United States via pipeline into the Midwest.

Higher crude runs in the Midwest and easing crude oil transportation constraints that are allowing more domestic crude oil to reach U.S. Gulf Coast refineries have pushed the WTI futures curve into backwardation over the next several months. This backwardation, with prices for close-in delivery above those for delivery in future months, creates an incentive to sell crude from inventory. On June 20, when the contract for August delivery became the prompt futures contract, prices for the next two months fell, resulting in the first consistent period of WTI backwardation since November 2011. In addition, on July 10, the prompt contract (August) premium over the second month reached $0.90 per barrel, the highest level since 2008. Spreads between the front month and longer-dated contracts are even wider. As of July 10, the December 2013 contract was trading at $4.23 per barrel below August.

On the Gulf Coast, inventories have fallen 16.3 million barrels since June 21, and in the Midwest inventories are down 6.8 million barrels. At Cushing, Oklahoma, the delivery point for the Nymex WTI futures contract, stocks fell 2.7 million barrels the week of July 5 and another 882,000 barrels the following week. Trade press reports indicated that crude production that was being delivered to Cushing storage is now being delivered directly to the Gulf Coast, thus reducing supply at Cushing. In addition, a syncrude crude processing facility in Canada was reported to have been out of service, reducing regional supplies of light sweet crude oil. Although average 2013 Cushing inventories remain 25 percent above 2012 levels, stock levels have declined for much of 2013 and are now slightly below their 2012 level. Along with pipeline infrastructure changes that have allowed crude to bypass Cushing, rail is facilitating the movement of crude oil directly from the Bakken formation in North Dakota to refineries on both the East and West coasts.

In addition to pushing the WTI market into backwardation, these developments are helping to raise Midcontinent spot prices, narrowing the spreads between North Sea Brent and WTI and between Bakken and Light Louisiana Sweet (LLS) crude oils. However, the resumption of syncrude imports and an anticipated refinery switch by BP Whiting to heavier Canadian crude later this year could take upward pressure off prompt WTI prices, flattening the forward curve.

Gasoline prices up for a second week; diesel fuel up for a third
The U.S. average retail price of regular gasoline increased five cents to $3.68 per gallon as of July 22, 2013, up 19 cents from last year at this time. The largest increase came on the East Coast, where the price is up seven cents to $3.66 per gallon. The Gulf Coast price is $3.51 per gallon, six cents higher than last week. The West Coast price is $3.95 per gallon, three cents higher. The Midwest price is $3.66 per gallon, two cents higher. Rounding out the regions, the Rocky Mountain price increased a penny to $3.62 per gallon.

The national average diesel fuel price increased four cents to $3.90 per gallon, 12 cents higher than last year at this time. The East Coast, Gulf Coast, Rocky Mountain, and West Coast prices all increased four cents, to $3.92, $3.84, $3.87, and $4.04 per gallon, respectively. Rounding out the regions, the Midwest price is up two cents to $3.88 per gallon.

Propane inventories gain
Total U.S. inventories of propane increased 1.5 million barrels from last week to end at 59.4 million barrels, but are 6.6 million barrels (10.0 percent) lower than the same period a year ago. The Midwest region led the gain with 0.9 million barrels, while Gulf Coast stocks increased by 0.5 million barrels. Rocky Mountain/West Coast stocks increased by 0.4 million barrels, and East Coast stocks decreased by 0.4 million barrels. Propylene non-fuel-use inventories represented 5.4 percent of total propane inventories.

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Brent - WTI Spread is Expected to Widen Through the End of the Year (8/8/2013)

The Brent-WTI spread, the price differential between Brent crude oil and West Texas Intermediate (WTI) crude oil, averaged just over $3 per barrel in July, its lowest monthly average since December 2010. The spread has been declining steadily since early this year, as midcontinent light sweet crude demand has increased and infrastructure improvement projects have allowed more U.S. crude production to reach refining centers on the Gulf Coast, in the East and on the West Coast, thereby putting upward price pressure on WTI. However, in its August Short-Term Energy Outlook (STEO), EIA forecasts the spread will widen from current levels to average $5 per barrel during the fourth quarter of 2013 and almost $7 per barrel for 2014 (Figure 1).

The spread began declining in early 2013 as new and expanded crude-by-rail and pipeline capacity made it possible to deliver crude oil directly from production areas to refining centers, bypassing congestion at the Cushing, Oklahoma, crude storage hub. Record high refinery crude runs, due to increased capacity and utilization on the Gulf Coast and further supported by the startup of a 250,000-barrel-per-day (bbl/d) crude distillation unit at BP's Whiting, Indiana, refinery, combined with maintenance at Canadian Syncrude processing facilities, helped to push up the price of WTI relative to that of Brent in July, compressing an already-narrowing Brent-WTI spread to the narrowest level in years.

EIA expects the recent sharp reductions in the Brent-WTI differential to be relatively short-lived, as refinery utilization rates decline from recent highs to lower post-summer seasonal levels and as crude oil production in North America continues to increase, outpacing takeaway capacity.

In the August STEO, EIA projects that refinery runs will fall from their recent high of 16.0 million bbl/d in July 2013 to averages of 15.7 million bbl/d and 14.9 million bbl/d in the third and fourth quarters of the year, respectively. Demand for WTI-grade crude oil in particular is expected to decline with the anticipated startup of new coking capacity at the BP Whiting facility late this year.

EIA also projects that U.S. lower-48 crude oil and Canadian liquids fuels production, which averaged 9.37 million bbl/d in the first half of 2013, will average 10.02 million bbl/d in the second half of 2013 and 10.75 million bbl/d in 2014, with most of the growth coming from tight oil produced from the Bakken, Eagle Ford and Permian Basin formations in the United States. Total production from these three formations is estimated to have averaged 3.0 million bbl/d during the first half of 2013, and EIA projects it will increase to 3.4 million bbl/d in the second half of the year and to 3.9 million bbl/d during 2014. To the extent that these production increases are not realized, there would be less downward pressure on WTI prices, and therefore a lower price discount to Brent, narrowing the spread.

The combination of lower refinery demand and growth in U.S. crude oil production is expected to put downward pressure on the price of WTI relative to that of Brent over the STEO forecast period. In the near term, EIA expects the differential will widen from current levels to average $5 per barrel during the fourth quarter of 2013, reflecting the downward pressure on WTI prices and some upward pressure on Brent prices from planned North Sea maintenance.

EIA expects the Brent-WTI differential to reach a high during the forecast period of $7.50 per barrel in early 2014, after which time planned pipeline expansions and seasonal increases in refinery utilization in the summer months again narrow the spread. EIA expects the spread to average $6 per barrel during the fourth quarter of 2014.

Gasoline and diesel fuel prices both decrease
The U.S. average retail price of regular gasoline decreased one cent to $3.63 per gallon as of August 5, 2013, one cent lower than last year at this time and below the year-ago price for the first time since May 2013. Prices decreased in all regions except the Midwest, where the price increased one cent to $3.59 per gallon. The largest decrease came on the West Coast, where the price fell four cents to $3.89 per gallon. The Gulf Coast price is $3.45 per gallon, three cents lower than last week. On the East Coast, the price dropped two cents to $3.63 per gallon. Rounding out the regions, the Rocky Mountain price declined less than a penny to remain at $3.64 per gallon.

The national average diesel fuel price decreased one cent to $3.91 per gallon, six cents higher than last year at this time. Prices increased less than a penny on the West Coast to remain at $4.05 per gallon and two cents in the Rocky Mountains to $3.93 per gallon, while decreasing in all other regions. The East Coast and Midwest prices both decreased one cent, to $3.92 per gallon and $3.88 per gallon, respectively. The Gulf Coast price declined less than one cent to $3.84 per gallon.

Propane inventories gain
Total U.S. inventories of propane increased 0.5 million barrels from last week to end at 61.8 million barrels, but are 6.2 million barrels (9.2 percent) lower than the same period a year ago. Gulf Coast inventories gained by 1.2 million barrels, while those in all other regions declined. East Coast stocks dropped by 0.4 million barrels, while Midwest stocks decreased by 0.2 million barrels. Rocky Mountain/West Coast inventories declined by 0.1 million barrels. Propylene non-fuel-use inventories represented 5.1 percent of total propane inventories.

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Gasoline Consumption: What Direction is it Heading? (7/31/2013)

As baseball nears its trading deadline on July 31, some teams need to decide if their recent upward trend is a short-term phenomenon or something that the team can build the future around. But baseball is not the only industry where midsummer trends are examined closely to determine if they are indicative of the future. The same can be said for U.S. gasoline consumption in the summer. It is not unusual for gasoline consumption to pick up during the summer. This year, however, gasoline product supplied (EIA's proxy for consumption) as reported in EIA weekly data has shown a more pronounced seasonal rise compared with previous years. From early May to the week ending July 5, U.S. product supplied for gasoline increased 10 percent to 9.3 million barrels per day (bbl/d) (Figure 1). However, this recent uptick in demand is unlikely to represent the beginning of a major boost in demand. Even with the recent rise, 2013 year-to-date gasoline consumption is almost unchanged from last year, and the estimated rise in gasoline demand is based on weekly product-supplied data that could change as more data, particularly on U.S. exports, become available.

For the weeks ending June 28 and July 5, product supplied for gasoline surpassed the 5-year average, based on data from the Weekly Petroleum Status Report (WPSR) through July 19, gasoline consumption in 2013 has averaged 8.6 million bbl/d, 0.4 million bbl/d below the 5-year average and marginally above 2012 average consumption.

However, at least some of the recent increase in reported gasoline consumption could be a result of the way EIA estimates weekly data, rather than an actual sharp increase in consumption. EIA uses a proxy for weekly U.S. gasoline consumption called product supplied, which measures the disappearance of a particular product from the primary supply chain. The WPSR uses seven surveys to collect data from respondents across the primary petroleum supply chain, made up of refineries, pipelines, bulk and blending terminals, gas processing plants and fractionators, oxygenate producers, and importers.

For a specific refined petroleum product, product supplied is equal to production plus imports minus stock change and exports.

The element subject to the most change between the WPSR product-supplied number and the monthly number published later in Petroleum Supply Monthly (PSM) is U.S. exports. The export data used in EIA's monthly product-supplied calculation come from the U.S. Bureau of the Census, which releases the data monthly with a two-month lag. As a result, the weekly product-supplied data considered in this discussion are estimated initially using two-month-old export data. As a result, when the official U.S. export data is released, the weekly estimates of gasoline product supplied are updated (Figure 2).

Adjustments to the WPSR motor gasoline export number have ranged between +300,000 to -280,000 bbl/d, meaning the recent perceived jump in gasoline demand is within the range of historical adjustments. This suggests that while the seasonal upward trend in gasoline demand is likely to remain, the recent surge in demand over the previous year and the 5-year average may become less pronounced once Census releases export data for June and July are released (May data are currently the latest available).

According to trade press, U.S. gasoline exports in June and July are likely to have increased as a result of demand from West Africa, which typically receives gasoline from European refineries. However, price-advantaged domestic crudes allow U.S. refiners to economically produce and ship gasoline to West Africa in greater quantities. If this is actually the case, apparent surge in demand witnessed since May, may prove to have been illusionary like the pennant hopes of many baseball teams.

Gasoline prices fall; diesel fuel up for a fourth week
The U.S. average retail price of regular gasoline decreased four cents to $3.65 per gallon as of July 29, 2013, up 14 cents from last year at this time. Prices fell in all regions except the Rocky Mountains, where the price increased two cents to $3.64 per gallon. The Midwest price is $3.58 per gallon, a decrease of nine cents from last week. The Gulf and West Coast prices both dropped three cents, to $3.48 per gallon and $3.93 per gallon, respectively. Rounding out the regions, the East Coast price is down a penny to $3.65 per gallon.

The national average diesel fuel price increased one cent to $3.92 per gallon, 12 cents higher than last year at this time, and the highest price since mid-April. Prices rose in all regions, with the largest increase coming in the Rocky Mountains, where the price is up five cents to $3.91 per gallon. The East Coast, Midwest, and West Coast prices all increased one cent, to $3.93, $3.89, and $4.05 per gallon, respectively. Rounding out the regions, the Gulf Coast price is up less than a penny to $3.85 per gallon.

Propane inventories continue to build
Total U.S. inventories of propane increased 1.9 million barrels from last week to end at 61.3 million barrels, but are 6.2 million barrels (9.1 percent) lower than the same period a year ago. The Gulf Coast and Midwest regions led the gain, with each rising by 0.8 million barrels. Rocky Mountain/West Coast stocks increased by 0.2 million barrels, and East Coast stocks increased by 0.1 million barrels. Propylene non-fuel-use inventories represented 4.8 percent of total propane inventories.

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U.S. Refineries are Running at High Levels (7/17/2013)

Crude runs at U.S. refineries have increased steadily since early March to reach some of the highest levels on record. At 16.1 million barrels per day (bbl/d) for the week ending July 5, U.S. crude oil runs were the highest for any week since 2007. This level represented a 2.1-million-bbl/d increase from the first week of March, the low point for the first six months of 2013. While the increase in crude runs since March reflects a particularly strong rebound from spring maintenance, an underlying combination of recent refinery capacity expansions and relatively healthy margins helped drive the absolute level of runs to a multiyear high.

Both the steep ramp-up in runs and the high absolute level in early July were driven by refiners in the Gulf Coast (PADD 3) and Midwest (PADD 2) (Figure 1). The Gulf Coast is home to more than 50 percent of U.S. refining capacity, and thus is often the key determinant of U.S. refining trends. Typically, the Gulf Coast, along with the West Coast, sees the country's earliest refinery turnaround season. In 2013, Gulf Coast runs reached their seasonal nadir the week ending March 1 at just under 6.9 million bbl/d, as several big facilities in the region underwent maintenance, including Lyondell's Houston refinery, Western's El Paso refinery, and Valero's Norco, Louisiana, facility. As facilities began to return from maintenance, Gulf Coast runs increased significantly. In each year from 2008 to 2012, Gulf Coast refiners ramped up crude runs by an average of 860,000 bbl/d from their first-half low point (which ranged anywhere from late January to early April) through the first week of July. This year, however, Gulf Coast runs increased by a staggering 1.6 million bbl/d, to reach 8.5 million bbl/d for the week ending July 5, down only 30,000 bbl/d from the record set the previous week.

To a large extent, record high Gulf Coast crude runs can be attributed to the new distillation capacity at Motiva's Port Arthur plant and relatively robust margins for the area's refiners. In June 2012, Motiva commissioned a new 325,000-bbl/d crude distillation unit at the refinery, but shortly thereafter, it encountered operational difficulties and was shut down for several months. With that expansion now fully operational, Gulf Coast operating distillation capacity stood at more than 8.7 million bbl/d as of January 1, 2013, up more than 180,000 bbl/d from a year earlier. In addition to higher capacity, Gulf Coast refineries are also running at very high levels of utilization, nearly 94 percent on average for the four weeks ending July 5.

While Midwest crude runs are not at record levels like the Gulf Coast, they also saw a sizable increase in recent weeks. A series of refinery outages hit the Midwest market in the middle of the second quarter, lowering crude oil runs to levels not seen since late 2010. As refiners returned from outages through June, Midwest runs ramped up steadily. This included the return of the Northern Tier St. Paul and Phillips 66 Wood River facilities. Additionally, trade press reports indicate BP ramped up production at its Whiting, Indiana, refinery to near full throttle of 405,000 bbl/d in June after the plant had been running at low rates for more than two years during the installation of a new coker designed to run heavy Canadian crude. While most of that refinery's distillation capacity is now on line, the coker is not expected to start up until later this year. In the meantime, the refinery is expected to satisfy its increased runs with light sweet crude. In sum, Midwest crude runs increased from 3.0 million bbl/d the week ending May 24 to more than 3.4 million bbl/d the week ending July 5.

Higher runs of light sweet crude at BP Whiting, and the seasonal increase in Midwest runs in general, are likely contributing to the recent narrowing of the Brent-WTI crude oil price spread to the lowest levels since late 2010. However, that spread has fallen below $3 per barrel recently, which has temporarily eroded some of Midwest refiners' competitive advantage. Earlier this week, with Brent priced at $109.29 per barrel and WTI at $105.88, the spread was $3.37. A narrower spread is likely to keep Midwest runs more muted than during times when the spread approached $30 per barrel and Midwest utilization neared maximum levels. But in the medium term, the Brent-WTI is likely to widen a bit from its current level. In the July Short-Term Energy Outlook, EIA projections have WTI's discount to Brent averaging $6.75 per barrel during the second half of 2013. While this projected spread is not as wide as at some points during the last two years, when combined with additions to upgrading capacity both in the Midwest and Gulf Coast that have increased the competitiveness of the U.S. refining base, it should generally make running crude profitable. In the current forecast, third-quarter crude runs average 15.5 million bbl/d, an increase of more than 200,000 bbl/d from both second-quarter 2013 and third-quarter 2012. Additionally, utilization rates on the Gulf Coast will likely drift downward from their current 94 percent with the arrival of autumn. While refiners can run at high rates and stress their operations for weeks or even months, utilization typically does not exceed about 90 percent over an extended period of time.

Gasoline and diesel fuel prices both increase
The U.S. average retail price of regular gasoline increased 15 cents to $3.64 per gallon as of July 15, 2013, up 21 cents from last year at this time. This is the largest one-week increase since February 2013. Regionally, the largest increase came in the Midwest, where the price is up 23 cents to $3.64 per gallon. The Gulf Coast price is $3.44 per gallon, 15 cents higher than last week, and on the East Coast the price is up 13 cents to $3.59 per gallon. On the West Coast the price is $3.93 per gallon, a nickel higher than last week. Rounding out the regions, the Rocky Mountain price increased less than a penny to remain at $3.61 per gallon.

The national average diesel fuel price increased four cents to $3.87 per gallon, 17 cents higher than last year at this time. The East Coast, Gulf Coast, and West Coast prices all increased five cents, to $3.88, $3.80, and $4.00 per gallon, respectively. The Midwest price is now $3.85 per gallon, three cents higher than last week. Rounding out the regions, the Rocky Mountain price is up two cents to $3.83 per gallon.

Propane inventories gain
Total U.S. inventories of propane increased 0.6 million barrels from last week to end at 58.0 million barrels, but are 6.8 million barrels (10.5 percent) lower than the same period a year ago. The Rocky Mountain/West Coast region led the gain with 0.4 million barrels, while Gulf Coast and Midwest stocks each increased by 0.2 million barrels. East Coast stocks decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 5.1 percent of total propane inventories.

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3 Secrets To Increasing Diesel Fuel Performance with A Fuel Management System

It used to be that the simple ability to choose diesel fuel over gasoline was a cost-benefit, but that’s no longer the case. Now you’re getting hammered, and fuel costs just keep rising. No wonder uncovering ways to increase diesel fuel performance has become a major concern for fleet operators.

Whether your fleet includes heavy-duty trucks, buses and other transportation vehicles, construction equipment or lighter vehicles using diesel, using an automated fuel management system can help you capture extensive data about how your vehicles are functioning and where your fuel is going. You can use that information to evaluate every aspect of your fleet operation.

And that means you can maximize diesel fuel performance for a more profitable bottom line.  

Resist the urge to idle.

The State of Connecticut prohibits idle times over three minutes except in certain unavoidable circumstances. And they’re not alone. Idling has become something of a “poster child” for excessive vehicle emissions, with resulting legislative action across the country. But getting idle time under control can significantly boost your company’s bottom line, too.

What’s your average mileage now? And what’s your average daily idle time per vehicle? Industry statistics show that a “typical” diesel-powered vehicle burns about one gallon for every hour at idle. If you could cut that by just 25%, how much would you save over a year?

Shutting down engines when they aren’t actually working or using auxiliary power to run air conditioning or heaters during stops and breaks can tremendously improve diesel fuel performance and save considerable money. It also reduces unproductive-but-costly engine hours. That means you’ll be able to stretch out your routine maintenance schedule. Lower total engine hours will increase the vehicle’s resale or trade-in value or simply extend its lifespan, and can extend the value of your warranty, too. 

Diesel fuel performance is easily monitored with a fuel management system. You get reliable, accurate, complete data – exactly the information you need to plan projects, manage daily operations, support long-term planning and capital investment strategy.

Take advantage of diesel fuel performance technologies.

In some cases, specialized equipment can help your engines produce top diesel fuel performance. You might consider:

Electronic chips can increase efficiency and performance.High-performance air intakes and filters can keep systems clean and cooler, for better fuel burn.High-performance exhaust systems with a larger diameter after the emission control device can improve mileage.Fuel injectors, even mileage-boosters such as diesel propane or water-methanol injection, are universally applicable and can help improve diesel fuel performance by burning slower, longer and more completely.

Enhance driver training.

Even the best drivers can get into a routine that may not be the most economical.

Power take-offs not only waste fuel, over time they can cause soot build-up that further reduces mileage and can cause expensive equipment failure. Speeding increases aerodynamic drag which in turn reduces mileage. For heavy-duty trucks, simply reducing speed from 56 to 50 miles-per-hour can reduce fuel consumption by as much as 22 percent.

Your fuel management system can monitor diesel fuel performance with detailed vehicle statistics but also with information that pinpoints where drivers could be more thoughtful or more conservative. Instituting specialized training or refresher courses can make drivers more aware of the effects of their actions. Get them actively involved in working to save fuel by rewarding them – hold a contest for the greatest improvement, or offer awards for the best quarterly record, etc.  

Ultimately, getting top diesel fuel performance depends on knowing what you have and putting it to the most cost-effective use. Investing in an electronic fuel management system can help you track, monitor and manage fuel assets, dispensing details, accounting and compliance reporting. It can eliminate human error and greatly enhance fuel security. And all that adds up to short-term and long-term savings.

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3 Benefits of a Fuel Management System

Anyone in the fueling or fleet operations business is well aware of the big bite fuel costs are taking from your bottom line. Since that’s not likely to change, savvy operators are turning to a fuel management system to boost efficiency and cut fuel-related costs.

A fuel management system is a technology-based tool that works with any pump-able liquid or gaseous fuel for attended or unattended fueling sites. The system provides real-time visibility of all aspects of fuel management and fueling activities, using automation to free up drivers and capture information that’s instantly available to any staff who may need it.

A fuel management system can provide broad-scale benefits for:

Fixed-base or mobile fueling operators.Fleet operators such as smaller transportation companies that handle fueling internally.Municipalities managing vehicles for utility crews, police, fire or the general motor pool.

It can even function entirely hands-free, allowing you to fully capitalize on security measures and gather comprehensive data to identify additional time and money savings. Here are three key benefits:

1. Better security.

Fuel losses are frustrating and costly. With a fuel management system, you always know what you have and where it’s going. And you can keep it from going astray.

2. Better tracking, operation-wide, in real time.

Automation can generate across-the-board efficiencies. It virtually eliminates human error, assuring timely, accurate and detailed information capture for each vehicle and each fueling session.

The ability to track details such as run and idle time can pinpoint opportunities for improved driver training, eliminating wasted fuel. You’ll get the most from the fuel you have and reduce unnecessary wear-and-tear on your fleet.

Automatic record-keeping ensures consistent regular maintenance, and real-time information allows early response to potential problems. You’ll improve vehicle performance and keep your fleet on the road longer.

You’ll always have complete data at your fingertips for reporting and financial purposes and for management review, analysis and decision-making.

3. You’re in control, at last.

Streamlining processes and ensuring accuracy and timeliness of record-keeping. Capturing valuable data to assess and refine operations. Curbing fuel losses and identifying potential problems before they get out of hand. It all adds up to bottom line savings, year in and year out.

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How Fuel Management Systems are Increasing Accountability

When we talk about fuel accountability, we’re usually referring to theft and other more mysterious losses that cause us to wonder what’s really going on with our fuel inventory. That’s a serious concern for any public or private entity that purchases large quantities of fuel, especially with prices as high as they are. There’s no question that an automated fuel management system can help increase accountability within your operation.

Incorporating a comprehensive fuel management system such as FuelMaster ProKeys has been proven to significantly reduce losses. The City of Tallahassee, for example, reduced their fuel losses by 97%. Operations that go one step further and incorporate vehicle-mounted Automotive Information Modules (AIM) with their fuel management system are seeing even broader and deeper benefits.

A fuel management system lets you take control of fuel handling and disposition. Real-time, consistent tracking of basic vehicle and fuel dispensing data ensures you always know where your fuel is, when and how it’s being dispensed. Automated data gathering also reduces “paper losses” and confusion that result from simple mistakes or misallocated information.

If you’re a fixed-based operator, using a fuel management system supports complete, accurate invoicing that assures accountability with your customers, too.

Total resource management.

But a fuel management system can provide across-the-board efficiencies that allow you to do much more than simply gain control over your fuel assets. You can see better accountability all the way up to the CEO’s office.

AIM enables you to capture detailed vehicle-specific data. You can track vehicle mileage and usage patterns to detect over-idling, “rabbit starts” or other fuel-wasting behaviors. With better driver training and alertness to these issues you can improve fuel efficiency in small increments that add up nicely.

You can use the data you gather to make more timely and better-informed decisions about every aspect of your business, from daily operations to billing, forecasting, budgeting and long-range planning.

A fuel management system helps you efficiently use all your resources, not just fuel itself. The ability to improve performance and increase the lifespan of your fleet vehicles can have a major impact on overall profitability as well as operations efficiency.

A fuel management system will certainly improve accountability within your organization. Choosing the right system and optimizing the ways in which you use it will help you prevent losses and save money through streamlined processes and increased productivity.

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Fuel Management Systems Suppliers: What To Look For

More and more businesses that manage fuel – and public entities, too – are discovering the tremendous efficiencies that can be gained by instituting a fuel management system. But it’s a major investment, one that has to make both practical and financial sense. Choosing among fuel management systems suppliers can be confusing. Who to pick?

The best fuel management system suppliers aren’t just there to sell you something, because it’s not just about buying a tool. Effective fuel management is about the bigger picture -- integrating fuel inventory control and fueling processes with your entire operation. That’s how you’ll get the broadest benefits so you can maximize the value of your investment.

Top quality fuel management systems suppliers know that. So pick one that has an obvious interest in helping you make a wise investment. The right supplier will:

Possess experience working with a variety of public and private organizations, because every fueling operation is a little different. And yours is the only one that counts when you’re making an important buying decision.Include environmental engineering experts, because fuel storage and handling regulations and related issues should be part of your fuel management plan.Help you thoroughly analyze your current situation – your most serious problems as well as the types of vehicles you fuel, how many, how often and where -- to understand your most immediate needs. They’ll ask about your long-term business and financial goals. And they’ll give you sound advice based on your unique situation, because knowing a fuel management system helped others is great, but you need to know exactly how it will help you.Sell the highest quality products like FuelMaster Prokees and AIM. You want proven success, not something that may not be up to the job.Stay with you after your purchase, to ensure your system is functioning properly and you’re using it fully. That way you’ll get the fastest return on your investment and you’ll always have the information you need to easily comply with internal and regulatory reporting requirements.

Choosing fuel management system suppliers shouldn’t give you a headache, it should cure the ones you already have. At least some of them. With the right research and planning you can make a smart decision that will be outstandingly productive and profitable, too. 

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How To Use An Automated Fuel System To Reconcile Fuel Usage

An ounce of prevention is worth a pound of cure.  Or in modern terms, a few dollars now can save thousands of dollars tomorrow. Installing and implementing an automated fuel system provides that ounce of prevention for what is likely one of your largest operating expenses - fuel. How many times have you wondered where did all of our fuel go, why can't I track it, or there must be a better way to manage this. A automated fueling system can significantly improve monitoring, tracking and overall control of your fuel-related operations, from purchasing through dispensing transactions. You get accurate tracking every step of the way to help reconcile fuel usage and avert problems.

Use your automated fuel system to:

Consistently gather data, including odometer and chronometer readings. Regular record-keeping enables earlier detection of potential problems, giving you an opportunity to address them before they grow into large expensive repairs or continue to waste fuel.Ensure the data you’re recording is complete, and completely accurate. That reduces simple mistakes due to human error as well as misallocation of information that can skew usage data. By studying the data, you’ll see additional ways to streamline operations so you always know where inventory is, where it’s going, how your individual vehicles and overall fleet are performing.Identify additional ways to save labor and money. Once you’re able to clearly see costs and other impacts of fuel usage, you can better evaluate your maintenance cycle and improve your ability to predict future purchasing and maintenance needs. Automation also significantly reduces time spent recording information and creating and producing reports.Increase fuel security, virtually eliminating costly losses from theft as well as inadvertent dispensing restriction errors.

Using a hands-free, RFID-based, nozzle to vehicle communication device like Syn-Tech's FuelMaster Automotive Information Modules (AIM2) can automatically initiate fueling, evaluate vehicle trouble codes, and upload data in real time for easy reporting. You can track information like:

Vehicle ID.Authorized fuel type.Quantity limit.Run and idle times.Engine trouble codes.Service hours and hours/miles remaining till next service.Travel direction.Site ID.

An automated fuel system helps you do more than reconcile fuel usage. It’s a highly cost-effective program that provides broad-scale opportunities to generate savings by streamlining operations and giving you far more control over your fuel supply.

Because important information is always updated regularly, you can use what you learn to make better-informed decisions about all your fuel-related operations, and you’ll be better prepared for reporting or audits or other scrutiny that comes your way.

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Increase Your Fleet’s Fuel Efficiency with a Fuel Management System

Anyone whose business includes operating a fleet of vehicles knows it can be tricky, and often frustrating, to properly manage fuel assets. A fuel management system may not be strictly necessary, but incorporating this type of automation can make your operation far more efficient and cost-effective.

A big part of that is improving fuel efficiency. But there’s a lot more to it than simply getting the best mileage possible from every vehicle.

A fuel management system puts automation to work at every step, reducing human interaction while enabling reliable and consistent information-gathering. If you choose to enhance your system by adding Syn-Tech's FuelMaster Automotive Information Modules (AIM2) your fueling processes can become entirely hands-free.

Taking the human factor out of the equation leads to even greater efficiencies. And since you can capture and store much more detailed information about your fueling process and each of your vehicles, you’re in a position to better analyze that data to identify further potential savings.

You can increase efficiency by reducing loss.  

Minimize or eliminate “apparent“ loss – and the accompanying accounting confusion – that comes from misallocation.

Minimize or eliminate actual loss as well as potential additional problems that come from improperly dispensed fuel type, spillage or outright theft by dispensing into containers or unauthorized vehicles. AIM2’s additional safeguards render these mistakes virtually impossible.

Reducing human participation in the process, especially recording odometer and chronometer readings, greatly reduces or eliminates simple mistakes, too – things like transposed numbers, forgetting to record everything every time or overlooked engine trouble codes.

These errors can significantly undermine your efforts to follow a careful and timely maintenance schedule. And if problems go unnoticed or regular preventive maintenance gets skipped, you can easily be facing expensive problems, not the least of which is inefficient mileage.

Use your fuel management system to monitor and improve driver behaviors that affect fuel efficiency, such as idle time, PTO and travel direction. Better training that results in tiny changes can have a significant impact on conserving fuel.

When you’re able to monitor every step from purchase through storage and dispensing, you never have to wonder where fuel assets are going, let alone whether they’re being used to your best economic advantage.

It’s worth your time to investigate all the benefits you could gain beyond improved fuel efficiency. 

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Top 5 Reasons You Need A Fuel Management System

A fuel management system provides high-tech electronic monitoring that can streamline your operations, no matter how large or small your business, how many locations you manage, or whether you use liquid or gaseous fuel. Particularly when used in conjunction with FuelMaster's Automotive Information Module (AIM2) or similar device, a fuel management system can provide truly outstanding functional improvements.

Any operation that manages fleets or tanks should seriously investigate the benefits, as they can accrue quickly and provide substantial year-in-and-year-out savings. Here are the top five reasons you need a fuel management system:

(Re)gain control over your fuel assets.

Mysterious losses are expensive, which means security is critical. The right fuel management system virtually eliminates waste, misallocation, incorrect dispensing and outright theft. You can confidently stay in compliance with government regulations or public oversight.

Increase productivity.

You can achieve human efficiencies using a fuel management system, with drivers, fuelers and other crew members spending less time on fueling activities. And you can achieve fleet-related efficiencies, too. More timely maintenance improves performance and extends vehicle life, and the additional driver and vehicle performance data available will help you detect opportunities to reduce wasteful behaviors such as prolonged idle time.

Increase accuracy.  

You’ll get reliable and consistent odometer readings, thanks to automated information capture that eliminates human error and miscommunication. Systems with AIM2 provide an entirely hands-free function.

Make more intelligent decisions.

Real-time data gathering and storage enables broader and more precise tracking and analysis. That means you can make better-informed decisions for budgeting and planning, reporting and tax accounting.

Save money.

All these benefits can add up to tremendous savings, from lower labor costs to reduced overall waste. And typically, a fuel management system will pay for itself in surprisingly short time.

If you’re like most fleet operators – public or private -- fuel costs represent a major portion of your expenses. Investing in a fuel management system can generate savings per vehicle, per year, that are sure to bring a smile of relief to your bottom line.

 

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Why Isn't Natural Gas an Election Issue?

In last week's acceptance speech, Republican Presidential candidate Mitt Romney held out this challenge: "President Obama promised to begin to slow the rise of the oceans and heal the planet. MY promise...is to help you and your family"

But what if it were possible to do both?

One of the surest ways to help protect the environment while creating jobs and revitalizing our economy is through increasing the conversion and use of natural gas here in the U.S.

Why has this opportunity towards increased reliance on natural gas been so obvious and yet so difficult for politicians of both parties to embrace?

It hasn't been solely because 2012 is an election year. Boone Pickens was on CNBC last week marking the fourth anniversary of his "Pickens Plan," the failed congressional effort to invest in truck natural gas engines and fuelling infrastructure to run them on.

In fact, if anyone wanted to see political partisanship in action slowing the real economic progress this nation could make, they'd find no better example than the history of the Pickens plan and other natural gas initiatives in Washington.

Both radical wings of each party have made advocating natural gas use impossible. Democratic environmentalists are concerned about hydraulic fracturing and its possible impact to aquifers. Republicans are reluctant to approve further federal spending of any kind as well as risk a charge of "picking winners" in natural gas -- a charge they have made successfully against Democrats.

Of course, both radical wings of both parties are wrong: Overwhelming evidence from every independent research source has concluded that hydraulic fracturing of shale for natural gas has proven to be safe to our water supplies and is getting safer all the time.

Republican reticence to support natural gas expansion belies a long history of government incentives for developing new energy sources, from as far back as our development of coal to our much discussed modern tax incentives for crude oil exploration and production.

It is a fact that our government has been picking winners in energy for as long as there's been government.

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Time to Act on Natural Gas Bill

The following commentary comes from an independent investor or market observer as part of TheStreet's guest contributor program, which is separate from the company's news coverage.

Have you had enough of paying $4 a gallon for gas? Do you wonder what you're going to do if gas prices go to $5 a gallon this summer? You're not alone.

Gas prices affect everyone, regardless of race, color or political party, yet Washington is stuck in neutral in finding the solution, which is staring them straight in the face: natural gas.

It's time for us to take responsibility and force Washington to act. Today, the natural gas bill, which would add about $3.4 billion in incentives to kick start the movement to natural gas as a transport fuel is expected to be voted down as an addition to the highway funding bill, the last reasonable moment in this election year in which this bill it has even the slightest chance of passage.

Take matters into your own hands. Call your congressman and demand that this bill be passed for the sake of jobs, the economy and your wallet.

It is at least politically clear why this bill is such a difficult one to get approved. Republican fiscal conservatives are opposed to new federal spending and are sensitive to oil interests in their home states. They view this bill as anti-free market, another example of government looking to "pick winners."

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Democrats are opposed to any measure that would encourage environmentally sensitive hydraulic fracturing for natural gas from shale. Between the two, despite being a virtual no-brainer, two iterations of the original "Pickens" bill have failed and so likely will this latest rewritten Nat gas act.

Why should it? Natural gas is greener, plentiful, domestic and cheap. As gas prices today rose over $3.83 as a national average, the equivalent cost of a "gallon" of natural gas is $1.60. Most analysts expect domestic prices for natural gas to stay relatively low for years, perhaps decades to come, while oil price is at the whim of every Middle East conflict, emerging market competition for resources and decreasing global production.

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The oil and gas industry is ready for this. Last week's CERA conference -- the yearly global energy get-together of all the majors -- could have easily been renamed the natural gas conference. Apache (APA) CEO Steve Farris claimed that US supply of nat gas isn't the claimed 100 years, it is more like 200 years.

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Another Sign Oil Prices Don't Reflect Reality

Why are crude oil futures for delivery three years from now $30 cheaper, or almost $1 a gallon less, than current oil prices?

That just doesn't seem possible, unless the oil trade is totally overrun with speculators and Fed-inspired cheap-money investors. 

 I got into a discussion with an executive at one of the larger derivative brokerages about the amount of speculation and investor interest in the oil markets today.

He made a number of good points, but one that wasn't so good was his comparison of the oil market to the stock market. He claimed that current oil prices reflected risk in the market accurately because they are "forward-looking."

That's an old saw for equities traders. It posits that stocks can react today to events and cycles that are still many months away. The equity market can be "forward-looking" and price in news that hasn't happened yet but is expected to happen.

But futures are not like stocks.

For any company, there is one primary instrument to trade: its common shares. But with oil futures, you have a multitude of monthly deliveries -- and you can trade any of them at any time.

In other words, futures don't need to be forward-looking. They are in fact real forwards -- with an expiration date attached to every investment or hedge you choose.

If you want to bet that an event will happen that will affect oil prices three months from now or three years from now, you need not buy physical "oil" or today's closest month to delivery. You can buy or sell oil that delivers exactly when you think that event will occur.

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Obama Has a Big Problem: Gas Prices

The biggest hurdle to President Obama's re-election is almost surely going to be the inevitable steady rise in gas prices over the summer.

And no matter how hard he -- or anybody else -- argues that higher pump prices are largely beyond his control, you and I both know that the American public won't much care for explanations. They'll just be looking for relief.

And $5 gas looks very likely. I have traded oil for 25 years, and the pattern we're seeing now looks eerily similar to the run-ups in crude prices that preceded the first Gulf War in 1990, the Iraqi invasion in 2003 and the Libyan excursion last year.

All of these big spikes in prices were based upon supply threats that ultimately occurred because of military action, and the time line that is playing out with Iran shows many of the same characteristics.

That doesn't mean I am predicting war, but it does mean that the oil market is preparing itself for a sudden deficit of at least a substantial proportion of the 3.5 million barrels a day of Iranian supply that feeds into the global chain.

There is a hard deadline for this to happen as well: July 1. That's when the EU has decided to begin its boycott of Iranian oil imports. Also, the U.S. has done a lot of work to gain at least some support for its cause from the biggest importers of Iranian oil: China, India and Japan.

So far, the president so far has been able to calm the Israelis, who have threatened to preemptively strike at Iranian nuclear targets. The administration has pleaded with them to wait for the boycott and economic sanctions to tighten the noose enough to get Tehran to comply with atomic agreements it has already signed.

In Iran, the leadership continues to act defiantly, threatening to close shipping lanes for oil and make preemptive strikes of its own, and declaring that nothing will deter its nuclear plans.

All of this leads to inevitably higher gas prices going through the hard deadline of July 1 unless lightning strikes and the Obama administration can solve this problem before then through diplomacy.

I wouldn't count on it: The last negotiation between Iran and the U.N. atomic agency, the International Atomic Energy Agency, lasted all of 18 hours last week before negotiators came to a roadblock and reboarded planes out of Tehran.

If you're a Republican candidate for President, this is an instant opportunity. The skyrocketing cost of gasoline is one of the few issues that will resonate with everyone.

Newt Gingrich recently promised there would be $2.50 gas if he was elected but neglected to explain how he would bring that about. This is a big step up from Michele Bachmann's promise of $2 gas and Donald Trump's claim of being ready to "tell the Saudis" what the U.S. is "going to pay."

All of these statements may sound ridiculous in the light of real facts about global oil markets, but a public suffering under gas costing $4-plus a gallon is going to listen very closely anyway.

So the president has a big political problem, one he surely wishes weren't coming to a head in an election year. So far, he has dealt with it by blaming supply threats and speculators. This is perfectly true and legitimate but likely to fall on deaf ears.

He does have some interesting tools he can use more effectively to combat high gas prices, but I'll wait to lay those out in my next column. I'll have lots of time to talk about them as I believe President Obama's political problems from high gas prices have only just begun.

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Oil's Toughest Question

This last week has seen an avalanche of articles, papers and opinion pieces attacking the idea that oil and gasoline prices are affected by speculation, in response to President Obama's recent plan to try and bolster the enforcement resources of the Commodity Futures Trading Commission against speculation.

This plan, which the president knows has no chance of passing through Congress in an election year, has been dismissed as populist political gamesmanship, not to be taken seriously.

President Obama visited an Oklahoma pipeline yard in March.

But just because an argument is populist sounding does not make it untrue. It is a shame that the president is proposing such small and ultimately fruitless changes in the oil market mechanism, because investment and trade in oil has certainly added $30 and perhaps more like $40 dollars a barrel to the price.

Very well-respected and strong economic arguments on the ineffectiveness of money pouring into the oil markets since 2003 have appeared recently in Foreign Affairs magazine, on the Center for Economic Policy Research Web site, as an editorial on Bloomberg and on the Chicago Mercantile Exchange Web site, to name just a few of the heavy hitters.

Wow -- this is quite an army of heavy minds summarily dismissing many of the conclusions I came to in my book on economic influences exerted in the oil markets, Oil's Endless Bid.

I read each of these reports with great interest and except for the one-page chart advanced by the CME, I also noted with interest that none of the other economists weighing in on this issue had ever had direct engagement with a futures market, either from the sell or the buy side.

I believe that many of the arguments advanced, even from the most learned of the economists, can be argued successfully and convincingly from the other side -- I believe I tackle and conquer most all of their real and counter-factual arguments in my book. But one issue continues to haunt them, one question that I don't believe any of them has ever even attempted to answer, because they can't: What happened to all the money?

It's a simplistic question to ask but still sums up the fundamental issue of "speculation in oil": Where is all the money? All detractors to the oil speculation argument will readily admit to an influx of nearly $200 billion dollars buying oil futures from indices since 2003.

But far more influential and what they are unable to track, is the amount of money driven into the oil market by hedge funds buying oil against rising stock indices and dropping dollar indices. Now, add in the trade from over-the-counter risk-management programs that have a nominal value of somewhere near $6 trillion dollars in oil alone and what you have is clear: A virtual deluge of buyers accumulating over the last 10 years, with a tiny respite for a global breakdown of asset markets in 2008.

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Polar Thaw Opens Shortcut for Russian Natural Gas

From this windswept shore on the Arctic Ocean, where Novatek owns enormous natural gas deposits, a stretch of thousands of miles of ice-free water leads to China. The company intends to ship the gas directly there.

Novatek, in partnership with the French energy company Total and the China National Petroleum Corporation, is building a $20 billion liquefied natural gas plant on the central Arctic coast of Russia. It is one of the first major energy projects to take advantage of the summer thawing of the Arctic caused by global warming.

The plant, called Yamal LNG, would send gas to Asia along the sea lanes known as the Northeast Passage, which opened for regular international shipping only four years ago.

Whatever blame for the grim environmental consequences of global warming elsewhere in the world that might be placed on the petroleum industry, in the Far North, companies like Novatek and Total, Exxon Mobil of the United States and Statoil of Norway stand to make profit.

“It’s a reality of what is available today, and commercially it is a route that cuts cost,” Emily Stromquist, a global energy analyst at the Eurasia Group, said in a telephone interview.

Because of easing ice conditions and new hull designs, the tankers will not even require nuclear-powered icebreakers to lead the way — as is the practice now — except through the most northerly straits.

Novatek’s alternative was extending the natural gas pipeline that goes to Europe over hundreds of miles of tundra, at great cost. While shipping the gas from the field on the Yamal Peninsula, one of the long, misshapen fingers of land that extend north of the Urals in Russia, remains expensive, it is relatively cheap to drill and produce from these rich fields, making the overall project competitive.

In addition to making it easier to ship to Asia, the receding ice cap has opened more of the sea floor to exploration. This has upended the traditional business model of using pipelines to Europe. Thawing has proceeded more slowly in the Arctic above Alaska, Canada and Greenland, but one day what is happening in Russia could happen there.

Still, the Arctic waters are particularly perilous for drilling because of the extreme cold. Tongues of ice that descend from the polar cap for hundreds of miles obstruct shipping and threaten rigs. After a rig ran aground last year, Shell canceled drilling this summer in the Chukchi Sea off Alaska.

This is not the first Arctic venture to benefit from newly cleared sea lanes. The decision to open the Arctic Ocean to drilling passed Russia’s Parliament in 2008 as an amendment to a law on subsoil resources. Exxon and Rosneft, the Russian state oil company, are already in a joint venture to drill in the Kara Sea, and last month they agreed to expand to seven new exploration blocks in the Arctic. Fourteen wells are planned.

With these ventures, Exxon has placed itself in the vanguard of oil companies exploring commercial opportunities in the newly ice-free waters.

In Russia, the mining company Norilsk can now ship its nickel and copper across the Arctic Ocean without chartering icebreakers, saving millions of rubles for shareholders.

Norway is also drilling deep in Arctic waters, but has less territory to explore. Tschudi, a Norwegian shipping company, has bought and revived an idled iron ore mine in the north of Norway to ship ore to China via the northern route.

In northwest Alaska, the Red Dog lead and zinc mine moves its ore through the Bering Strait, which is less often clogged with packed ice than in past decades.

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Suez Canal, Sumed Pipeline are key parts of Egypt's role in international energy markets

Egypt plays a vital role in international energy markets through the operation of the Suez Canal and Suez-Mediterranean (Sumed) Pipeline. In 2012, about 7% of all seaborne traded oil and 13% of liquefied natural gas (LNG) traded worldwide transited through the Suez Canal. Egypt's 2011 revolution and the unrest that has followed have not had any noticeable effect on oil and LNG transit flows through the Suez Canal or Sumed Pipeline.

The Suez Canal is an important transit route for oil and LNG shipments traveling northbound from the Persian Gulf to Europe and North America and southbound from North Africa and countries along the Mediterranean Sea to Asia. Changes to total oil and LNG flows through the Suez Canal in 2012 mainly occurred because of events outside of Egypt, particularly the restart of Libyan oil production and changing dynamics in LNG markets. Further, the Sumed Pipeline is the only alternative route nearby to transport crude oil northbound if loaded tankers are too large or ride too low in the water to navigate through the Suez Canal.

Oil flows. In 2012, southbound oil flows reached a record high as Libyan oil shipments through the Suez Canal quadrupled in 2012 compared with the previous year, reflecting the ramp-up of Libyan oil production after its civil war. In 2012, about 2.97 million barrels per day (bbl/d) of total oil (crude oil and refined products) transited the Suez Canal in both directions. This is the highest amount ever shipped through the Suez Canal, and made up about 7% of total seaborne traded oil. Crude oil flows through Sumed decreased in 2012 to 1.54 million bbl/d, as more crude oil was shipped through the Suez Canal via tankers.

LNG flows. Total Suez LNG flows as a percentage of total LNG traded worldwide fell to 13%, or 1.5 trillion cubic feet, in 2012, compared with 18% in 2011 for two main reasons. First, northbound LNG flows through the Suez Canal fell by nearly one-third in 2012 largely because of decreased LNG exports from Qatar to the United States and Europe. Second, northbound flows also fell because of reduced LNG exports from Yemen as a result of sabotage attacks on a gas pipeline.

Supply chain. Although external factors have to this point played a larger role in altering hydrocarbon flows through Egypt's transit points, unrest in Egypt still presents a risk, and the Egyptian army continues to guard the Suez Canal. Closure of the Suez Canal and the Sumed Pipeline would necessitate diverting oil tankers around the southern tip of Africa, the Cape of Good Hope. That would add 2,700 miles to ship oil from Saudi Arabia to the United States, increasing both costs and shipping time, according to the U.S. Department of Transportation. Moreover, shipping around Africa would add 15 days of transit to Europe and 8-10 days to the United States, according to the International Energy Agency.

Oil and natural gas production. Egypt's oil and gas production has largely been unaffected by the social unrest. The most visible effect of the revolution on Egypt's energy sector has been a series of attacks on the Arab Gas Pipeline that contributed to a significant drop in the country's pipeline gas exports. In addition, growing local demand for oil and gas amid stagnant production has led to energy shortages, contributing to continued protests and sporadic unrest in the country.

 

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Proved reserves of crude oil and natural gas in the United States up sharply in 2011

U.S. proved crude oil reserve additions in 2011 set a record volumetric increase for the second year in a row, according to newly published estimates in EIA's U.S. Crude Oil and Natural Gas Proved Reserves, 2011. Natural gas proved reserve additions fell short of setting a record, but still ranked as the second largest annual increase since 1977. Crude oil reserves rose 15% (almost 3.8 billion barrels) to the highest level since 1985, and natural gas reserves were up almost 10% (31.2 trillion cubic feet).

Proved oil reserves, which include crude oil and lease condensate, increased to 29.0 billion barrels, marking the third consecutive annual increase and the highest volume of proved reserves since 1985. Proved reserves in tight oil plays accounted for 3.6 billion barrels (13%) of total proved reserves of crude oil and lease condensate in 2011.

Texas recorded the largest increase in proved oil reserves among individual states, largely because of continuing development in the Permian Basin and the Eagle Ford formation in the Western Gulf Basin. North Dakota had the second largest increase, driven by development activity in the Bakken formation in the Williston Basin.

Source: U.S. Energy Information Administration, Form EIA-23, Annual Survey

Combined, Texas and Pennsylvania added 73% of the net increase in proved wet natural gas reserves in 2011. Pennsylvania's proved natural gas reserves, which more than doubled in 2010, increased by 12.7 trillion cubic feet in 2011, contributing 41% of the overall gain in proved reserves. Proved reserves in shale gas plays accounted for 131.6 trillion cubic feet (38%) of total proved reserves of wet natural gas in 2011.

Natural gas proved reserves, estimated as wet gas that includes liquids in the natural gas stream, increased by almost 10% in 2011 to 348.8 trillion cubic feet (Tcf), the 13th consecutive annual increase.

Source: U.S. Energy Information Administration, Form EIA-23, Annual Survey of Domestic Oil and Gas Reserves.For more details see the full report on U.S. Crude Oil and Natural Gas Proved Reserves, 2011. Additional state-level data are presented in the report, including estimates of proved reserves from selected tight oil and shale gas plays.
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Recent gasoline prices above last year, but 2013 year-to-date average lower than 2012

The average retail price of regular gasoline was $3.65 per gallon on Monday, July 29, 15 cents per gallon higher than a year ago, according to EIA's latest weekly survey. However, the average regular retail gasoline price for all of 2013 so far remains about 5 cents per gallon, or 1%, down from the average price over the same period last year. Prices varied greatly by regional market so far in 2013 (see graphs below). This year, crude prices and refinery availabilities have driven price trends. Key regional findings on gasoline price trends include

East Coast (PADD 1). Average gasoline prices were down 7 cents per gallon during the first half of 2013 compared to the same period in 2012, but as of July 29 they were 15 cents above their year-ago level. However, 2013 average prices through July were 5 cents below the same period a year ago.Midwest (PADD 2). While July 29, 2013 prices were 6 cents above their year-ago level, average year-to-date gasoline prices through July 29 were the same as in 2012. Planned and unplanned refinery maintenance as well as longer-term refinery upgrading projects over the past few months reduced gasoline production in the Midwest, drawing down gasoline inventories and pushing gasoline prices higher. As a result, Midwest daily average retail prices have fluctuated widely during 2013. On a state-level basis, prices were even more volatile. Several states reflected big gasoline price ranges including Minnesota, North Dakota, and Michigan.Gulf Coast (PADD 3). Average year-to-date U.S. Gulf Coast gasoline prices in 2013 are about 6 cents per gallon below their 2012 level, chiefly reflecting lower prices for the Light Louisiana Sweet (LLS) crude oil. However, as of July 15, PADD 3 gasoline prices had risen 15 cents from the previous week, up 24 cents per gallon compared to the same time a year ago. By July 29, prices rose to average $3.48 per gallon, 17 cents above the same week in 2012. Despite the recent increase in prices, compared to other regions, gasoline prices in PADD 3 have been relatively stable in 2013. This price stability occurred despite higher growth in gasoline demand than in other regions.Rocky Mountain (PADD 4). Gasoline prices so far in 2013 have reflected a wide range in PADD 4 because of the low price at the start of the year and the spillover effects from PADD 2 refinery maintenance. As of July 29, PADD 4 gasoline prices were 17 cents per gallon higher than a year ago, but the year-to-date 2013 average price remains 42 cents below the same period of 2012.West Coast (PADD 5). As of July 29, West Coast retail gasoline prices were 22 cents per gallon higher compared to the same time in 2012, but they were 9 cents per gallon on average lower year-to-date compared to 2012, the largest decline of any region. Refinery maintenance resulted in several sharp increases in wholesale gasoline prices in PADD 5 during the first half of 2013, but only one increase beginning in January significantly affected retail prices. Because of a combination of stringent environmental requirements and taxes, West Coast retail gasoline prices are generally the highest in the Lower 48 states (see chart below).
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Great Green Waste: Are Military Contracts the New Obama Stimulus?

The Department of Defense (DoD) is the largest energy consumer in the United States. To meet its energy needs, the Defense Logistics Agency (DLA) executes contracts to purchase fuel and electricity on behalf of the service branches. These contracts present opportunities for the federal government to provide de facto subsidies, should they choose to purchase more expensive sources of energy than is necessary. For the purposes of this report, subsidies are defined as disbursements by the federal government that have an identifiable federal budget impact and are specifically targeted at energy production. If the government pays more than the fair market value for a good or service, particularly in a closed-bidding process, this amounts to a subsidy.

The Institute for Energy Research’s (IER) Federal Energy Spending Tracker is a comprehensive database of the most significant forms of federal subsidies for energy producers. The database includes grants, loans and loan guarantees, and tax subsidies from FY 2009 to 2012. IER’s database, however, does not include contracts since the public data do not provide clear examples of cases in which the government paid more than fair market value for energy products.

This report serves as a starting point for evaluating government contracts for potential subsidies to energy producers. The report focuses exclusively on military biofuels and solar purchases, which, as purchases of products that are generally more expensive than readily available substitutes, are likely to contain subsidies.  For many of these purchases, the rationale for buying energy above market value is to satisfy military and political goals and mandates for greater renewable utilization.  In addition, another proxy for evaluating whether a contract includes a subsidy is to determine if a contract was either totally excluded from full and open competition or partially excluded.  In the case of military biofuel and solar purchases, this information was not readily available for all contracts; as such, they are evaluated in this report based on whether the product may have been purchased above fair market value.

Executive Summary

Over the last decade, the U.S. military has dramatically expanded renewable energy purchases. The DLA has spent more than $2.2 billion on solar purchases since 2003 and more than $65.2 million in biofuels purchases since 2009. This activity began under the George W. Bush administration after passage of the Energy Policy Act of 2005 (EPAct 2005) and the Energy Independence and Security Act of 2007 (EISA 2007) and has accelerated rapidly under the Obama administration.

In many instances, the DLA purchases biofuels dramatically above fair market value. Military biofuels purchases since 2009 have cost an average of $48.36 per gallon, even though the Department of Defense (DoD) can execute bulk contracts of conventional fuels for about $3.24 per gallon. The largest purchase was 450,000 gallons in 2011 at a cost of $26.75 per gallon for fuel used in a Navy demonstration of the so-called “Great Green Fleet.”  During this event, the Navy used a mix of biofuel and petroleum to fuel a guided missile destroyer and two destroyers, as well as some aircraft. The worst deal for taxpayers on a per gallon basis was a 2012 purchase of 55 gallons of biofuels for $245,000—a cost of $4,454 per gallon. These purchases are clearly subsidies, as they amount to the federal government purchasing products above market value when cost-competitive alternatives exist.  This serves to prop up the company supplying the subsidized product because in the absence of DOD’s purchases, no market would exist.

Compared to biofuels, however, it is more difficult to determine whether individual solar purchases constitute a subsidy, since it is less clear whether less costly alternatives were feasible in each specific case. However, solar is one of the most expensive sources of electricity generation and it is far more expensive than grid power in the United States. This means the vast majority of solar purchases made for installations connected to the grid are likely subsidies.

DoD Biofuels Purchases

The military has been purchasing biofuels since the mid-2000s and photovoltaic solar power since at least the 1980s. Both sets of purchases have been part of an energy diversification strategy that accelerated first during the George W. Bush administration and even more under the Obama administration. The military’s stated reasons for moving toward alternative fuel sources include climate change, dependence on foreign oil, and reliance on the civilian electrical grid. DoD is also shifting to alternative energy to comply with the National Defense Authorization Act of 2007, which requires the military to obtain 25 percent of its electricity from renewable sources by 2025.

Since 2009, the DLA has made at least 19 biofuels purchases totaling more than $65 million. As the next chart shows, on average, biofuels have cost taxpayers between $30 and $60 per gallon, compared to about $3.24 per gallon for conventional fuels on a bulk contract.

The above biofuels purchases have mostly been limited to a few companies. The largest include Sustainable Oils, Solazyme, UOP (Cargill), and Gevo. As the chart shows, Gevo has secured at least three biofuels agreements with DoD totaling more than $3.5 million, the most recent of which was announced by Gevo in its latest quarterly report. For each deal, DoD agreed to pay exactly $59 per gallon, significantly above market value.

In addition to direct biofuels purchases, the DoD is also trying to create “complete domestic value chains capable of producing drop-in replacement biofuels.” The Advanced Drop-In Biofuels Production Project provides an estimated $210 million in contract authority for the DoD to develop biofuels projects with the goal of developing an “Integrated Biofuels Production Enterprise” with at least 10 million gallons of annual production capacity.

To this end, the DoD announced in May its first contracts under the project totaling $16 million to Emerald Biofuels, Natures BioReserve, and Fulcrum Biofuels. The companies will develop plans for up to 150 million gallon biorefineries. The military expects the biofuels to be produced by 2016 at a cost of less than $4 per gallon. Currently, the DoD pays an average of $48.36 per gallon for biofuels.

The Department of Energy (DOE) is also in the business of funding biorefineries for military applications. Most recently, DOE announced that four biorefinery projects would receive up to $18 million to develop pilot-scale “drop-in” biofuels for jet fuel and ship diesel. One of the companies, Frontline Bioenergy LLCM, was awarded up to $4.2 million to build a refinery capable of producing just 1 barrel per day of fuels derived from woody biomass, municipal solid waste, and refuse. The following chart describes the projects:

 

In many cases, the military’s green energy purchases constitute subsidies for alternative energy. According to the Department of Energy (DOE), algal biofuels in particular are “not economical to produce using the technology available today.” Despite the exorbitant cost, the military continues to prop up industries that, in the case of algal biofuels, would essentially not exist without federal support.

In addition to the uneconomical cost of biofuels, America’s abundant supplies of domestic oil resources obviate the need for biofuels. North America’s 1.79 trillion barrels of total recoverable oil reserves are enough to fuel every passenger car in the United States for 430 years, almost twice as much as the combined proved reserves of all OPEC nations, and more than six times the proved reserves of Saudi Arabia. Furthermore, the federal government owns the National Petroleum Reserve—Alaska (NPR-A), formerly known as Naval Petroleum Reserve No. 4 when it was established in 1923 as an emergency oil supply for the U.S. Navy. According to the U.S. Geological Survey, NPR-A contains 896 million barrels of conventional, undiscovered oil. It makes little sense for the military to purchase expensive, scarce biofuels when the U.S. has vast supplies of affordable, conventional fuels.

Like grants and loans, green energy purchases are just another way for the federal government to subsidize expensive products that consumers do not want when conventional fuels are cheap and abundant. Instead of allowing the military to focus on its core mission, the federal government insists on using the military as a guinea pig for testing exotic biofuels.

DoD Solar Purchases

Military photovoltaic solar purchases have skyrocketed over the last 30 years. One agreement in 1980, for example, totaled $53,000, compared to a $1 billion agreement struck in 2011. The Bush administration spearheaded many of the purchase agreements of the 2000s, but the pace and size of the agreements accelerated during the Obama years. In 2012, the Obama administration announced “one of the largest commitments to clean energy in history” with the goal of deploying 3 gigawatts of green energy, including solar, wind, biomass, and geothermal, on Army, Navy, and Air Force installations by 2025.

At the time of the announcement, the Obama administration claimed that “renewable energy is critical to making our bases more energy secure.” Yet there are no discernible safety benefits to using renewable energy such as solar over conventional sources of electrical generation. For example, power inverters for solar systems are designed to shut off automatically in the event of a grid failure. In addition, solar power only works when the sun is shining, making it less reliable than baseload power sources such as coal and natural gas, and necessitating the use of conventional backup sources.

As the next chart shows, the vast majority of the solar purchases have been for military bases in Western states, including California, Arizona, New Mexico, and Hawaii. The largest purchases, respectively, have been $2 billion for 500 MW of solar power in Fort Irwin, CA in 2009 and $1 billion for 371 MW in 124 bases across 33 states in 2011. The companies providing the solar power have mostly been disparate. The major players include SolarCity, ACCIONA, and SunPower. The purchases include photovoltaic solar arrays, microgrids, and occasional experiments with concentrated solar power (CSP).

In addition to these purchases, the Air Force plans to add 488 MW of capacity from renewable sources by 2018 as part of its Renewable Energy Game Plan. The EPA’s Green Power Partnership ranks the Air Force number one in DoD and number two in the federal government for its green energy purchases. According to the Air Force, the branch more than doubled its number of renewable energy projects in 2012.

For its part, the Army recently announced a pair of $7 billion renewable energy purchases. One is described as a “first of its kind” Indefinite Delivery Indefinite Quantity (IDIQ) Multiple Award Task Order Contract (MATOC). The initial announcement was for a geothermal award, with contracts for solar, wind, and biomass expected by the end of 2013. The other provides $7 billion in contract capacity for green energy purchases over three decades through purchase power agreements.

Overall, DoD plans to install 3 GW of renewable energy at military installations by 2025 from a combination of solar, wind, biomass, and geothermal. President Obama reiterated this commitment as recently as June 25 at a speech on climate change at Georgetown University. Other broad goals include adding 1 GW of green energy capacity on Navy installations by 2020, 1 GW for the Air Force by 2016, and 1 GW for the Army by 2025.

As is the case with biofuels, the DoD’s solar purchases confer subsidies for solar energy producers. Electricity derived from solar tends to be more expensive than baseload sources such as natural gas, coal, and nuclear. EIA estimates the levelized cost of photovoltaic solar plants at $144.3 per megawatthour (MWh), compared to $67.1 per MWh for conventional natural gas, $100.01 per MWh for conventional coal, and $108.4 per MWh for advanced nuclear. Since these installations are connected to the electrical grid, the military has the option of purchasing electricity from less expensive conventional sources. By purchasing expensive solar energy instead of affordable conventional energy, the federal government is allowing political preferences to trump sound economics.

The Navy’s “Great Green Fleet”

In 2011, the military made its biggest biofuel purchase when it spent $12 million on 450,000 gallons of biofuel for the Navy’s so-called “Great Green Fleet.” The biofuel was used for a demonstration during the 2012 Rim of the Pacific (RIMPAC) exercise, the world’s largest international maritime exercise. The demonstration showed that the 50-50 mixture of biofuel and petroleum could be used as a drop-in replacement for conventional fuel in an operational setting.

However, focusing exclusively on whether biofuels can serve as replacement fuel ignores the cost of purchasing expensive biofuels over conventional fuel. The biofuels used in the Great Green Fleet demonstration cost taxpayers more than $26 per gallon, when conventional fuel can be purchased for much less. If both biofuels and conventional fuels have comparable performance, then it makes economic sense for the military to purchase the fuel that is less expensive.

The Great Green Fleet, which the Navy plans to deploy in 2016, is one of five “aggressive energy goals” announced by Navy Secretary Ray Maybus in 2009. One of the stated goals of the program is to “improve our combat capability and to increase our energy security by addressing a significant military vulnerability:  dependence on foreign oil.” Reducing dependence on foreign oil, specifically Middle Eastern oil, is a laudable goal. Fortunately, we do not need expensive biofuels to achieve this goal. As noted above, the United States, and North America as a whole, has vast energy resources. The U.S. supply of technically recoverable oil reserves is estimated at 1.44 trillion barrels. In total, North America has more than 1.79 trillion barrels of recoverable reserves.

Furthermore, the recent shale energy revolution, made possible by technological advancements in hydraulic fracturing and horizontal drilling, has led to the greatest domestic energy boom in American history. In oil shale alone, the U.S. has over 982 billion barrels of technically recoverable resources. The map below shows shale plays in the continental United States, many of which were inaccessible just a few years ago.

Those who doubt the abundance of domestic oil resources often note that while the U.S. has about 3 percent of the world’s oil reserves, the country consumes a quarter of the world’s oil. These misleading figures rely on proved reserves, which represent quantities of oil that are known to exist in places where development is already occurring at current economic prices. These figures do not, however, account for the massive quantities of oil that exist in areas where development is not permitted to take place or where new technology will add to the reserve base.

Proved reserves have been a historically unreliable indicator of America’s energy potential. In 1980, the U.S. contained about 30 billion barrels of proved reserves. Yet from 1980 through 2010, America produced over 77 billion barrels of oil. That means over the last 30 years, U.S. oil production exceeded proved reserve estimates by more than 150 percent. Total recoverable reserves, on the other hand, are significantly higher than U.S. proved reserve estimates. If these massive quantities of U.S. oil are made available to explore and produce, the current estimated reserves of 20 billion barrels would certainly increase, providing dramatically more domestic production for decades to come.

As the following chart shows, North American supplies of total recoverable oil resources dwarf the proved reserves of the rest of the world. Moreover, a recent analysis of global energy data finds that the U.S. led the world with the largest oil and natural gas production increases in 2012. Last year also saw the largest year-to-year gain in oil production in U.S. history. These figures demonstrate domestic energy abundance, not scarcity.

In contrast to America’s vast oil resources, the U.S. supply of biofuels pales in comparison. While the U.S. produced about 100 billion gallons of oil in 2012, the country produced just 13.3 billion gallons of ethanol, the largest source of biofuel, and a fuel with only two-thirds the energy content of an equivalent amount of oil. And unlike oil and gas, the biofuels industry is supported by a federal mandate that requires refiners to blend increasing amounts of ethanol into gasoline. Without this Renewable Fuel Standard (a form of subsidy in itself), the market for ethanol would likely shrink considerably.

Not only can America’s vast oil resources be produced domestically, but they are also cheap and abundant. In other words, conventional fuels represent a win-win for the military: energy that is both affordable and reduces America’s dependence on foreign oil. But the military is increasingly displacing affordable oil and natural gas in favor of exotic, unaffordable, and unproven biofuels. To ignore these basic economic facts in favor of propping up the biofuels industry constitutes a subsidy for biofuels and a waste of taxpayer funds.

Conclusion

Federal contracts are potential subsidies when the government purchases a product above fair market value, particularly in a closed-bidding process. Since data from USASpending.gov do not provide a clear picture of contracts for the purposes of identifying potential subsidies, IER does not include contracts data in the Federal Energy Spending Tracker. However, this report shows that the U.S. military has made numerous purchases of uneconomical biofuels and solar systems dramatically above market value when conventional sources provide cost-competitive alternatives. Such purchases should be treated as subsidies for the biofuels and solar industries just like grants, loans, and tax subsidies. At a time of increasing pressure on DOD budgets, questions are arising concerning the wisdom of spending more than is necessary for something so basic as energy for the military.  As time goes on, IER will continue to highlight examples of government contracts that confer subsidies to energy producers and products.

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