Language is important. The way we write and say things is important. I can’t count the number of times I have seen a news headline that would lead most people to conclude something entirely different than what the data actually suggested.

Take the recent release of the BP Statistical Review of World Energy 2013. There are a number of key takeaways from the report, and I will be delving deeper into the data in upcoming articles. Some of the important points were:

1. Consumption growth of all forms of fossil energy grew by 1.8% year-over-year, below the 10-year average of 2.6%

2. The US recorded the largest oil and natural gas production increases in the world, and the largest oil production gain in US history

3. Coal remained the fastest-growing fossil fuel, with China consuming half of the world’s coal for the first time

4. China and India alone accounted for nearly 90% of the net increase in global energy consumption

5. Global nuclear power output had the largest decline ever

I have seen the first point above misreported as “Global Fossil Fuel Energy Consumption Slows.” I have seen others write about the reduced demand for oil. That’s about as accurate as “Innocent until proven guilty.” For instance, in 2011 global oil consumption was 88.9 million barrels per day (bpd). If global oil consumption slowed in 2012 — as some sources have written — what would consumption need to be relative to 2011? Less than 88.9 million bpd. But according to the BP report, in 2012 oil consumption was 900,000 bpd higher than in 2011 — a new all-time record.

What is correct is that growth in oil consumption slowed in 2012. From 2009 to 2010 global oil consumption increased by 2.8 million bpd. From 2010 to 2011, consumption increased by another 1 million bpd. But in failing to note that it is the growth in oil consumption that fell, and not actual oil consumption — many are left with a false impression that perhaps the world is beginning to wean itself off of oil. To the contrary, this is an accurate headline: “Global Oil Consumption in 2012 at New All-Time High.”

Link to Original Article: Did Global Oil Consumption Slow in 2012?

By Robert Rapier

I just finished reading a story that made my blood boil. It was about how the oil industry is using dirty tricks to keep the ethanol industry in check. I need to sit down, take a deep breath, and make sure everyone knows of the atrocity that has happened in Kansas.

The problem started when the ethanol lobby requested — and subsequently received — a waiver from the Environmental Protection Agency (EPA) that would allow up to 15% ethanol in gasoline blends. The current limit is 10%, which is a problem for the ethanol industry because the mandate in the Renewable Fuel Standard already has the country at the 10% limit. It would be a huge boost to the ethanol industry if that limit was moved up to 15%, because that would increase the potential size of their US market by 50%.

Since the EPA allowed 15% — but didn’t mandate it — and because some automobile manufacturers have stated that use of E15 would void car warranties, I predicted that E15 sales would be essentially nonexistent.

And that is exactly what has happened. E15 has failed to win over consumers. Few stations offer it. Head ethanol lobbyist Bob Dinneen says that it is the oil industry’s fault that E15 isn’t being sold. Now comes evidence from Kansas that Dinneen may be onto something.

In Ethanol lobby sees red over a yellow gas hose in Kansas, Reuters brings us the story of Scott Zaremba, who owns Kansas-based Zarco 66. Zaremba says Phillips 66 (NYSE: PSX), his main fuel supplier, is telling him to stop selling gasoline blended with 15 percent ethanol. Well sort of. Actually, not really. Here is what the story claims:

On April 1, Zaremba received a notice from Phillips 66, the nation’s third-largest refiner, that he could no longer sell the E15 fuel from his regular black fuel hoses, as he had been selling it since last July.

Instead, any gasoline with more than 10 percent ethanol has to be served from a separate, yellow hose, according to a copy of the Phillips 66 guidelines seen by Reuters. The aim is to distinguish E15 from other Phillips 66-branded gasolines with 10 percent or less ethanol.

So they aren’t quite forcing him not to sell E15, but they are asking the impossible: For E15 — which many car makers have not approved — to be easily distinguished from E10 by dispensing it from a yellow hose. Now come on! A yellow hose? Do those even exist? Probably not. So in effect, they did force him to stop. The story goes on to explain that Zaremba has quite a dilemma:

He has other options, but they aren’t cheap – or very feasible. For example, it would cost $100,000 to $250,000 to install new stand-alone gas pumps for E15, Zaremba said. Or he can always pay a $412,000 fee to Phillips 66 to break his marketing contract – expensive options that have so far kept him in compliance with the Phillips 66 guidelines, the only way he said he could.

So, his choices were:

1. Get a yellow hose
2. Pay up to $250,000 for a new stand-alone E15 pump
3. Pay $412,000 to Phillips 66 to break his contract
4. Stop selling E15 and blame Phillips 66

Zaremba opted to stop selling E15. After all, what other choice did he have? Even if yellow hoses do exist, who wants to pump their gasoline from a yellow hose? Typical dirty oil company tricks. Monte Shaw, Executive Director of the Iowa Renewable Fuels Association couldn’t have said it any better: “They’ve essentially declared an all-out war (on E15).” I can only imagine the reaction of people who have experienced the horrors of war pulling up and seeing a yellow hose on a gas pump. I am sure it gives them flashbacks.

The oil companies already make it difficult for me to pump diesel into my gasoline-powered car. Now they want to make sure I am “aware” if I am putting in E15 just because it might void my warranty and I might blame them. It’s a sad day for Kansas, and a sad day for America. Yellow hoses indeed.

Link to Original Article: Oil Industry Declares War on E15

By Robert Rapier

Just how far had the price of West Texas Intermediate (WTI) fallen? All the way to $92 a barrel. Keep in mind that WTI opened 2013 at $93.14 a barrel. Since then it has traded between $98/bbl and $87/bbl. (In my Five Energy Predictions for 2013, I predicted that the price of WTI would average less this year than last year, and that the Brent-WTI differential would narrow. To date both predictions have proven to be accurate).

According to the US Energy Information Administration (EIA), the weekly average price of WTI this year traded below $90 only once. The week ending April 19th the average price was $88/bbl. Over the past 12 months, the weekly average has traded in a range of $17/bbl. The low took place during the week ending June 29, 2012 at $80.33 and the high occurred the week of Sept. 24, 2012 at $97.56. The weekly average price of WTI over the past 12 months has been $90.95. So despite the bearish headlines, WTI is still trading above the average over the past 12 months.

Over the past 2½ years, the average weekly price of WTI traded below $80/bbl only once. During the week ending Oct. 7, 2011 the weekly price averaged $79.43, but then climbed back above $100/bbl within two months. To get consecutive closes below $80/bbl, we have to go back nearly three years to the end of September 2010.

Following the oil price crash in 2008, there was some weakness in early 2009 that for a short time saw weekly averages in the $30’s and $40’s, but by October 2009 the price had once again reached $80 despite a severe economic slowdown.

Typically the cycle of oil prices goes like this. High oil prices result in increased spending on new projects by oil companies. But high prices also slow the economy, reducing demand for oil in the process. This combination causes a supply surplus that leads to plunging oil prices and lower investment in new oil projects.

This is a cycle that has been repeated many times, but I believe this cycle will ultimately come to an end because I don’t believe the oil companies will always be able to build out spare capacity to stay in front of growing demand.

Over time the lower prices brought on by the supply surplus act as a stimulus to the economy, and demand — and in turn oil prices — pick back up. Because of the underinvestment by oil companies during the period of low prices, we often see an increase in demand at a time when the oil industry isn’t increasing supply. Thus we return to the oil price spikes that slowed the economy in the first place.

But the 2008-2009 bust was unusually abbreviated. True, prices did plummet, but they didn’t stay down long. Here is why:

Historically global demand was dominated by the US, and while the US and EU both saw decreased demand as a result of the higher prices, demand in every developing region in the world continued to grow. Thus, unlike previous oil spikes, global demand continued to climb and the oil industry was unable to build out the kind of spare capacity that had taken place in the face of previous price spikes.

Between 2000 and 2011, global oil consumption increased by more than 11 million barrels per day, but the development of additional production capacity did not keep pace. This eroded spare capacity in the global oil market, which led to much higher prices and greater volatility.

A number of agencies are predicting much lower oil prices in the coming years. I have been hearing these predictions regularly since 2005. Daniel Yergin, author of the Pulitzer Prize-winning book on the oil industry called “The Prize” and one of the most highly-respected analysts in the industry, consistently underestimated the price of oil during the past decade before recently reversing direction.

But I do agree with the sentiment that supply is likely to expand for several more years. It’s just that demand is going to expand as well, and existing fields will continue to deplete. In an interview conducted last year with former Shell president John Hofmeister, he corroborated my thesis:

“In 2005 China needed about 5 million barrels per day (bpd) of oil; in 2011 China needed 10 million bpd of oil; by 2015 China will probably need 15 million bpd of oil. And that kind of tripling of demand in China, augmented by significant additional increases in daily demand from the rest of the developing world, including India and the fact that OPEC has been largely flat in its production and its inability to create spare capacity for most of the last decade is behind surging prices.”

Oil depletion reduces production in existing fields by 4 million to 5 million bpd each year, which means it takes that much new oil development just to maintain global production rates. Mr. Hofmeister summarized the problem as “We have not been able to keep up with demand growth and the decline rate simultaneously.”

However, over the past few years tremendous investments have been made in finding and developing new sources of oil, and growing demand will not as easily erode spare capacity as in recent years. This is why I have predicted that oil is likely to trade in a range — perhaps as low as $70 up to maybe $120 for the next few years. Some may feel that it is unlikely that oil could fall to $70. After all, it’s been three years since the price of WTI was at that level. But if Iran capitulates on its nuclear program, escaping the related trade sanctions, a lot of oil could hit the market, and certainly the expectations of oil traders could drive prices down in a hurry in that situation.

Link to Original Article: About Those Plunging Oil Prices

By Robert Rapier

In last week’s post Who Wins from Rising Natural Gas Prices?, I discussed the sectors that would benefit from rising natural gas prices. This week, let’s talk about the potential losers.

Natural gas is an important feedstock for the chemicals and fertilizer industries, so higher prices could pressure those sectors. Oil companies with significant chemical operations could also see this business segment take a hit, but based on ExxonMobil’s (NYSE: XOM) advocacy of liquified natural gas (LNG) exports, it clearly believes the net effect of rising natural gas prices on the company would be positive.

Dow Chemical (NYSE: DOW), on the other hand, has come out strongly against LNG exports because of the potential cost to its own business and that of other heavy users of natural gas. Ironically, last week the Department of Energy granted a permit to a facility called Freeport LNG — in which Dow owns a 15% stake. Dow’s answer to that is that they invested in the facility when it was supposed to be an LNG import facility.

Biofuels Sector

But the risks to the chemicals and fertilizer industries are well-known. What isn’t as well-known is the risk from higher natural gas prices to the biofuels sector. This may be counterintuitive, since renewables like wind and solar power become more competitive as natural gas prices increase.

The difference (unappreciated by many biofuels investors) is that many biofuel technologies rely heavily on natural gas. Corn ethanol production, for instance, is dependent on process steam that is mainly produced from natural gas. And since natural gas is also a key component in fertilizer, higher natural gas prices tend to drive up fertilizer prices and eventually corn prices, subjecting ethanol producers to a double whammy.

But the advanced biofuel industry may be at an even greater risk, since it hasn’t yet become economically competitive.

Take KiOR (Nasdaq: KIOR), for instance. KiOR’s technology starts with a fast pyrolysis process that heats up biomass rapidly to break it down. KiOR uses a common oil refining process called Fluid Catalytic Cracking (FCC) technology for the pyrolysis step in a process they call Biomass Fluid Catalytic Cracking (BFCC). The end product is partially upgraded pyrolysis oil (still very different from crude oil), which is further upgraded to gasoline and diesel blendstocks via another common oil refining process called hydrotreating.

The entire process is heavily dependent on hydrogen from natural gas. Based on my calculations from KiOR’s published statements on wood feedstock inputs (500 bone dry tons) and gasoline, diesel, and fuel oil outputs (13 million gallons per year), as much as half of the energy content of the produced fuel has to be derived from natural gas.

Natural Gas Laundering

As an aside, even though half of the BTUs are derived from natural gas, the fuel that is produced qualifies as 100% renewable fuel, and therefore receives tax credits as 100% renewable fuel. One might think of this as natural gas laundering, where the natural gas “becomes” renewable by being combined with biomass. And because this natural gas is being provided by companies like ExxonMobil, and is still relatively cheap due to the new supplies brought about by the fracking revolution, many advanced biofuel producers are ironically dependent upon both ExxonMobil and the fracking revolution.

Thus, KiOR — and certain other advanced biofuel producers — have a very high sensitivity to natural gas prices. This is another reason to shy away from investing in KiOR, which I have been advising investors to do since 2011. This has proven to be good advice, as the company’s share price has fallen 70 percent since mid-2011.

Meanwhile, KiOR recently announced a net loss of $31.3 million for the first quarter of this year. Several analysts surprisingly (to me) reiterated ratings of “Overweight” or “Outperform” on the company in response to the results, seemingly oblivious to the company’s sensitivity to higher natural gas prices. Even more surprising is that one analyst — Pavel Molchanov from Raymond James – reiterated the “Outperform” rating that he first made on August 15, 2011. How well has KiOR “outperformed” since he made this initial recommendation? The share price has fallen over 60%, and yet he reiterated his “Outperform” rating.

In my opinion many of the analysts covering these advanced biofuel companies don’t have a firm enough grasp on the technology or the risk factors involved. As a result, their clients end up with steep losses.

Conclusions 

Thus, if you believe that natural gas prices will retain strength in the coming months, the companies at most risk are chemical companies (including fertilizer manufacturers) and biofuel companies — particularly advanced biofuel companies engaged in hydrotreating.

Link to Original Article: Who Loses from Rising Natural Gas Prices?

By Robert Rapier

Stronger natural gas prices are good news for some and bad news for others. Natural gas producers like Chesapeake Energy Corporation (NYSE:CHK) were hit especially hard as gas prices fell. Between June 2011 and April 2012, CHK’s share price declined 25 percent. But over the past 12 months, CHK has rallied 36 percent as gas prices recovered. Since Chesapeake is the nation’s second-largest producer of natural gas, it’s not surprising that its shares track the price of the commodity. The company isn’t diversified, so it is nearly a pure play on natural gas.

(Related: Short-Term Trend in U.S. Natural Gas Prices Point Higher)

However, Chesapeake isn’t the nation’s largest producer of natural gas. That distinction goes to ExxonMobil (NYSE:XOM). ExxonMobil shares have underperformed in recent years because of the company’s ill-timed $41 billion buyout of natural gas producer XTO Energy in 2009. The week the deal was announced natural gas fetched close to $6 per MMBtu. The acquisition of XTO made Exxon the largest US natural gas producer just as prices began a long decline. By June 2012 CEO Rex Tillerson was admitting that “We are losing our shirts” on natural gas production because of low prices.

As a result, ExxonMobil’s share price has lagged that of competitors like Chevron (NYSE: CVX), whose natural gas production is a much smaller part of its business. Over the last five years CVX is up 23 percent, the S&P 500 17 percent, and XOM a mere 1 percent. (Keep in mind that this time period includes the oil price crash of 2008.) Over the past 10 years CVX is up 265 percent and XOM 154 percent, but CVX only began to seriously outpace XOM in 2009 — the year the XTO acquisition took place.

ExxonMobil wasn’t the only oil producer to have made an ill-timed foray into natural gas. The timing was even worse for ConocoPhillips (NYSE: COP), which acquired Burlington Resources for $35.6 billion in 2005 (when I was still working for COP). At the time, natural gas prices were hovering near $15 per MMBtu and many were predicting that they might stay that high for years. As with ExxonMobil, ConocoPhillips shares fell behind those of competitors as natural gas prices declined, a trend that only reversed once the company spun off its refining business in April 2012.

(Related: World Energy Consumption Facts, Figures, and Shockers)

So, if you are of the opinion that natural gas prices will retain strength in the coming months, the companies to target for superior performance are obviously the natural gas producers, especially those with the greatest potential to profitably grow their output. Given their heavy investments in natural gas, ExxonMobil and ConocoPhillips, along with Chesapeake, stand to benefit from the recovery in natural gas prices. Chesapeake has already made a strong upward move, so they may not have much upside left unless gas prices continue to rise. But I expect XOM and COP to outperform over the next 6-12 months as long as gas (and oil) prices remain strong.

Next week I will discuss the potential losers from higher natural gas prices, some of which are far from obvious.

Link to Original Article: Who Wins from Rising Natural Gas Prices?

By Robert Rapier

(Related: The Energy Industry’s Production Challenge: 100 Million Barrels Per Day)

The new USGS assessment stated that the Three Forks formation had not been previously assessed, but that an assessment was warranted based on a rise in drilling and production in the formation. Inclusion of the Three Forks formation added an estimated mean resource of 3.73 billion barrels of oil to the estimated 3.65 billion barrels of oil in the Bakken formation for a total estimated resource of 7.4 billion barrels of undiscovered, technically recoverable oil in the two formations. The two formations were also estimated to contain a mean of 6.7 trillion cubic feet (tcf) of undiscovered, technically recoverable natural gas and 0.53 billion barrels of undiscovered, technically recoverable natural gas liquids (NGLs).

Figure 1. Location of the Three Forks Formation Assessment Units (AUs) in the Williston Basin. Inset map shows location of the Bakken Total Petroleum System (TPS). Source: USGS

The new assessment represents a doubling of estimated undiscovered, technically recoverable oil and a nearly threefold estimated increase in mean natural gas and mean NGL resources from the 2008 assessment. The increase in estimated resources is primarily due to the inclusion of the Three Forks Formation. However, Rigzone reported that a USGS spokesperson explained that the size of the Bakken estimate also increased:

“It’s deceptive, because although our current estimate of 3.65 billion barrels of oil for the Bakken is numerically the same as the 2008 assessment for the Bakken, you have to remember that oil companies have been producing millions of barrels of oil since the 2008 assessment, gradually transforming the undiscovered resources to the proven reserves then production barrels,” the spokesperson commented. “Because our assessments do not include proven reserves or produced barrels of oil, the 3.65 billion does represent an increase.”

While recognizing that “undiscovered resources” are not quite a bird in the hand, these estimates are likely to assure that the oil boom in North Dakota continues for some time. If nothing else, companies will be searching for oil there.

(Read More: The Effect of New Production Methods on U.S Oil Output)

How much oil does this represent? The US currently uses nearly 7 billion barrels of oil per year, so the total from the new assessment of undiscovered oil would represent just a bit over a year of US oil consumption at current rates. Petroleum imports have been declining, but the US still imports about 3 billion barrels of oil per year. Thus, in terms of imports, this new assessment of undiscovered oil amounts to a little over 2 years of US petroleum imports.

So, while it is a lot of oil, it is going to take a lot more than that to make the dreams of US petroleum independence come true. I do expect US oil production to continue to climb for another 3 to 5 years though, primarily as a result of a continued growth in oil production in the Williston Basin, as well as the Permian Basin and Eagle Ford Shale in Texas.

(Related: The Amazing Reversal of the US Oil Industry)

Link to Original Article: Estimate for Williston Basin Oil Resources is Doubled

By Robert Rapier

This scenario could change dramatically if cost-effective energy storage solutions were developed. I consider this to be the most important unresolved problem in the energy business. A company that develops a way to efficiently and economically store intermittent energy for on-demand use will be a game-changer.

The ideal power storage solution would be able to store energy densely, at a reasonable capital cost, and would be able to return that power at high efficiency. For instance, if we put 1 unit of power into the storage system and we actually got 1 unit back out when we needed it, the system would be 100% efficient. Real-life efficiencies will be less than 100%, but the higher the efficiency, the more desirable the storage option.

A new report on energy storage from Navigant Research predicts that the market for energy storage for the electric grid could surpass $30 billion annually by 2022. Some of the potential options include batteries, pumped hydropower, compressed air energy storage (CAES), flywheels, hydrogen, and fuel cells. And of course nature also has a built-in storage mechanism for solar power (albeit an inefficient one) called biomass.

The following figure highlights the biggest problem with most energy storage options — the energy density is simply too low. Energy density measures the amount of energy stored per unit of volume or weight. What this means is that for a given volume or a given weight, the storage options can store only a tiny fraction of energy relative to liquid fuels.

The most energy dense options possible would be those at the top and to the right of the graphic. Were Uranium-235 included, it would have appeared at the top right corner, but far beyond the scale of this graphic. The least energy-dense options would be those at the bottom left of the graphic, which is where we find batteries, flywheels, and compressed air. At this scale, the energy density of these storage options appears to be near zero. Relatively speaking, gasoline contains more than 50 times the energy of the same volume of a nickel-metal hydride battery.

Pumped hydropower storage (PHS) is a storage option that is already commercially used in some conventional power plants. The concept is that off-peak power is used to pump water up to a reservoir at a higher elevation, and then returned through turbines to produce electricity. A March 2012 report by the Electric Power Research Institute (EPRI) indicated that PHS accounts for 99 percent of utility-scale storage capacity worldwide. PHS has a reported round-trip efficiency of about 75 percent, considerably higher than that of many other storage options.

There are around 50 PHS systems of at least 1 gigawatt (GW) installed around the world, with another 15 or so facilities of this size under construction. Operating facilities exist in the US, China, Japan, South Africa, Russia, Australia, South Korea and in a number of European countries. The largest facility in the world is a 3 GW system in Bath County, Virginia.

The primary advantage of PHS is that very large amounts of power can be stored for long periods of time, but accessed quickly. The major disadvantages are that initial capital costs are high and the technology is limited by geography to locations that can host a large reservoir at a significantly higher elevation than the power station.

Compressed air energy storage (CAES) is the second largest category of utility-scale energy storage. In a CAES system, off-peak power is used to compress air into a storage reservoir, which is later released through a turbine to produce electricity as needed. This reservoir is typically an underground cavern, but some work is being done to develop these systems under water, in enclosed bags that expand against the outside water pressure.

The first utility-scale CAES facility was built in Germany in 1978, utilizing a salt dome as the reservoir. The first system in the US was built in 1991 in Alabama. A salt cavern is also used in this system, which can compress air up to 1100 pounds per square inch (psi). Other projects are under development, with the US Department of Energy providing funding in some cases.

As with PHS, CAES is limited by geography. Further, the cycle efficiency of the systems currently operating is reportedly 40 percent or less — much lower than with PHS.

Hydrogen is one of the more energy-dense storage options by weight. One kilogram (kg) of hydrogen compressed to a pressure of 150 bar (2,175 psi) actually stores a lot more energy than one kg of gasoline (the horizontal axis is energy density by weight). As shown in the graphic, compressed hydrogen contains more than three times the energy of gasoline per kg (142 megajoules for hydrogen versus 46 megajoules for gasoline).

However, hydrogen falls short when it comes to volumetric storage (the vertical axis). One liter of gasoline contains over 20 times the energy of one liter of 150 bar hydrogen. Thus, one of the limitations of hydrogen as a fuel is that the range of a vehicle running on hydrogen will fall far short of that vehicle utilizing a similar-sized gasoline tank.

Nevertheless, the German utility E.ON (OTC: EONGY, Frankfurt: EOAA) is investing in a hydrogen-based storage system. In 2012 E.ON contracted with Canada’s Hydrogenics (NASDAQ:HYGS) to install a power-to-gas system in Falkenhagen, Germany. The idea in this case is that off-peak power is used to make hydrogen from water by electrolysis, and then the hydrogen is injected into a natural gas pipeline. The hydrogen-natural gas mixture can then be used as needed for power production, or for heating.

Of course energy is lost when water is broken down into hydrogen and oxygen. The efficiency of electrolysis of water into hydrogen can be as high as 85 percent. Hydrogenics reports that the efficiency of its hydrogen fuel cells “is greater than 55 percent” in converting hydrogen into electricity. So we could expect the cycle of converting off-peak power into hydrogen and then back to electricity during peak demand would be (0.85) * (0.55) = 47 percent efficient. In other words, a little more than half of the power sent to storage is wasted.

This also implies that the value of peak power would need to be more than twice the value of off-peak power to make such storage profitable. For example, if off-peak power is worth a nickel, and peak power is worth a dime, then a nickel’s worth of power sent to storage is only worth 4.7 cents (47% of a dime) at peak demand. On the other hand, if peak power is worth 15 cents in this scenario, a nickel’s worth of off-peak power can be turned into 7 cents of peak power (47% of 15 cents).

Batteries comprise an enormous global market, and are often used in personal solar systems to provide power at night. But batteries are seldom used to back up power plants because they have low energy density, are expensive, and have a limited lifespan. However, a great deal of research is being devoted to the development of advanced batteries, which are projected to reach gigawatt levels of utility-scale storage over the next 10 years.

Governments are investing heavily in the development of utility-scale storage, and a number of utility-scale storage possibilities are still in development. This is an area that promises to grow rapidly in the coming years given the number of countries implementing aggressive renewable electricity standards.

See also: The Most Important Problem in Renewable Energy — R-Squared Energy TV Ep. 22

Link to Original Article: The Key to Running the World on Solar and Wind Power

By Robert Rapier

In this case, the data sources are the 2012 BP Statistical Review of World Energy and the Energy Information Administration. A table showing the Top 15 countries with the highest percentage increases in oil production over the past five years follows the quiz. Answers are at the end.

1. Which country had the largest percentage increase in oil production from 2007 to 2011?

a. Canada
b. United States
c. Russia
d. Columbia

2. Which country produced the most oil in 2011?

a. Iraq
b. Qatar
c. United States
d. Brazil

3. Which country supplied no oil exports to the US in 2012?

a. China
b. Chad
c. Cameroon
d. Qatar

4. Which country was not among the Top 5 suppliers of oil to the US in 2012?

a. Nigeria
b. Venezuela
c. Iraq
d. Saudi Arabia

5. Which country was the largest export destination for refined products (e.g., gasoline, diesel, jet fuel) from the US in 2012?

a. Canada
b. Mexico
c. The Netherlands
d. Brazil

Here are the Top 15 countries with the largest percentage increases in oil production from 2007 to 2011.

Oil Production Increases in Countries from 2007 to 2011 (Source: 2012 BP Statistical Review of World Energy).

Answers

1. US oil production increased by a respectable 15% over this time period, but that lagged far behind the 67% increase in oil production that took place in Columbia.

2. US oil production in 2011 exceeded that of the other three countries combined.

3. According to the EIA, Qatar is the only country among the four from which the US imported zero oil in 2012.

4. Nigeria is traditionally one of the Top 5 suppliers of oil to the US, but declining production there plus an increase in production from Iraq caused Nigeria to slip behind Iraq and out of the Top 5.

5. All four countries imported significant amounts of products from US refineries, but Mexico was the top destination for US exports. In 2012 the US imported 970,000 bpd of crude oil from Mexico and sent them nearly 600,000 bpd of finished products.

Link to Original Article: Test Your International Oil IQ

By Robert Rapier

In reviewing the data for individual states, I came across some interesting trivia. So I decided to put together a little quiz. The data source is the EIA. A table showing the Top 15 states with the highest percentage increases in oil production follows the quiz. Answers are at the end.

1. Which state had the largest percentage increase in oil production over the past 5 years?

a. Texas
b. North Dakota
c. Colorado
d. Oklahoma

2. Which state had the largest volume increase in oil production over the past 5 years?

a. Texas
b. North Dakota
c. Alaska
d. Oklahoma

3. Which of the following states reported no oil production over the past 5 years?

a. Arizona
b. New York
c. Florida
d. Tennessee

4. Which state had the largest percentage decline in oil production over the past 5 years?

a. Louisiana
b. California
c. Montana
d. Alaska

5. Which of the following states had the highest average oil production over the past 5 years?

a. North Dakota
b. California
c. Louisiana
d. Oklahoma

Here are the Top 15 percentage increases in oil production  from 2007 to 2012.

Oil Production Increases in US States from 2007 to 2012 (Source: Energy Information Administration).

Answers

1. North Dakota’s oil production increased by a whopping 435% between 2007 and 2012. Colorado ranked second with an 86% increase over the 5-year period.

2. North Dakota gets the most press due to the oil boom there, but Texas has increased oil production by 900,000 barrels per day (bpd) over the past 5 years, versus 540,000 bpd for North Dakota.

3. Arizona is the only one of these states that reported no oil production over the past 5 years. Production in the other 3 states was modest, but New York, Florida, and Tennessee all reported some oil production in each of the past 5 years.

4. While all 4 of these states saw declines in their oil production over the past 5 years, Alaska’s 27% decline was the largest decline among all 50 states.

5. Although California’s oil production has been declining, it actually averaged a higher level of production than North Dakota, Louisiana, or Oklahoma over the previous 5-year period. California’s 554,000 bpd of average daily production over the past 5 years trailed only Texas’ 1.4 million bpd and Alaska’s 603,000 bpd. However, as of 2012 California had slipped behind North Dakota, but was slightly ahead of Alaska.

Link to Original Article: Test Your Oil IQ

By Robert Rapier

In 1978 the United States Environmental Protection Agency (EPA) issued a gasohol waiver that set the maximum legal limit of ethanol in motor gasoline at 10 percent denatured anhydrous ethanol.

27 years later, the Energy Policy Act of 2005 created a Renewable Fuel Standard (RFS) requiring 7.5 billion gallons of renewable fuel — primarily corn ethanol — to be blended into the fuel supply by 2012.

In 2007, an updated Renewable Fuel Standard — the RFS2 — accelerated the renewable fuel adoption schedule. Instead of 7.5 billion gallons by 2012, the new law required 9 billion gallons by 2008, soaring to 36 billion gallons by 2022.

Hitting the Limits

Americans presently consume about 133 billion gallons of gasoline each year, so somewhere in the range of 13 billion gallons of ethanol (approximately the amount of corn ethanol that is currently being produced in the US) the rising ethanol mandate was set to collide with the EPA’s 10% ethanol limit.

The ethanol lobby recognized this potential limitation to their market, so they petitioned the EPA to raise the allowable limit on ethanol content in conventional gasoline to 15 percent. But if this higher ethanol concentration were mandated instead of “allowed”, it would immediately increase ethanol’s market potential in the US by 50 percent.

The E15 push was opposed by automakers, oil companies, food producers, and environmental groups. Each lobby opposed the higher limits on different grounds, with automakers concerned about vehicle damage from using E15 in automobiles that weren’t designed for that concentration of ethanol. (Ethanol is more corrosive than gasoline, and while these corrosion issues can be addressed, some cars that weren’t designed for higher levels of ethanol could be damaged).

Despite the opposition, the EPA ultimately approved E15 for use, initially for model year 2007 and newer cars and light trucks, and later expanding that for use in 2001 and later models.

However, since it was allowed and not mandated — and damage could still result from using E15 in boats, motorcycles, small engines, and older cars – I predicted that adoption of E15 would be close to zero. That has in fact proved to be the case.

Forcing Consumers to Purchase More Ethanol

But I also predicted that once the waiver was granted, the next step would be for the ethanol lobby to ask for an E15 mandate. Some people argued that this would never happen. After all, how could the EPA force consumers to purchase fuel that many automakers have said would void their warranties? In response, I remind people that the EPA recently required gasoline blenders to blend nonexistent volumes of cellulosic ethanol. So it could definitely happen.

The ethanol lobby is now becoming more vocal in their calls for an E15 mandate. In a recent NPR story — EPA’s Push For More Ethanol Could Be Too Little, Too Late — chief ethanol lobbyist Bob Dinneen, who is President and CEO of the Renewable Fuels Association, continued to complain about the oil industry’s failure to embrace the ethanol industry:

Dinneen says this is the way Congress envisioned the mandate working: more and more ethanol over time in a gallon of fuel, and less and less petroleum.

“This is about market share,” Dinneen says. “This is about their profitability; it’s not any more complicated than that.”

Apparently, irony is lost on Dinneen — or he really is that big of a hypocrite — because it’s also about the ethanol industry’s market share. It’s about their profitability. Or does Dinneen want us to believe that his motives are as pure as the driven snow? That he isn’t being driven by his own fat salary — reportedly $469,332 in 2011 (available at http://www.guidestar.org/)? Incidentally, another irony is that because ethanol is mandated, we are all chipping in for Dinneen’s salary.

Demanding Perpetual Handouts to Stay Afloat

Here is my problem with the ethanol industry. My problem is not that there is an ethanol industry. Some people assume that if you have a problem with our ethanol policy, then you have a problem with ethanol, period. So I always have to add my standard disclaimer that my objections are about policy.

My problem is that the way we have gone about this has resulted in an industry that is dependent on perpetual welfare. The industry simply can’t exist without the direct involvement of the US government. Therefore, what’s been created is an industry that constantly has its hand extended for more government intervention lest it go under. Hence, the industry needs highly paid lobbyists who demand that the government force consumers to buy more and more of their product. That, to be blunt, is an exceedingly stupid way to create an industry.

Conclusion

As I have argued many times, I don’t have an issue with ethanol as a fuel. In fact, I think state governments — particularly in the Midwest — could do a lot to push E85 as the preferred fuel in the region (See E85 Case Study: Iowa). But the ethanol industry has never been about creating their own markets. They have always depended upon the government to force others to buy their product. This has established their industry as one of the largest recipients of welfare in the country, and it has made it virtually impossible for the industry to wean off of this welfare without collapsing.

A much better way to build a thriving ethanol industry would be to provide specific tax incentives for the adoption of ethanol. I am not talking about the federal tax credit that has since expired. I am talking about state governments shifting taxes from state income taxes, property taxes, and/or sales taxes into higher gasoline taxes — while exempting ethanol. This could be done in a revenue neutral manner, but one that makes locally produced ethanol more cost competitive with gasoline. If E85 established itself as a consistently more economical option than gasoline, then the Midwest alone could absorb three times the current US ethanol production.

But that would take too much effort I suppose. Far better to wine and dine lawmakers until they force consumers to buy your product. Instead of investing in ethanol distribution, continue to argue as Dinneen does that it is the oil industry’s fault that E15 isn’t being sold (despite the fact that automakers are warning of voided warranties). Over the long term, that not only keeps the industry dependent on the government, it creates an ever larger class of resentful consumers.

Note: I will be “off the grid” until April 12th, and unable to respond to comments.

Link to Original Article: Ethanol Lobby Agitates for E15 Mandate

By Robert Rapier