To be sure, the US faces numerous headwinds, and US economic policy is open to a number of valid criticisms. As an American, I cringe at the state of the nation’s public finances, the size of our national debt and the eroding value of the US dollar.

But when it comes to energy, the US is in a far stronger position than almost any other major industrialized power. The US economy is relatively sheltered from rising energy prices and has a comparatively benign domestic energy policy, at least for now.

US Advantage: (Relatively) Cheap Energy

Americans spend a lot of time complaining about gasoline prices approaching $4 per gallon, which means that readers frequently ask what impact $4 or $5 per gallon gasoline will have on the nation’s economy. Every investor has also seen the statistics about how much money the US spends on importing oil and other energy commodities from abroad.

But a graph of oil prices doesn’t capture the full energy costs borne by a country; households consume more than just gasoline and oil. In the US, only about 35 percent of primary energy consumed comes from oil; coal (23 percent), natural gas (20 percent) and nuclear power (8 percent) also figure into the energy mix. Changes in the price of gas and coal can have profound effects on the cost pressures consumers experience.

Source: Energy Information Administration, Bureau of Economic Statistics, Bloomberg

This graph tracks the total cost of energy in the US as a percent of gross domestic product (GDP) going back to 1970. This measure of energy includes the cost gasoline and diesel used in cars, natural gas used for heat and gas, and wind, solar, nuclear and coal-fired power.

As of the end of 2010, US energy use amounted to slightly less than 9 percent of GDP. That’s roughly one full percentage point below the average cost of energy in 2008, when crude oil prices approached $150 per barrel and natural gas exceeded $13 per million British thermal units (BTU).

This graph is based on annual data on US energy consumption and retail prices. On average energy cost US consumers about 10 percent of GDP in 2008; however, the average annual cost understates the pain Americans felt at the height of the commodity price boom in mid-2008. In the third quarter of that year, US energy spending came in at an annualized rate of 12 to 12.5 percent of GDP.

Of course, energy costs peaked in the early 1980s, approaching 14 percent of GDP in 1981. Although oil prices in 1980 and 1981 averaged $32 to $34 per barrel–compared to just over $100 in 2008–the value of the dollar was higher back in 1980-81. In addition, the US economy was far less energy efficient in 1981 than it is today; twenty years ago, it took more energy to produce $1 in GDP. That’s why high energy prices weighed more on the US economy in 1981 than in mid-2008.

Despite elevated gasoline prices, US consumers aren’t feeling the pinch as much as in mid-2008. Natural gas prices are about 70 percent below their 2008 high, and US thermal coal prices remain at less than half their recent high. On average, average US energy costs are about 1 percent of GDP less than in 2008 and as much as 3 percent less than July 2008 when oil prices peaked.

The situation is much worse in most countries, which also face higher prices but lack access to inexpensive coal, natural gas and electricity.

US Advantage: The Shale Revolution

The US is the world’s largest producer of natural gas, producing almost as much natural gas as the entire Middle East and Africa combined. This resource wealth stems largely from the development and commercialization of a number of unconventional shale gas fields such as the Haynesville Shale of Louisiana and the Marcellus Shale in Appalachia. In fact, the Haynesville is now the largest gas field in the US, overtaking the Barnett Shale in early 2011.

Producers have known about many of today’s hottest unconventional gas and oil plays for many decades. For example, the Barnett Shale of Texas is one of the largest and most developed unconventional shale reserves, accounting for about 8 percent of US gas production. But the Barnett has been known to contain large quantities of natural gas since at least the 1970s, and the first wells were drilled in the early ’80s. However, drilling technologies used at that time weren’t sufficiently advanced to produce economic quantities of gas from the play. According to the Oil & Gas Journal, only 82 wells were drilled in the prolific Barnett as of 1990–nearly a decade after the first well was drilled.

Two major technologies revolutionized the development of unconventional shale fields. Natural gas and oil doesn’t exist underground in some giant cavern or lake. Rather, hydrocarbons are found trapped in the pores and cracks of a reservoir rock. These rock formations lie in layers, not all of which contain economic quantities of gas.

A horizontal well travels vertically down to the most productive layers of rock and then sideways for 3,000 to more than 12,000 feet, depending on the field. This horizontal segment increases exposure to the productive region than a traditional well. Albeit more expensive to drill, horizontal wells are more prolific producers.

The second technological innovation behind the shale gas revolution is the development of hydraulic fracturing techniques. Most unconventional plays have plenty of gas in place, but the reservoirs lack permeability. In other words, the pores and cracks within the reservoir rock contain hydrocarbons, but a lack of interconnections prevents the oil or gas from flowing.

Hydraulic fracturing involves pumping a liquid into the reservoir; this pressure cracks the rock, creating room for the gas to flow through the formation into a well. That is, fracturing improves the permeability of the field. Producers also introduce what’s known as proppant–typically sand, sand coated with resin or ceramic material–into the fracturing fluid. The proppant enters the fractures caused by the fracturing and holds (or “props”) these cracks open. This prevents the newly formed cracks from closing as soon as pressure is removed.

With the US producing all-time record quantities of gas, the oversupply has depressed prices. The US has no real need to import natural gas in the form of liquefied natural gas (LNG). In fact, country is regarded as a market of last resort for LNG cargoes because North America has more capacity to store gas than most other gas-consuming regions of the world. In total, the US imports less than 10 percent of the gas it consumes, with virtually all of those imports coming from Canada.

In North America, natural gas costs less than one-quarter what oil costs on an energy-equivalent basis. The gas-to-oil price ratio is currently hovering near all-time lows. 

Compare that to other major economies around the world. In Europe the largest single source of gas imports is Russia, and most contracts with Russia are so called take-or-pay deals indexed to crude oil prices. European utilities must accept delivery of a contracted volume of gas or pay a penalty; with European gas markets well supplied in recent years, these penalties have grown significantly. With oil prices on the rise, natural gas prices in the contracts could jump to between USD13 and USD15 per million BTUs from USD8 in late 2010.

As a result, European gas buyers are accepting as little natural gas as possible under the contracts they’ve signed with Russia and are seeking to procure supplies from elsewhere in the form of liquefied natural gas (LNG), a super-cooled and compressed form of natural gas suitable for transport by ship.

But the costs of LNG cargoes are also rising in Europe. The LNG market has been glutted for the past few years, but that excess dissipating. Fewer LNG export projects are slated come onstream over the next few years. Meanwhile, demand, particularly in Asia, is rising rapidly.

The recent tragic earthquake in Japan likely will push up demand for LNG; Japan imports all of its natural gas in the form of LNG. Germany will also need to import gas to offset the loss of electricity output from the seven reactors it closed in the wake of the Fukushima accident.

Source: Bloomberg

This graph depicts the 12-month strip price–the average of the next 12 months of futures prices– for US natural gas that trades on the New York Mercantile Exchange. Currently, US natural gas currently goes for $4.73 per million BTUs, up from about $4.20 at the end of February 2011.

The graph also features the 12-month Intercontinental Exchange strip prices for gas. These prices are quoted in terms of British pence per therm (10 therms = 1 million BTUs). I converted the ICE futures prices to the US standard; current prices are about $11 per million BTUs, compared to $9 per million BTUs at the end of February. This spike in UK gas prices stems from Germany and other European nations relying more heavily on natural gas as a power source.

LNG is a top new theme in The Energy Strategist and a major beneficiary of the shift in global energy consumption in the wake of the tragic earthquake in Japan. We just added a company that’s a world leader in the production, transport and supply of LNG to the newsletter’s model Portfolio. Subscribers can check out the March 23, 2011, issue The Falllout for details. 

US Advantage: The Saudi Arabia of Natural Gas Liquids

Natural gas is composed primarily of methane, a hydrocarbon consisting of one carbon atom bound to four hydrogen atoms (CH4). But raw natural gas produced from wells isn’t homogenous; methane typically occurs with a variety of heavier hydrocarbons (NGLs) such as ethane (C2H6), propane (C3H8) and butane (C4H10). Crude oil, water vapor, carbon dioxide, nitrogen and sulfur also mix with raw natural gas.

The components of this mélange vary from field to field. Some regions produce “dry” natural gas, or gas that consists primarily of methane with little NGL content. In contrast, “wet” fields such as the Eagle Ford of Texas and the Marcellus Shale in Appalachia also contain large quantities of NGLs.

NGLs may not receive as much media attention as crude oil or natural gas, but they’re vital energy commodities. Ethane and propane are commonly employed as petrochemical feedstock. Ethane is used to make ethylene, while propane is used to manufacture propylene–chemicals that form the building blocks of various plastics. Oil refineries also use NGLs to boost the octane rating of gasoline.

When NGL prices are low, producers leave some NGLs in the natural gas stream to be burned with methane–a common practice for ethane the most prevalent and lowest-price NGL. But NGL prices are elevated by historical standards, while natural gas prices remain depressed. In this environment, producers maximize returns by removing the NGLs from the raw natural gas and selling each component separately. 

The US shale gas revolution is also a boon for NGL supply; many of the most promising US gas shale fields are rich-gas fields that also contain large quantities of NGLs.

For example, the Eagle Ford shale play in southern Texas contains three distinct windows: an oil window, a wet-gas window and a dry-gas window. As companies ramp up drilling in the Eagle Ford, they produce more NGLs–a key contributor to profit margins. Natural gas currently goes for $4 per million BTU in the US, near a multiyear low. Meanwhile, crude oil prices have shuffled between $100 and $115 per barrel this year. A mixed barrel of ethane, propane, butane and isobutene costs roughly $56 per barrel. Better prices for oil and NGLs has prompted producer to focus on liquids-rich plays. Check out this graph of US NGL production.

Source: Energy Information Administration

The increased availability of NGLs enables US petrochemical producer to better compete with international companies on price. During Enterprise Products Partners LP’s (NYSE: EPD) conference call to discuss fourth-quarter results, the MLP’s Chief Operating Officer quoted a passage from a recent sell-side analyst report on Dow Chemical’s (NYSE: DOW) new joint-venture chemicals production facility in Kuwait, EQUATE:

We visited EQUATE as a part of our Middle Eastern field trip in June 2010 and it was clear that lack of cheap ethane feedstock in Kuwait would mean future capacity expansions would use naphtha as a feedstock, which would likely position the new capacity above the US Gulf Coast on the cost curve. Similar issues appear to be present in Saudi Arabia.

Not too long ago, industry observers would have scoffed at the suggestion that US petrochemical firms would enjoy a cost advantage over facilities in Kuwait and Saudi Arabia. But the shale gas revolution has ensured that the US chemical producers have access to an abundance of NGLs at reasonable prices, a huge advantage over areas where NGL prices are higher or naphtha–which is derived from crude oil and therefore costlier–serves as the primary feedstock.

In fact, the US is becoming an increasingly important exporter of NGLs.

Some of my favorite plays in the US NGLs market are master limited partnerships involved in processing gas to produce NGLs, transporting NGLs or storing NGLs. Most offer yields in the 5 to 8 percent range

US Advantage: Low Oil Import Share

Before you laugh, consider that the US is the third-largest oil producer in the world, trailing only Saudi Arabia and Russia. The US produces over 7 million barrels per day, more oil than all of South America combined. And US oil production has actually increased over the past couple of years.

The dollar value of US oil imports is staggering because the US consumes a lot of oil and is a huge economy. But check out this graph.

Source: BP Statistical Review of World Energy, 2010

This chart shows the share of each country’s oil consumption that’s covered by domestic production. With the exception of the UK and other major energy-producing countries such as Russia and Australia, it’s hard to find a major economy in better shape than the US. Germany, France, Italy and Japan depend almost completely on oil imports from abroad, making them particularly vulnerable to oil supply shocks.

 The US produces about 40 percent of the oil it uses domestically, roughly the same share as China. But there are two big differences between the US and China when it comes to oil: US oil production is on the rise, while Chinese oil consumption continues to grow at a much faster pace than US demand. Over time, China’s dependence on oil imports will increase; the US imports will either stay roughly the same or decline.

The moratorium on deepwater drilling in the Gulf of Mexico was officially lifted late in 2010, but the government has only recently started issuing actual new drilling permits. It will take time for activity to ramp up, and the delay has hampered US oil production. Nevertheless, offsetting production from other sources should ensure that US oil output increases slightly while deepwater drilling recovers.

Shale oil is a big part of this story. Prospective investors should note the huge difference between oil shale and oil produced from shale reservoirs, often called shale oil.

Oil shale is an inorganic rock that contains a solid organic compound known as kerogen. Oil shale is a misnomer because kerogen isn’t crude oil, and the rock holding the kerogen often isn’t even shale.

There are several competing technologies for producing oil shale. ExxonMobil Corp (NYSE: XOM) has developed a process for creating underground fractures in oil shale, filling these cracks with a material that conducts electricity, and then passing current through the shale to gradually convert the kerogen into producible oil. Royal Dutch Shell (NYSE: RDS A) buries electric heaters underground to heat the oil shale.

Although estimates of the cost to produce oil shale vary widely, the process is more expensive and energy-intensive than extracting crude from Canada’s oil sands. Producers would require oil prices of at least $100 a barrel and probably somewhat more for a prolonged period before this capital-intensive process would be feasible on a commercial scale.

Shale oil plays such as the Bakken have far more in common with unconventional gas plays such as Appalachia’s Marcellus Shale and Louisiana’s Haynesville Shale than they do with Colorado’s oil shale. Specifically, producers in the Bakken and other unconventional fields simple use horizontal drilling and fracturing techniques to produce oil.

Not only do these fields produce crude that’s often of better quality than West Texas Intermediate, but break-even costs are also far lower than in the deepwater. In the core of the Bakken, for example, producers need oil prices in the $35 to $40 range to earn solid returns on their drilling programs. At current oil prices, some producers enjoy internal rates of return in excess of 100 percent.

The Bakken Shale play is centered in North Dakota and Montana, two states whose oil output has posted extraordinary growth in recent years.

Source: Energy Information Administration

This graph tracks crude oil production in Montana and North Dakota from 1981 onward. Output from the Bakken area likely topped 350,000 barrels per day in 2010. Given that these states produce roughly 370,000 barrels per day, the data serves as a good proxy of total production from the Bakken.

As you can see, oil output declined in both states from the mid-1980s to 2002-03, when production surged. More recently, production from Montana has declined slightly because operators have shifted their focus to the North Dakota side of the play.

Estimates of the basin’s potential production growth vary widely. Conservative estimates put the figure at 500,000 to 750,000 barrels per day over the next five years. Aggressive estimates suggest that the Bakken could yield 1 to 1.5 million barrels per day in a half-decade. Based on recent well results and comments from producers, I tend to believe that production will approach the high end of these estimates–assuming oil prices remain strong.

And the Bakken is only one of many oil and liquids-rich plays in the US. The Eagle Ford Shale of south Texas and parts of the Permian Basin of West Texas and New Mexico are also showing strong growth thanks to the use of horizontal drilling and fracturing.

None of this is enough to replace all of America’s oil imports but it has arrested an almost uninterrupted decline in American oil output since the early 1970’s. The Energy Strategist subscribers interested in more details on oil from shale fields and my top picks should check out the October 2010 report, A Rough Guide to Shale Oil.

US Advantage: Renewable Energy Policy

This advantage is the most controversial and will probably generate a fair amount of hate mail– send away. Commentators frequently complain that the US is falling behind the rest of the world in alternative energy technology and needs to invest more. Some cite Germany as an example of a country with a good approach to energy policy.

That’s pure rubbish. If the German experience is any indication, falling behind in alternative-energy technology is a good thing. Alternative energies such as solar and wind power may be popular investment stories from time to time, but they’re hopelessly overhyped and overrated by politicians and investors alike. The glowing media coverage they receive doesn’t reflect their value as energy sources or their utility in terms of reducing global pollution emissions.

The most recent issue of The Energy Strategist addresses this topic in considerable depth. But consider the graph below.

Source: German Federal Ministry for the Environment, Nature Conservation and Nuclear Safety, RWE AG

Germany subsidizes solar, wind and other renewables using a feed-in tariff (FiT) structure. These subsidies guarantee that solar and wind power producers will earn an above-market tariff for any electricity they produce and sell to the grid. The structure was set up under Germany’s Erneuerbare-Energien-Gesetz (EEG), or Renewable Energy Act, passed in 2000 and revised on a few subsequent occasions.

This graph depicts the billions of euros in fees paid to renewable energy producers under auspices of EEG. (Note that these are annual amounts, not cumulative.) As you can see, EEG fees started out small but are expected to explode over the next few years, largely because of rapid growth in German solar electricity capacity. Solar power installations earn a high FiT because the technology is many times more expensive than most other source of power and would never be built if it weren’t subsidized. And despite the big jump in capacity built, solar power still generates less than 1 percent of the country’s electricity.

As these high FiT rates are guaranteed for 20 years, this spate solar construction sets up two decades worth of ever-rising EEG fees–fees that are ultimately passed on to the German consumer in the form of higher electricity rates. For the record, Germany’s electricity rates, already the second-highest in Europe, are roughly $0.36 per kilowatt-hour (kwh), compared to an average closer to $0.08 to $0.09 per kwh in the US.

Even worse, solar and wind aren’t reliable baseload power sources. The largest wind power facility in Europe is Scotland’s Whitelee Windfarm, which comprises 140 wind turbines that stand 70 meters tall (230 feet) and sport wind-turbine blades of 40 meters (130 feet) in diameter. The rated maximum capacity of each wind turbine is 2,300 kilowatts (kw), so the farm’s total installed capacity is 322,000 kw, or 322 megawatts (MW). That’s equivalent to a small coal plant. But on a monthly basis, Whitelee Windfarm has yet to generate power at more than 40 percent of its rated capacity and in February 2010–a cold month when electricity was in high demand–the wind installation produced less than 13 percent of its maximum potential output.

Integrating renewable energy sources into the electric grid is a challenge, as the inevitable spikes and lulls in solar and wind power generation must be offset with natural gas and other flexible power sources–known as spare, shadow or reserve capacity–that can be fired up to ensure that the supply of electricity meets demand.

As spare capacity likely consists of natural gas-fired plants, increased dependence on renewable energy actually bolsters gas demand.

Meanwhile, Germany’s recent decision to shut down seven of its 17 nuclear reactors will spell greater demand for coal and natural gas. That spells more emissions of sulfur dioxide, nitrous oxide and carbon dioxide.

Many Americans complain that the US lacks a cohesive energy policy. That may be true. But no policy trumps an ill-conceived, expensive policy. 

Around the Portfolio

On Mar. 15, 2011, units of Enterprise Products Partners LP (NYSE: EPD) had a truly jaw-dropping trading day. The opening quote was $40.19 and proceeded to plunge as low as $27.85 intraday before closing at $40.20. Since then, they’ve traded back up over $42, squarely in the $40 to $45 range held since last autumn.

Our first reaction on seeing this kind of action is that there’s been a bad trade. In other words, the unit price never went that low in reality; rather, the low levels hit were due to electronic error.

In this case, however, Enterprise really did trade at those levels, i.e. orders were actually filled. Mar. 15 marked the bottom of a two-week downtrend in the unit price, which began shortly after the MLP announced a merger with affiliated Duncan Energy Partners LP (NYSE: DEP).

That deal was met with mostly positive feedback on Wall Street, which now has 19 “buy” ratings for Enterprise against just two “holds” and one “sell.” Predictably, there were also the requisite unitholder lawsuits, aiming at squeezing out a higher bid price. And the move also seemed to arouse fear among some investors about possible dilution.

Ironically, the dramatic events on Mar. 15 had no visible catalyst and occurred following two modest up days for Enterprise units. Within minutes of the open, a huge volume of “sell” orders came on the market, overwhelming “buy” orders temporarily. But by 10 am the units were already on the mend. In fact most of the trades that day did go off between $38 and $40 per unit.

In short, unless you were paying close attention on Mar. 15 you probably didn’t notice anything at all. But there were definitely some big-time winners and losers in Enterprise units that day. In the latter camp were all those who were “protecting” themselves by using stop-losses. We’ve warned investors time and again not to use stops on any position they’re holding for yield and long-term wealth building.

The primary reason is that stops have become very popular for investors who are worried about another 2008-09 decline but are loath to take profits on winning positions.

Particularly popular are trailing stops, which adjust upward along with the price of a stock.

If enough stops are in place around the same price, breaching that level will execute a huge number of sells at the same time. These “sell” orders will overwhelm the bids, sending the stock in question cascading lower. Stops will be taken out at the first available price, which is usually well below the actual stop price set.

In the case of Enterprise on Mar. 15, the losses were quickly erased, as the units quickly rebounded. Those who were stopped out, however, reaped only huge losses with no chance to get back in before the rebound.

Similarly, the speed and power of Enterprise’s fall and rise suggests misuse of leverage on the part of many investors, either via margin or options. Use of either can boost returns under the best of circumstances. But on days like Mar. 15, investors are just as likely to get washed out, and at horrific prices.

Our strong advice remains not to use leverage on positions like Enterprise Products Partners. There is, however, a way to magnify your returns in solid companies without taking on these risks, by utilizing buy limit orders, set at “dream” prices.

One investor I know well was executed at $33.25 per unit on Enterprise on Mar. 15. He’s currently up 26.8 percent on that position. Anyone who got in at the day’s posted low is up more than 50 percent, for doing nothing more than entering an order to buy only when a specific price level is reached.

If you truly set a buy limit order at a real bargain or dream level, odds are they’ll sit unexecuted for long periods of time. But as we saw once again with Enterprise on Mar. 15, even the most dubious catalyst can set off a selling wave. And, ironically, conservative companies heavily held by fearful investors are most vulnerable to these one-day volatility events.

During Enterprise’s Mar. 7 presentation to analysts Chief Financial Officer W. Randall Fowler stated his view that investors should “never want to sell” his company. As long as this owner of energy infrastructure continues to perform–dividends have been raised 33 consecutive quarters–we have no argument with that. In fact, failing to make the numbers should be the only reason any yield-focused wealth-builder sells Enterprise.

And as long as the numbers are solid, any dramatic price dip–such as occurred Mar. 15 for Enterprise–is a massive buying opportunity. It may be a long time before these units again hit $35 per unit. But there’s no harm putting in a buy limit order there, either.