Chinese energy companies have spent billions joint-venturing North American energy assets in the last two years.  But the money pipeline could reverse under a new Chinese law—North American companies are now being allowed to develop shale gas in China—where natural gas prices are a LOT higher than here.

China recently designated shale gas as an independent resource, which means that smaller energy companies – possibly including some from outside of China – will be able to develop the resource in the country.  As yet, China has NO commercial shale gas—but big reserves.

China’s Ministry of Land and Resources did this to bring more firms into the sector, according to Reuters. The Asian country’s energy sector is currently dominated by massive Chinese companies like PetroChina.

Xinhua News Agency cited a government official as saying China would seek to launch a second round of shale gas tenders in early 2012—i.e NOW.

China only uses clean burning natural gas for 4% of its energy supply, compared to 20% + for most of the modern world—and it is already the third largest consumer of natural gas in the world (after USA and Russia).  They have a goal of getting to 10% by 2020.  China is increasing their gas supply now via pipelines from foreign countries like Turkmenistan, Kazakhstan, Uzbekistan, Myanmar and Russia.

Natural gas prices vary widely across the country, as they are subsidized in some areas to keep inflation low.  But in Shanghai you can now get $12+ per mcf and I have heard as high as $22/mcf—one of the best prices in the world (North American LNG export terminal proponents are salivating…).  Price liberalization is increasing.

Firms from outside of China will not be allowed to participate in the tenders but will be able to partner with the Chinese companies that win them.

This move could have major implications for any companies that partner with the winning Chinese firms as the Asian nation has an incredible amount of shale gas reserves.

The U.S. Energy Information Administration estimated that there was 1.275-QUADRILLION-cubic-feet-worth of “technically recoverable” shale gas in China. By comparison, the U.S. – which has led the way with the development of shale gas – has “only” 862 trillion cubic feet.

China has shown it’s eager to develop its energy resources—they’re on the record saying they want to increase oil and gas output by 23% by 2015 to 360 million tons equivalent—and to 450 million tons by 2030.

——————————————————————————————————————–

In terms of just shale gas, China says it hopes to produce 229.5 billion cubic feet of the resource by 2015. By 2020, the country is targeting 2.82 trillion cubic feet of shale gas production, according to Reuters—almost a ten-fold increase in just five years.

Due to these enormous reserves, whatever foreign companies are able to partner with the winning Chinese firms will be in a strong position.

So far only the large Chinese firms have been winning bids to develop shale gas.

Earlier this month it was reported that China National Offshore Oil Corp, or CNOOC Ltd., which is the biggest Chinese offshore energy producer, began drilling its first shale gas project in the country.

Neil Beveridge, an energy analyst at Sanford C. Bernstein & Co. based in Hong Kong, told Bloomberg that this was a significant move for CNOOC.

“It may take more than five years for CNOOC to turn this exploration into real production, but the key message here is CNOOC signals a new direction on where the company will move in the future,” he said. “CNOOC will count heavily on unconventional oil and gas for growth down the road.”

Large companies dominated the first round of tenders in June.  This second auction will likely see smaller companies get involved in shale gas, due to the resource’s new designation.

Because of the challenges posed by recovering these unconventional resources, Chinese companies have been attempting to gain technical expertise by partnering with foreign firms to develop shale gas abroad.

One of the most prominent such ventures was Sinopec’s acquisition of one-third of Devon Energy Corp. (DVN:NYSE) for $900 million in cash. Bloomberg also reports that the deal could include the Chinese firm paying up to $1.6 billion in Devon’s future drilling costs.

“In these joint ventures, the partner does typically get some education on drilling,” Scott Hanold, an analyst for RBC Capital Markets, told Bloomberg.

The news provider reports that Chinese firms spent over $18 billion in 2011 buying oil and gas companies around the world.

China’s shale gas reserves are massive, as the profits for any company that is able to partner with a firm developing the resource in the country could potentially be.

The stocks of natural gas producers have been hit hard by the low price and bearish outlook for the commodity. But a new report from Denver-based energy analytics company BENTEK makes me think natural gas pipeline stocks, pipeline MLPs and pipeline ETFs/ETNs in the U.S. could come under big pressure in the coming weeks.

And their stock charts are agreeing with me.

Bentek’s report — “West Absorbs Marcellus Shale,” and just released on Thursday — says that the northeast US, the most lucrative retail gas market in North America, can be fed mostly from fast rising natural gas production out of the Marcellus shale —  a “local market” for that shale deposit.

If fact, with so many new shale gas deposits—located all over the U.S.—now every market can be served with “local” gas, greatly reducing the need for pipelines. Dividend paying pipeline companies have been some of the best performing stocks for resource investors, but the shale gas supply glut may drag them down now as well.

“From a fundamental and market point of view, it doesn’t bode well for those (gas pipeline) flows to remain high, due to growth in eastern shales,” says Bentek’s Sheetal Nasta, one of the authors of the report.

“We have local supply to serve local demand, not just in the Northeast, but in the Midwest, with the EagleFord and Granite Wash plays. Local production will serve local demand and long haul pipes are losing favour because of that.”

That is not good news for companies like Kinder Morgan (KMP-NYSE) which just spent $4.4 billion on the new REX pipeline that goes from Wyoming to Ohio—or for TransCanada Pipelines (TRP-NYSE; TRP-TSX), with its main gas line from Alberta to Sarnia Ontario.  To their benefit, many of these companies have long life contracts that get them through market swoons.

Pipeline stocks, ETFs/ETNs, and MLPs fell to their lowest intraday drop in months last Friday.  (MLPs, or Master Limited Partnerships, are tax-advantaged investment vehicles that make distributions similar to dividends; see our earlier MLP report here.)

The listings I saw affected most in Friday’s trading were the Alerian ETF and ETN products:

• MLPL-NYSE—2x Leveraged Long Alerian MLP Infrastructure Index ETN
• MLPI-NYSE—Alerian MLP Infrastructure Index ETN
• AMJ-NYSE—JP Morgan Alerian MLP Index ETN

They were NOT textbook reversals on Friday, but they were larger than normal downdays. (Each of these 3 is down again today.)

Two of the largest pipeline companies in the US also broke stride with recent uptrends after the Bentek report came out. Kinder Morgan’s KMP-NYSE listing had its biggest intraday drop since the market crunch of early October. Enterprise Partners (EPD-NYSE), also had a large intraday drop, but it was not as unusual. (KMP and EPD are both down today.)

The reason pipelines exist is to take low price supply to higher priced demand. But the huge supply has depressed gas prices everywhere in North America, so there is little to no price spread on gas between the various hubs in the US. And for the first time in history, some price spreads have gone negative, says Nasta.

“Westbound flows on Ruby (the new Ruby pipeline moves gas west, from western Wyoming to Malin Oregon, on the California border) picked up in November and eastern REX flows dropped off (REX takes gas east, from eastern Wyoming to Ohio).”

The reason REX gas flows dropped was because of all the new gas production out of the Marcellus shale—the east just didn’t need near as much western gas.

“Demand in the west absorbed that incremental gas,” Nasta continues. “Due to a combination of mild demand in the east and increased production in Marcellus, prices on east side of the US (the Dominion South hub in Ohio) got really weak–and the spread between east and west went negative.

“That is historically unusual.  It wasn’t that long ago—a couple years–the price spreads between those two hubs were over $1 (per thousand cubic feet, or mcf).  But I don’t think it’s ever been negative.”

*source: Bentek GIS

“Spreads across the country are flat. We don’t need long haul gas.”

For high REX volumes to keep flowing, she says, the gap, or spread in prices between Wyoming’s Opal hub and Ohio’s Dominion South hub have to widen out again—meaning the western Opal gas price has to get weaker.

But gas production in the Wyoming area is flat; no growth. Combine that with increased pipeline capacity to get gas out of Opal—thanks to the new Ruby pipeline that just started in 2011—Nasta says she doesn’t see Opal’s gas basis falling much anytime soon.

So not only is there a lot of gas, it’s everywhere, reducing the need for pipelines, and that’s all coming at a time when a lot of pipelines have been built. Pipelines are like any other commodity; their pricing goes by supply and demand. It appears that local supply is going up and long haul demand is going down. Competition is almost certainly going to bring pipeline prices—the toll charges they give gas producers—down.

For resource investors, and income investors, pipeline stocks have been a steady to good performer. But if Bentek is right, I see their multiples—if not their actual dividends—being reduced if current trends in the gas market keep going the way they are.

Here’s a link to the Bentek report.

There is a Canadian angle to this story as well, which I’ll cover in more detail in an upcoming OGIB Free Alert.  Meantime, you can read my original story on how all the new US gas pipelines have displaced Canadian natural gas.  Click here for the OGIB report on REX – the Rockies Express Pipeline.

- Keith

DISCLOSURE:  Keith Schaefer is neither long nor short any of the companies mentioned above, and has no intention of initiating a position.

My portfolio, which I use as the OGIB subscriber portfolio, finished 2011 up 48.2% on closed trades (stocks that I actually sold in 2011) and up 36% on open trades that were initiated, or first bought, in 2011.  If I include stocks I bought in 2009 and 2010, my gain on all open positions is 36.7%.

In all, gross gains in the portfolio totaled $449,744… while gross losses came to $52,860.

Strangely, the year didn’t seem that profitable, emotionally or mentally.   There was A LOT of volatility and angst—June and October were particularly harsh months for the junior resource sector.

And I was guilty at times of getting too wrapped up in the market swoons, trading out and trading in again.

HOWEVER — I did find what I think are my best trades of the year in the last two market bottoms in June and October—so I was able to use market panic to my advantage some of the time.

Each January I try to look objectively at my trading and track record and try to determine what I did right and wrong; what can I do better to bring more prosperity to me and my subscribers.

Here’s my list for 2011.  First, here is what made me money.  In my next article, I will share what lost me money in 2011 — and I’ll include my outlook for 2012:

1.      When I found a winner, I kept buying; averaging up.  In my four biggest winners of 2011, I continued to buy the dips as they rose—even after they doubled, I kept buying. I first bought Coastal Energy (CEN-TSX) at $2.50; I bought more in the June swoon at $8.80. Today, all those stocks are above the highest price I paid for them.  Now, when I do that, I listen to both the company and the stock; because sometimes they say different things.  My job is to do the research to see which one is more accurate.

2.       I did not average down on my losers—except one.  But my losing trades were obviously a lot smaller than the winners.  That’s because I don’t allow myself to believe that I’m smarter than the market.  If the market is selling a stock down, I always believe I have made the mistake and I start making calls to figure out what I don’t know.  I don’t say—”the market must be mad”—and start buying with both fists at lower prices—setting myself up for a BIG loss.   (My one average down stock is now back up to near-year highs)

4.      When the market turned negative in the early spring, I was vocal about selling my juniors and moving upmarket, to higher priced, more mature and less risky stocks.  This made me more open to buying additional shares of my higher priced winners — even after they were already up.  (I could also argue that I didn’t sell enough of the penny juniors fast enough and that DID COST ME a lot of money.)

5.       This lesson did cost me money, but it saved me a lot more — Be flexible; be willing to say you made a mistake.  Normally when you make a mistake it means taking your initial loss and moving on—I was able to exit Valeura (VLE-TSXv) and being able to exit the position with only a 6% loss—it’s now down 70%.

But being able to change your mind also means having no ego on a stock that turns around–which you previously sold.  I sold two stocks this year that had horrible charts in a bad market—and days later, they each had something happen that fundamentally changed the company—for the better.  I jumped back into both—well above the prices I just sold them at — for the same reason I originally bought the stock, and they are both 40% higher now—within weeks.

I’m very happy with 48.2% gain in 2011.  But it could have been a lot better if I had practised a couple simple trading rules.  Sadly, even after 25 years of investing, I find myself making some of the same mistakes I made as a rookie.  I’ll tell you about them, and why I have a bullish outlook for junior oil and gas stocks (OK… just oil) — in 2012.

A shale gas and shale oil boom is anticipated in Argentina, where recent finds have set expectations high in the South American country.

Former state monopoly YPF believes that a recent discovery could touch off a proverbial powder keg of development in Argentina, reports United Press International.

Tomas Garcia Blanco, the executive director for upstream activity at YPF, told the Financial Times that the discovery – in the Loma La Lata area of the country – could contain as much as 1 billion barrels of oil equivalent.

Last month, Repsol, which owns a majority of YPF, reportedly discovered 927 barrels of oil equivalent in the region, which is known as Vaca Muerta. Garcia Blanco said the company hoped to know the true extent of the discovery in January or even as soon as the end of the year.

Many people are enthusiastic about the potential for a major shale gas and oil discovery in the country due to the large amount of resources that are believed to exist there.

According to the U.S. Energy Information Administration, Argentina has 774 trillion cubic feet of technically recoverable shale gas resources in the world. That figure puts the South American nation behind only China and the U.S. in that regard.

Even with the 1 billion figure attached to the play, Garcia Blanco said that estimates of the Vaca Muerta were "conservative." In addition, he compared the play to the Eagle Ford shale in Texas, which has helped lead America's shale gas boom.

"It does seem to have some similarities to some very productive U.S. plays," Robert Clarke, an analyst who focuses on unconventional gas at Wood Mackenzie, told the Times.

If Vaca Muerta is in fact similar to the Eagle Ford, there could be a tremendous amount of shale gas production in Argentina. The Texas formation produced more than 8 million barrels of oil through the first eight months of 2011, which is already more than double the production for the entirety of 2010, according to the Railroad Commission of Texas. In addition, the play produced 139 billion cubic feet of shale gas in 2011 through August.

If the play is developed it could mean big things for Argentina, which produced 1.16 trillion cubic feet of natural gas in 2009. That figure represented a 35 percent decline from 2008, according to the U.S. Geological Survey.

Recently approved new rules governing activity in West Virginia’s portion of the Marcellus shale have become too pro-industry, environmental groups charge.

During a special session, the Senate Judiciary and Finance committees endorsed a version of the bill that had been reworked by Governor Earl Ray Tomblin, which has been widely panned by environmental groups and surface owner organizations alike.

Gary Zuckett, the director of the West Virginia Citizen Action Group, was outspoken in his criticism of the bill.

"What we now have is a Christmas tree for the drillers – it's an industry bill," he told the Charleston Gazette. "The whole process was hijacked in closed-door meetings after so much work was done all summer."

Additionally, the environmental groups are upset that the earlier version of the bill, which had been worked on for years with a special joint-chamber committee, was scrapped for what they feel is more industry-focused legislation.

"The select committee's bill was already a compromise," Jim Sconyers with the West Virginia Sierra Club told the news source. "Now it is unacceptable. Any bill we would support must contain at least the protections found in the compromise bill."

Specifically, Tomblin's version of the bill removed authority from the Office of Air Quality by not allowing it to regulate air quality at the sites. The governor's version also allows operators to drill without notifying adjacent property owners.

Tomblin's reworking also changed some required distances. Under the new version, wells need to be drilled 100 feet from wetlands but the prior version set the distance at 200 feet. In addition, the new bill will allow drilling activity to take place within 625 feet of homes, a distant that some opponents say is insufficient, reports The Associated Press.

The updated version kept the original's increase in permit fees. According to the AP, drillers now only pay $400 but will have to pay $10,000 for the initial well and $5,000 for each subsequent well under the new rules.

This is part of the reason those on the industry side are not thrilled by the new version, although many of them have endorsed the updated version of the legislation.

"Everything about this bill either adds expense or time or delays to our operations and our organizations, which we currently feel are adequately regulated," Mike McCown, vice president of Gastar Exploration (GST:NYSE Amex), told the AP. "But it's important to have some clarity moving forward."

The U.S. Environmental Protection Agency recently announced that hydraulic fracturing – or fracking – may be the cause of groundwater pollution in a Wyoming community. However, upon closer examination it appears that the federal agency's findings may be flawed, say investment and industry groups.

In its draft analysis of data from its investigation into drinking water in Pavillion, Wyoming, the EPA found compounds associated with fracking in ground water, according to a release from the federal agency.

Residents in the area have reportedly said that their drinking water smells of chemicals and the EPA has been investigating such claims – along with Wyoming officials and the owner of the oil and gas field, Encana Corp. (ECA:NYSE) – for the past three years.

However, a number of sources have pointed out that there are potentially serious flaws in the EPA's findings.

One issue is that the investigation did not establish a connection between deep and shallow water contamination in the aquifer. According to Global Hunter Securities, this may show that that the fracking fluid was unable to meaningfully migrate upward through strata. This is even more significant because as the EPA notes there was no serious stratigraphic barrier to prevent such a migration at the site in question.

Another serious issue with the investigation is that the water in question is produced from a reservoir that also naturally produces significant levels of hydrocarbons, so the presence of such substances is not surprising. Global Hunter also points out that it shouldn't be surprising that synthetic substances were found in the reservoir as it has been developed commercially for nearly 50 years.

The whole issue begs the question—where was the EPA for the last 50 years as conventional oil and gas was being produced from a drinking aquifer?

Additionally, a Credit Suisse note mentions that the alleged migration distance (less than 150 meters) is far less than in most of the other wells in the country. Almost all, if not all, fracking is done between half a mile and two miles underground, well below any groundwater reservoir.

For its part, the EPA did say in the release that these findings were only for the Pavillion area. Specifically, the fracking was taking place close to wells used for drinking water and below the level of the water aquifer. Fracking methods in other regions of the country vary due to different geological conditions.

Given the scientific flaws in the report, it’s unclear if this eye-grabbing report will have any actual effect on fracking operations throughout the country.

In Part 2 of his story on the Natural Gas Bull ETF, Guest Writer Cory Mitchell tells you historically WHEN the best time is to make this trade to maximize profits… and it’s coming up very soon.  He also explains what happens to this short trade if natural gas prices start to rise (Hint: It’s better than you think.)

- Keith

By Cory Mitchell, CMT

In Part 1, I explained The Best Trade in Natural Gas—shorting the Horizons BetaPro Natural Gas Bull ETF, symbol HNU on the Toronto Stock Exchange.  With very little volatility, investors who shorted this ETF in June 2008 would be up more than 99% now—in fact, there is almost no time in the past four years when this trade would not have been profitable.

Most retail investors look to ride a major trend to profits, and the downward slope of natural gas prices for the last three years have provided very steady capital gains.

So when is the BEST time to make this trade—shorting the HNU:TSX?

Charts suggest that the Monday of the last week of January has been a historically good entry point for short positions.  Here is what happened the last three years:

1. Monday, January 25, 2010—if you shorted and held you would have never seen a loss and would have made 88.95% between that date and December 2, 2011(closing prices).
2. Monday, January 24, 2011 was a steep drop day.  But if you sold on that day, the price never moved above it again, representing a 63.56% gain as of the close on December 2.
3. In 2009 the ETF did manage to move a bit higher after the last week in January, but by mid-February—only three weeks later– the ETF was dropping once again, never to reach those levels again.

Therefore, the first Monday of the last week in January has been a solid entry point, yet there is possibility that it could fluctuate and move higher from there in the short-term.  History indicates this is likely a high probability short position entry point, although history does not always repeat itself so retail investors must be vigilant on managing their own risk and not taking positions which they cannot afford to lose on.

What Happens if Natural Gas Goes Up in Price?

Natural Gas has been sliding this year, as mentioned, down 22.77% YTD as of Friday, December 2.  Therefore, if natural gas begins to rise over the long-term will HNU rise?

Given the structure of the ETF, this is extremely unlikely over the long-term.  Even if natural gas rises the ETF will continually be paying a higher price for new contracts than it receives for expiring ones.  The spot price at expiry will theoretically need to be higher than the futures price paid every time a contract is rolled in order for this ETF to appreciate long-term—a highly unlikely scenario.

The potential exists for a “backwardation” market condition to develop.  This would aid HNU in recovering some of the excessive losses it has seen since its inception.

Backwardation occurs when contracts in the future are priced lower than the current spot rate and then rise as they near expiry to converge with the higher spot price.  This would occur for example if short-term demand is higher than anticipated demand in the future. The current price is driven up, but contracts for future months are priced lower because demand is expected to decline by then.

This allows the leveraged long position ETF to profit when the spot price increases, remains flat or even if the spot price declines slightly–because the ETF will purchase contracts which expire in the future for cheaper than the current spot price (how much they sell expiring contracts for).

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As the contracts near expiry, its value will increase to the current price, at which point the position is rolled into another contract which is priced lower than the current spot price.  This allows the fund to purchase more of the new contract which is likely to provide a positive return even if the spot rate remains flat.

Backwardation rarely occurs in natural gas, which is called a “non-perishable commodity,” since there are storage and insurance costs for holding the commodity for delivery in the future.  This is why futures contract far away from expiration are priced higher than the spot price—it compensates the seller and holder of the commodity for costs incurred until delivery.

Sustained backwardation is really the only way HNU can recoup losses, and this scenario is highly unlikely. Therefore, it is very implausible HNU will be able to sustain an uptrend even if natural gas were to begin a long-term uptrend.

The daily objective of the fund means it is more suited to day traders, and long-term short sellers than bullish investors.  The odds are stacked against the bulls due to the structure of the fund and contango.  While bullish investors may be able to exit at a better price on daily gyrations, it is probable that this ETF will continue to decline, as it has done since July of 2008.  That provides an opportunity for those open to short selling.

We are approaching a time which was a great entry point in 2009, 2010 and 2011.

2008 saw a sharp rise in natural gas between January and the end of the July. This was the only time the ETF rallied—right after its inception.  It responded well to the bull market then mainly because during the first several months, contracts did not have to be rolled.  Once the contracts began to roll, the losses mounted as natural gas began its long-term decline.  If such a sharp rise occurred again, HNU.TO would likely rise, but the effects would be more muted than in 2008 because of the contango effect and the inefficiencies mentioned in Part 1.

Conclusion

HNU is a product long-term investors should avoid buying as the ETF does not accurately reflect the movement of natural gas beyond a single day.  The likelihood of a long-term rise in the ETF which will allow investors to recoup losses, even if natural gas begins a bull run, is slim.  The structure of the ETF is not favourable to long term appreciation.  In order for long-term appreciation to occur, conditions would need to be perfect, and need to run counter to the norms of the non-perishable commodity.

This makes the ETF a prime candidate for taking a short position as the inefficiencies of the fund create profits for further downside.  Couple this with a weak natural gas price and late January of 2012 begins to look like a good short-entry point.

- Cory Mitchell, CMT

EDITOR’S NOTE:  Several readers emailed in after reading Part 1 asking, why short the HNU ETF — why not buy the HND:TSX, the natural gas down ETF?  The answer is simple. In terms of being able to capitalize on a trend it has been less reliable.

Since March of 2009 HND has continually pulled back to former price lows (support).  HNU has not done this; very rarely on a long-term basis has HNU moved higher to test old resistance levels.  This makes HNU far more consistent in making new lows (good for shorts), than HND is at making new highs (tricky for longs).  For trend followers and investors who don’t want to have to babysit a position, the short in HNU is likely a better option.  HND provides great profit potential as well, but entries and exits are harder to pick as the movement is far less uniform than in HNU over the long-run.

Disclaimers: Cory Mitchell nor Keith Schaefer currently hold a position, short or long, in TSX:HNU. Neither Cory Mitchell nor Keith Schaefer are investments advisors; no part of this article should be considered personalized investment advice. As always, investors should consult with a licensed financial planner for help on their particular investment situations.

So much thought and energy is put into getting oil and gas out of the ground, that it can be easy for a lay person to forget about the infrastructure needed to transport these resources to places where they can be sold.

However, those in the industry know the importance of infrastructure when it comes to their operations, and a number of major companies recently said they would be working in such a capacity in the Bakken formation, both on the U.S. and Candian sides.

Enbridge Energy Partners (EEP:NYSE) recently announced that it would be investing $145 million in its North Dakota crude oil system.

The company – which focuses on transporting oil and gas in the U.S. – said that the money would go to increasing the capacity of its Berthold terminal by 80,000 barrels per day; it started handling 10,000 barrels per day in July. In addition, there will be a new rail car loading facility. It is hoped that the additional capacity will be in-service by early 2013, reports Dow Jones Newswires.

President Mark Maki said that the expansion wouldn’t just help Enbridge, but other companies in the area as well.

“Importantly, it allows producers and shippers the ability to continue to grow their business while Enbridge develops the next phase of pipeline expansions on the Enbridge North Dakota System,” he said.

Enbridge isn’t the only company looking to ship oil and gas out of the Bakken, as Canadian Pacific Railway Ltd. said that it would spend C$90 million to increase its shipments out of both North Dakota’s and Saskatchewan’s sections of the formation.

The company anticipates that shipments out of the formation will reach 70,000 cars per year.

An executive at an oil and gas company recently said that he expects the cost of drilling in North Dakota's Bakken formation to fall in the coming years.

James Volker, the chief executive officer of Whiting Petroleum (WLL:NYSE) says that he believes new drilling technology, better well designs and new sand mines will drive the costs down, reports Reuters.

Specifically, Volker said that the cost of a new well will drop to about $7.3 million from its current perch of $8.3 million. The executive – who was speaking at a Wells Fargo conference – said that the cost would eventually plummet further to $6.5 million.

According to Reuters, Volker said that his company spent $10 million on each new well when it began to operate in the Sanish Fields of the Bakken.

In addition to the costs of wells in the play going down, they are being completed even faster. According to analysts, it takes about 15 days to complete a well in the Bakken, a 50 percent reduction in time compared to 12 months prior, reports Reuters.

These developments – both a reduction in cost and an increase in speed – will help companies tap into one of the fastest growing plays in not only the country, but the world.

September saw the Bakken produce 485 million cubic feet of shale gas per day, which is up from the 150 million cubic feet per day figure from 2005, according to the U.S. Energy Information Administration.

Well costs in America's other shale gas darling – the Eagle Ford in Texas – have gone in the opposite direction.

Michael Hall, a senior analyst at Robert W. Baird, told the Hart Energy's Developing Unconventional Gas Conference & Exhibition in October that the costs of completing a well in the play have nearly doubled, going from $5.3 million to $10 million over the past year or so, reports the Houston Chronicle. 

Icarus failed to escape with his father from Crete because he flew too close to the sun. Now, some oil companies are now hoping that getting closer to the sun will bring them success.

Typically the extraction of heavy oil requires a tremendous amount of natural gas to create the steam needed to bring the oil to the surface. Seeking a different means to extract the precious commodity, GlassPoint Solar is using the power of the sun.

GlassPoint's solar enhanced oil recovery (EOR) utilizes large mirrors that are put in a glasshouse and reflect the sun on water-containing pipes. The water in the pipes becomes the steam that is used in the oil extraction.

A switch to this technology could potentially lead to significantly reduced operating costs as GlassPoint Chief Executive Rod MacGregor says that 60 percent of the cost of operating a heavy oil field is for the purchase of natural gas.

"Burning the product you're trying to produce is not that efficient, to say the least," MacGregor told AOL Energy.

GlassPoint isn't the only company out there harnessing Helios' chariot of the sun to get oil from the ground.

BrightSource Energy Inc. has been working in California with Chevron – the second largest oil company in the U.S. – to bring solar power into the oil industry. BrightSource's method is not incredibly different from GlassPoints, with mirrors being used to focus the sun's power on solar tower, where steam is created, reports Bloomberg.

Chevron Technology Ventures President Desmond King said there is a great amount of potential in the technology.

"This technology has the potential to augment gas-powered steam generation and may provide an additional resource in areas of the world where natural gas is expensive or not readily available," he said in a statement.