The gas rig count in the US has dropped by more than half in the last 18 months, but production continues at record levels-around 63-64 billion cubic feet per day (bcf/d). Why is that?

First, the stats: The February 15 Baker Hughes rig count-the Bible of the industry-showed the gas rig count at 421, the fifth-lowest in the current run down-that's down from 1,600 in 2008, or almost a 75% drop. Just this last year the gas rig count has dropped 41%.

(You can find this chart each week at http://intelligencepress.com/features/bakerhughes).

There are two obvious reasons for this-one is that there is more "associated gas" with oil production, especially in Texas (not so much in North Dakota on a per well basis, but overall the Bakken is up around 1 bcf/d in gas now).

But the big reason is drilling efficiency. When I go to conferences, I tell the crowd-fracking isn't improving every year. It's not improving every quarter. It's improving every month. That shows up in the reduced time it takes to drill a well now, thanks to improvements in horizontal drilling techniques, and in the amount of gas each well is able get out of the formation-thanks to improvements in hydraulic fracturing.

The problem is, few companies want to brag about how much they're improving production, so hard statistics are hard to come by.

In one of his blog posts last year, industry expert Rusty Braziel of RBN Energy published some statistics from Southwestern Energy, which provided in-depth numbers on its drilling operations in the Fayetteville shale in Arkansas and Oklahoma.

Over the course of five years, the company's average drilling time per well plunged from 17 days in 2007 to only 8 days in 2011, falling by more than half. In just one year from 2010 to 2011, drilling time dropped more than 27 percent. Over the same five-year period, the later length of wells grew by 82 percent, and initial production more than doubled, rising from 1.65 million cubic feet per day in 2007 to 3.3 million cubic feet per day in 2011.

All the while, the cost per well hovered around the same level, dipping 4 percent from 2007 levels.

So for the same costs, drilling rigs were producing more than twice as many wells, with more than double the initial production. That means the initial production additions per rig grew by 338 percent in half a decade. If the rest of the energy industry saw the same kinds of improvement over the same period, even while cutting rig counts by three-quarters from their 2008 peak, we would expect to see a modest rise in production from simple efficiency.

These changes are not just coming over the course of years, either. Southwestern reported huge swings in IP rates even from quarter to quarter. Between the first and second quarters of 2009, average IP rates at the company's wells rose 20.7 percent, and eight quarters out of five years saw an increase of at least 13.4 percent.

And other companies have seen comparable improvements. As recently as the third quarter of 2012, exploration giant Anadarko reported a 14 percent year-over-year reduction in drilling costs, along with a 40 percent drop in completion time at its Marcellus operations.

Future of Oil and Gas Goes Through Efficiency

Others are not only pointing out drilling efficiencies, but say they will continue into the future. A report released last summer from Credit Suisse hinged its estimates of future American oil production on expected improvements in efficiency.

Credit Suisse estimates that that drilling and completion times will fall by around 40 percent within the next decade as exploration companies become more familiar with new technology and new geology. Some of the newest emerging plays, particularly in California, would come closer to a 50 percent reduction.

That amounts to a less dramatic improvement than that observed by Southwestern over the past five years, but it would still allow energy firms to increase well counts by 27 percent by 2016 with only an 11 percent rise in rig counts.

The report also assumes steadily improving initial production, a trend that has already been observed in shale developments in North Dakota. Credit Suisse sees IP rates rising 21 percent over the numbers seen at the end of 2011.

As positive as these numbers sound, Reuters reports that consulting firm Bernstein Research points out the obvious other side of the coin-efficiency is improving dramatically because fracking operations at present are highly inefficient.

The firm released research last year suggesting that as many as half of all fracking stages contribute no additional production from a given well. In turn, the vast majority of all production - 80 percent - comes from only 20 percent of all fracking stages; yet another example of the somewhat infamous Pareto principle, commonly known as the 80/20 rule.

Nansen Saleri, president and CEO of consulting firm Quantum Reservoir Impact, told the news source: "In a few years the techniques used today for fracking will be viewed as primitive."

So as investors watch the gas rig count with a perplexed face, the industry has been steadily reducing the cost of drilling, lowering the break-even price of natural gas-and disappointing the bulls.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.

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Each of the last two years, the March-June timeframe gave investors serious downturns-the juniors as a group dropped by roughly 50%. It's tough (for me anyway) to hold stocks in those kinds of corrections.

It's my job to help subscribers find the best ways to make money in oil and gas. Sometimes it's the junior producers, which have given me some great wins-DeeThree and Coastal Energy now, and TAG Oil last year. That's sometimes-but now is not that time. Despite strong oil prices, Canadian junior producers are getting no love from Big Money-institutions. Part of the reason is the big discounts the producers are being forced into due to lack of pipelines (for heavy oil) and refineries (for light oil).

Another big part of the reason is that the market now understands the tight oil plays don't recycle cash fast enough for juniors-only a very few management teams are able to do that, and NOT have to go to market for dilutive financings every year.

Natural gas prices continue to languish, and Natural Gas Liquids pricing has also gone way down (except for condensate).

Also, oil is now in what I call the "no-win" price range for junior producers. The stocks of these juniors do the best when oil is at the BOTTOM of its trading range-usually around WTI $75-$85/barrel. Then traders know a rising tide will lift all boats, and the junior stocks get love-and bids.

But now, Brent oil is $119/bbl and WTI is just over $97. Since 2008, history is clear: oil juniors have an INVERSE relationship with oil prices when Brent gets above $120/bbl. That's because the market starts to price in lower global growth, if not outright recession. And one of the first things the market does then is sell the riskiest assets; i.e. junior stocks of all kind.

So at $120 Brent, it's hard for investors in junior stocks to win-if oil goes up, these stocks go down as the market prices in recession. If oil goes down, these stocks go down, as the market prices in lower cash flow.

What this really means for me right now is that-I'm much more likely to sell any junior that I don't LOVE, in the near term. Or at least reduce it. And if it's got a good chart, I'll keep it. But make no mistake, even my favourites are vulnerable. If a stock chart cracks more than 20% off its recent highs, I'm likely a seller and I wait on the sidelines.

I read a stat once that stuck with me-80% of all stocks trade with the market; they go up and down with the tide. And while the tide might be coming into equities now, they don't appear to be moving into junior oil stocks.

That's why I'm moving into stocks that process commodities-water, oil and ethanol for example-to make money in the energy space in 2013. There is always a bull market somewhere in energy, and that is especially true in the energy markets. In September 2012 I started buying select US refinery stocks, and it has become the biggest part of my OGIB subscriber portfolio.

They get to buy low-priced Canadian oil, and my attitude is-don't get mad, get even. Buy the refinery stocks.

As I explained in my September article, The Mystery Behind High North American Gas Prices, these companies get to buy cheap North American crude and sell their refined products at much higher Brent-based pricing-which is still $20/barrel higher right now than WTI, despite the Seaway pipeline expansion.

I also talked about this on FOX-TV in the US - you can see that on the OGIB web site's Media page, video # 2.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.

Canadian production of condensate is flat, which is bullish in the face of oilsands growth. But there is a cloud on the horizon-fast-rising US condensate production, particularly out of the Eagle Ford in southeast Texas.

I'm in Texas this coming week-the Eagle Ford in particular-on a property visit, and to learn more about the how and when the glut of American condensate could flow up to Canada.

In my next story, I'll outline the very bullish case for Canadian condensate prices and producers-both from the supply and demand side. I've been talking to oil and gas marketers in Alberta to get an "on-the-street" view of what's happening, and what the industry insiders think could happen.

And it's all good news for condensate producers. That's why I've made one junior condensate player one of my largest positions.

Part III of my series will focus on US efforts to get more condensate to Canada to take advantage of that great pricing. A lot of that article will include what I learn this week in Texas.

Today, to set up this profit picture, I explain the basics of condensate-a very complex molecule-in a simple way:

The What and How Much of Condensate

Condensate is oil, but a very light kind of oil. Here, 'light' describes the weight of an average molecule -condensate is made up of short hydrocarbon molecules that weight much less than the long hydrocarbon molecules in regular crude oil.

The API gravity system describes hydrocarbon weights. It's a system that uses an inverse scale: the higher the number, the smaller the molecules. Technically, condensates have an API gravity of 50° or higher. For contrast, WTI crude has an API gravity of about 39°, Brent sits around 35°, and crudes considered 'heavy' are those that come in below 22°.

Condensate earned its name because it is a vapour in its underground reservoir that condenses as its rises the surface, where the temperature is lower. And to be precise, condensate refers to a mixture of hydrocarbons, running the gamut from highly volatile natural gas liquids to naphtha range materials resembling gasoline.

(The other NGLs commonly produced with condensate and regular dry gas (methane) include ethane, propane and butane, and are much LESS valuable than condensate.)

So just how much condensate is North America producing?

Oil and gas wells in North America have always produced some condensate, but of late condensate production has simply ballooned. That's because it's produced alongside shale oil AND shale gas-and we all know how much that has increased in the last five years.

From the Eagle Ford shale in Texas to the Bakken shale in North Dakota and up to the Montney shale in northern BC, oil and gas shales are producing major volumes of condensate.

It is difficult to know exactly how much because few producers report condensate production volumes. Instead condensate gets lumped in with crude oil or added to natural gas production numbers by reporting both in terms of barrels of oil equivalent (which is misleading in all kinds of ways).

However, while I can't pinpoint precise condensate production numbers, I can get a good idea of condensate volumes by examining individual plays or provinces.

BC is a good place to start. The Montney shale basin in the province's north is earning a reputation of producing lots of condensate and natural gas liquids alongside its natural gas, bonus co-products for companies in Canada where condensate demand is high.

The drilling rush in the Montney started in about 2009, when natural gas prices fell and producers realized that co-produced natural gas liquids (NGLS) and condensate in the Montney turned uneconomic gas wells into profitable ones. As a result, between 2007 and 2011 annual condensate production in BC increased 28%. BC now produces more condensate than crude oil.

But condensate production growth in BC is a mere shadow of what is happening south of the border.

The best example comes from the Eagle Ford shale basin, which stretches across much of south and east Texas. The shale's tight sedimentary rocks contain a range of hydrocarbons:

1. wells on the southeastern flank generally produce dry gas,

2. wells in the middle produce gas, NGLs, and condensate, and

3. wells to the northwest generate oil and condensate.

Eagle Ford producers drilled their wells looking for oil or gas. Condensate was an unexpected bonus - but it now makes up a huge amount of the hydrocarbons produced from the formation.

Forecasts predict that total Eagle Ford oil output will reach 500,000 to 800,000 barrels per day by 2020. Up to 40% of those barrels will be condensate.

Compare that to 2011, when condensate production from the formation averaged 130,000 barrels per day. It means condensate production from Eagle Ford will likely grow by 150% in less than a decade. And Eagle Ford is just one of a slew of shale basins being drilled and fracked in the United States to produce oil, natural gas, NGLs, and condensate.

It sounds great, right? Not only are shale basins producing the natural gas and crude oil expected, they are also churning out piles of condensate, a hydrocarbon mixture so light you could often pour it straight into your tractor. Condensate must be making US shale producers happy, right?

Wrong.

Stayed tuned - this tale will continue for some time. Again, while I'm in down in Texas I'll be talking to shale producers and quizzing condensate marketers, and find out what is being done to monetize this unexpected bounty of light oil - and what the impact will be for Canadian shale producers, who are now making a killing on condensate.

- Keith

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.

Offshore there is talk of a Black Sea bonanza. The country has good governance, full-package infrastructure, easy access to markets and attractive fiscal terms.

But under the surface-in the ground, where it counts-there has yet to be a big discovery to ignite the country's energy sector, and the share prices of the Canadian and American juniors active there.

BACKGROUND-Big Oil is All Around Turkey

Turkey's oil production doesn't tell much of a story. Production is less than 70,000 boe/d, and Turkey imports 90% of its oil and natural gas needs.

Nor is Turkey about proven reserves: It only has about 270 million barrels of proven oil reserves and 218 billion cubic feet of natural gas reserves, so it isn't exactly Iraq-which borders Turkey to the southeast.

(click to enlarge)

Turkey is about close-ology and a recently renewed interest by the majors in the tight oil, or shale oil-the "unconventional" stuff.

In terms of close-ology, there is:

1. To the North-Black Sea potential.
2. To the South-27 billion barrel onshore finds like Iraq's Kirkuk field.
3. To the East-Azerbaijani oil fields.
4. To the West-well, this just gets silly. Look at this list:

a. 22+ billion barrels of oil in Greek waters in the Ionian Sea.
b. 4 billion barrels in the Greek waters of the northern Aegean Sea.
c. An estimated 7 billion cubic feet of natural gas in one well offshore the Greek-held part of Cyprus discovered late last year.
d. 33+ trillion cubic feet of gas discovered in nearby Israeli waters.

And Turkey knows how to lure investors. It offers foreign oil companies a flat 12.5% royalty tax and a 20% corporate tax rate.

Countries compete for private industry exploration dollars, and one key advantage Turkey has over competing nations-like those in the South American countries where a lot of juniors spend money-is speed in the bureaucracy.

"Approval processes are clear and rapid," Patrick McGrath, Chief Financial Officer for Anatolia Energy Corp., told OGIB. Anatolia is exploring for the Dadas shale in southern Turkey.

Turkey has a web of pipelines, refineries and export terminals. Here, there is no question of refinery difficulty or getting product to market.

For pipelines, there is:

• The Blue Stream system transporting Russian natural gas to Turkey under the Black Sea.
• The Baku-Tbilisi-Ceyhan pipeline (the longest), which transits oil from Azerbaijan.
• Kirkuk-Ceyhan pipeline (the largest), which transits oil from northern Iraq.
• The planned Samsun-Ceyhan crude oil pipeline which will run from Turkey's Black Sea province of Samsun to the Turkish Mediterranean hub at Ceyhan.

Six operating refineries can produce 714,275 bpd-yet there's only 58,000 bopd of internal production. The southwestern port at Ceyhan is becoming a major regional energy hub, with several new refineries already permitted.Combine this with the most favorable financial terms in the region and the infrastructure to get oil to market, and Turkey should be an energy hotspot. It just needs a big discovery. The majors are working offshore, and majors and juniors are working onshore.

OFFSHORE POTENTIAL-To the North AND to the South

State-owned Turkish Petroleum Company (TPAO) estimates there are up to 10 billion barrels recoverable in the Black Sea.

Turkey's offshore hopes have been hit as BP's Black Sea exploration failed to find any oil reserves in the marine regions off the northern Turkish coastline, though exploration continues. In late 2010, Chevron temporarily withdrew and a year later Exxon packed up in two areas after exploration yielded no finds.

But offshore exploration potential to the west remains attractive because of its geography: It adjoins Israeli, Cypriot and Greek waters where massive finds ALSO include:

• 232+ million barrels of oil and another 1.8 trillion cubic feet of gas discovered off Tel Aviv in March
• Turkey has also started exploratory drilling for onshore oil and gas in the Turkish north of Cyprus

This has also created some geopolitical tectonics.

Turkey has threatened war if Greece drills any further into the Aegean. And a deal struck between Israel and Greek Cyprus has Turkey worried that it will never benefit from its "share" of Cypriot gas. The Turks invaded Cyprus in 1974 and the island has since been split between the Greek zone (two-thirds) and the Turkish zone.

In early November, the Turkish authorities warned foreign oil and gas companies that they would be banned from participating in new oil and gas projects in Turkey if they cooperated with Greek Cypriot offshore drilling plans. This is a direct response to the Greek Cypriots awarding four Mediterranean Sea gas concessions.

The problem here is that the Turkish Republic of Northern Cyprus-and Turkey proper-claim the same rights to these concessions. Everyone is eyeing this Aphrodite field greedily as it sits next to Israeli waters that hold gross mean gas resources of more than 33 trillion cubic feet.

Turkey warned military action last year, but Greek-held Cyprus is supported by the United Nations, and the Turkish-held part is not recognized internationally.

- Jen Alic, guest editor

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

Business relationship disclosure: Jen Alic is a geopolitical analyst, co-founder of ISA Intel (isaintel.com) in Sarajevo and the former editor-in-chief of ISN Security Watch in Zurich

- Keith

Can you afford to miss out on an investment opportunity that has returned 66% to investors over the past five years - and has beaten every major market index in 11 of the past 12 years?

That's the promise, and the potential of Master Limited Partnerships (MLPS), an energy investor's answer to a long-unanswered question - how can I get income and growth appreciation out of a single investment - and earn a big tax break in the bargain?

When it comes to MLPs, the positives have outweighed the negatives, but that doesn't mean you should jump in eyes closed and head first.

Before you pour cash into an MLP, take these tips with you first:

Master Limited Partnerships Defined

By and large, master limited partnerships are just that - limited partnerships that happen to be highly liquid, and tradable on U.S. stock exchanges, just like traditional stocks.

Instead of shares, MLP's offer investors "units," and payouts aren't called dividends, they're called "distributions." In essence, MLPs offer the tax advantages of limited partnerships with the asset growth benefit associated with common stocks.

Tax-wise, MLPs are treated differently from stocks and bonds, and are generally treated more favorably by the Internal Revenue Service. Taxes are paid by MLP unit-holders, on a pass-through basis.

That means MLPs, unlike common stocks, don't face double taxation on distribution payouts to investors. However, non Americans (like Canadians, eh) do face double taxation-there is a withholding tax by Uncle Sam and they are not part of the Canada US tax treaty. All MLP investors should check with their tax accountants.

The vast majority of MLPs invest in midstream oil and gas companies, primarily in the pipeline, storage and distribution sectors.

Why MLP's?

Master Limited Partnerships are often referred to as an "investor's dream." Why? Because some MLPs really do make that true - at least from a historical sense.

Statistically, MLPs offer…

• Historical yields of up to 10%

• From 2002 to 2012, MLP's outperformed the Standard & Poor's 500 Index by a whopping 291%.

• In the past five-years, the Alerian MLP Index has returned of 66.6% to investors, approximately 32% of that return coming from price appreciation. Conversely, the S&P 500 fell 1.55% over the same time period.

• MLPs have averaged a14.5% annual rate of return over the past 10 years.

• In 2012, 78% of MLPs actually raised their distributions.

• Due to depreciation, up to 90% of MLP distributions are tax-free until you unload the investment. It's not unheard of for MLP investors to go 10 years before they pay a dime in taxes.

Demand for Oil Drives MLP Growth

There's no sure thing on Wall Street, but MLPs may be as close as a "sure thing" as possible. Since MLPs generally invest in relatively stable midstream energy companies - think pipelines, storage tanks, and oil and gas terminals - investors benefit from high demand for the services those midstream oil and gas companies provide. In other words, it doesn't matter where the price of oil stands - $150 or $75 - as long as global consumers use oil and gas, MLPs benefit from that steady demand.

Bear Market Benefits

Master limited partnerships have proven resilient against down stock market cycles. In the immediate aftermath of the economic collapse of 2008, 39 of 50 MLPs actually raised their distributions to investors to, on average, 10%. In addition, as MLP's invest in "high demand" midstream oil and gas companies, MLP's provide investors with stable, reliable.

Ups and Downs

While MLP's do offer stable, dependable yield growth, significant tax advantages, the tax situation is complicated, and you may need to bring in a tax advisor to handle the MLP portion of your investment/tax portfolio. In addition, exposure to small-cap oil and gas stocks - a common investment for MLPs - can lead to higher-than-normal volatility.

Not All MLPs Are Created Equal

Some master limited partnerships are riskier than others. For example, larger pipeline MLPs are relatively stable - they generate a steady cash flow, as they're not significantly impacted by oil and gas prices. Larger pipelines are also difficult to replace, making them more valuable for MLP investors.

That's not the case for smaller pipelines that move natural gas from processing plants to suppliers. Since natural gas is more vulnerable to commodity price fluctuations, MLP investors should proceed with caution when it comes to evaluating various MLP investments.

Midstream Demand

According to the Interstate Natural Gas Association of America both the U.Ss and Canada will shell out an estimated $84 billion to build new midstream oil and gas platforms, pipelines, storage tanks, and other necessary infrastructure that meets the needs of skyrocketing domestic energy production.

That demand will generate big revenues to MLPs, who are expected to provide that entire infrastructure. In turn, those revenues should fatten up distributions, and boost MLP performance for years - and maybe even decades to come.

SEC Regulated

MLPs are exactly the product of the Wild, Wild West. In fact, the U.S. Security and Exchange Commission regulates MLPs, just like it regulates stocks. As a result, MLPs must file annual and quarterly reports, and keep investors apprised of any changes to its business model, and any developments that may impact the MLP. In addition, MLPs must also comply with the accounting requirements mandated by Sarbanes-Oxley.

Why Investors Are Flocking To Energy MLPs

What are the top reasons why regular, everyday investors are so attracted to MLP's? Here are four big reasons why:

1. The high level of current income - MLPs offer steady, reliable yields, and steady, reliable distribution payouts. That makes it perfect for income-minded investors, especially retirees.

2. The growth element - As MLPs are essentially operating companies, which means they can buy companies and grow dynamically, MLPs are high-growth vehicles. The "perfect storm" of current income, distribution yields, and growth dynamics fuel the type of double-digit investment returns that MLP investors have enjoyed for years.

3. Low correlations - MLPs traditionally have low correlations with the U.S. equities market, and are largely immune from price volatility of crude oil.

4. Tax advantaged - MLPs offer investors extremely favorable tax treatment, allowing investors to keep more of their partnership profits, and keeping more cash out of the clutches of Uncle Sam.

Why Do So Many Investors Overlook MLPs?

Historically, master limited partnerships have been a relatively small asset class. Even as recently as 2000, there were only about 16 energy-related MLPs available for investor access.

Today, there are over 100 energy MLPs, and the largely positive investment returns have earned the notice of the financial media, of financial advisors, and finally, of investors. Now, MLPs are morphing from an asset option for the rich and powerful, to a broadened investment category open to investors of all financial categories.

Make no mistake, MLPs aren't a secret anymore. For energy investors, that increased visibility is good news, and it may just be an opportunity of a lifetime for savvy investors.

- Brian O'Connell, guest editor

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

Business relationship disclosure: By Brian O’Connell, guest editor

If so, it would join an elite group of oil fields able to produce at that rate. Only six other fields, including Saudi Arabia's famed Ghawar field, have ever topped 1 million barrels per day-they are Burgan (Kuwait), Cantarell (Mexico), Daqing (CHINA) and Samotlor (Russia) and Kirkuk (Iraq).

The Bakken is a growth story like no other in the North American oilpatch. Less than ten years ago the Bakken was a useless resource, a pool of oil locked away in rocks too tightly packed for our technologies to penetrate. Then fracking technology unlocked America's shale oil. Today, the Bakken is churning out more than 700,000 barrels of oil per day (bpd).

But a growing chorus of naysayers thinks the Bakken's days of growth are numbered in North Dakota. These analysts and operators argue that wells spacing is growing too tight, making each new well less successful.

Who is right? Will the Bakken best 1 million bpd? Or is the Bakken's biggest growth already over?

There's no clear answer. What is clear is that the North Dakota Bakken is maturing. It's now perforated with holes, with a well on almost every 1,280-acre unit, (in Canada, we call that two sections) and the name of the game has changed from wildcat exploration drilling to infill holes.

For the naysayers, it adds up to a Bakken story that has lost its edge. But if the optimists are right, Bakken output will climb by another 50% in the next year or two, the formation will earn historic status, and another round of investors will bank many a Bakken buck.

What Goes Up Must Come Down

The geologists with the North Dakota Department of Mineral Resources are tasked with understanding the Bakken - what has happened to the shale formation and what will happen. And their predictions tell a very interesting tale.

This chart is from a recent department presentation. It shows three possible scenarios for the North Dakota Bakken, all of which show production doing the same thing-but peaking at very different levels.

That's because the three forecasts describe three levels of certainty. Proven resources are barrels of oil in the ground that have a 90% chance of being economically recoverable. In other words, the black line showing the 'proven' future is a near certainty, one that would be derailed only if oil prices fell a lot.

The other two lines show what would happen to North Dakota's oil output if less certain resources also end up being put into production. Probable resources have a 50% chance of being economic to recover; possible oil carries a 10% chance of being pumped to the surface.

Areas with probable or possible resources have not seen enough drilling for geologists to be sure of the geology, which leads to two types of uncertainty. First, there may be more or less oil than estimated. Second, the oil may or may not be economic to recover - especially since no one knows what the price of oil will be when the resource is eventually drilled.

If oil prices remain strong and the Bakken's geology remains consistent through these less certain areas, operators will keep drilling new wells and North Dakota's Bakken output should hit 1.2 million barrels per day by late 2014. This optimistic outlook means several more years of booming Bakken in North Dakota.

If oil prices tank or the Bakken reveals a geologic surprise that renders billions of barrels of probable and possible resources economically moot, output will plateau at a lower level, and sooner. In fact, if this prediction is the correct one then production has already peaked, at just above 700,000 barrels per day.

The most likely scenario, based on current information, is the one in the middle: that production will kiss 900,000 barrels per day in 2014, remain at that level for almost a decade, and then start to decline.

Whichever one happens, the message is that the North Dakota Bakken is coming close to its production peak.

"There is that point where the older wells aren't producing as much and newer wells coming online aren't as successful, so it does even out and production stops going up," says Alison Ritter, public information officer with the North Dakota Department of Mineral Resources.

That being said, the North Dakota Bakken likely hasn't reached its plateau just yet - and even when it does, the region will still be pumping a huge amount of oil for many years.

"If you think about it, two to three years is still pretty far out - we've still got a long ways to go as far as the drilling phase of things," Ritter said. "It's just that we are entering the efficiency phase, where operators are using more efficient rigs to pad drill, so there are not as many drills turning."

Putting it into Perspective - The Backstory of the Bakken

The story of the Bakken to this point is of a technological triumph that unlocked billions of barrels of oil.

Until the advent of horizontal drilling and fracking, oil contained in shale formations like the Bakken was uneconomic. There was simply no way to access the oil trapped in those thin layers of tightly-packed rocks.

Horizontal drilling and fracking released the bounty of the Bakken. At first, oil production only inched upwards, in large part because there weren't enough of the powerful drill rigs needed to frack a hole. But as the number of rigs increased so did the average number of fracks completed per hole, and soon production started to skyrocket.

In 2007, Bakken output averaged 75,000 barrels a day. Three years later, production had increased six-fold to 458,000 barrels of oil a day. As of September, production had hit 728,494 barrels of oil per day.

The chart above shows North Dakota Bakken production, which to date is a pretty good proxy for overall Bakken output even though the formation reaches beyond that state's borders.

(click to enlarge)

Three Challenges

There are three main challenges for the Bakken to reach oil production of 1,000,000 bopd:

1. How much oil can be recovered

2. Can the Bakken overcome steep decline curves

3. The Bakken becomes a victim of its own success-in both geology and economics

There truly is still an immense amount of oil in the Bakken. Original oil in place (OOIP) for the formation stands somewhere between 200 and 400 billion barrels, and production since 1953 adds up to just 503 million barrels.

OOIP is interesting, but what really matters is the amount of oil that can be recovered. If you want to get to 1,000,000 bopd production, you must recover a lot of that oil. The older style, pre-shale, conventional reservoirs have recoveries of near 30% (that's called the Recovery Factor, or RF) of OOIP.

But in tight reservoirs like the Bakken, the Recovery Factor drops below 10%.

In 2008 the US Geological Survey estimated the Bakken contained 3 to 4.5 billion barrels of "technically recoverable" oil. Soon after the North Dakota Geological Survey came out with a much higher number: 11 billion barrels. For its part, Bakken pioneer Continental Resources (CLR-NYSE) pegged the formation's recoverable resources at 24 billion barrels.

Whatever the number, it is important to remember that technically recoverable is not the same as economically recoverable. An area with very low recovery rates might host technically recoverable oil, but oil seekers aren't going to spend millions of dollars on a well that will only produce a trickle of oil.

And a Bakken well that starts with a trickle is bad news, because in shale deposits well outputs decline rapidly - along the lines of 40% year-over-year for the first few years.

Wells in conventional oil fields usually decline in a much more gradual manner:

The third challenge is starting to become more apparent right now. In trying to reach 1 million bopd, the Bakken could be a victim of its own success. The Bakken boom took off so quickly that infrastructure could not keep pace, and now there isn't enough pipeline capacity to move oil from the Bakken to America's refineries-on the Gulf, east or west coasts.

The result: Bakken oil is piling up in the storage hub in Cushing, Oklahoma. Basic economics say a glut of supply means lower prices - a heavy burden in a place where wells are unusually expensive.

A vertical well into a conventional oil field costs something like $1 million. The Bakken's horizontal, multi-stage frack wells cost an average of $9 million, according to the North Dakota Department of Mineral Resources.

That's a huge upfront cost. Each well produces approximately 615,000 barrels of oil, meaning the breakeven price for each Bakken well ends up in the $70-$90/barrel range, once taxes, royalties, and expenses are included. If oil prices slump below that level, a lot of people say Bakken wells aren't worth the cost.

As the wells in the Bakken grow closer together, initial production rates are sliding. According to some sets of data, average first year well output climbed steadily from 2005 to a peak in mid-2010, then declined almost 25% over the following 12 months.

With more wells tapping into the same resources, there is simply less oil pressure available to each well. And when initial well output starts to fall, an accelerating number of new wells must be brought online to sustain overall production volumes.

Such is the heart of the pessimist argument: that sliding initial flow rates will tag-team with the Bakken's high decline rates to mean that, no matter how many new wells are drilled, production will stagnate.

Then there are the crowds of optimists who still see many bright days ahead for the North Dakota Bakken. One of those optimists is oil and gas writer Michael Filloon. Filloon says the naysayers are wrong because they generally fail to consider a slew of factors that impact the economic success of a Bakken well, including increasingly effective frac techniques, longer lateral wells, revenues from the sale of byproduct natural gas and natural gas liquids, and cost savings from the shift to pad drilling. (I really enjoy Michael's articles-if you're a serious Bakken investor you should read his articles at seekingalpha.com)

CONCLUSION - Production Plateau Is Coming Soon

Exactly when and at what level Bakken output plateaus, one thing is clear: the Bakken is a national treasure. North Dakota is now second only to Texas in terms of state oil production. By 2035, the US Energy Information Administration thinks shale oil could account for as much as a third of US oil production and believes North Dakota alone will contribute 10% of America's oil needs.

That's impressive by any measure.

While it's too early to say if the Bakken can produce 1,000,000 barrels of oil per day, the reality is we should know in the next 2-3 years. Bakken production does best 1 million bpd it will join an elite group of oil fields able to produce at that rate. Only six other fields, including Ghawar, have ever topped 1 million barrels per day.

Even at its current level near 730,000 bpd, the Bakken is a formidable discovery. It has significantly enhanced America's energy security and generated incredible wealth for investors, landowners, North Dakotans, and state and federal governments. And North Dakota's Bakken will continue to pump impressive volumes of light, sweet oil for many years.

But whether in a year or three, and whether after reaching that million-barrel mark or not, North Dakota's Bakken boom will soon plateau. That, my friends, is simply the nature of resource extraction - the Bakken bounty just can't last forever.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.