If You’re Thinking About Investing in Oil Stocks...Read This First

By Justin Spittler

Is it safe to buy oil stocks yet? If you’ve been reading the Dispatch, you know the price of oil has plunged more than 70% since June 2014. Thanks to a massive surge in production, oil hit its lowest price since 2003 earlier this year. New extraction methods like fracking made the production surge possible. Last year, global oil production hit an all time high. Since then, companies have been pumping far more oil than the world consumes.

America’s largest oil companies lost $67 billion last year..…
Falling profits caused oil stocks to plunge. The SPDR S&P Oil & Gas Exploration & Production ETF (XOP), a fund that tracks major U.S. oil producers, has dropped 72% over the past two years. The VanEck Vectors Oil Services ETF (OIH), which tracks major oil services companies, has fallen 57% since 2014. Oil services companies sell “picks and shovels” to oil producers. However, oil stocks have showed signs of bottoming out in the past few months. XOP is up 57% since January, while OIH is up 45% in the same period.

Oil companies have cut spending to the bone..…
They’ve abandoned ambitious projects. They’ve cut back on buying new machinery and equipment. Some have even stopped paying dividends. For many companies, spending less wasn’t enough. Global oil companies have laid off more than 250,000 workers since 2014. Companies have also sold parts of their business to raise cash.

In March, Royal Dutch Shell (RDS.A) announced plans to sell $30 billion worth of assets. Shell is the third biggest oil company on the planet. According to Oilprice, Shell’s huge sale could include oil pipelines in the United States. In April, Marathon Oil (MRO), one of the largest U.S. shale oil producers, said it plans to sell about $1 billion worth of assets. Both companies have no choice but to get leaner. Shell’s profits plummeted 80% last year. Marathon lost $2.2 billion in 2015. It was the biggest annual loss in the company’s history.

Many companies have sold oil assets in North Dakota..…
As you may know, North Dakota was ground zero of America’s shale oil boom. From 2009 to 2014, the state’s oil production surged 554%. It became the country’s second biggest oil producing state after Texas.
North Dakota’s booming oil economy attracted more than 80,000 workers. It became the fastest-growing state in the country. Then, oil prices plunged.

North Dakota’s oil production has fallen 10% over the last 18 months..…
And it’s likely to keep falling. According to The Wall Street Journal, more than 2,000 oil wells in North Dakota haven’t pumped a drop of oil in over a year. That’s the highest number of idle wells in over a decade. Many oil companies in North Dakota are burning through cash right now. They’re under distress, and they’re selling assets at deep discounts to pay the bills.

Last week, The Wall Street Journal reported that this has attracted opportunistic investors:

The vultures are descending on North Dakota…
Hundreds of wells have changed hands or are in the process of being sold, state figures show, to a grab bag of fortune seekers ranging from industry experts to first-time wildcatters. They are picking up properties as more established producers scale back or shed assets to pay creditors.

According to The Wall Street Journal, some of these opportunistic investors are Wall Street veterans:

Houston-based Lime Rock Resources, founded by a former Goldman Sachs Group Inc. banker and an oil-industry veteran, bought more than 340 North Dakota wells from Occidental Petroleum Corp. in November. The firm says it has at least $1.6 billion in private-equity money to invest, a portion of which it has spent on the Bakken. In another pairing of Wall Street and oil-patch veterans, NP Resources LLC bought 53 wells from Whiting Petroleum Corp. in December and is looking for more Bakken acreage.

This is a prime example of "crisis investing." Regular readers are familiar with this strategy. As you’ve probably heard us say, crisis investing is one of the world’s most powerful wealth building secrets. In short, crisis investing involves going against the crowd to buy beaten down assets that have been left for dead. You can often use this strategy to buy a dollar’s worth of assets for pennies. The good news is that you don’t need to step foot in North Dakota to crisis invest in the oil market. Anyone with a brokerage account can turn the oil crash into a money making opportunity.

As we said earlier, many oil stocks are showing signs of bottoming..…
Lots of big oil companies, like Devon Energy Corporation (DVN) and Continental Resources, Inc (CLR), are up 50% or more off their lows. That’s because oil prices have jumped 89% since January. Last week, oil prices closed above $50 for the first time since July. These big swings are typical for oil. Like most commodities, oil is cyclical, meaning it goes through big booms and busts.

It’s impossible to know for sure if oil prices have bottomed. Time will tell if oil’s recent jump is the start of new bull market. But we do know that many oil stocks are trading at their best prices in years. And because the world still runs on oil, it’s smart to go “bargain hunting” for great oil stocks today.

If you're buying oil stocks, stick to the elite companies..…
We look for a companies that can 1) make money at low oil prices. We also like companies with 2) healthy margins 3) plenty of cash and 4) little debt. In March, Nick Giambruno, editor of Crisis Investing, recommended an oil company that checks all of these boxes. It has a rock solid balance sheet…some of the industry’s highest profit margins…and “trophy assets” in America’s richest oil fields. Most importantly, it can make money at as low as $35 oil.

Like the “vultures” that descended on North Dakota, Nick used the oil meltdown as an opportunity to buy this world class oil company at a huge discount. He bought the stock just weeks after it hit a three year low. Since then, the stock has gained 10%. But Nick says it could go much higher. After all, it’s still down 30% since June 2014. You can access the name of this stock with a subscription to Crisis Investing, which you can learn more about right here.

By clicking this link, you’ll also hear about the biggest crisis on Nick’s radar. Every American needs to prepare for this coming crisis. By the end of this video, you’ll know how to protect yourself AND make money in its aftermath. Click here to watch this free video.

Chart of the Day

The oil surplus is shrinking..…
Today’s chart shows the price of oil going back to the start of 2014. As we said earlier, the price of oil has nearly doubled since January. But you can see that it’s still about half of what it was two years ago.
Oil prices are still low for a couple reasons. One, the global economy is slowing. As Dispatch readers know, the U.S., Europe, Japan, and China are all growing at their slowest rates in decades.

Secondly, the world still has too much oil. According to the Financial Times, oil companies are producing 800,000 more barrels of oil a day than the world consumes. In February, the global surplus stood at about 1.5 million barrels a day. The surplus has come down because oil companies are pumping less oil. But that’s not the only reason the global oil surplus has shrunk. On Monday, Bloomberg Business said the industry has also been hit by major “disruptions”:

Outages also have taken their toll on supply, with global disruptions reaching an average 3.6 million barrels a day last month, the most since the Energy Information Administration began tracking them in 2011. Fires that began early May in Alberta took out an average 800,000 barrels of Canadian supply last month, while Nigerian crude output dropped to the lowest in 27 years as militants increased attacks on pipelines in the Niger River delta.

The article If You’re Thinking About Investing in Oil Stocks, Read This was originally published at caseyresearch.com.

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New LNG Plant in North Dakota will Supply Oil and Gas Producers

A new natural gas liquefaction plant is slated to come online this summer in North Dakota to reduce the flaring of gas in the Bakken Formation and provide fuel for Bakken oil and gas operations. The developer, Prairie Companies LLC subsidiary North Dakota LNG, announced earlier this month that the plant would provide an initial 10,000 gallons per day (gal/d) of liquefied natural gas (LNG), and could expand to 66,000 gal/d. Assuming a 10% processing loss, the plant would take in a maximum of 6 million cubic feet per day (MMcf/d) once expanded. In 2012, North Dakota vented and flared 218 MMcf/d of natural gas because of record high oil production and insufficient pipeline takeaway capacity for natural gas produced as a byproduct.

Hess Corporation will supply the natural gas for liquefaction at Prairie's Tioga natural gas processing location. After the LNG is produced, it will be sent via truck to storage sites at drilling locations, where – once regasified – it can be used to power rigs and hydraulic fracturing operations as well as LNG vehicles. LNG itself cannot burn; in its liquefied state, its temperature is minus-260 degrees Fahrenheit. However, as a liquid, it takes up only 1/600th of its volume as a gas, so LNG is an excellent form to store or transport natural gas. Currently, most drilling operations run on diesel, and converting to natural gas provides potentially significant cost savings given the current differential between diesel and natural gas prices. In 2012, EIA estimated that nationally oil and gas companies consumed more than 5 million gal/d of diesel in their operations, representing a significant expense.

While conversion to natural gas might not be possible in many cases, in the past few years, several companies have developed and are marketing technologies that would allow drilling rigs and fracturing pumps to run in both dual fueled and or single fueled modes.

Although the liquefaction plant will be the first LNG project in the Bakken, some producers have begun using natural gas to power their operations, citing cost savings, access to natural gas, and environmental benefits. Statoil uses compressed natural gas (CNG) to fuel some of its drilling equipment. The natural gas is produced in the Bakken and compressed using General Electric's CNG in a Box system.

Additionally, outside of the Bakken, other companies have successfully used natural gas to power drilling operations. In 2012, Seneca Resources and Ensign Drilling installed GE LNG fired engines on drilling rigs in the Marcellus Shale. Apache, Halliburton, and Schlumberger have successfully used CNG and LNG to power hydraulic fracturing operations in the Granite Wash formation in Oklahoma.

Some of these companies have estimated fuel savings on the order of 60% to 70% compared to diesel, as well as payback on the conversion investment in about a year. The basic economics that have driven the recent interest in converting or manufacturing more heavy duty trucks to run on LNG are driving some of the interest in converting to natural gas for fueling stationary oil and gas operations.

Posted courtesy of the EIA


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99 Problems… And Crude Oil Ain’t One of Them

By Marin Katusa, Chief Energy Investment Strategist

America has some serious problems.


Despite the fact that the United States spends $15,171 per student—more than any other country in the world—American students consistently trail their foreign counterparts, ranking 23^rd in science and 31^st in math.

The US also spends more than twice as much on health care per capita than the average developed country, yet underperforms most of the developed world in infant mortality and life expectancy. The U.S. rate of premature births, for example, resembles that of sub-Saharan Africa, rather than a First World country. And if you think Obamacare is going to change that… I have a bridge to sell you.

K Street has a bigger influence on American politics now than Main Street, and economic key players like the TBTF banks, the insurance industry, etc., have nearly carte blanche to act in whichever way they see fit, with no negative consequences.

The US government is spending more money to spy on Americans and foreigners than ever before. Since August 2011, the NSA has recorded 1.8 billion phone calls per day (!)—with the goal of creating a metadata repository capable of taking in 20 billion "record events" daily.

More than one in seven Americans are on the Supplemental Nutrition Assistance Program (SNAP)—better known as "food stamps."

The list goes on and on.

But there is one problem that America doesn't have......getting oil out of the ground.

After decades of declining domestic production, U.S. producers finally figured out how to extract oil from difficult locations, whether that's the shale formations or deposits under thousands of feet of water… and they've kept going ever since.

Today, the U.S. is one of the few countries in the world that have seen double digit growth in oil production over the past five years.

This presents some great investment opportunities for the discerning investor.

The oil industry's new treasure trove, the legendary Bakken formation, has turned formerly sleepy North Dakota into one of the hottest places in the United States. According to the Minneapolis Fed, "the Bakken oil boom is five times larger than the oil boom in the 1980s."

Unemployment in the state with 2.7% is the lowest in the nation; in Dickinson, ND, even the local McDonald's offers a $300 signing bonus to new hires, on top of an hourly wage of $15.
Here are some more fun facts, courtesy of the Fiscal Times:

• There are now an estimated 40,856 oil industry jobs in North Dakota, plus an additional 18,000 jobs supporting the industry. Between 2010 and 2012, Williston, ND, a town with a population of only 16,000, produced 14,000 new jobs.

• While other US states are struggling, some even being close to bankruptcy, North Dakota now has a billion-dollar budget surplus.

• The number of ND taxpayers reporting income of more than $1 million nearly tripled between 2005 and 2011—and that in a state with a total population of 700,000.

• The low population numbers will soon be a thing of the past, though: the population in the oil-producing region is expected to climb over 50% in the next 20 years.

• 2,000-3,000 new housing units are built every year in Williston, ND, but it's still not enough to fill the need. Rents have gone from a pre-boom $350 per month for a two-bedroom apartment to over $2,000 today… the equivalent of a studio apartment in New York's rich Upper East Side.

The entire "energy map" of the United States has been altered by the Bakken: the Midwest, rather than the Gulf, is now the go-to area.

And who profits the most? The pipeline companies that can quickly adapt to this new situation and the refinery companies that can use this readily available domestic oil.

Though the rest of the world is trying to catch up, the United States has a huge head start over everyone else. The advancements it holds in hydraulic fracturing and horizontal drilling had been built on the back of one and a half centuries of oil and gas exploration and the thousands of firms that service the drillers and producers.

So far, other countries simply lack the experience and the infrastructure to even compete.

In fact, American companies have spent 50% more money on energy research and development (R&D) than companies anywhere else in the world. What's more, they are exporting this technology across the globe, enabling other countries to unlock their own hydrocarbon reserves.

Obviously, they're not doing this out of philanthropy; there is a lot of money to be made by licensing out their technology and "lending a helping hand."

The biggest winners, hands down, are the energy-service companies that already know how to get oil out of US fields… and that apply these methods to other fields worldwide to boost production and reduce decline rates.

As the easy-to-extract oil depletes in the U.S. and abroad, oil companies and governments are beginning to look at past-producing oil fields. As it turns out, the producing wells drilled in the 1970s and '80s weren't very good at getting every drop of oil out of the ground. With modern technology, however, it is now possible to access previously out-of-reach deposits. Even a mere 5% or 10% improvement in oil recovery rates means billions, if not trillions, more in revenues.

Rediscovering previously overlooked fields was what started the boom in the Bakken as well as the Eagle Ford formations… and other countries are beginning to catch on.

We believe that this new trend of applying new technologies to old oil fields is not a fad but here to stay. That's why our energy portfolios are stocked with companies doing just that in Europe, Oceania, and even South America.

As it's becoming clear that the era of cheap, light, sweet crude is nearing its end, the industry is adapting to this new reality of oil becoming more difficult to access. And if investors want to make profits in today's energy markets, they, too, must learn to adapt.

Read our 2014 Energy Forecast for more details on what's hot and what's not in this year's energy markets. This free special report tells you about the 3 sectors we are most bullish on for this year, and which sectors to avoid in 2014. Read it now.


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Energy Outlook: What’s Hot in 2014

By Marin Katusa, Chief Energy Investment Strategist

Investors who want to know how the energy sector will be doing in the coming year are, in my opinion, asking the wrong question. There really is no such thing as "the energy sector," because the performance of the different resources—from oil and gas, to uranium, to coal, to renewables—can vary dramatically.


Case in point: while unconventional oil exploration and production have seen a huge upswing in recent years, thanks to the vast success of the Bakken and other oil rich shale formations, at the same time natural gas has taken a nosedive, due to a supply glut that still hasn't found its balancing point.

To find out which investments will deliver the greatest profits for well positioned investors in 2014, my team and I have identified three trends that are hot… and may become even hotter in the course of this year.

HOT: Service Companies in North America

The oil and gas production in the United States is mature. Rather than looking for new basins, companies are looking to "rediscover" the past by applying new technology to increase economic production from known oil and gas fields.

This new technology comes in a variety of shapes and sizes: better software, bigger rigs, more efficient drilling processes. And it's being applied everywhere, onshore and offshore, conventional and unconventional alike.

Just as an example, today we're seeing operators drill more than 50 horizontal wells from a single well pad, a far cry from just a decade ago.

Exploration and production companies know that the focus moving forward is not just the amount of oil they can pump out of the ground, but the profit they can extract from every barrel (what we call the "netback"). This is even more true in the mature unconventional basins such as the Bakken, Eagle Ford, and the Marcellus shale plays, where the margins are tight and require an oil price of more than US$70 per barrel in order to be economic.

This means E&P companies have to use the best ways to increase production from every well—while at the same time reducing their drilling costs. Failure to do so would be to guarantee a firm's demise.

The dilemma for E&P companies is having to prioritize what their shareholders want in the short term—growing production and dividends—over whatever may be best for the company in the long term. At the same time, they have to fight the natural decline of oil coming out of their wells.

All the while, service companies continue to extract fees for their tools and services. Drillers, pumpers, frackers, and other oilfield-service guys make money regardless of whether E&P companies find oil or produce it at economic rates.

We've said it before: Many E&P companies are running on a treadmill, and the incline is going higher and higher, which means higher costs to produce the same amount of oil.

Of course, not all service companies will rake in the dough. The ones that will do the best are the ones that can consistently stay at the forefront of technology and keep signing contracts with the supermajors like Exxon, Chevron, and Shell.

HOT: European Energy Renaissance

Russia's grip on European energy continues to tighten, and there's a push to produce oil and gas within their own borders all around Europe.

2014 looks to be an exciting year for companies like one of our Casey Energy Report stocks, a TSX-V-listed oil and gas explorer and producer with a 2 million acre concession in Germany. We call the deposit it's sitting on the "Next Bakken" because we believe that its potential to deliver exceptional output could rival that of the famed North American formation.

This development is still in its early stages, but investors who position themselves now could see outsized gains for years to come. It's not really a question of "if" the oil is there—previous oil production in the very same location yielded more than 90 million barrels—but of "how much" oil can be extracted with the modern methods not available the last time companies worked on this field.

The company has completed its first well and will continue to drill additional wells (both vertical and horizontal) next year. While the initial well cost more than anticipated, it's a good start that indicates economic oil can be produced in Germany. We're also confident this company's experienced management team is applying the lessons of its first foray to reduce drill costs on future wells.

As our Energy Report pick proves up any of its projects in 2014 and early 2015, we can expect another of our holdings, which has just entered the German oil and gas scene, to either farm into the company or even buy it out.

We predict that by the end of 2015, our "Next Bakken" play, and others like it, will have attracted a lot of attention, not just from individual speculators, but from institutional investors as well—and investors who have gotten in early will be very happy indeed.

Another of our portfolio holdings is just beginning to drill on its Romania projects after a series of delays due to politics and bureaucracy. We have reason to be optimistic because its JV partner, a Gazprom subsidiary, has drilled successful wells on the same basin on the other side of the border in Serbia. If our pick has anything close to that level of success, the markets will surely take notice and its shares will go much higher.
As the "Putinization" of the global energy markets continues and Russia's dominance grows, European countries become increasingly more desperate to escape from under Putin's heavy thumb and to start developing their own energy resources.

The European Energy Renaissance is real, and we continue to monitor companies that are funded and have the permits and ability to drill game-changer wells in Europe in 2014.

HOT: Uranium

During a recent trip to London, I spoke with Lady Barbara Judge, chairman emeritus of the UK Atomic Agency and an advisor to TEPCO on the Fukushima nuclear disaster in Japan. I asked her point blank whether Japan was willing to bring any nuclear reactors back online in 2014.

Her answer was an unequivocal "Yes." The Japanese have no choice, really, because the alternative—importing liquefied natural gas (LNG)—is far too expensive.

Japan is the world's largest importer of LNG and has had to double its imports since the Fukushima incident. For that privilege, the country pays some of the highest rates on the planet, almost four times more than what we pay for natural gas in North America.

South Korea also shut down its nuclear plants post-Fukushima to do inspections and maintenance upgrades, and it, too, has had to import a lot of LNG. Both countries are looking to restart their nuclear reactors so they can stop paying a fortune to foreign energy suppliers. When these countries restart their reactors, they'll also restart the uranium market, so we expect uranium prices to begin to shake loose of the doldrums this year.

Another driver will be throwing the switch at ConverDyn, the U.S. uranium facility that is slated to start converting natural U₃O₈ to reactor-ready fuel in late 2014 or early 2015.

We currently hold two solid uranium companies in the portfolio—one is a U.S. based small cap producer (one of the very few in America), the other is the lowest risk way to play the uranium market that I know of. Both, we believe, will take off in 2014 on the renewed interest in uranium and the associated stocks.

If you want to know more about our thoroughly vetted energy stocks and their potential for amazing gains in 2014 and beyond, give the Casey Energy Report a try. You'll find all my "What's Hot" predictions and the full names of the stocks I've mentioned above in our January forecast issue… plus the energy sectors you should avoid like the plague this year… as well as a feature article on elephant oil deposits in the Gulf of Mexico and a new stock pick ready to profit from them.

Giving the Casey Energy Report a try is risk-free because it comes with a 3 month, full money back guarantee. If the Energy Report is not all you expected it to be, just cancel within those 3 months and get a prompt, full refund. Or cancel any time AFTER the 3 months are up for a prorated refund. Getting started is easy.......Just Click Here.


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The Next Bakken?

Just a few days ago, a hastily assembled team including Chief Energy Investment Strategist Marin Katusa and Casey Research Managing Director David Galland were preparing to fly to a secret location. A location where a small oil company is about to drill the first oil well into what appears to be a massive new oil bonanza.

But at the last minute, the oil company's lawyers canceled the trip and imposed a total communication blackout. They did so out of concern that regulators would think having the Casey Research team on site gave Casey Energy Report subscribers an unfair advantage.

While disappointed that the site visit was canceled, the Casey energy team has already extensively researched the company and are now free to tell their subscribers about it.

And that's why I'm writing to you today: the Casey energy analysts believe this company may have as much or even more potential than those companies that made billions in the now legendary Bakken formation.

To put that assertion into perspective, let me tell you a little bit about the Bakken. In case you're unfamiliar with it, it's a monster oil and gas deposit covering almost 15,000 square miles across North Dakota, Montana, and Alberta, Canada.

The latest US Geological Survey estimates that the Bakken contains upwards of 7.4 billion barrels of recoverable oil - and that is considered on the low end of the range. An executive of a company deeply involved in the Bakken recently estimated that the basin will ultimately yield 20 billion barrels.

And those who discovered the Bakken's tremendous potential ahead of the crowd are now very well off indeed....When It Rains, It Pours... Cash

Until 2005, the Bakken had been largely written off as uneconomic. Then leapfrogging advances in horizontal drilling technologies changed everything, triggering a land rush that made multimillionaires out of landowners and explorers.

Take Harold Hamm, for example. The founder and CEO of Continental Resources (CRL), Hamm, as Forbes magazine puts it, "is responsible for cracking the code of the Bakken."

In 2007, the same year that Continental was listed on the NYSE, the company was the first to complete lateral, multi-stage drilling over 1,280 acres in North Dakota.

One year later, Hamm was the first to demonstrate that the Three Forks formation, which was initially believed to be part of the Bakken, was a separate reservoir and might hold more oil than the Bakken itself.

The rest, as they say, is history. Hamm is now worth $11.3 billion, which makes him the 90th richest person on the planet.

But it's not just the wildcatters themselves that rake in the big money: Early bird investors in Continental Resources made gains of up to 459% within 14 months after the company's NYSE listing. And those who held on were looking at gains of 549% when CRL's stock peaked in February 2012.

In other words, had you trusted in Hamm's genius when he started out drilling in the Bakken, an investment of just $10,000 would have turned into $64,900 for you.

There's no question about it: The use of new technologies to unlock the Bakken, the Eagle Ford Shale, and other huge oil deposits previously considered uneconomic has been a game changer for North American energy supplies.

And you could be the beneficiary of the next Bakken-type windfall....The Next Bakken - But Even Better?

As I said before, the Casey energy analysts believe that the small company they've uncovered could be the next Continental Resources, sitting on unimaginable riches.

Over the last year this little company has quietly assembled a 2-million-acre concession in a region whose geological conditions for the production of oil and gas are actually far more promising than those in the Bakken.

And about one week from now, these resources could finally be proven to be in place. You can imagine what that could do to the company's share price.

The company's top executives appear to have a similar vision: Many of them have personally invested millions of dollars to fund the company and its current drill program.

In July, one director of the company, who is also the CEO of a major Canadian oil player, bought 200,000 shares at the market – bringing his holdings of the company's stock to a total of 1,235,237 shares.

I think his optimism is well placed, considering that the company's management includes seasoned Bakken veterans who not only recognize the potential of the "new Bakken," but also have the skills to get the oil out of the ground.

If the initial well now being drilled meets management's expectations, this small-cap company will be on the fast track for explosive shareholder returns, potentially for years on end. Be There When the Truth Is Unveiled - for a Chance at Staggering Returns

Best of all, so far only a handful of research firms have been paying attention to this virtually unknown company. Therefore, we are uniquely positioned to take advantage of the news released once the well data have been compiled.

In fact, within minutes of the company breaking the silence imposed by its lawyers, Casey’s analysts will be standing by to share their on the spot analysis with subscribers to the Casey Energy Report....even if it's the middle of the night.

To be fair, though, I have to remind you that this is a speculation, not a slam dunk investment. Drilling is always a risky business, so we have to keep our enthusiasm in check until the first well is completed and the initial flow data are logged.

If, however, the initial well test confirms that the company is sitting on the "next Bakken," the investment returns from its 2 million acre concession should be nothing less than spectacular. And the odds for that happening are excellent. Be Ready: Initial Drilling Results Are Expected on or Around Monday, September 16

Until the company has completed its flow tests and made a public announcement, Casey can't share any details about the company, or even the country where the next potential Bakken is located.

But once the company issues its own press release, everyone who is an active subscriber to the Casey Energy Report will receive our alert with an up-to-the-minute analysis and specific recommendation on how to invest.

In addition, to ensure that Energy Report readers get the full picture of this exciting new play, the Casey Energy team is now preparing a comprehensive report about the "next Bakken" and the small-cap company already supremely positioned to profit from it.

While no one can say exactly when the drill will reach the pay zone and the subsequent well flow test will be completed, the last estimate provided by the company before the lawyers instituted the communications blackout was mid September.

Based on Casey’s own analysis of the processes involved, they anticipate the company will be ready to release news on or about Monday, September 16. Of course, due to the nature of any drill program, this is only an estimate.

Regardless, once the testing is completed and the company issues its public press release, Casey Energy Report subscribers will immediately receive an Alert with our analysis - and their special report on the next Bakken.

Of course, it would be massively unfair (and poor business ethics) to release this information to non paying subscribers.

Not to worry, though. If you subscribe today, you can still participate in the earliest phase of what could become a flood of investment into the "next Bakken." Make a Bundle or Pay Nothing for Your Subscription

How much does it cost to get in on what could be the next Bakken? Thousands of subscribers to the Casey Energy Report pay $248 per quarter, an amount that may seem high to some.

However, that they were prepared to send an executive team to the secret well site - involving international flights and almost 11 hours in a car - should make it clear just how much potential we believe this investment has for our subscribers. If they're right, the potential returns will make the cost of your subscription pale by comparison.

But what if they're wrong, and the first well is a bust? What then?

It's simple: thanks to Casey’s 3-month, no-questions-asked, 100% money-back guarantee, if you don't make a bundle off this exciting new play within the first three months of your subscription, simply drop them an email and they'll promptly return every penny you paid.

It's a completely straightforward proposition that works entirely in your favor.

Of course, they're pretty confident you won't cancel your subscription.

Because they believe that they are about to make a lot of money on this stock, and that it will continue to provide exceptional returns for years (or until it is taken over by a larger company hungry for the 2-million-acre concession it has assembled on the next Bakken – and if that happens, it'll be just as good for us).

In a May 2010 interview broadcast on Business News Network, Chief Investment Strategist Marin Katusa spoke about Africa Oil, another early Casey energy pick. In that interview, he said, "This stock has a realistic potential to give you 10 to 15, even 20, times your money."

He was right: Africa Oil handed early investors a profit of over 1,200%.

In a recent email, Marin wrote, "Since that interview on Africa Oil, I have never made a similar forecast about a company, but I have no reservations saying that this new company easily has as much or more potential."

You do not want to miss out on this opportunity.

Getting in on the ground floor is as simple and easy as clicking here to sign up for the Casey Energy Report now.

Remember, Casey’s ironclad 100% money back guarantee means you've got nothing to lose to give the Casey Energy Report a try. With the drill turning and their energy team hard at work preparing its comprehensive report on the "next Bakken," now is definitely the time to act.

Sincerely,

Ray @ The Crude Oil Trader

P.S. It's important to highlight that members of the Casey Research team own shares in investment funds that have invested capital in this firm back from the time it was just an idea. That the company appears to have made good use of its capital to build its position on this potentially huge new oil play is all to the good and the only reason we are bringing this stock to the attention of our readers. To avoid a conflict of interest, Casey’s corporate policies (correctly) require them to provide advance notice to subscribers before they sell, which we don't see happening until the company has unlocked its full potential and its shares are trading at many multiples of where they are now.

If you, too, want to join in on this early stage play, be sure to sign up today - or at the latest before Monday, September 16. And don't forget: you either make a bundle or you simply cancel within 3 months for your money back. Even after three months, you can still cancel anytime and receive a prorated refund.

Don't miss this rare opportunity to get in on the ground floor.

Here again is the secure link to join Casey Energy Report.

Could TPLM Be The Most Undervalued Bakken Producer

From Bret Jensen, Daily columnist for RealMoney at TheStreet.com. Chief Investment Strategist for Simplified Asset Management......

Earlier this month, I did a deep dive analysis on Triangle Petroleum (click here to get your free trend analysis for Triangle Petroleum). I argued based on recent acquisitions, this Bakken energy producer was tremendously undervalued compared to its acreage and production. I postulated that the stock could double over the next 18-24 months. The stock sold at $5.40 a share at the time of the article. TPLM has moved up more than 25% since then and I continue to see further upside ahead of this fast growing producer.

Today, I want to talk about quite possibly the most undervalued producer in the Bakken that I have in my own portfolio, Emerald Oil (EOX). I would have led with Emerald, except the company has been a serial disappointment to investors over the last couple of years. However, its production and acreage is significantly undervalued by the market. The company also appears to be picking up some positive catalysts and finally looks poised to enable a sustained rise in its equity price.

The company is a small ($160mm market capitalization) independent E&P concern. The company’s main production comes from the 54,000 net acres (23,500 operated acres/30,500 non-operated acres) it has in the Bakken shale region (Williston). It has tens of thousands of other net acres in other shale regions outside the Bakken. Emerald’s main production comes from its core Williston acreage and it has been in the process of selling off its other properties to raise capital to concentrate on developing its operated acreage in the Bakken

Read the Full Story Here 





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North Dakota Crude Oil Production Continues to Rise

North Dakota's oil production averaged 660 thousand barrels per day (bbl/d) in June 2012, up 3% from the previous month and 71% over June 2011 volumes. Driving production gains is output from the Bakken formation in the Williston Basin, which averaged 594 thousand bbl/d in June 2012, an increase of 85% over the June 2011 average. The Bakken now accounts for 90% of North Dakota's total oil production.

Production gains in the Bakken formation are the result of accelerated development activity, primarily horizontal drilling combined with hydraulic fracturing. According to the North Dakota Department of Mineral Resources, there were a total of 4,141 producing wells in the North Dakota Bakken in June 2012, up 4% from May 2012 and up 68% from the number of producing wells in June 2011.



Increasing oil rig counts underscore the quickening pace of drilling in the region. Data from Baker Hughes show that in the Williston Basin, the average weekly count of actively drilling horizontal rigs totaled 209 in June 2012, essentially unchanged from the May 2012 average but 26% above the June 2011 average (see below). Most of these rigs are positioned in the Bakken.



The transportation system oil pipelines, truck deliveries, and rail to move crude oil out of the area is being affected by constraints due to growth in crude oil production from the Bakken formation. As a result of these bottlenecks, the difference between spot prices for Bakken crude oil and West Texas Intermediate (WTI) crude oil expanded through much of the first quarter of 2012. The spread has generally narrowed in recent weeks, however, reflecting the addition of rail transport facilities and increased refinery capacity in the Bakken area.



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EOG Resources Reports Second Quarter 2012 Results, Increases 2012 Crude Oil Production Growth Target to 37 Percent

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EOG Resources, Inc. (NYSE: EOG) today reported second quarter 2012 net income of $395.8 million, or $1.47 per share. This compares to second quarter 2011 net income of $295.6 million, or $1.10 per share.

Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one time items, adjusted non GAAP net income for the second quarter 2012 was $312.4 million, or $1.16 per share. Adjusted non GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share.

The results for the second quarter 2012 included impairments of $1.5 million, net of tax ($0.01 per share) related to certain non-core North American assets, net gains on asset dispositions of $75.1 million, net of tax ($0.28 per share) and a previously disclosed non cash net gain of $188.4 million ($120.7 million after tax, or $0.45 per share) on the mark to market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $173.2 million ($110.9 million after tax, or $0.41 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

With 86 percent of North American wellhead revenues currently derived from crude oil, condensate and natural gas liquids, EOG delivered strong earnings per share growth of 64 percent for the first half of 2012 compared to the same period in 2011. Discretionary cash flow increased 29 percent and adjusted EBITDAX rose 28 percent over the first half of 2011. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)

"EOG's financial and operating results get better and better. We are achieving this consistent string of home runs because EOG has captured the finest inventory of onshore crude oil assets in the entire United States and has the technical acumen to maximize reserve recoveries," said Mark G. Papa, Chairman and Chief Executive Officer. "EOG is the largest crude oil producer in the South Texas Eagle Ford and North Dakota Bakken with the sweet spot positions in both plays. In addition, we are uniquely positioned to market a significant portion of this crude oil at robust Brent type pricing through our own rail offloading facility at St. James, Louisiana, and to reach the Houston Gulf Coast market via the recently completed Enterprise Eagle Ford pipeline."

Read the entire EOG earnings report

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North American Spot Crude Oil Benchmarks Likely Diverging Due to Bottlenecks

Gold and Silver on the Verge of Something Spectacular

West Texas Intermediate at Cushing, Oklahoma (WTI Cushing), a light, sweet crude grade, is North America's most closely observed crude oil price benchmark and the underlying commodity of the NYMEX crude futures contract. Until 2008, all North American crude grades broadly tracked fluctuations in WTI Cushing prices and were clustered within about $8 per barrel of the WTI Cushing price. Pricing differences between crude grades were largely explained by the different quality characteristics of the crude oil in each location and transportation costs to Cushing, the delivery point of the NYMEX contract.

Since 2008, however, the price differences between WTI Cushing and other North American crude oil benchmarks have increased sharply (see chart below). In addition to WTI, other crude grades have emerged as alternative benchmarks. In particular, the Argus Sour Crude Price Index (ASCI), a weighted average of prices for several offshore Gulf of Mexico sour crude grades, has become the benchmark or reference used for assessing the price of several imported grades sold on a long-term contract basis, including Saudi Arabian and Kuwaiti crude grades.



Transportation constraints in the wake of rising production from inland fields in Canada, North Dakota, and Texas are one of the main drivers of the growing price discrepancy between crude grades since 2008. Limited pipeline capacity has made it difficult to bring crude oil out of the center of the continent, lowering all the affected benchmarks compared to prices outside the area. But within the constrained area, prices have also diverged from each other, reflecting local transmission bottlenecks within the larger constrained area. For example, crude oil benchmarks for the Bakken, Western Canada, and West Texas Sour (Midland, Texas) have traded at a discount to WTI Cushing. Rising production in the Bakken and West Texas have exacerbated these price differences. Outside the constrained areas, benchmarks like Louisiana Light Sweet, Alaska North Slope, and Mars Blend in the Gulf of Mexico reflect premiums to WTI Cushing, sometimes significant.

The phrase "transportation constraints" refers to a broad range of logistic issues, with inadequate pipeline capacity being the most common issue. However, EIA is not aware of any crude oil production capacity being shut in because of a lack of capacity to move the oil. In the short term, production surges and/or pipeline shutdowns force oil producers to compete with each other for more expensive transport options: rail and then truck. In the longer term, additional transportation capacity (rail and pipeline) is likely to be built, which should lower the cost of transporting the oil to markets.

Some North American crude oil benchmark locations are identified in the map below.

Source: U.S. Energy Information Administration. 

Gold Still at Risk of a Large Downward Move Before the Rally

Williston Basin Crude Oil Production and Takeaway Capacity are Increasing

Crude oil production from the Williston Basin (primarily the Bakken formation) recently increased to more than 600 thousand barrels per day (bbl/d), according to Bentek Energy, LLC (Bentek), testing the ability of the transportation system, oil pipelines, truck deliveries, and rail to move crude oil out of the area (see chart below). The current price gap between Bakken crude oil and West Texas Intermediate (WTI) shows the effects of this constraint. Bentek projects more transportation capacity coming online in 2012, potentially alleviating this constraint.




 Due to pipeline capacity constraints, Williston Basin producers rely on rail and trucks to move additional crude oil out of the region. Because of these transportation constraints, Bakken crude oil currently sells at a discount of $7.50 per barrel to WTI. This discount was as much as $28 per barrel in February 2012 and is expected to continue as long as transportation constraints persist.

Currently, North Dakota has only one refinery, which processes about 58 thousand bbl/d of crude oil. Crude oil is delivered to other markets using a combination of pipeline, rail, and truck. Delivery capability as of April 2012 was: 450 thousand bbl/d by oil pipeline; 150 thousand bbl/d by rail; and small volumes by truck. However, in 2012, incremental additions to rail and oil pipeline capacity for the Williston Basin could total 350 thousand bbl/d.

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EIA: U.S. Imports of Nigerian Crude Oil Have Continued to Decline in 2012

The trend of declining crude oil imports into the United States continued in the first month of 2012. There has been a particularly sharp decline in imports from Nigeria due to the idling in late 2011 of two refineries on the East Coast, which were significant buyers of Nigerian crude, and reduced imports by refiners on the Gulf Coast. Prior to the idling of the refineries, Nigeria typically accounted for about 10% of the crude oil imported into the United States; in January, that share dropped to about 5%.



 In January 2012, imports from Nigeria totaled just 449 thousand barrels per day (bbl/d), a 54% (519 thousand bbl/d) decrease from January 2011, marking the lowest monthly import total from the country since 2002. One third of this decline was the result of two idled Philadelphia area refineries. ConocoPhillips' Trainer refinery (idled in September 2011) and Sunoco's Marcus Hook refinery (idled in December 2011) imported a combined 173 thousand bbl/d of Nigerian crude in January 2011. Most of the remaining decrease in Nigerian imports was the result of several Gulf Coast refiners reducing Nigerian imports in favor of domestically produced crude.

The idled refineries were suited to run light-sweet crude oils, and Nigerian crude oils tended to match well with that requirement. However, because of their quality, Nigerian crude oils are often expensive compared to heavier or more sour crude oils used by many of the Gulf Coast refineries.

 Additionally, Nigerian crudes are currently expensive compared to some of the inland domestic light sweet crudes of similar quality such as West Texas Intermediate (WTI), Bakken, and Eagle Ford. Given the growing production from the Bakken and Eagle Ford formations and associated transportation constraints, these inland crudes have been selling at a discount to waterborne crudes on the Gulf Coast, providing refiners in that area further incentive to switch from imported crude to inland, domestically produced crude when available.

Preliminary weekly data indicate the trend of decreasing Nigerian imports continued in February and March with March imports averaging just 301 thousand bbl/d, which, if confirmed in the monthly data, would represent a 64% decrease compared to March 2011.

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Refinery Utilization Rates React to Economics in 2011

The divergence of West Texas Intermediate (WTI) and Brent crude oil prices in 2011 affected refinery utilization in the United States, particularly in the East Coast (PADD 1) and Midwest (PADD 2) regions. Historically, refineries in these districts operated at 80-90% of their capacity. Changes in refining economics last year contributed to real contrasts in refinery utilization in some of the PADDs (see Overview chart).

Source: U.S. Energy Information Administration, Refinery Utilization and Capacity.

 Some key findings by PADD include:

• PADD 1. East Coast refining typically relies on imports of crude oil based on the Brent crude price, which, on average, increased to a $16-per-barrel premium over WTI spot prices in 2011. As a result, two East Coast refineries idled capacity due to poor economics, while another is considering selling or shutting down. PADD 1 utilization averaged only 68% of operable capacity in 2011, which includes the idle capacity of closed refineries. This utilization rate reflects both the drop in East Coast refining capacity and lower crude oil inputs.
• PADD 2. Midwest refineries benefitted from supplies of less expensive crude oil coming from Canada and increased production in the Bakken formation. Thus, PADD 2 refineries averaged about 91% utilization in 2011, even with increased refining capacity. As a result, PADD 2 average crude oil inputs of nearly 3.4 million barrels per day were at the highest level since 2000.
• PADD 3. Gulf Coast (PADD 3) continued capacity expansions as refineries upgraded infrastructure to maximize yields. Growing oil production in Texas and the Midwest contributed to increased inputs. The Gulf Coast refineries were able to use different types of crude oil to maximize production. Refineries in this region used cheaper sources of crude compared to the rest of the country.
• PADDs 4 and 5. Refinery closures, outages, and a lack of access to less expensive crude oil reduced inputs in 2011 to refineries in PADDs 4 and 5 and helped drive down utilization rates.

 

Musings: Did The Oil Sands Win Over Europeans With Report?

Last week the battle over the "dirty" oil from the oil sands reached a crescendo with the release of a study claiming that on a global scale, oil sands carbon emissions are not as bad as those that would be released by burning all the world's coal resources. Moreover, the study's conclusion shows oil sands emissions are actually less than those from other heavy crude oils being burned.

This report came merely days before a decision requiring greater environmental offsets for use of the fuel was to be rendered by the European Union (EU) Fuel Quality Directive Committee composed of experts from each of the 27 member countries of the EU. This committee was considering a proposal to revise the EU Fuel Quality Directive that has a mandatory target for fuel producers and suppliers to reduce greenhouse gas emissions (CO2) by 6% from 2010 levels by 2020.

The study's conclusion shows oil sands emissions are actually less than those from other heavy crude oils being burned.

While the proposal would not have banned the importation and use of oil sands bitumen, it would have assigned it a carbon footprint that is 23% greater than that of conventional crude oil. This would force users of oil sands bitumen to make significant improvements in their operations to offset the additional carbon emissions or buy green credits from others under the mandatory greenhouse gas reduction target.

For all practical purposes, the ruling would have been the equivalent of a ban. For Canada, this would be a problem as other governments around the world might use the EU determination as grounds to ban or restrict the use of this bitumen. That would shrink the markets available for this rapidly expanding output, with potentially significant implications for Canada's and Alberta's economy and employment.

The Committee failed to approve the policy as the vote was 89 for, 128 against with 128 abstentions. The Committee was using a qualified majority voting system that awards more votes to larger country members. Belgium, Germany, France, Cyprus, the Netherlands, Portugal and the U.K. all abstained. Had the proposal received 255 votes the ruling would have gone immediately into law. The proposal will now be considered in June by the Council of Europe, which is composed of the ministers from the 27 member countries in the EU.....Read the entire "Musings From the Oil Patch" article.

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Over One-Third of Natural Gas Produced in North Dakota is Flared or Otherwise Not Marketed

Source: U.S. Energy Information Administration, based on the North Dakota Department of Mineral Resources.

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Natural gas production in North Dakota has more than doubled since 2005, largely due to associated natural gas from the growing oil production in the Bakken shale formation. Gas production averaged over 485 million cubic feet per day (MMcfd) in September 2011, compared to the 2005 average of about 160 MMcfd.
However, due to insufficient natural gas pipeline capacity and processing facilities in the Bakken shale region, over 35% of North Dakota's natural gas production so far in 2011 has been flared or otherwise not marketed. (It is generally better to flare natural gas than to vent it into the atmosphere because natural gas—methane—is a much more powerful greenhouse gas than carbon dioxide.) The percentage of flared gas in North Dakota is considerably higher than the national average; in 2009, less than 1% of natural gas produced in the United States was vented or flared.

Natural gas production in the Bakken shale. North Dakota natural gas production from the Bakken shale, which is situated in the northwest portion of the State, increased more than 20-fold from 2007 to 2010, and the number of wells producing natural gas increased 7-fold.

Source: U.S. Energy Information Administration, based on the North Dakota Department of Mineral Resources.

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Natural gas infrastructure. The necessary natural gas infrastructure—gathering pipelines, processing plants, transportation pipelines—surrounding the Bakken shale play has not expanded at the same pace, effectively stranding the natural gas that is produced during oil production. A 2010 report by the North Dakota Pipeline Authority highlights an example of this, stating that one county was able to reduce its flaring from December 2008 to December 2009 by 62% with the addition of two new natural gas plants and the expansion of associated gas gathering systems. The report also details several other projects that have either come online recently or are planned to for the immediate future, which may reduce the amount of natural gas flared.

Natural gas flared or otherwise not marketed. The North Dakota Department of Mineral Resources estimated that in May 2011, nearly 36% of the natural gas produced did not make it to market. Most of this gas—29% of the total gas produced—was flared. The remaining natural gas that did not make it to market—7% of total gas produced—is unaccounted for or lost, which means the gas may have been used as lease and plant fuel, or encountered losses during processing or transportation.

Natural gas flaring regulations. According to current North Dakota state regulations, producers can flare natural gas for one year without paying taxes or royalties on it, and can ask for an extension on that period due to economic hardship of connecting the well to a natural gas pipeline. After one year, or when the extension runs out, producers can continue flaring but are responsible for the same taxes and royalties they would have paid if the natural gas went to market.

Toby Shute: 3 Oil Deals Shaking the Market

This week, I've spotted at least three billion dollar oil deals that should be of interest to investors (all this as of Tuesday!). Combined with other activity in recent weeks, this suggests that there's plenty more M&A mayhem to come as we approach the end of the year.

A big splash in the Gulf
First off, Energy XXI (Nasdaq: EXXI) agreed to pick up a bunch of ExxonMobil's (XOM) shallow water Gulf of Mexico properties for $1 billion. This follows similar moves by Apache (APA), which grabbed Devon Energy's (DVN) shallow Gulf assets for an identical sum, and McMoRan Exploration (NYSE: MMR), which picked up the pieces from Gulf dropout Plains Exploration & Production (PXP).

Energy XXI is picking up 66 million barrels of oil equivalent (Boe) of proved and probable reserves, and 20,000 Boe per day of production. The cash flow multiple paid is 3.2. Apache got more reserves with its purchase (83 million boe), slightly less production (19,000 boe/d), and paid 3.7 times estimated cash flow. In both cases, oil and natural gas production is split roughly 50/50, so I assume the lower Energy XXI cash flow multiple is largely a reflection of higher oil prices. Any way you slice it, the purchase price looks reasonable.

With this purchase, Energy XXI becomes the third largest oil producer on the Gulf of Mexico shelf, leapfrogging W&T Offshore (WTI) in terms of reserves, and both McMoRan and Stone Energy (SGY) in terms of production. The assets acquired have the potential to deliver around 720 million Boe at a development cost of around $15 per barrel.

That would be a really compelling figure, if a large component of that total resource potential was oil. The potential oil mix, surprisingly, is only around 10%, however, alongside 3.9 trillion cubic feet of gas. So the big upside appears to be in deep and ultradeep gas prospects, such as the ones Energy XXI is exploring in partnership with McMoRan elsewhere on the Gulf of Mexico shelf.

Incidentally, Exxon walked away from one of these ultradeep drilling projects a few years ago. This week's sale confirms that the company lacks an appetite for this activity. Given the likely difficulties in securing future permits to drill these extremely high-pressure wells, I can't really blame it. I'm a decided fan of wildcat drilling in the Gulf, but my preference is for companies sizing their bets more conservatively.

Yet another Bakken buy
Last week we saw Williams (WMB) make a $925 million purchase in prime Bakken territory up in North Dakota. This week, Hess (HES) edges it out with a $1.05 billion buy of privately held TRZ Energy. This follows closely on the heels of the company's acquisition of American Oil & Gas (AEZ) earlier this year.

The 167,000 acres acquired in this latest deal bring 4,400 barrels of daily production to the table. That's a pretty massive $238,600 per flowing barrel purchase price. At under $6,300 per acre, though, this purchase comes at a discount to those executed by Williams and Enerplus Resources Fund (NYSE: ERF). From what I can piece together, TRZ is active in Dunn and Williams County. You may recall that Dunn County is the location of Kodiak Oil & Gas' (AMEX: KOG) core development area. This should be very prospective acreage, suggesting that Hess may have gotten a great deal here.

Another Asian oil sands suitor
Over the past year or two, one of the most active players in the Canadian oil sands has been China. PetroChina (PTR) took a big stake in a pair of Athabasca Oil Sands' projects last September. More recently, Sinopec (SHI) snapped up ConocoPhillips' (COP) 9% stake in Syncrude, and a Chinese sovereign wealth fund snapped up a stake in some Penn West Energy Trust (NYSE: PWE) properties.

Showing that China isn't the only one salivating over the security of long term oil sands supply, Thai energy company PTTEP has also stepped forward. The company is picking up 40% of Statoil's (STO) Kai Kos Dehseh oil sands project for $2.3 billion. The entry looks low-risk, as first production is slated for early 2011.

Thanks to heady oil prices, the oil sands have made a roaring comeback since the dark days of 2008. As long as you believe that the world economy will continue to support $70 plus oil prices, the oil sands are indeed an interesting place for your money. Cenovus Energy (CVE) continues to be my favorite operator in that realm.


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Hess Extends Bakken Footprint with TRZ Energy Deal

Hess has agreed to acquire 167,000 net acres in the Bakken oil shale play in North Dakota from TRZ Energy for $1.05 billion in cash. The properties being acquired are located near Hess' existing acreage and have current net production of approximately 4,400 boe/d.

"This acquisition strengthens our leading land position in the Bakken, leverages our operating capabilities and infrastructure and will contribute to future reserve and production growth," said Greg Hill, President of Worldwide Exploration and Production at Hess. The transaction has an effective date of October 1, 2010 and is expected to close by December 28, 2010.

Posted courtesy of Rigzone.Com

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