There’s been too much production and unprecedented coronavirus-led demand destruction. Global storage capacity is also nearly full.

But the hurt is just getting started…

Price Update

In the exploration and production (E&P) space, cash flow is king.

If an E&P company isn’t pumping and selling crude oil, it doesn’t have cash coming in. And if that’s the case, it doesn’t have any choice but to close its doors.

And that’s exactly what an increasing number of E&P companies are doing. When oil briefly traded below $0 per barrel a few weeks ago, a number of big E&P operators like Whiting Petroleum Corp. (NYSE: WLL) threw in the towel.

Prices have since recovered and are now trading north of $20 per barrel. But for E&P companies, that price is still a nightmare.

No E&P company in the U.S. can turn a profit selling oil at these prices. You can’t “make it up on volume,” as the old saying goes.

The bankruptcies we’ve seen so far are likely just the tip of the iceberg. According to Rystad Energy, if oil continues to trade around $20 per barrel, as many as 533 U.S. E&P companies could go bankrupt by the end of next year.

And if oil starts trading in the teens, the number of bankruptcies could double. Essentially, any E&P company that has debt (and most E&P companies do) would be at risk.

As I write this, WTI and Brent crudes are trading at $25.51 and $29.92 per barrel, respectively. Prices are holding firm at the moment.

That’s because Saudi Arabia has agreed to cut an additional 1 million barrels per day (bpd) starting in June. At this point, June production from the oil kingdom looks like it will be 7.5 million bpd.

After the Saudis announced the additional cut, oil prices barely budged. Brent’s price initially increased 1%, but it quickly gave up those gains.

Prices are still down by more than 50% since January. Even Saudi Arabia is facing tremendous financial pressure.

It’s been actively campaigning to other members of OPEC+ to follow its lead and make additional voluntary production cuts. So far, the United Arab Emirates and Kuwait have agreed to additional cuts of 100,000 and 80,000 bpd, respectively.

False Hope

All of these cuts should eventually bolster prices, right?

Wrong.

The cuts are nowhere near enough. The demand destruction that occurred several months ago was nearly double the supply cuts.

We are starting to see some minimal demand resume as some countries gingerly begin returning to normal life.

Italy, South Korea, Singapore and a number of U.S. states have lifted stay-at-home orders. People are out and about again. And they’re buying gas for their cars.

But that may be another false hope.

In those countries and in many U.S. states, the coronavirus is returning and rearing its ugly head. This will create demand destruction all over again.

In the U.S., demand is just over half of what it was before all this started…
The overall problem in the oil patch remains one of overproduction. U.S. producers are still producing too much oil.

If they don’t pump, they don’t generate cash and they risk bankruptcy. If they do pump, they exacerbate an already difficult situation.

They are damned if they do and damned if they don’t. It’s a good reason for investors to steer clear.

Good investing,

Dave

The post Oil Demand Is Returning, but Prices Are Still Too Low appeared first on Investment U.

His administration gave Royal Dutch Shell (NYSE: RDS-A) conditional approval to drill for oil in the Arctic Ocean. (As a result, Shell’s stock quickly jumped 3%.)

The petroleum industry is lauding the decision as a major victory. Environmentalists are calling it a devastating blow. We’ll look at both sides in a minute.

First, let’s look at where – exactly – Shell has been approved to drill.

An Estimated 34 Billion Barrels of Crude

The Bureau of Ocean Energy Management said Shell can now begin its “multi-year Exploration Plan” in the remote, icy Chukchi Sea.

Nestled between Siberia and Alaska, with an area of 230,000 square miles, the Chukchi Sea is navigable only four months of the year.

Given the harsh conditions, not to mention our current relatively low-priced crude environment, you might wonder why American oil companies are so interested in drilling there.

Three reasons…

First: The Chukchi is shallow. More than 50% of it is less than 200 feet deep.

Second: The potential amount of crude oil located there. The Arctic, which includes both the Chukchi and Beaufort seas, is estimated to contain at least 20% of the world’s undiscovered crude oil and natural gas.

That equates to about 34 billion barrels of crude in the U.S. Arctic waters.

Third: Further energy security for the U.S. While we are currently enjoying a resurgence in oil production from shale fields, the Energy Information Administration (EIA) estimates total U.S. crude production will fall to 1 million barrels per day by 2040.

Only further development of U.S. offshore oil resources will avert that decline. And given how long it takes to explore and develop new offshore oil resources, the time to start is now.

Just consider…

Drilling in the Chukchi: Still a Long Way to Go

The recent Mars and Atlantis deepwater projects in the Gulf of Mexico took 11 and 12 years to develop, respectively.

Now imagine moving this same type of operation from warm, tropical waters to the cold, frigid environment of the Arctic. Setup times can (and do) double. Easily.

BP’s (NYSE: BP) Northstar, the only existing U.S. Arctic offshore project, took 22 years from lease sale to production startup.

The development meter on Shell’s proposed project in the Chukchi Sea is already seven years and counting. The company originally bid on and won the lease back in 2008. But achieving significant volumes of oil production will likely take 30 years or more.

One of the biggest problems is simply the remoteness of the region. Supply chains would be lengthy, and exploration seasons limited to four months of the year.

And when talking about offshore Arctic drilling, there’s one thing oil companies and environmental groups agree on: The Chukchi Sea is one of the world’s most dangerous places to drill for oil.

Potential for Catastrophe

An Arctic spill could be even more disastrous than the Deepwater Horizon disaster in 2010. Right now, the closest U.S. Coast Guard base is 1,000 miles away from where Shell is exploring.

There are no roads. The nearest deepwater port is hundreds of miles away. And those are just the obstacles in fair weather.

A winter spill would be even more catastrophic. During these months, major storms, frigid waters and 50-foot-high waves are common.

Oil trapped beneath the ice might migrate long distances. There would be virtually no way to clean up or contain the spill.

Those are all valid concerns, without question.

However, as I mentioned above, nearly all of the Arctic’s oil lies in relatively shallow water. The technology for drilling and producing oil in water less than 200 feet deep has been around for decades.

And the amount of oil we could potentially produce here may be too significant to pass up.

A Crucial Part of Our Economic Engine

Quoting the National Petroleum Council, “With a sustained level of leasing and exploration drilling activity over the next 15 years, offshore Alaska could yield material new production by the mid-2030s and sustain this level of production through mid-century and beyond.”

The EIA, in its 2014 Reference case outlook for U.S. crude production, notes that U.S. production will max out at 9.6 million barrels per day (MMb/d) in 2019. After that, it should decline to about 7.5 MMb/d in 2040.

That means the recent improvements in the U.S. economy – as a result of increased crude production – would reverse.

However, the EIA also prepared an alternative “High Resource case.” This assumes higher oil and gas resource development in Alaska. According to the report, the U.S. would be able to satisfy 85% of its total crude demand by 2040. But it would “require sustained exploration and development activity over the next two decades.”

I believe we will cut our use of oil and gas dramatically over the next 50 to 100 years, out of necessity. However, it’s currently a crucial part of our economic engine.

Long-term planning dictates we must start the development of our Arctic oil resources now. This is one of the most important issues in energy today.

Good investing,

Dave

*The views and opinions expressed in this article are those of the author and do not necessarily reflect the official position of Wall Street analysts.

The post The Pros and Cons of Arctic Oil Drilling (And Why We Should Start Now) appeared first on Investment U.

Fast-forward to 2007…

The technology of horizontal drilling and hydraulic fracturing opened up the potential of the Barnett Shale. With much of it underlying the city of Fort Worth, the Barnett has become a major source of natural gas.

If we’re talking Texas oil, the Eagle Ford has been in all the headlines.

But there’s a new Texas oil shale field that few analysts are even aware of. And one company is in very early… which means it stands to make a bundle.

We’ll get to who that is in a moment. But before we back up the truck, let’s take a look at how big Texas’ oil boom really is.

Texas: The Energy Capital of the World

The Lone Star state may be the second largest state in the Union, but it’s got more oil under it than any other. Take a look at the map below, courtesy of the Energy Information Administration (EIA). It shows some (but not all) of the shale plays in Texas and elsewhere in the United States.

There are at least 10 shale plays with production potential in Texas. Right now, only a few of them are being tapped. Even so, Texas oil production is on a tear, producing 2.139 million barrels a day last November. That breaks a 25-year record.

Can “Saudi Texas” Really Live Up to Its Name?

To begin to answer that question, let’s take a look at the second annual study done last March by the University of Texas-San Antonio (UTSA). It measured the economic impact Eagle Ford shale oil production has had on Texas.

In 2011, it found the total economic impact was $25 billion in the 20-county Eagle Ford area. It also indicated that the Eagle Ford supported 48,000 jobs in the oil and gas sectors. But take a look at the graph below, courtesy of the Railroad Commission of Texas.

Prior to 2011, Eagle Ford shale oil production was virtually nonexistent. Output really took off in 2011. Then it almost tripled from 2011 to 2012.

According to the latest UTSA study, the 2012 economic impact from the Eagle Ford was $61 billion. These incredible statistics made Eagle Ford the biggest oil and gas development on Earth last year.

Total number of oil and gas jobs now supported? 116,000. Many are in counties that only five years ago were seeing population declines.

There’s more to the story than just new jobs and cash inflows to the local economy, however. Last year’s tax revenues were off the charts. The Eagle Ford generated $1.2 billion in state tax revenues and more than $1 billion in municipal tax revenues. Talk about a windfall…

According to an article in Eagle Ford Shale, nearly $30 billion will be spent on continuing development of the Eagle Ford this year. So how much oil is in the Eagle Ford?

Complete development of the field will take decades. The U.S. Geological Survey (USGS) has estimated the Eagle Ford recoverable reserves at 10 billion barrels of oil.

To put that in perspective, that’s 2 1/2 times North Dakota’s Bakken shale. The USGS estimates the Bakken could hold 4.3 billion barrels. In the 15 months ending last November, Texas oil output increased by 654,000 barrels a day. That’s as much as all of the daily Bakken production.

Remember, we’ve just been talking about the economic impact from one of Texas’ numerous shale plays. As of May 10, Texas has 838 drill rigs turning. That’s more than half of all U.S. rigs, and over 20% of all rigs worldwide.

Let’s try to put Texas oil production in proper perspective by comparing it to North Dakota. It’s the No. 2 oil-producing state. Last November, “Saudi Texas” production dwarfed that of North Dakota. It pumped nearly three times as much oil.

This Play Could Easily Dwarf the Eagle Ford

According to an article in Forbes, “there are several studies that point to the Eagle Ford Shale eclipsing the East Texas Field as the biggest oil field ever discovered in the lower 48 states.”

The historic East Texas Field has produced over 5.2 billion barrels of oil since it was first discovered back in 1930. It’s thought to contain as much as 7 billion barrels. Many of its 30,340 wells are still actively producing today.

But in true Texas style, there’s yet another oil shale play that could make the Eagle Ford and the East Texas fields both look like small potatoes.

How big is it? Initial estimates are pointing to recoverable reserves of 30 billion barrels of oil.

The name of this up-and-coming play is the Cline Shale. Check out the map below.

Also known as the lower Wolfcamp, the Cline Shale is part of the much larger Permian Basin. So far, initial studies have shown the Cline to produce a light crude, very similar to that of the Eagle Ford.

The shale layer itself varies from 200 to 550 feet thick. It runs north to south and is roughly 140 by 70 miles in size. It covers a 10-county area just below the Texas Panhandle.

The Cline Shale is further east than the more heavily drilled areas near Midland, Texas. Greg Wortham is the mayor of Sweetwater, Texas. Sweetwater is a small town located about 250 miles northwest of Austin and 40 miles west of Abilene.

In an article in Statesman.com, Wortham – in typical Texas fashion – had this to say about the oil boom he foresees coming to Sweetwater: “It is coming, and it is big.”

According to Benjamin Shattuck, an industry analyst with Wood Mackenzie in Houston, the Cline has seen just 80-100 wells drilled so far. This makes available data sketchy at best. “Operators are doing their best to keep results confidential. The big thing in the Cline is that results so far have been good.”

One of the Cline’s Early-In Players

Devon Energy Corp (NYSE:DVN) is an independent oil and natural gas exploration and production company. The company operates in four important Midwest regions: the Rocky Mountains, Mid-Continent, Permian Basin and the Gulf Coast.

With regards to the Cline Shale, Devon has partnered with Sumitomo Corporation. In exchange for a 30% interest, Sumitomo has invested $1.4 billion in Devon’s activities in the Cline Shale. Devon holds the drilling rights on 650,000 acres.

Last year, the partnership drilled 40 wells in the Cline, with 28 of them in the second half. Right now, Devon has two rigs drilling in the Cline Shale. For 2013, Devon has an aggressive drilling program, with up to 140 wells planned for the Cline Shale.

In addition to operations in the Cline Shale, Devon has significant acreage positions in the above-mentioned regions. If the Cline turns out to be anywhere close in size to industry estimates, Devon will be in a great position to profit.

Investors wishing to capitalize on an early exposure to the Cline Shale might want to consider adding a few shares of Devon Energy to their portfolio.

Good Investing,

Dave

*The views and opinions expressed in this article are those of the author and do not necessarily reflect the official position of Wall Street analysts.

The post Cline Shale: The Newest, Hottest Shale Oil Play appeared first on Investment U.