Advanced Energy TrendWatch – Q2 2016

The Current State of the Crude Oil Industry

This past quarter has been an interesting one for the oil markets.

With oil prices hitting 11-year lows, U.S. E&P companies are, through no fault of their own, becoming the global crude swing suppliers.

However, the low-price gasoline debacle is going to be short-lived.

Let me explain…

U.S. production has been dropping ever since mid-February.

In mid-March, the combined number of U.S. rigs drilling for oil and gas hit the lowest level since at least 1948.

That’s according to Baker Hughes Inc. (NYSE: BHI), which began separately counting rigs drilling for oil and gas in late 1948. That’s a 68-year low.

Rigs drilling for oil dropped to 386, the lowest oil rig level since 2009. That’s 480 fewer than the 866 that were drilling in March 2015.

Active rig numbers are often viewed as a proxy for oil and gas industry activity, and numbers this low really put things into perspective.

And this isn’t the first time I’ve written about the coming crash in rig numbers.

But the bottom line is each operating rig represents a decision to drill a new gas or oil well. And lately, fewer companies want to pony up the $2.5 million drilling and $5 million to $6 million well-completion fees for a new horizontal well, regardless of how good the geology looks.

So there’s an excellent chance that we could set a few more all-time lows before this mess ends. And it will end.

The big question is, how violent will the reversal be?

Eventually, lower supply translates to higher prices. And that’s exactly what we’re starting to see right now.

The price of WTI crude is up nearly 50% from its 2016 lows. That’s a big jump, but it could jump even faster in the coming months.

Is the drop in rigs going to continue? As I said above, economics aren’t supportive of shelling out big chunks of capital for new wells.

Some of the E&P companies with operating wells are putting chokes on their wellheads. A choke is simply a smaller-diameter section of pipe that reduces the flow rate of the well.

Horizontally drilled and fracked wells have a very high (70% to 80%) first-year depletion rate. Choking or “throttling” back on well output evens out the depletion curve somewhat.

More importantly, it evens out cash flows. And right now, cash flows are what keeps E&P company CFOs up at night.

So yes, I think we’ll continue to see rig counts drop a little further. I don’t know how long this will be the case – and neither does anyone else. U.S. production will continue to drop until prices rise high enough to justify the economics of drilling.

U.S. production peaked during the week of January 15, 2016, at 9.235 million bpd. In early March, it actually rose by a mere 1,000 bpd. That’s just noise in the numbers.

In the 10 weeks ending on March 25, 2016, U.S. productiondropped by 213,000 bpd, to 9.022 million bpd.

Check out the production and supply graph (my favorite) below, courtesy of Ycharts.com. It clearly shows the peak in U.S. production.

While oil prices remain volatile, there are opportunities. The first company I’m adding is one of them.

This Company Is Profitable With $40 Crude

This is perhaps one of the top remaining E&P companies operating in the U.S. And it’s in a unique position.

It can drill and make money with oil selling for $40 per barrel and below. And it can do it for the next 10 years.

Why? Because it has 3,200 drilling locations that are profitable with oil below $40 per barrel. At its current rate of drilling, those locations will last it a decade.

As you can see from the graph, this company can even turn a profit with oil selling at $30 per barrel. However, its profits improve dramatically every time crude increases.

When prices rise, it has another 9,300 locations in its inventory that it can add to its drilling schedule. Those will be icing on its earnings cake.

This company has premium acreage in all of the top horizontal shale plays in the U.S. Since it was early to the shale party, it didn’t have to overpay for its acreage, either.

The company I’m talking about is one I’ve written about before. It’s EOG Resources Inc. (NYSE: EOG).

While 97% of its reserves are located in the U.S., EOG also has proven reserves in Canada, Trinidad, China and the United Kingdom. EOG’s top goal is “to be the most profitable independent exploration and production company in terms of return on capital employed.”

Those aren’t just empty words, either. Right now, with oil at $40 per barrel, EOG’s premium drilling locations generate an after-tax rate of return of at least 30%.

That’s impressive. It continues to grow its premium inventory at a rapid pace.

Once again, I’ll repeat what I call “Dave’s First Law: Technology marches on.” My law (it’s really just a proven fact) applies to drilling and fracking, just like it would to any other sector.

That’s what’s enabled EOG to improve existing plays. Innovation has allowed EOG drillers to precisely target the best lateral locations that will yield the greatest amount of oil.

In addition, well completions have benefited from new technology. The result is increased production for longer periods.

With oil prices as low as they are, preservation of capital is very important. So EOG set a goal to increase the productivity of the capital it’s deploying in 2016.

It plans to drill about 200 new wells and complete about 270 wells. It had 300 drilled but uncompleted wells in its inventory at the end of last year.

It expects to be utilizing 11 drill rigs in 2016. At the end of the year, it will have nine rigs remaining on contracts.

Its 2016 goal is to have its overall oil production decline just 5% year over year. However, it expects to be able to do that while spending 47% less capital than it did last year.

As you can see from the above graph, EOG isn’t just whistling Dixie when it talks about cutting capital expenditures. And look at how little its production has been affected.

There are few, if any, E&P companies that have reacted as quickly to the oil price downdraft as EOG has. That’s one of the reasons its outlook is excellent going forward.

It’s clear EOG is quickly figuring out how to become a low-cost oil producer. It’s doing this through the efficient deployment of capital – and, at the same time, it’s maintaining a strong balance sheet.

Building on a Record Year

It’s one thing to say you’re going to become a low-cost producer. It’s another thing to actually achieve it.

However, EOG recognized early last year it was going to have to become lean and mean. Last year, it reduced its capital spending by 44% compared to 2014’s spending.

Even more impressive, it maintained oil production at 2014 levels. On the exploration side, it identified more than six times the number of new well locations it drilled last year.

That turns out to be approximately 2,200 in the Permian Basin and about 960 in the Bakken. Those locations equate to an additional 1.6 billion barrels of oil equivalent of new resource potential.

In addition to adding new drilling locations, EOG acquired 34,000 new acres in the sweet spot of the Permian’s Delaware Basin. It accomplished all of this while keeping its capital spending below forecasted levels.

Focusing on costs has allowed EOG to become a low-cost operator. That gives it a big, sustainable competitive advantage.

Saudi Arabia’s not going to force this company out of business. That’s why I’m adding EOG Resources to the Advanced Energy Strategist portfolio.

Action to Take: Buy EOG Resources Inc. (NYSE: EOG) at market. Use a 30% trailing stop to protect your principal.

This E&P Company Is Operating Under the Marcellus

By now, nearly every energy investor who follows unconventional oil and gas has heard of the Marcellus Shale. It is truly a world-class unconventional deposit of shale gas.

Located in New York, Pennsylvania, West Virginia and Ohio, the Marcellus is being most actively drilled in Pennsylvania. It’s located roughly 5,000 feet below ground.

Two decades ago, geologists studying the Appalachian Basin’s oil and gas deposits were aware of the Marcellus. However, none of them thought twice about it as a commercial source of natural gas.

When wells were drilled through it, they produced a little gas, but nothing resembling commercial quantities.

What a difference a few decades and some new technology makes.

Now the Marcellus has gone from a “marginal” gas field to one that is producing nearly 25% of all the natural gas in the U.S. That translates into about 14.4 billion cubic feet of gas per day. So much for being a marginal source.

The Natural Gas Giant Below the Natural Gas Giant

However, it turns out there’s an even bigger gas field two miles beneath the Marcellus.

It’s called the Utica Shale.

Check out the map below, provided by the Energy Information Administration.

With an area of 170,000 square miles, the Utica Shale is nearly twice the size of the Marcellus. It stretches from Ontario all the way to Tennessee, through New York, Pennsylvania, Ohio, Maryland, Virginia and Kentucky.

Initially, few E&P companies paid any attention to the Utica. The Marcellus was much closer to the surface and it was loaded with natural gas. Why spend the extra money to drill down 14,000 feet to access the Utica Shale?

Well, it turns out the Utica isn’t that deep everywhere.

The map below shows the approximate elevation below sea level of the Utica Shale. In eastern Ohio, the Utica Shale rises and comes within 2,000 feet of the surface in some areas.

The thickness of the Utica varies from less than 100 feet to more than 500 feet. Throughout most of Ohio, the Utica Shale is from 200 to 400 feet thick.

The thing that makes a shale deposit worth exploiting is something called the total organic carbon content. The higher the TOC, the greater the correlation to oil and natural gas.

In eastern Ohio, the Utica has a TOC of greater than 3%. This indicates the shale in this area contains mostly natural gas.

In central and western Ohio, the Utica has a TOC of 2%, which is an indicator of mostly oil. Obviously, there are areas in between that contain both oil and natural gas.

The Little E&P Company That Gambled on the Utica

All this information was of great interest to a small E&P company called Gulfport Energy Corporation (Nasdaq: GPOR). Gulfport Energy is a small, independent E&P company located in Oklahoma City, Oklahoma.

Back in 2012, most E&P companies were focusing on the Marcellus. However, Gulfport began quietly acquiring Utica acreage in central and eastern Ohio.

The blue section in the map below shows Gulfport’s primary area of operation in Ohio. It presently has 243,000 acres.

Since Gulfport had early-mover advantage, it paid far less per acre than nearly all of its competitors. And it could pick and choose what it thought was the best acreage in the play.

As a result, the acreage Gulfport ended up with was within the fairways of the dry gas, wet gas and condensate windows of the Utica Shale. After doing some test drilling, Gulfport ultimately determined its proven reserves were 1.7 trillion cubic feet equivalent.

The U.S. Geological Survey estimates that the Utica holds up to 940 million barrels of oil and 38 trillion cubic feet of natural gas. The Ohio Geological Survey believes the oil content is much greater, estimating the Utica holds 8.2 billion barrels. It also thinks the gas component is less, at 15.7 Tcf.

Another early explorer in the Utica was Chesapeake Energy(NYSE: CHK). In 2011, Chesapeake management proclaimed the Utica Shale as “world class.”

It snapped up roughly 619,000 acres. However, Chesapeake’s acreage turned out to be far less productive than Gulfport Energy’s.

Today, the Utica’s natural gas production is 67% higher than the Bakken’s, according to the EIA. Its crude oil production is greater than the Marcellus’ crude oil production.

A number of other E&P companies piled into the Utica, snapping up acreage at prices four and five times what Gulfport paid. However, many companies soon realized the Utica geology was far more challenging than that of the Marcellus.

The first challenge is the greater depth, and that creates the second challenge. The Utica is a highly pressurized layer, much more so than the Marcellus.

The Marcellus has bottom pressures that average 4,000 psi. Bottom well pressures in the Utica are routinely greater than 10,000 psi.

Because of the higher pressures, more expensive wellhead equipment and drilling procedures are required in the Utica. Few companies wanted to make the extra investment and acquire the knowledge needed to drill the Utica.

With Chesapeake Energy dealing with major financial issues, Gulfport Energy gradually became the top producer in the Utica Shale. In conducting its fracking operations, Gulfport quickly learned that the Utica reacts much differently than the Marcellus.

However, Utica production rose quickly, and in 2015 the EIA began tracking its production as a separate play. Last year, the Utica was the only major shale play to increase both its natural gas and oil output.

Gulfport’s Current Operations

Gulfport is currently operating three drilling rigs on its Utica Shale acreage in Ohio. Last year, Gulfport’s average production from the Utica Shale was 548.2 million cubic feet per day (Mmcfepd).

In 2016, the company expects daily production will average 695 Mmcfepd to 730 Mmcfepd. The company’s proven reserves are roughly 91% gas, although that could change as Gulfport develops its acreage.

To support its 2016 drilling program, it expects to spend approximately $335 million to $375 million. Gulfport expects to grow 2016 production 27% to 33%.

One of the things that jumped out during my research of Gulfport was its conservative financial strategy. Like EOG, Gulfport has positioned itself to weather the current downturn in oil and gas prices.

It is able to fund its 2016 capital expenditures from its operating cash flows and its credit facility. Gulfport plans to deploy its capital in areas showing the highest potential returns.

Another thing I like about Gulfport is that it actively hedges some of its expected production at very attractive rates. Right now, the company has 76% of its estimated 2016 natural gas production hedged at $3.29 per million British thermal units.

It also has 347 Mmcfepd of 2017 production hedged at $3.07 per MMBtu.

As a general rule, Gulfport’s hedging target is 50% to 70% of its expected annual production. Another aspect of Gulfport’s strong balance sheet I like is it recently reaffirmed its capital borrowing cache of $700 million, which remains undrawn.

In 2016, Gulfport expects to drill between 21 and 24 new wells in the Utica Shale. It further expects to add between 36 and 39 wells to its growing production base.

Last year it increased its reserves by 83% year over year. There’s an excellent chance this top player in the Utica Shale could do it again. That’s why I’ve decided to add it to the Advanced Energy Strategist portfolio.

Action to Take: Buy Gulfport Energy Corporation (Nasdaq: GPOR) at market. Use a 30% trailing stop to protect your principal.

The Birth of a New E&P Company

Back in 2001, Paul Rady and Glen Warren had just sold their previous company, Pennaco Energy, to Marathon Oil Corporation (NYSE: MRO). They had built it into a highly successful coal-bed methane producer in the Powder River Basin.

Under Rady and Warren’s direction, Pennaco drilled more than 1,400 coal-bed methane wells.

Those wells produced more than 95 Mmcfepd of natural gas. During the two years that it traded as a public company, Pennaco was the top-performing E&P company in the U.S.

So when Rady and Warren decided to form their new company, no one was questioning their track record. The only question was, could they do it again?

Rady and Warren set up shop in Denver, Colorado. However, from the beginning, they set their sights on the Appalachian Basin.

They were betting that both the Marcellus and the Utica shales would yield world-class amounts of natural gas and crude oil. As it turns out, their instincts were right, and Antero Resources(NYSE: AR) was born.

Today, the company holds more than 422,000 acres in the southwestern fairway of the Marcellus Shale. In addition, it has more than 147,000 acres in the Utica Shale fairway.

The company is still run by its co-founders. Rady is chairman of the board and CEO, and Warren is president and CFO. The company currently has about 475 employees.

Antero Resources is the most active driller in the Marcellus Shale. Its Utica Shale wells are among the top-producing wells in the play.

As with the previous two companies in this report, Antero Resources has a highly sustainable business model. It holds a leading position in the lowest-cost basin in the U.S., the Marcellus.

Its production base is substantial, and Antero Resources has grown it annually. Like Gulfport, Antero Resources has large, long-term hedges on its production.

Antero Resources is selling nearly all of its production into favorable markets. And the company has more than $5 billion of liquidity, which is important in today’s low-price environment.

Those are the highlights. Now, let’s delve into Antero Resources in a little more detail. I mentioned it had a substantial and growing production base.

As of the end of 2015, Antero Resources grew its production to 1.493 billion cubic feet equivalent per day (Bcfe/d). That was a 48% jump from the end of 2014.

This year, the company expects to grow production 15%, to 1.715 Bcfe/d. For 2017, its targeted growth is 20% higher than 2016’s guidance.

Another thing that’s important, especially in today’s low-price environment, is low development costs. In 2015, Antero Resources cut its development costs by $0.88 per thousand cubic feet equivalent, a 10% reduction from the previous year’s costs.

However, Antero Resources thinks it can squeeze another 12% out of its costs in 2016. And between the Marcellus and the Utica, its geologists have identified 2,227 horizontal drilling locations with economics similar to those of its current wells.

I mentioned hedging, and Antero Resources has done very well in that department. In fact, it has the largest gas hedging position among U.S. E&P companies.

For 2015, it hedged 94% of its guidance at $4.43 per MMBtu. That equates to 1,316 billion Btu per day.

For 2016, the company has hedged 1,793 BBtu/d, which is approximately 100% of its guidance. However, it hedged it at an outstanding price of $3.94 per MMBtu, a 118% premium over today’s natural gas price of $1.81 per MMBtu.

For 2017, Antero Resources has once again hedged 100% of its target guidance (2,073 BBtu/d). Its hedged price is $3.57 per MMBtu. That’s a 97% premium over today’s price.

Antero’s Link Between Exploration and Production

As Antero Resources continued to grow at a rapid pace, it became necessary for it to develop midstream assets to support its exploding production. So Antero Resources formed Antero Midstream Partners L.P. (NYSE: AM).

Antero Midstream is a growth-oriented MLP. It is 67% owned by Antero Resources.

Its assets include compressor stations and a gathering pipeline network. These provide midstream services to Antero Resources.

Antero Midstream has long-term, fixed-fee contracts with its parent company. Most of its gathering network overlays Antero Resources’ wells in southwestern Pennsylvania, northwestern West Virginia and southern Ohio.

Antero Midstream currently pays a dividend of 4.04%. You may wonder why I haven’t chosen Antero Midstream instead of its parent company for the portfolio.

The answer is simple. The parent company, Antero Resources, will achieve faster growth as oil prices firm up.

Antero Midstream, while paying a dividend, will grow slower since it gets paid on the volume of gas and oil it moves, not the price.

Now, let’s delve into Antero Resources’ operations in the Marcellus and Utica shales.

World-Class Marcellus Development

As you can see in the map below, most of Antero Resources’ 422,000 leasehold acres are in southwest Pennsylvania and northern West Virginia. As an early-in player, the company was able to get great acreage, all in the southwestern fairway of the Marcellus.

Right now, Antero Resources is running seven rigs in West Virginia. In Q4 2015, its Marcellus well production averaged 1,051 Mmcfepd.

That production number includes about 33,750 bpd of crude oil and natural gas liquids. So far, Antero Resources has drilled and completed 433 horizontal wells in the Marcellus Shale.

All of Antero Resources’ Marcellus wells are online. The company is constructing additional gathering pipelines in Ritchie, Doddridge and Tyler counties in order to connect new wells to processing and connection facilities.

Antero Resources currently processes more than 1,900 Mmcfepd of rich gas from the Marcellus using MPLX L.P.’s (NYSE: MPLX) Sherwood processing complex. MPLX is a processing and gathering midstream MLP owned by Marathon Oil.

Drilling the “Core of the Core” in the Utica Shale

As you can see below, most of Antero Resources’ 147,000 leasehold acres are in a very small window of eastern Ohio. The company refers to this as the “core of the core” of the Utica Shale.

Antero Resources has more than 147,000 leasehold acres in the Utica Shale. Unlike the Marcellus, the Utica acreage covered by Antero Resources is focused in the rich gas/condensate window of the play.

The company is currently running three drill rigs in the Utica Shale. In Q4 2015, production from Utica wells averaged 446 Mmcfepd.

That includes about 21,000 bpd of natural gas liquids and crude oil. So far, Antero Resources has 109 drilled and completed horizontal wells in the Utica Shale.

All of its Utica wells are currently online.

Antero Resources has five plants, Seneca 1 through 5, all located in Noble County, Ohio. The last one, Seneca 5, went into service in mid-September of last year.

Pioneering Greener Drilling and Completion

For as long as E&P companies have used horizontal drilling and fracking, local residents have cast a wary eye on the process. Antero Resources has pioneered many industry-first green drilling and completion techniques.

Natural gas-fired generators power nearly all of Antero Resources’ drill rigs. Instead of moving 2,000 truckloads of water from one drill site to the next, Antero Midstream installs networks of water pipelines to move water from area to area.

When doing well completions, many completion crews release large quantities of methane (a greenhouse gas) into the atmosphere. Antero Resources’ completion is entirely green.

Its equipment eliminates methane emissions during flowback and well cleanup. This is done before each well is connected to the gathering network.

Antero Resources’ well completion equipment is also completely natural gas-powered. Its first natural gas-powered fleet began doing completions in July 2014.

Antero Resources currently has 30 natural gas vehicle trucks. It has plans to gradually convert its entire fleet to natural gas vehicles.

Since Antero Resources uses a lot of water during the completion process, it’s important for it to recycle as much as possible. During 2015, the company recycled more than 74% of well flowback water.

The company also uses a closed-loop mud system when drilling. This eliminates the large, open mud pit typically found at drill sites. It also allows for smaller drilling pads.

Protection of leaseholder property is paramount. After clearing and leveling a drill pad, protective linings and mats are used to reduce soil compaction and prevent contamination.

As you can see, Antero Resources is well-positioned to ride out the current low-price natural gas and crude oil environment. Even better, it’s ready to capitalize on higher prices, which I believe we’ll see later this year. That’s why I’m adding Antero Resources Corporation to the Advanced Energy Strategistportfolio.

Action to Take: Buy Antero Resources Corporation (NYSE: AR) at market. Use a 30% trailing stop to protect your principal.

Well, there you have it. I hope you enjoyed reading the latest edition of Advanced Energy TrendWatch. The three companies profiled above are poised to add to some of the gains we’re currently sitting on.

We’ll continue to track our new picks as well as the rest of the Advanced Energy Strategist portfolio stocks in our regular Advanced Energy Weekly.

Good investing,

David Fessler