The good news is that pullbacks offer tremendous opportunities in the form of outstanding values. One group that’s been particularly hard-hit in recent weeks despite a strong long-term fundamental backdrop is stocks levered to natural gas.

Many subscribers are familiar, at least in passing, with names such as the Barnett Shale, Bakken Shale and Marcellus. These are just three examples of promising, fast-growing unconventional oil and natural gas fields in the US that are generating tremendous returns for producers. I discussed some of these fields at length in the most recent issue of The Energy Strategist, The Natural Gas Boom.

I’ve recently outlined the longer-term bullish fundamental case for oil and natural gas prices in the past few issues. Going forward, the most important factor to watch isn’t the bullish news itself. Investors should pay particular attention to how the market reacts to that news. See Market View.

The development of onshore unconventional reservoirs has driven extraordinary growth in US gas production of late. These plays have been around for years, but they continue to make waves. I explore the technological innovation that enables unconventional gas production. See Unconventional Growth.

In this issue, I dig into six major unconventional shale plays in North America, detailing the major players in each and the prospects for growth. I remain convinced we’re just a few weeks away from a tremendous buying opportunity in gas-levered names. This issue offers my guide to some of the most promising trends and plays in the group. See Play by Play.

I take a closer look at the “granddaddy” of all US gas shale plays and outline the companies taking advantage of its offerings. See Barnett Shale.

Although the spotlight has shifted to other plays, I delve into the potential of the Marcellus Shale, which isn’t well understood. See Marcellus Shale.

Well-known as a successful US and Canadian play, production in the Bakken Shale has surged in the past few years. And it continued development ensures increased production for years to come. See Bakken Shale.

One of the most exciting unconventional plays, the Haynesville Shale—covered extensively in the last issue of TES—takes a backseat this time around. See Haynesville Shale.

A smaller, higher-cost shale, the Woodford Shale is a world-class gas play that’s getting plenty of attention from an oil giant. See Woodford Shale.

A highly developed play located in Arkansas and Oklahoma, the Fayetteville Shale plays an integral role in a larger gas-producing region called the Arkoma Basin. See Fayetteville Shale.

I’m recommending or reiterating my recommendation in the following stocks:

• Norfolk Southern (NYSE: NSC)
• Delta Air Lines (NYSE: DAL)
• EOG Resources (NYSE: EOG)
• Chesapeake Energy (NYSE: CHK)
• XTO Energy (NYSE: XTO)
• Quicksilver Resources (NYSE: KWK)
• Talisman Energy (NYSE: TLM)
• Petrohawk Energy (NYSE: HK)
• Southwestern Energy (NYSE: SWN)

I’m recommending holding or standing aside in the following stocks:

• Devon Energy (NYSE: DVN)
• Range Resources (NYSE: RRC)
• Continental Resources (NYSE: CLR)
• Newfield Exploration (NYSE: NFX)

Although Hurricane Gustav was no Katrina, the storm has shut in significant oil and natural gas production from the Gulf of Mexico, which disrupted refinery operations and resulted in the closure of a key import terminal. At the time of this writing, more than 7 billion cubic feet (bcf) per day of natural gas and 1.3 million barrels per day of crude oil production remain offline.

And even if there’s no damage found on offshore platforms and rigs, production is unlikely to rise to normal levels until sometime next week at the earliest.

This news is seemingly bullish for crude oil and natural gas, at least from a fundamental perspective. But, as I noted in the most recent issue of TES, the most important factor to watch isn’t the news itself but how the market reacts to that news; in this case, crude oil and gas have sold off sharply this week.

Traders have chosen to focus on the idea that Gustav wasn’t as bad as it could have been rather than the continued production outages. In addition, the presence of three additional named storms in the Atlantic Basin hasn’t offered any additional support.

I’ve outlined the longer-term bullish fundamental case for oil and natural gas prices in the past few issues of TES. Ultimately, the fundamentals will prevail, offering investors the best buying opportunity in the energy patch since early 2007. From its early 2007 lows to its 2008 highs, the Philadelphia Oil Services Index returned an impressive 100 percent. 

Nevertheless, in light of these reactions, I continue to believe that golden buying opportunity is still a few weeks away. There could well be some more short-term downside for both oil and natural gas.

My strategy for dealing with this downturn is the same as it’s been in dealing with prior pullbacks; long-term subscribers will remember several similar corrections over the past few years. First, there are always sectors performing well, even during weak markets for energy as a whole. For example, railroad Norfolk Southern and airliner Delta Air Lines have been performing well for us since recommendation earlier this summer.

In addition, some of my recommended Master Limited Partnerships (MLP) and closed-end MLP funds have begun to outperform other energy-oriented stocks lately. Many of these recommendations have been hit since the credit crunch began a little over a year ago; I’m beginning to see signs that investors are returning to the group as a safe-haven for high income. For example, note that the Alerian MLP Total Return Index is up 4.1 percent since July 15 compared to a 14 percent decline for the S&P 500 Energy Index. Although this is still a nascent recovery and hasn’t helped all MLPs, look for a more detailed analysis of the group in an upcoming issue of TES.

Finally, this correction is offering some outstanding values for those willing to hold through some near-term volatility. Over the past few issues, I’ve highlighted the services stocks such as Schlumberger and Weatherford. In the last issue, I also examined some select exploration and production (E&P) firms. And in this week’s issue, I’ll expand on that theme, offering more detail and specifics on one of the most exciting long-term trends I see developing in the North American market: the boom in unconventional US gas production.

In the most recent issue of TES, I highlighted the extraordinary growth in US gas production driven primarily by development of onshore, unconventional reservoirs. Simply put, these fields could make the US the world’s largest natural gas producer within five years.

For newer subscribers unfamiliar with unconventional reservoirs, I offer a detailed explanation in the Feb. 20, 2008, issue of TES, Growing Unconventionally.

Unconventional fields are really nothing new; producers have known about many of today’s hottest unconventional gas and oil plays for many decades. For example, the Barnett Shale of Texas is one of the largest and most developed unconventional shale reserves in the US. Production from the Barnett should hit 5 bcf per day next year, equivalent to roughly 8 percent of total US consumption.

But the Barnett Shale has been known to exist and to contain large quantities of natural gas since at least the 1970s and the first wells were drilled in the early ’80s. However, drilling technologies used at that time weren’t sufficiently advanced to produce economic quantities of gas from the play. According to the Oil & Gas Journal, there were only 82 wells drilled in the prolific Barnett as of 1990, nearly a decade after the first well was drilled.

Some pundits believed that the poor permeability of shale plays like the Barnett would render them impossible to produce economically. The Barnett was openly derided at this time.

But the development and widespread acceptance of three-dimensional seismic mapping, hydraulic fracturing and horizontal drilling have changed all that. Although only 82 wells were drilled in the Barnett by 1990, a total of 3,679 permits for Barnett wells were issued in 2007 alone; the Barnett, once derided as uneconomic, is now the second largest field in the US.

Three-dimensional (3D) seismic mapping–the use of sound and pressure waves to map underground rock formations–allows producers to delineate their fields more accurately. In addition, advanced seismic surveys enable firms to identify and locate natural fractures–cracks in reservoir rock–that can affect the way a particular field produces. A thorough understanding of underground rock formations is crucial for drilling the most productive wells possible in a particular field.

Horizontal drilling is a simple and largely self-explanatory concept. These are wells drilled sideways underground. Natural gas and oil don’t exist underground in some giant cavern or lake. Rather, hydrocarbons are found trapped in the pores and cracks of a reservoir rock. These rock formations lie in layers, and certainly not all layers contain economic quantities of oil or gas. For example, check out the geologic map of the Haynesville Shale region of Louisiana, a giant gas play I outlined in the most recent issue of TES.

This chart shows the layers of rock in one part of the Haynesville Shale play. As you can see, there are several geologic layers in this area; the further below the surface you move, the older the formation.

Let’s assume you drill a vertical well to produce the Haynesville Shale formation on this chart. A vertical well would pass directly through several of these layers. The only productive part of that well would be the part that passes through the Haynesville Shale. The productive layer is roughly 200 to 250 feet wide. Roughly 250 feet of the well would intersect the gas-bearing shale.

But imagine a horizontal well that travels vertically down to the Haynesville Shale and then sideways for a distance of 3,000 to 4,000 feet. This horizontal segment would be totally exposed to the productive region; a far longer length of the well would be exposed to gas-bearing rock. Although it’s more expensive to drill, it’s not hard to see why horizontal wells are more prolific producers.

The final technological innovation to enable unconventional gas production is the development of hydraulic fracturing techniques. Most unconventional plays have plenty of gas in place, but the reservoirs lack permeability. That means that there are pores and cracks within the reservoir rock that are holding gas or oil, but those pores aren’t well connected. Since the pores aren’t connected to one another, there’s no way for the gas to flow through the rock into a well.

Consider the following two images.

The first picture is a piece of sandstone. This is a common reservoir rock; in fact, most conventional oil and gas fields are made of sandstone. You can clearly see the large pores, holes and channels dotting this rock; this is why many sandstone reservoirs have good porosity–lots of pores to hold hydrocarbon–and permeability.

The second picture is a piece of shale. Notice how much denser this rock appears. This shale does contain pores though many of these pores are tiny or, in fact, can’t be seen at all with the human eye. As you can imagine, it’s harder for oil and natural gas to find its way out of such pores and through shale rock. Shale reservoirs are perhaps the most exciting unconventional gas plays in the US right now.

Hydraulic fracturing involves pumping a liquid into the reservoir under tremendous pressure; this actually cracks the rock, creating cracks for the gas to flow through the formation and into a well. In short, fracturing improves the permeability of the field. Typically, producers also introduce what’s known as proppant–typically sand, sand coated with resin or ceramic material–into the fracturing fluid. As the name suggests, the proppant actually enter the cracks caused by the fracturing and holds or “prop” those cracks open. This prevents the newly formed cracks from closing as soon as pressure is removed.

To give you an idea of the scale of a fracturing or “frac” job, it’s not unusual for liquid to be pumped into a well at pressures of 8,000 pounds per square inch or more. A frac job can involve pumping more than 5 million gallons of fresh water into a particular field.

Fracturing also isn’t a new technique; however, the technology and availability has improved greatly in just the past five to 10 years. Producers now routinely do multi-stage fracturing jobs and experiment with different techniques to determine which works best in a particular field.

Armed with these three basic techniques, producers are finding plenty of new unconventional drilling targets in both the US and Canada. These prolific plays have become a major growth driver for the exploration and production firms; companies with acreage in favorable locations can generate eye-popping growth. And unconventional plays are also a major growth driver for the services and drilling firms. Drilling many unconventional fields requires the use of advanced rigs and service techniques.

In the last issue of TES, I highlighted my short and intermediate term outlook for the oil and gas markets. In addition, I offered some detail about the unconventional Barnett and Haynesville Shale plays. But there are several other plays that are currently seeing plenty of activity by producers. A thorough understanding of these plays and the key players in each region is absolutely crucial to picking the winners of the North American natural gas boom.

In addition, don’t forget about crude oil. Some unconventional oil plays, such as the Bakken Shale, have received considerable attention in the popular press. These plays also hold promise for investors.

Here’s a rundown of a lengthy list of the major unconventional oil and gas plays in North America, the prospects for growth and the major and best-placed producers in each region.

Barnett Shale

As noted earlier, this is the “granddaddy” of all US gas shale plays. The Barnett Shale of Texas is among the most developed and well-understood unconventional gas plays in the US. As I noted earlier in today’s issue, the Barnett has been under production to some extend since the early ’80s; however, the pace of that development has clearly accelerated over the past few years. The chart below offers a closer look.

According to the Texas Railroad Commission (TRC), there are now more than 7,770 wells drilled in the Barnett Shale region of Texas and 3,679 drilling permits were issued in 2007 alone. In fact, in just the period from January through May of this year, the TRC issued 1,669 drilling permits; on an annualized basis, that works out to more than 4,000 permits for 2008. This compares to just 1,112 permits issued in 2002.

All that drilling activity is obviously bearing fruit. The chart above shows that production from the Barnett has ballooned from 28 bcf in 1997 to nearly 1.1 trillion cubic feet (tcf) last year. That’s a jump of nearly 40 times in just a decade. For the record, the TRC also estimates 345 bcf of production in the first quarter of this year; annualized that’s about 1.4 tcf or 3.85 bcf per day.

As I outlined above and in greater depth in the last issue of TES, most producers in the region estimate that Barnett production will soon hit a wall, topping out at 5 to 6 bcf per day. Most of the big producers in the area believe that peak rate of production will be sustainable until around 2012; after that, its quite possible production from the Barnett Shale will begin to decline.

Obviously, different firms have various estimates as to the quantity of gas that will ultimately be recoverable for Barnett. But an estimate of 30 to 50 tcf appears reasonable. Please note that this isn’t an estimate of the total amount of gas in the field but what will ultimately be able to be produced. This is a statistic called estimated ultimately recoverable (EUR) reserves.  With total US gas reserves estimated by BP at 211 tcf, this is a huge play.

The Barnett Shale is located in north-central Texas near the city of Fort Worth. Here are two maps showing the major counties in the Barnett area.

The first map shows the entirety of Texas with the counties with current producing wells in the Barnett shale highlighted in red. The second offers a close up on these counties. The active gas wells are shown in red, and drilling permits–mainly for gas–are shown in blue. The small green dots are oil wells.

It’s a bit tough to see some of the county names due to the preponderance of dots. But the most active counties would be Denton, Johnson, Tarrant and Wise Counties. I highlighted those four counties in a thick black line.

One thing to note here that also applies to other unconventional fields is that the Barnett is geographically widely spread; however, there’s a very well-defined “fairway” or sweet spot for the play. This is a key point because you will sometimes hear companies hype up their acreage position in a particular play, saying they’ve accumulated 100,000 acres in the Barnett. But that claim is fairly meaningless on its own. If those acres are all in Johnson or Tarrant County, it could well be a big deal. But if the firm has accumulated a bunch of acreage in Erath County on the south western edge of the play, it’s not as impressive.

To give you a rough idea of what I’m talking about, consider the following datapoints from major Barnett producer EOG Resources (NYSE: EOG). The company announced that it drilled five wells on Johnson and Tarrant Counties that offered an initial production rate (IP rate) of 6.1 million cubic feet (MMcf) to 9.2 MMcf per day. These would be considered impressive wells.

The company also drilled several wells in what it calls the “Western Counties.” In Erath County, EOG’s most impressive well offered an IP rate of 3 MMcf per day; on average, most operators have been reporting IP rates on Erath Country wells of around 1 mcf per day to 2 mcf per day. And in Hood County, its 25 wells averaged 1 mcf per day. This doesn’t mean that these western counties are worthless. However, they’re clearly not as valuable as acreage in the fairway of the Barnett.

Finally, note the green dots representing oil wells near the north end of the Barnett play. Surprisingly, I haven’t heard much talk about this play from the financial media, but EOG did mention it extensively in its recent quarterly call. At its northern reaches, the Barnett Shale becomes much shallower and actually produces oil.

Based on data from the TRC, here’s a table of the largest Barnett Shale producers and their production in terms of total bcf in the first quarter of this year. 

EOG Resources is already a recommendation in the TES Wildcatters Portfolio, and I’ve recommended or written extensively about XTO Energy (NYSE: XTO), Quicksilver Resources (NYSE: KWK) and Chesapeake Energy (NYSE: CHK) in past issues. Here’s a quick rundown of recent news and drilling projects from some of these firms relating to the Barnett Shale. 

Devon Energy (NYSE: DVN)–Devon is the largest operator in the Barnett Shale and drilled 189 new wells in the second quarter alone. In total, the company plans to finish 650 wells this year and is targeting 1.2 bcf per day in production from the play by yearend up from just under 1.1 bcf per day in the second quarter.

Devon was notably more upbeat on the Barnett than some of its competitors in the area. As I noted in last week’s issue, EOG, Chesapeake and others have stated that they expect overall Barnett production to peak out and plateau over the next few years as acreage in the core areas of the play are finally fully drilled. Devon, however, stated it doesn’t yet see evidence of Barnett growth ending until around the middle of the coming decade, though it does see growth slowing.

Specifically, Devon announced that it’s been trying some longer horizontal wells to try and boost production rates. The company reported some initial success, noting two Johnson County wells with 5.5 MMcf per day IP rates. Overall, the company believes it can boost production to as much as double the current level over the next few years.

Devon does have an excellent position in the Barnett. The company has identified about 7,500 potential drilling locations; many of these are in “fairway” counties of the play. At current drilling rates, that’s about a 10-year drilling inventory.

Overall, I like Devon and its position in the Barnett is one of its most attractive assets. However, I suspect management may be a bit optimistic about Barnett growth based on comments from other operators in the region. Also note that Devon is hardly a pure play on Barnett. The company produces both oil and gas and is a major player internationally and in deepwater. I track Devon Energy as a hold in the How They Rate coverage universe table for now.

EOG Resources–I highlighted some of EOG’s general comments regarding the Barnett in the most recent issue of TES.

EOG has had some problems with pipeline capacity in the Barnett. Basically, some of the pipelines it uses to ship gas out of Johnson county are experiencing high pressure. This is a fancy way of saying the pipelines are hitting maximum capacity. In addition, EOG is experiencing issues with natural gas liquid (NGL) pipeline capacity.

In its raw form, natural gas consists primarily of methane but also includes other hydrocarbons as well as impurities such as carbon dioxide. Many of these other hydrocarbons exist as liquids at surface pressures. Typically, these NGLs are stripped from the gas at processing facilities and can be sold separately. Since the prices of NGLs tend to be more related to crude than natural gas, NGLs can offer an important source of revenues. The problem for EOG is that it doesn’t have enough NGL pipeline capacity to strip and move all of the NGLs it produces along with its gas.

EOG believes the gas pipeline capacity problem will be resolved by October and the NGL problem sometime next year. This will hurt EOG’s Barnett gas production for the immediate future, however.

But there are no signs of problems with the actual wells EOG is drilling. As I noted earlier, the company’s Johnson Country wells produced some impressive IP rates.

EOG’s Barnett oil play is also compelling. EOG believes it’s secured most of the acreage associated with this play; the company noted that one major competitor tried to grab land in the area but couldn’t amass a significant stake because EOG had already grabbed many of the best locations. EOG noted that the player has since pulled out of the area.

Back in February, EOG stated it had drilled eight horizontal wells in the Barnett oil play; these wells produced 150 to 350 barrels of oil per day each along with about 500,000 to 1 MMcf of gas. Although that might not seem like a lot, 150- to 350-barrel-per-day wells would be considered huge on land in North America.

At any rate, EOG has been doing work there but isn’t ready to announce results. EOG plans to announce more details of this play in an upcoming call, likely the first quarter of 2009. EOG also expects Bakken oil to start adding to production in 2009, helping to offset a slowing of growth in its Barnett gas play.

EOG has a solid slate of acreage in the Barnett and the oil play in the northern Barnett could prove exciting; management stated it’s still extremely excited about the play, and I can’t imagine that the company would say that and then announce bad news on the Barnett Oil play. When you couple this with EOG’s position in the Bakken oil play (see below for more), the company is on course to generate significant growth in unconventional oil production in coming years. EOG Resources remains a buy recommendation in my Wildcatters Portfolio.

Chesapeake Energy–I highlighted Chesapeake at some length in the most recent issue of TES. See that issue for details on its Barnett play. Chesapeake rates a buy in “How They Rate,” and it ranks near the top of the list of companies I’m looking to add to the portfolio in the near future.

XTO Energy–XTO has been following an acquisition-centric strategy targeting some of the most promising unconventional plays in the US, including the Barnett Shale. So far, XTO has spent $10.6 billion on acquisitions in 2008 alone. Across all of its acreage, XTO expects to have 15 tcf in proven reserves by the end of this year and has a goal of doubling its reserves and production between now and the end of 2011.

Specifically, with reference to the Barnett, XTO has 280,000 acres under lease, roughly 155,000 of which are in the play’s fairway. Current production from the play stands at 600 MMcf per day, roughly 38 percent of XTO’s 1.6 bcf per day in total gas equivalent production.

Given its recent acquisitions in Barnett, XTO believes it can grow production in the region by 30 percent over the next few years. XTO has experience in the Barnett. The firm’s Barnett production has soared in recent years from less than 150 MMcf per day at the beginning of 2005.

XTO has seen some success generating growth by spacing wells on its core Barnett properties more closely together; there’s scope for XTO to do more downspacing in coming quarters. Some operators have expressed doubt as to how widely this strategy can be employed, but it does seem to have met with success for XTO, at least in some of its core acreage.

I certainly wouldn’t bet against XTO on the growth front; the company has a history of making acquisitions at favorable prices, going on to produce superior production growth. Like EOG, XTO has had some issues with pipeline takeaway capacity but it has been aggressively adding infrastructure and I don’t see it as a major limitation on growth.

We were stopped out of a position in XTO earlier this summer for a profit; in light of the recent pullback, XTO is looking attractive once again. Although its goal to double production looks aggressive, XTO does stand well placed to grow in the Barnett and several other high-potential unconventional plays I’ll detail later in this report. For now, XTO Energy rates a buy in my How They Rate coverage universe.

Quicksilver Resources–In terms of sheer production from Barnett, Quicksilver can’t compete with the likes of Devon, Chesapeake and XTO.

But Quicksilver has an enterprise value (the value of all outstanding stock and debt) of just more than $5 billion compared to $27 billion for EOG and $49 for Devon. Quicksilver is more leveraged to the Barnett than any of the other companies I’ve mentioned, with more than 40 percent of production coming from the region.

Quicksilver has been generating impressive growth in the Barnett area. About a year ago, the company sold some of its mature wells in Michigan and reinvested some of the proceeds into more aggressive development of Barnett acreage. That seems to have paid off as Quicksilver announced that production gains from its core Barnett properties have more than made up for the production it sold in Michigan.

In what Quicksilver calls the Fort Worth Basin (Barnett), the company reported year-over-year production growth of an astounding 121 percent. Even better, Quicksilver is producing a lot of extremely “wet” gas from its acreage. That means that some 35 percent of what it produces is NGLs rather than pure natural gas. Given sky-high oil prices, Quicksilver has been getting some high prices for its NGL sales.

For a long time, Quicksilver was a TES recommendation; I recommended selling earlier this year for a big profit because the stock had simply rallied too far, too fast and was trading at a significant valuation premium to other US natural gas producers. But in light of the recent swoon in Quicksilver stock, it’s once again looking like a good value. I’m upgrading Quicksilver Resources in the How They Rate portfolio from a hold to a buy.

The Marcellus Shale is located under a large section of the Northeast US and Appalachia. This play received considerable press attention and interest last spring, although the spotlight now seems to have shifted from the Marcellus to the Haynesville Shale of Louisiana and Texas.

Check out the map below for a closer look at the exact location of the Marcellus play.

This chart from the USGS shows the basic region covered by the Marcellus Shale, the area shaded in green in the chart. Although few associate Appalachia with hydrocarbons, that’s totally unfair; in fact, in 1859 Edwin L. Drake drilled the first commercial oil well in the US near Titusville, Pennsylvania. Many see Drake as the father of the modern oil age.

Appalachia is also home to a large number of conventional natural gas wells that have been in production for many years. For example, according to the Energy Information Administration (EIA), there are currently 49,750 producing gas wells in the state of Pennsylvania, up from 40,100 in 2001. Meanwhile, West Virginia has 53,003 producing gas wells, Virginia has 5,179 and New York has 5,985. This is hardly untapped territory. Together, these states produced 541 bcf of natural gas in the year 2006, the last year for which the EIA has reliable production data.

But this is primarily production from conventional reservoirs. The unconventional Marcellus Shale has even more potential. However, although the conventional wells in this region have been in production for many years, the Marcellus Shale is still a relatively unexplored region. That means that any estimates as to the potential of the play are less reliable than for the Barnett. This shale reservoir is simply not as well understood. However, a rough estimate of the gas ultimately recoverable from Marcellus is roughly 50 to 75 tcf. In terms of reserve potential, this would put the play on a par with the Barnett.

The problem is, of course, that reserves and production aren’t equivalent. The Marcellus Shale region is much more difficult from a producer’s standpoint than the Barnett. For one thing, much of this region is highly mountainous and rugged, making it tough to move equipment into place.

Another issue is water availability. As with the Barnett and most other unconventional plays, producers are using horizontal drilling and fracturing to produce in the Marcellus. You can’t use salt water to frac a well because it’s corrosive to well pipe, so producers need to use fresh water supplies. And as I noted earlier, a single frac job can consume millions of gallons of water. Getting access to fresh water supplies in the Marcellus area is a big problem, and local regulators are also worried about the potential for fracturing fluid to enter drinking water aquifers. Drilling in New York State Marcellus acres has come to a standstill; this is one of the main reasons.

Even more important is infrastructure. Although there’s some conventional oil and gas production in Appalachia, there just aren’t enough pipelines in many regions of Marcellus to handle all the production that could come from the play. In addition, obtaining right-of-ways for pipelines in more densely populous parts of Appalachia can be a big problem and/or very expensive.

And then there’s services and equipment. There just aren’t as many advanced drilling rigs and fracturing trucks available in the Appalachia region, making it tough for producers to ramp up their drilling activity.

The bottom line: the Marcellus Shale will be an important near-term catalyst for several producers. But most firms with acreage in the area seem to concur that the most meaningful production from Marcellus won’t occur until at least 2012-13 at the earliest.

One final point is worth noting: just as with Barnett, there does appear to be a sweet spot to the Marcellus Shale. Although the Marcellus area is huge, it appears that parts of Pennsylvania and West Virginia have the best potential.

Two big players in the Marcellus are Chesapeake Energy and Range Resources (NYSE: RRC). XTO Energy and Gushers Portfolio holding Talisman Energy (NYSE: TLM) both also have significant stakes. Here’s a quick take on the latest Marcellus news from Chesapeake and Range:

Chesapeake Energy–In its most recent conference call, Chesapeake noted that it’s drilled two horizontal wells in its Marcellus acreage. Both are located in West Virginia and had IP rates of 7 MMcf per day. Chesapeake believes that each well offers recoverable reserves of 11 bcf. From a pure economics standpoint, these two horizontal wells are prolific producers and offer a high return on investment. 

In total, Chesapeake has 1.6 million acres in the region, much of which is held under 10-year leases or held by production (HBP). HBP leases specify that the producer holds the mineral rights as long as a certain minimum quantity of gas is produced from the field. Therefore, by producing gas from conventional wells on Marcellus acreage, Chesapeake can maintain its leases until it’s ready to tackle the Marcellus and until infrastructure is available.

In its recent conference call, Chesapeake management stated, “We have plenty of time to work through the substantial challenges of developing this very promising play [Marcellus].” This suggests to me that, although the acreage Chesapeake controls is promising, Marcellus won’t be the first play the company drills.

Chesapeake has also announced it’s looking to sell a stake (up to about 25 percent) in its Marcellus acreage. This will allow it to monetize its huge, attractive acreage position immediately while maintaining a controlling interest in the play. This will also generate cash to fund further exploration and development work.

Range Resources–Range Resources is the leader in the Marcellus Shale play. The company has 1.4 million acres in the area, 850,000 of which are located near what would be considered the core or fairway of the play.

The company has drilled a total of 22 horizontal wells in the area since it started exploring back in 2006, well before most of the competition started sniffing around the Marcellus. The most recent seven horizontal wells Range has completed had an average IP rate of 4.9 MMcf per day and cost around $3 million to $4 million to drill. Range estimates that each well offers around 3 to 4 bcf of total recoverable gas reserves.

This makes them attractive wells by any measure. Range noted in its investor presentation that the internal rate of return for a Marcellus well is more than 80 percent, considerably higher then the return on a Barnett well. The real core of the Marcellus play appears to be the region of southwestern Pennsylvania and northwest West Virginia, where Range has a huge position.

In addition, Range typically earns a higher price for the gas it sells than producers in other regions of the country. That’s because the Marcellus Shale is located near the Northeast, a key gas-consuming region. Finally, gas from Marcellus is high in energy content.

But the most important point for Range is that they’ve done the most to alleviate Marcellus infrastructure problems. The company has secured significant water sources and disposal facilities; this will allow Range to undertake the large frac jobs necessary to complete Marcellus wells. And the producer has also been rapidly expanding its pipeline capacity; management believes that infrastructure will be less of an issue for Range than it is for other producers.

Marcellus production and drilling activity looks likely to pick up in 2009 as some of this infrastructure is completed. For now, I will track Range Resources as a hold in How They Rate. The company has some excellent reserves in the Marcellus, but the real catalyst for upside will come in 2009 as it kicks off a more aggressive drilling program; positive results should reignite interest in the Marcellus.

The Bakken Shale is an unconventional oil play located in North Dakota, Montana and across the Canadian border in Saskatchewan. The US side of the play offers thicker deposits of oil; however, the Bakken looks like a commercial play in Saskatchewan as well. Here’s a map of the US side of the Bakken from the US Geological Survey (USGS).

The USGS recently updated and vastly revised higher its estimates of the total amount of oil and gas in the Bakken play. These estimates are “risked,” meaning that the USGS believes that there’s a 95 percent chance of at least as much oil as they estimate being present. That also means that once producers start drilling the play more aggressively and collecting more data, it’s quite possible reserves will prove much higher. 

On that basis, the USGS estimates 3.7 billion barrels of oil, 1.85 bcf of gas and 148 million barrels of NGLs. To give you an idea of scale, BP estimates that the US has 29.4 billion barrels of proven oil reserves. If the USGS estimates are accurate then the Bakken would be one of the largest oil plays in the US. And some other estimates peg Bakken oil reserves at far higher levels. Some believe the play could contain north of 400 billion barrels.

But, as with any other reserve, what counts isn’t the amount of oil in the ground but how fast that oil can be produced. Don’t be fooled by hype that claims that the US can achieve full energy independence because of Bakken. It’s an impressive, high-potential play that will make investors a great deal of money in coming years, but it’s not a panacea.

Check out the chart of Montana and North Dakota’s combined oil production over the past several years.

As you can clearly see on this chart, combined Montana and North Dakota oil production appeared to be in a state of terminal decline toward the end of the ’90s. But the development of the Bakken play over the past few years has totally altered the picture; these two states are now producing 218,000 barrels of oil per day, surpassing the prior ’81 production peak. That production could surge more than 500,000 barrels per day over the next few years.

Granted, this level of oil production is small when you consider the US uses more than 20 million barrels of oil per day. But it can certainly be significant for producers with quality acreage in the Bakken. For a closer look at that issue, here’s a rundown of recent results from major producers in the Bakken unconventional oil play:

EOG Resources–Wildcatters Portfolio holding EOG Resources is one of the biggest players in the Bakken Shale and is investing heavily in the region. EOG has about 320,000 acres in the Bakken play, primarily in North Dakota. The company has a total of eight rigs operating, seven in the core fairway of the play and one prospecting some outlying areas. In total, EOG is looking to drill 80 wells this year and 100 in 2009.

In its second quarter conference call, EOG offered some more details on wells it’s drilling and what it sees for the play. The company mentioned one well drilled in the quarter that flowed at a peak rate of 3,744 barrels per day. Again, this may not seem like a big number, but it’s truly huge for an onshore US well; most US oil production is from extremely mature wells with declining production. Consider that more than 80 percent of US oil wells are so-called stripper wells, meaning they produce less than 15 barrels of oil per day.

All told, the average EOG Bakken well drilled in the first half of 2008 produced at an IP rate of 1,732 barrels per day. On average, each well offers about 850,000 barrels of reserves. These wells offered EOG a more than 100 percent return on its investment.

Most analysis of the Bakken you’ll read will discuss the Elm Coulee field in Montana as the core of the Bakken. But EOG’s stellar drilling results are in North Dakota’s Parshall field. EOG recently revised higher its reserves in this area from 50 million to 80 million barrels. It’s likely EOG will revise that estimate far higher in coming quarters as it accelerates drilling activity. The company is also experimenting with downspacing wells and drilling in some non-core regions. Early drilling results in non-core acreage suggests a highly economic play offering some 250,000 to 450,000 barrels of oil reserves per well drilled. The Bakken remains one of EOG’s most exciting fields and avenues of growth.

Continental Resources (NYSE: CLR)–Roughly 82 percent of Continental’s reserves and 76 percent of production come from unconventional reserves. The company is clearly investing heavily in the Bakken Shale play as it accounts for about 28 percent of its near $900 million 2008 capital spending plans. That’s the largest share of any play in Continental’s portfolio.

The company has about 529,000 acres in the Bakken, making it the largest single leaseholder in terms of total acres. In total, Continental produced more than 8,400 barrels oil per day in the second quarter from this region and has a total of 13 rigs operating; by yearend the producer has announced plans to ramp up to 16 operating rigs. This also makes Continental one of the most aggressive drillers in the region.

Although Continental does have more total acres than EOG, its well results haven’t been quite as impressive. The 13 wells completed in the first quarter of 2008 had an average IP of 455 barrels per day; in the second quarter, Continental’s 33 wells offered 513 barrels of oil per day. Although it’s not quite as high as EOG, these numbers remain impressive.

In addition, recent wells drilled in the Three Forks/Sanish region of the North Dakota Bakken have offered particularly impressive results, including one well with an IP rate over 1,250 barrels per day. This appears to be a promising area for future development.

And Continental is still prospecting different regions of its Barnett acreage and trying new techniques such as larger frac operations and well downspacing. Given the quality of the Bakken play, positive results from new drilling activity could easily be a catalyst for the stock later on this year. For now, I’m adding Continental to the How They Rate table as a hold recommendation.

XTO Energy—XTO has amassed roughly 450,000 acres in the Bakken Shale play, primarily via acquisitions completed over the past few quarters.

The company recently announced that it drilled one well with an initial production rate of 650 barrels per day, a respectable IP. XTO also noted in its recent conference call that a good deal of its acreage is located around the Three Forks/Sanish area that’s proven productive for Continental. It’s still the early days for XTO in the Bakken, but you have to give the company credit as it has a history of cost effectively producing unconventional reserves.

Talisman Energy (NYSE: TLM)–Gushers Portfolio recommendation Talisman offers a play on the Canadian side of the Bakken play. Back in May, Talisman offered a new strategy for investing in its North American unconventional reserves; this strategy was the result of a detailed review of operations undertaken by the new management team.

The company has about 340,000 acres in the Canadian Bakken Shale play. Talisman has drilled and tested just three horizontal wells in the region, all producing more than 200 barrels of crude oil per day. This is smaller than the numbers for the US producers, but that’s mainly because the Canadian side of this shale play isn’t as thick as the US side. The company claims that this is actually above average for the Canadian side of the play.

The company has announced plans to spend about $50 million to $60 million on drilling in the region both this year and next year. The company sees potential for a total of up to 200 wells and is targeting 800 to 900 barrels per day in production for 2008 and 2,900 to 3,000 barrels per day for 2009. That’s impressive growth.

I offered a detailed look at the Haynesville Shale in the most recent issue of TES. I won’t bore readers by repeating that entire analysis here. Suffice it to say that the Haynesville is one of the most exciting unconventional plays in North America today. I covered two of my favorite Haynesville plays in the last issue: Chesapeake and Gushers recommendation Petrohawk Energy (NYSE: HK).

The Woodford Shale is an unconventional gas play located in Oklahoma. Check out the map of the state below to see where the Woodford is centered.

The blue dots represent gas well completions in Woodford. You can clearly see the well-defined core of this play. The Woodford has been heavily developed and the largest producer in the region, Newfield Exploration (NYSE: NFX), estimates the current output from the field at about 400 MMcf per day, roughly a tenth of the amount that flows out of the Barnett.

Newfield also estimates that more than 600 horizontal wells have been drilled in the Woodford. The play’s total recoverable reserves are estimated at around 12 tcf.

The Woodford is sometimes derided as a higher-cost play. The numbers suggest there’s some truth to that. The key metric to watch here is finding and development (F&D) costs, which are a measure of the average cost of adding 1,000 cubic feet of gas reserves–or one barrel of oil equivalent (boe)–to a company’s proven reserves base through exploration and development activities.

According to Bloomberg data, Woodford-focused Newfield’s F&D costs averaged about $20/boe in 2007 compared to $10 for XTO Energy and $13 for EOG. But Newfield has said that it’s been pushing costs in the Woodford down, and based on management projections, it appears that Newfield’s costs will ultimately trend down toward levels more in line with the rest of the unconventional gas producers.

Furthermore, just because of its smaller size and higher costs, you shouldn’t assume that the Woodford is a useless or uneconomic play. Consider that integrated oil giant BP recently purchased 90,000 net acres of core Woodford Shale property from Chesapeake for $1.75 billion in cash. That works out to more than $20,000 an acre.

Granted, this isn’t exactly a huge acquisition for a company the size of BP. But an oil major like BP doesn’t get to be a true global giant by buying poor-quality reserves. Obviously, BP sees Woodford as a world-class gas play.

The most relevant firm to keep an eye on in the Woodford is Newfield. The company saw record production of 200 MMcf per day in the second quarter based on acreage it operates. On a net basis—factoring in Newfield’s partial ownership of some wells—the company produced about 131 MMcf of gas per day.

That means Newfield-operated wells account for about half of production from the Woodford. Newfield also operates a third of all wells in the region and has the largest presence in terms of total drilling rigs dedicated to the play.

Overall, production on properties Newfield operates is up an impressive 21 percent since the end of 2007. Management estimates that by yearend, production will jump a further 25 percent. And the company is accelerating its drilling plans longer term, planning to expand from a current 12 operating rigs to 24 over the next two to three years. I currently rate Newfield Exploration a hold in the How They Rate table.

The Fayetteville Shale is located primarily in Arkansas, spilling over into Oklahoma, and is a highly developed play. In 2008 alone, its estimated 1,000 wells will be drilled in the Fayetteville region. The play is part of a larger gas-producing region known as the Arkoma Basin; in addition to unconventional shale wells, parts of this Basin are amenable to conventional production techniques.

Industry participants suggest that current production from the Fayetteville Shale stands at roughly 750 MMcf per day. Chesapeake estimates that this play can grow 300 MMcf to 400 MMcf per day each year for the next few years. This would put the Fayetteville shale at about 1.5 bcf per day of production by 2011. This is significant growth.

Southwestern Energy (NYSE: SWN) is currently the leading producer in the Fayetteville play. The company holds 857,000 net acres in the play and the Fayetteville Shale accounts for roughly half of Southwestern’s total gas reserves and gas production.

Southwestern has rapidly ramped up its drilling activity in Fayetteville over the past few years. Back in the first quarter of 2007, the company drilled 58 wells; in the first quarter of this year, Southwestern drilled 75 wells. In the first half of 2008, the producer spent $739 million on exploration and production (E&P). Of that total, $547 million was spent on drilling or participating in 262 wells in the Fayetteville shale. On average, Southwestern has a stake of 75 percent in these wells. 

In addition, Southwestern has been focused on improving performance from its Fayetteville wells. The company has gradually increased the length of its laterals. The horizontal portion of the wells it’s drilling–from 2,100 feet in the first quarter of 2007 to more than 3,500 in the second quarter of this year. Also, Southwestern has been optimizing its frac jobs, doing more extensive fracs before it commences producing a well. The end result: The average IP rate of new wells has doubled to 2.5 MMcf per day since the beginning of 2007.

All told, Southwestern’s Fayetteville production has soared to 500 MMcf per day in July compared to 300 MMcf per day one year ago. Management is targeting total production for 2008 of between 181 bcf and 185 bcf, up from 113 bcf in 2007, an impressive 64 percent growth rate.

The Fayetteville seems to offer attractive economics, Southwestern’s F&D costs stood at about $15/boe last year, higher than XTO and EOG but lower than Newfield in the Woodford. In addition, the company has been steadily cutting well costs and is projecting a further drop in F&D costs for the full year this year. I will track Southwestern Energy as a buy in How They Rate.

In addition to Southwestern, Chesapeake and Petrohawk both have significant positions in the Fayetteville Shale. Although the Haynesville has been the focus of most analyst attention for both firms lately, that doesn’t mean the Fayetteville acreage is unattractive.

Gushers recommendation Petrohawk has 157,000 net acres in the heart of the Arkansas Fayetteville. The company has nine rigs in the region and is planning to add a tenth this quarter. The company has budgeted $395 million this year in Fayetteville, actually a larger amount than its $295 million capital spending target in the Haynesville.

Petrohawk seems to be drilling some nice wells in the region, including two wells it completed in the second quarter with IP rates near 3 MMcf per day. This statistic suggests Petrohawk isn’t sitting on second-tier acreage.

Fall is the perfect time to enjoy Washington, DC’s outdoor treasures and catch a glimpse of nature’s splendor. And this year you can enjoy the immediate aftermath of the Presidential election in the seat if the federal government.

Join me and my colleagues Neil George and Roger Conrad for the DC Money Show, Nov. 6-8, 2008, at The Wardman Park Marriott.

Go to www.moneyshow.com or call 800-970-4355 and refer to priority code 011361 to register as our guest.

We also have a special invitation for our readers. KCI Communications, Inc., is organizing an exciting 11-day investment cruise Dec. 1-12 through the Caribbean and Panama Canal. Participants will have the opportunity to meet and chat with my colleagues Roger Conrad, Gregg Early and Neil George.

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