Growing Unconventionally
Exploration and production (E&P) firms have been among the most successful recommendations in The Energy Strategist over the past year; my five pure-play E&Ps are up an average of nearly 50 percent since their initial recommendation. Ironically, firms focused on natural gas production have been among the best performers of all despite the fact that gas prices have lagged crude prices markedly.
I see continued strong performance ahead for the group. As I’ve outlined over the past few issues, natural gas prices have upside from current levels, thanks to a steadily improving inventory outlook.
I’ve been slowly adding exposure in natural gas leveraged names over the past few months. Because many independent E&Ps have more exposure to gas than oil, this will boost results even further.
In North America, the key to E&P performance is production growth, and the key to true, organic production growth is exposure to unconventional oil and natural gas reserves. Not only are these reserves prolific producers, but they also have low exploration risk and are cheap to produce using modern techniques.
Having recently highlighted integrated oils, I thought it appropriate to revisit exploration and production companies, given their relation to currently surging energy prices. See Exploration and Production.
The most important measure of E&P companies, strong production growth potential typically indicates an E&P company will handily outperform its peers. And unconventional production is the single most important source of natural gas in the US. See Production Growth.
There are three different types of unconventional gas reserves. Each is more difficult than simply drilling, but advanced techniques now make drilling such wells more efficient. See Going Unconventional.
Gas isn’t the only unconventional resource. Oil sands and shale oil are also popular with many resources domestically. Advanced technology has been an asset in this field as well. See Unconventional Oil.
Two other factors to consider when evaluating E&Ps are their cost structure and mix of oil and gas production. See Costs and Mix.
I hold several attractive E&P companies in the Wildcatters and Gushers portfolios. Here’s a rundown on each. See How to Play It.
I’m recommending or reiterating my recommendation in the following stocks:
But the E&P industry is also one of the most diverse in the energy patch. The major integrated oils, profiled in the Nov. 21, 2007, issue, Super Oil, have large E&P divisions; most integrated oil firms concentrate on developing reserves located outside North America or in the deepwater. These are typically large-scale, multi-year projects targeting significant oil and/or gas deposits.
In contrast, there are legions of smaller independent E&Ps located in the US, Canada, Europe and Australia. Traditionally, the independent E&Ps have focused on smaller reserves located closer to their home markets. But nowadays that’s an overgeneralization as many independent E&Ps have grown rapidly via acquisitions over the years; they’re now starting to enter markets that were traditionally dominated only by the major integrated oils.
This isn’t the first time I’ve highlighted the E&P business. In the Dec. 6, 2006, issue, Looking for Some Upside, I highlight some of the smaller North America-based E&Ps. And in the June 20, 2007, issue, Europe’s Gas, I took a closer look at a few select European E&P names.
Because I recently highlighted the integrated oils, I’ll concentrate on the independent E&Ps in this issue. The most important point to keep in mind is that, like the services and equipment names, stock selection is absolutely crucial when playing the E&P business.
E&Ps benefit directly from higher oil and gas prices through higher price realizations for the products they produce. But it’s a big mistake to assume that commodity prices are the sole factor to consider when analyzing the group.
For example, consider the three pure-play US-based E&Ps in the TES portfolios: EOG Resources, Quicksilver Resources and XTO Energy. All three have production profiles weighted in favor of natural gas, not crude oil.
As I noted in last week’s issue, the best measure of natural gas pricing in North America is the 12-month New York Mercantile Exchange (NYMEX) strip price. This is the average of the next 12 months’ worth of natural gas futures prices traded on the NYMEX.
Because most producers hedge at least part of their future production using futures, this is a good indicator of the prices they actually attain for their production over time. Check out the chart of the 12-month strip below.
Source: Bloomberg
It’s clear that the natural gas strip topped out in the fall of 2005. This was immediately in the aftermath of hurricanes Katrina and Rita when US gas production was temporarily curtailed.
If natural gas-focused E&Ps were completely reliant on commodity prices for growth and performance, these stocks would have performed poorly since gas topped out. But that’s completely incorrect. Check out the chart below.
Source: Bloomberg
I created an index using the three gas-focused E&Ps currently in the TES portfolios and plotted that index starting with a base value of 100 on the day natural gas prices topped out in 2005. As you can see, these stocks performed phenomenally well since that date; the index is higher by close to 50 percent, despite the fact that gas prices are still well under their 2005 highs.
The best-performing stock in the index was XTO Energy, up some 71.2 percent since gas peaked in 2005. The worst performer was EOG Resources, up a still-respectable 37 percent.
In comparison to these figures, the S&P 500 is up 20 percent including dividends since that same date, and the S&P 500 Energy Index is up 22 percent. So not only did the E&Ps perform well in a weak gas environment, they actually outperformed the broader market and energy sectors.
My point is that, although we can’t afford to ignore the commodity pricing environment when analyzing E&Ps, it’s far from the only determinant. There are three other key factors to keep an eye on in my view: production growth potential, production costs and the mix of oil and gas produced.
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Companies with stagnant production are entirely beholden to commodity prices. Their revenues will rise and fall with the price of oil or gas.
But firms that can grow their production steadily over time can make money even when commodity prices are falling. Rising production can keep sales and earnings growing as long as realized sales prices remain above production costs.
This is also a key metric that Wall Street watches. Historically, companies that exhibit strong production growth have handily outperformed the industry as a whole. Check out the chart below.
Source: Bloomberg
I’ve highlighted this chart before in TES. To create these three lines, I examined all 20 of the North America-focused E&P companies that make up the S&P Supercomposite E&P Index. I tossed out any stocks that haven’t been public for at least five years.
I then sorted the remaining universe by five-year production growth. The line labeled E&P Best represents the stock price performance for the three stocks with the highest production growth; the line E&P Worst represents the performance of the three stocks with the slowest production growth. Finally, I also included the overall S&P Supercomposite E&P Index for reference.
The trend here couldn’t be clearer. The E&P firms with the fastest production growth rose 580 percent over the past five years, compared to just 330 percent for the S&P E&P index and 150 percent for the slowest growers. Production growth is every bit as important as commodity prices when analyzing the E&P industry.
Of course, I constructed this chart with the benefit of hindsight. There’s no way to know for certain which E&Ps will show the best growth going forward. However, we can evaluate growth potential by looking at the location and quality of a firm’s reserves and their drilling plans.
When it comes to North America-focused E&P firms, the fastest-growing producers typically target one of a number of unconventional reserves. Broadly speaking, the term unconventional (or nonconventional) refers to any field that can’t be produced economically using traditional well technologies.
Unconventional gas production already makes up close to 40 percent of US gas output. And that number is only going to rise in the coming years. Check out the chart below for a closer look.
Source: Energy Information Administration (EIA)
This chart depicts US production broken down by source. The chart shows historical data going back to 2004 and projections out to 2030 from the Energy Information Administration’s (EIA) most recent report.
As you can see, not only is unconventional production the most important single source of gas in the US, it’s also one of the only sources that’s likely to show real growth in the coming years. And consider that as recently as 2000, conventional gas production was far higher than unconventional production. These reserves have come to dominate the US gas market.
Note also the other lines on the US production chart. The EIA projects conventional onshore production will fall at a slow but steady rate in coming years. Associated and dissolved gas—basically gas that’s produced alongside oil—is also likely to decline out to 2030. The agency projects that offshore growth is likely out to the middle of the coming decade as new deepwater projects come onstream; after that, production offshore is also slated to see a gradual decline.
Historically, the EIA and the Information Energy Agency (IEA) have been too conservative when it comes to estimating decline rates for wells. In other words, it’s likely that production from some of these conventional sources will fall a good deal more quickly than the chart suggests. That makes unconventional production even more important.
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Gas isn’t found in giant underground caverns, and oil isn’t located in giant rivers or lakes underground. Instead, hydrocarbons exist in the pores, cracks and crevices of underground rock formations.
The rock that holds the gas or oil is known as the reservoir rock. Sandstone is a classic example. Anyone who’s ever picked up a piece of sandstone knows that it’s composed of sand particles; typical sandstone is full of tiny pores. This makes it capable of holding large quantities of hydrocarbons.
But if the sandstone extends all the way to the surface of the Earth, there’s a problem: Gas will eventually be forced by underground pressures to the surface. The oil or gas wells would have, over time, simply seeped to the surface.
Natural gas (and oil) seeps are hardly uncommon. The first oil wells dug in Pennsylvania were found because of the presence of oil seeps. And the ancient Greeks understood gas seeps; the constant flame at the famed Oracle of Delphi was really powered by natural gas naturally seeping through the rocks.
But in some cases, the porous reservoir rock is covered by an impermeable cap rock, which prevents the hydrocarbons from seeping out of the reservoir rock. This is a classic hydrocarbon trap. To produce this sort of reserve, a producer only has to drill through the cap rock into the reservoir rock. The gas or oil under pressure then naturally flows into the wellbore and to the surface.
But things aren’t always that simple. Sometimes, the reservoir rock can be highly porous, with a large number of holes containing gas or oil. But that rock isn’t permeable; in other words, the pores aren’t well connected so gas or oil doesn’t flow easily into the wellbore when a well is dug.
An example of this is the tight sands gas deposits in the Rocky Mountains. Fields such as the San Juan Basin of New Mexico and Colorado and the Jonah fields in Wyoming are among the largest producing fields in the US today.
Historically, tight sands gas plays wouldn’t produce economically. Simple, vertical wells will see an initial rush of gas, but gas located further away from the wellbore can’t travel through the reservoir rock to the well. Therefore, although producers have known these fields existed for decades, they weren’t assumed to be economical to produce. Producers instead went after more standard gas plays that were cheaper to produce.
But newer technologies allow the production of such fields. There are really two key enabling technologies: horizontal/directional drilling techniques and fracturing.
Horizontal drilling is fairly intuitive. These are wells that are drilled sideways underground. The advantage of such a well is that a producer can expose more of it to the producing reservoir rock. This allows hydrocarbons to be produced more efficiently. Check out the chart below.
Source: Bloomberg
This chart shows the number of horizontal and directional wells drilled in the US as a percentage of total wells drilled. As you can clearly see, producers greatly stepped up their horizontal drilling activity starting in the mid- to late 1990s. In 1996, simple vertical wells accounted for close to 80 percent of all wells completed in the US. Now, that figure is closer to 50 percent, and within a few years, horizontal wells are likely to become the dominant technique.
Much of the growth in popularity of horizontal drilling is tied to the need to produce unconventional reservoirs more efficiently. Although horizontal drilling was once considered too expensive to be worthwhile, the decline of conventional fields is forcing a technology revolution in the oil patch. This will continue to power growth in unconventional production.
The second technique is fracturing. I’ve explained this service function at great length in TES on a few occasions, including the Nov. 7, 2007, issue, Coal and Services. I won’t bore longtime readers with another lengthy explanation.
Fracturing is a way of improving the permeability of reservoir rock. The procedure involves pumping a liquid mixture into the reservoir under extreme pressures, often exceeding 8,000 pounds per square inch. This literally cracks that rock and forms small channels for the oil or gas to flow through.
Fracturing can actually extend as far as 3,000 feet from the well. And producers also pump small grains of sand or more-advanced proppants to literally prop open these fissures and cracks. In this manner, once the pressure is removed, the cracks remain open.
Typically, using a combination of these techniques, producers can generate economic production from an unconventional well. To offer an idea of the difference these technologies make, consider that using traditional vertical technologies, a well could recover less than 10 percent of the natural gas in the reservoir because most of that gas was stranded in unconnected pores. Using horizontal drilling techniques and fracturing, producers can recover more than half the gas in place. That’s a phenomenal improvement.
Tight sands deposits consist of an impermeable sandstone reservoir that won’t produce economically until fractured. Gas shale reservoirs are similar. Shale is one of the most common rocks in the world; it looks like a chalkboard in its natural state.
Traditionally, shale isn’t considered a reservoir rock. Because of its impermeability, it often acts as a trap or cap rock for hydrocarbons.
But that isn’t always the case. There are shale reservoirs around the world that contain vast quantities of natural gas (or oil). Typically, the gas is found trapped in small pores of the rock or adsorbed to organic material in the shale. The term adsorbed is different to absorbed; it means that the gas adheres to the organic material.
Just as with tight gas, shale reservoirs can be produced using a combination of fracturing and horizontal drilling techniques. The best-known shale gas reservoir in the US right now is the Barnett Shale, located around Fort Worth, Texas.
However, there are several other potentially hot shale plays. And outside the US, there are also many potentially viable shale gas plays that may be exploited in coming years using the more advanced technologies available today.
CBM wells are a bit different. The natural gas in such wells is found adsorbed to underground coal reservoirs.
Typically, CBM gas is found adsorbed to coal in the presence of water. To produce the gas, the seam is first dewatered by pumping the water out of the coal. This process reduces the pressure in the reservoir and frees the methane gas, allowing for production. The best-known location for CBM gas would be the US Powder River Basin, home to the nation’s largest coal deposits.
The beauty of unconventional reserves is their size and predictability. Many of the hottest unconventional reserves in the US are known as resource plays—widely distributed deposits that have little or no exploration risk. Producers with access to acreage can focus on drilling wells into known deposits and producing the gas.
The focus for many is on drilling wells closer together to produce more of the gas in place and improving the efficiency of their fracturing jobs to boost recovery rates. Also, over time, producers have become far more efficient in drilling wells, allowing more wells to be drilled in a given time period.
Overall, the potential size of US unconventional reserves is huge. Most estimate total producible reserves at 500 trillion to 1,000 trillion cubic feet. Given the size of these resources, their low exploration risk and improving technology, I prefer to focus on US and Canadian E&P firms with access or exposure to unconventional reserves.
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Oil sands are nothing more than a solid hydrocarbon known as bitumen that’s mixed with sand, dirt and water. This bitumen can be processed into refined products just like oil.
There are really two main production methods: strip mining and in-situ production. Strip mining involves simply scooping large quantities of oil sands and heating them to remove the bitumen from debris. This is practical only for oil sands resources located reasonably close to the surface.
In-situ mining is used to produce oil sands located further under the surface. One common sort of in-situ mining is known as Steam Assisted Gravity Drainage (SAGD). In SAGD, producers drill two horizontal wells.
Into one well, the producer pumped superheated steam that literally melts the bitumen from the sands. As the bitumen melts, it flows (via gravity) to the lower horizontal well and can be pumped to the surface. It’s estimated that roughly 80 percent of Canada’s oil sands reserves are located too far under the surface to be produced via strip mining.
The oil sands are a classic resource play—widely distributed with little exploration risk. For surface mining operations, the largest costs are upfront.
Most surface mining operations underway or planned in Canada also call for building and running an upgrader. Because mining operations tend to be larger scale and produce more daily output, it makes economic sense to also pay for an upgrader to process the bitumen into synthetic crude oil. The synthetic oil can be sold to refiners just like light sweet crude, the highest-value product in the marketplace.
In-situ projects tend to be smaller. Although some larger projects do have upgraders, that’s not often the case. This presents two problems.
First, the producer has to find a source of natural gas liquids or synthetic crude oil to use as a diluent; basically, the producer has to mix the bitumen with other products so it will flow through a pipeline. Second, the final product is bitumen, which is priced more like heavy oil than light sweet crude.
Not all refineries have upgraders and facilities designed to handle heavy crude. Bitumen is trading at a large discount to light sweet crude oil or synthetic crude. The advantage of an in-situ operation is that the upfront costs of developing are lower because you don’t need to pay for an expensive upgrader.
Operational costs are another big issue for the sands. In in-situ operations, steam is used to heat the bitumen so it can flow into a well. The problem is most steam is produced using natural gas. Producing steam is an energy-intensive process; producing in-situ oil sands requires a large amount of natural gas.
Although surface mining operations don’t use steam to heat the bitumen for mining purposes, it’s often used to separate bitumen from sand. And natural gas is an important commodity for many upgraders. Hydrogen produced from natural gas, for example, is used to turn bitumen into synthetic crude.
Producing a barrel of crude can require moving two tons of sands. The fuel to power the giant earth-moving equipment used in such operations is diesel. Obviously diesel and natural gas prices are an operational cost.
According to the Canadian Association of Petroleum Producers (CAPP), the oil sands industry consumed some 500 cubic feet of natural gas per barrel of oil sands production in 2005. Given that current production is around 1.1 million barrels per day, that equates to some 550 million cubic feet of natural gas used per day, or 6.5 percent of Canadian natural gas demand. But if production expands to 3.6 million barrels per day as forecast, gas use would jump to more than 1.8 billion cubic feet per day.
Although all these costs and considerations are relevant, most estimates suggest that oil sands production is profitable as long as oil prices remain above $30 to $40 per barrel, depending on the project. And oil sands production is the only source of Canadian production that’s set to actually grow in coming years. Check out the chart “Canadian Oil Sands Production.”
Source: EIA
This chart shows historical Canadian oil sands production going back to 1990 and projections out to 2030. The EIA estimates that production will climb from about 1.1 million barrels per day at this time to roughly triple that level by 2030.
This is one of the fastest rates of production growth for any resource in the world; access to potential oil sands production is an attractive opportunity for E&P firms. This interest is also apparent from the chart below.
Source: CAPP
This chart shows total spending on oil sands developments from 1999 through 2006. It’s clear that producers are taking oil sands seriously: Spending has jumped nearly sixfold since 1999.
But oil sands aren’t the only unconventional resource. All too often, investors confuse oil shale with shale oil. Oil shale is a resource similar in many ways to oil sands.
Basically, a heavy oil product attached to rocks and sand. It’s possible to remove bitumen from oil shale, and the US has a large amount of this resource. However, oil shale has less water in it than oil sands. Therefore, it takes far more energy to produce oil shale and separate the bitumen than oil sands. This makes it more expensive.
The world’s major oil producers have targeted oil shale in the past. I’m quite sure they’ll seek out production of this reserve in the future as well. But it will require oil prices to remain elevated for a prolonged period. The last oil shale boom occurred in the early ’80s and ended as oil prices dropped to levels that made production uneconomical.
Shale oil is a different resource entirely. Basically, like natural gas, some oil is trapped in impermeable or weakly permeable reservoirs. Like gas, this oil can be produced using horizontal drilling techniques and fracturing. A classic example of this resource is the Bakken shale play that encompasses parts of North Dakota, South Dakota, Montana and the Canadian provinces of Saskatchewan and Manitoba.
The Bakken reservoir has been known for many years. However, just as with shale gas, it’s tough to produce using conventional technologies; the shale is only weakly permeable.
In addition, traditional drilling mud can actually cause the shale to swell and close off the natural fractures and channels in the rock, permanently ruining the well. But this reserve is thought to hold several billion barrels of potential oil reserves, and the resource is widely distributed.
Not surprising, the Bakken has become a hot area for drilling activity. With production ramping up quickly, it’s clear that shale oil, such as that from the Bakken reservoir, is an attractive resource for producers.
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The F&D cost is a measure of how much it costs a firm to add one barrel of oil equivalent to its proven reserves via actual exploration and development work. This measure doesn’t include the costs of acquisitions but actual organic reserve development.
The table of E&Ps below lists each firm’s F&D costs. Most E&Ps only report this figure annually; for most of the E&Ps in the table, the reported F&D cost is for 2006, not 2007.
Although you can never generalize, companies with access to attractive unconventional reserve acreage tend to look favorable on an F&D basis as well. Consider longtime favorite Wildcatters Portfolio member EOG Resources. The main attraction of this firm is its position in the fast-growing Barnett and Bakken shale plays; EOG was one of the first E&Ps to seriously target these unconventional reserves.
But in addition to these fast-growing plays, EOG also has some conventional wells located in Canada. In its fourth quarter and full-year 2007 earnings release, the firm reported total US F&D costs of $1.90 per thousand cubic feet equivalent. But for EOG’s conventional Canadian reserves the F&D cost was closer to $6.25 per thousand cubic feet.
It should come as little surprise that EOG is focusing its development operations on the US. This also illustrates the major cost advantages that some unconventional reserves offer.
Finally, you should evaluate an E&P’s relative exposure to oil and natural gas. Many of the E&Ps in the table below are gas-levered; however, that’s not always the case.
EOG, for example, plans to grow its liquids production at a far faster pace than gas in the coming years. The firm will be considerably more balanced in terms of oil and gas mix in coming years. Other E&Ps such as Denbury Resources and Suncor are heavily leveraged to oil.
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Under generally accepted accounting principles (GAAP), a producer must account for all oil and gas hedges by marking them to a fair market value each quarter. Because companies like EOG often hedge a portion of their production years into the future, that means marking several years’ worth of futures prices to a current market value each quarter. This is purely a paper profit or paper loss, not an actual cash flow.
This makes no logical sense. Producers hedge a portion of their production so that they’re able to lock in a fixed price for oil or gas they’ll produce at some time in the future. A more meaningful way to account for hedges is to account for only the hedges that expire in a given quarter.
On that basis, EOG earned $1.29 in the fourth quarter, considerably above the $1.05 to $1.10 that most analysts had predicted. The stock reacted favorably to the release.
Historically, EOG has been mainly a natural gas play. It’s most-exciting, fast-growing gas reservoir is the Barnett Shale play I outlined above. The company continues to see strong growth from Barnett; production averaged 284 million cubic feet equivalent per day from the region in 2007 and exited the year at a run rate of about 375 million.
For 2008, EOG is expecting average production of 470 million cubic feet per day, up from its prior estimates of 450 million. In addition, management indicated that it sees gas production from its Barnett play continuing to grow through at least 2010.
EOG is now producing more aggressively from the western side of the Barnett region. But production rates from this side of the field appear to be more or less in line with what the company saw from more core areas. Even better, EOG stated that it’s seeing much higher natural gas liquids (NGL) production from the western Barnett.
NGLs include a number of liquid products that exist with the gas naturally in the reservoir. NGL prices typically follow the price of oil at least directionally; given current attractive oil prices, rising NGLs production is another benefit for EOG. Higher NGL content in the western Barnett is driving EOG’s expectations for 40 percent year-over-year growth in NGL production.
And although Barnett remains solid, perhaps EOG’s most-exciting opportunity right now is in its Bakken shale play in North Dakota. The Bakken is primarily an oil play; EOG has estimated its total share of reserves at about 80 million barrels in the region. The company’s actual proved reserves at year-end stood at about 21 million barrels.
EOG’s production from the Bakken is only just ramping up, and management expects 38 percent year-over-year growth in oil production for 2008 and continued elevated growth for 2009 and 2010 driven by production from Bakken.
At this time, EOG has only 24 producing wells on its Bakken properties and more than 175,000 acres worth of land in the region. Wells are spaced at 640 acres, which is considered a wide well spacing for most oil plays.
Results from EOG’s first wells have been solid: They’re producing around 1,700 barrels of oil per day at initial production. Although that may not sound like a lot, wells generating that much production are highly unusual in the US. Now EOG is experimenting with spacing wells closer together and drilling wells near existing producers to try to establish the size and limits of the fields.
As the firm completes this drilling work, I expect its estimates of total reserves and production growth to gradually move higher. Management sounded conservative on the earnings conference call. I expect that conservatism is partly due to the fact that EOG has scheduled a lengthy analyst meeting for Feb. 28 and plans to offer greater details in that call.
In addition, EOG is still buying up drilling rights to acreage in the region, so it may not want to give away details of exactly where it’s drilling for fear of tipping its hands.
Overall, EOG should have little trouble meeting its 15 percent year-over-year production growth target for 2008. Most of that growth will come from EOG’s unconventional plays, while operations in Canada, Trinidad and the UK will likely see flat year-over-year production.
The company benefits from exposure to two of the hottest unconventional plays and a production profile that’s becoming increasingly more balanced between gas and oil. I’m raising my buy price for EOG Resources to 105.
Wildcatters Portfolio holding XTO Energy is an unconventional gas-focused E&P. The company recently reported 30 percent year-over-year growth in production for the fourth quarter over the same quarter in 2006. Of that 30 percent, roughly 14 percent came from actual exploration and development, while the remainder came via acquisitions.
What’s really impressive about XTO from a pure numbers perspective is its F&D costs. On an organic basis–excluding acquisitions–XTO’s F&D costs stand at just $1.36 per thousand cubic feet compared to an average of roughly $3 for gas-focused E&Ps.
Like EOG, XTO has a strong position in the Barnett Shale play; XTO reported growth of 25 percent over the same quarter last year from Barnett. The company is relatively new to that region, entering Barnett only in 2004. But production growth has remained consistent since it started producing from the region, and XTO now has an impressive 250,000-acre position in the core of this hot region.
In addition, XTO has operations in unconventional plays in the Rockies as well as some newer up-and-coming gas shale plays, such as the Woodford and Fayetteville shales in Oklahoma and Arkansas, respectively. In the Woodford Shale, XTO drilled 12 wells last tear and is looking to drill 40 to 50 in 2008. That’s a significant step up in activity that indicates XTO sees plenty of potential from this play.
Management noted in its conference call that each well costs $4.5 million to $5 million and contains about 3 billion cubic feet of natural reserves. Costs are falling, and reserves are rising as XTO gains experience with wells in the region.
This is the same thing that XTO managed with Barnett. As the company gained experience drilling in the region, XTO was able to cut the time needed to drill a well in Barnett from 30 days to around 20 days. By cutting costs and improving efficiency, XTO is able to accelerate production at a low cost. This is the reason for its extraordinarily low F&D costs.
XTO, like EOG, has room to grow simply by drilling more wells on existing high-quality properties. The only real limitation management has found to growth in these regions is a lack of pipeline and processing capacity to handle all the gas produced. But XTO is moving ahead on schedule with expansion projects that will alleviate those bottlenecks.
XTO has also been an aggressive acquirer in recent years. In 2007, XTO bought up significant reserves from Dominion Energy. These reserves represent a diverse mixture of plays, but by drilling more aggressively, XTO should be able to boost production. Because Dominion is primarily an electric utility, the firm didn’t spend enough cash to fully develop its properties; XTO will be able to generate significantly more growth from these assets.
Although XTO is among the most expensive E&Ps in the table above, it’s consistently delivered strong production growth and one of the lower F&D costs of any North American E&P. I’m boosting my buy target for XTO Energy; the stock rates a buy under 65.
Gushers Portfolio holding Quicksilver Resources hasn’t reported fourth quarter results; earnings are scheduled for release on Feb. 26. However, the firm did offer an update on reserves and production earlier this month. Reserves were flat year-over-year, but that doesn’t adjust for the fact that Quicksilver divested some 550 billion cubic feet of its slower-growing gas reserves earlier this year.
With that adjustment, Quicksilver’s reserves soared more than 35 percent. And production for the year was up a respectable 27 percent on total F&D costs of just $1.38 per thousand cubic feet, among the cheapest F&D costs of any US E&P.
I expect to see strong production growth from Quicksilver’s Barnett Shale play when it reports later this month; Barnett Shale makes up roughly 80 percent of Quicksilver’s current reserve base. The company’s deal to sell off slower-growing fields in Michigan to master limited partnership BreitBurn Energy Partners last fall was a major positive.
Quicksilver’s Barnett acreage offers more growth opportunities, and by selling off slower-growing assets, the firm generates cash to ramp up spending on drilling projects there. About 90 percent of Quicksilver’s capital spending budget is targeted at Barnett.
At the same time, Quicksilver continues to own a stake in BreitBurn, so it’s still benefiting from cash flows from the Antrim Shale of Michigan assets it sold.
Quicksilver’s stock is up 75 percent from my original recommendation in August, once you account for the 2-for-1 split in the stock on Feb. 1. In addition, on a price-to-cash-flow basis, the stock is more expensive that its peers. I’m maintaining Quicksilver Resources as a hold in this issue and recommending a higher stop of 27.25 to lock in gains.
I highlighted Wildcatters Portfolio holding BG Group in the Oct. 24, 2007, issue, Liquid Gold. Clearly, it’s not a North America-focused E&P firm; it’s not in the same business as EOG or XTO.
But my thesis on BG’s liquefied natural gas (LNG) business remains unchanged. The company owns natural gas liquefaction capacity located near low-cost gas reserves. This allows BG to produce gas cheaply and sell it into any market where it’s in the highest demand. In the Atlantic basin LNG trade, BG has become a dominant player.
But I won’t bore readers by repeating my bullish case for BG’s LNG business. It’s worth noting that BG is also part of the exciting new Tupi deepwater project in Brazil. Tupi is a giant deepwater oilfield that BG and Petrobras estimate could hold 12 billion to 30 billion barrels of oil equivalent reserves. Tupi could well be the largest oilfield discovered in the world since Kashagan in Kazakhstan.
BG will hold a significant share of the project, as much as 2.5 billion to 3 billion barrels of oil equivalent reserves. That would make Tupi larger than all of BG’s other projects put together. Yet, while many investors are talking about Petrobras’ exposure to Tupi, few have noted BG’s.
Although it’s still too early to know the full extent of the field’s potential, BG hinted that it could hit peak production of 500,000 to 1 million barrels of oil equivalent per day sometime in the middle of the coming decade. As more news is forthcoming about Tupi, it will act as an additional upside catalyst for BG’s stock. I’m raising BG Group from a hold to a buy under 120.
My final recommended E&P play is London-traded Tullow Oil. Tullow has oil and natural gas production operations primarily in the North Sea of Britain and Africa. Africa is the most exciting region for Tullow from a production growth perspective, with production up 21 percent in 2007 compared to overall production growth of 13 percent.
Unlike EOG and XTO, Tullow doesn’t target resource plays. In 2007, the company dug a total of 16 exploration wells. Nine of those wells discovered hydrocarbons, while the remainder didn’t produce economically. Although that level of success is considered solid, clearly Tullow is taking a risk in drilling wells.
There are several key catalysts for Tullow’s stock in 2008. First, I’ll be watching its ongoing exploration and development activities in Ghana. Tullow found a massive deepwater field, dubbed Jupiter, off the shore of Ghana that has proven reserves of more than 170 million barrels of oil; the company estimates that final reserves could be above 1.2 billion barrels.
Tullow has plans to drill four more wells in the region in the first half of 2008 and a total of seven wells for the year. As the company digs these wells and reports results, reserve and production estimates will likely rise considerably.
The company also continues to ramp up activity in Uganda with plans to invest $200 million in exploration projects for 2008, following on from $100 million invested in 2007. Tullow may see some early production from its fields there in the second quarter.
Tullow has production and or exploration projects underway in at least 10 African countries. Africa is one of the most promising new markets for oil and gas production, and large areas of the continent and offshore regions are still relatively underexplored.
Tullow has already had success partnering with firms in the region on projects and generating actual production. This makes it an excellent play on the prospects for further production growth in Africa.
Production from the North Sea region, Tullow’s second most-important producing region, actually fell in 2007 by around 6 percent. However, this was due primarily to delays in certain scheduled startup projects that have since come on stream.
Tullow has several small projects in the area scheduled for 2008 that could help to hold production basically flat with 2007 levels. However, Tullow’s interest and spending has increasingly shifted to Africa, where prospects for growth are far superior. Buy Tullow Oil in London under GBP7 (USD13.75).
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I see continued strong performance ahead for the group. As I’ve outlined over the past few issues, natural gas prices have upside from current levels, thanks to a steadily improving inventory outlook.
I’ve been slowly adding exposure in natural gas leveraged names over the past few months. Because many independent E&Ps have more exposure to gas than oil, this will boost results even further.
In North America, the key to E&P performance is production growth, and the key to true, organic production growth is exposure to unconventional oil and natural gas reserves. Not only are these reserves prolific producers, but they also have low exploration risk and are cheap to produce using modern techniques.
In This Issue
In this issue, I’ll take a closer look at some key unconventional reserve plays and results and outlooks for my five favorite E&P firms.Having recently highlighted integrated oils, I thought it appropriate to revisit exploration and production companies, given their relation to currently surging energy prices. See Exploration and Production.
The most important measure of E&P companies, strong production growth potential typically indicates an E&P company will handily outperform its peers. And unconventional production is the single most important source of natural gas in the US. See Production Growth.
There are three different types of unconventional gas reserves. Each is more difficult than simply drilling, but advanced techniques now make drilling such wells more efficient. See Going Unconventional.
Gas isn’t the only unconventional resource. Oil sands and shale oil are also popular with many resources domestically. Advanced technology has been an asset in this field as well. See Unconventional Oil.
Two other factors to consider when evaluating E&Ps are their cost structure and mix of oil and gas production. See Costs and Mix.
I hold several attractive E&P companies in the Wildcatters and Gushers portfolios. Here’s a rundown on each. See How to Play It.
I’m recommending or reiterating my recommendation in the following stocks:
- BG Group (London: BG; OTC: BRGYY)
- EOG Resources (NYSE: EOG)
- Tullow Oil (London: TLW)
- XTO Energy (NYSE: XTO)
- Quicksilver Resources (NYSE: KWK)
Exploration and Production
E&P is probably the simplest, most-recognizable face of the energy industry. These companies explore for, produce and sell oil and/or natural gas.But the E&P industry is also one of the most diverse in the energy patch. The major integrated oils, profiled in the Nov. 21, 2007, issue, Super Oil, have large E&P divisions; most integrated oil firms concentrate on developing reserves located outside North America or in the deepwater. These are typically large-scale, multi-year projects targeting significant oil and/or gas deposits.
In contrast, there are legions of smaller independent E&Ps located in the US, Canada, Europe and Australia. Traditionally, the independent E&Ps have focused on smaller reserves located closer to their home markets. But nowadays that’s an overgeneralization as many independent E&Ps have grown rapidly via acquisitions over the years; they’re now starting to enter markets that were traditionally dominated only by the major integrated oils.
This isn’t the first time I’ve highlighted the E&P business. In the Dec. 6, 2006, issue, Looking for Some Upside, I highlight some of the smaller North America-based E&Ps. And in the June 20, 2007, issue, Europe’s Gas, I took a closer look at a few select European E&P names.
Because I recently highlighted the integrated oils, I’ll concentrate on the independent E&Ps in this issue. The most important point to keep in mind is that, like the services and equipment names, stock selection is absolutely crucial when playing the E&P business.
E&Ps benefit directly from higher oil and gas prices through higher price realizations for the products they produce. But it’s a big mistake to assume that commodity prices are the sole factor to consider when analyzing the group.
For example, consider the three pure-play US-based E&Ps in the TES portfolios: EOG Resources, Quicksilver Resources and XTO Energy. All three have production profiles weighted in favor of natural gas, not crude oil.
As I noted in last week’s issue, the best measure of natural gas pricing in North America is the 12-month New York Mercantile Exchange (NYMEX) strip price. This is the average of the next 12 months’ worth of natural gas futures prices traded on the NYMEX.
Because most producers hedge at least part of their future production using futures, this is a good indicator of the prices they actually attain for their production over time. Check out the chart of the 12-month strip below.
Source: Bloomberg
It’s clear that the natural gas strip topped out in the fall of 2005. This was immediately in the aftermath of hurricanes Katrina and Rita when US gas production was temporarily curtailed.
If natural gas-focused E&Ps were completely reliant on commodity prices for growth and performance, these stocks would have performed poorly since gas topped out. But that’s completely incorrect. Check out the chart below.
Source: Bloomberg
I created an index using the three gas-focused E&Ps currently in the TES portfolios and plotted that index starting with a base value of 100 on the day natural gas prices topped out in 2005. As you can see, these stocks performed phenomenally well since that date; the index is higher by close to 50 percent, despite the fact that gas prices are still well under their 2005 highs.
The best-performing stock in the index was XTO Energy, up some 71.2 percent since gas peaked in 2005. The worst performer was EOG Resources, up a still-respectable 37 percent.
In comparison to these figures, the S&P 500 is up 20 percent including dividends since that same date, and the S&P 500 Energy Index is up 22 percent. So not only did the E&Ps perform well in a weak gas environment, they actually outperformed the broader market and energy sectors.
My point is that, although we can’t afford to ignore the commodity pricing environment when analyzing E&Ps, it’s far from the only determinant. There are three other key factors to keep an eye on in my view: production growth potential, production costs and the mix of oil and gas produced.
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Production Growth
Production growth potential is the most important of these three factors. I explained this at some length in the Dec. 6, 2006, issue; nonetheless, it bears repeating here.Companies with stagnant production are entirely beholden to commodity prices. Their revenues will rise and fall with the price of oil or gas.
But firms that can grow their production steadily over time can make money even when commodity prices are falling. Rising production can keep sales and earnings growing as long as realized sales prices remain above production costs.
This is also a key metric that Wall Street watches. Historically, companies that exhibit strong production growth have handily outperformed the industry as a whole. Check out the chart below.
Source: Bloomberg
I’ve highlighted this chart before in TES. To create these three lines, I examined all 20 of the North America-focused E&P companies that make up the S&P Supercomposite E&P Index. I tossed out any stocks that haven’t been public for at least five years.
I then sorted the remaining universe by five-year production growth. The line labeled E&P Best represents the stock price performance for the three stocks with the highest production growth; the line E&P Worst represents the performance of the three stocks with the slowest production growth. Finally, I also included the overall S&P Supercomposite E&P Index for reference.
The trend here couldn’t be clearer. The E&P firms with the fastest production growth rose 580 percent over the past five years, compared to just 330 percent for the S&P E&P index and 150 percent for the slowest growers. Production growth is every bit as important as commodity prices when analyzing the E&P industry.
Of course, I constructed this chart with the benefit of hindsight. There’s no way to know for certain which E&Ps will show the best growth going forward. However, we can evaluate growth potential by looking at the location and quality of a firm’s reserves and their drilling plans.
When it comes to North America-focused E&P firms, the fastest-growing producers typically target one of a number of unconventional reserves. Broadly speaking, the term unconventional (or nonconventional) refers to any field that can’t be produced economically using traditional well technologies.
Unconventional gas production already makes up close to 40 percent of US gas output. And that number is only going to rise in the coming years. Check out the chart below for a closer look.
Source: Energy Information Administration (EIA)
This chart depicts US production broken down by source. The chart shows historical data going back to 2004 and projections out to 2030 from the Energy Information Administration’s (EIA) most recent report.
As you can see, not only is unconventional production the most important single source of gas in the US, it’s also one of the only sources that’s likely to show real growth in the coming years. And consider that as recently as 2000, conventional gas production was far higher than unconventional production. These reserves have come to dominate the US gas market.
Note also the other lines on the US production chart. The EIA projects conventional onshore production will fall at a slow but steady rate in coming years. Associated and dissolved gas—basically gas that’s produced alongside oil—is also likely to decline out to 2030. The agency projects that offshore growth is likely out to the middle of the coming decade as new deepwater projects come onstream; after that, production offshore is also slated to see a gradual decline.
Historically, the EIA and the Information Energy Agency (IEA) have been too conservative when it comes to estimating decline rates for wells. In other words, it’s likely that production from some of these conventional sources will fall a good deal more quickly than the chart suggests. That makes unconventional production even more important.
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Going Unconventional
There are three main types of unconventional gas reserves: tight sands, shale gas and coal bed methane (CBM). To understand what these reserves are and how they’re different from conventional reservoirs, it’s useful to understand how a normal oil or gas reserve is structured.Gas isn’t found in giant underground caverns, and oil isn’t located in giant rivers or lakes underground. Instead, hydrocarbons exist in the pores, cracks and crevices of underground rock formations.
The rock that holds the gas or oil is known as the reservoir rock. Sandstone is a classic example. Anyone who’s ever picked up a piece of sandstone knows that it’s composed of sand particles; typical sandstone is full of tiny pores. This makes it capable of holding large quantities of hydrocarbons.
But if the sandstone extends all the way to the surface of the Earth, there’s a problem: Gas will eventually be forced by underground pressures to the surface. The oil or gas wells would have, over time, simply seeped to the surface.
Natural gas (and oil) seeps are hardly uncommon. The first oil wells dug in Pennsylvania were found because of the presence of oil seeps. And the ancient Greeks understood gas seeps; the constant flame at the famed Oracle of Delphi was really powered by natural gas naturally seeping through the rocks.
But in some cases, the porous reservoir rock is covered by an impermeable cap rock, which prevents the hydrocarbons from seeping out of the reservoir rock. This is a classic hydrocarbon trap. To produce this sort of reserve, a producer only has to drill through the cap rock into the reservoir rock. The gas or oil under pressure then naturally flows into the wellbore and to the surface.
But things aren’t always that simple. Sometimes, the reservoir rock can be highly porous, with a large number of holes containing gas or oil. But that rock isn’t permeable; in other words, the pores aren’t well connected so gas or oil doesn’t flow easily into the wellbore when a well is dug.
An example of this is the tight sands gas deposits in the Rocky Mountains. Fields such as the San Juan Basin of New Mexico and Colorado and the Jonah fields in Wyoming are among the largest producing fields in the US today.
Historically, tight sands gas plays wouldn’t produce economically. Simple, vertical wells will see an initial rush of gas, but gas located further away from the wellbore can’t travel through the reservoir rock to the well. Therefore, although producers have known these fields existed for decades, they weren’t assumed to be economical to produce. Producers instead went after more standard gas plays that were cheaper to produce.
But newer technologies allow the production of such fields. There are really two key enabling technologies: horizontal/directional drilling techniques and fracturing.
Horizontal drilling is fairly intuitive. These are wells that are drilled sideways underground. The advantage of such a well is that a producer can expose more of it to the producing reservoir rock. This allows hydrocarbons to be produced more efficiently. Check out the chart below.
Source: Bloomberg
This chart shows the number of horizontal and directional wells drilled in the US as a percentage of total wells drilled. As you can clearly see, producers greatly stepped up their horizontal drilling activity starting in the mid- to late 1990s. In 1996, simple vertical wells accounted for close to 80 percent of all wells completed in the US. Now, that figure is closer to 50 percent, and within a few years, horizontal wells are likely to become the dominant technique.
Much of the growth in popularity of horizontal drilling is tied to the need to produce unconventional reservoirs more efficiently. Although horizontal drilling was once considered too expensive to be worthwhile, the decline of conventional fields is forcing a technology revolution in the oil patch. This will continue to power growth in unconventional production.
The second technique is fracturing. I’ve explained this service function at great length in TES on a few occasions, including the Nov. 7, 2007, issue, Coal and Services. I won’t bore longtime readers with another lengthy explanation.
Fracturing is a way of improving the permeability of reservoir rock. The procedure involves pumping a liquid mixture into the reservoir under extreme pressures, often exceeding 8,000 pounds per square inch. This literally cracks that rock and forms small channels for the oil or gas to flow through.
Fracturing can actually extend as far as 3,000 feet from the well. And producers also pump small grains of sand or more-advanced proppants to literally prop open these fissures and cracks. In this manner, once the pressure is removed, the cracks remain open.
Typically, using a combination of these techniques, producers can generate economic production from an unconventional well. To offer an idea of the difference these technologies make, consider that using traditional vertical technologies, a well could recover less than 10 percent of the natural gas in the reservoir because most of that gas was stranded in unconnected pores. Using horizontal drilling techniques and fracturing, producers can recover more than half the gas in place. That’s a phenomenal improvement.
Tight sands deposits consist of an impermeable sandstone reservoir that won’t produce economically until fractured. Gas shale reservoirs are similar. Shale is one of the most common rocks in the world; it looks like a chalkboard in its natural state.
Traditionally, shale isn’t considered a reservoir rock. Because of its impermeability, it often acts as a trap or cap rock for hydrocarbons.
But that isn’t always the case. There are shale reservoirs around the world that contain vast quantities of natural gas (or oil). Typically, the gas is found trapped in small pores of the rock or adsorbed to organic material in the shale. The term adsorbed is different to absorbed; it means that the gas adheres to the organic material.
Just as with tight gas, shale reservoirs can be produced using a combination of fracturing and horizontal drilling techniques. The best-known shale gas reservoir in the US right now is the Barnett Shale, located around Fort Worth, Texas.
However, there are several other potentially hot shale plays. And outside the US, there are also many potentially viable shale gas plays that may be exploited in coming years using the more advanced technologies available today.
CBM wells are a bit different. The natural gas in such wells is found adsorbed to underground coal reservoirs.
Typically, CBM gas is found adsorbed to coal in the presence of water. To produce the gas, the seam is first dewatered by pumping the water out of the coal. This process reduces the pressure in the reservoir and frees the methane gas, allowing for production. The best-known location for CBM gas would be the US Powder River Basin, home to the nation’s largest coal deposits.
The beauty of unconventional reserves is their size and predictability. Many of the hottest unconventional reserves in the US are known as resource plays—widely distributed deposits that have little or no exploration risk. Producers with access to acreage can focus on drilling wells into known deposits and producing the gas.
The focus for many is on drilling wells closer together to produce more of the gas in place and improving the efficiency of their fracturing jobs to boost recovery rates. Also, over time, producers have become far more efficient in drilling wells, allowing more wells to be drilled in a given time period.
Overall, the potential size of US unconventional reserves is huge. Most estimate total producible reserves at 500 trillion to 1,000 trillion cubic feet. Given the size of these resources, their low exploration risk and improving technology, I prefer to focus on US and Canadian E&P firms with access or exposure to unconventional reserves.
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Unconventional Oil
Gas isn’t the only find in unconventional reservoirs. Probably the best known unconventional oil reservoir is the oil sands of Canada.Oil sands are nothing more than a solid hydrocarbon known as bitumen that’s mixed with sand, dirt and water. This bitumen can be processed into refined products just like oil.
There are really two main production methods: strip mining and in-situ production. Strip mining involves simply scooping large quantities of oil sands and heating them to remove the bitumen from debris. This is practical only for oil sands resources located reasonably close to the surface.
In-situ mining is used to produce oil sands located further under the surface. One common sort of in-situ mining is known as Steam Assisted Gravity Drainage (SAGD). In SAGD, producers drill two horizontal wells.
Into one well, the producer pumped superheated steam that literally melts the bitumen from the sands. As the bitumen melts, it flows (via gravity) to the lower horizontal well and can be pumped to the surface. It’s estimated that roughly 80 percent of Canada’s oil sands reserves are located too far under the surface to be produced via strip mining.
The oil sands are a classic resource play—widely distributed with little exploration risk. For surface mining operations, the largest costs are upfront.
Most surface mining operations underway or planned in Canada also call for building and running an upgrader. Because mining operations tend to be larger scale and produce more daily output, it makes economic sense to also pay for an upgrader to process the bitumen into synthetic crude oil. The synthetic oil can be sold to refiners just like light sweet crude, the highest-value product in the marketplace.
In-situ projects tend to be smaller. Although some larger projects do have upgraders, that’s not often the case. This presents two problems.
First, the producer has to find a source of natural gas liquids or synthetic crude oil to use as a diluent; basically, the producer has to mix the bitumen with other products so it will flow through a pipeline. Second, the final product is bitumen, which is priced more like heavy oil than light sweet crude.
Not all refineries have upgraders and facilities designed to handle heavy crude. Bitumen is trading at a large discount to light sweet crude oil or synthetic crude. The advantage of an in-situ operation is that the upfront costs of developing are lower because you don’t need to pay for an expensive upgrader.
Operational costs are another big issue for the sands. In in-situ operations, steam is used to heat the bitumen so it can flow into a well. The problem is most steam is produced using natural gas. Producing steam is an energy-intensive process; producing in-situ oil sands requires a large amount of natural gas.
Although surface mining operations don’t use steam to heat the bitumen for mining purposes, it’s often used to separate bitumen from sand. And natural gas is an important commodity for many upgraders. Hydrogen produced from natural gas, for example, is used to turn bitumen into synthetic crude.
Producing a barrel of crude can require moving two tons of sands. The fuel to power the giant earth-moving equipment used in such operations is diesel. Obviously diesel and natural gas prices are an operational cost.
According to the Canadian Association of Petroleum Producers (CAPP), the oil sands industry consumed some 500 cubic feet of natural gas per barrel of oil sands production in 2005. Given that current production is around 1.1 million barrels per day, that equates to some 550 million cubic feet of natural gas used per day, or 6.5 percent of Canadian natural gas demand. But if production expands to 3.6 million barrels per day as forecast, gas use would jump to more than 1.8 billion cubic feet per day.
Although all these costs and considerations are relevant, most estimates suggest that oil sands production is profitable as long as oil prices remain above $30 to $40 per barrel, depending on the project. And oil sands production is the only source of Canadian production that’s set to actually grow in coming years. Check out the chart “Canadian Oil Sands Production.”
Source: EIA
This chart shows historical Canadian oil sands production going back to 1990 and projections out to 2030. The EIA estimates that production will climb from about 1.1 million barrels per day at this time to roughly triple that level by 2030.
This is one of the fastest rates of production growth for any resource in the world; access to potential oil sands production is an attractive opportunity for E&P firms. This interest is also apparent from the chart below.
Source: CAPP
This chart shows total spending on oil sands developments from 1999 through 2006. It’s clear that producers are taking oil sands seriously: Spending has jumped nearly sixfold since 1999.
But oil sands aren’t the only unconventional resource. All too often, investors confuse oil shale with shale oil. Oil shale is a resource similar in many ways to oil sands.
Basically, a heavy oil product attached to rocks and sand. It’s possible to remove bitumen from oil shale, and the US has a large amount of this resource. However, oil shale has less water in it than oil sands. Therefore, it takes far more energy to produce oil shale and separate the bitumen than oil sands. This makes it more expensive.
The world’s major oil producers have targeted oil shale in the past. I’m quite sure they’ll seek out production of this reserve in the future as well. But it will require oil prices to remain elevated for a prolonged period. The last oil shale boom occurred in the early ’80s and ended as oil prices dropped to levels that made production uneconomical.
Shale oil is a different resource entirely. Basically, like natural gas, some oil is trapped in impermeable or weakly permeable reservoirs. Like gas, this oil can be produced using horizontal drilling techniques and fracturing. A classic example of this resource is the Bakken shale play that encompasses parts of North Dakota, South Dakota, Montana and the Canadian provinces of Saskatchewan and Manitoba.
The Bakken reservoir has been known for many years. However, just as with shale gas, it’s tough to produce using conventional technologies; the shale is only weakly permeable.
In addition, traditional drilling mud can actually cause the shale to swell and close off the natural fractures and channels in the rock, permanently ruining the well. But this reserve is thought to hold several billion barrels of potential oil reserves, and the resource is widely distributed.
Not surprising, the Bakken has become a hot area for drilling activity. With production ramping up quickly, it’s clear that shale oil, such as that from the Bakken reservoir, is an attractive resource for producers.
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Costs and Mix
Two other factors to consider when evaluating E&Ps are their cost structure and mix of oil and gas production. To address the first point, one of the most commonly analyzed metrics is finding and development (F&D) cost.The F&D cost is a measure of how much it costs a firm to add one barrel of oil equivalent to its proven reserves via actual exploration and development work. This measure doesn’t include the costs of acquisitions but actual organic reserve development.
The table of E&Ps below lists each firm’s F&D costs. Most E&Ps only report this figure annually; for most of the E&Ps in the table, the reported F&D cost is for 2006, not 2007.
Although you can never generalize, companies with access to attractive unconventional reserve acreage tend to look favorable on an F&D basis as well. Consider longtime favorite Wildcatters Portfolio member EOG Resources. The main attraction of this firm is its position in the fast-growing Barnett and Bakken shale plays; EOG was one of the first E&Ps to seriously target these unconventional reserves.
But in addition to these fast-growing plays, EOG also has some conventional wells located in Canada. In its fourth quarter and full-year 2007 earnings release, the firm reported total US F&D costs of $1.90 per thousand cubic feet equivalent. But for EOG’s conventional Canadian reserves the F&D cost was closer to $6.25 per thousand cubic feet.
It should come as little surprise that EOG is focusing its development operations on the US. This also illustrates the major cost advantages that some unconventional reserves offer.
Finally, you should evaluate an E&P’s relative exposure to oil and natural gas. Many of the E&Ps in the table below are gas-levered; however, that’s not always the case.
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E&P Companies
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Company Name (Exchange: Symbol)
|
F&D Costs (BOE)
|
Reserve Replacement
|
Percent Oil
|
Price/Cash Flow
|
| Anadarko (NYSE: APC) | $1,379.62 | 6.70 | 29.8% | 9.73 |
| Apache (NYSE: APA) | 22.51 | 106.06 | 31.7 | 7.45 |
| Can. Nat. Resources (TSX: CNQ) | 14.35 | 179.75 | 49.0 | 6.36 |
| Chesapeake Energy (NYSE: CHK) | 30.20 | 232.59 | 8.0 | 3.63 |
| Cimarex Energy (NYSE: XEC) | 38.26 | 100.32 | 23.9 | 4.17 |
| Comstock Resources (NYSE: CRK) | 13.08 | 100.66 | 18.0 | 3.63 |
| Denbury Resources (NYSE: DNR) | 33.36 | 154.02 | 62.4 | 14.47 |
| Devon (NYSE: DVN) | 17.30 | 178.64 | 36.0 | 6.34 |
| EnCana (NYSE: ECA) | 12.69 | 191.46 | 18.2 | 6.32 |
| EOG Resources (NYSE: EOG) | 15.33 | 202.27 | 11.0 | 8.18 |
| Newfield Exploration (NYSE: NFX) | 20.74 | 215.89 | 20.0 | 5.58 |
| Nexen (NYSE: NXY) | 9.11 | 586.42 | 50.0 | 5.42 |
| Occidental Petroleum (NYSE: OXY) | 21.39 | 84.55 | 73.0 | 9.94 |
| Pioneer Drilling (NYSE: PXD) | 39.28 | 89.02 | 40.3 | 6.90 |
| Questar Resources (NYSE: STR) | 14.02 | 210.97 | 12.0 | 8.29 |
| Quicksilver Resources (NYSE: KWK) | 6.35 | 840.72 | 5.8 | 18.55 |
| Suncor (NYSE: SU) | 2.25 | 452.55 | 86.6 | 11.62 |
| Swift Energy (NYSE: SFY) | 30.09 | 82.49 | 69.0 | 2.89 |
| Talisman (TSX: TLM) | 23.63 | 136.67 | 27.5 | 3.97 |
| Ultra Petroleum (NYSE: UPL) | 6.59 | 501.02 | 4.4 | 26.66 |
| W&T Offshore (NYSE: WTI) | 61.38 | 96.94 | 39.1 | 3.74 |
| XTO Energy (NYSE: XTO) | 9.61 | 265.17 | 17.7 | 7.14 |
EOG, for example, plans to grow its liquids production at a far faster pace than gas in the coming years. The firm will be considerably more balanced in terms of oil and gas mix in coming years. Other E&Ps such as Denbury Resources and Suncor are heavily leveraged to oil.
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How to Play It
Wildcatters Portfolio holding EOG Resources reported fourth quarter and full-year results that exceeded analyst expectations. When evaluating E&P earnings, I typically concentrate on the adjusted earnings figure that strips out the mark-to-market impact of oil and gas hedges.Under generally accepted accounting principles (GAAP), a producer must account for all oil and gas hedges by marking them to a fair market value each quarter. Because companies like EOG often hedge a portion of their production years into the future, that means marking several years’ worth of futures prices to a current market value each quarter. This is purely a paper profit or paper loss, not an actual cash flow.
This makes no logical sense. Producers hedge a portion of their production so that they’re able to lock in a fixed price for oil or gas they’ll produce at some time in the future. A more meaningful way to account for hedges is to account for only the hedges that expire in a given quarter.
On that basis, EOG earned $1.29 in the fourth quarter, considerably above the $1.05 to $1.10 that most analysts had predicted. The stock reacted favorably to the release.
Historically, EOG has been mainly a natural gas play. It’s most-exciting, fast-growing gas reservoir is the Barnett Shale play I outlined above. The company continues to see strong growth from Barnett; production averaged 284 million cubic feet equivalent per day from the region in 2007 and exited the year at a run rate of about 375 million.
For 2008, EOG is expecting average production of 470 million cubic feet per day, up from its prior estimates of 450 million. In addition, management indicated that it sees gas production from its Barnett play continuing to grow through at least 2010.
EOG is now producing more aggressively from the western side of the Barnett region. But production rates from this side of the field appear to be more or less in line with what the company saw from more core areas. Even better, EOG stated that it’s seeing much higher natural gas liquids (NGL) production from the western Barnett.
NGLs include a number of liquid products that exist with the gas naturally in the reservoir. NGL prices typically follow the price of oil at least directionally; given current attractive oil prices, rising NGLs production is another benefit for EOG. Higher NGL content in the western Barnett is driving EOG’s expectations for 40 percent year-over-year growth in NGL production.
And although Barnett remains solid, perhaps EOG’s most-exciting opportunity right now is in its Bakken shale play in North Dakota. The Bakken is primarily an oil play; EOG has estimated its total share of reserves at about 80 million barrels in the region. The company’s actual proved reserves at year-end stood at about 21 million barrels.
EOG’s production from the Bakken is only just ramping up, and management expects 38 percent year-over-year growth in oil production for 2008 and continued elevated growth for 2009 and 2010 driven by production from Bakken.
At this time, EOG has only 24 producing wells on its Bakken properties and more than 175,000 acres worth of land in the region. Wells are spaced at 640 acres, which is considered a wide well spacing for most oil plays.
Results from EOG’s first wells have been solid: They’re producing around 1,700 barrels of oil per day at initial production. Although that may not sound like a lot, wells generating that much production are highly unusual in the US. Now EOG is experimenting with spacing wells closer together and drilling wells near existing producers to try to establish the size and limits of the fields.
As the firm completes this drilling work, I expect its estimates of total reserves and production growth to gradually move higher. Management sounded conservative on the earnings conference call. I expect that conservatism is partly due to the fact that EOG has scheduled a lengthy analyst meeting for Feb. 28 and plans to offer greater details in that call.
In addition, EOG is still buying up drilling rights to acreage in the region, so it may not want to give away details of exactly where it’s drilling for fear of tipping its hands.
Overall, EOG should have little trouble meeting its 15 percent year-over-year production growth target for 2008. Most of that growth will come from EOG’s unconventional plays, while operations in Canada, Trinidad and the UK will likely see flat year-over-year production.
The company benefits from exposure to two of the hottest unconventional plays and a production profile that’s becoming increasingly more balanced between gas and oil. I’m raising my buy price for EOG Resources to 105.
Wildcatters Portfolio holding XTO Energy is an unconventional gas-focused E&P. The company recently reported 30 percent year-over-year growth in production for the fourth quarter over the same quarter in 2006. Of that 30 percent, roughly 14 percent came from actual exploration and development, while the remainder came via acquisitions.
What’s really impressive about XTO from a pure numbers perspective is its F&D costs. On an organic basis–excluding acquisitions–XTO’s F&D costs stand at just $1.36 per thousand cubic feet compared to an average of roughly $3 for gas-focused E&Ps.
Like EOG, XTO has a strong position in the Barnett Shale play; XTO reported growth of 25 percent over the same quarter last year from Barnett. The company is relatively new to that region, entering Barnett only in 2004. But production growth has remained consistent since it started producing from the region, and XTO now has an impressive 250,000-acre position in the core of this hot region.
In addition, XTO has operations in unconventional plays in the Rockies as well as some newer up-and-coming gas shale plays, such as the Woodford and Fayetteville shales in Oklahoma and Arkansas, respectively. In the Woodford Shale, XTO drilled 12 wells last tear and is looking to drill 40 to 50 in 2008. That’s a significant step up in activity that indicates XTO sees plenty of potential from this play.
Management noted in its conference call that each well costs $4.5 million to $5 million and contains about 3 billion cubic feet of natural reserves. Costs are falling, and reserves are rising as XTO gains experience with wells in the region.
This is the same thing that XTO managed with Barnett. As the company gained experience drilling in the region, XTO was able to cut the time needed to drill a well in Barnett from 30 days to around 20 days. By cutting costs and improving efficiency, XTO is able to accelerate production at a low cost. This is the reason for its extraordinarily low F&D costs.
XTO, like EOG, has room to grow simply by drilling more wells on existing high-quality properties. The only real limitation management has found to growth in these regions is a lack of pipeline and processing capacity to handle all the gas produced. But XTO is moving ahead on schedule with expansion projects that will alleviate those bottlenecks.
XTO has also been an aggressive acquirer in recent years. In 2007, XTO bought up significant reserves from Dominion Energy. These reserves represent a diverse mixture of plays, but by drilling more aggressively, XTO should be able to boost production. Because Dominion is primarily an electric utility, the firm didn’t spend enough cash to fully develop its properties; XTO will be able to generate significantly more growth from these assets.
Although XTO is among the most expensive E&Ps in the table above, it’s consistently delivered strong production growth and one of the lower F&D costs of any North American E&P. I’m boosting my buy target for XTO Energy; the stock rates a buy under 65.
Gushers Portfolio holding Quicksilver Resources hasn’t reported fourth quarter results; earnings are scheduled for release on Feb. 26. However, the firm did offer an update on reserves and production earlier this month. Reserves were flat year-over-year, but that doesn’t adjust for the fact that Quicksilver divested some 550 billion cubic feet of its slower-growing gas reserves earlier this year.
With that adjustment, Quicksilver’s reserves soared more than 35 percent. And production for the year was up a respectable 27 percent on total F&D costs of just $1.38 per thousand cubic feet, among the cheapest F&D costs of any US E&P.
I expect to see strong production growth from Quicksilver’s Barnett Shale play when it reports later this month; Barnett Shale makes up roughly 80 percent of Quicksilver’s current reserve base. The company’s deal to sell off slower-growing fields in Michigan to master limited partnership BreitBurn Energy Partners last fall was a major positive.
Quicksilver’s Barnett acreage offers more growth opportunities, and by selling off slower-growing assets, the firm generates cash to ramp up spending on drilling projects there. About 90 percent of Quicksilver’s capital spending budget is targeted at Barnett.
At the same time, Quicksilver continues to own a stake in BreitBurn, so it’s still benefiting from cash flows from the Antrim Shale of Michigan assets it sold.
Quicksilver’s stock is up 75 percent from my original recommendation in August, once you account for the 2-for-1 split in the stock on Feb. 1. In addition, on a price-to-cash-flow basis, the stock is more expensive that its peers. I’m maintaining Quicksilver Resources as a hold in this issue and recommending a higher stop of 27.25 to lock in gains.
I highlighted Wildcatters Portfolio holding BG Group in the Oct. 24, 2007, issue, Liquid Gold. Clearly, it’s not a North America-focused E&P firm; it’s not in the same business as EOG or XTO.
But my thesis on BG’s liquefied natural gas (LNG) business remains unchanged. The company owns natural gas liquefaction capacity located near low-cost gas reserves. This allows BG to produce gas cheaply and sell it into any market where it’s in the highest demand. In the Atlantic basin LNG trade, BG has become a dominant player.
But I won’t bore readers by repeating my bullish case for BG’s LNG business. It’s worth noting that BG is also part of the exciting new Tupi deepwater project in Brazil. Tupi is a giant deepwater oilfield that BG and Petrobras estimate could hold 12 billion to 30 billion barrels of oil equivalent reserves. Tupi could well be the largest oilfield discovered in the world since Kashagan in Kazakhstan.
BG will hold a significant share of the project, as much as 2.5 billion to 3 billion barrels of oil equivalent reserves. That would make Tupi larger than all of BG’s other projects put together. Yet, while many investors are talking about Petrobras’ exposure to Tupi, few have noted BG’s.
Although it’s still too early to know the full extent of the field’s potential, BG hinted that it could hit peak production of 500,000 to 1 million barrels of oil equivalent per day sometime in the middle of the coming decade. As more news is forthcoming about Tupi, it will act as an additional upside catalyst for BG’s stock. I’m raising BG Group from a hold to a buy under 120.
My final recommended E&P play is London-traded Tullow Oil. Tullow has oil and natural gas production operations primarily in the North Sea of Britain and Africa. Africa is the most exciting region for Tullow from a production growth perspective, with production up 21 percent in 2007 compared to overall production growth of 13 percent.
Unlike EOG and XTO, Tullow doesn’t target resource plays. In 2007, the company dug a total of 16 exploration wells. Nine of those wells discovered hydrocarbons, while the remainder didn’t produce economically. Although that level of success is considered solid, clearly Tullow is taking a risk in drilling wells.
There are several key catalysts for Tullow’s stock in 2008. First, I’ll be watching its ongoing exploration and development activities in Ghana. Tullow found a massive deepwater field, dubbed Jupiter, off the shore of Ghana that has proven reserves of more than 170 million barrels of oil; the company estimates that final reserves could be above 1.2 billion barrels.
Tullow has plans to drill four more wells in the region in the first half of 2008 and a total of seven wells for the year. As the company digs these wells and reports results, reserve and production estimates will likely rise considerably.
The company also continues to ramp up activity in Uganda with plans to invest $200 million in exploration projects for 2008, following on from $100 million invested in 2007. Tullow may see some early production from its fields there in the second quarter.
Tullow has production and or exploration projects underway in at least 10 African countries. Africa is one of the most promising new markets for oil and gas production, and large areas of the continent and offshore regions are still relatively underexplored.
Tullow has already had success partnering with firms in the region on projects and generating actual production. This makes it an excellent play on the prospects for further production growth in Africa.
Production from the North Sea region, Tullow’s second most-important producing region, actually fell in 2007 by around 6 percent. However, this was due primarily to delays in certain scheduled startup projects that have since come on stream.
Tullow has several small projects in the area scheduled for 2008 that could help to hold production basically flat with 2007 levels. However, Tullow’s interest and spending has increasingly shifted to Africa, where prospects for growth are far superior. Buy Tullow Oil in London under GBP7 (USD13.75).
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