In This Issue
The fallout from the Macondo disaster and depressed natural gas prices have increased investment in developing the nation’s shale oil fields. Here’s an overview of some of the most exciting shale plays. See The Plays.
Elliott provides a detailed analysis of his favorite bets on growing oil production from US shale. See The Players.
Want to know which stocks to buy now? Check out the updated Fresh Money Buys. The table includes two new additions and updated buy targets for some of Elliott’s favorite plays. See Fresh Money Buys.
EOG Resources (NYSE: EOG)—Buy @ 115
Brigham Exploration (NSDQ: BEXP)—Buy in Energy Watch List
Continental Resources (NYSE: CLR)—Buy in Energy Watch List
Oneok Partners LP (NYSE: OKS)—Buy in Energy Watch List
Enterprise Products Partners LP (NYSE: EPD)—Buy @ 42
Whiting Petroleum Corp (NYSE: WLL)—Buy in Energy Watch List
Macmahon Holdings (Australia: MAH; OTC: MCHHF)–Hold
I can’t recall an investment conference where I haven’t received at least one question about the potential of oil-rich plays such as the Bakken Shale and Eagle Ford Shale. Interest in unconventional oil fields has picked up in the wake of the Macondo disaster. Whereas new regulations and permitting delays will hamper US deepwater drilling for at least another 12 to 24 months, onshore shale plays offer the best prospects for production growth.
Prospective investors should note the huge difference between oil shale and oil produced from shale reservoirs, often called shale oil.
Oil shale is an inorganic rock that contains a solid organic compound known as kerogen. Oil shale is a misnomer because kerogen isn’t crude oil, and the rock holding the kerogen often isn’t even shale.
Liquid crude oil consists of organic material–plant and animal remains–that’s been exposed to heat and pressure over millions of years. The slow transformation of organic material into oil progresses through a number of stages. Kerogen occurs relatively early in this process. To understand where kerogen fits into the developmental timeline, consider that bitumen–the hydrocarbon found in Canada’s oil sands–represents a later stage in the process. In a sense, bitumen is a higher-quality and more useful hydrocarbon than kerogen.
To generate liquid oil synthetically from oil shale, the kerogen-rich rock is heated to as high as 950 degrees Fahrenheit (500 degrees Celsius) in the absence of oxygen, a process known as retorting.
There are several competing technologies for producing oil shale. Proven Reserves recommendation ExxonMobil Corp (NYSE: XOM) has developed a process for creating underground fractures in oil shale, filling these cracks with a material that conducts electricity, and then passing current through the shale to gradually convert the kerogen into producible oil. Royal Dutch Shell (NYSE: RDS A) buries electric heaters underground to heat the oil shale.
Although estimates of the cost to produce oil shale vary widely, the process is more expensive and energy-intensive than extracting crude from Canada’s oil sands. Producers would require oil prices of roughly $100 a barrel before this capital-intensive process would be feasible on a commercial scale.
In the early 1980s Exxon embarked on a massive effort to produce oil shale in Colorado. The so-called Colony Oil Shale project was expected to cost $5 billion–an exorbitant amount in 1980–but the investment appeared worthwhile based on prevailing oil prices and the company’s optimistic production forecasts.
But a collapse in oil prices forced Exxon to write off a $1 billion investment. It was one of the most dramatic boom-and-bust cycles in energy industry’s history. A few larger companies continue to work on oil shale, and plenty of smaller outfits market themselves to unsuspecting investors with tales of massive reserves locked in oil shale.
This issue of The Energy Strategist doesn’t focus on the oil shale fairy tale but rather a number of shale oil reservoirs located around the US. Shale oil plays such as the Bakken have far more in common with unconventional gas plays such as Appalachia’s Marcellus Shale and Louisiana’s Haynesville Shale than they do with Colorado’s oil shale.
What makes an oil or natural gas play unconventional? Hydrocarbons don’t occur in giant underground pools but are trapped in the pores and cracks of a reservoir rock. Conventional reservoir rocks such as sandstone feature high porosity and permeability. That is, they have many pores capable of holding hydrocarbons as well as fissures and interconnections trough which the oil or gas can travel. When a producer drills a well in a conventional field, oil and gas flow through the reservoir rock and into the well, powered mainly by geologic pressure.
Shale fields and other unconventional plays aren’t particularly permeable. In other words, these deposits contain plenty of hydrocarbons but lack channels through which the oil or gas can travel. Even in shale fields where there’s plenty of geologic pressure, the hydrocarbons are essentially locked in place.
Producers have developed and refined two major technologies in recent years to unlock the natural gas and oil trapped in shale deposits–horizontal drilling and fracturing. The first technology is self-explanatory: Horizontal wells are drilled down and sideways to expose more of the well to productive reservoir layers.
Fracturing is a process whereby producers pump a liquid into a shale reservoir under such tremendous pressure that it cracks the reservoir rock. This creates channels through which hydrocarbons can travel, improving permeability. Over the past several years US producers have perfected these techniques in a number of prolific shale gas plays. Now more and more of these exploration and production (E&P) firms are applying the same techniques to a handful of established and emerging shale oil plays.
Producers are increasingly finding that long horizontal wells–“long laterals” in industry parlance–and huge multistage fracturing jobs maximize output from shale deposits. For example, in the Bakken producers routinely drill laterals that exceed 10,000 feet in length, a distance of nearly two miles. Plenty of producers do fracturing jobs in more than 30 stages, and a few are contemplating fracturing projects of 42 stages or more. As technology and drilling techniques evolve, output and efficiency continue to improve.
The results explain why exploration and production outfits have rushed to secure acreage in the most promising plays. Not only do these fields produce crude that’s often of better quality than West Texas Intermediate (the US standard that’s the basis for NYMEX futures), but break-even costs are also far lower than in the deepwater.
In the core of the Bakken, for example, producers need oil prices in the $35 to $40 range to earn solid returns on their drilling programs. At current oil prices, some producers enjoy internal rates of return in excess of 100 percent.
As you can see, it’s important not to confuse shale oil projects with oil shale. With this distinction in mind, let’s examine some of the largest horizontal shale oil plays in the US and their prospects for future growth.
The Bakken Shale occupies the Williston Basin, a vast area centered in North Dakota and Montana. The play also extends into Canada, though the US portion is generally considered to be more prospective for oil. The map below shows exactly where this play is located.
Source: Energy Information Administration
Rocks are deposited in layers. The Bakken comprises three layers of shale–an upper, middle and lower Bakken–located at a depth of between 8,000 and 11,000 feet in the play’s most productive areas. Drilling activity targets the Bakken’s middle layer, a naturally fractured shale rock that contains a light, sweet high-quality crude oil.
Some parts of the play include another productive formation, the Three Forks-Sanish. Operators initially characterized the Three Forks as an area where oil that spilled out of the Bakken collected. But drilling results increasingly suggest that the Bakken and Three Forks are actually separate plays; activities in the Three Forks formation don’t sap production from nearby Bakken wells.
The Williston Basin and Bakken Shale aren’t new discoveries–the first wells were drilled back in the 1950s. Technology and techniques were the real discovery.
The simple vertical wells sunk in the 1950s failed to produce oil at high rates. A vertical well travels straight through the Bakken formation, but the only productive part is the 50 to 100 feet of the shaft that touches the middle Bakken. In contrast, a horizontal well drilled along the productive layer exposes thousands of productive feet to the well. In addition, hydraulic fracturing supplements the middle Bakken’s natural fractures, further enhancing productivity
In 2000 E&P firms drilled the first horizontal wells in the field. Since then, several major producers have ramped up activity to the point that the Bakken has emerged as the leading onshore oil play in the continental US. The graph below tells the tale.
Source: Energy Information Administration
This graph tracks crude oil production in Montana and North Dakota from 1981 onward. Output from the Bakken area is expected to top 350,000 barrels per day in 2010. Given that these states produce roughly 370,000 barrels per day, the data serves as a good proxy of total production from the Bakken.
As you can see, oil output declined in both states from the mid-1980s to 2002-03, when production surged. More recently, production from Montana has declined slightly because operators have shifted their focus to the North Dakota side of the play.
Estimates of the basin’s potential production growth vary widely. Conservative estimates put the figure at 500,000 to 750,000 barrels per day over the next five years. Aggressive estimates suggest that the Bakken could yield 1 to 1.5 million barrels per day in a half-decade. Based on recent well results and comments from producers, I tend to believe that production will approach the high end of these estimates–assuming oil prices remain strong.
As for recoverable reserves, in 2008 the US Geological Survey (USGS) estimated that the field contained 3.65 billion barrels of oil, 1.85 billion cubic feet of gas and 148 million barrels of NGLs. Investors should note that this estimate fails to reflect the increasingly productive Three Forks-Sanish play. Initially regarded as a gross overestimate, the USGS figure is now regarded as quite conservative. Continental Resources (NYSE: CLR), the leading player in the field, pegs the region’s recoverable reserves at 24 billion barrels.
But don’t get vertigo from these dizzying reserve estimates; what really matters is production, how many barrels of oil per day the play generates. Under the most optimistic assumptions, the region could produce about 1.5 million barrels per day by 2015, a drop in the bucket compared to US oil consumption of 20 million barrels per day.
Don’t believe the hype about the Bakken enabling the US to become energy independent or an oil exporter. That being said, the field is large enough that it will have a meaningful and lasting impact on US oil production growth.
As far as investors are concerned, low production costs ensure that, at current oil prices, many producers are generating returns in excess of 100 percent for each well drilled. Most wells pay for themselves in 1.5 to 3 years. The economics become even more attractive in the event of higher oil prices. Companies with attractive acreage positions in the Williston Basin should be able to grow profits significantly in coming years.
Eagle Ford Shale
Discovered by Gushers recommendation Petrohawk Energy Corp (NYSE: HK) in 2008, the Eagle Ford is located in south Texas and consists of three distinct windows, depicted in the map below.
Source: EOG Resources
Wells in the northern part of the play, or oil window, produce mainly crude oil, though it also contains smaller volumes of natural gas and NGLs. Located just to the south of the oil window, the wet-gas region produces gas along with high volumes of NGLs. The play’s southernmost window contains mostly gas.
Depressed natural gas prices have ensured that much of the drilling activity to date has occurred in the oil and wet-gas windows, a bias that should persist for the foreseeable future.
In terms of economics, some of the field’s sweet spots offer returns rivaling those in the Bakken. With several producers planning to step up drilling in the area, you can expect to hear more about the Eagle Ford in coming years.
Exploration and production (E&P) firms are notoriously tight-lipped about their acquisition programs and initial discovery wells for fear of instigating a land rush and losing out on prime properties. But whenever an explorer announces compelling drilling results in uncharted or forgotten territory, the competition pays attention–and opens up their wallets.
That’s exactly what happened when Wildcatters Portfolio recommendation EOG Resources (NYSE: EOG) revealed at its 2010 Analysts Conference that it had accumulated 400,000 net acres in the Denver-Juneburg (DJ) Basin, a sedimentary field in Colorado’s eastern plains as well as parts of southern Wyoming and western Kansas and Nebraska. EOG’s holdings in the DJ basin are concentrated in northeast Colorado and part of Wyoming. What management has identified as the core part of this play is near existing infrastructure in the Hereford prospect.
Source: PDC Energy
Confirmation of early results from #2-01H Jake set the industry abuzz. Drilled in the third quarter of 2009, the horizontal Jake well produced at a maximum rate of 1,558 barrels of oil per day from a 3,800-foot lateral. After 90 days, the Jake had produced 50,000 barrels of oil.
Although additional test wells have failed to live up to the Jake–perhaps because of restricted flows and different drilling techniques–the announcement sparked a massive land grab in the region. Early movers secured leases at $350 to $500 an acre. But these days, real estate in the play’s most prospective areas goes for more than $3,000 an acre. Wyoming has reported bids as high as $5,900 per acre in land auctions held this summer.
Amid all this excitement, it’s important to note that early results suggest that the Niobrara likely contains multiple core areas as well as some regions that are duds. Moreover, as Noble Energy’s (NYSE: NBL) CEO often points out, the Niobrara effectively consists of two plays: the well-documented Wattenberg Field where Noble Energy and other operators have sunk a number of vertical wells and less-developed areas that have set investors’ imaginations racing.
Well results from Noble Energy have demonstrated the benefits of horizontal drilling in areas rife with vertical wells. Remember that these vertical wells only come into contact with a small fraction of the oil-rich shale. Noble Energy’s tests indicate that the average horizontal well in the Wattenberg yields 10 times the IP rate of a vertical well, seven times the recovery and double the return.
As of this writing, much of the Niobrara has yet to be de-risked. Third-quarter conference calls from EOG Resources and Noble Energy should include additional well results and could provide insight into each company’s 2011 drilling program. Rest assured that we’ll be monitoring these developments closely.
In recent quarters a trend has emerged among US-based E&P outfits. Buffeted by depressed natural gas prices and a surfeit of supply, operators are scaling back spending on natural gas production while announcing plans to boost output of oil and natural gas liquids (NGL).
Come to think of it, I don’t think I’ve listened to a single conference call from a major US-based E&P lately that hasn’t included at least a handful of slides showing their projected shift from natural gas to oil production over the next few years.
EOG Resources was among the first E&Ps to begin this transition, securing territory in key US unconventional oil fields roughly four years ago. This foresight should pay off: The company has amassed substantial acreage in the most prospective areas of five major shale oil plays: the Eagle Ford, the Bakken, the Niobrara the Barnett Combo and the Leonard Shale.
This rapidity with which management implemented this new strategy is staggering. In 2007 natural gas accounted for 77 percent of EOG’s revenue; in 2010 management expects liquids to garner 63 percent of its revenue from liquids output, of which three-quarters will be oil. NGL production will contribute the remaining quarter of liquids-related revenue.
Expect this trend to continue over the longer term. Management estimates that in 2011 and 2012 EOG roughly 80 percent of EOG’s capital expenditures (CAPEX) will be funneled into oil and liquids-rich natural gas production. The remaining 20 percent will support key natural gas operations, including holding acreage and advancing its efforts to export liquefied natural gas (LNG) from North America. (We discussed its Kitimat LNG joint venture in the Sept. 26, 2010, issue of The Energy Letter, Cheniere Energy Partners and LNG Exports.)
In total, EOG expects to grow oil production by 65 percent in 2011 and 40 percent in 2012. Natural gas output, on the other hand, will be flat in 2011 and increase by just 13 percent in 2012.
The stock slipped after the firm announced its second-quarter results, primarily because oil output fell short of expectations. This shortfall stemmed from delays in completing new wells and putting them into production, not poor well performance. EOG should work through that backlog in the third and fourth quarters, so long-term production goals remain within reach.
Here’s a look at each of EOG’s main horizontal oil and NGL plays.
Eagle Ford Shale
At a recent industry conference, EOG described the Eagle Ford as its biggest and best play. The company boasts 580,000 acres in the region: 505,000 acres in the play’s oil window, 26,000 acres in the NGL-rich window and just 49,000 in the dry-gas window. The company estimates that its holdings contain potential (not proven) reserves of 900 million barrels of oil equivalent (BOE), 77 percent of which is oil and 11 percent of which is NGLs.
The company has already drilled between 50 and 60 horizontal wells in its Eagle Ford acreage and has shared results from more than half of these wells. Several producers have drilled vertical wells in the region for as many as 25 years. This production history, coupled with two to 14 months of ongoing production results from horizontal wells, makes EOG confident in its reserve estimates.
Results from the 31 wells for which it has results have been remarkably consistent, showing initial production (IP) rates of 600 to more than 2,000 BOE per day.
Reserve and production estimates likely will head higher as EOG hones its drilling techniques to maximize output and efficiency.
The company continues to experiment with lateral lengths, spacing and completions on the wells it’s drilling. EOG’s efforts to identify the best production techniques may already be paying off. New wells Brothers #3H and Brothers #1H, which featured longer horizontal segments and benefited from additional three-dimensional seismic data, yielded IP rates of 2,075 and 1,365 BOE per day, respectively. That’s near the top end of the company’s well results in this area.
These incremental improvements to drilling efficiency also counteract the rising cost of key services such as pressure pumping. EOG expects these efforts to reduce costs to between $4.5 and $5.5 million for each well drilled.
Management estimates that the average well in the northwest portion of the Eagle Ford holds 385,000 recoverable barrels of oil. Recoverable reserves on the typical well in the southwest portion are pegged at roughly 254,000 barrels.
With crude in the neighborhood of $80 a barrel, EOG is earning attractive returns on its oil wells. And the company should be able to boost its potential reserve estimates over time as it optimizes production methods, drills more wells and proves longer production results from existing wells.
As of its most recent update, EOG had drilled some 25 wells that were awaiting production and assessment. Expect to hear more about results from those wells when the company reports third-quarter results on Nov. 3. And with 245 wells scheduled for completion next year, a steady stream of drilling results and reserves updates should provide plenty of upside catalysts for the stock.
EOG was also one of the first movers in the Bakken Shale, producing and testing wells in the region back in 2006. EOG has assembled about 580,000 net acres and estimates total potential reserves at 420 million BOE. The average well in the region yields more than 80 percent crude oil and roughly 10 to 15 percent NGLs.
The most recent well results in what management refers to as the Bakken Core have been in line with previously drilled wells. The Van-Hook 7-23H and Fertile 37-07H wells flowed at IP rates of 2,525 and 1,654 barrels of oil per day, respectively.
EOG also recently tested wells located in the western part of its acreage, near the border of North Dakota and Montana. Results from these wells resembled those from other wells in the Bakken Lite, suggesting that EOG’s holdings are productive across a wide geographic area.
The firm also continues to experiment with longer lateral segments and well spacing to optimize production. One of EOG’s latest tests spaced wells at intervals of 1,280 feet and included longer lateral segments, an approach that yielded an IP rate of 1,036 barrels per day. More well results on these tests are due before the end of the year.
In total, EOG plans to drill 42 wells in the Bakken Core, 57 wells in the Bakken Lite and 18 wells in the Three Forks-Sanish. The latter appears to generate results and economics that resemble wells in the Bakken Lite.
The Barnett Shale, located near Fort Worth, Texas, was the first major unconventional gas play to be widely exploited in the US. But the field’s northern reaches also contain large volumes of oil and NGLs. EOG is the only major producer with significant exposure to the Barnett Combo and holds about 156,000 net acres in the core of this liquids-rich play. Management estimates the Barnett Combo’s total potential reserves at 370 million BOE.
Results from the Bray #1H and Bray #2H wells yielded 452 and 528 barrels of oil per day, respectively, along with roughly 2 million cubic feet per day of NGL-rich natural gas.
EOG had planned to drill a balanced mix of 126 horizontal and 120 vertical wells in the eastern reaches of the Barnett Combo play–until horizontal well results trounced IP rates on the vertical ones. Now the firm will sink 200 horizontal wells and just 34 vertical wells, a move that should improve average well economics.
Although this 25,000-acre expanse in the eastern portion of the play likely contains the most oil, the geology is by far the most challenging. Results from its first horizontal wells suggest that EOG is learning the best ways to produce this portion of the play.
With a number of new wells in the works, the company expects production from the Barnett Combo to increase significantly in the second half of 2010.
The Leonard Shale is a small play in the Permian Basin, along the border of Texas and New Mexico. Of the 120,000 acres EOG holds in this field, the company has drilled on only 31,000 of these acres and has completed seven horizontal wells.
Early results indicate that each well generates about 400,000 BOE worth of reserves. Output consists of about 41 percent oil, 31 percent NGLs and 28 percent natural gas. At this juncture, management estimates total possible reserves at 65 million BOE.
Recent wells drilled in the region have produced 400 to 800 barrels of oil per day and 1.2 to 2 million cubic feet of gas, a production mix that suggests similar economics to wells in the Barnett Combo play.
EOG holds 400,000 acres in Colorado’s Niobrara Shale and had four rigs working the play at the end of the second quarter. In its most recent update, management released well results from two drilling sites, the Critter Creek #01-03H and the #04-09H, each of which produced roughly 600 barrels of oil per day. But both wells were operated at restricted rates, so these initial figures may not reflect the full potential of these wells. Other wells drilled by EOG since late 2009 have generated IP rates as high as 1,558 barrels of oil per day and 350,000 cubic feet of gas.
Having drilled only a handful of wells in the Niobrara, management believes it’s too soon to estimate the play’s total reserves. However, with further well results likely over the next few quarters, look for the company to begin estimating reserves. This news should help Wall Street gain additional confidence in the field’s predictability.
Although this issue focuses on North American oil and NGLs plays, it’s worth mentioning EOG’s sizeable positions in the cheap-to-produce Haynesville Shale of East Texas and Louisiana and its potential 9 trillion cubic feet of reserves in British Columbia’s Horn River Play.
Management correctly believes that it won’t get full value from ramping up gas production in the current environment, but these will be premier holdings when leasehold drilling peters out and natural gas prices recover.
EOG’s most exciting natural gas-related prospect is its 49 percent stake in the proposed Kitimat LNG export terminal in British Columbia, a facility that would ship LNG to gas-hungry Asian markets. E&P giant Apache Corp (NYSE: APA) owns the remaining 51 percent of the facility.
The two Kitimat partners are in preliminary negotiations to sign long-term contracts where the price of LNG exported from the terminal is linked to oil prices. Such contracts are typical in Japan and South Korea.
If completed, the facility would substantially boost the value of EOG’s Horn River play and provide a welcome release valve for its gas production.
One of the best-placed companies in most of the major and minor US oil- and NGL-rich plays, EOG Resources is a buy up to 115.
Brigham Exploration (NSDQ: BEXP) has onshore properties in the Gulf Coast, as well as in the Anadarko basin and West Texas. But the stock’s performance and future growth prospects are heavily leveraged to the Bakken and Three Forks plays in North Dakota and Montana.
The company first began accumulating acreage in the Williston Basin in 2005, and the vast majority of its planned CAPEX is concentrated on the region. Most of Brigham Exploration’s acreage and drilling activity has historically been in North Dakota, though the firm is drilling wells to establish the value of its acreage in eastern Montana.
In total, Brigham holds 368,400 net acres in the Williston Basin: 154,400 net acres in the Rough Rider region of western North Dakota; 98,700 acres located to the east of Rough Rider; and 115,300 acres across the border in eastern Montana.
Brigham has completed a total of 36 horizontal wells in the Bakken and Three Forks plays, with an average peak production rate of 2,684 BOE per day. The outfit has also drilled some of the Bakken’s top producers, including the Sorenson, which yielded an IP rate of 5,133 BOE per day. With an IP rate of 4,675 BOE per day, the Domaskin is another recent gusher.
Based on these successful wells, management has identified 571 potential developments in its core Williston holding, an expanse that totals 200,000 net acres. As of the beginning of October, the company had five rigs operating in this region, with plans for a sixth rig to start drilling later in the month and an additional two rigs to be added in early 2011.
At this rate, Brigham would drill these 571 development locations over a period of 13 years. Management estimates that each of its horizontal wells in this core area can generate recoverable reserves of 500,000 to 700,000 BOE.
The stock offers exposure to two additional upside catalysts.
In early October Brigham announced that it completed its first well in the Rough Rider region. Although this isn’t the first well Brigham has drilled in the deposit, all of its other wells had been drilled further east, in North Dakota. A long horizontal well fractured in 31 stages, the site yielded an IP rate of 2,356 BOE per day, suggesting that the Three-Forks Sanish could be productive throughout the Rough Rider area.
More testing is necessary, but if future wells are similarly prolific, it would add approximately 362 potential development locations to Brigham’s inventory.
In Montana, Brigham has completed a single well that initially produced 909 barrels of oil per day. Two additional wells are slated to be completed in Montana–one this month and one in November–and a number of other producers, including EOG Resources, already have completed economic wells in the region. Depending on these well results, Brigham has estimated that it could identify as many as 667 development sites in Montana.
By the end of 2010, Brigham expects to produce about 7,400 barrels of oil per day, up from 5,584 in the second quarter and just 2,867 in the fourth quarter of 2009. As it ramps its drilling fleet to eight rigs, production growth should continue apace.
But the real upside for Brigham will come from de-risking its acreage in eastern Montana and the Three Forks formation in western North Dakota.
Brigham’s laser-like focus on the Williston Basin means it isn’t as well diversified EOG Resources. In addition, Brigham is still a relatively small producer, so most of its market value is based on future drilling success rather than actual results. But with a clean balance sheet, heavy focus on oil production and plenty of upside catalysts, Brigham Exploration rates a buy in my Energy Watch List.
Continental Resources’ (NYSE: CLR) three most important plays are the Bakken, the Niobrara and the Woodford Shale. Crude oil accounts for roughly three-quarters of the company’s production, making it among the most oil-levered E&Ps in my coverage universe.
In 2010 management expects the firm to produce about 15,800 BOE per day and recently boosted its 2011 guidance to 20,600 barrels. If the company reaches its goal of producing 41,000 BOE per day by 2014, that would represent an annualized growth rate of nearly 25 percent.
Here’s an overview of the company’s oil plays.
Boasting 864,559 net acres, Continental is the No. 1 leaseholder and most active driller in the Bakken. The company estimates that a total of 56 percent of its reserves are in the Bakken–43 percent in North Dakota and 12.4 percent in Montana.
At a recent analyst day, Continental increased its estimate of total recoverable oil in the Bakken to 24 billion barrels, six times the figure provided by the USGS in 2008. There’s no way to know whether Continental’s forecast is correct, but given the firm’s acreage and experience, it would be foolhardy to ignore management’s prognostication. In any event, such a large reserve estimate suggests that Continental’s confidence in its own holdings remains undimmed.
About 72 percent of the company’s total acreage has been de-risked and is now in development. The company has 21 rigs operating in the Bakken and plans to ramp that up to about 23 rigs by the end of 2010.
As the company becomes more familiar with the play, the efficiency of its drilling operations has increased considerably. In June 2008 it took the firm more than 60 days to drill a well; these days that number has decreased to 30. Concomitant with shorter drilling periods, 30-day average production rates also have increased to 623 BOE per day in the third from 603 BOE per day in the prior quarter. Consider that in the first quarter of 2009 the average 30-day production rate was just 209 BOE per day.
It’s important to note that these are 30-day average production rates, not the maximum initial production rates quoted by some producers.
The company’s ECO-Pad drilling technology enables the firm to drill wells in pairs, with two wells targeting the Bakken formation and the adjoining two targeting Three Forks-Sanish. This innovation reduces costs by increasing the speed at which the firm can drill wells. Its first ECO-Pad experiment showed an IP rate of 4,359 BOE per day for the four wells.
By the end of 2010, Continental will have five rigs working on ECO-Pad projects. Management also sees the potential to double its pleasure again and drill a total of eight wells (four in each formation).
Based on recent drilling results, the company has hiked its estimated recoverable reserves per well drilled to 518,000 BOE and has identified 3,394 development locations in the Bakken. All told, management’s calculations suggest that its acreage contains north of 500 million barrels of potential reserves.
If the firm’s experiments with its ECO-Pad technology continue to succeed and Continental is able to decrease the spacing between wells, the firm could unlock an additional 700 million barrels of potential reserves.
Typically regarded as a natural gas play, Oklahoma’s Woodford Shale has been dismissed by many analysts because the well economics aren’t as attractive as those in the Haynesville and Marcellus. But like many unconventional fields, the Woodford features distinct production windows; natural gas predominates in the play’s northern and western parts, while production becomes oilier its southern and eastern reaches.
Continental estimates that about 42 percent of total production is crude oil and 28 percent is NGLs, with natural gas accounting for the balance.
Continental has six rigs operating in the Woodford and plans to boost its rig count to eight by year-end. Although the economics of this play can’t match the Bakken because of ultra-low gas prices, management estimates that the oilier portions can generate a nearly 40 percent internal rate of return.
Consider the case of Ballard 1-17H, a well in the field’s southeastern corner. This site produced around 750,000 cubic feet of gas per day and 200 barrels of oil. Moreover, the gas produced contains around 1.35 million British thermal units (BTU) per 1,000 cubic feet, thanks to the presence of high-BTU NGLs. That’s compared to a standard of about 1 million BTUs.
According to Continental, all of these hydrocarbons add up to roughly $8.50 per thousand cubic feet of natural gas. With more than 250,000 acres in the field, the firm is the region’s top leaseholder. Even a modest improvement in natural gas prices–a likely outcome in the second half of 2011 as forced leasehold drilling declines–would increase the value of this play, a nice potential catalyst for the stock.
Continental drilled vertical wells in the Niobrara shale back in 1989. What a difference two decades make. Today, the firm boasts 73,000 net acres in the Niobrara–three-quarters in Wyoming and the balance in Colorado. Continental further estimates that its acreage contains 53 million barrels of potential reserves and 228 potential drilling locations.
That makes the Niobrara a much smaller play for Continental than either the Bakken or the Woodford. That being said, the company plans to drill its first well this quarter; the results could be a catalyst for the stock into early 2011. Right now, Continental estimates that each well will generate recoverable oil reserves of about 286,000 barrels.
With a leading position in the Bakken Shale and potential growth kickers from its Woodford and Niobrara Shale plays, Continental rates a buy in my Energy Watch List.
One of the major challenges facing Continental and other major Bakken producers is the lack of sufficient takeaway capacity in the region. In other words, existing pipeline infrastructure can’t handle planned production growth.
A lack of gathering capacity for the volumes of natural gas and NGLs produced alongside oil is a common complaint. Although these concerns may seem inconsequential in an oil-focused play, these shortcomings can force producers to limit IP rates from their wells in an effort to match production to available.
Help is on the way. Master limited partnership (MLP) Oneok Partners LP (NYSE: OKS) plans to spend $1.4 billion over the next few years to build out its natural gas and NGL infrastructure to accommodate increased production.
Already the region’s largest independent processor, Oneok boasts extensive assets in the area. Here’s the lowdown on some of its major planned expansions.
Stateline I, a gas-processing facility with capacity of 100 million cubic feet per day, will cost Oneok $180 million to $205 million to erect and will be completed by mid-2012. This plant will remove NGLs such as propane, butane and ethane from natural gas.
In addition, Oneok plans to spend an additional $120 million to $150 million to upgrade and expand its existing infrastructure in the Bakken and connect new wells to a gathering system for transport to Stateline I. The MLP is also evaluating the potential for a second processing plant, the unimaginatively named Stateline II.
Scheduled to come online by the end of 2011, Garden Creek is a gas-processing plant that will cost $150 million to $210 million to build. Like Stateline I, the facility will be able to process up to 100 million cubic feet of natural gas per day. Oneok will also spend about $200 million on well connects and system upgrades in the surrounding area.
The Bakken Pipeline is designed to carry NGLs south from the Bakken Shale to Colorado’s Overland Pass Pipeline in Colorado. The pipeline would cost $450 million to $550 million and could transport up to 60,000 barrels of NGLs per day.
By connecting to the Overland Pipeline, Oneok can then transport NGLs east to its fractionation facility in Bushton, Kan. Once the fractionation plant is expanded, the facility will be able to separate 210,000 barrels per day of NGLs into their constituent parts.
And because the Bakken Pipeline would wend its way through the heart of the Niobrara Shale, it could also service that play as production heats up.
Management expects the new pipeline and expanded fractionation plant to come online in the first half of 2013.
Like other midstream MLPs, a significant portion of Oneok’s cash flow is guaranteed under long-term, fee-based contracts. In this case, fee-based businesses account for 70 percent of the firm’s total revenue, meaning that the MLP has some exposure to natural gas-processing and fractionation economics.
The partnership’s exposure to commodity prices should decline in coming years as new projects come online. In the mean time, management will continue to hedge out some of this risk.
That being said, Oneok isn’t fully hedged this year, and its unhedged exposure to NGL and natural gas prices only increases in 2011.
Higher NGL prices increase demand for processing and fractionation and make the economics more attractive; investors in Oneok should watch NGL prices closely. These days, the outlook is sanguine.
This summer brought concerns about an oversupply of some key NGLs–chiefly ethane, the most common NGL by volume–the price of a mixed barrel stands at between 57 to 60 percent of what a barrel of crude oil would fetch. That’s roughly in line with the long-term average.
Moreover, demand for NGLs continues heat up. Key petrochemicals such as ethylene and propylene–the base materials used to make a variety of plastics–can be synthesized from either NGLs or by refining and processing crude oil.
NGL prices in the US are extremely attractive relative to most other regions in the world, so US petrochemical plants are operating at utilization rates of more than 90 percent. There’s also a burgeoning export market for US NGLs.
These fundamentals support continued strength in NGL prices and Oneok’s processing margins. Still, investors should watch these dynamics like a hawk.
Management projects that the MLP’s distribution will increase $0.01 per quarter throughout 2011, followed by annualized growth of 5 to 10 percent as new projects come online in 2012-13. That’s measurably better than the less-than-4-percent annualized rate at which Oneok’s distribution has grown over the past three years.
That would put quarterly distributions at $1.17 by the end of 2011 and as high as $1.34 by the end of 2013.
I’m adding Oneok Partners LP to the Energy Watch List as a buy and may look to add it to the model Portfolio on a pullback. Yielding 5.7 percent, the MLP is a way for income investors to profit from production growth in the Bakken.
For those unfamiliar with MLPs, I discuss this security class and its tax-advantages in the April 1, 2010, issue of The Energy Letter, Master Limited Partnerships and Taxation, and the May 19, 2010, issue of this publication, The Big Picture: Energy Stocks and Europe’s Debt Crisis.
For the time being, investors interested in playing infrastructure related to shale oil should buy Proven Reserves Portfolio bellwether Enterprise Products Partners LP (NYSE: EPD). This longtime favorite recently inked a 10-year deal with EOG Resources to transport oil over a 140-mile pipeline that will serve the Eagle Ford.
And this is just the beginning. Enterprise owns considerable assets in the Eagle Ford that are well placed to serve the rapid increase in production over the next few years. In a sign of strength, the MLP raised its quarterly payout to $0.5825, up from $0.5525 in the same quarter one year ago. That’s Enterprise’s 25th consecutive quarterly distribution increase, an amazing record of consistency.
In light of these developments, I’m boosting my buy target on Enterprise Products Partners LP from 38 to 42.
Whiting Petroleum Corp’s (NYSE: WLL) production profile consists of 80 percent oil and just 20 percent natural gas. It’s the second-largest producer in the Bakken and a major producer in the Permian Basin and Mid-Continent.
Whiting holds 532,266 net acres in the Bakken and Three Forks. A little over 100,000 of these acres are in Montana, and the balance is in North Dakota. Of that acreage, nearly 90 percent has yet to be developed, leaving Whiting with a great deal of high-potential drilling targets to pursue.
In 2010 the firm plans to complete 90 new wells in the Sanish, plus eight wells where it’s a participant but not an operator. The company has a long history of drilling in the Sanish, and average IP rates on its wells continue to increase.
For wells drilled in 2010, average production over the first 90 days is 875 BOE per day; from 2008-10, this figure came in at 724 BOE per day. Management estimates that wells in this core region could generate 750,000 to 950,000 BOE in recoverable reserves. The company’s internal rates of return on its wells exceed 100 percent, among the highest in the industry. Whiting has 67,893 net acres in the Sanish field and 35,304 undeveloped acres.
The largely undeveloped Lewis & Clark field, located in North Dakota’s southwestern Williston Basin, is the company’s biggest acreage position within the Bakken; proving and de-risking the play is essential to Whiting’s growth.
Drilling is underway in Lewis & Clark, and Whiting expects to complete 13 wells by the end of 2010. The company has three operating rigs and plans to increase that count to four by the end of this quarter.
Early results were solid. The company’s first well, Federal 31-4h, flowed oil at an IP rate of 1,970 BOE per day and was producing at a still-healthy 447 BOE per day after 90 days. Two additional wells were completed in late September, with initial production rates in-line with their predecessor. Early results suggest that each Lewis & Clark well will add 350,000 to 500,000 barrels of recoverable oil reserves.
The Bakken shale doesn’t extend into the Lewis & Clark, so Whiting is targeting the Three Forks.
If future drilling results pan out, Whiting’s large acreage position could contain at least 500 potential drilling locations. Certainly, management’s decision to quickly scale up its rig count in the area suggests growing confidence in the play.
While production growth from Whiting’s assets in Texas isn’t quite as exciting as for the Bakken play, this oil-rich production remains a valuable part of the business. In particular, Whiting has initiated tertiary recovery projects for oil in the Postle and North Ward Estes fields, using carbon dioxide injections to re-pressurize the fields and aid production.
Total output from these two fields has jumped from 14,125 BOE per day in the second quarter of 2009 to 17,250 BOE a year later. The company has capital spending plans of $230 million in 2010 for these projects and plans to drill a net total of 18 wells.
Further well results from Lewis & Clark will serve to de-risk the play and should be a major upside catalyst for Whiting; early results suggests the field could be better than most had imagined. I’m adding Whiting to the Energy Watch List as a buy.
At this juncture, the top leaseholder in the Niobrara Shale is Noble Energy, a name whose diversified operations also include deepwater E&P projects in the Gulf of Mexico and West Africa. In addition to the firm’s substantial position in the Wattenberg Field, Noble Energy also has amassed 350,000 net acres in the DJ Basin Niobrara at a low entry cost of $350 per acre.
The firm should drill roughly 20 horizontal wells in the Wattenberg this year as well as nine in the northern part of Colorado, near the border with Wyoming. IP rates on recent wells in this region range between 580 and 845 BOE per day, with liquid content of 70 to 90 percent. Production from the Wattenberg is roughly 53 percent liquids.
Management estimates well costs at roughly $3.5 million–on par with the Bakken–though that will improve over time. Already the firm has lowered the time it takes to drill a horizontal well from 20 days to 13 days. Management has indicated that it will announce a more in-depth drilling plan for the Niobrara at year-end.
Although both EOG Resources and Noble Energy both represent relatively safe plays on the Niobrara because of their diversified business lines and substantial acreage, investors seeking greater leverage to the field should consider Denver-based PDC Energy (NSDQ: PETD), formerly Petroleum Development Co.
Like many independent producers, PDC Energy has announced ambitious plans to shift its production mix to increase its exposure to oil. Today, natural gas accounts for roughly 80 percent of the company’s output; management has announced plans to decrease that exposure to 65 percent.
But unlike other gas-focused E&Ps, PDC doesn’t have to shell out huge amounts of cash or go out on a limb to secure leaseholds in oil-rich plays. The firm has operated in the Rockies for a little less than a decade, with most of its operations focused in the Wattenberg where it owns almost 65,000 acres and operates over 1,400 vertical wells. Roughly 28,000 of these acres are undeveloped.
At an analysts meeting earlier this year, management announced that it would drill two horizontal wells in 2010 and expand this program in 2011. Given the company’s familiarity with the Wattenberg and the success of Noble’s horizontal wells in the play, this effort represents a meaningful and relatively inexpensive source of production growth.
In addition to its position in the Wattenberg, the company also operates in the Piceance Basin, the Marcellus and the Wolfberry. That being said, PDC Energy is a good way for investors to gain concentrated exposure to production growth in the Niobrara.
The stocks recommended in the three model Portfolios represent my favorite picks. The three Portfolios are designed to target different levels of risk: Proven Reserves is the most conservative list; the Wildcatters names entail a bit more volatility; and Gushers are the riskier plays but have the most potential upside.
I realize that this long list of stocks can be confusing; subscribers often ask what they should buy now or where they should start. To answer that question, I’ve compiled a list of 16 Fresh Money Buys that includes 14 names and two hedges.
I’ve classified each recommendation by risk level–high, low or moderate–and included a brief rationale for buying each stock. Conservative investors should focus the majority of their assets in low- and moderate-risk plays, while more aggressive investors should layer in exposure to my riskier and higher-potential plays. Hedges are appropriate for investors looking to offset some of their portfolio’s broader exposure to energy stocks.
Also note that stocks that exceed my buy target for more than two consecutive issues will either be removed from the list or the buy target will be increased. Here’s the list followed by a short update on picks with major news events.
Source: The Energy Strategist
Macmahon issued surprisingly negative profit guidance, citing cost overruns on a major rail contract in Western Australia. Although management declined to name the contract in question, it’s likely the Pilbara rail expansion construction for BHP Billiton (NYSE: BHP).
The main reason to own Macmahon is that the company’s contract mine and mine infrastructure business is leveraged to growth in Australia’s mining industry and, in particular, growth in the coal exports to Asia.
This investment thesis remains intact, and the company’s profit shortfall doesn’t suggest a slowdown in growth prospects for coal. Rather, Macmahon’s troubles are company-specific; costs related to this project have overrun expectations, but the firm is contractually bound to deliver the project at a pre-arranged cost.
Cost overruns aren’t particularly uncommon at construction firms, but this is a significant miss and the company has indicated it won’t be able to provide much in the way of additional details until its annual meeting in November.
When I added rated Macmahon to the Gushers Portfolio in the Sept. 22, 2010, issue, I noted that it was a higher risk pick because it’s a small firm leveraged to a handful of major projects like Pilbara–a miss on one deal can cause a significant shortfall in results.
The initial reaction like will prove too harsh, but the market abhors the lack of clarity; I don’t expect much upside for the stock until after the firm’s annual meeting.
Over the long term, Macmahon remains well positioned to benefit from growth in Australia’s mining industry. For now, I don’t recommend buying into the stock.
I’m adding two new picks to the Fresh Money Buys list: EOG Resources, profiled at great length in this issue, and Cameron International (NYSE: CAM), which I added to the model Portfolios in a recent Flash Alert. Cameron International is a buy under 46. Also note that I have boosted my buy targets on a handful of Fresh Money Buy candidates to reflect the recent rallies.
Nabors Industries (NYSE: NBR) is a land-focused contract driller. Nabors specializes in advanced high-power rigs that are needed to drill the long lateral segments in America’s unconventional oil and gas fields. The company is the leading drilling contractor in several key shale fields, including the Bakken, and is an outstanding play on the oil plays outlined earlier in this report.
Weatherford International (NYSE: WFT) reported earnings earlier this week, generally beating earnings forecasts. The company enjoyed another strong performance in North America, but some analysts felt that the pick-up in the company’s international business has been slower than expected. Weatherford International also issued better-than-expected guidance for 2011.
The stock pulled back in response to this release, and financial journalists have come up with all sorts of fundamental reasons to explain the drop. The reality: Weatherford International’s stock surged from about $12.50 at the beginning of July to around $19 before this release. After such an impressive run, investors were looking for any excuse to book profits.
The post-earnings drop only erased about five trading days’ worth of gains, and I saw nothing in the report to suggest that the company’s growth prospects have changed. Use this temporary dip to buy shares of Weatherford International up to 26.