Exploration and production (E&P) companies are among the last in the energy sector to report quarterly results. Fourth-quarter reports and conference calls are arguably the most important of the year, as management teams often discuss new plays they’re developing or results from important well tests.

The larger E&P firms make a habit of commenting on big picture issues such as changes in pricing for rigs and key drilling-related services and, of course, their expectations for commodity prices. This is invaluable information for determining an individual company’s prospects as well as identifying important trends that may impact its peers or other energy-related industries.

In This Issue

The Stories

The Securities and Exchange Commission’s (SEC) new reserve reporting requirements went into effect, but these changes won’t have a meaningful impact on stock valuations. I review how I evaluate exploration and production (E&P) names. See Reserves and the SEC.

EOG Resources (NYSE: EOG) is a key portfolio holding and one of the top E&P names for investors seeking long-term growth. I examine the company’s fourth-quarter earnings report. See The Rundown.

Management’s comments during EOG Resources’ (NYSE: EOG) conference call provide updates on certain key macro trends. See The Big Picture.

I discuss how other Portfolio recommendations will fare in 2010 based on macro trends and developments at the company level. See How to Play It.

The Stocks

EOG Resources (NYSE: EOG)–Buy @ 110, Stop @ 57.50
Nabors Industries (NYSE: NBR)–Buy @ 28, Stop @ 17.50
Baker Hughes (NYSE: BHI)–Buy @ 51, Stop @ 36
Range Resources (NYSE: RRC)–Buy @ 60, Stop @ 40.75
Petrohawk Energy (NYSE: HK)–Buy @ 30, Stop @ 17.50
Anadarko Petroleum (NYSE: APC)–Buy @ 75, Stop @ 55
Tenaris (NYSE: TS)–Buy @ 47, Stop @ 31
Valero Energy Corp (NYSE: VLO)–Buy @ 19, Stop @ 15.65

Reserves and the SEC

Some analysts and pundits spend considerable time scrutinizing changes in a particular E&P outfit’s reserves over time. This has led to considerable uncertainty heading into 2010 due to some changes in the Securities and Excange Commission’s (SEC) reserve reporting requirements that went into effect this year. These represent the first major changes to SEC rules governing reserves since 1982.

Without going into all the gory details, suffice it to say that under the old rules companies could only establish proved reserves through well flow data and production tests. Under the new rules, companies can establish reserves using newer technologies such as seismic data. In addition, companies will be allowed to provide a more detailed look at reserves rather than focusing exclusively on proved reserves. That change is meant to give investors a clearer picture of a company’s true reserve base and prospects for future reserve additions.

In addition, reserves are calculated based on what is economically recoverable at a certain price. Under the old rules that reference price was the closing price of oil and gas at the end of the year. The old system clearly distorts results because the price on the last day of the year may or may not reflect conditions over the course of the year. This is particularly true for natural gas prices, which are subject to seasonal factors and are relatively volatile. And volatility has become the norm rather than the exception in recent years. Under the new SEC system, the reference price will be based on the monthly average price over the course of the year.

Finally, the new rules allow companies to report unconventional oil sources such as oil sands as proved reserves rather than just conventional oil.

These changes shouldn’t have any lasting effects on the valuations of E&P companies in my coverage universe. Companies have been providing additional information about their developing plays for many years, even when they were unable to book reserves from those plays as “proved” under SEC rules. And no analyst worth his or her salt would ignore unconventional oil reserves held by an E&P just because those reserves didn’t meet the SEC’s official definition of proved reserves.

In short, investors and analysts have known about the problems inherent under old SEC rules and had adjusted their expectations and valuations accordingly. These regulatory changes reflect the industry best practices and the realities of the modern E&P business. However, to the extent that the new rules afford companies the opportunity to offer more information and eliminate the quirks of the old system, the change is a modest positive.

Furthermore, identifying the best-placed E&P names isn’t as easy as looking at a company’s market value relative to officially proved reserves. If that were all it took to pick winners, the investment process would be a great deal easier than it is.

I look for a few key traits in E&P stocks I recommend in The Energy Strategist. Although a number of factors drive an individual E&P outfit’s performance over time, production growth is the most powerful. The table below provides a closer look.

Source: Bloomberg

To create this table I examined companies in the Philadelphia Oil Exploration & Production Index that have already reported earnings and production figures for 2009.

Looking at total production of oil and natural gas in millions of barrels of oil equivalent, I calculated both five-year total production growth and five-year production growth per outstanding share. I then calculated a five-year total return assuming all dividends were reinvested. A cursory examination shows that higher production growth and, in particular, higher production growth per share tends to match up well with total return. That is, the higher the growth rate, the higher the return.

That being said, the table features a few outliers. For example both Wildcatter Portfolio holding EOG Resources (NYSE: EOG) and Denbury Resources (NYSE: DNR) generated returns that rank near the top of the list, though production growth for both firms was in the middle of the pack. One logical explanation for these exceptions is that both EOG and Denbury have focused on crude oil production rather than natural gas.

It’s easier to grow natural gas production than oil production. And oil prices have held up better over the past 18 months than gas prices; producing oil has been more profitable lately. Logical exceptions like EOG and Denbury don’t vitiate the basic pattern.

Of course, it’s a great deal easier to evaluate production growth potential after the fact than on a going-forward basis.  But simply looking at an E&P firm’s officially proved reserves doesn’t reveal much about its growth potential. I prefer to examine where a company’s reserves are located.

For gas producers, exposure to high-growth, relatively low-cost gas plays like the Haynesville Shale of Louisiana is desirable. The performance of a particular E&P’s wells relative to its competitors is another key consideration. The Haynesville Shale encompasses a huge area, but acreage near the center of the play is worth a great deal more than acreage at the periphery. And in the more-established Barnett Shale near Fort Worth, Texas, wells in the core of the play can be as much as five to 10 times more productive than those on the outskirts.

When selecting which stocks to recommend, I also look for upside catalysts–developments that could have a positive impact on the stock. For Portfolio holding Anadarko Petroleum Corp (NYSE: APC) that catalyst is a series of wells that will be drilled off the West African coast in 2010; the deepwater off the shores of Ghana, Sierra Leone, Liberia and the Ivory Coast is emerging as of the most promising and fast-growing oil-producing regions in the world.

And as I’ll explain below, Wildcatters Portfolio holding EOG Resources has an emerging catalyst: a number of new horizontal oil plays it’s evaluating around the US. Management has dubbed these prospects “stealth oil plays” and plans to release more details at an analyst meeting on April 7.

The Rundown

North American producer EOG Resources (NYSE: EOG) continues to transition from its longstanding focus on natural gas to a company whose production mix is evenly split between oil and gas. On an energy equivalent basis, 76 percent of EOG’s production was natural gas in 2006, compared to 64 percent last year. Management expects natural gas to account for just 55 percent of production this year and 50 percent by 2011 or 2012. The company forecasts that liquid hydrocarbons will generate 50 percent of its revenues in 2010.

At the beginning of last year, management estimated that production would grow 3 percent in 2009 and steadily increased that estimate to 6 percent over the course of the year. But production was up 6.5 percent from a year ago, more than twice the company’s original estimate. Most of that upside stemmed from better-than-expected production of oil and natural gas liquids (NGL); in 2009, oil production grew 21 percent, while NGL output was up 48 percent.

Management expects production growth to pick up substantially in 2010, with oil once again leading the way. The company estimates that production will increase a whopping 13 percent–double its 2009 performance. Management expects oil production to expand 55 percent, a 28 percent jump in its output of NGLs and a 2 percent increase in natural gas.

Higher oil prices undoubtedly contributed to these growth projections; with the recovery in energy markets, EOG has more capital and cash flow to reinvest in its drilling programs than it did at the beginning of 2009. That EOG is able to ramp up its production quickly to benefit from higher oil prices is a sign of the quality and scalability of its horizontal oil plays.

Two major plays are driving EOG’s production growth: the Bakken Shale, and the Barnett Combo Play. I’ve written extensively about these plays in previous issues, but EOG has announced important new information about both fields.

Before discussing these fields, however, it’s important to make a key point: The Bakken and EOG’s other shale plays are not oil shale plays but shale oil fields. I explained this important distinction in the Nov. 4, 2009, issue of The Energy Letter, Oil Shale versus Shale Oil. To summarize, oil shale is a rock that contains a substance known as kerogen that can ultimately be refined into oil and related products. To produce kerogen, companies traditionally heat the kerogen to extreme temperatures so that it could be pumped to the surface. Alternatively, the kerogen could be mined and heated on the surface.

This is not what EOG is producing in the Bakken or any of its other shale oil plays. The Bakken contains actual crude oil, not kerogen or bitumen (oil sands). In fact, EOG has said in prior calls that the quality of Bakken crude is actually the same or slightly better than West Texas Intermediate (WTI), the US standard grade of crude that’s the basis for the NYMEX futures contract.

The Bakken and Barnett Combo plays have more in common with unconventional natural gas fields like the Haynesville than they do with kerogen shale oil plays. The crude in the Bakken is locked in an impermeable shale reservoir rock–in other words, the field contains plenty of oil, but there’s no way for that crude to naturally flow into a well. To produce this oil, EOG drills a horizontal well through the Bakken shale, exposing more of the well to the productive part of the play. EOG then fractures these fields by pumping a liquid into the ground under tremendous pressure, creating cracks and fissures that facilitate the flow of oil into the well.

The Bakken Shale

The Bakken Shale stretches across North Dakota, Montana and parts of Canada. The bulk of EOG’s play is located in North Dakota in an area known as the Parshall Field and includes 00,000 leased acres–among the largest land positions of any major oil company in this core part of the Bakken. EOG plans to drill 35 new wells in this part of the field in 2010, each of which should generate about a 100 percent after-tax rate of return.

The company also has significant acreage outside this core area in an area it calls the Bakken Lite. EOG announced that it had drilled a well called Round Prairie 1-17H in a new area of the Bakken Lite located 90 miles to the west of the Parshall, close to the border between North Dakota and Montana. The firm sank this “step-out well” to prove the viability of the western reaches of its Bakken Acreable. Although the well wasn’t as productive as those in the Parshall, it had a solid initial production (IP) rate and currently yields 450 barrels of oil per day.

EOG plans to drill 72 wells in the Bakken Lite this year and expects these projects to generate a 35 percent after tax rate of return.

And the Bakken isn’t the only productive rock layer underneath EOG’s acreage in North Dakota and Montana. EOG has drilled several wells to test the Three Forks Formation. The last three wells drilled were the Van Hook 100-15H well, which produced oil at an initial rate of 1,390 barrels per day; the Austin 101-15H well, which had an IP rate of 510 barrels per day; and the Burke 100-20H well, which had an IP rate of 430 barrels per day.

Management expects that the Three Forks Formation will generate returns and production rates similar to those in the Bakken Lite.

EOG is also experimenting with longer laterals, or the length of the horizontal segment in a well. To date, the company primarily has drilled midsize wells with a lateral that measures 5,000 feet. The company tried a lateral that stretched 7,100 feet in the Bakken and believes this approach is roughly one-and-a-half times more productive. Although this isn’t a stellar improvement, I suspect EOG will continue to test even longer wells.

Bottom line: The Bakken Shale is a proven productive play, and EOG has solid exposure to the field’s core regions. The company is now testing some of the more marginal acreage outside the core and finding that returns on investment remain solid at current oil prices. All of this suggests EOG has years of impressive production growth ahead of it in this region.

Barnett Combo

The Barnett Shale is best known as a natural gas play, as the Barnett was the first major US unconventional gas field to be developed. This is where George Mitchell, widely considered the father of shale gas, pioneered the techniques that have dramatically changed the outlook for US gas production.

But north of Fort Worth, Texas in Montague county the Barnett is an oil play, and EOG is more or less the sole holder of acreage in this field.

As in the Bakken Shale, EOG is testing various alternative development strategies in the Barnett Combo. Recent drilling results bear out what management has asserted for some time: Wells show IP rates of between 250 and 1,000 barrels of oil per day, plus around 130 barrels per day of NGLs and 1 to 2 million cubic feet of natural gas.

EOG plans drill aggressively in the Barnett Combo this year and expects to sink 120 vertical wells and 126 horizontal wells.

Emerging Oil Plays

EOG has also drilled a series of wells in two emerging plays: the Waskada Field in Manitoba and the Cleveland Field in the Texas Panhandle. These are primarily unconventional fields like the Barnett and Bakken that EOG produces using horizontal wells and fracturing. 

EOG noted that it has achieved initial production rates as high as 1,000 barrels per day in the Cleveland and plans to drill 24 wells in the region this year. The firm must be earning impressive returns in Waskada; it drilled just 48 wells in 2009 and plans to sink in 2010.

The question-and-answer (Q&A) session from EOG’s fourth-quarter conference call also yielded some interesting tidbits. Analysts peppered CEO Mark Papa with questions about various new horizontal oil plays, including the promising Niobrara field in northern Colorado and southern Wyoming. Another inquired about why EOG’s costs spiked this quarter; management noted that the firm is investing in new acreage and drilling in new shale plays.

Papa reminded listeners that EOG does not comment on new plays while they’re still leasing acreage. When a company leases land this becomes public record, giving rise to rumors about massive new plays that a particular company is targeting. But E&P outfits generally don’t highlight their most promising plays; such an announcement would invite competition and increase lease prices. EOG’s management team has dubbed these new prospects as stealth oil plays.

The CEO also intimated that more details about these stealth plays would be forthcoming in EOG’s analyst meeting on April 7:

I think it’s a pretty open secret that we spent a lot of money on leasehold for the stealth oil plays last year. And, of course, all that’s reflected, would be reflected, in whatever mining costs you calculate…we’re going to look back, and 2009, I think, will be viewed as a positioning year for EOG relating to horizontal oil plays. And again, what I would ask of you–I know you’re going to –everybody out there is going to calculate reserve replacement in a different way, but what I would say is that you will get a pretty clear picture in early April of kind of a lot more of the items relating to EOG.

In our model Portfolios, EOG is a longer-term play on unconventional oil and the company’s prospects for production growth. But traders always look for short-term upside or downside catalysts for stocks. I regard the April 7 analyst meeting as just such a catalyst; investors will be excited about the potential for more clarity on the oil stealth plays.

Statements likes this suggest that management was building up expectations during the earnings call; if the company announces a hot new find the stock could pop nicely.

Natural Gas

The bullish story for EOG involves crude oil rather than natural gas. However, it’s a mistake to ignore the company’s positioning in key gas plays. Despite the renewed focus on oil, the firm quickly can ramp up natural gas production as prices recover.

Two plays are worth mentioning: the Haynesville Shale and the Horn River play.

In the Haynesville, the most interesting development this quarter was the Sustainable Forest 5 well. Drilled in DeSoto Parish, La, right in the heart of the Haynesville region, the well didn’t target the Haynesville Shale itself. Rather, Sustainable Forest was drilled into the Bossier Shale, about 200 feet above the Haynesville.

EOG announced that this well generated an IP rate of 13 million cubic feet per day of gas with low NGL content. Management noted that the pressure in the Bossier was equivalent to the Haynesville. In addition, the rock shares certain characteristics with the Haynesville, but management confirmed that gas does not travel between the Haynesville and Bossier layers.

The company believes that the Bossier Shale may be productive in more than half its Haynesville acreage, providing another target inside its existing Haynesville acreage.

EOG’s Horn River Basin in British Columbia, Canada is truly massive. The shale is thick and EOG has drilled several big wells with high IP rates. EOG plans to sink 12 new wells in 2010.

Its horn river properties aren’t receiving as much investment because the region’s infrastructure is lacking; with gas prices still relatively depressed, it’s not as profitable to produce this massive field.

But EOG has signed a memorandum of understanding to supply gas to the Kitimat liquefied natural gas (LNG) export terminal. Located on the west Coast of Canada this terminal could export LNG from Horn River to fast-growing and energy hungry Asian markets.

The Big Picture

EOG’s fourth-quarter conference call produced five key takeaways.

1. Be careful comparing IP rates on wells between different operators. 

It’s common for E&P companies to quote the initial rate at which their wells produce oil or natural gas. However, this can be misleading in some cases; different operators may drill lateral segments of various lengths. It’s likely, for example, that a lateral well of 10,000 feet will produce more than a lateral well of 5,000 feet and exhibit a higher IP. The question is which type of well is a more efficient means of producing a field.

2. Day-rates for land rigs are on the rise as are prices for fracturing services.

This development wasn’t entirely unexpected but does have positive implications for contract drillers and services companies with exposure to North America–for example, Wildcatters Portfolio holding Baker Hughes (NYSE: BHI) and Gushers recommendation Nabors Industries (NYSE: NBR).

During the fourth-quarter Q&A session, an analyst asked the CFO about day-rates (the daily leasing fee) EOG on horizontal land rigs and the cost of performing fracturing work. Here’s the CFO’s response

We’ve been able to contract the rigs that we’re going to need through the next year. We’ve got 39 rigs under long-term, that is like a year contract. Rates are starting to increase in some of the high activity areas. And over the last two or three months, yes, we’ve seen them go up anywhere from 5 to 15 percent. And the same is probably going to relate to stimulation. We expect maybe in 2010 to see stimulation cots creep up in the 5 to 15 percent range as well.

This suggests that EOG has leased enough rigs under one-year contracts to cover its needs, sheltering the firm from rising rates. However, management noted that spot rates–prevailing real-time cost of leasing rigs–are on the rise.

This suggests that operators may be viewing today’s relatively low rates as an opportunity to secure rigs. It also indicates that operators are willing to commit to term contracts in an effort to secure good day-rates. Because Nabors Industries specializes in high-specification land rigs used to drill in shale plays, it stands to benefit disproportionably from this uptick in rates.

In its fourth-quarter conference call, Nabors’ management alluded to the same trends. Its highest-specification rigs–the sort needed to drill shale plays–were available at day-rates of about $13,500 at the nadir of the market in 2009. Now, those same rigs are fetching around $19,000 per day, roughly 40 percent higher.

Management also noted that all of the Nabors’ high-specification units were in use and that producers were willing to agree to five-year leases in order to secure available rigs. The stock pulled back from its highs in early January due to the broader market selloff; based on comments from both EOG and Nabors’ management teams, I view this as a great buying opportunity. Buy Nabors Industries up to 28.

I reviewed Baker Hughes in the Feb. 3, 2010, issue, Earning Their Keep. Suffice it to say the firm’s decision to purchase BJ Services (NYSE: BJS) gives the company significant leverage to improving pricing in the pressure pumping business. Buy Baker Hughes under 51 with a stop at 36.

3. EIA-914 data is skewed and not particularly accurate.

The EIA-914 report is a monthly publication from the Energy Information Administration (EIA) details total US natural gas production as well as production from key states and the Gulf of Mexico.

EIA-914 has been a highly controversial report for some time. Despite a big drop-off in the US rig count after August 2008, the EIA-914 report suggests that US gas production has held up well thanks to prolific production from US shale gas plays.

Feeding the current concern of an ongoing glut of gas is that the US horizontal rig count–a measure of activity in shale plays–recently hit a record high. Although the total US rig count is still well off its 2008 highs, there are more horizontal rigs working today than at that peak.

My own view is that strong production growth from shale plays would likely keep gas prices from replicating the high achieved in 2008. But over the long term, the industry likely requires prices in the $6 to $7 range to meet normal US demand for gas. In addition, as I noted in the Jan. 20, 2010, issue, 2010: The Year for Natural Gas, the US Congress could pass legislation that would encourage the use of natural gas–a major upside catalyst for prices.

EOG’s management continues to assert that this EIA-914 data is skewed. During its most recent conference call, management noted that its own internal model, coupled with its analysis of weather-adjusted natural gas storage statistics, suggests that the EIA underestimates the drop in US production over the past year.

Such an environment would be bullish for gas prices. EOG expects natural gas to average around $6.75 in 2010 and believes prices will remain relatively weak in the first half of the year before heading higher in the second half. The company is also putting its money where its mouth is, leaving its gas production in the back half of the year unhedged to participate in any upside.

4. EOG’s management doesn’t buy the uncompleted well theory.

Skeptical pundits often speculate that natural gas producers have a backlog of wells that they have drilled but have not yet put into production. According to this theory, any rise in gas prices would prompt producers to uncork these wells and flood the market with gas.

EOG’s management stated that the firm doesn’t have a substantial inventory of mothballed walls and emphasized that the consensus has overblown these fears. This supports my bullish stance on natural gas

5. Winter weather has affected operations in certain areas.

Freezing temperatures in the Bakken Shale made it difficult and expensive to fracture well, prompting the company to postpone drilling plans until the weather improves.

Investors should monitor first-quarter conference calls for any weather-related production shortfalls. Such a development wouldn’t necessitate any drastic moves, but I’ll be monitoring this closely when E&P firm’s report first-quarter earnings.

How to Play It

Wildcatters Portfolio holding Range Resources (NYSE: RRC) offers exposure to the Marcellus Shale natural gas play in Appalachia, one of the only US natural gas plays that’s economic to produce at current prices. In 2009, Range Resource’s finding and development (F&D) costs were $4.67 per barrel of oil equivalent compared to $9.67 per barrel at XTO Energy (NYSE: XTO).

Range Resources reported its 28th consecutive quarter of production growth and hit a new production record of 457 million cubic feet per day in the fourth quarter. The company also slightly exceeded the high-end of its production guidance.

Management expects production from its properties in the Marcellus Shale to increase substantially in 2010 and 2011. Range produced a little over 100 million cubic feet per day from the Marcellus at the end of 2009 and had ramped up production to 115 million cubic feet per day in late February. Management plans produce 180 to 200 million cubic feet per day at the end of 2010 and 360 to 400 million cubic feet per day at the end of 2011. In other words, Range Resources doubled its output from the Marcellus Shale in 2009 and expects to double this production rate again in 2010 and 2011.

And management assured investors that the firm wouldn’t need to issue new equity in the near future–unless it decides to make a major acquisition. Accordingly, most of this production growth will translate into per-share production growth. As I noted at the beginning of this issue, per-share production growth is one of the most important drivers of a stock’s performance; Range Resources is among the top performers in terms of production growth per share and total return.

A couple of additional points are worth noting about Range Resources’ operations in the Marcellus. First, the company is testing new areas of the play and experimenting with longer lateral segments. Range Resources has been drilling lateral segments of about 2,800 feet with eight fracturing stages (this multistage process ensure greater permeability in the surrounding shale). Since last August, Range has tested wells up to 5,000 feet in length and up to 17 fracturing stages.

Management is pleased with the early results of this effort. In addition, increasing the number of fracturing stages has boosted productivity in other US shale plays; the company expects this approach to bear fruit in the Marcellus Shale as well.

And now that Range has ramped up production in the core of southwest Pennsylvania, it’s moving to the Northeast portion of the state. The company has drilled two wells that have yielded average IP rates (based on seven-day average production) of 13.5 million cubic feet per day, an impressive IP rate by any measure.

In addition, Range Resources is testing the Utica and Upper Devonian formations above its Marcellus shale play–both regions appear to contain meaningful gas deposits.

Management also noted that it considered a joint venture with a major oil company to develop part of its Marcellus acreage–hardly a surprise, as major international oil companies are wading into the US unconventional oil and gas production industry. BP (NYSE: BP), Statoil (NYSE: STO), Total (NYSE: TOT) and ExxonMobil (NYSE: XOM), among others, have entered the unconventional oil and gas business either via joint ventures with acquisitions of independent producers like Range Resources. The most recent deal was between Japan’s Mitsui & Co (NSDQ: MITSY) and Portfolio recommendation Anadarko Petroleum (NYSE: APC) in the Marcellus.

Because Range Resources has what’s considered to be the largest acreage in the core of the play and plenty of experience drilling in the region, it’s a logical partner or acquisition target for one of the major integrated oil firms. Along these lines, management stated that it would expect a better deal than Anadarko Petroleum received in its recent joint venture.

It wouldn’t surprise me if the company eventually secures such as deal.

Another play that’s developing quickly for Range is the Nora field located in southwest Virginia. The company is targeting a number of formations in this field, including the Huron shale where it has now completed 23 horizontal wells. The company produces over 61 million cubic feet per day of natural gas in Virginia and a bit more across the border in West Virginia. Buy Range Resources under 60 with a stop at 40.75.

The core of Petrohawk Energy’s (NYSE: HK) operations is the Haynesville Shale of Louisiana but it is also a major player in the emerging Eagle Ford shale in south Texas.

Petrohawk’s production was at 598,000 cubic feet of gas per day in the fourth quarter, slightly higher than estimated. And although management estimated that the firm would grow total production volume 35 percent in 2010, the firm has a habit of exceeding and boosting guidance over time.

During the company’s fourth-quarter conference call, management and analysts spent a great deal of time discussing the company’s efforts to “choke back” certain wells in the Haynesville Shale. That is, if a well normally produces 18 to 20 million cubic feet initially, Petrohawk is limiting the flow to about 7 to 10 million cubic feet. The company has determined that this practice extends well pressures and increases the estimated ultimate recovery (EUR).

EOG has tested similar measures in its Haynesville properties, though both companies noted they lack sufficient data to determine conclusively which methodology is better.

Petrohawk has applied this restricted production method to wells drilled seven or eight months ago. I expect management to discuss this strategy in upcoming quarters; if successful, this strategy shift could constitute an upside catalyst for the stock.

Another key catalyst for Petrohawk will be tests of its Red Hawk field in the Eagle Ford shale. The Red Hawk is located north and west of the Eagle Ford shale’s core in Zavala County, Texas. The company has drilled two wells in the region, and early results have created a buzz; the characteristics of the play are similar to the Eagle Ford, and the wells appear to contain crude oil as well as natural gas, offering an upside to economics.

More data on Red Hawk is forthcoming–another potential upside catalyst for Petrohawk.

Finally, management noted that the firm has signed long-term contracts for fracturing services that cover 75 percent of its anticipated needs in 2010, echoing comments from EOG’s management. This suggests a growing sense of urgency in locking in rigs and services related to shale plays. It also implies that producers are trying to lock in relatively low rates.

When asked specifically about the jump in fracturing costs in the Haynesville Shale, management stated that costs have picked up, albeit not to the extent that some analysts have forecast. Petrohawk remains a buy under 30 with a stop at 17.50.

Growth Portfolio bellwether Anadarko Petroleum (NYSE: APC) has emerged as one of the world’s premier plays on deepwater E&P. The company announced a total of nine deepwater discoveries in 2009, including the Lucius discovery in the Gulf of Mexico and the pre-salt Itaipu field off the coast of Brazil. Management has flagged the latter discovery as a potential mega-project.

For newer subscribers unfamiliar with my take on deepwater oil finds and the prospects for production growth, check out the Oct. 7, 2009, issue, The Golden Triangle.

Well results from a series of appraisal and exploration prospects slated for this year could be a major upside catalyst for Anadarko’s shares.

On the exploration front, Anadarko is drilling a series of four wells off the coast of Mozambique.

Source: Oxford Cartographers

These four wells target two prospects, the Windjammer in the Rovuma Basin and the Collier just to the southeast. Anadarko was drilling the first of these four wells at the time of its fourth-quarter conference call and subsequently has released data indicating that it found a large natural gas prospect in the field. The company plans to drill the well a bit deeper to examine other intervals.

That leaves three wells to be drilled in Mozambique, including the separate Collier prospect to the south. Further successful well results would be an upside catalyst for the stock. Anadarko has a 43 percent interest in these plays.

The company also plans to drill more wells in Ghanaian waters near where two previous discoveries, Mahogany and Twenboa.

Additional appraisal wells are scheduled for plays in all three legs of the deepwater Golden Triangle: West Africa, Brazil and the deepwater Gulf of Mexico. Given the company’s recent exploration successes and myriad upside catalysts for the quarter ahead, I am boosting my buy under target for Anadarko from 70 to 75 and raising my suggested stop from 47.50 to 55.

Additional Portfolio Updates

Oil country tubular goods (OCTG) manufacturer Tenaris (NYSE: TS) missed earnings estimates for the fourth quarter, sparking a bit of a selloff in the shares. That being said, the stock has regained much of this lost ground and trades considerably higher than our entry price.

Tenaris’ miss doesn’t concern me. Management’s caution in the first half of 2010 isn’t abnormal; drilling activity, particularly in North American gas, is still recovering from the late 2008 and early 2009 price collapse. Inventories of pipe are at healthy levels, and the company has seen a pick up in volumes sold–an indication that increased drilling activity is translating into growth.

As I noted earlier, demand for high-specification rigs and fracturing services appears to be on the rise, and prices are recovering quickly. Because Tenaris’ high-performance pipes are a necessity in many of these shale plays, the company should benefit from the same basic trend over time. Take advantage of the market’s overreaction and buy Tenaris up to 47. Also note that I am raising my stop to 31.

In the previous issue, I examined the refining industry and offered my rationale for a trade in Valero Energy Corp (NYSE: VLO) over the next few months. The stock has taken off and now trades just shy of my buy target.

In trades such as this, it’s important to pay attention to technical levels–areas of support and resistance on the charts. In this case, I am maintaining my buy price at 19 and my stop at 15.65. Should the stock eclipses 19.50, I will likely raise the stop to ensure we at least break even; readers should look out for a Flash Alert about this trade.