Shares of Wildcatters Portfolio holding EOG Resources (NYSE: EOG) tumbled more than 9 percent on Wednesday after the company released third-quarter results. EOG posted adjusted earnings of $0.18 per share, roughly in-line with analysts’ expectations, but quarterly earnings had little to do with the selloff in the stock.

Instead, investors were troubled with EOG’s revised production guidance for 2010-12. The company lowered its full-year 2010 production growth estimate to 9 percent from 13 percent. Management also trimmed its forecast for 2011 production growth to 10 percent and its 2012 estimate to 12 percent. 

At its analyst day in April, EOG had projected output growth of more than 20 percent for each of the next two years; these latest numbers represent significant downward revisions. This isn’t good news for EOG, but the market’s reaction to the news has been overdone.

Nearly 70 percent of the reduction to 2010 production guidance stems from scaled-back natural gas drilling activity. EOG now plans to cut spending on gas drilling to the bare minimum–just enough to hold leases and delineate the size of its massive gas plays in Canada.

Management’s decision to scale back gas drilling isn’t a negative; with gas prices still at depressed levels, it makes sense for EOG to focus as much of its attention on producing crude oil and natural gas liquids (NGL), two commodities that trade at higher prices and offer fatter margins.

EOG also increased the scope of planned asset sales for the next two years. The company now plans to sell $600 million to $1 billion worth of primarily gas-producing properties in 2010, with the vast majority of those deals expected to close in the fourth quarter. And management also plans to divest an additional $1 billion in gas assets next year.

The funds from these assets sales, coupled with additional debt capital, will enable EOG to fund more aggressive oil and liquids-related drilling. EOG doesn’t intend to follow Chesapeake Energy Corp’s (NYSE: CHK) strategy of forming joint ventures with foreign partners or selling partial stakes in its core horizontal oil plays; management wants to own as much as possible of this production.

It’s important to note that EOG has raised its debt-to-capitalization target to 30 to 35 percent from 25 percent. But a debt-to-capitalization ratio of 35 percent is hardly excessive, particularly when you consider that EOG’s investment-grade rating enables it to borrow money for long periods at rock-bottom rates.

But scaled-back natural gas production doesn’t account for all of management’s downward revision; EOG also has reduced projected oil and liquids output growth significantly over the next two years. That being said, the oil and liquids production shortfall has absolutely nothing to do with the quality of EOG’s unconventional reserves.

In fact, as part of its release, EOG offered additional data on new wells it has drilled over the past few months. Information on the company’s wells in the Eagle Ford Shale generated the most excitement. Management estimated that the firm’s Eagle Ford acreage contains 900 million barrels of oil-equivalent reserves, 77 percent of which is actual crude oil.

Now that EOG has drilled 77 wells in the play, management expressed increased confidence in the size of these reserves, noting that wells drilled in different sections of its core acreage are producing similar results.

In the play’s western reaches, EOG is targeting a single producing layer–the lower Eagle Ford–where a typical well offers an initial production (IP) rate of 600 to 1,000 barrels per day. Wells in the field’s eastern reaches are even more productive because the company can target two thick zones–the upper and lower Eagle Ford. IP rates in this often exceed 1,000 barrels of oil per day. 

The Eagle Ford appears to exhibits reservoir characteristics that make it a particularly productive and well-behaved region.  

EOG also announced solid well results in North Dakota’s Bakken Shale, northern Texas’ Barnett Combo play and the emerging Niobrara Shale in northeastern Colorado. The firm’s Critter Creek wells drilled in the Niobrara showed initial production rates of 690 and 748 barrels per day despite restrictions that prevented these wells from flowing at their maximum potential rate. These drill results in Niobrara are encouraging because the play isn’t quite as well developed as the Eagle Ford or Bakken.

If well results were so strong, why did EOG reduce its oil production targets? The main culprit is a tight market for pressure-pumping capacity. 

Pressure pumping, also known as fracturing, involves pumping a mixture or primarily water and sand into a field under extremely high pressure. This slurry cracks and fractures the reservoir rock that contains oil or natural gas, while the sand creating pathways through which oil or gas can. Pressure pumping and horizontal drilling are the keys to producing the unconventional oil and natural gas fields that have been developed in recent years.

In this week’s issue of The Energy Strategist, I highlighted earnings results from three of the four major oil services companies. One consistent theme emerged from these reports: The North American services market proved much stronger than management teams had expected, driven entirely by accelerating activity in US unconventional shale oil and liquids plays.

EOG’s production issues are nothing more than the flip side of this trend. That oil services companies are boosting prices for fracturing amid robust demand means more money in their pockets. But producers such as EOG face rising production and drilling costs, while backlogs mean that they have to wait longer to have wells drilled and fractured. Of course, oil prices over $80 per barrel provide a degree of protection.

Nonetheless, EOG reported some staggering statistics during its third-quarter conference call. Consider the following quote from EOG’s CEO Mark Papa:

In terms of the frac [fracturing] situation between April and today, it’s really gotten worse. I mean, worse from a producer’s viewpoint. It’s literally at the point now where if we wanted to frac a well and we call up one of the major service companies typically they’ll say well we can get to you maybe right after the first of the year and the price, we’ll tell you the first of the year but its going to be even higher than your worst case scenario to frac this well and if you don’t like that particular price or availability, we’ve got a lot of other people that are needing fracs. So it’s – I would say we certainly had a peak activity several years ago when gas was $9 or $10 and there was a frenzy of activity but the frac situation was not as tight then as it is today in my opinion.

Papa went on to say that fracturing costs are up as much as 50 percent since April. In addition to price increases, the average delay between drilling a well and putting it into production is between 60 and 90 days, depending on the play. It’s pretty clear that the services companies are in the driver’s seat.

This is a particularly big problem for producers that focus unconventional fields. Common industry practice is to drill groups of three to five wells and then fracture them all at one once. A delay in obtaining fracturing equipment means that all five wells sit uncompleted for months.

Management went on to say that the situation should ease a bit toward the back half of 2011 as some producers begin to scale back gas drilling activity. The gas-directed rig count could drop as much as 200 to 300 rigs by mid-2011, when many producers complete the drilling programs they need to hold leases. But as long as oil prices remain elevated, fracturing equipment can easily find plenty of new work in oil-directed plays.

Bottom line: New capacity eventually will be brought on-stream to ease the ultra-tight fracturing market. Reduced production growth has nothing to do with the quality of EOG’s reserves.

I agree with some of the industry chatter that EOG was a little too optimistic about its production growth potential when it unveiled a host of new drilling results and plays. The miss is rendered even more shocking by the fact that management has a long track record of meeting its production targets. The size of the shortfall and management’s own history of consistency are behind the market’s outsized reaction.

EOG’s third quarter is a classic kitchen-sink quarter, in which management throws all the possible bad news at the market. With that out of the way, I don’t see much to catalyze additional downside in EOG’s stock. In fact, I suspect management has actually been ultra-conservative in setting production targets, putting the company in an outstanding position to beat these estimates over the next few quarters.

And at the end of the day, EOG Resources is still a company that is conservatively forecasting crude oil and condensate production growth of 36 percent in 2010, 53 percent in 2011 and 30 in 2012. This makes the stock a must buy in an environment where oil prices continue to rise. A good value at current levels, EOG Resources is a buy up to 115.

The second point to note is the read-through from the EOG call. EOG’s comments about fracturing capacity make me even more bullish on the oil services group and heighten my confidence that strong North American activity levels will continue well into 2011.