On February 9, GW gave a presentation at the Credit Suisse Energy Summit that makes me even more comfortable with this position. The presentation is available at http://phx.corporate-ir.net/phoenix.zhtml?c=110377&p=irol-EventDetails&EventId=1470969

until March 10. The presentation gave a worthwhile update on Q1 and 2007. References to Slides are from this presentation.

 

The NG Glut is Gone: The Winter Withdrawal (from inventory) season lasts from November 1 – March 31, followed by the Summer Injection Season. End of Winter inventory estimates have rapidly declined from 1700 a few weeks ago to below 1450, which is only slightly above average and below last year. Something similar is happening with Canadian storage. Despite having gone through one of the mildest years ever with virtually no Gulf of Mexico hurricanes, we will end the season with storage only slightly above average levels (both in the US and Canada), with NG pricing still in the $6-$8 range and US rig count close to a 20 year high. This is extraordinary and makes one consider what the situation will be if we ever have a sustained period of severe weather. With off-shore rigs (a very different market) deserting the Gulf of Mexico to go overseas and projected NG exports from Canada declining, the US is more and more dependent on increased US land drilling.

 

Newbuilds & The Drilling Treadmill: This is the real crux of the matter. Will the new supply of rigs cause a glut? In the 5 quarters ending Q4 2007, about 20% (net) may be added to the fleet. By the way, it is important to back out estimated rig attrition (4-8% annually is typical) to calculate new additions to the fleet. For example, according to the Reed Hycalog mid-year census of US land rigs (available at the Grant Prideco website), the total (Land + Water) 2006 US rig fleet had a net gain of 272, as a result of 391 additions and attrition of 119.

When you look at that census of US land rigs, it is hard to see a correlation between rig additions and utilization. For example, here is the recent history of US land rigs. The Gross Withdrawals (in Million Cubic Feet) are from the EIA’s Annual Energy Review. Granted that 2005 was an unusual year due to the hurricane disruptions and there is a difference in cutoff dates for the two reports but you can see that there has not been a huge surge in NG production to match the increase in active rig count (to be fair, there is some preliminary data to suggest that 2006 production is showing a slight uptick but this is nowhere close to the surge in active rigs).

 

 This is supposedly because the typical well requires more footage either vertically or horizontally, implying more demand for the most powerful rigs. While I believe this to be true, I haven’t been able to find data that incontrovertibly supports it. However I do feel comfortable that the average well taps into fewer reserves (Slide 14), and the depletion rate gets steeper and steeper (Slides 13-15). For example, Chesapeake shows their typical depletion rates for several different fields. Production in Month 13 is only 1/3 that of production in Month 1, and production in Month 25 is only 2/3 that of Month 13, resulting in Month 25 Production only 20-30% that of Month 1 production. The consensus seems to be that land rigs need to increase by at least 15% annually to maintain flat NG production. When the increase is less than that, NG supply declines within a few months causing NG pricing to rise, increasing the margin of the NG producers.

Rig utilization is more dependent upon the incremental margin that producers can capture than on the size of the fleet. Rig utilization follows NG pricing, not fleet size. This makes sense since it takes less than a month to drill a new well, most of the NG is extracted within a few years, and the producer can hedge the price he will get. Thus, as long as the producer has an effective hedging policy he will drill as many wells as he can when NG pricing is strong. Active rigs in Canada have decreased because NG margins have gone down dramatically more there than in the US, not because new supply has entered the market. The December 2006 Lehman Bros Survey projected a YOY increase in US E&P (Exploration & Production) Capital Spending. It looks like the E&P companies will continue drilling as long as NG pricing is above $7.

What really seems to happen is that when supply increases more than the 15% trendline, the new more capable rigs drive down demand for less capable rigs, especially since the long term trend for non-conventional plays requires those more capable rigs. In addition, most of these new rigs come to market with term contracts already signed (at least for GW, HP, NBR).

 

The Company: GW had TTM revenues of $909 million, EPS of $0.91, Net Income of $206 million, Net Debt of $32 million, FCF/share of $0.60 using total CapEx, ROE 50%, ROA 21%. Consensus EPS is $0.96 (2006) and $0.99 (2007). GW has a fleet of 118 rigs, ranking it behind Patterson, Nabors, and H&P. Slide 37 shows that GW’s fleet is at least as capable as any of its competitors and better than most. It has no direct exposure to the Canadian market.

As of February 9, 116 of their 118 rigs were working, with 84 on term contract, the highest percentage of term contracts in their history and a higher percentage than most of their competitors; thus they were not that exposed to the spot market. Of these term contracts, 14 come due for renewal in Q1 (three of which have since been renewed), 20 in Q2, 11 in Q3, and 14 in Q4. In Q4, 14 of the 19 term contracts coming due were renewed for an average revenue increase of $2800 per day. There were also a few additional term contracts signed. As of early February, GW expected the Q1 renewals to show a $200-$300 daily increase per rig from the prior contracts. 

GW believes that their $11,000 Daily Gross Margin per Rig in 2006 compared favorable to their peer group of $9,000 and that only H&P has higher margins. GW has stated that Q4 was not the peak in their average day rates for this cycle and it’s quite possible that the peak will be in Q2, Q3 or even later.

Cap Ex in 2007 is projected to decline to $124 million from estimated 2006 of $208 million. If you back out the costs of new rigs and ½ the cost of refurbishments and upgrades, you come up with maintenance Cap Ex of $76 million (2007) and $125 million (2006), which should result in Maintenance FCF approximately equal to Net Earnings, since Maintenance Cap Ex will be close to Depreciation.

As of Q3, GW had 234 million Diluted Shares and 190 million basic shares. Over 42 million of the dilution is due to $275 million of Convertible Senior Notes, convertible at $6.45 and $6.51. The Notes are due in 2023-2024 and represents their debt. Cash on hand was $243 million, probably higher now. Shareholder Equity was $495 million.

In 2006, GW bought back 9.3 million shares and as of early February had purchased an additional 1.2 million shares.

Management compensation is reasonable. Of special note is that 20% of the 2007 Short Term Incentive Awards will be based upon company wide safety measurements and another 20% will be based on EBITDA per rig, compared to the competition. The latter means that there is no incentive to bring on too many new rigs (as opposed to a measurement based on total EBITDA) and that any new rigs are more likely to be high-end, since those command higher EBITDA.

 

PTEN has a lower percentage of their rigs on term contracts and is believed to have a less capable fleet (although their management strongly believes otherwise). That is why their valuation is lower than the others.