The recent pullback in global stock markets is a healthy and natural reaction to the nearly uninterrupted rally we’ve enjoyed since late summer. Although the popular media continues to look for some fundamental justification for the correction, there are few obvious candidates–most economic data has been upbeat, and corporate earnings for the third quarter are broadly beating expectations.

But some profit-taking always occurs after a big rally. As I pointed out in last week’s Flash Alert, some Portfolio recommendations have soared close to 30 percent from early October to highs later in the month. It’s only natural some investors would look to book gains.

The current pullback and any additional downside to come over the next few weeks should be regarded as a gift, a second chance to buy into recommended stocks at attractive levels. As I note in today’s issue, the fundamentals for energy markets remain strong; I now expect crude to top its 2008 highs by sometime in 2011.

In This Issue

Comments from key third-quarter conference calls suggest that higher oil prices have yet to catalyze further spending on exploration and production. Nevertheless, the fundamentals indicate that oil prices will remain above key thresholds for some time–this skittishness will dissipate before long and prospects are still bright for the long haul. See Nervous Producers, Higher Prices.

This quarter’s conference calls provided additional evidence that the current cycle is troughing, and my enthusiasm remains undimmed. See The International Oil Cycle. 

Remember the lessons of Jellystone and don’t listen to bears. The fundamentals of supply and demand suggest that demand from emerging markets will drive the long-term bull market for energy commodities. See Signs of Demand.

The US economic recovery bodes well for services firms levered to key nonconventional gas plays. See North America and Gas.

Australia’s central bank raised interest rates for the second time in four weeks. Chinese demand for Australian coal is a big part of the economic recovery down under. See China, Coal and Australia.

Nervous Producers, Higher Prices

Dissecting earnings reports is akin to peeling an onion in that there are multiple layers of significance to consider. At first blush, the main points most investors focus on are whether the company beat or missed earnings estimates and what sort of guidance management offered for coming quarters. Then, of course, I always check the market’s reaction to the news, an excellent gauge of sentiment and how much good news is already priced into a stock.  

Quarterly conference calls provide excellent insight into a company’s prospects as well as a point of comparison to previous calls.

But only after listening to calls from several companies in the same industry is it possible to identify key commonalities and reflect on their long-term significance. This quarter, one of the more important comments I heard from several big oil-services firms was that producers are nervous; after last year’s dramatic boom and bust in prices, companies are reluctant to increase their exploration and production budgets.

This simple observation suggests that crude oil production growth will lag far behind demand in 2010. Such a scenario would have significant implications; I expect crude oil prices to hit new all-time highs by 2011.

Since the end of 2008 and early this year, I’ve predicted that we would see oil would hit USD80 a barrel in 2009 and exceed USD100 in the first half of 2010. Oil prices have already borne out my first prediction, and my second prognostication appears much more conservative than earlier this year when oil was hovering around USD40 a barrel.

The rationale behind my forecasts was simple: normalization in global crude oil markets. My basic take was that the extremes of market sentiment, economic and credit market conditions would reverse by the latter half of 2009 and pull oil prices from depressed levels. With oil at USD40 a barrel, companies simply can’t justify the billions of dollars in investment required to bring new deepwater oil projects on stream. In fact, at prices under USD50, producers can’t even afford to undertake development projects to stabilize falling production from mature fields.

Every time I write that many oil projects are uneconomic at USD50 oil, I receive e-mails citing articles claiming that oil can be produced at much lower price points. There’s a degree of truth to these claims–some fields in the Middle East can be produced profitably even with oil at USD10 a barrel. But low-cost production isn’t the issue; investors need to pay attention to marginal production, extra barrels from higher-cost plays such as oil sands, deepwater and mature fields that require aggressive drilling to produce.

With global oil demand returning to a normalized growth rate, these marginal barrels are required to balance supply and demand. Given my assumption that the global economy would show signs of life by the end of 2009, I argued that oil prices would need to rise to a level that incentivized the production of marginal barrels. The only way to encourage real investment is price: Producers want to know they’ll not only break even on new projects but earn a reasonable return on investment.

And the proof is in the proverbial pudding. Amid the collapse in oil prices late in 2008 and early 2009, several oil sands producers–including Wildcatters Portfolio recommendation Suncor Energy (NYSE: SU)–delayed or canceled planned expansion projects because of weak commodity prices. Even within the Organization of Petroleum Exporting Countries (OPEC), a total of more than three dozen major projects were canceled or delayed at the beginning of this year. None of those major oil projects have since been green-lighted.

Based on comments from producers and services firms, I felt that oil prices between USD70 to USD80 a barrel represented a neutral “marginal barrel” oil price–a level consistent with some investment in new production projects and ongoing development spending.

I still see this USD70 to USD80 band as a sort of neutral price from a pure price and economics standpoint. But management teams at the major oil producers are subject to the same basic forces of greed and fear that guide investors; although oil prices are rising to levels that should incentivize spending and exploration, last year’s rout is fresh in most producers’ minds and they’re reacting far more conservatively as a result.

The importance of this caution can’t be overstated. Consider that West Texas Intermediate crude oil prices averaged USD66.02 a barrel in 2006 and USD72.20 a barrel in 2007–levels below the current quote. But back then producers were boosting capital spending budgets, and services firms were struggling to keep pace with demand. This time around they’re doing just the opposite, in many cases not planning major increases to their budgets for 2010.

Although most investors remember that oil prices neared USD150 a barrel in mid-2008, the commodity only traded over USD100 for a relatively short period that year. Based on trading history up to that point, prices around USD80 would have been considered extraordinarily attractive. With oil at that level once again, one would expect companies to be downright giddy and eager to invest in expansion projects.

But that’s not the case just yet. Oil-services giants Schlumberger (NYSE: SLB) and Halliburton (NYSE: HAL) both made remarkably similar comments in this regard during their third-quarter conference calls. Consider this comment from Schlumberger CEO Andrew Gould, one of the most respected managers in the energy industry, during the company’s third-quarter conference call:

It’s not the spot price of oil that encourages my customers to change their spending. It’s the notion that an increase in the price has reached some level of stability. So last quarter I talked about 70 to 75[USD a barrel crude oil prices]. And I think today that most of my customers are still budgeting slightly below that.

And I think that if they gain confidence…in the first half of next year that this price is sustainable then they will increase spending. But today I think the increases we’re seeing are in activity based on their capacity to obtain more activity at lower prices within their existing budget. So, yes, obviously USD80 oil, if it stays at USD80, will eventually lead them to increase their budgets. I don’t think they’re ready to make that call yet.

In this excerpt, Mr. Gould refers to comments made during the company’s second-quarter conference call; I analyzed these statements in the August 19 issue of The Energy Strategist, Mapping the Cycle. His point at the time was that oil prices were still too volatile and that oil would need to be around USD75 at the end of the year for producers to even maintain their 2009 spending plans into 2010.

His comments in the third quarter suggest that oil producers are looking for prices to stabilize in that magic USD70 to USD80 range into early 2010 before they increase their spending. Gould suggests that it might take producers into the first half of 2010 to make the call to increase spending–even though crude oil prices have remained relatively strong since the company’s second-quarter call.

It appears that much of the recent uptick in activity is simply “budget flush”–that is, in the weak commodity price environment that prevailed through much of the first half of 2009, companies under-spent relative to allocated budgets. Now with commodity prices higher, they’re playing catch-up. This shuffling of spending from the first half to the second half of the year doesn’t represent a meaningful allocation to exploration and development.

In addition, weak demand at the beginning of the year enabled producers to negotiate some price cuts, allowing them to fund a bit more activity with the same budgets.

Halliburton’s CEO David Lesar noted this trend in his prepared comments, released before the service giant\’s third-quarter call:

While there is risk of a further decline in international activity in the coming quarters I am more optimistic than I was previously that this downturn will not match previous cycles in terms of duration and depth.

However, we believe operators will not materially increase their spending levels despite stable commodity prices without compelling evidence of recovery in hydrocarbon demand. As a result they continue to reduce capital expenditures by deferring projects and exerting pressure on the oil service companies to improve their project economics. 

Lesar suggests that oil companies may continue to delay projects until it becomes obvious that global oil demand is rebounding. As I explain later in today’s issue, I expect this realization to set in over the next three to six months.

At any rate, oil producers are likely to be slow to restart delayed projects and reaccelerate spending. Many international projects take years to bring to fruition; a decision to spend more money or commence a project doesn’t result in an immediate jump in production volume. As oil demand normalizes in 2010 and strong growth resumes in emerging markets, supply will adjust only slowly to meet that demand.

Producers’ reticence to embrace rising spot prices will just further delay this production. These comments also suggest that higher, stable oil prices will be a prerequisite for new projects.

This general fear and spending discipline may be logical and responsible in light of last year’s commodity price collapse. But this attitude further magnifies the inevitable production squeeze; by the end of 2010 demand for oil will grow at a robust pace, led by gains in emerging markets. At the same time, non-OPEC supply declines will only accelerate. To compensate, OPEC will be forced to boost production and again shrink its spare capacity; as in summer 2008, this combination of forces will push crude to new all-time highs by 2011.

The International Oil Cycle

Back in the August 19 issue, Mapping the Cycle, I spent considerable time analyzing earnings reports from oil- services companies, including Schlumberger and Weatherford. My goal was to determine where the group was in terms of its long-term cycle.

My basic argument remains the same today as it was three months ago:

I’ve never claimed that the services industry–or, more broadly, the energy business–has evolved into a perpetual growth machine. Rather, one of the core precepts of this publication is that the post-2004 cycle was not a one-off phenomenon. The industry no longer faces the short-cycle of the 1980s and 1990s; the new paradigm will bring longer cyclical upturns punctuated by short, cyclical declines.

Further, profit margins at the peak of these cycles will be far higher, on balance, than at the peaks of the short cycles of the 1990s. By extension, margins at cyclical troughs will also be far higher sthan during previous cyclical downturns. In other words, the current environment for energy resembles the industry’s cyclical pattern during the big energy stock rally of the 1970s and early 1980s.

Where do we currently sit in this cycle? The short answer is that pretax profit margins for oil- services companies largely topped out in the third to fourth quarter of 2008, depending on which firm is under the lens. Since then the oil patch has been in a cyclical downturn that I expect to bottom out over the next two to three quarters. Share prices will rally in earnest, months before profitability improves; the stock market is a forward-looking mechanism, anticipating future conditions rather than reacting to current realities.

Bottom line: The cycle for oil-services stocks appears to be at or near its lows, and the sector remains my favorite long-term play in the energy industry. Buy Schlumberger (NYSE: SLB) and Weatherford International (NYSE: WFT) at current prices–these firms will benefit directly from the increasing technical complexity of oilfield development.

This quarter’s conference calls provided additional evidence that the current cycle is troughing, and my enthusiasm remains undimmed. Much of the talk was of a stabilization in spending outside of North America.

As I noted before, I expect activity levels to pick up in some markets over the next two quarters as producers allocate budgeted money that went unspent in the first half of the year. As we move into the second half of 2010, oil prices will remain steady at higher levels and producers will find themselves playing catch-up to meet growing global demand.

In the company’s third-quarter conference call, Schlumberger’s CEO Andrew Gould commented on the coming oil-services cycle and how it compares to prior cycles:

First I think that everyone needs to understand that the state of the general economy in this downturn is much worse even than it was in 1986 and bears no comparison to ’99 or ’01.  And therefore there is this underlying question that everybody needs to ask themselves about demand. And, if you remember, if you look back, the collapse in 1986 was due to a huge collapse in the demand for oil in the years before 1986.

So there is this underlying question, which is fundamental to the oil and gas business, what is happening to demand? And we have seen some encouraging signs but we’re not out of–we’re not back into high demand growth. And, in fact, if you looked at the presentations I’ve made recently or people are making recently, the assumption on world GDP [gross domestic product] is absolutely fundamental to where demand is going to go. And if it’s 3 percent or 4 percent of 5 percent, the amount of demand for oil particularly is going to be substantially different. So that’s the first thing.

The second thing is that unlike 1986 for oil there is an overhang of six or seven million barrels, or whatever it is, but it is nothing like the overhang that existed in 1986. And, as you know, the ability of the industry to renew the production base is a lot less flexible than it was in 1986.

So in terms of the need to sustain activity, any growth in demand coupled with the relatively modest overhang of production will mean that demand will act as an accelerator on investment. So, you know, that’s why I made all these remarks in my comments about the level of general investment. So for oil, there’s a fundamental difference in the economy and there’s a fundamental difference in the supply situation.

The analyst who elicited this response had asked how the current cycle compares to the down-cycles that occurred in 1999 and 2001, but Gould spent most of the time comparing the current cycle to the decline back in 1986.

In late 1985 West Texas Intermediate (WTI) crude oil prices were over USD30 a barrel but collapsed to around USD10 a barrel by early 1986. Ignoring a brief spike during the first Gulf War, crude oil traded between USD12 and USD25 a barrel through the end of the 1990s.

As a result of the severe commodity price downturn, the global active rig count–the total number of rigs actively drilling for oil and gas–collapsed from more than 4,000 rigs in early 1985 to less than 2,000 in mid-1986. Simply put, the 1986 cycle was among the most vicious the industry has every endured.

Gould notes that both the demand and supply situations are different than in 1986. On the demand front, the global economy is in worse shape than it was in 1986, a product of the Great Recession. Of course, this doesn’t take into account that emerging economies weren’t major factors in the oil market 23 years ago.

The most important takeaway from Gould’s comparison is that the global supply picture has changed dramatically. Back in 1986 the main cause of the collapse in prices wasn’t weak oil demand but excess supply. Global spare capacity at the time was as high as 20 percent of global demand. The world was awash in excess oil supply, and global producers had plenty of relatively young fields to produce in the North Sea and Mexico, among other locales.

Now the situation couldn’t be more different. There is a global overhang of about six or seven million barrels of oil. Most of that excess capacity is in Saudi Arabia and a handful of other OPEC producers; in total, this represents about 7 percent of global demand. And producers don’t have the large, easy-to-exploit fields they did back in 1986; the world’s largest producers are struggling to maintain output despite an unprecedented wave of investment from 2004 through 2008.

What this all adds up to is a shorter and more-violent cyclical downturn in the oil-services sector. But unlike what transpired in 1986, the main cause of the recent down-cycle was a sharp decline in demand rather than a big jump in supply.

But there’s a flip side to that equation: a faster global recovery for the group. Supply remains constrained, and nervousness on the part of global producers will only exacerbate that problem. This reticence to invest in new production suggests that improving demand will tighten the oil market more quickly than in past cycles–as Schlumberger’s CEO puts it, any incremental demand will act as “an accelerator on investment.”

Comments from the big services companies this quarter simply increase my confidence in the “end of easy oil” thesis I summarized in the September 23 issue, Top Three Energy Themes. My top recommendations on this theme include oil services recommendations Schlumberger and Weatherford International, as well as the deepwater focused plays highlighted on the October 7 issue, The Golden Triangle.

Signs of Demand

All year, oil bears have focused on US oil demand and US inventory levels. This line of thinking is hardly a new phenomenon–back in 2005 I remember arguing with several analysts who expected oil prices to return to the teens because of high US crude inventories.

Now, as then, treating US oil inventories as the sole indicator for oil prices is a failing strategy: the US is no longer the only engine of global oil demand. Over the past decade oil demand has grown less relatively little; developing economies account for almost all of the increase in oil demand.

Faulty logic aside, any sign of resurgence in US oil demand or normalization of inventories could act as an accelerant for the oil services stocks and oil prices. Although bearish analysts continue to focus on bloated US inventories, investors should note that the trends are headed in the right direction.


Source: EIA

This graph depicts total US inventories for gasoline, distillates (diesel and heating oil) and crude oil. There’s no denying that product inventories remain elevated, but the action over the past few months indicates that US product inventories have likely peaked and are returning to normal.

It was encouraging to see stocks of distillates fall 2.12 million barrels last week, a faster-than-expected pace. US distillate demand is now entering an important season, as the category includes heating oil.

And although the decline from recent highs in US inventories has been modest to date, keep in mind that the US economic rebound is only just beginning. Last week, the US Bureau of Economic Analysis (BEA) announced that gross domestic product (GDP) grew 3.5 percent in the third quarter, well above forecasts for a 3.2 percent rise. This is the first positive showing for GDP since the second quarter of 2008, and the largest jump since the third quarter of 2007.

In last week’s issue of Personal Finance Weekly, Parsing GDP, I scrutinized the numbers. Although plenty of evidence links some of the GDP growth to short-term government stimulus, longer-term forces are also at work–for example, an inventory restocking cycle.

And the economic data released in recent weeks have been almost uniformly positive. The Institute of Supply Management’s (ISM) Manufacturing Index is a case in point.


Source: Bloomberg

Readings above 50 on the ISM Manufacturing Index are consistent with expansion in manufacturing. The recent reading of 55.7 for the month of October was above the consensus forecast of 53 and one of the highest readings in some time–the turnaround from the beginning of this year has been dramatic.

Longtime readers know that I pay careful attention to the year-over-year change in the Conference Board’s Leading Economic Index (LEI). When LEI turns goes from positive to negative, it’s an indication the economy is slipping into recession. This simple indicator called the onset of this contraction at the end of 2007, a point when many pundits were still expecting the economy to skirt a contraction.

Source: Bloomberg

As you can see, LEI turned positive in mid-summer, suggesting suggests that the US economy likely exited recession in the third quarter; the release of third-quarter GDP confirms that outlook.

With the US economy just emerging from the worst downturn in decades, it’s hardly surprising that US oil inventories are only just beginning to fall from their highs. Moving forward, however, I expect this trend to continue.

From a slightly longer-term perspective, I expect US oil demand growth to remain relatively muted in coming years. In fact, it would not surprise me if the country’s demand has already peaked. This outlook has nothing to do with a mass switch to electric or hybrid cars–such a switch is not only impossible given current electric grid infrastructure–but rather generally high crude oil prices that will crimp demand growth and prompt some conservation.

More specifically, I see demand rebounding from the near-depression levels of late 2008 and 2009 but not resuming the high growth rates witnessed over the past two decades.

Emerging markets will furnish the real growth story. Studies have estimated that an annual income of USD4,000 to USD6,000 represents a key tipping point for consumers in emerging markets. At that income level, discretionary spending begins to rise; in Asia as many as half a billion consumers are hitting that key threshold. The equation is simple: Higher discretionary spending equates to higher energy demand.

To meet rising demand from emerging-market consumers, the world will need to find supply. Because new production is constrained, a major source of oil supply will be demand destruction in the developing world. In other words, peak oil demand in the US and other developed countries is a necessary condition to accommodate growth from emerging markets. Don’t misinterpret weak US demand growth as a bearish signal for oil prices; it’s a rather bullish indicator for demand in emerging markets.

Mounting evidence suggests that demand is growing once again among emerging-market consumers. In the most recent Oil Market Report, the International Energy Agency (IEA) revised global oil demand estimates higher by 200,000 per day in 2009 and 350,000 barrels per day in 2010.

Of the 1.42 million barrels per day increase in global oil demand that the agency expects for 2010, only about 14 percent (200,000 barrels per day) is expected to come from a snapback in US demand. Asia and the Middle East, on the other hand, account for more than half the expected jump, with demand from the former expected to increase by 470,000 barrels per day and demand from the latter expected to increase by 270,000 barrels per day.

North America and Gas

Investors should always draw a distinction between the North American services market and markets outside the US and Canada. In North America, oil-services firms operate in classic short-cycle conditions because most drilling projects in the region are relatively small, short-term deals.

North American producers can cancel projects quickly in reaction to commodity prices. Most activity in North America tracks natural gas prices, not crude oil; a fall in gas prices can lead to a dramatic decline in activity in only a few months. Because services firms are sensitive to drilling and development activity, their fortunes can change on a dime due to volatile commodity prices.

The international cycle is longer. Projects that drive profits for the big services companies are typically large-scale, multi-year deals. As a group, international producers tend to be less sensitive to commodity prices in the short term. This is particularly true for the large integrated oil companies (IOCs) and national oil companies (NOCs) that have the cash and credit to continue drilling regardless of near-term pullbacks in pricing. And NOCs such as Brazil’s Petrobras (NYSE: PBR A) often view oil developments as long-term national priorities.

Simply put, it’s impossible to disassociate the outlook for the US and Canadian services markets from the price of natural gas. As I explained in the previous issue, the 12-month calendar strip is the most important metric for investors with positions in gas-levered stocks. Trading at around USD5.50 per million British thermal units, the strip is off its October highs of about USD6 per million British thermal units but well off its 2009 lows of close to USD4. I expect prices to continue to rebound into 2010, ultimately stabilizing between USD6 and USD8 per million British thermal units–well off the 2008 highs but several times the recent lows of near USD2.

The prevailing opinion holds that the major oil services companies were incrementally more bearish on the outlook for natural gas this quarter. I’ve read plenty of headlines stating that Schlumberger and other big services firms provided a weak outlook for North American spending. I’ve also heard several pundits cite this as a reason to avoid stocks leveraged to natural gas.

But the truth is that we knew heading into the quarter that the North American gas drilling market was weak. Certainly, the collapse in the US and Canadian gas-directed rig counts is no secret, nor is the fact that current natural gas prices are below the marginal cost of production for all but a few plays in the US.

That the service majors noted weakness in gas drilling in the third quarter is not news–it’s a continuation of the same trends we’ve heard about for several quarters now. At the beginning of September, I scrutinized this trend in The Gas Puzzle, my detailed outlook for the North American gas market.

Both Halliburton and Schlumberger noted that the natural gas market faces several headwinds through the first half of 2010. The high levels of natural gas currently in storage represent the first challenge. Another obstacle is that unlike oil production, US natural gas production can be ramped up relatively quickly thanks to strong production growth potential from the big US shale plays. As I explained in the September 2 issue, the North American shale plays represent a new paradigm.

Even with a pick-up in gas demand over the coming months and declining production due to the US rig count, the natural gas inventories aren’t likely to normalize until the second half of the year.

Here’s how Halliburton’s management put it in the firm’s third-quarter conference call:

We believe that a significant improvement in the natural gas market in the next few quarters is unlikely without the resurgence of a broad economic demand and support of winter withdrawal and supply patterns.

While we expect the industry will see accelerating production declines in the coming months in response to reduced drilling activities, we don’t believe these declines will be adequate to provide a meaningful near-term correction of the current supply and demand imbalance.

The first part of this quote reiterates something that a long list of gas-levered firms have been saying for several quarters: The US will need an uptick in demand for gas before prices can recover. Industrial demand–the use of gas in manufacturing industries–has been the hardest hit segment over the past year.

But, there are signs of life, including the most recent reads on industrial production (noted in the previous issue of TES) and the ISM data I highlighted earlier in this report. Because industrial demand is heavily correlated to manufacturing and industrial production, improving figures suggest recovering demand for gas.

The second half of this excerpt notes that the company expects US natural gas production to fall at an accelerating pace into 2010 because of the big decline in drilling activity since last summer. But the services giant suggests that the shift in supply/demand fundamentals won’t be immediate; it will take a period of rising demand and falling supply to work through the excessive inventories currently evident in this market.

Later on in the call, Halliburton’s management offered more color as to what it expects for the North American gas market:

Earlier this year we discussed the parallels of this cycle compared to previous cycles. This quarter provides the industry with additional reference points, and with that in mind it’s a good time to revisit analogies from past downturns.

Based on the familiar mix that we discussed earlier in the call of supply storage and demand it’s our view that the North America cycle could be consistent with that of the 2002 recovery. In 2002, gas-directed rig counts rebounded from trough levels and then were range-bound for around 33 weeks, versus being range bound for around 17 weeks at this point in the 2009 cycle. If we follow this pattern, then drilling activity may remain at restrained levels into the first half of 2010 before demonstrating a meaningful increase.

Complicating factors in the recovery include shut-in wells and the impact of the 1,300 to 1,500 wells which have been drilled and not completed.

As always, no two periods in history are exactly alike. But Halliburton’s management offers a roadmap as to how the cycle might play out. Based on Halliburton’s timetable, the US rig count will remain relatively stable for another three to four months before it begins to recover.

This roadmap suggests that North American drilling activity could begin to rebound by roughly the middle of the first quarter of 2010. Complicating this is a backlog of wells that have been drilled but aren’t yet in production. Halliburton estimates there are around 1,500 such wells, though other companies have suggested that the number is less.

At any rate, let’s assume that these wells will delay the beginning of the next up-cycle in activity levels by another month or two; the pattern evinced in 2002 suggests there will be a resurgence in gas drilling activity in the first half of next year.

As I explained in Off to a Good Start, the performance of gas-levered stocks is more closely correlated to the 12-month calendar strip than to spot gas prices. The strip averages the next 12 months worth of futures contracts, offering a better indication of long-term supply/demand fundamentals.

If Halliburton is correct and gas fundamentals begin to turn for the better in the first half of 2010, the strip price of gas has more upside. The market will likely react to shifting trends in supply/demand conditions more so than the amount of natural gas currently in storage.

This forecast is broadly consistent with the 2010 gas rally theme I outlined in the September 23 issue, Top Three Energy Themes. Of course, the ultimate arbiter of success is the stock market. Since the end of August, the Philadelphia Oil Services Index is up 12.1 percent and the S&P 500 Energy Index is up 9.8 percent, while my index of gas-levered stocks is up 15.0 percent. Although two months is undoubtedly a short time, that gas-levered stocks are outperforming the energy sector as a whole suggests that the prospects for a 2010 recovery in gas are improving rapidly.

Newer readers might be unfamiliar with the TES US Gas Index. Here’s a quick synopsis of why and how I constructed this alternative index.

Several popular indexes purport to track the performance of North American gas-levered stocks. But in my view none of these indices are completely satisfactory for two reasons. First, most are weighted by market capitalization: One or two large names have an outsized impact on the index’s overall performance. Second, some include names like Schlumberger, a global oil-services firm whose stock price is more closely correlated to oil prices, or BG Group (London: BG), a play on international gas prices rather than market dynamics in North America.

To avoid these issues, I created an index of 10 firms that are direct plays on the North American gas market. The index is equal-weighted–all constituents have an equal impact on the index’s performance. For reference, the ten stocks are: BJ Services (NYSE: BJS), Chesapeake Energy (NYSE: CHK), Hercules Offshore (NSDQ: HERO), Petrohawk Energy (NYSE: HK), Quicksilver Resources (NYSE: KWK), Nabors Industries (NYSE: NBR), Patterson-UTI Energy (NSDQ: PTEN), Range Resources (NYSE: RRC), Southwestern Energy (NYSE: SWN) and XTO Energy (NYSE: XTO). I plan to replace BJ Services in this index as soon as its merger with Baker Hughes (NYSE: BHI) is finalized. Also note that the index’s constituents aren’t all recommendations; this index is simply meant to track how US gas-levered names are performing.

Another point that emerged from conference calls this quarter is that there are two separate gas markets: the market surrounding production from conventional fields and the market focused production from premium unconventional gas shale plays such as the Haynesville in Louisiana and the Marcellus in Appalachia.

With the 12-month strip trading between USD5.50 and USD6, drilling activity in conventional US gas fields and production from higher-cost shale plays should continue to decline. But at those prices there appears to be some steadiness and growth in the most economic plays.

Consider the following exchange between Schlumberger CEO Andrew Gould and an analyst during the company’s recent conference call:

Q: …shifting to North America again, one further question. In terms of the prospects for recovery in pricing [for services] we all know that as the rig count increases, there’s really no magic number at which you start to have pricing power. But if you\’re sized today for the market in North America and the rig count begins to increase, activity picks up and you have to go out and hire and begin to incur some expenses in meeting that higher level of demand, is there a potential to get pricing improvement at that point, or are we in your view–is it further out until we get to a substantially higher level of pricing in North America?

A: Well, I think it depends on what type of activity it is. If it’s a continuation of what we’ve seen in the Haynesville, for example, where actually the type of service and the complexity and the intensity is quite high, then I think pricing will react quite fast, because there will be a limited field of players that the customers will want to use. If it\’s just general spread across the board, then it will obviously take much longer.

Q: And your expectation is the type of recovery would most likely focus on these high service intensive shale plays like the Haynesville and Marcellus?

A: Yes, I do. Because I think that’s where the highest initial production indexes come from and are going to continue to come.

This particular passage needs little explanation. Gould states that he sees the recovery in North American services pricing emanating from the premium shale plays–the Haynesville and Marcellus Shales are the two highest-profile plays at the current time.

Nonconventional shale plays will provide the first signs of recovery for several reasons. First, these shale boast among the lowest production costs of any US play and are among the only plays offering solid returns even with natural gas prices below USD6 per million British thermal units. If gas were to climb to the USD7 per million British thermal units that I forecast, activity in these fields would accelerate dramatically.

Second, the Haynesville and Marcellus shales are service-intensive to produce. As I’ve explained on a few occasions, the big North American nonconventional deposits require special techniques to yield economic production. Producers have found, for example, that long laterals–sections of horizontal wells that are thousands of feet long–are needed to produce shale plays most effectively. And all of the big shale plays require massive fracturing operations, a technique used to improve the permeability of shale fields.

Drilling these wells is far more complex than the simple vertical and short horizontal wells producers used to produce conventional fields; service providers earn more money per well from shale wells as compared to conventional operations.

Third, due to the cutting-edge nature of the services required to produce these shale fields, only a few service providers can perform the necessary work. Although there is copious excess service capacity for simple wells in conventional fields, the same cannot be said for big shale plays. Less competition spells higher profit margins and a faster recovery.

One of the biggest beneficiaries of these trends is Nabors Industries (NYSE: NBR), a recommendation in the Gushers Portfolio. Nabors has been hard-hit by the slowdown in US gas drilling over the past year. I added the stock to the portfolio earlier this year, expecting its business to trough by the second half of the year and a corresponding rally in the stock’s price.

Thus far my logic has panned out. At the time of its third-quarter conference call Nabors reported a total rig count of 137 rigs–115 working rigs and 22 inactive rigs that were still under long-term contracts with producers. Management noted that at one point in the third quarter, the company had a total of 117 rigs operating in North America. This is a clear sign that the gas drilling and services markets hit a low point in the third quarter and are now seeing the first signs of recovery.

And as Nabors CEO Eugene Isenburg pointed out, that recovery is being led by premium nonconventional plays:

Despite these less than ideal–even, frankly, less than expected results in the quarter–there are a number of positive indicators that suggest the turnaround is reasonably near. These include the resiliency in our PACE [programmable AC electric] rig margins in the spot market, which frankly are already starting to improve, and the uptick which has already been seen in our domestic rig count. And also in offshore and international market, we’re seeing the probability of upticks that are frankly better than the forecast.

In addition, more and more tangible evidence supports our long-term contention that customers recognize and are willing to pay for the economic benefits derived from the efficiencies generated by our high specification, high performance rigs, particularly in exploitation of shale plays. These rigs constitute approximately two thirds of our US land drilling fleet and an even larger percentage of our global fleet. I think that this will make us the primary beneficiary of the upturn when it actually evolves and progresses.

Nabors’ PACE rigs are highly capable rigs that are primarily used to drill in shale plays. Management indicated that it has actually seen some improvement in the rates it can charge for PACE rigs on the spot market.

This is an absolutely crucial point. Many PACE rigs are contracted under long-term deals, and a large portion of those deals were signed back in 2008 when demand for gas drilling was much stronger–the rates charged under contract deals tell us little about margins and demand in this business. The spot market–the rates Nabors can charge for a rig that’s needed immediately–can be quite volatile from week to week. That rates on these rigs are inching higher suggests that the supply/demand balance for these rigs is already tightening.

Of the gas-levered recommendations the Portfolios, Seahawk Drilling (NSDQ: HAWK) offers the best direct exposure to the coming rally in natural gas prices–a prospect I outlined in a recent Flash Alert.

Seahawk owns jackup drilling rigs primarily used to target gas fields in the shallow-water Gulf of Mexico–not a premium market and a region that is costly to produce. This market has been decimated over the past year. Seahawk is a leveraged play on a bounce-back in the shallow-water Gulf; the stock is priced at depressed levels, and further signs of even a tepid recovery could send the stock above 40 in short order.

Hercules Offshore (NSDQ: HERO) and Seahawk are effectively a duopoly that controls most of the capacity in the shallow-water Gulf of Mexico. Hercules’ recent earnings release and conference call highlighted early signs of a recovery from extraordinarily depressed conditions.

In particular, management noted that in July the company submitted only four bids for short-term work; in September, Hercules submitted 21 bids and 11 bids through the latter half of October. Not every bid turns into a contract, but this uptick suggests that Hercules’ customer base is renewing its interest in drilling projects.

Moreover, as demand for rigs improves in the Gulf of Mexico the upside leverage in rates should be impressive. Only 41 rigs are available for work in this region–dozens of rigs are now in long-term storage. The real supply is closer to 35 when you consider rigs that are likely to be cold-stacked. Bear in mind that just a few years ago, capacity in the shallow-water Gulf of Mexico was well over 100 rigs.

Current demand isn’t strong enough to utilize all those rigs. But if gas prices were to rebound above USD7 per million British thermal units, rig utilization in the Gulf of Mexico would quickly jump to 90 percent or more of available capacity. At that level of utilization, day-rates tend to rise rather quickly; I expect big a bounce-back in Hercules and Seahawk’s business headed into the second half of next year. As more investors pick up on this turn in the cycle, the stock will rally in anticipation–and the move could be dramatic.

Seahawk is a higher-risk play on improving natural gas prices; conservative investors should limit the size of their positions to reflect this added risk. That being said, the potential upside is tantalizing.

China, Coal and Australia

On November 4, the Reserve Bank of Australia hiked its interest rate a quarter of a point to 3.50 percent, the second increase in the past four weeks. The decision made Australia the first developed country to begin to tighten its monetary policy.

This is a clear indication that Australia is recovering faster than the rest of the developed world. The reason is obvious: Australia is rich in natural resources, and trade in these resources is booming because of strong demand from countries like China and India.

Australian-Chinese relations looked strained earlier this year. But rhetoric on the heels of high-level meetings between the two nations suggests that both countries are working to patch things up. Such a repair would be mutually beneficial: China needs Australia’s coal and other resources, and Australia’s economy benefits tremendously from China’s demand for its resources.

I will cover Australia at length in an upcoming issue of TES. But readers should note that the Australian economy’s quick rebound strengthens my rationale for investing in companies leveraged to the Australian coal industry–Peabody Energy (NYSE: BTU), Bucyrus (NSDQ: BUCY) and Felix Resources (Australia: FLX). I recently boosted my buy targets on Peabody and Bucyrus to reflect this upside, while Felix remains a hold pending its acquisition by Yanzhou Coal (NYSE: YZC).