As I’ve forecast for months, oil prices under USD70 just don’t encourage investment in new oilfield developments. Falling global oil supply isn’t a huge problem right now given depressed demand conditions. But as demand conditions normalize, supply won’t be sufficient to meet demand, and oil markets will quickly tighten.

Understanding the broad roadmap for energy prices is important, but making real money investing in the group requires delving into the specifics of each commodity market, identifying the best-placed sub-sectors going forward.

Here’s a detailed rundown of my oil and natural gas price forecasts and the prospects for four key energy sub-sectors and how to play each group, updated to reflect recent earnings releases and fundamental news.

In This Issue

My outlook for oil and natural gas prices is unchanged. We’re likely to see USD70 oil by the end of this summer, and I suspect we’ll see prices back over USD100 by early in 2010. And I’m looking for gas to trade into the USD6 to USD7 per million British thermal units range by year’s end. See Looking Ahead.

It’s one thing to project numbers, quite another to understand the factors that will lead to those numbers. I take a closer look at mounting evidence that supply reductions are beginning to impact crude markets. See Crude Oil.

The gas market is a bit more controversial. However, with the North American gas-directed rig count collapsing to around 700, there’s mounting evidence that US production will be falling at an unprecedented rate of more than 10 percent by early 2010. That level of decline is inconsistent with even depressed demand conditions. See Gas and EIA-914.

In the May 6 TES I wrote about the ongoing revival of global uranium markets. Since that issue was published, even more evidence of an impending turn in the uranium market has emerged. See The Other Yellow Metal.

Chinese coal imports have hit a record high while Chinese coal exports have slumped to near record-low levels. Simply put: China is once again aggressively buying coal to feed its resurgent economy. See China Is Buying Coal.

Looking Ahead

Last week at the Las Vegas Money Show I had the opportunity to field numerous questions both during sessions that followed each of my presentations and in smaller discussions at the KCI Investing booth. Two questions, asked in many different ways, dominated these exchanges.

First, I was asked if I thought oil and natural gas prices had bottomed. Second, a close runner-up in terms of frequency, investors wanted to know why oil and natural gas stocks are rising even though commodity supplies seem adequate and demand remains weak.

My view remains that crude oil and natural gas prices have bottomed for this cycle. I seriously doubt we’ll see oil in the USD30s again in the foreseeable future. Natural gas has seen its low in the USD3 per million British thermal units (MMBtu) neighborhood; at prices below USD4, the US gas-directed rig count will continue to melt away to levels that will generate massive declines in production by the end of 2009, if not sooner.

It’s true that the short-term supply/demand fundamentals for both oil and natural gas remain weak. After all, both the Energy Information Administration (EIA) and International Energy Agency (IEA) revised lower their expectations for oil demand in reports released last week. Meanwhile, inventories of crude oil and the amount of gas in storage in the US and across most of the developed world remain well above average, quite frankly at glut levels.

But, as I’ve outlined in this space on several occasions, the market isn’t a backward-looking animal. Traders and energy market participants are always looking ahead, to expectations for supply and demand conditions a quarter or two in the future. The fact that inventories are glutted and demand is weak isn’t new news; this has been an enduring theme since last fall, one I’ve discussed frequently.

As I noted in two recent issues, Finding a Bottom and Islands of Growth, there’s no argument that drilling and exploration activity has collapsed alongside oil prices since last summer. This has, predictably, hit the profitability of oil and gas services firms, including TES favorites Weatherford International (NYSE: WFT) and Schlumberger (NYSE: SLB).

The question isn’t if demand is currently weak or if current inventories are adequate; it’s the potential for change. The recent rally in oil, natural gas and related stocks is due to the fact that market participants see fundamentals improving over the next few quarters.

Late last year billionaire investing legend Warren Buffett stated that if investors wait for the robins, spring will be over. Mr. Buffett was talking about the broader market averages, not energy specifically. However, the same principles apply.

Investors who wait for concrete evidence that demand is growing again and inventories are falling to normal levels will have already missed a good portion of the rally. When the robins arrive, I suspect we’ll be seeing gas at USD6 per MMBtu or higher and oil north of USD70 a barrel.

The most important transition to watch for both crude oil and natural gas markets is the shift in the market’s focus from demand to supply. I’ve written about this shift on many occasions over the past nine months, including in the previous TES. Simply put, with demand at depressed levels no one cares about supply–there’s more than enough oil and gas to meet demand at recessionary levels.

But as demand stabilizes, it will quickly become clear that there just isn’t enough production capacity out there with prices at sub-USD70 levels. Oil prices need to rally above that level and remain there for some time to induce producers to make the sort of investments needed to meet normal demand.

I’ve long forecast that this transition would occur sometime around the middle of 2009 as the US economy bottoms out. This process is underway, and I see no reason to revise my expectations for oil to top USD70 by year’s end and for gas to revert to the USD6 to USD7 per MMBtu region.

Back to In This Issue

Crude Oil

For better or worse, the first commodity that jumps to mind when investors hear the word “energy” is crude oil. Although the fundamental drivers for crude aren’t as connected to coal, natural gas and uranium as some pundits suggest, there’s definitely a psychological link. Moves in crude have a tendency to pull other commodities along for the ride. It’s therefore imperative to keep a watchful eye on this market.

Short-term fundamentals for crude aren’t bullish. Demand remains weak, and inventories are bloated. Let’s start by looking at demand; check out my chart below.

Source: Energy Information Administration

This chart is based on the four-week moving average demand figures the EIA provides in its weekly petroleum inventory reports. This chart specifically looks at motor gasoline demand; gasoline demand accounts for roughly half of total US petroleum consumption.

As you can see, US gasoline demand is still off more than 2 percent compared to the same four-week period a year ago. This represents a considerable improvement from the year-over-year decline rates witnessed at the end of 2008, but it’s still negative.

One key point to watch here: Gasoline demand is particularly important this time of year because Memorial Day weekend marks the unofficial start to the US summer driving season. As we move into June, it will be critical to watch these year-over-year numbers for signs that gasoline demand is ticking higher.

My educated guess is that the combination of a stabilization of the economy and cheaper gasoline prices will prompt a seasonal up-tick in consumption. Moreover, many consumers may decide that a driving holiday is a more economic alternative than flying to a distant resort. Historically, these factors have supported demand in the summer driving season.

This slump in demand has been the major factor behind the jump in US crude oil inventories to unprecedented levels over the past six months, as the chart below illustrates.

Source: Energy Information Administration

Although I’ve only plotted the past two and a half years of inventory data on this chart, the recent peak in inventories is actually a record high. Because demand is weak, oil has simply been piling up in storage since the second quarter of 2008.

But there’s a glimmer of hope emerging in this data. Last week’s inventory report showed a 4.6 million barrel a day decline in crude oil inventories against expectations for a 1 million barrel build. Gasoline inventories declined by 4.15 million barrels compared to expectations for flat inventories. Check out my chart below for a closer look at this data.

Source: Bloomberg

This chart shows the change in US crude oil inventories as reported by the EIA each week compared to analysts’ consensus expectations heading into the release. The interpretation is simple: Negative numbers on this chart suggest crude inventories are falling faster than expected or rising less than expected. In other words, negative numbers are bullish for crude oil prices.

As you can see, last week’s data was the most bullish inventory report on this measure since the early summer of 2008. Although the data was released too late to be included in the chart above, the inventory numbers released this morning were equally bullish.

The EIA reported a 2.11 million barrel drop in US oil inventories against expectations for just a 400,000 barrel per day drop. Similarly, the agency reported that US gasoline inventories fell by more than 4.3 million barrels compared to expectations of a 1.2 million barrel drop.

The report also showed further improvement on the four-week moving average for demand. Motor gasoline demand is down just over 1 percent year-over-year.

It’s still early to make a definitive call, but the recent decline in inventory data likely reflects the beginnings of a tightening in supply. Specifically, demand appears to be stabilizing, while global oil production is in outright decline. OPEC countries have been cutting their output in line with targets agreed to earlier this year. These nations have also delayed planned projects that would have increased their production capacity.

Meanwhile, oil and gas exploration and drilling activity has declined markedly in non-OPEC countries, and there’s growing evidence that production is declining more rapidly than expected. I highlighted comments from oil services giants Weatherford and Schlumberger and Weatherford in each of the last two issues, and both firms agree that current levels of investment and drilling activity will result in declines in global oil supply and production.

Oddly, in last week’s Short-Term Energy Outlook (STEO) the EIA revised lower its expectations for global oil demand and revised higher expectations for non-OPEC production. The action in the crude oil market since that release suggests market participants don’t put much stock in these estimates. This report doesn’t really jibe with the following chart.

Source: BP Statistical review of World Energy 2008, Bloomberg, The Energy Strategist

This chart shows non-OPEC oil production and crude oil prices. The important point to note is the final few years on the chart. Obviously oil prices soared over this time from an average price of less than USD40 a barrel in 2004 to a near USD100 average last year. With those high and rising oil prices, exploration and production firms poured record sums into oil exploration and development. Yet despite all these incentives and investment over five-years non-OPEC oil has basically remained flat over this time period.

If oil production remained flat with record sums invested, it doesn’t seem at all reasonable to expect oil production to do anything this year but decline given the precipitous drop in spending. And that’s exactly what’s happening.

The final point worth noting is that the US is the world’s largest oil consumer, not the world’s only oil consumer. China is a key source of global oil demand, and the Chinese economy is reviving far faster than most pundits expected at the beginning of the year.

Several Portfolio holdings will see an outsized benefit from improving conditions in the global oil market. I mentioned oil services firms Weatherford and Schlumberger above and in the previous issue. Three more solid plays on oil’s upside are: Gushers Portfolio recommendation Dril-Quip (NYSE: DRQ) and Wildcatters Portfolio recommendations National Oilwell Varco (NYSE: NOV), Suncor Energy (NYSE: SU) and EOG Resources (NYSE: EOG).

I recommended Dril-Quip and National Oilwell Varco in the April 1 issue. National Oilwell is an oil services and equipment firm that operates in three basic businesses: Rig Technology, Petroleum Services and Supplies and Distribution Services.

Rig technology is the crown jewel of National’s business; the unit builds key equipment used on land and offshore drilling rigs. The unit is currently benefiting from the boom in deepwater drilling activity; as Schlumberger pointed out in its recent conference call, deepwater is one of the only drilling markets that continue to see growth despite the decline in commodity prices this year.

Equipment used on deepwater drilling rigs is far more complex and expensive than that used on land or shallow-water rigs. As a result, selling equipment into the deepwater market carries far higher profit margins for National.

National Oilwell’s stock price did decline slightly following its first quarter earnings release in late April. That decline was a great buying opportunity. Since then, the stock has rebounded and recaptured its post-earnings decline and then some.

One potential ongoing catalyst for National Oilwell is a series of major deepwater oil projects being managed by Brazil’s national oil company, Petrobras (NYSE: PBR). The company has announced several major discoveries over the past year and a half and should be releasing more data on the potential for these fields in coming months.

Petrobras will need at least 28 new ultra-deepwater rigs to develop all of the fields it’s found, and a new ruling from the company’s government regulator may force it to accelerate the development of these fields. This would, of course, mean more business for National Oilwell, a key supplier of equipment for such rigs. I’m raising my buy target for National Oilwell Varco slightly to USD37.

Dril-Quip is another direct play on the prospects for growth in deepwater exploration and development activity.

Dril-Quip has two divisions: Drilling Equipment and Services. The former accounts for about 85 percent of revenues and is the main division of interest from an investing standpoint. The company’s drilling equipment segment mainly manufactures subsea products used primarily in deepwater offshore field developments.

Dril-Quip beat analysts’ expectations by a small margin when it reported earnings May 8, but the stock soared close to 10 percent on the results. The stock reacted positively to the upbeat tone of management’s conference call and the fact that many expect Petrobras to award significant contracts for subsea equipment over the next six months. Dril-Quip should win more than its fair share of these deals.

Given ongoing strong leverage to growth in deepwater, I’m raising my buy target for Dril-Quip to USD32. The stock is showing a profit of close to 40 percent since my early April recommendation. To lock in some of that gain, I’m raising my recommended stop to USD31.50.

I recommended oil sands giant Suncor in the March 18, 2009 issue, and followed up on the proposed Suncor/PetroCanada (TSX: PCA, NYSE: PCZ) merger in a March 23, 2009 Flash Alert.

Suncor reported earnings in late April. The company reported stronger-than-expected refining results for the first quarter, a reflection of improved refining margins in Canada in the first quarter relative to depressed levels of late last year.

Longer term, the more exciting story for Suncor is its upstream business, the actual production of oil. As I noted in my original recommendation for the stock, the company is one of the only firms on the planet capable of significantly increasing its oil production over the next three to five years. Up until commodity prices collapsed last year, Suncor had planned a series of expansion projects that would have allowed it to double its production to about 550,000 barrels a day by the end of 2009.

The only swing factor is capital spending. To increase its production, Suncor would need to invest heavily in its oil sands projects and related infrastructure. To make that worthwhile, oil prices need to stabilize north of USD70. When it became clear that oil would head below that level last year, Suncor delayed plans for expansion.

But Suncor’s upstream business isn’t in standby mode. The company is taking steps to reduce its operating costs, effectively lowering the breakeven costs for its existing operations. That breakeven cost is currently around USD33 for Suncor, and management believes it can push those costs down even further in coming quarters. This should help shore up profitability as oil prices recover.

Keep in mind, however, that there’s a difference between operating costs and new development costs. The former applies to existing production capacity where many key infrastructure investments have already been made. The latter applies to new developments that will require billions in new spending on related infrastructure and equipment.

The idea that Suncor loses money at current oil prices is totally wrong; existing operations are nicely profitable with oil near USD60. But to justify billions in new spending, Suncor needs oil prices reliably above USD70. If I’m right about crude, we’re likely to see Suncor ramping up its spending plans again in 2010.

The firm will be well-placed to bring new volumes online in a rising price environment, and current cost-cutting efforts will bear fruit in the form of higher profitability as crude rallies. Suncor Energy is a buy under USD32; set a stop-loss at USD21.50 to control risk.

Most investors seem to regard EOG Resources as a play on natural gas prices, not crude oil prices, as it’s traditionally been gas-focused. But that’s not a fair assessment; in fact, much of EOG’s planned production growth in coming years will come from oil plays, not gas developments.

EOG has announced a series of key crude oil plays in recent quarters. Two of the most important are the Bakken oil play of Montana and North Dakota and the Northern Barnett Shale of Texas. Both of these fields are what are known as unconventional shale plays.

Unconventional fields are nothing new; producers have known about many of today’s hottest unconventional gas and oil plays for many decades. However, these fields were mainly thought to be uneconomic to produce.

Natural gas and oil don’t exist underground in some giant cavern or lake. Rather, hydrocarbons are found trapped in the pores and cracks of a reservoir rock. A typical conventional reservoir rock is sandstone; sandstone looks like a mass of sand particles stuck together to form a rock. Sandstone has many pores that are capable of holding hydrocarbons. In other words, sandstone has favorable porosity.

Typically, those pores are also well connected such that oil and gas can easily travel through sandstone reservoir rock. Such rocks have a high degree of permeability. When a producer drills a well in a conventional field, oil and gas travel through the reservoir rock and into the well, powered mainly by geologic pressures.

Shale fields and other unconventional fields aren’t particularly permeable. That means while there is plenty of oil and/or gas trapped in the rock, there are no channels through which that oil or gas can travel. Thus even in shale fields where there’s plenty of geologic pressure, the hydrocarbons are essentially locked in place.

Producers have developed two major technologies in recent years to unlock shale: horizontal drilling and fracturing. The first technology is self-explanatory: Horizontal wells are drilled down and sideways to expose more of the well to productive reservoir layers.

Fracturing is a process by which producers actually pump a liquid into a shale reservoir under such tremendous pressure it cracks the reservoir rock. This creates channels through which hydrocarbons can travel–fracturing therefore improves permeability.

The Barnett Shale play is located near Fort Worth, Tex. It’s primarily known as a gas play; however, EOG has discovered and developed a series of highly productive oil wells in its northern reaches.

Source: Texas Railroad Commission

This map shows a close-up of the portion of northern Texas where the Barnett Shale is centered. The red dots are gas wells, the blue dots are permits and the green dots are oil wells. Montague County, Tex., located on the northern part of this map in the very center between Clay and Cooke counties, is the center of what EOG calls its Barnett “oil combo” play.

The typical well in this area produces one-third crude oil, one-third natural gas liquids (NGLs that tend to have prices based on crude oil) and one-third natural gas. EOG has seen some extremely solid well results from this area and has the largest acreage position in the region.

All told, EOG plans to increase its oil production from the Barnett combo play from 12,000 barrels a day this year to 42,000 by 2012. The company has stated it gets solid profitability from these wells at current prices.

EOG’s Bakken oil play is centered in North Dakota. EOG has a total of about a half million acres there and has drilled some of the most successful oil wells of any producer in the region. The company has scaled back output for two reasons: a desire to wait for higher prices to bring back production and a lack of transportation capacity.

A single pipeline that serves the Bakken area EOG operates in that’s owned by Enbridge Energy Partners (NYSE: EEP). That pipeline is basically maxed out, so EOG was at one point trucking oil out of the play down to Cushing, Okla., at costs as high as USD25 a barrel, rendering such production weakly profitable at best.

EOG is taking steps to sort out its transport issues, trying to guarantee as much capacity as possible on the Enbridge pipeline. In addition EOG has arranged for rail service with Burlington Northern Santa Fe (NYSE: BNI) to transport barrels of crude to key terminals; according to management, this train offers transports costs roughly in line with the tariffs for the Enbridge pipeline.

Other producers may even want to pay EOG to piggyback some of their volumes on EOG’s train service. The company believes it could ramp up this service to transport as much as 20,000 barrels a day from the Bakken.

At any rate, based on management’s comments we could see Bakken volumes begin to ramp higher again by mid-summer if oil prices continue to improve. With most of its growth coming from unconventional oil plays, EOG Resources, a great play on a recovery in oil prices, is a buy under USD100.

Back to In This Issue

Gas and EIA-914

I’ve spilled considerable ink over the past month discussing the reasons for my bullish outlook for natural gas prices. My outlook is firmly out of consensus; there are plenty of pundits calling for a prolonged, multi-year period of depressed natural gas prices.

However, over the past two weeks several key natural gas exploration and development firms have reported earnings and offered their outlooks for gas production and prices. That list includes Chesapeake Energy (NYSE: CHK), the firm behind Wildcatters Portfolio recommendation Chesapeake Energy 4.5 Percent Preferred D (NYSE: CHK D) and Proven Reserves holding Chesapeake Energy 6.375 Percent Note of 06/15/15 (CUSIP: 165167BL0). Also reporting earnings was Wildcatter XTO Energy (NYSE: XTO).

Reports from these firms back up my bullish gas thesis. It appears that the only question surrounding gas markets is when they’ll rally, not if they’ll rally. Further, most producers are in agreement that USD6 to USD7 per MMBtu gas prices will be necessary longer term to support sufficient production to meet normal market demand.

Chesapeake CEO Aubrey McClendon offered the following observation in his remarks opening his company’s first quarter earnings conference call:

Today’s gas prices are clearly not strong enough to support a North American rig count that is high enough to prevent a very severe and unprecedented decline in North American gas production. In fact, our modeling shows that if gas rig counts stay around the 700 mark in the US and the 50 mark in Canada during 2009, that by the end of the 2010 first quarter, North American gas production on a year-over-year basis will be about 10 percent lower, and headed further south very quickly.

Once all of us figure out what LNG [liquefied natural gas] imports will look like this summer, and once we get a better handle on gas demand trends for the rest of the year, investors will begin focusing on the inescapable reality that by the middle of the winter of 2009 and 2010, North American gas production will likely be in freefall. I ask you to consider how many gas market investors will want to be short natural gas in that scenario. My view is not many. This will set the stage for a dramatic reversal of natural gas prices sometime this fall or winter.

Mr. McClendon offers a nice overview of how Chesapeake is looking for the gas markets to unfold in coming months. Basically, he’s saying that the current North American gas-directed rig count of 728 will result in a year-over-year decline in US natural gas production of more than 10 percent. He seems to suggest that the rate of decline would continue to accelerate rapidly the longer the rig count remains depressed.

There’s good reason for this: huge decline rates. More and more natural gas production is coming form unconventional shale plays such as the Barnett. One issue with many of these fields is that they have extraordinarily high decline rates; while initial production rates are sky-high and economics are solid, production drops off quickly in the first year of a well’s productive life.

Take the prolific Haynesville Shale in Louisiana. This play is perhaps the most talked-about unconventional natural gas play in the US today. According to Chesapeake, the first-year decline rate for its Haynesville wells is a whopping 86 percent.

In the first year of its life, production from a Haynesville gas well drops off precipitously. Chesapeake further noted that the second-year decline rate is a further 29.5 percent, the third-year about 20 percent. At the end of its third year, a Haynesville well will be producing less than 8 percent what it was when first put into production.

If new wells aren’t drilled to offset these decline rates, production will inevitably tail off. The further the rig count declines, the more that massive unconventional shale well decline rate will bite into production.

Chesapeake management did mention two potential bearish factors for natural gas prices. The first is imports of liquefied natural gas (LNG), which is simply a super-cooled form of natural gas that can be loaded onto special tanker ships and shipped over extremely long distances. I discuss this concern in the March 25 Energy Letter; while I suspect we’ll see a seasonal up-tick in LNG imports this summer, it won’t be as significant as some bears project.

First, many of the planned LNG export facilities that were due for completion before this summer are likely to be delayed or have already been delayed. Moreover, with gas prices higher in the European Union, Asia and parts of South America, these regions will absorb a good bit of the world’s uncommitted LNG cargoes.

Second, just as with oil, there’s a demand issue. In the previous TES I described my surprise at the severity of the decline in industrial demand for gas over the past year. This decline in demand is primarily a function of weak economic growth. But I see the US economy stabilizing and likely mounting a recovery by the end of this year. The outlook for gas demand will likely improve over the next few quarters.

Bottom line: Gas prices under USD4 per MMBtu price in the risks of weak demand and higher LNG imports but don’t account for the potential for a 10 percent or greater drop-off in gas production by the end of 2009. Thus, I see fundamentals for gas improving by year’s end; prices of related equities will likely lead that recovery by six months or more as traders try to anticipate the turn. This is exactly what’s been happening in recent weeks as natural gas and related equities have rallied off their lows.

Chesapeake management mentioned a handful of additional interesting points during its conference call. Consider the following:

Our own internal work suggests the very best unconventional plays will need USD6 to USD7 NYMEX gas prices to justify an increase in drilling while the more challenged conventional plays will need at least USD8 to USD9 NYMEX gas prices…

…Please remember that the Big 4 shale plays [Barnett, Haynesville, Fayetteville and Marcellus] only produce about 12 percent of North American gas production. So we have to have a gas price that can keep the vast majority of the other 88 percent of gas production supported by maintenance-level drilling.

The unconventional US shale plays are arguably the most exciting natural gas plays in the world today. Analysts tend to spend an inordinate amount of time analyzing growth prospects for these huge, fast-growing plays. This makes some sense, but Chesapeake makes a good point: The US still gets most of its gas production from outside these plays. These conventional fields need to be at least maintained over the long term to ensure US gas production won’t fall. Because conventional fields tend to carry higher costs than the shale plays, gas prices need to rise to a level that will sustain the economics of these plays.

Another interesting component of the Chesapeake call was the discussion about falling services costs. Basically, falling gas prices have meant idled drilling rigs. The same is true of other key natural gas-related services such as hydraulic fracturing capacity. As demand for gas-related services and drilling declines with the rig count and capacity is idled, services firms are cutting their prices. Most of the producers noted overall declines in services costs of roughly 30 to 35 percent beginning in April of this year.

The obvious assumption is that falling services costs will eventually bring down well costs and make wells profitable at lower gas prices. One implication is that this would lower the normalized price level for gas producers from about USD6 to USD7 to some lower range. In other words, perhaps with lower services costs, producers could handle a lower gas cost.

But the reality is that this effect appears to be overstated. Several producers noted that the scope for services costs to come down is limited. Here’s what Chesapeake had to say:

…Putting it in the context of seeing [natural gas] prices decline 75 to 80 percent and seeing the ability probably for the service guys to get their costs down 50 percent, you see the gap…It [services costs] just doesn’t yet reflect what has happened more dramatically on the revenue side. Now we’re going to continue to push prices lower…but obviously there is a limit…

Chesapeake says that while services costs have fallen, they haven’t fallen as dramatically as gas prices. And, if services firms with a focus on North America are to remain viable longer term, costs can’t drop much further. There are also more intractable costs such as transportation and steel, which don’t provide scope to come down much further.

Gas prices still need to rally significantly from current depressed levels. Services, drilling and equipment cost reductions just aren’t enough to make producers profitable at USD3.50 to USD4 gas.

I’m not stove-piping Chesapeake management’s comments because they support my bullish view on gas prices. While there are subtle differences, most producers made broadly similar comments about the current environment. Consider the following comment from XTO Energy, another key TES holding:

…I think you’ll see the back half of the year production falling off at some 10 to 12 percent cliff if the rig count keeps coming down. I think your natural gas rig count is at 740, it’s kind of flattened for a couple of weeks, but I doubt that holds.

I know we are going to drop a couple more rigs and some other people will as well, so I think you’ll see rig count continues to decline and get under 700 here over the next couple of weeks. And so I think we will be set up for a price rebound as we get into late ’09, early ’10 as production begins to fall off and demand begins to pick back up.

This outlook is remarkably similar to Chesapeake’s. XTO is also looking for the rig count to bottom out around 650 to 700 rigs and states that that level of rig count is compatible with a 10 to 12 percent decline in US gas production. Like Chesapeake, XTO highlights the back half of 2009 and into 2010 as the key window for such a normalization of prices.

XTO Energy also notes that it’s put its money where its mouth is when it comes to gas price projections. Typically, the firm looks to hedge about half to two-thirds of its production in any given time period. But management is willing to stretch that rule when it feels there’s a change in gas market fundamentals.

XTO was prescient in locking in 80 percent of its 2009 gas production last year when prices were much higher. But only 30 percent of XTO’s 2010 gas production is hedged; it will look to take that up to a 50 to 66 percent level on an opportunistic basis. Right now, XTO is looking for higher gas prices, so it isn’t yet adding to its hedges. The fact that XTO has maintained such an unusually large unhedged position for 2010 suggests it wants to participate in rising gas prices.

Many producers seem to concur with the view that current depressed gas prices and rig counts are unsustainable and that USD6 to USD7 per MMBtu represents a more normal natural gas price. The obvious question is what will catalyze a reversion to this “normal” price range. In other words, what will finally break gas out of its current bottom near USD4 per MMBtu.

The answer: a definitive turn in the EIA-914 Monthly Natural Gas Production Report. EIA-914 details natural gas production in the US by state. It’s released with a significant lag; the latest EIA-914 report was released at the end of April and showed data through the end of February. When the next report is released May 29, it will offer revised February data and preliminary estimates for March.

What we’re looking for are concrete signs that US natural gas production has begun to fall as a result of the rapid drop in the rig count–evidence that the supply normalization scenario that all of the producers are looking for is coming to pass.

We’re already seeing evidence that production is falling in the weekly storage reports released by the EIA. But EIA-914 is extraordinarily widely watched–about three-quarters of the E&P firm conference calls I listened to included mention by management of the report by name.

There’s a bit of debate among different firms as to exactly when EIA-914 will begin to show declines. However, the consensus seems to be that this decline will be evident by the May data at the latest; preliminary EIA-914 data covering May will be released in late July. Gas prices should see a boost as the EIA-914 figures turn.

As I noted in the previous TES, the reason the decline in production is lagging the decline in the rig count has to do with the way wells are drilled and put into production. XTO explained this concept in answering an analyst’s question:

…If you are in most of the conventional plays, you got a pipeline sitting there. So a conventional play maybe rig moves off, 60 days later you’ve got it on production, the shale plays maybe 90 to 120 days. That’s why I’m saying I think you’ll run out of your inventory in the March-April timeframe that we’ve built up, a la you might see production still build to that point and then start to fall as rig count is falling now. And I think a good way to look at that to give you an idea is frac [hydraulic fracturing] costs did not drop until April.

So, all these frac companies helped their margins until April and all of a sudden we saw them start coming in and dropping their prices 30 or 35 percent. What that says is they are letting frac crews go, a la we now have too much frac crews to the number of wells that are being completed…we are running out of the backlog of wells that used to be there.

What XTO is saying is that many of the unconventional shale wells that were drilled in the third and fourth quarters of 2008 were still waiting to go into production early in 2009. Back then, the rig count was much higher, so a large number of wells were drilled.

This backlog of drilled but not yet producing wells was enough to keep production growing up until around April. But with that backlog exhausted, the declining rig count will begin to show up in actual EIA-914 production data.

The traditional relationship between the US rig count and gas prices hasn’t been abolished; rather, due to pipeline and other infrastructure constraints that existed last year, the lag effect between rig count and production has increased somewhat.

Remember that gas-levered stocks could typically be expected to rally before the commodity and fundamentals for gas improve. I suspect that’s exactly what we’re seeing today–gas-levered stocks have rallied significantly in recent weeks.

XTO Energy, which reported solid first quarter results, is the most direct natural gas play in the TES Portfolio.

XTO has a long history of making acquisitions in key plays and then systematically cutting operating costs to boost profitability. Over the past few years the firm has assembled a top-notch position in several of the most promising US shale plays, including the Barnett, the Arkansas-focused Fayetteville, Oklahoma’s Woodford, Louisiana’s Haynesville, and the Marcellus in Appalachia.

XTO has 277,000 net acres in the Barnett, nearly 60 percent of which are located in what’s known as the “core” or “fairway” of the play. This is an important factor to watch. Don’t be duped by companies that market the fact they hold huge acreage positions in a particular play. Be very careful in evaluating where those acres are located. In the Barnett, wells located in the core areas spanning Johnson and Tarrant counties can be 10 times more productive than wells located on the western frontier of the play in counties such as Erath.

XTO showed 7 percent growth in Barnett production for the quarter and has 13 rigs running in the region. The firm is reporting a large number of new wells that are highly productive and is therefore actually struggling to bring production growth down; XTO doesn’t want to produce this gas to sell at USD3.50 even though its finding and developing costs in the Barnett core stand at USD1.13 per thousand cubic feet. XTO plans to scale back wells completed to bring down growth and wait for higher prices.

In the highly productive Fayetteville, XTO has 380,000 net acres and is seeing some stellar growth rates in production. The company has six rigs in the region and was producing about 60 million cubic feet per day, up from 25 to 30 at the end of 2008. XTO is looking for a further doubling in production by year’s end.

XTO is also diverting cash to its Haynesville play. The company has been gradually bringing its well costs down to improve economics and has drilled a total of just two wells, both of which have shown strong initial production rates.

XTO also has a solid position in the Bakken oil play; this play has been performing well above expectations so far this year.

XTO Energy, with its low cost structure, is a buy up to USD45; use a stop-loss at USD27 to limit downside.

Given the potential for gas prices and related equities to see a strong rally between now and year’s end, it’s time to increase our exposure to gas in the Portfolio.

I profiled contract driller Nabors Industries (NYSE: NBR) in the previous TES. Nabors is a contract land driller but is differentiated from the rest of its industry by the fact it has strong international operations and a fleet that includes some of the industry’s most capable and efficient rigs.

Nabors can be a volatile stock, so I’ve set a relatively wide stop; consider establishing a smaller position to compensate for the added risk. Nabors Industries, a new addition to the aggressive Gushers Portfolio, is a buy under USD19 with a stop-loss at USD12.50.

Another play on gas I’m watching for possible inclusion in the Portfolio is US Natural Gas Fund (NYSE: UNG). This is an exchange traded fund (ETF) that tracks the actual price of NYMEX-traded natural gas.

This ETF isn’t a perfect reflection of gas prices, but it’s close enough to be useful. For now, I’m adding it to the How They Rate coverage universe as a buy recommendation. I may look to add it to the Portfolio on any further weakness in coming weeks.

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The Other Yellow Metal

In the previous TES I wrote extensively about the ongoing revival of global uranium markets. Since that issue was published, even more evidence of an impending turn in the uranium market has emerged.

TradeTech, a uranium market news and information service had the following to say about spot uranium in its May 15 update:

The spot uranium market continues to be quite active with nearly 3 million pounds U3O8 equivalent purchased in seven separate transactions over the past week. The buyers consisted of utilities, producers, and traders. Three of these transactions were in negotiation at the close of business last week, but were not concluded until the early part of this week. Additionally, spot uranium demand continues to emerge with at least six parties actively seeking offers for just over 2 million pounds U3O8 equivalent.

Not surprisingly, the sharp increase in the spot uranium price over recent weeks has caused a few buyers to pull back from the market while higher prices have stimulated more interest from some sellers. As a result, the steep climb in prices observed over the past two weeks has moderated somewhat, with TradeTech’s Spot Price Indicator increasing USD2.00 to USD51.00 per pound U3O8, as compared to last week’s increase of USD4.00 per pound U3O8. Prices in transactions concluded during the first part of the week were near last week’s Spot Price Indicator while those concluded at the end of the week were at, or near, today’s Spot Price Indicator.

Volumes traded in the spot uranium market have exploded in recent weeks amid buying interest from utilities, producers and traders alike. This activity has removed the supply overhang in the spot market that’s depressed prices over the past year and a half.

It’s also interesting that there’s growing interest in uranium on the part of investment/financial buyers. This source of demand dried up almost entirely during the credit crunch last year. It could well be a source of incremental demand going forward. I look for uranium to head back to the USD60 to USD70 per pound region over the next few months.

One interesting development among the uranium picks I discussed May 6 is that one of my long-time favorites, Paladin Energy (Australia: PDN; Toronto: PDN), has been added to the MSCI Global Standard Index for Australia.

As always, the addition of a stock to an index typically results in buying interest. Many money managers passively track indexes and must buy all of the stocks in a particular index. The MSCI indexes are popular, so this should help push up Paladin between now and its official June 1 addition.

This index addition also reflects the fact that Paladin has successfully started two mines in Africa and is now an established producer. The company is no longer just an exploration or development stage firm. Buy Paladin Energy as part of my Uranium Field Bet.

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China Is Buying Coal

I’ve written extensively about global coal markets in recent issues. There are still a few key headwinds facing producers.

Demand for steel hit a wall late last year as the global economy ground to a halt. Particularly damaging was the slump in the Chinese economy and in China’s seemingly endless demand for steel. Metallurgical, or coking, coal is a high-energy-content form of coal that’s used in steel production. Demand and prices for met coal fell sharply as demand for steel waned.

As for thermal coal, utilities in the US are reporting fairly bloated stocks of coal on hand. According to the railroads and mining firms I analyzed in the April 22 issue, these utes are more likely to look for ways to reduce or delay their coal shipments to prevent an outright inventory glut.

Miners are supported by a few key trends as well. First, most sell a considerable portion of the coal they produce under long-term contracts, not on the spot market. In many cases, these contracts were signed last year, when coal prices were sky-high. Many of the big producers, including TES recommendation Peabody Energy (NYSE: BTU), are actually seeing their realized prices rise as legacy contracts signed years ago at even lower prices roll off the books.

Second, producers are responding to the slump in coal prices by reducing output. Many higher-cost mining operations in the Eastern US will simply shut down; at current prices they just aren’t profitable. This has, and will continue to, pushed supplies down and support prices.

Now I’m also seeing another bullish development for coal firms and it related directly to China; check out the two charts below for a closer look.

Source: Bloomberg

Source: Bloomberg

These charts show Chinese coal imports and exports for March. It’s clear that Chinese coal imports have hit a record high, even higher than the booming coal trade market of early 2008. Meanwhile, Chinese coal exports have slumped to near record-low levels. Simply put: China is once again aggressively buying coal to feed its resurgent economy.

This is great news for global coal producers, especially those in Asia that sell directly into China such as Gushers play Peabody Energy. Thanks to its purchase of Excel Coal a few years ago, Peabody has some prolific mines in Australia primarily aimed at exporting coal to China.

I discuss my recommended covered call trade in Peabody Energy in the May 6 TES.

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