Crude oil is far and away the most widely watched energy commodity. Although many investors fixate on every price change in the crude oil market, they ignore the fact that coal mining stocks have actually outperformed oil-related names in recent months.

Prospective investors seeking exposure to the coal industry should remember that selectivity is the key to success. Some coal markets are booming right now; others are in for at least another year of depressed prices. In this issue I’ll sort through the sector, survey the dynamics driving different coal markets and highlight my favorite plays.

Natural gas prices have lagged in recent months, but indicators continue to suggest a bottom; I expect gas prices to rise through year-end and double over the next 12 months.

There is a great deal of misinformation out there about natural gas; I have read essentially the same bearish arguments for gas in several mass-market publications. But these arguments are equivalent to three-day-old leftovers: Investors have known about these headwinds for months and, at under $4 per million British thermal units (MMBTU), prices have already more than factored in these challenges.

In this issue, I’ll analyze what’s really going on and the prospects for a big recovery in gas in coming months.

In This Issue

Coal-related stocks have been some of the energy sector’s top performers over the past several months. I explain my bullish stance on coal companies with exposure to emerging markets and discuss the near-term and long-term prospects for US coal miners levered to the domestic market. See Coal.

The complex dynamics that drive natural gas prices cause a great deal of misinformation to circulate in the mainstream media. I outline my bullish case for natural gas prices over the next 12 months and explain why now is the time to invest in this industry. I also set the record straight on production from unconventional plays and its implication for gas prices. See The Comeback Kid.

Selectivity is the key to picking winners levered to the recovery in natural gas. I highlight the top plays in the TES Portfolios as well as one for the future. See Natural Selections.

Energy markets are fast moving. I provide an update on how our hedge against a pullback in oil prices has fared. See Portfolio Update.

Coal

In the last issue of The Energy Strategist, I highlighted earnings results from railroad CSX Corporation (NYSE: CSX) and coal mining giant Peabody Energy (NYSE: BTU). I won’t rehash my analysis here; suffice it to say that the US coal market continues to languish–utilities have large coal stockpiles, and demand is weak because of a struggling US economy and cooler-than-average summer.

The situation could not be more different in Asia. For two months straight, China’s imports of coal have reached record levels. The Chinese steel industry is reviving, powering demand for high-value metallurgical (met) coal. And demand for thermal coal used in power plants in both China and India is also strong; utilities in India, in particular, are reporting dangerously low stockpiles of coal.

Reports have surfaced that there are Indian utilities with only two days worth of coal on hand. Inventory levels between 20 to 30 days would be considered tight but more comfortable for most utilities–this is a truly razor-thin stockpile cushion. Although China has a tendency to grab headlines and attract investors’ attention, India is emerging as a more important demand story for thermal coal over the next five years, a point that I outlined in the previous installment of TES.

The Australian mining sector is the primary beneficiary of a bullish Asian coal market. Australia is the world’s dominant exporter of met coal and will remain so for the foreseeable future. And in thermal coal, Australia should overtake Indonesia to become the world’s largest exporter.

Those are the factors behind my recommendation of two coal mining firms: Peabody Energy (NYSE: BTU) and Felix Resources (Australia: FLX). Peabody is a US-based firm that recently spun off its Eastern US mining operations into a separate company, Patriot Coal (NYSE: PCX). Since 2004, Peabody has beefed up its overseas operations, particularly in Australia; in fact, the region now accounts for close to half of Peabody’s profits.

That transition has effectively reduced Peabody’s exposure to the weak US market and boosted its weighting in the strong Asian markets. Although I don’t recommend Peabody Energy directly, I recommended Peabody Energy covered calls in the March 4 issue, Big Budget Blues, and updated that recommendation in the May 6 issue, A Turn for the Better.

Peabody has performed well since that recommendation; if you were to close the covered call out today, your total profit would be roughly 38 percent. The total potential profit on this covered call recommendation is 68 percent if Peabody closes above USD40 on January 15, 2010 — the details of this calculation are explained in the the May 6 issue.

Subscribers who haven’t entered this position should consider buying Peabody Energy (NYSE: BTU) stock under USD40 directly without selling any calls. For much of the first half of this year, call options fetched unusually high prices thanks to the volatility priced into the options market; that volatility has since abated, and covered calls are less attractive than they were a few months ago.

For a more direct play on the Australian coal story, I continue to recommend buying Felix Resources (Australia: FLX; OTC: FLRFF). The company has a number of major mine expansions underway that will dramatically increase output just as Asian demand is on the rise. This will put Felix in an outstanding position to sell coal into a hot market.

In addition, given the size and quality of Felix’s major mines, I would not be at all surprised to see the company acquired, perhaps by a Chinese firm looking to secure supply. I outline the investment case for the stock in more depth in the June 3, 2009, issue of TES, “The New Super-Cycle.” Felix Resources rates a buy under AUD20 given continued strong fundamentals for Australian coal.

I resume my discussion of coal in this issue because the group remains among the best-performers in my coverage universe and should remain so for the remainder of 2009. Also, I’d like to caution subscribers about a few a names that have participated in the upside despite weak fundamentals.


Source: Bloomberg

This chart shows the performance of a half dozen coal companies over the past six months. The chart shows that all six have outperformed the S&P 500 Energy Index by a comfortable margin; given our bullish stance on certain coal stocks, this is a definite positive.

Note that Felix Resources is among the best performers on this chart; the stock is also among the top performers in the industry since my recommendation. For the reasons I’ve outlined, this makes sense based on fundamentals.

What I find somewhat puzzling is the positive relative performance of stocks like Massey Energy (NYSE: MEE) and International Coal Group (NYSE: ICO). Both stocks operate mines primarily in the Central Appalachian (CAPP) region of the US and lack direct exposure to the strong growth in Asian coal demand.

Both also face relatively high mining costs and increasingly stringent environmental regulations. I have consistently recommended that subscribers favor mining firms with overseas business to those with heavy CAPP exposure; at least over this period, I have been right to recommend coal and Felix but dead wrong about the risks to CAPP producers.

Nevertheless, second-quarter earnings releases from the CAPP producers do little to change my bias in favor of Australian operations and the international market. Massey Energy is an outstanding company, and its mines in West Virginia, Kentucky and Virginia are among the lowest cost in all of CAPP.

The company also has a sterling financial position, an unusual trait among coal mining firms. Massey has more than $600 million in cash on the books and about $1.3 billion in debt, a reasonable net-debt position for a company with a market capitalization close to $2.4 billion.

Analysts participating in the Massey’s recent conference call asked management what it intends to do with all its cash and excess liquidity. Although management stated that it might use a small amount for strategic acquisitions, the content and tenor of this response suggest that the company plans to be conservative with its cash. I regard this restraint as a positive in a market where credit conditions are still returning to normal.

The problem with Massey isn’t how it runs its business, but the strength of its core market. In Improving Tone, I highlighted several comments from Peabody Energy’s conference call concerning the dismal state of the US thermal-coal market. Massey’s management broadly echoed those sentiments, noting that coal inventories at US utilities are extremely high and demand is weak because of cool summer weather.

Not surprisingly, because utilities have ample coal inventories, few are interested in contracting with coal mining firms to build supplies for 2010. In response to an analyst’s question about coal contracting volumes, Massey’s CEO Don Blankenship stated:

Now, I think that it’s as slow at this time of year for succeeding years as I’ve seen in my two decades of being familiar with it, so it’s slow. Inventories are high domestically. Prices will still be in the $60 [per short ton] range for a 12.2, 12.3 Central App coal [a common grade of CAPP thermal coal] because people can’t get it out of the ground on average for less than that. So the costs are fundamentally changed over what they were four or five years ago and that will keep the price higher than it was three or four or five years ago in a down market, but the market is very soft because everything–it’s the imperfect storm.

Although utilities do buy coal on the spot market for immediate delivery, most volumes are purchased under longer-term deals. Blankenship states that the utilities aren’t showing much interest in signing new contracts for coal supply.

But, it’s interesting to note his comments about price. Here’s a chart showing the price of a common CAPP coal over the past 9 years.


Source: Bloomberg

Blankenship indicates that coal prices aren’t headed back to their 2002/03 lows in this cycle because production costs have risen sharply since that time. Even the lowest-cost US coal producers wouldn’t be able to mine thermal coal profitably at $20 to $30. Although CAPP coal costs are well off the abnormally high prices of mid-2008, they’re still in line with prices roughly five years ago.

As you might expect, Blankenship and analysts on the call spent considerable time discussing when fundamentals for US thermal coal might improve and what events might catalyze such an improvement. The real wild card for US thermal coal prices is US coal exports.

One of the factors that drove the spike in coal prices depicted in the above chart was a surge in US coal exports. This occurred primarily because of European demand for US coal. Europe is a significant importer of coal but typically has imported most of its coal from Australia, South America and other major exporters of thermal coal. Although the US has been a major supplier of metallurgical (coking) coal to the EU, traditionally it hasn’t been a big supplier of thermal coal exports.

Last year that changed when Asia essentially grabbed all of Europe’s coal. Demand for thermal coal in countries like China and India soared; South African and Australian coal exports that might normally head for the European Union (EU) instead were diverted to Asia. Europe, desperately looking for an alternative supplier, found that the US not only had ample supply but, thanks to a weak US dollar, was a cheap source of coal. Imports surged, pulling considerable volumes of coal out of CAPP markets.

But exports collapsed when the global economy hit a proverbial wall last autumn and the credit crunch began to take hold. This contributed to the elevated inventories of thermal coal; without the export release valve, US producers were massively overproducing.

The wild card in this market is simply when this export release valve for US thermal coal might return. As Blankenship states in the company’s second-quarter conference call:

…as for the utility export side it’s just a heads-up for what is considered a soft Central Appalachia steam market, which is only 160 million ton market up against a 5 billion ton world market. [Market conditions] can change overnight if the dollar changes or freight rates, oil prices. So, we’re hesitant to forecast that the 2010-11 utility market will be really bad for Central App. We think it’s bad absent something like that happening…absent something export, I expect it to be very ugly for the next 18 months as far as new sales.

Massey’s CEO goes on to state that these comments aren’t based on any specific orders, though non-US utilities have “kicked some tires” and expressed interest in diversifying their coal supplies.

My take is that the potential for the thermal export market to reaccelerate is real: It happened in 2008 and could well happen again–and perhaps a lot sooner than most analysts expect.

However, given that we have no real evidence that such a trend is underway, it’s premature to forecast a recovery in US thermal coal prices. It also appears that the US economy is recovering more quickly than the European economy; EU electricity demand could remain sluggish even as US demand begins to stabilize and grow. If I’m correct in that assessment, coal demand could remain sluggish in the EU, lessening the region’s need to import thermal coal.

Bottom line: Blankenship states in the call that a key international coal benchmark known as API2 probably has to reach $80 to $90 per metric ton before US coal exports to the EU make sense. That particular grade of coal is about $10 to $15 below that range and might need to rise above the range and stay elevated for a while to really incentivize US exports.

In the absence of an export release valve, the US coal markets will likely take a year to 18 months to balance. In this scenario, I see another upside price squeeze in US coal occurring by 2011; US coal prices are now far too low for many smaller miners to make money. Even worse, their costs are rising as the Mine Safety and Health Administration (MSHA) has imposed a bevy of new expensive-to-implement safety regulations in recent years.

Two other problems endemic to CAPP are geology and permitting. As to the first point, CAPP is one of the oldest coal-producing regions in the world and seams are becoming thinner and deeper, rendering them hard to produce and prone to production shortfalls.

The permitting issue is an even bigger potential problem. International Coal Group discussed one mine in its conference call tfor which it has won a state permit on three separate occasions. Each time, the permit has subsequently been challenged by anti-mining activist groups; these challenges required another round of hearings and delays.

If coal prices stay where they are and costs continue to rise, a large number of smaller mining firms are headed for bankruptcy. Over the longer term, Massey and other large miners with lower costs will be able to consolidate market share by purchasing distressed mining assets. These bigger players can better afford the regulatory compliance spending needed to mine in CAPP.

But when utilities eventually return to the market looking for coal, they’re going to find a good deal less production capacity and a smaller number of sellers. That translates into shortages and higher prices to incentivize production. That being said, I view this scenario as a 2011 phenomenon–not an issue for 2009 or 2010.

The US thermal coal market appears weak, and there are limited and uncertain prospects for a near-term recovery. However, the US metallurgical coal market–coal used to make steel–is showing signs of life. At the risk of sounding like a broken record, this upside is being driven by demand from Asia.

In its quarterly call, Massey’s management team stated that it has seen estimates that China will need to import 50 million tons of met coal this year. Meanwhile, Indian steel production jumped 9 percent from a year ago in May, implying a surge in demand.

As a result, the company is enjoying increasing demand for its met coal and rising prices; Massey estimates that, going forward, half of its met coal exports will be destined for Asia–up from next-to-nothing a few years ago. The company raised its production forecast and brought some furloughed workers back into its employ thanks to a better-than-expected jump in met coal demand.

Note that there is an important distinction between the met coal business and the thermal coal business for Massey and other miners; the thermal market is normally US-centric, whereas met coal has a higher potential for export.

For its part, International Coal Group indicated that its met coal business is primarily domestic. However, it also appears to be benefiting from higher coal prices and met demand in Asia, two factors that are affecting US coal prices; the export release valve is working in the met coal market even though it’s still just a hope in thermal.

The upshot is that I wouldn’t sell Massey, International Coal and other US producers short right now. But I prefer to focus on producers that will directly benefit from overseas demand, especially Asian demand, which has been and will remain the light at the end of the proverbial tunnel for the coal industry this year. In this case, that means buying Peabody Energy and Felix Resources.

However, don’t forget this analysis. If we begin to see signs that US thermal coal exports are ticking higher or utility inventories are coming under control, stocks like Massey and International Coal will be my go-to names. For now, however, both stocks have rallied a bit too far, too quickly.

The Comeback Kid

For investors looking to play a market swinging from depressed conditions to a “normal” outlook, I prefer natural gas to US thermal coal.

One interesting comment I heard regarding the natural gas market actually came from International Coal’s CEO Bennett Hatfield during the company’s second-quarter conference call:

Natural gas prices also appear to have stabilized, although at a historically low price level. We expect natural gas prices will gradually increase due to the rapid decline in new exploration activity, as evidenced by the significant rig count drop in the US.

Coal demand, however, remains very weak and meaningful thermal price recovery may not occur until 2010…We expect that coal producers will continue to curtail production in response to soft demand. Recent weekly production comparisons indicate that deeper and accelerated production cuts are occurring in most US producing basins.

Coal mining executives monitor gas prices closely because natural gas and coal are potential competitors. Coal is normally the cheapest (and dirtiest) source of power, but natural gas can compete with coal when prices dip low enough.

That appears to have transpired this year. According to data on US electricity generation for April 2009 (the latest available), total electricity generation is off 4.7 percent year-over-year. But whereas the amount of coal burned in US plants dropped by 12.8 percent, gas use dropped just 2.4 percent. That jibes with comments from utilities, mining and natural gas executives regarding substitution between coal and gas this year.

Mr. Hatfield’s quote implies that he views the production adjustment process as somewhat further along for natural gas than coal; he expects that gas prices will begin to recover before the thermal coal market. Broadly speaking, I agree with this outlook.

I have outlined my bullish case for gas prices on several occasions over the past three months. Gas has seen some volatile moves in both directions but has essentially traded sideways; I view this market as a coiled spring, likely to see a significant move to the upside in coming months. Given the almost uniformly negative sentiment, most of the bad news is priced into this market–I see little downside risk from current levels.

I outlined my basic case for buying gas in brief in a May 28 Flash Alert, Gas Up. But in light of recent earnings reports and several months of additional data on production and storage, it’s time for an update on gas.

At the heart of any analysis of US gas prices are weekly US inventory statistics.

Source: EIA

This chart, which should be familiar to longtime subscribers, shows total natural gas in storage in the US compared to historic norms and averages.

The US natural gas storage cycle is fairly straightforward: More gas is consumed in winter than in summer because natural gas is a key source of heat. Although gas is also used in power plants and as an industrial fuel, the big seasonal swing in demand comes from the use of gas as a heating fuel.

During the winter months, the US tends to use more gas than it produces; the gas deficit can be filled by drawing gas out of storage. Accordingly, the period from roughly early November through early April is known as the withdrawal season.

Gas demand also spikes during the hottest summer months as gas is burned to produce electricity and power air conditioning; it’s rare but not unprecedented for the amount of gas in storage to fall during a hot summer.

Nevertheless, the period from the end of the heating season in April through the beginning of the next season in November is usually the injection season. That’s because demand for gas tends to be less than supply, so storage increases in preparation for the coming winter.

In the chart above, you’ll see four lines. The shaded blue line traces the average gas storage level from 2003 through 2008. The shaded yellow and purple lines indicate the 5-year maximum and minimum storage levels over the course of the year.

Finally, the solid line on my chart tracks natural gas storage levels this year. As you can see, the year started off with gas storage levels falling in line with the average. In late February or early March that all changed: Storage levels jumped and eventually broke to a new five-year high. Needless to say, there is a large amount of natural gas in storage in the US and no immediate sign that this glut will be eliminated. Ample supply usually leads to weak prices or at least puts a lid on gas price advances.

This inventory picture is the basis for all of the bearish arguments you’ll hear surrounding natural gas prices. But a known fundamental is a useless fundamental; if everyone already knows about something, the news is probably priced into the market.

The weekly gas storage report is no secret; it’s the most widely anticipated market-moving event for the industry. As you can see from the above chart, the glut of gas is nothing new, and gas inventories have been trending well above their five-year maximum levels for several weeks running.

And the consensus is that natural gas storage will actually reach its maximum physical level by the end of the injection season, if not before. While no one knows the maximum total storage capacity, it’s likely in the region of 3.7 to 4 trillion cubic feet of gas. The country could probably squeeze a bit more capacity out by simply increasing the pressure in pipelines, but that’s hardly a solution. Ultimately some producers would be forced to shutter wells until there’s sufficient storage space to accommodate additional gas.

If the US does max out natural gas storage facilities, gas injections would stop and storage would remain near that maximum level until the onset of winter heating (withdrawal) season. The natural gas market would effectively reset with the approach of winter heating season.

Chesapeake Energy (NYSE: CHK) is the largest independent gas producer in the US, so I always listen carefully to its conference calls and comments made by the company’s well-known CEO Aubrey McClendon. McClendon stated clearly in the company’s most recent call that natural gas in storage is likely to hit the maximum level.

 …given where storage is it was our analysis that we’re going to be full up on storage by the end of the year. And as we get closer to that, pipeline pressures are going to increase and that is going to cause involuntary curtailments. I think that our view was that there was no reason for us to voluntarily curtail gas, when pretty soon, everybody is going to start involuntarily curtailing gas and so we didn’t see any reason to take it on the chin for the team more than we did. And instead, we’ll just let the system work to spread the pain across the whole industry here over the next couple of months.

Although McClendon expects natural gas storage to hit its physical limits by the end of the injection season, Chesapeake isn’t voluntarily shutting down any of its wells because it sees no reason to forego revenue while others continue to produce. Once gas hits its maximum level, it will force all producers to shut in wells to balance the market.

Bottom line: It’s no secret that natural gas inventories are extraordinarily high and storage capacity is dwindling. These fundamentals are why gas dropped from the mid-teens last summer to $3 to $4 per million British thermal unit. Nonetheless, it’s truly amazing how many articles have been written in prominent business publications using just this rationale to predict lower prices.

The important issue isn’t whether gas will hit its theoretical maximum storage levels this year; I’m more interested in whether gas storage levels will normalize quickly as we move into 2010. For insight into future trends, one has to delve into the reasons behind the supply glut: weak gas demand and robust production from unconventional plays.

The most recent demand data from the Energy Information Administration (EIA) is for the month of May. The EIA breaks down gas demand into five categories: Residential, Commercial, Industrial, Vehicle Fuel and Electric Power. Here’s a graph illustrating the changes in gas consumption over the past year.

Source: EIA

Positive numbers on this chart indicate months when demand increased compared to 2008. As you can see, residential and commercial gas use was actually higher in January than it was one year earlier, primarily because January 2009 was colder than average while January 2008 was warmer than average.

Residential and commercial demand was lower year-over-year in February and March but the comparison isn’t the most instructive; because key gas-burning regions of the US experienced a cold snap in February and March 2008, we can’t attribute weak gas demand to residential or commercial consumers–demand patterns are weather and heating related.

Electric power demand also fails to show a clear bias. In fact, as I noted earlier in today’s report, you can clearly see that power demand for gas increased in May from year-ago levels, likely as consumers substituted cheap gas for coal.

A decade from now, gas may become a more important fuel for cars, trucks and buses, but vehicles account for slightly over 0.1 percent of US gas consumption. Clearly the automobile segment is not the primary driver of the decline in demand.

That brings us to industrial demand, the final component of natural gas consumption. As depicted in the graph, the industrial segment is the only component that showed persistent demand declines for the first five months of 2009. That strongly suggests that the industrial segment is the primary culprit behind weakness in natural gas demand this year. Industrial demand is also the single most important source of gas consumption, accounting for just shy of 40 percent of total gas demand in a normal year.

Among other applications, industrial demand encompasses gas used to produce energy in factories, gas used in chemical and fertilizer production and gas used to heat metals. Industrial demand is sensitive to economic conditions; industrial production figures, released monthly by the government, serve as an excellent proxy for industrial gas demand.

The graph below plots the year-over-year change in US industrial production (IP) since the 1960s.

Source: Bloomberg

I have placed rectangles over major downside spikes in IP that coincide with US recessions. The recent decline in US industrial production is even deeper than the decline witnessed in the nasty recessions of 1974 and the early 1980s.

In this light, it should come as little surprise that industrial gas demand has fallen so sharply. Longtime subscribers know that my favorite quick measure of the US economy’s health is the Conference Board’s Index of Leading Economic Indicators (LEI). Following LEI allowed us to utter the word recession in late 2007 and early 2008 when most analysts felt the US could narrowly skirt a contraction.

My analysis of current LEI data leads me to believe that the US recession is bottoming out and that the recovery will begin by the end of the third quarter or early in the fourth quarter–an outlook I discussed at length in Improving Tone. I also analyze economic indicators and conditions regularly in my free e-zine, PF Weekly.

IP data is also showing signs of bottoming out, as depicted in the following graph.

Source: Bloomberg

Month-over-month changes in IP are noisy and there are plenty of short-term spikes in the data. However, I have once again labeled the major recessions since the 1970’s, and you can clearly see the deterioration in IP data inside the rectangles I have drawn.

In this most recent cycle, month-over-month numbers spiked to the downside in late 2008 and early this year–the action looks similar to what occurred in 1974. But IP figures have improved over the past few months.

Although industrial production is still shrinking 0.4 percent month over month, this measure appears close to moving into positive territory. A cursory examination of the 1974 and 1982 cycles demonstrates that the current pattern of IP stabilization and improvement is quite similar to the recoveries during those deep economic downturns.

The Institute of Supply Management (ISM) survey for manufacturing, formerly known as the Purchasing Managers Index (PMI), is another indicator worth watching.

Source: Bloomberg

ISM is a diffusion index: Levels above 50 mark an expansion in the manufacturing sector, whereas levels under 50 indicate a contraction. The index is based on a survey conducted by a non-profit association of around 300 US purchasing managers.

The most recent ISM release shows the index rebounding to 48.9, just shy of 50 and significantly higher than many economists had forecast for that period. It’s likely we’ll see ISM move above 50 over the next few months.

To make a long story short, the demand picture for natural gas is weak–primarily because of a massive slump in industrial demand. But the indicators suggest that industrial demand for natural gas will stabilize and begin to grow between now and year-end.

Natural gas supply is the second part of this equation. The key to US natural gas supply is production from so-called unconventional fields such as the Barnett Shale in Texas and the Haynesville Shale in Louisiana. I have written extensively about unconventional gas plays over the past few years. The September 3, 2008, issue of TES, Unlocking Shale, serves as a good primer on unconventional fields.

Over just the past few quarters, major US gas producers have been discussing yet another new unconventional gas field in the US that appears full of promise: The Granite Wash, which runs through western Oklahoma and the Texas panhandle. Some of the biggest players in the region include Chesapeake Energy (NYSE: CHK), Newfield Exploration (NYSE: NFX) and St. Mary’s Land and Exploration (NYSE: SM).

In late July, Newfield announced that the seven wells it drilled in the region returned an average initial production (IP) rate of 22 million cubic feet per day–an extraordinary result, especially if this IP rate is fairly consistent across the territory.

With this find, the US has the potential to overtake Russia as the world’s top gas producer, if these unconventional plays pan out as expected and are drilled aggressively. That’s the key point to keep in mind: Production of natural gas is directly related to drilling activity, especially in unconventional plays.

When a producer drills a conventional gas well, production starts off strong; underground pressures are high, so the natural gas flows easily to the surface. But as the well is produced, underground pressures gradually decline–along with the rate of production.

A conventional well in the US might see production decline by about 30 percent from the IP rate. The decline rate slows over time, and a conventional well can continue producing at highly economic rates for many years.

At some point, a conventional well will reach maturity and production will plateau. Although this mature production rate is a fraction of a well’s IP rate, the pace of decline drops to just a few percent annualized.

The profile of an unconventional well is different. Late last month, just ahead of its second quarter earnings release, E&P giant Chesapeake put out a detailed operational paper that sheds some light on the production profile for four major US unconventional plays: the Haynesville, Barnett, Marcellus and Fayetteville Shale. This is a treasure trove of data because it’s based on a large sample of actual wells that the company has drilled.

The following chart depicts the production profile of a well Chesapeake drilled in the Barnett Shale, the first major US unconventional play to enter production:


Source: Chesapeake Energy Operational Update

The average Barnett well initally produces about 2.5 million cubic feet of gas per day. The graph tracks the production trend from the average Barnett well over a 36-month period. As you can see, within seven months, production falls 50 percent. The first year decline rate is 70 percent, roughly double a conventional well’s decline rate. After three years, production at the average Barnett well plateaus around 400,000 cubic feet per day–roughly 16 percent of its IP rate. In other words, production declines 70 percent in the first year and by 85 percent over three years.

The Barnett isn’t unique in this regard, ase demonstrated by the production curve for a typical well in the Haynesville Shale.


Source: Chesapeake Energy Operational Update

The IP rate for an average Haynesville well is 14.1 million cubic feet per day, an absolutely astronomical number that’s around six times the IP rate on a Barnett Shale well. 

But the average first-year decline rate for a Haynesville well is 85 percent; three years after a Haynesville well is drilled, that well is producing at just 7 percent of its IP rate.

In other words, US gas producers must drill aggressively in unconventional plays to increase overall production. Given the decline rates on unconventional plays, overall gas production will plummet without sufficient drilling activity. That is, producers exposed to unconventional plays must drill new wells to offset production declines at existing wells. To increase output, producers must constantly accelerate drilling activity to keep pace with existing wells and add to incremental output.

But US producers aren’t drilling aggressively. In fact, as the following graph shows, drilling activity has plummeted since late 2008.


Source: Bloomberg

This chart shows two key US rig counts, the gas-directed rig count (white line) and the horizontal rig count (orange line). The US gas-directed rig count is the total number of rigs actively drilling for natural gas in the US. As you can see, this rig count dropped precipitously back in 2001 when gas prices plummeted.

The US horizontal rig count measures how many rigs are actively drilling horizontal wells–a good proxy for drilling activity on unconventional plays. Of course, the horizontal rig count would also include horizontal wells targeting oil.

Back in 2001, the horizontal rig count dipped slightly, but there were less than 100 horizontal rigs in operation; unconventional plays in the US were still in their infancy.

Note what has happened in the most recent cycle. The US gas-directed rig count topped out in late August of 2008 at just over 1,600 rigs. The count plummeted as gas prices fell sharply and producers began to scale back drilling activity. The rig count now sits at 677 rigs, off around 60 percent, an even steeper decline in percentage terms than back in 2001.

I have seen all sorts of misinformation published about unconventional drilling activity; some analysts believe that although gas drilling has slowed, companies have continued to drill unconventional plays. This is patently untrue: The US horizontal rig count has fallen from its late-October 2008 highs of 650 to as low as 372 in early June–a more than 42 percent decline.

Why has the horizontal rig count ticked higher in recent weeks? Some observers claim this is evidence that gas shale drilling activity has reaccelerated. But remember that the gas-directed rig count includes both horizontal and vertical wells; we can see from the gas-directed line that gas drilling activity hasn’t budged from its lows.

The answer to this paradox is simple: The horizontal rigs that have come back into service since early June are targeting crude oil, not natural gas. This is logical when you consider that oil prices around $65 to $73 a barrel have made many US oil plays profitable again.

The plummeting rig count will eventually impact production, but the effect won’t be immediate. The Energy Information Administration publishes a monthly report entitled EIA-914 that breaks down total US gas production by region. The agency changed its methodology for calculating these figures earlier this year after many producers questioned the report’s accuracy.

At least some producers believe that EIA-914 is now a valid measure of US gas production. Here’s what Chesapeake Energy’s management had to say about the accuracy of this report during the company’s second-quarter conference call:

Analyst: …I wanted to get your thoughts on the accuracy of the 914 data and is that telling us a story consistent with with your view of what is happening with natural gas?

 Jeffrey Mobley Senior VP IR and Research: There are some flaws in the 914 data, and a change in their methodology that they announced earlier in the year does make you a little curious about the data. But at the end of the day, we think it is probably the most current and reliable data that you can find in the market on an aggregate basis. As you have seen in our prior presentations, we’ve done quite a bit of work to try to model out US gas production, and so far, the numbers that we have seen reported for that [report] are right on top of the model that we have outlined.

This statement indicates that the EIA data are meaningful and, in fact, track Chesapeake’s proprietary internal figures closely. Unfortunately, the EIA-914 data are released with a two-month lag; the most recent release on July 31 covered May production. The data is also subject to revision, though what’s really important is the direction of the trend. Here’s a look at EIA-914 data for this year.


Source: EIA

This chart shows the percentage change in US gas production from month to month. As you can see, US gas production actually grew in January and February despite the plummeting rig count.

You may have read articles in the popular media claiming that this uptick is a sign that US unconventional plays are so prolific that they continued to show production growth even amid a declining rig count. That’s absolute rubbish.

The horizontal rig count in the US didn’t top out until late October, and after a well is drilled, it takes time for it to be connected to a pipeline and actually begin producing gas. That means that there was a sizeable backlog of wells drilled during the rig count boom in late 2008 that weren’t hooked up to the pipeline network until early this year. Because of the magnitude of the 2008 drilling boom, that backlog was unusually large. And because the IP rate for unconventional wells is so high, this resulted in a massive rush of gas as the wells were fed into the pipes.

Nevertheless, the trend is clear. With the rig count continuing to plummet and the decline rate for unconventional wells ravaging production from existing wells, US gas production dropped at a 0.8 percent month-over-month pace in May–on top of a 0.3 percent decline in April. Keep in mind that if US production falls 0.8 percent monthly, the annualized cumulative decline would be roughly 10 percent, or more than 6 billion cubic feet of production per day.

These numbers are broadly consistent with Chesapeake’s expectations. The company stated on its call that US gas production would be down 2.5 to 3 billion cubic feet (bcf) per day by the end of this year and closer to 5 bcf per day by late next spring. If these figures are correct, US gas production should be around 60 bcf per day by the end of this year and fall to roughly 57 to 58 bcf to day by late next spring.

Here’s a basic, back-of-the-envelope calculation for what that means in terms of gas storage. Let’s assume that US storage ends the season full, roughly 500 bcf above average levels.

In a normal year, natural gas inventories should be 198 bcf lower on July 24 than they were on January 2. However, this year inventories are actually 193 bcf higher. That 391 bcf surplus works out to 13.5 bcf per week, or around 2 bcf per day, of excess gas so far this year.

We know that’s partly because of demand and partly because of production (supply). Let’s assume that industrial demand recovers half of its 2007/2008 decline by late this year and early next year. That would add about 1.4 bcf per day of demand.

Let’s further assume that Chesapeake’s estimates are correct and production declines by 3 to 5 bcf per day by early next year. Adding these figures up, the jump in average demand plus the decline in supply could impact storage figures on the order of 4.5 to 6.5 bcf per day downwards from early 2009. But US storage was building by an excess of 2 bcf per day this year; the actual effect on storage would be 2.5 to 4.5 bcf per day, relative to normal levels. That’s equal to between 20 and 30 bcf per week.

It’s  not hard to see how an inventory draw on the order of 25 bcf more than average could remove all of that 500 bcf excess inventory in about 20 weeks, or four and a half months. 

Of course, these estimates are rough and full of assumptions. However, I include these figures to offer an idea of how quickly supply might adjust given some modest assumptions for industrial activity, gas demand and gas production.

The bottom line from my standpoint is that as these storage effects begin to take hold, I see US gas prices climbing from current levels to north of $5 per million British thermal units by the end of this year and towards the $7 area by late spring of 2010. That’s double current prices, implying significant upside for our natural gas- levered recommendations.

Natural Selections

We already have several plays on natural gas in the TES Portfolios. The most direct play is the US Natural Gas Fund (NYSE: UNG), an exchange-traded fund (ETF) that tracks the price of near-month natural gas futures. This ETF rises or falls directly in line with gas prices.

Some investors are worried about the Commodity Futures Trading Commission’s (CFTC) efforts to target speculators. I addressed these concerns specifically in the July 14 Flash Alert, Energy Correction, Speculation and Investors. The July 29 installment of The Energy Letter, Don’t Buy Oil Speculation, offers my broader take on speculation and energy prices.

Some subscribers have told me that UNG doesn’t effectively track the price of natural gas over time. In this case a picture is worth a thousand words.


Source: Bloomberg

This chart shows the normalized performance of UNG and front-month gas futures over the past year. Although gas and UNG don’t align exactly, the correlation is close enough that it’s fair to describe the ETF is a good proxy for gas.

In addition to the gas ETF, I also recommend bonds and preferred shares issued by Chesapeake Energy. I outline the pertinent details of these securities and the logic behind this investment in High Income with Upside.

Suffice it to say that the preferred shares offer high current income coupled with participation in the performance of Chesapeake’s common stock. The company’s outstanding acreage position in all of the most important unconventional plays is a major competitive advantage.

Chesapeake highlighted the success of certain operational strategies in its most recent call. Specifically, the firm has been able to partner with other companies to develop some of its key plays, including the Marcellus and Haynesville Shale. This strategy means that Chesapeake doesn’t shoulder all of the exploration and development associated with these plays, cutting costs and boosting profit margins.

Management also noted that thanks to ongoing free cash flow generation over the coming year, the company should have investment grade credit metrics by the end of 2010. Improving credit quality is a big positive for both the bonds and the preferred shares. Buy Chesapeake Energy Preffered D (NYSE: CHK D) under USD75 and the Chesapeake 6.375 Bonds of 06/15/2015 (CUSIP: 165167BL0) under 95.

Gas-focused producer XTO Energy (NYSE: XTO) also has strong positions in key unconventional plays. The company has a reputation for successfully stripping costs out of its operations over time, boosting profitability as it gains experience producing new territories.

The firm reported earnings the morning of this issue’s release; I haven’t had time to fully examine all the details or listen to the conference call. But the early read is positive. XTO’s fields are performing better than expected; although management also expects US gas storage to reach full capacity, the firm will be in an ideal position to ramp up production when withdrawal season kicks off this fall. Buy XTO Energy under USD45.

EOG Resources (NYSE: EOG) has traditionally been a gas-focused play, though most of its production growth is slated to come from crude oil over the next few years. In particular, the company has enjoyed a good deal of success drilling for oil in the northern reaches of the Barnett Shale and in the Bakken Shale.

EOG will benefit in the near term from the run-up in crude oil prices this year. And as gas prices recover, EOG could divert more cash to its gas production. With little or no debt, EOG has among the most bulletproof balance sheets of any stock in my coverage universe. Buy EOG Resources under USD 100.

Finally, contract driller Nabor’s Industries (NYSE: NBR) is an outstanding play in the current environment. As I explain in the June 17 issue of TES, The Drilling Dozen, contract drillers lease their drilling rigs to producers in exchange for a fee known as a day rate.

Day rates rise with drilling activity and tend to fall when activity is weak; the fall in the US gas-directed rig count from 1650 to 675 has been a big negative for the stock.

I recommended Nabor’s Industries in the May 20 issue of TES, Supply Takes the Driver’s Seat; the US gas-directed rig count had finally begun to stabilize under 700 rigs, and the oil-directed rig count began to tick slightly higher. My basic thesis: the rig count decline was already priced into the stock.

Moreover, Nabor’s Industries continues to benefit from its ownwership higher-specification rigs that are designed for the shale plays; the company is positioned to benefit from growth in unconventional production as we exit the current down-cycle. And Nabor’s has a growing international business. Because a good deal of international drilling activity targets oil, business should pick up in coming months–crude at USD65 to USD75 a barrel supports an uptick in activity.

Based on comments in Nabor’s call, I expect their business to bottom this quarter. I project the gas-directed rig count to recover to around 1,000 rigs longer term; this is the level that would balance a normal demand market with supply. As earnings recover from the current depressed levels, the stock has the potential to double in price. Buy Nabor’s under USD19.

Hercules Offshore (NSDQ: HERO) is one name I’m close to adding to the portfolio as a play on gas prices. If I’m correct about gas prices, this higher-risk shallow-water drilling play could triple in price over the coming year. The likely renegotiation of the company’s debt covenants is another potential catalyst.

I explain this investment in The Drilling Dozen. For now, Hercules remains a Buy in How They Rate, but I will look to add it to the Gushers Portfolio in coming weeks via a Flash Alert.

Portfolio Update

In the July 1 issue of TES, I recommended buying the PowerShares Double Crude Oil Short (NYSE: DTO) as a hedge against the potential for a sharp correction in crude oil prices in July due to weaker-than-expected economic data and rumbles about new regulations from the CFTC. I issued a follow-up Flash Alert on July 6 entitled Playing the Pullback.

The good news: I was right to flag a pullback in crude as oil fell from over USD70 a barrel to under USD60 in July. The rise in DTO helped to offset pullbacks suffered by other TES recommendations.

The bad news: the crude oil market snapped back a lot further and faster than I expected, stopping us out of the hedge for a small loss of roughly 5 percent. I see crude oil prices locked in a wide range between the low USD60s and USD73 over the next couple of months before  year-end rally over USD80. I recommend standing aside from this hedge for now.

Of course, this isn’t really bad news; the rally in crude prices has reignited most of the Portfolio recommendations, swamping the minor loss in PowerShares.