This year no commodity has frustrated investors more than natural gas. Although natural gas prices recently hit a seven-year low on the spot market, the action in longer-dated futures and gas-related stocks suggests that a marked improvement is around the corner.

Looking ahead to 2010, there are some big potential catalysts for gas–namely, a recovery in demand and rapidly declining supplies. And there’s another wildcard on the horizon: The growing likelihood that the Senate version of any climate change legislation will include significant carrots for the natural gas industry.

Inside This Issue

The emergence of technologies to produce nonconventional gas plays has effected a paradigm shift in the US gas market, which should benefit the manufacturing segment. And the natural gas industry is pushing for favorable treatment in the Senate bill designed to limit carbon-dioxide emissions. See Paradigm Shift.

Given the potential for demand to rise even as supply begins to drop, why have natural gas prices sunk to seven-year lows in recent days? I tackle this perplexing question and discuss how to play it. See The Gas Conundrum.

Exploration and Production (E&P) remain the best way to play the natural gas market. I recap the investment thesis behind the five E&P recommendations in the Portfolios and their exposure to unconventional gas reserves. See Playing Exploration and Production.

Paradigm Shift

The outlook for long-term US natural gas production has changed markedly over the past five years, and many people, particularly natural gas consumers and policy-makers, still haven’t fully grasped the sea change.

Late last year, I spoke at an energy conference in the Midwest. One of the other speakers represented a consortium of manufacturers, many of which rely on natural gas to fuel their factories. This speaker noted that manufacturers  were largely opposed to expanding the use of natural gas as a fuel for electric-power plants.

Traditionally, manufacturers view the electric power industry as a key competitor in the natural gas market; that is, the added demand from electric utilities pushes gas prices higher, raising manufacturers’ costs and making them less competitive on a global scale. The speaker suggested that rising US energy costs were a major reason that many Midwest manufacturers had decided to relocate to countries where lower labor costs help to offset high energy costs.

A few minutes later, I spoke extensively about the emergence of unconventional natural gas plays–for example, the Barnett Shale in Texas and the Haynesville Shale play in Louisiana. I explained that the US could easily overtake Russia as the largest gas producer, if demand were sufficient to warrant that production.

I also explained why US natural gas prices would remain among the lowest in the world (though higher than the current quote) for the foreseeable future. Finally, I suggested that natural gas could become a more important source of electric power, continue to fill a vital role as an energy source for manufacturers, and even find wider use as a transportation fuel–without the US relying on imported gas.

Needless to say, those contrasting views became a rather hot topic at a subsequent roundtable discussion. My basic argument was that at one point in time, the speaker’s outlook had considerable validity. Paging through back issues of the Energy Information Administration’s (EIA) Annual Energy Outlook, I came upon the following chart from the 2005 edition.


Source: EIA

This graph breaks down net US gas imports by source. As you can see, the US primarily imported natural gas from Canada.

Back in 2005, the EIA projected that US gas imports from Canada would gradually decline over time, but remain significant through the entire forecast period. There are a few reasons for this expectation. For one, the agency assumed that Canadian gas production was nearing a peak. At the same time, Canadian domestic demand for natural gas was on the rise a number of reasons; for example, producing the nation’s vast oil sands reserves requires large amounts of natural gas. Higher domestic demand and falling, or at best flat, supply translates into less natural gas available for export to Canada’s gas-hungry southern neighbor.

To replace those Canadian gas exports, the EIA expected the US to ramp up imports of liquefied natural gas (LNG), a super-cooled version of natural gas that’s easy to transport.

When gas is cooled to around minus 260 degrees Fahrenheit (minus 162 degrees Celsius), it condenses into a liquid. Better still, as gas cools, it takes up less space; LNG takes up roughly 0.0610 the volume of gas in its natural gaseous state. To put that into context, a beach ball-sized volume of gas shrinks to the size of a standard ping-pong ball when it’s converted to LNG.

Pipelines traditionally have transmitted the vast majority of natural gas. By extension, reserves located far from existing pipeline infrastructure had little or no value. Oil from such fields can be loaded onto tankers and shipped worldwide, but stranded gas was routinely burned (flared) or re-injected into the ground for permanent storage.

LNG frees gas from geographic constraints imposed by the pipeline grid. In its liquid state, natural gas can be loaded onto tankers and transported anywhere in the world. Thanks to LNG technologies, gas reserves once deemed useless could now be exploited.

Many analysts expected imported LNG to meet rising US gas demand; companies built a large number of import facilities (regasification terminals) to handle the anticipated inflow. As a consequence of greater reliance on LNG, the US would have found itself competing for gas supply with fast-growing Asian countries and the heavily gas-dependent European Union (EU). That likely would have translated into higher prices, just as an increased reliance in imports led to higher oil prices in the 1970s.

In that context, the manufacturers’ argument had some validity; higher energy prices would drive up costs, making it tough for some struggling industries to survive.

But the above-noted projection concerning LNG imports fell short of the mark. In 2005, the EIA projected that US LNG imports would top 1.75 trillion cubic feet in 2008; in reality, the US imported a paltry 352 billion cubic feet (bcf)–less than half the 770 bcf the country imported in 2007.

The US imports some LNG, mainly because most other countries that consume the gas have insufficient storage capacity to handle large quantities of LNG. In the summer months, when heating demand is low, some LNG to finds its way to the US market because there’s simply nowhere else to store it. But domestic supply and demand don’t dictate that the US import natural gas; domestic production could be more than sufficient to make the country energy independent, at least when it comes to natural gas.

The emergence of nonconventional gas plays in the US scuttled the predicted boom in LNG imports. Subscribers unfamiliar with shale gas plays will find useful background information in the Aug. 20, 2008, issue of The Energy Strategist, The Natural Gas Boom, and the Sept. 3, 2008, issue, Unlocking Shale.

To emphasize the scope and importance of US shale plays, consider the uptrend in the US horizontal rig count.



Source: Bloomberg

As I’ve explained at length in previous issues, horizontal wells are essential to producing natural gas from unconventional plays. US independent producers have become adept at drilling increasingly long, complex horizontal wells to extract gas from shale formations. Accordingly, the number of rigs actively drilling horizontal wells serves as an excellent proxy for unconventional gas drilling activity.

Clearly, horizontal drilling activity has expanded rapidly. In 2003 there were fewer than 100 rigs drilling horizontal wells in the US. But as activity in unconventional plays picked up, the rig count jumped  to roughly 650 rigs in late 2008. The rig count rose especially quickly from late 2007 through the summer of last year, thanks to higher gas prices.

Even some of the big gas producers were surprised at how quickly US natural gas production ramped up in early 2008. Average daily production in the first six months of the year was up 9 percent from the first half of 2007. And only a lack of rigs prevented production from heading even higher; given the number of unconventional plays, natural gas companies have a surfeit of high-quality reserves to drill.

The horizontal rig count topped out in late-October to early-November of last year as producers reacted to falling commodity prices and the capital constraints imposed by the ongoing credit crunch. But because of a backlog of drilled wells that weren’t yet hooked up to the US pipeline network, US gas production continued to rise. reaching a new high in February of this year.

US natural gas production is now on the decline; the impact of plummeting production activity is finally manifesting itself. I expect this trend to continue through the end of the year, though US gas production data is often volatile from month to month and remains subject to substantial revisions.

Also don’t be alarmed by the upturn in the rig count over the past few months; most of the new horizontal rigs target crude oil, not natural gas. (Although not nearly as prevalent as natural gas, the US boasts some promising unconventional oil plays–for example, the Bakken Shale located in the States of North Dakota and Montana).

The main point is that the US could produce more gas via increased drilling activity in a handful of key shale plays. But doing so makes little sense with gas prices at current depressed levels and US storage nearly full. As I’ve outlined in the past few issues of TES, I believe producers require gas prices of at least USD6 per million British thermal units to stabilize production over the long term.

Nevertheless, if demand were sufficient to support higher production, the US has plenty of attractive, low cost shale gas reserves that could be tapped. In other words, when prices rally to a point where it’s economic to produce gas, US production will expand, constraining price growth. Given the resources available within its borders, the US will likely enjoy lower gas prices than Europe or Asia; the EU, in particular, is heavily reliant on imports of Russian gas.

This returns me to my original point: Because of the speed at which producers have tapped unconventional plays, many gas consumers have yet to realize that the outlook for rising LNG imports and falling domestic consumption that was the consensus just a few years ago no longer holds water.

These trends have much broader implications. Just as high natural gas prices put US manufacturers at a competitive disadvantage, relatively low prices might provide a tailwind.

Recent articles published in the Wall Street Journal and elsewhere have highlighted US manufacturers that have shifted production back to the US. Scores of factors go into a decision of that magnitude, including a weak US dollar, rising freight transport costs due to high oil prices and a desire to exert greater control over global supply chains. But one has to assume that rock-bottom gas prices resulting from enormous domestic supply could be a meaningful positive for US manufacturing.

Another logical, long-term outcome is that the US will develop new sources of demand, new uses for those abundant gas reserves. Examples might include the use of natural gas as a transportation fuel or simply greater reliance on clean-burning to fuel electric power plants.

As I explained in the July 1, 2009, issue of TES, The Politics of Carbon, the US carbon-dioxide regulation bill that passed the House of Representatives earlier this summer contained surprisingly few incentives for gas consumption. Because natural gas is plentiful, cheap and emits half the carbon dioxide of coal and significantly less than oil, it’s a logical fuel for any country seeking to cut carbon emissions. In fact, natural gas is central to the UK’s efforts to cut carbon emissions to levels mandated by the Kyoto Protocol.

Longtime readers know that I don’t enter the global warming debate in this newsletter. I’m not here to save the world or make judgments about whether global warming is real, caused by humans or extent to which it will affect the global climate.

However, that does not mean we can afford to ignore the issue; by its very nature, the energy industry is heavily impacted by legislative efforts to limit carbon-dioxide emissions. Such legislation has been and will continue to affect your investments, acting as an upside catalyst for some subsectors and a potential headwind for others. To ignore the impact of new greenhouse gas (GHG) regulations and the politics of climate change on our investments would be pure folly–not to mention a waste of potential opportunities.

Some in the US natural gas industry, including Chesapeake Energy (NYSE: CHK) CEO Aubrey McClendon, also expressed shock at how little attention natural gas received in the climate bill passed by the House. The rationale behind this omission is simple: Gas producers didn’t lobby hard enough, while coal firms and utilities spent millions to make sure they were taken care of in the climate bill. Like it or loathe it, that’s the reality of Washington, DC.

Learning from their mistakes earlier this summer, about two dozen natural gas producers have created a new lobbying group, America’s Natural Gas Alliance, which will spend $80 million this fall on a media blitz and lobbying Senators to include incentives for the gas industry.

Congress isn’t known for being particularly astute when it comes to energy-related issues; I suspect many lawmakers still subscribe to the fallacy about falling US gas production.

The natural gas industry likely will succeed in its efforts to influence Senate version of the bill. Although I doubt legislation will pass this year, any concrete signs that natural gas is winning friends in Washington will serve as another upside catalyst for the group. Already several prominent Democrats and Secretary of Energy Stephen Chu have recently discussed the environmental advantages of natural gas.  

This brings me to my outlook for the US natural gas market and prices. Current levels aren’t sustainable; with gas prices around USD3 per million British thermal units, even many of the lowest-cost producers aren’t profitable. And those that are profitable would have trouble generating enough cash flow to fund an aggressive drilling program; gas prices would need to exceed USD6 per million British thermal units if drilling activity is to stabilize gas production.

Near-term gas prices depend on two main factors: the state of the US economy and the supply picture. As to the first point, there are three main uses for natural gas in the US: residential/commercial heating, electric power production and industrial uses. Residential and electric demand for natural gas has held up fairly well over the past year, despite the weak economy; industrial demand, which includes the needs of the manufacturing industry, has collapsed.

Here’s a graph that tracks US industrial gas demand over the past few years.


Source: EIA

This graph requires little explanation: US industrial gas demand is clearly seasonal, but there’s no mistaking the pattern of falling highs and lows.

Industrial demand is sensitive to the state of the economy and, most particularly, the health of the manufacturing industry. The following graph illustrates current trends in US manufacturing.


Source: Bloomberg

This graph tracks the Institute of Supply Management (ISM) Manufacturing Index, an indicator that measures activity in the manufacturing sector. Readings above 50 indicate an expansion in activity; levels under 50 indicate contraction.

This graph includes data going back to the 1970s. As you can see, the most recent recession brought the most dramatic decline in manufacturing activity since the 1974 contraction. The ISM Manufacturing Index plunged to as low as 32.9 back in December, but soared to 52.9 in August after the largest two-month increase since the early 1980s. This was higher than the reading most economists had expected.

This uptick in ISM suggests that the US economy is expanding once again. And the most recent reading from my favorite quick measure of US economic health, the Conference Board’s Leading Economic Index (LEI), was up 0.2 percent year over year, the first gain since fall 2007. Given this indicator’s predictive accuracy in the past, I believe the recession has ended or is winding down. (For those unfamiliar with LEI and its 10 constituent indicators, check out the Jan. 30, 2009, issue of Personal Finance Weekly, Follow the Economy’s Lead). Bottom line: I expect industrial gas demand to improve with the economy.

Earlier in this issue, I outlined some of the reasons I expect US natural gas production to decline. I also offered a more detailed rundown of my rationale in the Aug. 5, 2009, issue of TES, Buying Coal and Natural Gas.

The Gas Conundrum

Given the potential for demand to rise even as supply begins to drop, why have natural gas prices sunk to seven-year lows in recent days? The reality is that natural gas price weakness is almost entirely concentrated in the near-month futures and the spot market.

The situation is very similar to the unusual pattern witnessed in the oil market earlier this year, a condition explained I explained in the most recent installment of The Energy Letter, The Real Price of Crude.

As with crude oil, traders can purchase natural gas for delivery in every month of the year, for years into the future. For example, natural gas for delivery in October of this year costs less than USD3 per million British thermal units, while gas futures for delivery in March of next year trade at around USD5 per million British thermal units. The graph below provides a closer look.


Source: Bloomberg

This graph depicts the natural gas futures curve. You can clearly see that the curve slopes upward; natural gas futures for near-term delivery trade at a huge discount to futures expiring in six or 12 months. This spread is known as contango and currently stands at a record high.

If you watch business television, you may have heard pundits say that natural gas prices have fallen sharply over the past six months. This is true only of the near-month futures contract. Consider that on March 1, 2009, near-month gas futures traded at roughly USD4.25 per million British thermal units; today, near-term contracts fetch USD2.85, a more than 30 percent drop in prices.

But if we look at natural gas prices 12 months down the line, futures prices have decreased less than USD0.50 per million British thermal units over the past six months.


Source: Bloomberg

The above graph depicts the natural gas futures curve on March 1 (green line) and Sept. 1 (white line) of this year. Although both curves indicate a state of severe contango, they’re almost identical beyond the next eight to 12 months.

This suggests that the root cause of weakness in gas prices is a near-term concern, not a longer-term trend. In this case, it appears the gas market is primarily concerned about the period between now and the onset of winter heating season in November.

As I noted in the Aug. 5 issue, most natural gas production firms expect US storage to hit its maximum capacity before November, which would force producers to curtail production. Knowledge of this impending storage crisis is widespread; I believe that much of the bad news is already priced into the gas market.

Although longer-term gas futures contracts have borne out this view, that hasn’t been the case with contracts expiring over the next few months. Clearly, traders remain jittery enough about the immediate storage picture to sell near-term contracts to seven-year lows.

Weakness in near-term futures prices has been bad news for Gushers recommendation, US Natural Gas Fund (NYSE: UNG); this position touched my recommended stop on Tuesday, resulting in a loss. Because US Natural Gas Fund owns near-month futures, it’s been directly exposed to this unprecedented contango in the gas futures market.

And as I predicted in the July 14, 2009, Flash Alert, Energy Correction, Speculation and Investors, the fund’s decision to cease creating new units for sale caused it to trade less like an exchange-traded fund (ETF) and more like a closed-end fund.

ETFs typically have an open-ended number of shares trading on the exchanges; when demand for an US Natural Gas Fund rises, the manager can create new shares in increments of 100,000, using the proceeds from the sale of new units to purchase natural gas futures, swaps and options. Shares can also be redeemed in the same manner in units of 100,000.

When the ETF issues new units to meet demand, the fund’s price hews closely to its net asset value (NAV)–the market value of the futures, swaps and options it holds. However, when the ETF can’t issue new shares, prospective investors must purchase the units from other investors. In other words, the ETF becomes a sort of closed-end fund; if investors’ demand for shares is high, the value of the fund can rise to a significant premium to NAV. When demand is weak, the fund can trade at a stark discount to NAV. .

Source: Bloomberg

This graph tracks the price of US Natural Gas Fund compared to its net asset value. As you can see, this fund rarely traded more than a percent or two away from its NAV–until a few weeks ago. That premium now approaches 20 percent.

Since many investors don’t trade futures, commodity ETFs are the easiest way to directly play commodity prices. The premium is caused by the fact that investors have been buying UNG as a proxy for gas, forcing the value of the fund to exceed the value of the contracts it holds.

But even with this significant, growing premium UNG has fallen sharply in recent weeks, triggering our stop order.

I continue to believe that gas prices will touch USD5 to USD6 in the first part of 2010; in that scenario, UNG could triple from current levels. At the same time, whenever we’re stopped out of a position in TES, it’s time to take a closer look at our rationale and reevaluate the position. The fact that we were stopped out indicates we were wrong on this position, at least for now.

In this case, I recommend standing aside from US Natural Gas Fund. I will reexamine the position in October or November as we approach the end of the injection season. By that time, the market should be looking beyond the near-term storage glut and toward the prospects for resurgent demand into 2010, falling production and potential new legislation that encourages gas use.

But it’s not all bad news. As I noted in the last issue of TES, shares of natural gas exploration and production (E&P) firms have not followed near-month natural gas futures. Although some of these stocks are trading below their summertime highs, that’s mainly a function of the recent market correction.

That these stocks are outperforming suggests that traders are looking beyond near-term storage issues; no one believes that gas prices will remain this low as we head into 2010.

Baker Hughes’ (NYSE: BHI) recent acquisition of BJ Services (NYSE: BJS) in a deal worth around $5.5 billion likewise underscores this point. BJ Services specializes in pressure pumping, a service that’s absolutely crucial to producing natural gas from unconventional plays. BJ derives two-thirds of its revenues from North America, the most cyclical and commodity-sensitive energy market in the world.

Baker is taking advantage of weak gas prices and a slow market for pressure pumping to snap up BJ Services. But Baker’s management wouldn’t do this deal if it didn’t believe in the longer-term prospects for North American unconventional gas drilling. Baker appears to recognize that the near-month futures contract prices don’t represent market reality.

Given that backdrop, we’ll stick with what has worked when playing gas this year–buying service and exploration firms with exposure to gas.

Readers should note that this is a very different story to crude oil. I outlined my long-term bullish case for oil and services names in “Mapping the Cycle.” I still expect oil prices to top USD80 this year and USD100 in 2010. The contango picture in crude oil was broadly similar to gas earlier this year, but the gap has closed significantly since that time.

Playing Exploration and Production

E&P is the first industry that springs to mind when investors think of investing in energy-related stocks. These are the companies that actually explore for and produce oil and natural gas.

Given my bullish long-term outlook for both natural gas and oil, I already recommend five North American E&P stock: XTO Energy (NYSE: XTO), EOG Resources (NYSE: EOG), Suncor (NYSE: SU), Chesapeake Energy Preferred D (NYSE: CHK D) and Linn Energy (NSDQ: LINE).

I’ll revisit the rationale behind these recommendations and outline their exposure to unconventional natural gas plays. Subscribers seeking a more detailed treatment of this subject, including maps of the most important shale plays, should consult Unlocking Shale, the September 3, 2008, issue.

EOG Resources

Wildcatters favorite EOG Resources historically has focused on natural gas production. But in recent quarters, the company’s growth plans have centered on crude oil and natural gas liquids (NGLs).

In 2000, oil and natural gas liquids accounted for 13 percent of EOG’s production. Now liquids represent about 21 percent of production, and that ratio should increase thanks to the company’s Bakken Shale and Barnett  plays. Over the past year alone, total production rose about 8 percent: Natural gas production is up 3.9 percent, oil production is up 18.7 percent and NGL production is up 53 percent. This shifting production mix has been a positive for EOG in recent quarters; crude oil prices have handily outperformed natural gas.

In terms of future development, EOG has drastically cut back on its natural gas drilling activity; natural gas production is down about 3.3 percent from its peak in the first quarter of 2009, and that trend is likely to continue. Meanwhile, the company has transferred much of its capital spending budget to crude oil plays. In fact, in its second-quarter conference call, management announced that the company boosted its 2009 liquids production growth target from 22 to 25 percent.

The Barnett Shale is primarily known as a natural gas play, the heart of which is located around and to the west of Fort Worth, TX. EOG owns significant acreage in the gas portion of the Barnett and plans to ramp up production over the long term. Although EOG is cutting spending on gas drilling and development in the near term, management emphasized that gas prices are unlikely remain at depressed levels over the long haul.

Wells in the northern reaches of the Barnett Shale, what management refers to as the combo play, typically produce a mixture of crude oil and gas rich in NGLs.  At the beginning of 2009, EOG had three rigs working in the region; that number has since increased to seven, and management expects the rigs to drill as many as 120 wells this year.

According to EOG, each well in the combo play costs about USD3 million and initially produces oil at a rate of 200 to 500 barrels per day. Each well also produces 1 to 2 million cubic feet of NGL-heavy gas per day. All told, EOG earns a 30 to 60 percent after-tax return from each well drilled, even at today’s gas and NGL prices. With those economics, it’s easy to see why EOG is boosting its spending budget in the region. And EOG has bought up most of the acreage available in the combo region.

EOG’s Bakken Shale play is located in North Dakota. Although many E&P firms have acreage in the Bakken, not all of these plays are created equal. Some smaller players trumpet their exposure to the region, but hold only marginal acreage that’s located outside the field’s so-called sweet spot–the area containing the top-producing wells.

This isn’t an issue for EOG. The company holds 100,000 acres in the most prolific part of the play and has drilled some of the best-performing wells of any E&P firm. A typical well costs USD4.1 million, but yields an astounding initial production rate of 1,100 to 1,800 barrels of oil per day. At current oil prices, management estimates that the company’s Bakken wells generate an after-tax return on investment that exceeds 100 percent.

These two prolific oil plays, coupled with EOG’s decision to cut back near-term spending on gas production, will push the firm’s production mix to a near 50/50 split between oil and gas. Nevertheless, the market doesn’t appear to be fully pricing in the advantages of this shift; investors likely still view EOG as a US-centric gas producer.

In EOG’s second-quarter conference call, CEO Mark Papa shared some interesting tidbits regarding the longer-term prospects for natural gas prices:

We’ve historically devoted a lot of work to developing domestic gas supply models, and we think our current model is the most granular and best we’ve ever built. It’s telling us that December 2009 domestic gas production will be 4.8 Bcf a day lower this year than at the end of 2008 and that this deficit will deepen further through 2010

This is broadly consistent my earlier comments regarding the decline in drilling activity and US production. What struck me about Papa’s comments is that EOG forecasts an even bigger decline in production than fellow E&P outfit, Chesapeake Energy. I discussed Chesapeake’s outlook in the August 5, 2009, issue.

Regardless of magnitude, if the US natural gas market rebalances as we expect, EOG is well-placed to take advantage. The company boasts significant acreage in the Louisiana Haynesville Shale and has drilled five wells in the play with initial production rates that match the best-performing wells of its competitors. Ninety percent of EOG’s Haynesville wells produce at an initial production rate that’s over 10 million cubic feet per day.

EOG’s solid exposure to Haynesville is important because the play offers some of the most attractive economics in the nation. According Ultra Petroleum’s (NYSE: UPL) shareholder presentation, long-term gas prices only need to be around USD3.50 per million British thermal units for Haynesville wells to generate a 10 percent internal rate of return. This same presentation estimates that gas wells located in the core of the Barnett require gas prices around USD4.20 to produce a 10 percent internal rate of return.

And EOG is also drilling a number of additional gas plays across the US and Canada. The list includes a significant acreage position in the Marcellus Shale of Appalachia, where EOG expects to generate its first commercial gas sales by the end of the year. In Canada, EOG has an enviable position in the Horn River Basin of British Columbia.

In short, EOG is one of the lowest-cost producers in the E&P industry, boasts a proven track record of growing production and has the flexibility to concentrate on crude oil production while gas prices remain depressed. Buy EOG Resources under USD100. 

XTO Energy

XTO Energy likewise offers exposure to both oil and natural gas production, with oil production accounting for around 15 percent of the total. That being said, XTO represents a purer play on natural gas than EOG Resources.

And XTO’s management has echoed EOG ‘s sentiment regarding gas production, acknowledging the near-term anomalies as injection season winds down and noting that production could decline to roughly 4 bcf per day by year-end.

The firm’s biggest play is the Freestone Trend, located in East Texas. In the second quarter, production in this region was up 16 percent over from a year ago, but the company has sharply scaled back drilling activity–whereas 27 rigs operated there a few quarters ago, that number is down to 17 rigs. After all, it makes little sense to ramp up gas production further with prices under USD3.

Not far from the Freestone Trend, XTO holds significant acreage in both the Texas and Louisiana sides of the Haynesville Shale play. XTO’s acreage in the region doesn’t appear to be as prolific as EOG or Chesapeake’s holdings, but its wells generally boast initial production rates that exceed 6 million cubic feet per day.

And XTO also is a major producer in the Barnett Shale, controlling properties in the play’s core as well as a few more marginal areas. Although wells in the Barnett play aren’t particularly economic at current gas prices, this low-cost producer is well-positioned to ramp up production when prices rebound. For now, XTO has shrunk its rig count in the region from 27 rigs in late 2006 to 10 rigs today.

XTO has a 160,000 acreage position in Oklahoma’s Woodford Shale, where it has three active rigs. Although the firm’s total gas production from the play remains around 70 million cubic feet per day, roughly a tenth of what it produces from the Barnett, that figure has more than tripled since the beginning of 2008.

The company likewise holds 380,000 acres in the Fayetteville Shale play in Arkansas, where it has managed to grow production at similar rates to the Woodford over the past year. XTO has maintained 6 active rigs in the region because the play is profitable even at relatively low gas prices.

Finally, XTO has a 280,000 acre position in the Marcellus Shale but has only just begun to drill. The company plans to drill about a dozen wells next year with the two rigs assigned to the region.

As for crude oil, XTO has around 450,000 acres in the Bakken Shale and produced nearly 17,000 barrels of oil per day in the second quarter.

Given the breadth of its holdings, XTO offers perhaps the best-diversified acreage position of any E&P I follow. The firm literally has exposure every imaginable unconventional play in the US, not to mention some attractive conventional fields.

Thanks to its vaunted efficiency, firm is one of the lowest-cost producers operating in the US, which provides a degree of protection against weak gas prices. Buy XTO Energy under USD45.

Suncor

Relative to EOG and XTO, Suncor is a far more direct play on crude oil. The company is most experienced player in Canada’s oil sands region and produced roughly 290,000 barrels of oil per day in the first half of 2009, up from 265,000 barrels per day in 2008.

Although oil sands are generally expensive to produce, Suncor steadily reduced its average extraction costs to USD32.50 a barrel in the first six months of the year and USD31.30 in the second quarter.

Amid plunging oil prices in late 2008 and early 2009, Suncor canceled or postponed a number of planned expansion projects that would have allowed the firm to double its production by end of 2012. But with the rally in crude prices, management is reexamining delayed projects that again make economic sense.

That being said, Suncor will have its hands full integrating Petro-Canada over the near term, after the USD18 billion deal closed last month. As I explained in the March 23, 2009, Flash Alert, A New Canadian Giant, I regard this acquisition as a positive for Suncor.  

PetroCanada offers exposure to the oil sands as well as conventional oil and natural gas production. Suncor’s management hinted in its second-quarter conference call that the merged company will remain oil-focused, suggesting the firm might sell off some natural gas assets and focus capital spending on oil development. I would also not be surprised if Suncor offloaded some of Petro-Canada’s foreign operations.

The deal makes the combined firm less of a pure play on the oil sands, which now represent less than two-thirds of the new company’s production mix (compared to almost 90 percent at the old Suncor). And the post-deal Suncor is the largest Canadian energy company, giving it additional financial flexibility to fund expensive oil sands expansion projects in future. Suncor rates a buy under USD37.

Chesapeake Energy Preferred D

I don’t recommend Chesapeake’s common stock directly, instead favoring the convertible preferred shares. These preferreds offer a yield of around 6.5 percent with some upside participation if the common stock continues to rally.

Chesapeake is a heavily gas-focused producer with exposure to most of the major US shale plays, including Haynesville, Barnett, Marcellus and Fayetteville. By most metrics, Chesapeake is a higher-cost producer than EOG Resources and XTO Energy and faces significant challenges when gas prices are depressed.

But the company has taken steps to alleviate that problem, cutting a series of partnership deals to develop some of its key plays without incurring the bulk of the cost.

I provide a detailed rundown of Chesapeake’s operations in the August 5, 2009, issue of TES, Buying Coal and Natural Gas. Buy Chesapeake Energy Preferred D under USD75.

Linn Energy

Linn  Energy is a limited liability company (LLC), a corporate structure that offers the same basic, favorable tax treatment as a Master Limited Partnership (MLP).

The key point to remember about Linn is that the firm is primarily focused on generating cash flows to pay distributions, a different business model than the growth-oriented E&P firms previously discussed. In fact, Linn seeks to remove much of the commodity price risk from its operations, so unitholders can depend on its distributions.

To that end, Linn has hedges covering all of its production through the end of 2011 and smaller percentages through 2014. Because the company set most of those hedges last year, it’s locked in sky-high prices for both its oil and gas production.

Linn recently purchased oil and natural gas properties in the Permian Basin of Texas and New Mexico for USD118 million, indicating that US credit markets have thawed enough that well-run companies like Linn can take on financing for accretive acquisitions. This deal, not to mention those likely to come, should help Linn to begin increasing its distributions again in coming quarters. Buy Linn under USD25.

In addition to the current E&P recommendaition, I’m eyeing a handful of other E&P names for potential inclusion in the TES portfolios. I plan to use any weakness in the broader market and energy prices this month as an opportunity to buy the sector.

As I have noted in previous installments, I expect some sort of a broader market correction in September and early October, traditionally one of the market’s weakest periods. The fact that the red-hot Chinese market has already corrected more than 20 percent suggests that the recent bout of selling in the US may be the beginning of that pullback.

I favor two characteristics when selecting natural gas E&P firms. First, I will be looking for companies with low operating costs that can remain profitable even with relatively low gas prices. Second, I am looking for companies with the potential to ramp up relatively low-cost production quickly as gas prices rise.


Source: Ultra Petroleum 2Q Investor Presentation

This table shows the gas prices required to generate a 10 percent internal rate of return (IRR) in some of the most widely watched US gas-producing fields. I will target producers with heavy exposure to the lower-cost plays listed in this table.

Three names that fit the bill are Petrohawk Energy (NYSE: HK), Southwestern Energy (NYSE: SWN) and Ultra Petroleum (NYSE: UPL).

Petrohawk is a leading player in the Haynesville shale, a reserve that’s widely considered among the lowest-cost plays in the US. The company recently did a 25 million share offering to raise capital to pursue an aggressive drilling plan in the Haynesville over the next few years. It’s likely that in coming years Petrohawk will have the highest rate of production growth of any major E&P I cover. Costs are coming down for Petrohawk as it gains experience in the Haynesville.

And as the company drills new wells it’s able to book reserves, which tends to act as a catalyst for the stock. For now, Petrohawk is a buy in How They Rate, but I’m looking to possibly add the stock to the model portfolio in coming weeks.

Southwestern Energy (NYSE: SWN) is a low-cost producer in the economically attractive Fayetteville Shale play of Arkansas. This is a proven play for Southwestern; the company has boosted its production from 36 bcf in 2000 to as high as 288 bcf this year, among the fastest production growth rates of any E&P outfit I cover.

Finally, Ultra Petroleum’s (NYSE: UPL) all-in costs (total operating costs dividend by production) are around USD2.75 per thousand cubic feet, the lowest of any E&P firm I cover. This is considerably under the industry average of about USD4.50 to USD5 per thousand cubic feet.

Ultra operates in two main areas: Appalachia and the Green River Basin of Wyoming. In Wyoming, Ultra focuses on the Pinedale and Jonah fields. The Pinedale, in particular, offers some of the lowest production costs of any field in the US. Another big advantage for Ultra’s production from these Rockies plays is that over the last few years gas prices in the region have been depressed because there has been insufficient pipeline capacity to move the gas to market in the East.

But Kinder Morgan Energy Partners’ (NYSE: KMP) Rockies Express pipeline is helping to change that; Rockies gas prices are now moving more in line with the rest of the country. Because Ultra has capacity on the Kinder line, the firm to earn higher prices for its production.

In Appalachia, Ultra is pursing an aggressive development plan targeting the Marcellus Shale. The firm has plans to drill 32 wells in the region this year and early drill results are positive. Ultra Petroleum also rates a buy in How They Rate.