The US shale oil and gas revolution took many industry observers by surprise. Consider the sudden shift in fortunes of US companies that built liquefaction facilities to import natural gas.

Earlier this decade most analysts projected that US imports of liquefied natural gas (LNG) would increase steadily, offsetting lower domestic production. In 2003 there were at least two dozen proposals to build new re-gasification terminals.

But US LNG imports never reached the 812 billion cubic feet per year that the Energy Information Administration (EIA) projected in its Annual Energy Outlook 2004 and have fallen off a cliff after peaking in 2007. According to the EIA, the US imported only 431 billion cubic feet of LNG in 2010, down from the 2007 peak of 771 billion cubic feet. In the first 11 months of 2011, the US imported only 323 billion cubic feet of LNG.

Source: Energy Information Administration

What happened? Frenzied drilling activity in the nation’s shale plays flooded the domestic market with natural gas, sending prices for the thermal fuel to record lows. Our current forecast calls for US natural gas prices to remain depressed for at least the next two to three years.

Although the upsurge in US natural gas production blindsided Cheniere Energy (AMEX: LNG) and other LNG importers, the shale oil and gas revolution didn’t occur overnight.

Geologists and oilmen long knew of the hydrocarbons trapped in shale and other “tight” reservoir rocks, though the drilling technology and techniques used to exploit these reserves wouldn’t become widely available until the mid-1990s.

In fact, the perceived inutility of these “stranded” oil and gas deposits earned them a brief cameo in William Gaddis’ novel JR (first published in 1975), in which the eponymous character amasses a paper empire of penny stocks and discarded assets that includes the rights to shale gas in Utah (possibly the Uinta Basin).

Even horizontal drilling and hydraulic fracturing–production techniques critical to unlocking shale oil and gas reserves–have been around for decades.

A horizontal well branches off laterally from an initial vertical drill hole, exposing more of the productive layer to the well. Horizontal drilling came became commercially viable in the 1980s after decades of experimentation.

Hydraulic fracturing, or stimulation, increases the permeability of the reservoir rock, allowing oil and natural gas to flow from the reserve rock into the well. This process involves pumping large quantities of water and a small portion of chemicals into the rock formation at high pressure, producing a network of cracks. The inclusion of a proppant–typically sand or ceramic material–ensures that these passages remain open.

Stanolind Oil & Gas Corp in the late 1940s experimented with hydraulic fracturing, and Halliburton Oil Well Cementing Co in 1949 performed the first two commercial treatments. At times in the mid-1950s, the number of wells enhanced by hydraulic fracturing exceeded 3,000 per month.

Of course, the technology has evolved substantially to flow oil and gas trapped in low-permeability shale formations. For example, whereas early fracturing jobs typically involved 750 gallons of fluid and 400 pounds of sand, today’s treatments can include more than 1 million gallons of liquid and 5 million pounds of proppant. (For more details on the history and evolution of hydraulic fracturing, consult Carl Montgomery and Michael Smith’s excellent Hydraulic Fracturing: History of an Enduring Technology from the December 2010 Journal of Petroleum Technology.)

In short, the US shale oil and gas revolution actually took place over a 30-year period.

Argentina’s Neuquen Basin: Promising Geology

Drilling techniques and technology have advanced significantly over the past decade. However, investors shouldn’t expect development and commercial exploitation of Argentina’s shale oil and gas resources to occur overnight.

The EIA raised eyebrows in April 2011 after releasing a study that estimated technically recoverable shale gas resources in 32 countries at 5,760 trillion cubic feet. According to this report, Argentina boasts the world’s third-largest unconventional gas resource; roughly half this 774 trillion cubic feet worth of natural gas is potentially located in the Neuquen Basin, an area in west-central Argentina that includes the provinces of La Pampa, Mendoza, Neuquen and Rio Negro.

Althrough production from the Neuquen Basin has dwindled since the early 2000s, the region has long been a hotbed of conventional oil and gas production–the presence of existing midstream infrastructure is a distinct advantage to early-stage development of the area’s promisng shale plays.

Much of the limited drilling activity that’s occurred in the Neuquen Basin has targeted the Vaca Muerta shale formation, which is between 200 and 1,700 feet thick and occurs at an average depth of about 8,000 feet. The region also contains a second hydrocarbon-bearing shale formation, Los Molles, which is situated at an average depth of 9,500 feet to 12,500 feet.

Through its 57 percent ownership stake in Argentine energy company YPF (Buenos Aires: YPF), Repsol YPF (Madrid: REP, OTC: REPYY) boasts exposure to roughly 3 million of the approximately 7.4 million acres in the Neuquen Basin that are prospective for the Vaca Muerta shale formation. With this leading acreage position and access to the region’s existing midstream infrastructure, Repsol YPF has driven much of the early appraisal and development work in the basin.

The company in December 2010 announced its first major discovery: an estimated 4.5 trillion cubic feet of natural gas in the Loma La Lata block. Repsol YPF followed up this major find, equivalent to roughly one-third of Argentina’s proved gas reserves, by discovering an estimated 150 million barrels of technically recoverable shale oil in the region.

Estimates of these unconventional reserves have increased steadily as YPF advances its appraisal and development program. Results from test wells prompted YPF in November 2011 to up its estimate of recoverable resources to 927 million barrels of oil equivalent (boe), including roughly 740 million barrels of oil. On Feb. 8, 2012, Repsol YPF disclosed that a third-party audit covering about 2 million acres of the firm’s leasehold estimated the gross prospective resources at 21.1 billion boe, 77 percent of which is oil and the remainder of which is condensate, natural gas and natural gas liquids. This audit increased the company’s current estimate of the volume of technically recoverable hydrocarbons in its Vaca Muerta acreage to 22.8 billion boe.

Management’s 2012 drilling program calls for Repsol YPF to sink 20 additional wells targeting the Vaca Muerta as part of an ongoing effort to appraise the resource base and develop a plan for commercial production.

In the Feb. 8 press release, the company indicated that development of the 271,815 acres that the firm has explored thus far could increase Argentina’s annual gas production by 50 percent. To achieve this goal, industry stakeholders would need to invest about USD28 billion in coming years and bring 60 additional onshore rigs to the nation.

The company claims that if exploratory operations prove successful and development continues apace, output from the Vaca Muerta could double Argentina’s current oil and gas production within 10 years. Management estimates that such an effort would require about USD25 billion in annual capital investment from all stakeholders.

Although the Neuquen Basin remains in the early stages of development, the promising play has attracted investments from Canadian junior producers Americas Petrogas (TSX-V: BOE) and Gran Tierra Energy (TSX: GTE, AMEX: GTE), as well as larger operators such as Apache Corp (NYSE: APA), Chevron Corp (NYSE: CVX), EOG Resources (NYSE: EOG), ExxonMobil Corp (NYSE: XOM), Royal Dutch Shell (LSE: RDSA, NYSE: RDS A) and Total (Paris: FP, NYSE: TOT). The table below summarizes their leaseholds and recent news flow as of Feb. 27, 2012.

Source: Company Reports

We expect smaller local producers to continue to partner with international oil companies to appraise their concessions in the Neuquen Basin. However, we must emphasize that the Vaca Muerta–though a promising resource–is in the very early stages of development and will take at least five years to eight years to yield meaningful production.

Argentina’s Neuquen Basin: Political and Pricing Challenges

The potential for an upsurge in domestic oil and gas production is a tantalizing prospect in Argentina, which has suffered escalating energy shortages since the country fell into recession in 1999 and the government defaulted on USD100 billion in debt.

This default and devaluation of Argentina’s currency, coupled with price controls on oil and natural gas, prompted many oil and gas producers to curtail investment in the region or exit the area entirely. Nevertheless, these price controls have contributed to the post-crisis rebound in Argentina’s economy; with the exception of 2008 and 2009, the nation’s gross domestic product has grown at an annual rate that exceeds 8 percent.

Source: Bloomberg

However, this resurgence came at a cost: The nation’s oil and gas industry has suffered from more than a decade of chronic underinvestment, while energy demand has grown substantially along with the economy.

Oil production, for example, has dwindled because of an exodus of international energy companies and an export tax on crude and related byproducts that increases along with global oil prices. This mechanism contains oil prices and encourages producers to sell into the domestic market.

Source: BP Statistical Review of World Energy 2011

The oil industry will face additional headwinds after the government suspended its Oil Plus program, an initiative launched in November 2008 that sought to increase domestic output by granting tax credits to qualified producers. In a statement, the Planning Ministry noted that while the program was in effect, domestic oil prices had increased to more than USD70 per barrel from USD35 per barrel in 2008.

As you can see, the program had at least stemmed the decline in Argentina’s proved oil reserves.

Source: BP Statistical Review of World Energy 2011

The move is expected to save the government USD461 billion annually and represents a calculated bet that the promise of the Vaca Muerta and other shale oil and gas formations will continue to attract foreign investment. Whether this move will stymie further exploration remains to be seen. At this point, the country remains an oil exporter, though the supply-demand balance will tighten in coming years.

The current regime caps oil export prices at USD42 per barrel or USD47 per barrel (depending on quality) when a barrel of West Texas Intermediate crude oil exceeds USD62. Meanwhile, the government also imposes a 35 percent tax on industry profits and a 12 percent royalty on production, though these rates vary depending on individual contracts.

That being said, the supply-demand balance in Argentina’s natural gas market has reached critical levels because of underinvestment in exploration and production and rising domestic consumption. Argentine demand for natural gas first eclipsed output in 2008. The gap has widened in subsequent years.

Source: BP Statistical Review of World Energy 2011

Some of the upsurge in domestic gas consumption stems from Argentina’s thriving economy. However, government price controls have also depressed natural gas prices, stimulating demand among manufacturers, industrial firms and individual consumers, a growing number of which have converted their vehicles to run on the thermal fuel.

In January 2002, the government decreed that domestic natural gas prices would be denominated in the devalued peso, effectively slashing the thermal fuel’s price by 67 percent. Other measures restricted producers’ ability to export their natural gas output. The current system divides the market in to four segments–industrial users, utilities, residential users and vehicles that run on compressed natural gas–with residential and commercial consumers (“priority demand”) paying a dramatically lower fixed rate. Upstream operators are also required to ensure that these priority markets were supplied with domestic production.

Rising consumption of natural gas and a decade of underinvestment in the energy industry have hastened the depletion of Argentina’s proved reserves, which declined by 53 percent between 2000 and 2010.

Source: BP Statistical Review of World Energy 2011

Inaugurated in 2008, the Gas Plus program seeks to provide a degree of relief, enabling eligible producers to negotiate non-regulated prices in individual supply agreements with industrial companies. Through this exception, the government aims to incentivize producers to grow output and ramp up exploration. Of course, the challenge is forging agreements with industrial users willing to pay more than the regulated rate for a reliable supply of gas.

These pricing headwinds are exacerbated by cost inflation for oil-field services and equipment, as well as the labor disruptions that inevitably occur in this heavily unionized country.

Meanwhile, rising imports of liquefied natural gas at prices that are several multiples of regulated domestic prices have saddled the government with a hefty bill for energy subsidies. Argentina’s President Christina Fernandez de Kirchner on Jan. 25 maligned the energy industry after the cost of the nation’s fuel imports more than doubled in 2011 to USD9.4 billion. Kirchner also called on producers to increase output.

At the same time, the government’s reluctance to liberalize its dysfunctional pricing scheme, coupled with new restrictions on imports and rules requiring oil companies to repatriate all foreign currency earned on exports, hasn’t exactly endeared the Kirchner administration to the energy industry.

These pricing and political headwinds will likewise slow the appraisal and development of Argentina’s promising shale oil and gas plays.