Poland’s Test for Shale Gas Might Test Its Resolve

Poland seems to be pioneering the shale gas development in Europe.  Unlike France, Poland embraced shale gas as an opportunity to reduce dependence on Russian gas and enhance its energy security.  According to Rice University’s Baker Institute, shale gas in Poland may account for about 55 percent of approximately 220 trillion cubic feet (tcf) of estimated recoverable shale gas resources in Europe.  The European Centre for Energy and Resource Security estimates that development of only a small part of the European shale gas would help reduce dependence on high-priced Russian gas and allow for greater diversification of gas sources.  With 30 companies exploring shale gas in Poland, there is hope that drilling will begin by the end of this year.  

But there is as much caution about shale gas development in Poland as there is optimism.  Shale gas in the US took 20 years before it reached the current boom.  A combination of a long history of drilling for hydrocarbons, deregulation of the gas market, competitiveness that brought down the costs of producing shale gas and equipment are behind the success of the shale gas in America.  It is yet to be seen how the US scenario could be replicated in Europe.  Costs of drilling appear to be the number one hurdle.  Given the difficulties to extract shale deposits in Europe due to complex geology, it may be more costly to bring them on line compared to the US.  Higher population density and access to water may complicate drilling in Poland, particularly given scarcer water resources in this eastern European country vis-à-vis the US.  The ongoing controversy in the US surrounding water use, well casing, and treatment of flowback water after shale gas production, it is likely that these issues will cause concern and opposition in Poland as well. 

The time, testing and lowered costs of production that led to US shale gas success may be needed for Poland’s boom.  Until then, the wild card is environmental groups that may prevail to stop drilling shale gas before it occurs, as it happened in France. 

Natural Gas “OPEC” or Not?

This week’s announcement of the world’s major natural gas exporters at a meeting in Doha, Qatar, that they will cooperate in producing and trading of this energy source as well as increasing prices and supplies seems to have sent ripples of alarm to importers.  Participants of the Gas Exporting Countries Forum (GECF), which includes Russia, Algeria, Qatar, Iran, Libya, Egypt, Equatorial Guinea,  Bolivia, Venezuela, Nigeria, Trinidad and Tobago, and Oman, agreed that the price of gas was too low.  Iran’s Oil Minister Rostam Qasemi proposed that GECF could establish the price by synchronizing strategies of the member countries.  According to Qatar’s Energy Minister Mohammed Al-Sada, a “fair price for gas would be at par with that of oil.”  While there were assurances that GECF would not limit output for its member, unlike the Organization of Petroleum Exporting Countries (OPEC), gas prices were likely to stay linked to OPEC’s crude oil.  Importers are concerned about possible influence of GECF on the global gas market.

While there are grounds to be concerned about a rise of a potential OPEC-style natural gas cartel, there are major challenges ahead for any gas cartel due to the complexity of the gas market and the difficulty among producers to effectively coordinate volumes of gas production and prices.  Gas is not nearly close to trading of crude oil in the global market and is constrained by pipeline deliveries or liquefied natural gas (LNG) with long-term contracts.  Although the GECF member-countries stress cooperation in developing each other’s markets, often they are also competitors. 

Besides, some GECF countries may risk losing their valued markets by trying to create a gas cartel.  For example, Russia already faces a tough challenge to maintain its presence in the European gas market due to its tainted reputation as a result of its recurring gas wars with Ukraine that left Europe without gas in wintertime on more than one occasion.  Russia provides nearly 40 percent of Europe’s gas demand and needs this market as much as the other is dependent on it.  To this day, Russia is still in a deadlock with Ukraine over gas prices.  As Europe actively seeks to diversify its gas sources from dominant Gazprom, Russia is walking a fine line between pushing for a gas cartel and keeping its lucrative market satisfied.  Lastly, a gas producer’s acceptable price might be too high for its customer(s).  A good example is Russia again.  Recently, Turkey rejected Russian gas because of its high price ($328 per thousand cubic meters in 2010) and signed an agreement with Azerbaijan in October 2011 on a package of gas contracts, which it considers more profitable.  There is no guarantee that unified gas prices of GECF would not backfire on their member-states.  The likelihood of a global gas cartel is not a near-term possibility. 

Russia’s Nord Stream an Ultimate Triumph? Think Again.

A launch of a new Nord Stream gas pipeline from Russia to Germany through the Baltic Sea on November 8, 2011, by the monopolistic giant Gazprom was a triumph to secure its European energy market, but kind of.  More immediately, Nord Stream dealt a blow to Ukraine, which is a transit country of Russian gas to Europe and has been in a repeated dispute with Russia since 2005 over gas pricing, debt and supply.  The Russo-Ukrainian gas war brought gas cutoffs in wintertime to downstream Western European markets.  With a capacity to carry 55 billion cubic meters of gas per year, the new $12.1 billion pipeline bypasses Ukraine altogether and is likely to boost Russia’s leverage on Ukraine in the recurring crisis between the two and help secure Gazprom’s position in the European markets.  While the former may be true, it is hard to bet on the latter. 

While Germany is a main beneficiary of the Nord Stream pipeline, the general sentiment in Western Europe is deep cynicism about Gazprom and fear of more dependence on it as European markets recover from the global economic downturn.  Receiving two thirds of its gas supplies from Russia, Europe’s main goal going forward is diversification of supply sources, which includes greater price and volume flexibility with imports of LNG, development of domestic shale gas in individual EU member countries (e.g. Poland, Germany), and building a direct pipeline access to energy riches of the Caspian countries.  It is unlikely that the launching of Nord Stream and a pending South Stream pipeline (from Russia through Black Sea to Bulgaria, Greece, Italy and Austria) would keep Europe locked to Gazprom.

Recognizing Europe’s policy of diversification of energy sources, a common attitude among Russian policymakers and energy observers is also centered on seeking other markets, particularly to its eastern direction.  While the October 2011 visit of Prime Minister Vladimir Putin to China ended again in an impasse on a gas deal due to price disagreements, Russians are confident that Beijing would eventually need their gas for its energy-thirsty economy and the sources from Turkmenistan and Qatar would be insufficient.  China continues to demand nearly half the price that Russia charges for its gas to Europe.  Some Russian energy observers argue that rushing in to the growing Chinese gas market and accepting its price will be highly disadvantageous to their country.  The Kremlin is aware that the Gazprom's supplies to European markets will be shrinking with time, but until then it is likley to bide its time to negotiate an acceptable price with China as well as to seek entry to the markets of South Korea and Japan. 

EPA to Release a Study on Hydraulic Fracturing in 2012

The US Environmental Protection Agency announced on November 3, 2011, that it finalized a plan to study the impact of hydraulic fracturing (fracking) – a method to extract natural gas from shale formations – on water by examining its mixture with chemicals, use of water in fracking, management of flowback liquids, as well as their treatment and disposal.  The EPA study, mandated by Congress, would be released by the end of 2012, with a final report due in 2014. 

While the shale gas industry maintains that the time-tested hydraulic fracturing method is not a problem, it admitted cases when natural gas migrated from drilling (not fracking) to the surface of drinking water wells.  However, it has been also hard to prove whether presence of methane in drinking water was due to drilling.  For example, Pennsylvania Secretary of Environmental Protection and chief regulator of natural gas exploration in Pennsylvania, Michael Krancer, said that Pennsylvania “had shallow gas formations for centuries,” which has caused methane to pass through to private water supplies.  According to a study done by researchers from the Massachusetts Institute of Technology (MIT), water contamination cases near drilling sites had to do with poor well construction, not the fracking itself.

At a minimum, there seems to be an agreement between the gas industry and environmentalists that natural gas is a necessary clean energy source.  From that starting point and given that shale gas production in the US has revolutionized the gas industry, increasing from next to nothing in 2000 to over 13 billion cubic feet a day now, it is hard to imagine how it could be curtailed under the existing pressure from some environmental groups.  There is a strong belief that that shale gas could fuel the US economy towards growth.  Advocates of shale gas industry are confident that the EPA study would validate that fracking poses no major threat to public health and the environment.  While it is hard to bet on that, the EPA study may demand full disclosure of chemicals and their contents used in fracking and the efficient use and disposal of flowback water – measures that this new industry has already begun taking.

Betting on Libya’s Timeline to Increase Oil Production

Muammar Qaddafi’s dramatic fall invariably caused many questions about Libya’s future, including return of its oil production to pre-uprising levels.  Various factors, such as destruction of oil facilities, continued civil unrest and internal divisions, proliferation of small arms across the country, lack of the rule of law and a stable government, as well as the global economic situation created various speculations about timing of Libya’s ability to restore oil production.  A general agreement among experts seems to be 18 months before this North African nation can resume its pre-uprising capacity of 1.6 million barrels a day.  Some say that even if Libyan oil output is fully restored, it would hardly be a game-changer, because it accounted for only around 2 percent of the global production.  But Libya still sits on the biggest oil reserves in Africa, which are sought after because of the high quality of oil.  European and Asian refineries covet the “sweet” crude from Libya for its low sulfur content.

An interesting observation on Libya’s potential to increase its oil capacity was made by Anas Alhajji in Oil and Gas Journal.  According to him, the experiences of Iran, Russia, Kuwait, and Nigeria showed that it took them generally 3 years to boost capacity after a major political instability or violence.  But unlike Kuwait, Russia or Iran, Libya experienced far more infrastructural damage and lacks any institutional and legal structure at this point.  And unlike Iraq, Libya is not occupied or invaded, faces no sectarian divisions (e.g. Sunni vs. Shi’a in Iraq), and may benefit from geographic vicinity to European markets and an open coastline to facilitate oil exports.  But it is still unclear whether the civil unrest in Libya would end with the death of Qaddafi and how soon a government with a constitution and a set of laws would emerge.  Weighing these setbacks and challenges, Anas Alhajji may be right that it will take up to 3 to 4 years before the country returns to the pre-crisis production levels, not 18 months.

New Source Performance Standard’s Unlikely Start in 2011

International Emissions Trading Association (IETA) held a symposium on October 18, 2011, in Washington DC, dedicated to climate change and business risk. Of due significance for the energy industry was a panel discussion on the proposed Environmental Protection Agency’s (EPA) New Source Performance Standard (NSPS), which would step up control on greenhouse gas (GHG) emissions from new, modified and existing power plants and petroleum refineries.  While EPA missed its September 30 deadline to propose NSPS for power plants and it is unclear whether the proposed standards for refineries, scheduled for December 2011, would be also missed, the effort seems to be a tough call at the moment. If NSPS for power plants and refineries are further delayed, they may not come into effect in 2012.  Complicating the matter is a lack of clarity on the design and execution of these regulations, which may make their realization impossible during the election year.  According to one of the panelists, Marisa Buchanan of Bloomberg, implementation of GHG standards would be delayed or thwarted if Obama is not re-elected in 2012. 

A discussion on how the NSPS regulations could potentially work was perhaps the most interesting part of the panel.  While panelists advocated market-based regulations, including emissions trading, it remained unclear what kind of form such regulations would take.  Further, it was not clear what the “standards of performance” would be like; that is, a standard which would reflect the degree of an emission limit.  Steve Cornelli from NRG Energy noted some important caveats on the potential impact of NSPS on power plants.  According to him, attempting to put an acceptable price on industries by adjusting performance standards was not likely to work.  He noted that it was hard “to predict credit prices accurately and current estimates may be overly optimistic.”

The petroleum industry sees inflated benefit estimates from the proposed NSPS regulations, noting that EPA was putting limited government resources on regulation when unemployment in the country was high and the economy was struggling.  The industry representatives expect limited environmental benefits from the new regulations. 

Learning lessons from the past, regulators should be reminded of the difficulty with implementing the lead phasedown from gasoline in the 1970s and 80s in the US.  Back then, EPA relied on market-based regulation to carry out the lead phasedown, i.e. providing market incentives to reduce emissions more cheaply than by imposing the same standard to all sources.  The more the agency relied on market-based flexibility to phase out lead, the more it was riddled with violations by refineries through false reporting.  It ended up being a costly regulation.  A premium is put on greater accountability under emissions trading compared to a command-and-control program. 

If lead phasedown is any lesson, compliance and enforcement under market-based regulations are more difficult and expensive than a command-and-control regulation.  At the same time, a command-and-control regulation would disproportionately impact the economic operation of less efficient power plants and refineries.  At the time of slow economic growth, encumbering the booming shale oil and gas industries or increasing the price of fossil fuel energy in the US with new regulations may meet vast disapproval among the public and energy producers.  So, NSPS is likely to face delay.

US Rise to the Top with Unconventional Energy Sources - Still Uncertain

In light of the stubbornly bleak economic situation in the US, optimism appears to exist in only two of its industrial sectors – oil and gas.  Advances in technology, which made production of shale gas in the US economically feasible and revolutionized the gas industry, gave enormous push to the development of shale oil in recent years.  Employing horizontal drilling and hydraulic fracturing, energy companies began adding thousands of barrels of oil per day to the US crude oil production.  According to the US Geological Survey, the US sits on over half of the world’s shale oil, with largest known deposits in the Green River area of Colorado, Utah, and Wyoming.  So far, the Bakken shale oil field in North Dakota has been a major success story, followed by Eagle Ford in South Texas.  

The Energy Information Administration (EIA) predicted that the US oil production would reach about 5.65 million barrels per day (bpd) in 2012, crediting the shale oil development for the anticipated increase.  At the same time, domestic oil production from Alaska and Gulf of Mexico was expected to fall.  Goldman Sachs made an even bolder prediction that the US would become a top oil producer by 2017, reaching 10.9 billion bpd and surpassing Russia and Saudi Arabia.  But according to EIA’s 2011 Annual Energy Outlook, US crude oil output was to increase to only around 6 million bpd by 2020.

While the prospect of US joining the leaders of oil production in near future is welcome news, a caution against over-optimism may be needed.  First, with the rise of shale oil output, costs to develop new fields are increasing as well.  Second, as with shale gas production, there may be uncertainties about projecting shale oil output in the U.S. due to its possible rapid decline rates.  Some fractured shale gas wells experienced rapid declines, from 50 up to 80 percent or more during the first year.  Given the newness of this industry, sufficient experience and time may be necessary to determine recoverability of reserves, decline rates and production lifespan of shale gas and oil wells.