Wednesday, October 26, 2011

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.

Wednesday, October 19, 2011

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.

Wednesday, October 12, 2011

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.

Wednesday, October 5, 2011

US Senate Hears Promises and Caveats of Shale Gas

Development of shale gas is possibly one of the few economic good news of the US.  Shale gas has made the country self-sufficient in gas supplies over the past five years and dramatically reduced gas prices at a time of decline of conventional gas production.  It now accounts for 30 percent of natural gas production in the US.  Many energy experts believe that shale gas would satisfy the US needs for the next 100 years.  Using techniques of shale gas production such as horizontal (lateral) drilling and hydraulic fracturing, where rock formations are broken apart and pumped with slick water and sand at a high pressure to break the sediment and release the gas, shale oil production in the US is increasing as well.  While shale gas production created an unprecedented economic boon and improved the US energy supply security, it also caused serious concerns about the industry’s effects to the environment and public health.  As these issues are increasingly in public limelight, a hearing at the Senate Committee on Energy and Environment on October 4, 2011, discussed a new study report by the Secretary of Energy’s Subcommittee on Shale Gas on the safety and environmental performance of shale gas production. 
This task force, led by Daniel Yergin, concluded that hydraulic fracturing and chemicals used in fluids to get gas out of shale rocks were safe, but it warned about outstanding issues related to water use and pollution, air emissions, and community impact.  The task force testimonies tried to shift emphasis from concerns over hydraulic fracturing to improving well construction and casing to prevent leakages, spill and leakage containment, efficient use of water, controlling and recycling of flow-back water, and capturing fugitive methane from gas production.  The task force’s recommendation that the industry should improve its impact measurements, community engagement, and disclosure and transparency of all non-proprietary information on public websites is a welcome development, particularly, given that most companies have maintained secrecy of chemical components used in shale gas production.  An important takeaway from the hearing was that there was a well-developed state regulation without the need of added federal regulation.
A more alarming account on environmental and public health effects from harmful chemicals used in hydraulic fracturing appeared in an April 2011 report by the House Committee on Energy and Commerce.  According to the report, 14 companies have used over 780 million gallons of hydraulic fracturing products, containing 750 various chemicals.  Chemicals included harmless substances such as salt and citric acid as well as toxic benzene and lead.  Energy companies used 29 chemicals, including benzene, toluene, ethylbenzene and xylene, which are potential human carcinogens as well as air pollutants, regulated under the Safe Drinking Water Act (SDWA) or Clean Air Act.  The report criticized gas producing companies for not knowing about some of the chemicals they used in hydraulic fracturing.  Various other reports and allegations of pollution are yet to lead to more probing and empirical study of hydraulic fracturing and chemicals used in fluids to prove or disprove their hazardous effects. 
Similar to the Heisenberg uncertainty principle, calculating damage costs from hydraulic fracturing and determining discounting of its future damages, long-run impacts as well as abatement costs remain largely uncertain, owing to a limited study of this relatively novel industry’s alleged harmful impact on the environment and public health.  The existing knowledge on hazards of hydraulic fracturing is often contradictory. 
At the moment, the field of shale gas and oil seems to suffer from a similar problem of incompleteness and uncertainty, as was the case surrounding the hazards of the tetraethyl lead in the 1920s.  The 1926 review and discounting of hazards of tetraethyl lead by the US Surgeon General resulted in a ruling that allowed continued sale of leaded gasoline, based on its finding that there were “no good grounds for prohibiting” it.  As the case with tetraethyl lead, it may require time, trial and error before the shale gas and oil industry is well understood and regulated.  The first step towards it would be public disclosure of measuring the volume and composition of what goes in and comes out of the ground and what happens to the flow-back water, as recommended by the Secretary of Energy’s Subcommittee on Shale Gas at the Senate hearing.