The Impact of Pricing Regulations on Argentina’s Energy Sector

23 Monday May 2016

Posted by V. Markov in Argentina, Fracking, Natural Gas, Oil, Vaca Muerta

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Argentina, Economics, energy, Energy Independence, Energy Security, fracking, gas, Kirchner, LNG, Macri, natural gas, oil, oil and gas, peronism, peronismo, Politics, security, shale, unconventional, unconventional resources, Vaca Muerta

Introduction

Since 2001, Argentina has tried to achieve the goals of promoting domestic production and supporting consumption of energy simultaneously. In a departure from the deregulation of the 1990s, Argentina’s government imposed a pricing regime to maintain the stability and affordability of consumer energy prices in order to stimulate economic growth and preempt the possibility of hyperinflation. Exports of energy were curtailed through a system of capital controls and export duties. As consumption rebounded following the 2001 economic crisis, producer prices remained below the prices for energy imports, thereby discouraging investment and volume growth. In response, the government instituted a system of producer price controls and subsidies to encourage investment, making up the difference between producer prices and controlled prices through federal budget outlays. Argentina’s regulatory system accomplished its goal of stimulating demand and limiting exports, however, in doing so it introduced distortions in the market that prevented the market from balancing with domestic production. The Argentina case study provides a lesson for countries seeking to accomplish contradictory goals through regulation, establishing a need for professional technocratic regulation, rather than regulation by decree, and flexibility in overcoming the interaction effects caused by intervention in the markets.

Energy Regulation between 1989 and 2015

Following a period of liberalization and deregulation in the 1990s, Argentina’s energy sector has been increasingly regulated since the 2001 economic crisis. The energy sector operates under the basic 1967 Ley de Hidrocarburos (Law No. 17.319),[1] which establishes hydrocarbon reserves as the patrimony of the nation and grants the Executive wide powers to grant concessions and regulate energy. The energy sector became heavily regulated until the Menem administration (1989-1999) pursued a vast liberalization of the economy. During this time, the Congress promulgated the Ley de Reforma del Estado (Law No. 23.696)[2] in 1989 with the aim of privatization and deregulating industry. The Menem reforms enabled private participation in oil and gas, deregulated prices, and culminated in the full privatization of YPF, a process that started with Law No. 24.145 of 1992.[3] During this time, Argentina’s economy and energy sector underwent rapid growth. Despite the oversupply in the international oil markets and the weakness of Brent prices, Argentine oil production increased 76% between 1990 and 2001, while gas production more than doubled as presented in Figure 1.

Figure 1

Following the 2000-2001 economic crisis, the Argentine government took a much more interventionist role in the energy sector and economy in general. Seeking to stimulate economic growth and prevent a return to hyperinflation, the short-lived Duhalde administration (2002-2003) issued Decrees 310/2002 and 809/2002, which established export restrictions on oil and oil products, including a 20% export duty.[4] Export duties were extended to gas in 2004. The administration further began controlling energy prices, particularly freezing rates in the electricity sector.[5] Law 25.561, passed in 2002, established emergency control measures over the exchange rate and prices.[6] Further clarifying its role through Resolution 1104/2004, the Ministry of Energy and Mines established formulaic pricing for energy.[7] Both the Nestor Kirchner (2003-2008) and Cristina Fernandez de Kirchner (CFK, 2008-2015) administrations maintained the price controls. Although export duties were introduced as temporary emergency measures, they were effectively made permanent in 2007 through Law 26.217.

Consumer Prices and the Impact on Demand

While the price controls did appear to stimulate economic growth and promote stability in the early 2000s, the lack of political will to raise consumer prices stimulated demand beyond what would have been commensurate with economic growth. As a result of the price control legislation coming into force after 2001, energy prices were denominated in pesos and remained nearly fixed, in spite of wide fluctuations in the USD prices of commodities. Natural gas prices, as presented in Figure 2, remained close to their 2003 level until 2013, despite peso inflation averaging 17% per year between 2000 and 2014.[8] Figure 3 shows vehicle fuel prices at the official exchange rate, representing an unreactive pricing system. Faced with punitive export terms and pressure from the government to maintain prices, producers had no choice but to direct domestic production to the market at low prices.

Figure 2

Figure 3

Demand for controlled products, gasoline and transportation fuels, natural gas, and electricity, grew faster after 2001 than over the period 1990 – 2001. Compound annual growth rates for fuel and product demand are presented in Figure 4. As presented in Figure 5, demand for oil products, gas, and electricity grew rapidly in relation to its 2002 level, in total reaching 150% of 2002 demand by 2013. Consumers expanded structural demand for energy, leading to a large growth in residential energy demand per capita, as show in Figure 6. The low fixed costs for products disrupted the distribution business, garnering complaints from the Argentine gas distributors trade group, citing the inability of distributors to maintain operations at current prices; GasNatural Fenosa, for example, depended on federal assistance of 515 million pesos for operation and maintenance in 2015.[9]

Figure 4

Growth in Demand by Product and Sector	CAGR 1990-2013	CAGR 1990-2001	CAGR 2002-2013
Transport – Oil Products	1.5%	0.8%	3.2%
Residential – Gas	3.9%	4.1%	4.2%
Residential – Electricity	5.7%	6.4%	5.9%
Commercial – Gas	-1.2%	-5.0%	2.9%
Commercial – Electricity	6.5%	9.3%	4.6%
Industry – Oil Products	5.4%	12.9%	-0.2%
Industry – Gas	2.3%	1.7%	2.8%
Industry – Electricity	3.7%	4.4%	3.6%

Figure 5

Figure 6

Regulatory Impact on Industry

The regulation of the wider economy and energy sector in particular created large distortions in supply and demand that led to a severe decline in the upstream sector, in terms of investment, production, and wells drilled. Figure 7 presents private investment in the energy sector over the 2000s. Since consumer prices were fixed and could not react to increasing demand, prices in the upstream sector remained depressed, depriving the market of signals to raise production and seek new supply. The aforementioned export duties were introduced as a measure to maintain domestic supply for the market, yet only served to extinguish exports. Over the five year period following the 2002 introduction of export restrictions on oil, crude oil exports declined by 79%, despite production only falling by 12% over the period, as shown in Figure 8. Similarly, gas exports collapsed five years after export duties were introduced in 2004, falling 87% while production only decreased 7% (Figure 9). Imports of gas rose 36% during the period. The inability of producers to sell at realistic market prices, in either the domestic or international markets, disincentivized investment and production. Restrictions on repatriations for foreign firms, currency controls, and denomination of energy prices in pesos made Argentina even more unattractive as an upstream market.

Figure 7

Figure 8

Figure 9

Regulation of Production

Seeking to address the deteriorating energy balance and decrease the outlays of foreign reserves to purchase energy in the international markets, the government sought to stimulate domestic production through a complex system of subsidies and producer pricing regulations. Wellhead prices for natural gas prices remained below $2.30/MMBtu until 2012 as a result of import competition and fixed consumer prices. Relative to international benchmarks, wellhead oil prices were also depressed as a result of an autarkic market and consumer price controls.

During the CFK administration, the Ministry of Energy and Mines declared Resolution 24/2008,[10] introducing the Gas Plus program, which enabled producers to receive prices greater than the controlled prices agreed to between the Ministry and producers. Similarly, the oil market received tax credits through the Oil Plus program, as part of Decree 2014/2008. Seeking to eliminate gas exports to keep the domestic market supplied, Resolution 127/2008 further raised the gas export tax to 100% of the highest price between Bolivian and LNG imports. Natural gas was subject to greater taxation as a result of its systemic importance to the Argentine economy, penetrating all sector including transport, and thus was deemed more important for retaining for the domestic market. This taxation stands in contrast to oil, which was taxed to a lesser degree and provided foreign currency export revenues for the government.

As the problem of domestic production became more acute by 2012, the government took more drastic steps through Decree 1277/2012, establishing the Commission for Planning and Strategic Coordination, and Law 26.741, nationalizing YPF-Repsol. The Commission gained pervasive powers to regulate the energy sector, including price-setting and approvals of private investment plans. The ultimate intention of the Commission was to ensure that firms were investing in the upstream sector in accordance with government plans for production. The expropriation of YPF similarly sought to bring greater control over the largest E&P player in the country in order to develop resources more quickly, particularly prolific unconventional reserves.

Production Subsidy Structure

The Commission, acting under a series of decrees, laws, and resolutions passed between 2012 and 2015, created a complex series of pricing regulation that sought to simultaneously subsidize both producers and consumers. In particular, Resolution 1/2013 set the wellhead price of natural gas to $7.50/MMBtu for production exceeding levels planned by the Commission. The federal budget covered the difference between the $7.50 price and the market price, which typically remained below $3/MMBtu, leading to large expenditures on energy. The remaining resolutions are summarized in Figure 10. The Commission established differential pricing for producers based on the final use of the gas, the date of operation, and the resource basin. Wells operating before 2013 may receive a price between USD $4/MMBtu and $7.5/MMBtu, depending on the production curves and whether or not the gas is reinjected. Projects streaming after 2013 sell into the market and receive the difference from the government to equal a wellhead price of $7.5/MMBtu.[11] Basins make a further difference, with the highest prices reserved for Neuquén Basin shale. Production for CNG networks receives a price of 0.89 ARS/m³. The complexity of the subsidy structure, not only introduces uncertainty over its maintenance by political forces and added transaction costs, but also ensures that only large producers are able to meet their investment targets and field the legal expertise to capture the subsidy rents.

Figure 10

Law	Effect
Decree 929/2013	New E&P projects can export up to 20% of production tax-free
Resolution 60/2013	Price range for incremental volumes for small gas producers set to between USD $4.00 and $7.50/MMBtu.
Law 27.007	Amends 1967 law extending length of concessions and lowers investment requirements
Resolution 139/2014	Defines rights of acquired companies to subsidies
Resolution 123/2015	Better defines participation in subsidy program
Resolution 185/2015	More firms eligible for production subsides

The oil sector, historically offering terms similar to international oil prices, attained a large degree of support following the 2014 oil price collapse. The CFK government retained pricing support at $77.5/bbl[12] at the wellhead in order to encourage investment and prevent an increase in unemployment in sensitive provinces. The Macri administration, coming into power at the end of 2015, lowered price support to USD $67.5/bbl for light Neuquén crude and $54.90/bbl for heavier San Jorge basin crude.

The combined total of energy subsidies, for both the upstream and consumer segments, began to take up an increasing portion of the federal budget. The budgetary cost in 2015 amounted to $18.4 billion USD, primarily requiring servicing through foreign reserves. After the accession of the Macri administration, Decree 272/2015 abolished the Commission and its duties were transferred to the Ministry of Energy and Mines. The Macri government began to unwind the subsidy structure, lowering guaranteed prices at the wellhead as previously mentioned and permitting free exports and imports and repatriation of 70% of export revenues. The pro-market agenda has already attracted investment, though years are likely to pass before the investment materializes into production growth.

Argentina: A Case Study in Regulation

Argentina’s energy regulations are the result of a series of incremental regulatory measures seeking to react to the problems caused by the initial energy price controls. The primary regulations of 2001 intended to stabilize prices and stimulate economic growth were successful, while export taxes did diminish exports, providing the domestic market with stranded supply intended for export markets. However, the temporary measures became permanent in practice and began to severely distort the market. Fear of political unrest ensured that only additional regulation, rather than amendments and rollbacks of previous measures, were possible. In accordance with basic economic principles, the price ceilings on energy resulted in a supply shortage as producers found it uneconomical to continue investments. Subsequent regulations sought to spur investment through a series of command-and-control measures and subsidies. However, each incremental regulation failed to bring about a balanced energy market.

Argentina provides a case for the need of an independent, institutionalized, and professional regulator that can balance the interests of consumers, producers, and the social goals of the government. In Argentina’s centralized political system, in which the Executive retains large powers to regulate and issue emergency decrees, requiring a 2/3 vote in the Congress to overturn, regulations were easy to issue and difficult to lift without checks and balances. Regulation by decree is inherently subject to political whims and only provides broad solutions to a particular problem. As such, the Argentine system continually introduced uncertainty into the energy market, preventing firms from modeling financial performance and investing, while constant changes precluded the institutionalization of a professional regulatory body. The complex multi-tiered pricing structure also added unnecessary opacity, complicating investment decisions and leaving room for patronage and moral hazard. An independent regulator, with formulaic, rather than set prices, would serve to introduce stability, particularly through cost-plus pricing. In particular, targeting bands of prices, rather than fixed prices, would allow limited price signals to give producers, consumers, and regulators insights into market developments. The top-down Argentinian regulatory model has not brought the energy market to balance, only eroded energy security, and its failures demonstrate the need for professional regulatory capacity for other countries seeking to manage the energy market.

Beyond the regulator itself, Argentina demonstrates the interaction effects of intervention in the markets. Additional regulation, rather than simply causing its intended effect, can often interact with preexisting market distortions to cause unintended consequences. Argentina’s government consistently sought to correct problems through additional regulation, which begot further issues and regulations. Often, the impact of a particular regulation is unpredictable, especially for energy, which impacts every sector of the economy. The interaction effects call for recognition of problems and the flexibility to address them, even at political cost. Argentina’s particular form of political populism may preclude the possibility of addressing such issues quickly and early, but the lesson may be applicable elsewhere. The economic impact of additional regulation makes a strong case for a technocratic regulatory body, with the power to reverse decisions as necessary; it is not expected that all regulations are correct or achieve their desired outcome each time. Maintaining simple, transparent, and flexible regulations can better achieve social goals than crystallized controls, even if it takes some power away from politicians.

Conclusion

Argentina’s energy regulations throughout the 2000s demonstrate that even well-intentioned regulation can be subverted by top-down political processes and interaction effects, creating the need for an independent regulator and the ability to reexamine regulations, rather than introduce new ones to correct prior measures. In response to the 2001 crisis, Argentina enacted price controls to protect consumers from rising prices and stimulate economic growth. After a return to growth, price controls became fixed and permanent as the government feared political unrest resulting from their abolition. Low and fixed consumer prices, coupled with export restrictions, translated into producer prices that were insufficient to enable investment in the country, particularly given the general volatility of economics and politics. The government turned to making the energy market more autarkic before resorting to command-and-control measures and subsidies to correct the low producer prices caused by the initial regulations. Ultimately, the Argentine government oversaw a vast increase in federal energy subsidies while the country became a net importer of hydrocarbons. The Argentine case shows the inefficacy of broad centralized regulation by decree, necessitating an independent regulator to balance the interests of the government and market participants. The interaction effects of various decrees and controls further show that flexibility in implementing regulations is necessary to correct for unintended consequences. Argentina’s energy regulations evolved into capricious decrees that only worsened problems in the energy market, rather than solving them, demonstrating the need for pragmatic flexibility and a professional regulatory apparatus that can be applied beyond Argentina.

[1] Government of Argentina. “Ley de Hidrocarburos.” 23 June 1967

[2] Government of Argentina. “Reforma del Estado” 17 August 1989

[3] Government of Argentina. “Federalización de Hidrocarburos” 24 September 1992

[4] Government of Argentina. “Exportaciones” 13 May 2002

[5] David Mares. Political Economy of Shale Gas in Argentina. (Cambridge, MA: Belfer Center 2013).

[6] Government of Argentina. “Emergencia Publica y Reforma del Regimen Cambiario” 6 January 2002

[7] Ministry of Energy and Mines. “Aclaraciones y recomendaciones” 10 April 2016

[8] World Development Indicators. (Washington, DC: World Bank Group, 2016).

[9] GasNatural Fenosa. Interim Report January – September 2015 Results. 4 November 2015.

[10] Government of Argentina. “Gas Natural” 3 June 2008

[11] YPF. Form 20-F 2015. December 31, 2015.

[12] “Argentina Cuts Wellhead Prices” ArgusMedia. 6 January 2016.

Iran’s Future in Regional and Global Gas Markets

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Posted by V. Markov in Iran, Natural Gas

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gas, iran, Iraq, kerry, LNG, natural gas, negotations, oil, oman, P5+1, pakistan, pipelines, qatar, rouhani, sanctions, saudi arabia, Turkey, turkmenistan

Iran’s Future in Regional and Global Gas Markets

The anticipated return of Iran to world energy markets has marked consequences for oil and gas. While Iranian oil exports easily influence the global spot market, the potential for gas exports, despite Iran’s prolific reserves, are much more muted. Iran’s prospects for becoming a major regional or LNG exporter capable of impacting global prices in the short term are low. Iranian gas production must outpace consumption, requiring extensive upstream investment and a decrease in consumption growth, while risk and uncertainty in the country discourage the foreign investment that could rapidly develop new production and LNG capacity.

Risk in Energy Sector Organization

The Iranian energy sector is restrictive even by Gulf standards, leading to underinvestment and a struggle to produce enough gas to meet domestic consumption. The constitutional prohibition on foreign investment and ownership of energy resources has created an environment of buyback contracts. Essentially service contracts, these limited offerings, though expanded in recent years, have discouraged foreign investment amid high risks for the return. Coupled with American and international sanctions, the sector suffers from chronic underinvestment and mismanagement.

Production

Iranian gas production centers on the South Pars field, which holds 40% of its reserves.[1] An ambitious expansion plan to develop the field in 24 phases, of which half are currently complete, is expected to bring online new production, though much of it only after 2020. Previously, European energy firms were developing the field, however, they mostly pulled out of Iran in 2010, leaving the work to domestic firms. Developing the field is critical for new export plans as, over the past few years, Iran has only maintained a marginal level of net exports, amounting to 2.7 bcm in 2014 out of its total production of 172.6 bcm.[2]

Consumption Growth

Eroding the volumes of gas available for export, Iranian energy subsidies have encouraged profligacy while gas reinjection into aging oil fields adds further strains on production. Subsidies doubly impact natural gas as they have incentivized consumption of both gas and electricity, most of which is generated in gas plants.[3] Subsidies amounted to 27% of GDP in 2007/2008,[4] representing a substantial incentive for consumption and a drain on public finances. As a result of these circumstances, Iran uses energy inefficiently.[5] Aside from subsidies, gas reinjection to improve recovery rates from aging oil fields consumes about 12% of production.[6]

Beginning in 2010, Iran began to eliminate subsidies in two phases ending in 2015, using the savings to implement a cash transfer program to offset the impact. Domestic prices are set to increase to 90% of international market values, although this requires a constant reevaluation of prices in terms of rials as the price increases themselves fuel inflation. The impact of the subsidy reform is as yet unclear, though it will likely reduce growth in residential, commercial, and industrial gas consumption.

Regional Export Potential

Even if Iran were to produce sufficient quantities for export, its regional options remain limited, even though several of its neighbors are growing gas consumers.

A 14 bcm capacity pipeline already exists to supply Turkey with 10 bcm annually,[7] though Turkey is reported to have ended the take or pay relationship[8] with Iran in 2014. The pipeline crosses Turkish Kurdistan and has been bombed in the past, making its future particularly uncertain as Turkey intensifies its campaign against ISIS and the PKK. Moreover, Turkey has alternatives to Iranian imports, the most expensive among its import partners, with Russian, Azeri, and Algerian gas.

In the Gulf itself, Iran and Iraq signed an agreement in 2013 to supply Baghdad with up to 25 mcm per day,[9] equating to annual exports of 9.13 bcm, within 6 years. The pipeline is currently under construction and nearing completion. In 2014, Iran and Oman signed a $60 billion deal to build a pipeline financed by Oman to deliver Iranian gas. However, disagreements over the project, particularly the route and price of gas,[10] have made realization more difficult.

The long awaited Iran-Pakistan pipeline, reportedly built on the Iranian side but undeveloped on the Pakistani side,[11] is receiving Chinese backing and financing amid the thaw in relations between Iran and the US. The pipeline was intended to extend to India, however, a multitude of geopolitical factors have hindered the extension.

Although Iran is entering into export agreements, it remains doubtful whether the requisite infrastructure and sustained export volumes would be available in the short run or whether the parties can strike and maintain pricing arrangements, even if sanctions were lifted.

EIA Map of regional pipelines (2012)

Global Gas Markets and LNG

Three conditions must be met for Iran to leverage its gas reserves and become a major global gas exporter capable of influencing prices: the global gas market must mature into a fungible global spot market, Iran must develop its nonexistent LNG export infrastructure, and gas production growth would have to outpace consumption enough to capture a significant percentage of the growing 333 bcm LNG market. None of these is a short-term possibility, and although LNG markets have begun to transition from long term oil-indexed contracts, they are still predominant for the time being.

Iran has sought LNG capacity for decades and has come close to construction several times. Iran lacks the financing and technology to build the liquefaction plants domestically and thus contracted Western firms to build them during the 2000s. Amid US pressure, Iranian contracts to build liquefaction facilities with a host of European energy firms were cancelled in 2008.[12] Similar contracts with Chinese firms were also cancelled in 2010 following the imposition of sanctions. With potential of easing sanctions in 2015 and beyond, European firms are once again trying to resume work on previous projects.[13] Construction times for such projects are measured in years, even in stable and secure markets. Accounting for the uncertainty over the nuclear agreement and the risk of deals with the Iranian government or state-owned companies ensures that such projects would only be further drawn out into the medium-term.

Iran and the Gas Markets

A confluence of factors of varying likelihood must come together for Iran to enter regional and global markets and begin to impact gas prices. Iran must slow down consumption while increasing production in order to provide volumes for export. Subsidy reform will help slow consumption, especially once the cash transfer program ends. Iran will need to foster a stable, less uncertain environment with more attractive terms for international energy firms in order to encourage upstream investment and increase production. Such trust will take time to establish before development can begin, especially given Iran’s rocky history of contract dealings. These same firms will also be necessary to provide the expertise and financing to build both pipeline and LNG export infrastructure. In the short-term, these factors are unlikely to come together, though some work may begin on a number of projects. Over the longer term, especially if sanctions are lifted and Iran faithfully reforms its contract structure for foreign firms, Iran may well become a major gas exporter, but this development is far from certain.

[1] EIA. “Iran: International Energy Data and Analysis.” 19 June, 2015

[2] Unless otherwise noted, all figures are derived from BP Statistical Review of World Energy June 2015. (London: BP, 2015).

[3] EIA. “Iran: International Energy Data and Analysis.” 19 June, 2015

[4] World Bank. “Iran: Overview.” 1 March, 2015

[5] Using World Bank GDP data and BP Consumption statistics, Iran produced $225 of GDP per BOE of primary energy consumed in 2014. This compares unfavorably with its neighbors – Saudi Arabia – $425, UAE – $531, Qatar – $573 – and with other countries – Russia – $372, Norway – $1460, USA – $1034.

[6] Derived from EIA. “Iran: International Energy Data and Analysis.” 19 June, 2015

[7] Olgu Okumuş, “Why is Turkey buying more gas than it needs from Iran?” Al-Monitor. 28 February, 2014.

[8] Natural Gas Europe. “Turkey to Abandon ‘Take-or-Pay’ Clause for Azeri Gas in 2015.” 21 October, 2014.

[9] Natural Gas Asia. “Iran Commences South Pars Link to Pipe Gas to Iraq.” 10 August, 2015.

[10] Alexander Cornwell, “Oman-Iran gas pipeline faces obstacles.” Gulf News. 13 April, 2015.

[11] Saeed Shah, “China to Build Pipeline From Iran to Pakistan.” The Wall Street Journal. 9 April, 2015.

[12] Natural Gas Europe. “Iran Eyes Resuming Huge LNG Project with Germany.” 7 May, 2015.

[13] Christopher Adams, et. al, “Iran: The oil and gas multibillion-dollar ‘candy store’.” 16 July, 2015.

Reality Check: Iran

01 Sunday Dec 2013

Posted by V. Markov in Iran, Natural Gas, Oil

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electricity, europe, G5+1, gas, iran, natural gas, nuclear, oil, Power, united states

Given the recently brokered deal between Iran and the G5+1, one may wonder about Iran’s ultimate intentions in terms of energy. Why is Iran trying to develop nuclear power at all?

A quick look at Iran’s energy sector reveals a country self-sufficient in energy:

157 billion barrels of oil – Second largest conventional reserves
3.680 million barrels daily production – 1.971 million barrels daily consumption – Surplus of 46.4% of production
1187.3 trillion cubic feet of natural gas – Largest natural gas reserves
160.5 bcm yearly production – 156.1 bcm yearly consumption – Surplus of 2.7% of production

These figures, however, obscure a lack of Iranian refining capacity, making it a net importer of gasoline.

Regardless, Iran remains self-sufficient in fossil fuels and brings 1.7 million barrels to world markets daily, albeit at a discount because of the sanctions. As it stands, Iran could comfortably expand both gas and oil production to meet any domestic demand, though it remains limited by sanctions when it comes to bringing in foreign expertise, constructing pipelines, moving oil shipments, or finding trade partners, among other concerns.

This begs the question, why would Iran seek nuclear power when it’s sitting atop so much natural gas and oil?

Several reasons spring to mind:

Iran could be trying to free up fuels destined for electricity production for export, thus giving it more hard currency reserves.
Iran could be trying to diversify its energy mix and wean itself off of fossil fuels.
Iran could be seeking the prestige associated with developing indigenous civil nuclear capacity.
Iran could be seeking the prestige of having the first nuclear reactor in the Middle East.
Iran could be trying to prove itself to the world and Middle East rivals.
The Iranian regime could be trying to legitimize itself by portraying a scientific and geopolitical victory to the people.
The regime could also be trying to legitimize itself by successfully defying the United States.
Iran could be trying to export nuclear technology.

Many of these reasons overlap, but the reasons for doing so remain mostly political.

One thing is for sure, economically, an Iranian nuclear reactor makes no sense. This is a list, by no means exhaustive, of the costs Iran faces, both political and economic, for developing nuclear power.

Iran faces the high initial capital costs, especially dire for a country recoiling from international sanctions
The costs of research and development
The costs associated with ensuring that nuclear power provides a substantial portion of electricity consumption
The costs of uranium imports, which will likely be compounded by additional sanctions
The costs associated with reconfiguring the power grid to account for base load nuclear power
The costs of ensuring that nuclear facilities remain intact in a region prone to earthquakes
The opportunity cost and opprobrium associated with defying the G5+1 for years
Developing small scale nuclear power would only be acceptable to the West if accompanied by rigorous inspections and dismantling of much enrichment capacity, hardly acceptable for Iranian prestige
The secondary costs and effects of having to contend with increasingly alarmed and militarized Middle East rivals
Iran could face punitive action by OPEC. OPEC could attempt to lower oil prices, as it hurts Iran relatively more than the other members of OPEC.

This is not to suggest that states act rationally in the economic sense at all times. However, Iran clearly has more to lose than gain in economic terms by developing civil nuclear capacity. The question still remains, what need is there for nuclear power when the country has such plentiful fossil fuel resources? Despite protestations to the contrary, Iranian nuclear power makes little sense except for as a means of acquiring a nuclear weapon.

US Energy Independence

25 Monday Nov 2013

Posted by V. Markov in Natural Gas, Oil, United States

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CNG, coal, Economics, energy, Energy Independence, LNG, natural gas, oil, security, shale, unconventional, unconventional resources, united states

Exactly 40 years ago, on November 25, 1973, Richard Nixon, in a speech to the nation in the wake of the OPEC oil embargo, first described the desire to maintain self-sufficiency in energy. These are Nixon’s exact words:

Let me conclude by restating our overall objective. It can be summed up in one word that best characterizes this Nation and its essential nature. That word is “independence.” From its beginning 200 years ago, throughout its history, America has made great sacrifices of blood and also of treasure to achieve and maintain its independence. In the last third of this century, our independence will depend on maintaining and achieving self-sufficiency in energy.

What I have called Project Independence 1980 is a series of plans and goals set to insure that by the end of this decade, Americans will not have to rely on any source of energy beyond our own.

1980 came and went and the United States was no closer to self-reliance in energy, though it did begin to use less oil as prices spiked to $102.62 (2012 dollars) per barrel in 1980. The oil glut of the 1980s and the consequent price tumble quieted the calls for energy independence. With lower prices and more diversified energy sources, energy became more of an afterthought. However, the post-2003 rise in oil prices once again resulted in calls for energy independence. As horizontal drilling and hydraulic fracturing became economical in 2009, causing a surge in US oil and gas production, energy independence may finally appear within reach for the first time since 1942, when defined as a minimization of crude oil imports.

From pundits to the president, energy independence has become a hot topic of discussion. In an Orwellian bend, the term itself can only be positive. Who could possibly be opposed to having a self-reliant US that need not depend on the rest of the world? However, the feasibility of a truly self-reliant US and the benefits that it would bring are two distinguishable issues that deserve a second look.

Meeting US Energy Demand Domestically

A quick look at the figures reveals a decades long shortfall in US domestic energy supply.

US Consumption and Production in 2012 in million tons of oil equivalent (mtoe)

Oil – Consumed – 819.9 mtoe – Produced – 394.9 – Shortfall – 51.8%
Gas – Consumed – 654 mtoe – Produced – 619.2 – Shortfall – 5.3%
Coal – Consumed – 437.8 mtoe – Produced – 519.9 – Surplus – 15.7%
Nuclear – Consumed – 183.2 mtoe – Produced – 183.2
Hydro – Consumed – 63.2 mtoe – Produced – 63.2
Renewables – Consumed – 50.7 mtoe – Produced – 50.7

While US oil production has grown every year since 2008 and gas production has increased every year since 2006, the US is still some way off from being able to produce enough energy domestically to meet its needs. Factoring in oil imports from Canada and Mexico, equivalent to 197.9 mtoe, the shortfall only decreases to 27.6%. The question then becomes, can the US increase its production of oil by 27.6% of consumption or decrease consumption to equal production?

In terms of oil, the United States has a reserves to production ratio of only 10 years, meaning that present oil reserves would be depleted in 10 years, given that production continues at the current rate. It should be noted that, despite increasing production, US proved reserves have only increased since 1992 from 31 billion barrels to 35 billion in 2012. This figure, however, depends on oil prices, technological advances, which impact the cost of extraction, and discovery of new reserves.

Increasing production, with its high capital costs and need for associated infrastructure, is a longer term prospect, making immediate energy independence unfeasible. It should be noted that petroleum is only used for 1% of US electricity generation, with its primary usage being transportation and industrial purposes. As a result, energy independence becomes an issue of finding alternatives for transportation rather than electricity; the US is self-sufficient when it comes to electricity production. It is very simple to conflate the issue of electricity production and transportation and many pundits seem to ignore the difference.

Reducing use of oil for transportation can come in several forms. Vehicles can become more efficient, Americans can use less energy by driving and flying fewer miles, or another fuel source can supplant or diversify the energy used for transportation.

Partly as a result of market forces and partly because of government regulations, American vehicles have become more efficient. Between 1980 and 2012, the average fuel efficiency increased by 46.5%, from 24.3 mpg to 35.6 mpg. However, as the number of vehicles in the US has increased over the years, oil consumption only grew. Recent trends, partly as a result of higher gasoline prices, have prompted Americans to drive and fly fewer miles, decreasing consumption. In fact, US oil consumption peaked in 2005 at 20.8 mbd, even before the 2008 financial crisis hit. As such, energy independence becomes a reality as oil production increases while consumption simultaneously decreases.

Similarly, over a medium-long time horizon, the US, with its present glut of natural gas, could potentially supplement the oil used for transportation. There are several options to this end. Vehicles can be retrofitted or manufactured to run on compressed natural gas (CNG) or liquefied natural gas (LNG). CNG and LNG achieve comparable performance to gasoline or diesel at a fraction of the cost. The infrastructure is, for the most part, not present. However, T. Boone Pickens has, through Clean Energy Fuels, tried to address this by connecting both coasts with LNG refueling stations. This map from Clean Energy Fuels demonstrates the coast to coast connections. However, it should be noted, as more vehicles begin using natural gas as fuel, its price will increase, given flat production. Nascent gas-to-liquids technology could also advance to the point of being an effective replacement for gasoline, though the technology is not economical at this point.

Natural gas, coupled with improvements in battery technology in electric vehicles and improvements to efficiency and increases in conversation, could supplement oil-derived fuels and decrease US oil consumption and thus reliance on foreign oil.

Given that this natural gas infrastructure and other technologies are not ready in the short term, it appears that energy independence can only be achieved by increasing oil production and decreasing demand. Even if the United States were able to produce all of its oil domestically, it would still not be energy independent, and the costs associated with any potential autarkey would be too great to bear.

Oil is a global fungible commodity. Oil produced domestically and in other countries is equally interchangeable on the open market, though price differences do exist because of shipping costs and the needs of refineries for certain types of oil. As such, US prices would still remain at the mercy of the markets. Does independence allow for the country to be susceptible to instability and supply shocks around the world? Closing the country to both oil imports and exports, thus providing an autarkic market, would insulate it from these shocks but also increase prices. Most of the recent increases in oil production have been from unconventional sources, making it more expensive to extract when compared to conventional oil. Note, as domestic oil prices increase in this scenario, more production would come online as more expensive to extract deposits become economically viable. In addition, these increased prices would only hurt the economy as they shave points off of already slow GDP growth.

Moreover, it would not make sense for the US to produce all of its own oil, even if it had the capacity. It can receive cheaper oil from abroad than it can produce by itself. After all, the point of energy is to sustain economic activity; more expensive energy would only hurt economic activity. As it stands, autarkic markets with a surfeit of a good lower prices, as evident in the US natural gas market that exports very little, while autarkic markets with a scarce good will increase its price.

Fungibility of oil makes it such that energy independence is a convenient rhetorical phrase, but would remain unworkable and lacking substance.

Feasibility Aside, What are the Benefits of Energy Independence?

As previously mentioned, energy independence does not appear feasible in the short-term without a major restructuring of the US economy. What would actually happen if the US removed itself from the global oil market?

In this scenario, where the US simultaneously increases supply and decreases demand, oil prices would decline, increasing economic activity around the world. The US current account deficit would shrink and the US would stop funding the national oil companies that fund various states. On the surface, this appears wholly beneficial, more money stays in the US, unfriendly regimes receive less funding, and economic activity increases. However, over the years, petrostates have come to rely on oil at over $100 a barrel to balance state budgets. As these states and their expensive low-tax, high-subsidy, high-entitlement ways of life begin to unravel, they become less stable. A basic principle of human psychology is that human beings hate to lose more than they like to gain, especially when it comes to losing things that they have been accustomed to receiving.

Where government largess once bought the loyalty of the governed, repression begins to become dominant as a means of controlling the people and allowing the regimes to remain in power. At this point, the US has lost the leverage and influence it once enjoyed as a buyer, and, often, protector of these countries. Thus, without US dollars flowing to these petrostates, they become more volatile, alienated, and more prone to domestic and international conflict. Although many of these states are undemocratic and violate many of the rights Americans hold dear, they provide convenient bulwarks against instability, particularly in the Persian Gulf.

Two potential scenarios emerge, one where China and other emerging economies fill the void that the US left behind and buy petroleum and natural gas from these countries, thus helping them balance their budgets. With disappointing recent growth figures, however, these countries are unlikely to equal the lost US demand. In addition, these countries certainly do not possess the power project capability and naval strength to maintain the sea lanes of communication to energy suppliers. As a result, they would feel vulnerable and begin building military capacity, which is inherently destabilizing. An arms race between the emerging countries and the US is possible. A second scenario could be the unraveling of OPEC as countries attempt to break their cartel rules and make up their budget shortfalls by increasing production, resulting in a race to the bottom. Once again, prices would plummet and these states would face unbalanced budgets and the resulting protests.

Neither of these scenarios is particularly welcome and the second and third order effects of an energy independent US, though two potential scenarios are given here, are difficult to predict due to the interrelated nature of world petroleum supply and demand and how different entities would react to it.

This is only an urging to avoid unbridled optimism; US energy independence may seem to be only beneficial, however, upon inspection of the secondary and tertiary effects, it may be just as negative as positive.

Note: All data herein derived from BP Statistical Review of World Energy 2013 or BP historical data, unless otherwise noted.

The Venezuelan Bounty and the Political Future

18 Thursday Apr 2013

Posted by V. Markov in Natural Gas, Oil, Venezuela

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Tags

Capriles, Chavez, Economics, energy, gas, Hugo, Maduro, natural gas, oil, PDVSA, Politics, PSUV, Venezuela

In light of Hugo Chavez’s passing on March 5th, it is useful to explore this ever salient topic and Venezuela’s plentiful hydrocarbon reserves.

As usual, any figures cited below come from the BP Statistical Review 2012, unless otherwise stated.

Oil

Venezuela is, of course, known for its oil reserves, which stood at a staggering 296.5 billion barrels at the end of 2011, compared to Saudi Arabia’s 264.5 billion barrels.

In 2009, the Oil and Gas Journal cited Venezuelan reserves as 99.4 billion barrels of conventional reserves. In 2011, this figure was revised to 211 billion barrels. BP figures put Venezuelan reserves at 296.5 billion barrels, of which 220 billion are extra heavy crude from the Orinoco Belt. Extra heavy oil is usually considered to be unconventional oil.

However, as mentioned in other blog posts, all oil is not created equal. Most Venezuelan oil is particularly dense and viscous, giving it the appellation of extra heavy crude. The American Petroleum Institute (API) ratings for this viscosity are referred to as API Gravity and measured in degrees.

From United States Geological Survey (USGS) reports, the following list describes the different viscosities of oil. Less viscous oil, meaning that it is less dense and flows more freely, is more desirable as it can produce more oil products

Conventional Oil – Gravity of 20 degrees or more. The lightest crudes stand at about 46 degrees and can be found in Algeria and Malaysia.
Heavy Oil – Gravity between 10 and 20 degrees
Extra Heavy Oil – Gravity between 4 and 10 degrees
Bitumen/Asphalt – Gravity less than 4. Natural bitumen is immobile and mostly found in Canada, Kazakhstan, and Russia.

Venezuelan oil production has declined from a high of 3.517 million bbl in 1997 (EIA) to 2.72 million bbl in 2011. It is important to remember that, although Venezuela has reserves rivaling Saudi Arabia’s, they are unconventional and require additional expertise, infrastructure, and investment to exploit. As a result, the correlation between reserves and production is not as straightforward as it might appear initially.

Oil, Politics, and PDVSA

Venezuela’s national oil company, PDVSA (Span. Petróleos de Venezuela, Sociedad Anónima), came into existence with the nationalization of the oil industry in 1975. Even at inception, PDVSA was intended as a revenue source to fund industrialization and government spending. However, the collapse of oil prices in the 1980s and 1990s and increasing liberalization of the oil industry allowed PDVSA to shed many of its political shackles and focus on producing increasingly larger quantities of oil. With the rise of Chavez to the presidency, the state began reasserting its power over the oil industry. In 2006, exploration and production were further nationalized, resulting in joint ventures with foreign oil companies, who were only allowed minority stakes in projects. PDVSA was mandated to take a minimum of 60% ownership in projects.

As a result, PDVSA operates as a monopoly on the basis of politics rather than economics. An example of this limitation is the failure of PDVSA to take advantage of increased commodity prices in the 2000s to increase both reinvestment into wells and oil production in general. PDVSA oil production actually declined while prices increased. The opposite phenomenon occurred in other major oil exporting countries. For example, Saudi Arabian oil production increased by 22.39% from production of 8.809 million bbl in 2002 to 10.782 million bbl in 2008, when prices reached a higher peak than previous high point in 1980. Similar production increases can be found in other major oil producers.

According to the CIA, oil exports account for 95% of Venezuelan export earnings and provide about 45% of federal budget revenues. Although PDVSA has been able to fund expensive social programs, it neglects to reinvest windfalls into maintaining existing wells. The EIA estimates that Venezuela must spend at least $3 billion each year to maintain production at its mature existing fields. Coupled with the political risk for foreign energy companies, Venezuela’s infrastructure does not receive the investment or expertise required to maintain oil production at constant levels.

Hugo Chavez was not one to hide his political leanings, proudly proclaiming himself a socialist and expanding social spending, subsidies, and programs in accordance. According to the Council on Hemispheric Affairs, Chavez implemented “missions” to reduce illiteracy, provide education, healthcare and housing. According to the report, these initiatives have met with some success, especially in promoting literacy, and reduced poverty by more than half, from 54% to 26%, while extreme poverty fell by 72%. Chavez also implemented fuel and food subsidies, which are both draining to the government’s budget. Government spending reached 45% of GDP in 2012. However, these successes have come at an extraordinary cost, subsidized by oil prices and devaluations, rather than organic poverty alleviation through development of industry. As a result, inflation remains an issue, as does the crime and corruption associated with largess and a weak justice system. Corruption is endemic, placing Venezuela at 165/176 according to Transparency International.

In accordance with the resource curse, Venezuela fell victim to capricious government spending, which proved itself unsustainable once oil prices retreated. Debt to GDP reached about 71.9% in 1995 and a restructuring period followed in the late 1990s with IMF loans of 350 million SDR (Special Drawing Rights, essentially used as an internal currency based on a basket of currencies for the IMF) in 1996. One should note that this austerity may have fueled discontent and allowed Chavez to gain power. By 1998, Debt to GDP had reached 40.1%. Debt to GDP stabilized afterward, before surging to 49.3% in 2004 and dropping down to 26.3% in 2009 on the heels of record oil prices. A combination of high oil prices, which are denominated in USD and not cheap Bolivars, and currency devaluation, which occurred in 2002, 2003, 2004, 2005, 2010, 2011, and 2013, helped minimize the debt the GDP ratio. During Chavez’s presidency from 1999 to 2013, the Bolivar has been devalued by 992 percent. Even with such a cheap currency, Venezuelan exports outside of the energy sector are virtually nonexistent and the country remains dependent on imports and plagued by shortages.

Natural Gas

Venezuela has substantial natural gas reserves as well as oil. These numbered 195 tcf or about 2.7% of the world’s proven reserves. However, the country only produces 31.2 bcm in 2011, (1.1 tcf) a figure which has remained relatively constant during the 2000s. Venezuela consumed 33.1 bcm in 2011, meaning that it also imports natural gas despite its reserves. As a result of its consumption and production patterns, Venezuela remains mostly insulated from the global gas markets and forgoes a potential source of revenue. Once again, the expertise and capital required to export natural gas would ensures that such a possibility remains years in the future.

Political Future

In April 2013, Nicolas Maduro was elected president of Venezuela following the death of Hugo Chavez. As the former foreign minister under Chavez and reportedly his “anointed successor,” he is expected to carry out or expand the policies started under Chavez. Maduro secured the state apparatus to aid him in electoral victory, including the “unconstitutional use of state resources,” such as the army, to assist in campaigning, and the extensive cult of personality cultivated by Chavez. In addition, many Venezuelans, if not most, benefit directly from the patronage mechanisms instituted by Chavez. Henrique Capriles, the centrist opposition candidate, who appears to be warm towards the US, was defeated in an election marred by electoral irregularities, that were enough to “render Mr Maduro’s victory margin moot.”

With such a turn of events, it can be reasonably expected that the political and economic situation will remain somewhat static in the future. PDVSA will remain a political asset intended to contribute to government revenues, which in turn provide subsidies and patronage for the ruling party, the United Socialist Party of Venezuela (PSUV) in this case. Coupled with oil spot prices likely to hover around $100 per bbl, PDVSA may be able to carry on as an ineffective, yet stable, monopoly. Enough Venezuelans remain unsatisfied with the status quo as to merit a tempering of previous policies, but the government still finds itself in a position to increase pressure on opposition forces. Regardless, government involvement in the economy, coupled with growing inflation and uncompetitive exports, high levels of crime and corruption, and a partially dissatisfied populace will force the ruling party to come to terms with the economic reality. Maduro will have to make the politically difficult choice of coming closer to the center and liberalizing the economy, or remain a Chavista and preside over worsening economic conditions and increasing inflation that will further degrade popularity. He already lacks the charisma and authority of his predecessor, leaving him with few options. A sudden liberalization will be very unpopular, especially as many ordinary citizens stand to lose some benefits, while increasing repression or even resorting to violence, puts Venezuela in a very precarious position. Such a situation would likely affect worldwide oil spot prices, if the markets sense an increasing likelihood of diminished Venezuelan production; oil production never occurs in a vacuum. The most preferable development would be a steady, but not sudden, political and economic liberalization that would avoid the ire of citizens losing benefits, but also allow industry, markets, and opposition parties to adjust to the new conditions. Maduro would have to be ready to pay the political costs and compete more fairly with the opposition.

Header Image: Image by Agência Brasil – Used under Creative Commons Attribution License. The image may be found here.

Algerian Energy Disruptions and European Implications

28 Monday Jan 2013

Posted by V. Markov in Algeria, Natural Gas, Oil

≈ 2 Comments

Tags

Algeria, energy, europe, France, gas, Germany, Italy, LNG, natural gas, oil, pipeline, security, Spain

All figures below are derived from BP’s Statistical Review of World Energy 2012 unless otherwise noted.

Algeria’s Hydrocarbon Reserves

Petroleum

Algerian oil reserves presently stand at 12.2 billion barrels of oil. For comparison, Nigerian proven reserves stand at 37.2 billion barrels of oil and Saudi Arabian reserves contain 265 billion barrels. Of this, Algeria produces 1.7 million barrels a day, compared to Saudi Arabia’s 11 million barrels a day. Comparing the ratio of reserves to production, Algeria is relatively high producer of oil.

According to OPEC Figures, Algeria exported 698,000 barrels daily in 2011. Of this total, 41.69% (291,000 barrels) went to Europe, 41.4% (289,000 barrels) went to North America, and 16% (112,000) went to Asia with the rest, .08%, going to Latin America.

However, one should note that oil is a fungible and liquid global commodity subject to wide speculative markets. As a result, the origin of a barrel of oil is often uncertain as it may have had multiple owners.

All crude oil is not identical and can range widely in quality. Algerian oil, referred to as the Saharan Blend, is sweet and light, the most desirable of oils. The oil has a low sulfur content, giving it a slightly sweet taste. It is also light, referring to its density and viscosity, meaning that it flows easily. These two qualities are superior because refining and processing the petroleum becomes easier and yields larger quantities of different petroleum products. In contrast, much of the Middle East produces heavy sour crude oil, which imparts additional costs to extraction and refining. The BBC has a quick explanation of the dynamics of this market, while the US Energy Information Administration has produced an excellent resource comparing the quality of different petroleum deposits around the world.

If there were any losses in Algerian oil production, a greater quantity of inferior oil would likely have to be brought to the market to make up for the superior quality of Algerian oil. Prices for sweet crude would likely rise, which itself would have an impact on producers and consumers alike. According to the US Energy Information Administration, OPEC crude oil spare production capacity stood at the relatively low level of 2.5 million barrels per day in Q1 2013, dipping from post-2008 heights of 4.35 million barrels per day in Q4 2009. This stands in stark contrast to spare capacity figures of .99 million barrels a day in Q3 2008. As such, OPEC could withstand a supply shock in Algerian production, despite the superior quality of Algerian oil. One may examine the effects of the Libyan Civil War, in which Libyan oil production, also light and sweet, collapsed by 71% in 2011, to predict the effects of disruption of Algerian production. Although OPEC production increased to offset the loss of Libyan production, Brent crude prices increased sharply, reaching a high of $126.46USD/bbl in April 2011. One should note that infrastructure in place to refine such oil is static in the short term and cannot use heavier oils as a substitute, making prices highly sensitive to supply changes.

Effects on Europe

In 2011, Europe imported 12,086,000 barrels of crude oil daily. 6,039,000 or 49.96% came from the Former Soviet Union (FSU), 2,543,000 or 21.04% came from the Middle East, 1,001,000 or 8.28% came from North Africa, and 1,159,000 or 9.05% came from West Africa. Coupled with the ability of OPEC to absorb sudden supply shocks and the possibility of buying oil on the spot market rather than a long term contract, Europe is not wholly reliant on Algerian oil imports. Of course, however, European energy consumers would suffer from increased crude and refined product prices due to any such supply shocks.

Natural Gas

Algeria is one of the major suppliers of gas to Europe, particularly Western Europe. Algeria’s proximity, existing pipeline and LNG infrastructure, large reserves, and low domestic consumption allow it to be a major exporter.

Overview of Algerian Gas in 2011:

Proven Gas Reserves: 159.1 tcf
Gas Production:75 tcf (78 bcm)
Gas Domestic Consumption:98 tcf (28 bcm)
Gas Available for Export:13 tcf (60.2 bcm)
Total Gas Exports: 82 tcf (51.5 bcm)
Gas Pipeline Exports:21 tcf (34.4 bcm)
Gas LNG Exports:6 tcf (17.1 bcm)

Algeria has the tenth largest natural gas reserves, amounting to about 2.2% of the world’s proven total. However, Algerian gas production has been in decline since hitting a peak of of 3.11 tcf (88.2 bcm) in 2005, averaging 2.9 tcf (82.24 bcm) annually between 2001 and 2011. Domestic consumption is up 36% between 2001 and 2011 to 0.98 tcf, putting the gas exports under pressure as domestic consumption takes an ever larger portion of production.

Algeria’s energy sector is centralized and the government determines energy prices through the Sonatrach monopoly. As a result, domestic gas prices have not kept up with inflation and remain below marginal production costs. These price controls serve as subsidies and encourage the same consumption that erodes exports. Oil and gas exports constitute an overwhelming majority of Algerian exports, and provide hard currency earnings for the government. Disruptions to the system of government revenues could impact stability and further disrupt supplies to consumers in Europe.

2011 European Recipients of Algerian Gas

France: LNG – 0.2 tcf (5.7 bcm)
Italy: LNG – 0.05 tcf (1.6 bcm), Pipeline – 0.75 tcf (21.3 bcm)
Spain:LNG –14 tcf (4.0 bcm), Pipeline – 0.33 (9.4 bcm)
Turkey: LNG – 0.14 tcf (4.0 bcm)

For comparison, Italy received 15.4 bcm (0.54 tcf) from Russia by pipeline while France received 8.6 bcm (0.3 tcf).

2011 Dependence on Algerian Gas:

France: 14% – Consumed 1.42 tcf, of which 0.2 tcf originated in Algeria
Italy: 11% – Consumed 2.52 tcf, of which 0.8 tcf originated in Algeria
Spain: 74% – Consumed 1.13 tcf, of which 0.47 tcf originated in Algeria

For comparison, the United Kingdom is well insulated from Algerian supply shocks; it produces about half of its gas consumption domestically and imports the rest mainly from Qatar and Norway. Germany similarly produces some gas domestically and relies on Russia, Norway, and the Netherlands for imports. Germany further provides for its own energy security through a large emergency gas storage agency, (Germ. Erdolbevorratungsverband, or EBV) which supplies 90 days’ worth of natural gas. Many other countries in Europe have storage facilities, serving as reservoirs for peak shaving for electricity generation and strategic reserves.

Quantity of Gas Stored as of January 1st, 2012:

France: 0.55 tcf (15.49 bcm) – 38.7% of yearly consumption
Germany: 0.72 tcf (20.43 bcm) – 28% of yearly consumption
Italy: 0.55 tcf (15.6 bcm) – 22% of yearly consumption
Spain: 0.083 tcf (2.37 bcm) – 7% of yearly consumption

Source: Eurogas Statistical Report 2012

In Amenas Gas Facility Attack and Potential Disruptions

On January 21, 2013, militants crossed over the Libyan border and captured an Algerian gas facility in In Amenas, taking a multitude of hostages. According to Norway’s Statoil, In Amenas is the fourth largest gas development in Algeria, a joint venture between BP, Statoil, and Algeria’s national oil company (NOC) Sonatrach.

Disruptions in Algerian natural gas production pose a significant economic and political threat to the Western European countries. These countries can weather localized and temporary disruptions of gas, but replacing even a few percentage points of their Algerian imports for a longer term would require a reevaluation of the domestic energy policies and long term infrastructure.

The problem becomes more difficult as several countries rely on the same Algerian gas imports, compounding the effects of gas disruptions. This is an especially salient problem for Spain, which remains underprepared in terms of its strategic reserves, depends highly on Algerian gas, and remains isolated from the Russian gas pipeline network. Spain is one of the few European countries that do not import gas from Russia and would have to rely on indirect Russian imports or look to the LNG markets to make up a shortfall.

Given the recent low levels of confidence in European governments, particularly those of Spain and Italy, gas disruptions could carry significant political risk as it could undermine confidence in the government and its ability to provide for its citizens.

A foreign intervention to help secure Algerian hydrocarbon exports would not be feasible. Given Algeria’s bitter colonial history, any such interventions would be unacceptable to the regime and the people. Moreover, launching such a long-term intervention where European citizens would be targets for rebels and terrorists would also be politically untenable for European populations. With few options, an Algerian gas disruption could easily lead to domestic instability and the fall of governments. The secondary effects of such instability would likely rattle bond markets creating a feedback loop of instability.

It is important to note that Germany’s restructuring away from nuclear power and toward cleaner energy sources could put further strains on Algerian supply and LNG if it chooses to diversify future gas imports away from Gazprom. Given the cleanliness of natural gas, a German shift to additional gas could be a large burden on a complex system.

Conclusion

Disruptions to gas production could have dire consequences for Western Europe, particularly for Spain. Spain is underprepared in terms of supply, highly dependent on Algerian gas, and lacks the preexisting infrastructure to diversify gas supplies. The fate of Spain is tied to that of Algeria in the short term. By contrast, Italy is less dependent on Algerian gas, remains integrated into the Russian supply network, and has substantial enough strategic reserves to weather a short-term disruption. France is even more prepared for Algerian disruptions and has substantial shale gas reserves, despite its refusal to exploit them.

The secondary effects of disruptions to Algerian gas production give rebels an ability to project power beyond what their actual physical capability allows. By attacking Algerian gas, they realize the potential to attack Western Europe and exert an undue influence on Western targets. Given the recent political instability in Southern Europe, the rebels’ power is magnified. The situation in Mali, in which half of the country is effectively outside of governmental control, and the power vacuum in Libya left in the wake of Qaddafi’s death provide additional avenues to launch attacks. Libyan weapons caches remain outside of provisional government control and Qaddafi’s former Tuareg mercenaries remain in the country and without a steady income stream. These factors come together to foster an environment of heightened risk as rebels gain further ability to launch strikes on energy infrastructure in Algeria.

Algeria’s ruling party, the National Liberation Front, has been in power since 1962 and remains oppressive. As typical for states reliant on hydrocarbon revenues, the government uses these revenues for a mixture of largesse and repression designed to stem unrest. The regime’s tactics against terrorists and rebels are notoriously brutal and the government is not reluctant to use force and is already predisposed to repressive measures. As such, if Algeria were to be deprived from oil and gas revenues, its system of governance could potentially unravel, further compounding supply disruptions.

Potential Scenario

As a result of the Algerian government’s dependence on energy revenues and repression to remain in power, a threat to the present system would likely lead to instability and additional repression. Primarily, the government could increase domestic repression in attempt to prevent attacks to keep hydrocarbon exports secure. This could lead to instability within the country or an uneasy order maintained by repression. In light of recent Arab Spring events, the government would suffer a decrease in its legitimacy as a result. This brings forth the possibility of a positive feedback loop in which discontent begets further repression which causes more discontent. The risk of regime collapse would increase greatly.

If the Algerian regime were to collapse altogether as a result of attacks or the response to attacks, the secondary effects on North Africa would have a great impact. In such a scenario, large swathes of the Sahara in Algeria, Mali, and Libya would remain outside of the control of any government. The effects of the power vacuum have the potential to empower rebel and terrorist groups across the region and legitimize the effectiveness of asymmetric attacks and movements in general. Furthermore, this instability would threaten the uranium production of Niger, which would greatly increase the chance of French intervention in the region due to its reliance on this uranium, and even the hydrocarbon production of Nigeria; these events would have worldwide impacts. Moreover, the contagion effects of such developments could easily move eastward to destabilize Egypt and Sudan.

If the rebel threat is left unchecked and these groups become bolder and more organized, the secondary and tertiary effects of wide disruptions in Algerian energy production would be far reaching.

Natural Gas Primer

20 Thursday Sep 2012

Posted by V. Markov in Natural Gas, Primer

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Tags

climate, energy, environment, fracking, gas, hydraulic fracturing, iran, middle-east, natural gas, qatar, russia, shale, transportation, turkmenistan, unconventional, united states

Basics

What is natural gas?

Natural gas is nothing more than gas mixture, consisting primarily of methane (70-90%) and other gases, such as propane and butane. As a fossil fuel, it results from the decay of organic matter from high temperatures and pressures within the Earth. It is often found in conjunction with oil deposits as the processes for forming each are similar. However, natural gas tends to form at higher pressures and temperatures and, therefore, is found in deeper deposits. Most natural gas is formed in this manner, though microorganisms can also generate it by chemically breaking down organic matter.

Conventional natural gas is the gas that is cheapest to extract given current technology. Historically, this has been gas found alongside oil deposits. Presently, unconventional natural gas can take several forms, though some are quickly becoming cheaper to extract. These are several forms:

Deep Gas Deposits – Usually more than 15,000 feet underground. Most conventional gas is found only a few thousand feet underground.
Tight Sand Gas – Gas trapped in impermeable rock
Shale Gas – Gas trapped in porous shale rock
Coal Bed Methane – Gas found alongside coal beds
Methane Hydrates – Gas trapped in crystalline ice structures. This is the least researched form of unconventional natural gas, though there may be more methane hydrates than all of the world’s coal, oil, and gas resources combined. Some research suggests that exploiting these hydrates could affect the world’s carbon cycle.

Distribution of Conventional Natural Gas

Present proven reserves are primarily found in Russia and the Middle East. The following list displays the countries with the largest conventional proven reserves.

Note: Present proven reserves is not an absolute figure showing all the gas reserves known to exist. Proven reserves refers to reserves that have been discovered AND are economical to extract. As a result, even with zero new discoveries and zero gas extraction, proven reserves can fluctuate based on the price of natural gas and the advancement of extraction technology.

The world’s total proven gas reserves equate to 7360.9 Trillion cubic feet (tcf) or 208.4 trillion cubic meters (tcm).

Russian Federation – 1575 tcf or 44.6 tcm – 21.4% of world’s total conventional gas.
Iran – 1168.6 tcf – 15.9% of world total
Qatar – 884.5 tcf – 12% of world total
Turkmenistan – 858.8 tcf – 11.7% of world total
Saudi Arabia – 287.8 tcf – 8.2% of world total
United States – 299.8 tcf – 4.1% of world total
United Arab Emirates – 215.1 tcf – 2.9% of world total
Venezuela – 195.2 tcf – 2.7% of world total
Nigeria -180.5 tcf – 2.5% of world total
Algeria -159.1 tcf – 2.2% of world total

All other countries contain less than 2% of the world’s total conventional proven gas reserves.

It is interesting to note that the US actually produces more natural gas than the Russian federation, mostly because of its unconventional gas resources.

Source: British Petroleum Statistical Review of World Energy – June 2012

Natural Gas Production Figures

Total natural gas production figures for 2011, including both conventional and unconventional gas, are as follows:

United States – 22 tcf – 20% of world total production
Russian Federation – 21.42 tcf – 18.5% of world total
Canada – 5.64 tcf – 4.9% of world total
Iran – 5.35 tcf – 4.6% of world total
Qatar – 5.18 tcf – 4.5% of world total
China – 3.62 tcf – 3.1% of world total
Norway – 3.58 tcf – 3.1% of world total
Saudi Arabia – 3.5 tcf – 3% of world total

The US experienced 7.7% production increases over 2010. Peru experienced 56.9% growth, Turkmenistan 40.6%, Iraq 42%, while Libyan production sank by 75.6% due to the civil war, and UK production decreased by 20.8%.

Source: BP Statistical Review of World Energy

Natural Gas Consumption

In 2010, natural gas consumption in the US broke down as follows:

24.13 tcf consumed in total

Residential – 4.94 tcf – 20.47%
Commercial – 3.20 tcf – 13.26%
Industrial – 6.60 tcf – 26.35%
Electricity Generators – 7.38 tcf – 30.58%
Other – 2.01 tcf – 8.32%

Projections for 2035:

26.63 tcf consumed in total

Residential – 4.64 tcf – 17.42% of total (-3.05 percentage points from 2010)
Commercial – 3.60 tcf – 13.51% of total (+.25 percentage points from 2010)
Industrial – 7.00 tcf – 26.28% of total (-.07 percentage points from 2010)
Electricity Generators – 8.96 tcf – 33.64% of total (+3.06 percentage points from 2010)
Other – 2.43 tcf – 9.12% of total (+.80 percentage points from 2010)

Source: Department of Energy/Energy Information Administration Data

Natural gas has relatively even distribution of uses, with electricity generation taking the highest plurality of gas consumption, a figure which is expected to rise.

The rise in this figure has several likely causes. Natural gas is relatively clean in its emissions as previously mentioned. Newly exploited American unconventional gas deposits are plentiful and likely to provide a cheap, at least for the present, domestic source of energy. Natural gas power plants are also relatively efficient in their production of electricity when compared to other energy sources. Combined cycle plants are able to convert generated heat to electricity, achieving efficiencies of up to 60%. This compares to the thermal efficiency of gasoline engines of 25% and that of coal-fired plants at about 35%.

Moreover, natural gas power plants are not baseload plants and can increase and decrease their electricity outputs to meet demand as necessary. (A baseload plant is one that provides a constant level of electricity production. Such plants are coal, nuclear, and hydroelectric plants.)

Much of the residential use goes towards heating. Industrial usage, although there are chemical applications of natural gas, also goes towards electricity generation onsite.

Emissions

Natural gas is often reported as the cleanest of the fossil fuels. For each British Thermal Unit (btu) produced from natural gas, it emits fewer greenhouses gases and other pollutants. As an environmental solution, natural gas remains the best option amongst the fossil fuels. The following chart portrays the discrepancies between gas, oil, and coal.

Fossil Fuel Emission Levels – Pounds per Billion Btu of Energy Input
Pollutant	Natural Gas	Oil	Coal
Carbon Dioxide	117,000	164,000	208,000
Carbon Monoxide	40	33	208
Nitrogen Oxides	92	448	457
Sulfur Dioxide	1	1,122	2,591
Particulates	7	84	2,744
Mercury	0.000	0.007	0.016
Source: EIA – Natural Gas Issues and Trends 1998

Natural Gas Distribution

Most natural gas is distributed through pipelines. This is the most economical way to distribute gas in most cases. Natural gas can also be shipped by liquefying it and shipping it by sea. Pipelines are more economical up to a distance of 3,500 km while shipping it by sea is more economical at further distances. Most island nations find the expenses associated with building pipelines prohibitive and must rely on shipments of liquefied natural gas (LNG), regardless of distance.

As one may imagine, constructing pipelines is a long-term commitment with large capital costs and political and geopolitical implications and concerns. As a result, natural gas is not as fungible a commodity as oil simply because pipelines deliver most gas, and these pipelines are governed by long term contracts.

Pricing

Natural gas prices are generally set by 20 year contracts on pipelines. These 20 year contracts are necessary to ensure that building a pipeline is economical and the capital costs involved in construction are recuperated. As a result, natural gas prices can vary widely from one region to another. For example, European gas prices are much higher than US gas prices, though other factors are at play in determining European prices.

LNG is presently indexed to the price of oil and thus fluctuates in accordance to oil prices. However, a spot market is emerging for natural gas that will likely replace oil price indexation and the present system of long term contracts. Gas will likely become as fungible and liquid a commodity as oil as new LNG facilities and technologies are developed.

Liquefied Natural Gas

History:

Liquefied natural gas (LNG) has only recently come to prominence in the public eye. However, LNG has existed since 1912 as a method of storage and the first transnational shipment of LNG occurred in 1959. The US presently mostly uses LNG technology for gas storage at peak-shaving facilities. These facilities store gas in liquefied form and make it available for peak energy consumption times, typically about 6 PM in the US.

The US, previously a world leader in LNG technology, has historically been able to meet its needs for gas domestically, disincentivizing research into and development of LNG. In more recent times, interest in LNG increased as it appeared the US would be unable to meet its gas needs domestically in the face of growing demand. However, as hydraulic fracturing and horizontal drilling made the extraction of shale gas economical in 2009, the US has experienced a boom in natural gas production, revitalizing the industry for the export of LNG while minimizing the need for imported LNG. Presently, Qatar leads the world in LNG technology and exports.

What exactly is LNG?

Liquefied natural gas is nothing more than gaseous natural gas cooled to -260 F and stored in this form. This makes it convenient for transport as LNG takes up 1/600th of the space of the same quantity of gaseous natural gas. LNG is regassified at special terminal and then shipped by pipeline to customers. LNG terminals are capital intensive and the technology is still somewhat expensive, though new developments and construction of LNG terminals are driving down costs.

Great Economist article on LNG and the markets

Gas-to-Liquids

Gas-to-liquids is a process that essentially turns natural gas into a synthetic crude oil products. The process essentially removes the impurities from natural gas, leaving only methane. The methane is then combined with oxygen at high temperatures to create a mixture of hydrogen and carbon monoxide. This mixture is then processed and transformed into long-chained waxy hydrocarbons. These long-chained hydrocarbon are able to interact with hydrogen and cut into smaller molecules. This process can create many of the products created from crude oil, such as kerosene, for mixture with jet fuel, diesel, and base oils for industrial lubricants.

Qatar is currently considered the leader in this technology and several international energy companies are examining the technology and working to commercialize and make it a viable addition to world energy solutions.

Unconventional Gas

As usually discussed in US media, unconventional gas usually refers to shale gas exploited through hydraulic fracturing (fracking). The recent boom in US natural gas production, allowing it to overtake Russia as the world’s largest producer despite having only 19% of Russia’s conventional gas reserves. In 2009, extracting this unconventional shale gas became economical because of the refinement of two technologies: hydraulic fracturing and horizontal drilling.

Hydraulic fracturing involving drilling a well bore, perforating the sides of the well, and then pumping fluids at high pressure into the perforations to induce fractures in the shale rock. The fluid mixture is 99% water, .5% sand, and .5% proppants. These proppants prop up the rock in these fractures to allow the gas to flow through these seams once the water has been removed. These fluids are removed from the site once they are used. An operation may use about 3.8 million gallons of water. This technology has been around for several decades, but has not been able to fulfill its potential until the advent of horizontal drilling ,

Horizontal drilling, as the name implies, is the drilling done horizontally. Previously hydraulic fracturing was limited to vertical drilling which could only yield limited gas and required many wells to cover a large territory. With horizontal drilling, much larger areas can be exploited, making extraction economical.

The Energy Information Administration estimates there are 862 tcf of technically recoverable shale gas in the US. For comparison, the EIA estimates that China has 1,275 tcf, Argentina has 774 tcf, and Mexico has 681 tcf of shale gas. Total world technically recoverable shale gas resources are estimated at 6,622 tcf, though this figure will undoubtedly increase as new gas plays are found. The full figures are found in the link below.

Source: Energy Information Administration Data

As far as a total of shale, coalbed, and tight sand gas the US National Petroleum Council estimates world reserves at 33,000 tcf by the US National Petroleum Council. Methane hydrates have the potential to add much more to this figure.

As far as pollution and the controversy surrounding news reports and films such as GasLand, the drilling occurs well below the water table and the recycling and removal of fluids involved is regulated by the federal and state governments. Regardless, exploiting these deposits continues in the US.

Flaring

Flaring is the burning of natural gas emissions that are not captured during commercial extraction. This releases many CO2 emissions with no commercial benefits, although it does prevent methane from entering the atmosphere. Countries have moved to prevent such frivolous waste, although much gas is still wasted in this manner.

In 2010, about 133 billion cubic meters (4.69 tcf) of gas were wasted in this manner. Russia contributed about 35 bcm, or about 26% of the total. Nigeria contributed 15 bcm. Iran contributed 11 bcm.

Estimates from National Geophysical Data Center

Future Consumption Trends

In 2011, world energy consumption grew by 2.5%. As energy demand grows, natural gas can be expected to arise as a convenient solution to demand due to the low cost of natural gas powerplants, the lower environmental impact of gas, its ability to meet demand, its thermal efficiency, and its relative abundance.

Energy Security

~ At the Intersection of Energy, Economics, and Politics

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