Cleaner at the coalface

08 July 2011 

The International Energy Agency's Keith Burnard, Carlos Fernández Alvarez and
Dennis Volk discuss the merits of clean coal technologies in the quest for decarbonisation…

Considering the reputation of coal as the 'dirtiest of the dirty fossil fuels', it may seem an oxymoron to highlight clean coal technologies (CCTs). Yet in recent decades, numerous technological advances have transformed coal into a low emission fuel source and dramatically reduced the negative health and environmental impacts associated with burning coal.

CCTs work because they are used throughout the coal chain, from production through to final end-use. They have been developed over decades to reduce 'traditional' emissions such as sulphur dioxide (SO2), nitrogen oxides (NOX), heavy metals and particulate matter (PM).¹ Prior to transport to a power station, for example, raw coal may be washed (using cyclones or vibrators) to partially separate out unwanted minerals and reduce the ash content that would normally be a waste product of conventional combustion. At the power station, other CCTs either inhibit pollutants from forming or capture them before release into the atmosphere. 

Governments and industry have worked together to avoid emissions from coal, largely through three approaches:

- Encouraging the uptake of alternative 'cleaner' fuels;
- Improving the efficiency of power generation plants; and
- Developing better ways to prevent emissions from entering the atmosphere. 

The CCTs that minimise traditional emissions are now widely deployed around the world. But coal still struggles to shed its tainted reputation for two reasons: an evolving definition of 'clean' and market competition. 

Though it remains important to think of 'near-zero' emissions in terms of all pollutants from coal-fired electricity production, governments and intergovernmental organisations have become increasingly focused on carbon dioxide (CO2) emissions known to play a major role in global warming. In 2008, coal-fired power stations contributed 30% of global CO2 emissions (IEA, 2010a). But the CCTs proven to reduce CO2 often add costs to plant construction and operation. Thus, unless clear policy drivers are in place, the cleanest coal plants have a hard time competing against plants without CCTs. 

Why use coal?

Coal is the most abundant and widely distributed fossil fuel on the planet. Proven reserves are estimated at around one trillion tonnes (IEA, 2010a) – enough to meet current consumption rates for another 150 years. Reserves are located in around 75 countries (WEC, 2010), with the bulk in the US, Russia, China and India. 

In 2008, coal provided more than one-quarter of global energy demand. It was the fuel source for over 40% of the world's electricity, and is also vital to iron-making, cement manufacture and industrial processes. 

Because it offers abundant, cheap and affordable energy worldwide, coal will continue to play a key role in meeting energy demand well into the 21st Century. 
Its use is central to supporting global economic development and alleviating poverty. But geographical differences are important. Dependence on coal will drop off for OECD countries in which overall energy demand will remain relatively stable; CO2 emissions in these countries are expected to decline. By contrast, as coal is likely to remain the fuel of choice for major developing economies for several decades (IEA, 2010b), rising energy demand will also drive up CO2 emissions. In 2008, China alone accounted for over 40% of global coal consumption (IEA, 2010a).

There are three ways to reduce emissions from coal:
- Fuel switching refers to strategies that use 'cleaner' fuel sources to meet electricity demand with lower consumption of coal. Some countries aim for 'zero carbon' sources such as nuclear or renewable energy; others opt for 'CO2 neutral' fuels such as biomass, or a less carbon-intensive fuel such as gas; 
- Increasing efficiency focuses on technologies to improve processes so that coal-fired plants produce more electricity from each tonne of raw coal and therefore emit less CO2 per unit of electricity generated. New technologies have led to substantial gains: in the 1980s, typical subcritical plants had maximum efficiencies of around 38%, whereas today's ultra-supercritical plants operate at 45% or higher and prospects of reaching 50% appear very realistic in the near future. Moreover, great scope remains for upgrading or replacing existing coal plants: too many small, inefficient coal-fired power stations are still operating in both OECD and non-OECD countries;
- Carbon capture and storage (CCS) aims to capture CO2 emissions and lock them deep underground, effectively preventing them from entering the atmosphere. It is the only technology currently under development that can legitimately stake a claim for producing electricity with near-zero CO2 emissions. Possible storage locations must be well characterised and may include saline aquifers,² depleted oil fields or abandoned mines. Early CCS options show some possible side benefits: pumping CO2 into depleting oil or gas fields can boost recovery; injecting it into disused coal seams displaces methane, which can then be extracted for use as a fuel. But being a 'young' technology, CCS has not yet been demonstrated on a large scale at a commercial coal-fired power station, and power-sector stakeholders (particularly investors) are uncertain of its potential.

Can clean coal compete? 

In a liberalised power market, investors base decisions on the benefits (including revenues) they can expect to achieve. Assuming that the final price paid for electricity is independent of the original fuel source, the cost of plant construction and operation becomes the determining factor. In general, investors have three options: plants with high capital but low operating costs (such as nuclear and renewables), plants with low capital but high operating costs (such as gas), or something in the middle, which is where coal typically sits. 

In 2010, the International Energy Agency (IEA) undertook a global study (IEA, 2010b) to examine whether investors might make different choices under different circumstances – particularly the development of a carbon market that puts a price on CO2 emissions. The study estimated levelised costs of electricity for the European power market, which includes prices for carbon emissions. Assuming a stable carbon price of €20 per tonne of CO2 (/tCO2) emitted, burning of brown coal came out as the cheapest domestic fuel, while high capital/operating costs made it impossible for nuclear and plants equipped with CCS to compete against coal or gas-fired plants. If the carbon price is set at €40/tCO2, CCS-equipped plants then become competitive.³ 

Three ways to stimulate CCTs and CCS 

To avoid the more extreme consequences of climate change, scientists generally agree on the need to limit global warming to between 2°C and 3°C, which means stabilising CO2 emissions in the atmosphere at 450ppm (IPCC, 2007). All three CCT approaches are pivotal to this aim, but only CCS has the potential to deliver deep CO2 cuts quickly.

As CCS is still in an early stage, governments must take strong action to lead its further development and deployment. The current challenge is to demonstrate CCS performance at large scale to secure initial stakeholder buy-in. Progressive governments and governmental organisations (IEA, 2010c) are now providing funding support for demonstration projects. Globally, approximately 80 large-scale CCS projects are at various stages of development, five of which are operational (GCCSI, 2010).

But lessons from earlier CCT deployment show that barriers to uptake extend well beyond technology development. Industry needs assurance of a new technology's long-term competitiveness before it is likely to invest in the innovation needed to reduce capital and operational costs. In the case of proven CCTs, legislation that restricted emissions from coal-fired plants effectively drove such innovation. Over time, many governments have made legislation more stringent and extended it to cover more pollutants. The range of CCTs now available confirms that industry is very innovative when it feels certain of future markets. In fact, where emissions other than CO2 remain high, it is often because effective legislation is not yet in place or not being properly monitored or enforced. 

Given the urgent need to address climate change concerns, governments have an even more powerful tool to stimulate the deployment of CCS. The introduction of carbon markets with effective pricing schemes can further stimulate innovation, thereby driving down capital and operational costs for CCS, and reducing risk (as well as the perception of risk). 

Strategic action by governments can also revitalise a promising technology that has been somewhat dormant. Integrated gasification combined cycle (IGCC) technology offers an alternative that could be more cost-effective than combining CCS with conventional coal-fired plants. IGCC plants use high pressure (typically around 3MPa) to transform coal into a gas, and then combust the fuel gas. This process makes it easier and less expensive to reduce traditional emissions. To date, very few coal-based IGCC plants are in operation, but some analysts predict that their economic appeal would increase if governments were to regulate CO2 emissions. 

Ultimately, to limit global warming, the power sector needs to be virtually 'decarbonised', which implies greater contributions are needed from energy-efficiency, nuclear power and renewable energy technologies. IEA analysis demonstrates that failing to achieve broad deployment of CCS would make it much more difficult to avert climate change and significantly increase the overall cost. Without CCS in the clean energy technology mix, the additional investment cost in the power sector from 2010 to 2050 would increase by 78% (IEA, 2010d). 

¹ Coal combustion produces both fly ash, a fine dust that can be transported and emitted with the plant exhaust gases, and bottom ash, a coarser substance that can be collected from the base of the combustion chamber
² Saline aquifers are geological formations consisting of water-permeable rock (such a limestone) saturated with salt water (brine). When injected into an aquifer, pressurised CO2 may dissolve in the brine, react with dissolved minerals or the surrounding rock, or become trapped in porous spaces. Cement is used to plug the well after the injection
³ At present, the costs for CCS plants have a high degree of uncertainty; due to the newness of the technology, there is a lack of reference plants that can provide cost and performance data
References 

- GCCSI (2010), 'Status of CCS Projects, Interim Report April 2010', Global CCS Institute, Canberra, Australia
- IEA (2010a), 'World Energy Outlook 2010', International Energy Agency, Paris, France, OECD/IEA
- IEA (2010b), 'Projected Costs of Generating Electricity', International Energy Agency, Paris, France, OECD/IEA
- IEA (2010c), 'IEA/CSLF Report to the Muskoka 2010 G8 Summit, Carbon Capture and Storage: Progress and Next Steps', International Energy Agency, Paris, France, OECD/IEA
- IEA (2010d), 'Energy Technology Perspectives 2010', International Energy Agency, Paris, France, OECD/IEA
- IPPC (2007), 'IPCC Fourth Assessment Report', Intergovernmental Panel on Climate Change, Geneva, Switzerland
- WEC (2010), '2010 Survey of Energy Resources', World Energy Council, London, UK

Huge Dividends From America's Energy Game Changer

By Dan Dzombak | More Articles 

July 7, 2011 | Comments (4)

Natural gas companies are selling gas to North American customers for peanuts when they could be getting much higher prices internationally. However, it is currently not possible to ship natural gas from the U.S. to the rest of the world. That will change over the next few years with the completion of multiple natural gas liquefaction plants. I've already revealed mysecret to commodities investing and an alternative way invest in increased natural gas production. Read along, and I'll explain why liquefied natural gas, or LNG, is a game changer, how it will affect natural gas companies, and a dividend stock to profit from LNG's expansion.

NatGas!In the past few years, new technologies and cheaper costs allowed producers to access gas trapped in parts of the U.S. previously considered unreachable. As more companies have tapped these unconventional plays, U.S. natural gas production has risen roughly 25% over the past five years, to 78 billion cubic feet per day, or Bcfd for short. Experts expect production to keep rising over the next 25 years, to 113 Bcfd by 2035.

Currently there is a rush to secure drilling leases in the U.S., which is keeping natural gas supply higher than demand. This has pushed down the price of natural gas to a very low $4.2/mcf, below many producers price of production. The low prices in the U.S. are a stark contrast to the rest of the world.

Source: World Bank Commodity Price Data (Pink Sheet).

So why don't U.S. companies just sell to Europe and Asia? To ship natural gas, you need to cool it to -260 degrees Fahrenheit so it becomes a liquid (hence the name, LNG) and can be safely transported. The problem is, while the U.S. has receiving terminals, we have no liquefying terminals. At a rough cost of $5/mcf to liquefy and transport to Asia, it formerly made no sense for North American producers to ship it, as they were better off selling gas on the continent.

International markets offer large long-term growth for the U.S. natural gas business. While Asian natural gas plays like InterOil's (NYSE: IOC  ) Elk and Antelope fields in Papua New Guinea will be able to meet some demand, Global LNG demand is expected to exceed supply under construction by 2017. So what's happening in the U.S.?

LNG in the U.S.The only exporting plant in North America is ConocoPhillips' (NYSE: COP  ) Kenai LNG plant in Alaska. The plant is in the process of being shut down as natural gas supplies in the Cook Inlet basin area have been falling. The problem was recognized years ago, and a pipeline was considered to connect the area to the main North American pipeline network, but the investment was never made, so no out-of-area natural gas can be processed there.

In the U.S. there are two large projects in the works. Freeport LNG is owned by Michael Smith, ConocoPhillips, Dow Chemical (NYSE: DOW  ) , and other partners. It is targeting a July 2015 start date and is expected to have a capacity of 1.4 Bcfd.

The project open to regular investors is Sabine Pass LNG owned by Cheniere Energy Partners (AMEX: CQP  ) with the general partner being Cheniere Energy (AMEX: LNG  ) . The company currently runs a 4.0 Bcfd receiving terminal with half its capacity contracted toTotal and Chevron with Cheniere Energy, taking the rest for themselves. The company plans on building a 2.6 Bcfd liquefaction plant so it can both import and export LNG. Targeting a 2015 start date, Cheniere Energy's shares got a boost in May when the Department of Energy approved its application to export LNG.

So why is this a game changer?Assuming roughly $5 to liquefy and ship, compared to selling natural gas to consumers in the U.S., 4 Bcfd of natural gas liquefied at Sabine Pass and Freeport LNG and sold in Asia at $14/mcf will allow natural gas producers to earn an extra $20 million a day, or $7 billion a year! This would made it possible for natural gas companies to thrive, compared to now, when they are selling gas below their cost of production in many cases.

Dividends!While Cheniere Energy Partners pays a large dividend of 9.4%, there is a better way to invest in the growth in LNG and still reap large dividends. I'm talking about LNG shippers.

LNG shippers will profit from the growth in LNG no matter where it is, and unlike Cheniere Energy Partners, they are not dependent on one complicated project working out. The two you can invest in are Teekay LNG Partners LP (NYSE: TGP  ) and Golar LNG Ltd.(Nasdaq: GLNG  ) .

Golar LNG owns four floating storage and regasification ships (floating LNG receiving terminals), which are under contract till the end of the decade. The company also owns six LNG carriers. The stock has taken off this past year, rising some 300%, and as such, the company only yields 2.8%.

The stock I like is Teekay LNG. The company is a pure shipper, providing marine transportation for LNG and crude oil under long term contracts. Over the past five years, it has grown from four LNG carriers and five tankers to 21 LNG carriers, five LPG carriers, and 11 conventional oil tankers. The company is organized as an MLP and has increased its distributions at an 8% CAGR to $2.52 per share last year for a 6.7% yield. The company is well-positioned to grow with the LNG market, wherever that may be.

Kosmos Says Transocean Rig Damage May Delay Ghana Drilling

By Jim Polson and David Wethe - Jul 7, 2011 11:05 PM GMT+0100

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Kosmos Energy Ltd. said damage to Transocean Ltd. (RIG)’s Marianas rig may delay drilling of a well off Ghana’s coast.

A force majeure notice was delivered to the government of Ghana and Ghana National Petroleum Corp. after an anchor- handling accident damaged the rig, Dallas-based Kosmos said today in a statement. The Marianas was scheduled to arrive July 10 for drilling, Kosmos said.

Kosmos said it anticipates that either the Marianas or a substitute rig will be “available soon” to drill the Cedrela-1 well in the West Cape Three Points Block. Yesterday 108 of 121 workers on the vessel were evacuated after it took on water while preparing to leave an Eni SpA drilling site roughly 40 miles off Ghana, the rig owner said.

The market for deep-water rigs in that part of the world is so tight that Kosmos will likely have to wait at least a month for a comparable drilling vessel, said Brian Uhlmer, an analyst at Global Hunter Securities in Houston. Moving an unused rig from the Gulf of Mexico could take about 45 days.

“There’s literally nothing in Ghana that can come back to work quickly,” Uhlmer said. “I think the most likely is to pull something from the Gulf.”

Towing for Repairs

Transocean expects it will take at least a week to tow and inspect the rig for damages, Guy Cantwell, a spokesman for the Vernier, Switzerland-based drilling contractor, said today in a telephone interview. No estimates can be made on the damage or where the repairs will take place until the inspection is complete, he said.

Some workers will return to the rig, “but not a tremendous amount,” Cantwell said, declining to give specific numbers. Workers are monitoring the situation and removing water from the vessel, he said.

The Marianas rig, which was used in 2009 to start drilling the Macondo well for BP Plc in theGulf of Mexico, may be out of service for as many as 180 days with most of the time taken up by moving it to a yard and final inspections, Uhlmer said. “It’s not like fixing your kid’s soccer ball,” he said.

The rig started drilling the Macondo well on Oct. 6, 2009, and was damaged a month later by Hurricane Ida, according to a report posted on Transocean’s website. Drilling was suspended while the rig was moved to a shipyard for repairs.

Bad Luck Rig

Taking its place at the well was Transocean’s Deepwater Horizon rig, which exploded and sank in April 2010, leading to the largest U.S. offshore oil spill.

“It’s a bad luck rig,” Uhlmer said.

Geoff Kieburtz, an analyst at Weeden & Co. in Greenwich, Connecticut, said he’s still trying to understand how serious the situation is after more than 100 people were removed from the rig.

“You don’t do that unless you’re reasonably concerned about something,” he said in a telephone interview. “On the other hand, you don’t leave 13 people on there if you think it’s an imminent threat. So, it’s all a little bit fuzzy to me.”

Kosmos rose 49 cents, or 2.9 percent, to $17.32 at 4:15 p.m. in New York Stock Exchange composite trading. Transocean rose 24 cents to $62.47.

While parts of the Marianas rig date to 1979, the rig was upgraded in 1998 and is able to work in water as deep as 7,000 feet (2,000 meters), according to a Transocean regulatory filing. The rig wasn’t drilling when the water was discovered and it was stable, Cantwell said yesterday.

Kosmos operates the West Cape block and holds a 30.875 percent interest, according to a July 5 statement. An Anadarko Petroleum Corp. (APC) affiliate also holds 30.875 percent, a Tullow Oil Plc (TLW) affiliate holds 22.896 percent, Sabre Oil & Gas holds 1.854 percent and E.O. Group Ltd. has 3.5 percent of the block. Ghana National Petroleum has a 10 percent interest.