GE Promoting Combined Natural Gas Wind and Solar Power Plant

While the “Gas Age" won’t last forever, gas fired power looks like being used as a way of kick-starting the transition to 100% renewable energy, with hybrid plants like this one being proposed by GE enabling solar thermal, wind and gas fired power generation to share generation and transmission infrastructure. Technology Review says - “The hybrid plant could be the cheapest and easiest way to add renewable energy to the grid" - GE Combines Natural Gas, Wind, and Solar. Alstom are moving in a similar direction, but not as fast - Building bridges.

GE has announced the first power plant to integrate wind and solar power with natural gas—a 530-megawatt plant that will start operating in Turkey in 2015. The power plant is made practical by a flexible, high-efficiency natural-gas system the company announced two weeks ago and a solar thermal power system created by eSolar, a Burbank, California-based startup that GE recently invested in.

Such hybrid plants may become the dominant type of new power plant in some parts of the world, GE says. The new technology is aimed at countries that use 50 hertz electricity (the United States uses 60 hertz). In particular, it could make it easier for China and the European Union to meet their renewable energy targets.

Adding solar power to natural gas plants isnt a new idea, but it hasnt been economical without government subsidies. GE says that because of its new turbines and related equipment, these hybrid plants can, for utilities with the right combination of sunlight and natural gas prices, be competitive even without government support.

While combining solar thermal power and natural-gas turbines is not new, adding wind power to such a system is, GE says. Pairing wind with the natural gas plant helps shave some of the cost of the wind power—the wind farm can share some of the natural gas plants control systems and its connection to the grid. The natural gas plant also smooths out variations from the wind turbines.

Solar thermal power involves the use of an array of mirrors to concentrate sunlight and the resulting heat to produce steam. That steam can be fed into the steam turbine at a natural gas combined cycle plant to boost its power output.

The solar concentrator array from eSolar helps lower costs in two ways—its modular concentrator system is easy to install and easy to modify for the needs of specific plants. It also produces higher temperature steam than some previous solar thermal systems, increasing power output. GE has also developed a natural gas power plant that is highly efficient, and whose power output can easily be adjusted to make up for variations in power output from solar power.

Connecting a solar thermal system to a natural gas power plant, and thus eliminating the need to buy a separate steam turbine and related equipment, can cut the cost of a solar thermal system by up to 50 percent, says Jon Van Scoter, CEO and president of eSolar. Paul Browning, vice president of thermal products at GE, calls it "the most cost-effective form of solar energy available today."

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Flaring The Ultimate Gas Guzzler

Next100 has a post on the unnatural practice of natural gas flaring - The Ultimate Gas Guzzler.

If you wanted to help curb global warming by slashing emissions of 400 million tons of CO2 annually, you could:

* take 77 million automobiles off the road, or
* eliminate the wasteful practice of venting and “flaring” (burning) of billions of cubic meters of unused natural gas from production wells.

Much as Id like to choose Plan A on some days as a solution to my morning commute hassles, I have to admit that Plan B sounds more practical. In fact, it sounds like a no-brainer. After all, why hurt the environment by wasting a resource that could instead make money by putting it to productive use?

The staggering waste of gas—and consequent economic opportunity for conservation—was highlighted this week in a study released by GE called Flare Gas Reduction: Recent Global Trends and Policy Considerations. It concludes that with existing technology, some $20 billion in gas could be reclaimed to generate electric power and “yield billions of dollars per year in increased global economic output.”

One of the biggest offenders is the Russian Federation, which flares up to 50 billion cubic feet of natural gas annually due to underinvestment in gas processing and power generation technology.

Runners up include Nigeria, which wastes 15 billion cubic feet per year, and other countries in West Africa, which together burn off some 10 billion cubic feet. Fortunately, Nigeria plans major investments to capture and turn its flared gas into a valuable asset.

Wasteful flaring takes place even in the United States. In North Dakota, for example, roughly a quarter of all gas produced from oil wells is simply burned off.

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Santos bid lights up coal seam gas sector

The SMH reports that the new carbon tax is accelerating interest in coal seam gas, with Santos moving to acquire the rest of Eastern Star Gas - Carbon tax not the end of fossil fuels, just ask Santos.

HYDROCARBONS have been copping some bad press lately.

What with all the flak over emissions and how best to reduce them, you could be forgiven for thinking the end of the industry is nigh. But the past few days has seen a flurry of takeover activity, starting last Monday with Peabodys $4.7 billion bid for Macarthur Coal and ending the week with BHP Billitons $14 billion tilt for American gas producer Petrohawk.

Then, before the market even opened yesterday, Santos jumped in with an agreed mop-up of pubescent coal seam gas outfit Eastern Star Gas, valuing the group at just shy of $1 billion. At a nominal 90¢ a share, the deal delivers Eastern Star shareholders a whopping 51 per cent premium to last Fridays closing price.

Rather than spelling the death knell for fossil fuels, it would appear the carbon price arrangements announced last week have partially eliminated the uncertainty that has caused energy and power companies to continually delay long-term investment decisions.

BHPs expansion of its American energy portfolio obviously falls outside the Australian carbon tax proposal but gives a clear indication the mining giant sees a future in lower emissions energy sources as carbon pricing becomes a global inevitability.

It was BHPs chief executive Marius Kloppers who last year reignited calls for carbon pricing while power suppliers like Origin Energys Grant King have roundly criticised the inordinate length of time it has taken successive Australian governments to implement a carbon pricing policy.
It takes up to eight years to get a power station from the drawing board to the paddock and in the policy vacuum that has existed here for most of the past decade, operators like Origin have been unable to decide whether to build old-style, low-tech operations belching out coal fumes or something a little more modern.

That has left a worrying dearth of investment in power generation, particularly in the eastern states.

It therefore is no coincidence that the junior partner in Santoss latest coal seam gas expansion is the Hong Kong-based TRUenergy which, along with Origin, snapped up the NSW state government-owned electricity distribution companies last year. TRUenergy also owns the Yallourn brown-coal-fired power station in the Latrobe Valley, one of the worlds dirtiest.

Under the terms of the friendly deal announced yesterday, Eastern Star Gas shareholders will swap their shares for Santos scrip, giving the Adelaide-based oil and gas group full control. But a second leg of the deal will see Santos emerge with 80 per cent of Eastern Stars gas permits with TRUenergy accounting for the remaining 20 per cent.

Eastern Star has extensive reserves in the Gunnedah Basin but, as a corporate minnow, was always constrained by a lack of capital in developing the resource. Crunch time was approaching, either to joint venture with a much bigger partner for a smaller slice of the future, or merge. ....

Santos will now have a major presence in every eastern Australian onshore gas basin from Moomba in South Australia near the Queensland border to the giant fields of the Bowen and Surat basins inland from Gladstone and in the Otway basin in Victoria.

Just how and where it will ship the gas from the Gunnedah Basin has yet to be decided. It may decide to pipe it up to its new $18 billion Gladstone liquefied natural gas plant, currently under construction. Or it could opt for another port facility at Newcastle.

The SMH has another article looking at the supposedly tight east coast gas supply once the CSG LNG terminals are operational - Santos bid lights up coal seam gas sector.

The $730 million bid by Santos for NSW coal seam gas (CSG) group Eastern Star Gas was a welcome relief from the investor gloom that has characterised the CSG sector in the last 12 months.

Share prices of the CSG companies not yet swept up by the big boys of the industry, with their gas export plans, are popping again, regardless of the on-going environmental campaign against the industry.

Investors are again playing a who-is-next game, driving up CSG share prices across the board. Bow Energy and Metgasco have led the pack, with Dart Energy and Comet Ridge also receiving some new attention.

Julia Gillard has also helped fuel the renewed interest in the CSG sector, with the proposed carbon tax set to drive a shift away from coal-fired power generation to gas-fired power with its 60 per cent lower emissions

But the reality is that with or without the Santos bid and the carbon tax, the CSG sector was due for a return of investor interest on the simple premise that Australia’s eastern seaboard faces a gas shortage, one in which domestic gas prices will have to about double to pull back gas that would otherwise head offshore to higher priced markets.

It is a theme that Morgan Stanley zeroed in on in the wake of the Gillard minority government unveiling its carbon tax plan on July 10. “The era of cheap and plentiful gas in eastern Australia is over,’’ the broker declared. ‘’Steady demand growth and depletion of historical conventional production is leading to a shortage evident after 2014, with CSG and other unconventional gas required to meet the gap.’’

The broker said that it was generally accepted that the carbon tax would increase the use of gas as a ``transition’’ fuel for power generation.

Assume that will increase demand for gas, and a case can be built that annual eastern state gas demand is set to grow from around 720 petajoules in 2011 to more than 1350 petajoules by 2020.

But there isn’t enough gas to meet that sort of growth. Morgan Stanley reckons that existing conventional gas supply (mainly Bass Strait and the Cooper Basin) will be largely depleted within 10 years.

The build-up in CSG resources was meant to flood the market. But there isn’t enough of that either as the multiple gas export projects being built at Gladstone in Queensland will soak it all up to chase the much higher export prices.

Morgan Stanley says the end result of all that is obvious – domestic gas prices are ``likely to escalate sharply to divert high-cost unconventional gas earmarked for export markets back to the domestic market’’.

``We believe this will take effect after 2014 as existing long term contracts wind down and need to be replaced. A gap-up to export parity (about $7.50 a gigajoule) is the likely first step,’’ Morgan Stanley said.

That means those that own gas resources on the eastern seaboard are heading towards a golden era. It also means that we have not seen anything yet in home energy bill shocks.

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Documents Leaked Shale Gas Industry E Mails and Reports

The New York Times has a follow up to their recent article on doubts about the financial sustainability of the shale gas rush, quoting their anonymous sources for the article - Documents: Leaked Industry E-Mails and Reports.

Over the past six months, The New York Times reviewed thousands of pages of documents related to shale gas, including hundreds of industry e-mails, internal agency documents and reports by analysts. A selection of these documents is included here; names and identifying information have been redacted to protect the confidentiality of sources, many of whom were not authorized by their employers to communicate with The Times.

Geologist and official from Anglo-European Energy:

After buying production for over 20 years, hopefully I know the characteristics of great wells (flat decline curves, low operating costs, large production), and as you know, the shale plays have none of these. The herd mentality into the shale will eventually end possibly like the sub-prime mortgage did. In the meantime it is very difficult to sell any kind of prospect that is not a shale play.


Analyst from PNC Wealth Management (2011):

Money is pouring in from investors even though shale gas is inherently unprofitable. Reminds you of dot-coms.


Analyst from IHS Drilling Data (2009):

The word in the world of independents is that the shale plays are just giant Ponzi schemes and the economics just do not work.


Retired geologist for major oil and gas company (2011):

As I think you would agree, we are looking at a bubble here with caveats. The caveats are how corporate hubris and bad science have caused a lot of folks to think that gas is nearly too cheap to meter. And now these corporate giants are having an Enron moment, they want to bend light to hide the truth. The bubble will burst, folks will get run over, reason will be restored, if only temporarily.


Official from Bold Minerals LLC (2010):

1. The players never did any careful regional studies before they made serious and irrevocable capital commitments to the various shale plays. Our scouting sources never got calls for logs or cores on the significant old tests, especially in the Haynesville. This was mystifying.

2. The pronouncement that the reservoir was uniform and covered 10 or 20 counties or (in the case of Marcellus) 5 states was absolute heresy in the conventional business. This very extravagant claim was never really debated or contested by the technical community. The downhole data for these broad sweeping conclusions was simply never there.

3. The escalation of lease bonuses to ridiculous heights and the taking of 3 year term leases put the companies in the position of being compelled to drill hundreds of potentially technically unsound wells with insufficient downhole information or face massive impairments by letting incredibly expensive acreage expire undrilled. In previous hot domestic plays, no major company would ever commit itself to lease positions of this scope and scale of expenditure that they could not afford to abandon if the technical picture became negative.

4. The ‘bait and switch’ where one massive set of capital outlays in the ‘best’ shale uncovered was soon to be eclipsed by the recognition of even better shales which required even more outlays before a thorough technical assessment of existing shale positions had been obtained could only be classified as a type of ‘mania’. It has no precedent in financial scale to any of the previous lease plays that experienced a speculative frenzy in domestic onshore petroleum history.


Official at Phoenix Canada Oil Company (2010):

It is my strong view that we will see a near collapse of that play, probably sooner rather than later. Perhaps we will see a repeat of the coal bed methane (CBM) play disappearance -- where that exciting development faded into history without a trace!


Official from Schlumberger (2010):

All about making money. Im working on a shale gas well that was just drilled in Europe. Looks like crap, but the operator will flip it based on ‘potential’ and make some money on it. Always a greater sucker....

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Could Natural Gas Fuel a Trucking Revolution

The Energy Collective has a post from Geoffrey Styles on the growth of natural gas fuelled road transport - Could Natural Gas Fuel a Trucking Revolution ?. might as well use that transition fuel up as fast as possible...

The International Energy Agency (IEA) released its latest Medium-Term Gas Market Report in St. Petersburg, Russia last month. Although the IEA sees the growth of gas in the power sector slowing, they also cite its emergence as "a significant transportation fuel." What really caught my eye was their projection that gas over the next five years would have "a bigger impact on oil demand than biofuels and electric cars combined," in light of the US shale gas revolution and tougher pollution rules in China.

Thats quite an assertion, considering oils longstanding dominance in transportation energy. As I noted in March, Italy, Pakistan and several other countries already have well-established demand for compressed natural gas (CNG) for passenger cars. Despite these hot spots only 3% of gas is currently used in transportation, globally, based on analysis from Citigroup. The IEA is forecasting that transportation growth will consume 10% of the projected global gas production increase of roughly 20 trillion cubic feet (TCF) per year by 2018. Thats 2 TCF per year of additional natural gas demand in the transport sector, equivalent to 1 million barrels per day of diesel fuel.

Id be more skeptical about that figure if I hadnt seen a presentation from Dr. Michael Gallagher of Westport Innovations at the Energy Information Administrations annual energy conference in Washington, DC last Monday. Westport specializes in natural gas engine technology for heavy-duty trucks and played a major role in implementing the LNG vision of the ports of Los Angeles and Long Beach, CA a few years ago.

Dr. Gallagher made a strong case for gas in heavy-duty trucking, starting with the low cost of US natural gas compared to oil and its products. Initial growth rates in several segments look encouraging, including transit buses and new trash trucks, for which natural gas now has around half the market. Growth in China has apparently been even faster, with LNG vehicles increasing at over 100% per year (from a small base) and natural gas refueling stations growing at 33% per year since 2003.

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Australias Gas Pains

The Wall Street Journal reports that entry into the gas age is not without pain fopr would be exporters of Australian natural gas - Australias Gas Pains.

Seven LNG projects now under construction in Australia are expected to cost 140 billion Australian dollars (US$144 billion). By 2020, Australia could produce as much as one quarter of the worlds LNG—up from less than a tenth today—making it one of the worlds top two producers alongside Qatar.

The price of such rapid growth will be high. Resource workers are expensive and will become more so as the market for labor remains tight. Woodside Petroleum has already seen cost overruns of US$3 billion at its giant Pluto LNG project in Western Australia, partly because of labor shortages.

The soaring Australian dollar, up 65% against the U.S. dollar since the worst of the financial crisis, is also pushing up the cost of business for resources companies.

Australia-listed Oil Search said last month the dollars rise has pushed up the budget on its Papua New Guinea project, operated by Exxon Mobil, by US$700 million, or nearly 5%.

BernsteinResearch says the cost per ton of Australian LNG could average as much as US$4,000, compared with about US$1,000 at Apaches Kitimat project in western Canada.

For Australias LNG projects, politics are an unwelcome obstacle. There are moves at federal and state levels that could limit gas extraction on vast tracts of land deemed critical to the countrys agricultural production. That shouldnt affect existing projects, though it could temper expansion—which actually could help Australia avoid the worst labor shortages.

Meanwhile, pressure is building to get the Australian projects up and running soon. Qatar—which produces some of the worlds lowest-cost LNG—has a moratorium on further development of its gigantic North field in order to preserve its longevity. But the self-imposed ban ends in 2013.

The ABC reports that Inpex are optimistic about their project going ahead - Inpex LNG venture tipped to attract investors.

A senior economist says he expects Inpex will have no trouble in securing investors for its planned multi-billion dollar gas project in Darwin. The Japanese company announced yesterday that it had already sold its total projected liquefied natural gas output from the proposed operation.

A final investment decision on the project, to pump gas from the Timor Sea to Darwin via a 900 kilometre pipeline, is yet to be announced. But it is believed Inpex hopes initial construction work will begin in March.

Macquarie Bank senior economist Brian Redican says investors are likely to view the project as a low-risk venture. He says a surge in oil prices in recent years means Inpex is in a strong position to secure investors. "Because petrol prices and energy prices are so high, they are actually extraordinarily profitable at the moment," he said.

The Australian has yet another report on the prospect of the US exporting LNG from shale gas - US to enter LNG export market amid domestic supply glut. It will interesting to see the reaction in the US if local gas prices converge with those in Asian export markets (the same unpleasant adjustment that is beginning in Australia already).

AUSTRALIAN gas exporters had better watch out - theres a new kid on the block. The US could emerge as a major competitor to Australia’s burgeoning gas-export market, challenging the viability or expansion plans of close to a dozen Australian liquefied natural gas projects, according to Noel Tomnay, the head of global gas at UK-based energy consultancy Wood Mackenzie.

Traditionally an importer of gas, the US is experiencing a domestic supply glut owing to heavy investment in the production of shale gas in states like Texas. That’s depressing US gas prices and prompting some companies to investigate the potential of terminals on the US coast geared for export to take advantage of higher prices abroad.

Cheniere Energy recently signed two long-term gas supply deals with offtakers, including with BG Group, as it presses ahead with plans to build the first LNG export terminal in the US. Last month, Cheniere said it has enough supply locked into long-term contracts to start construction of a proposed LNG export terminal in Sabine Pass, Louisiana, in 2012.

Tomnay told Deal Journal Australia: "We’re of the view that North America will have 20 million tonnes of LNG capacity maybe as early as 2018. Consequently, that will remove potential market share for Australian LNG projects."

Investment totalling more than $140 billion has been earmarked for new Australian LNG terminals focused mainly on Asia since 2007, which could catapult Australia ahead of Qatar as the world’s largest LNG exporter within a decade. In the latest development yesterday, Japan’s Inpex signed 15-year deals to supply five Japanese utilities with $US70 billion ($68.3bn) worth of LNG from its proposed Ichthys project in the Northern Territory.

The other risk facing would be LNG exporters to Asia is China taking its first steps towards producing shale gas - Chinese shale gas find may cut LNG demand
.

ROYAL Dutch Shell has found shale gas in China, prompting fears that the country could develop enough domestic supply to limit imports of liquefied natural gas. An official at PetroChina, Shells partner in the region, told Reuters that results from two wells had been positive.

In less than a decade shale gas has transformed the US from gas shortage to a point where companies are planning to export LNG, fundamentally altering the dynamics of the international gas market. Existing LNG producers had hoped that higher demand from China would offset the decline in imports to the US.

Shale gas is obtained by hydraulically fracturing rock, which requires large quantities of water and chemicals. There is concern among environmentalists that the process can contaminate groundwater supplies.

Analysts have predicted shale gas could supply up to half the natural gas produced in North America by the end of this decade.

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Move Over Electricity Gas and Water Meters Are Getting Smart

Greentech Media has a report on the expansion of smart metering to water and gas - Move Over, Electricity: Gas and Water Meters Are Getting Smart.

For all of the chatter about smart meters, the conversation rarely wanders far from the realm of electricity. But action is starting to heat up in the smart gas meter market, and water isn’t far behind.

Last week, consulting group Capgemini announced it was chosen by Southern California Gas Company (owned by Sempra) to install more than six million smart meters in the next five years, the largest gas-only utility smart meter project in the U.S. SoCalGas’s project is part of a nearly three-fold increase in the penetration of smart gas meters worldwide estimated by Pike Research between 2010 and 2016.

“The gas grid is certainly a different animal,” said David DuCharme, vice president of Utility and Smart Energy Services at Capgemini. “The largest issue is safety and management.”

In Europe, there is already more activity in the gas market; the U.K. government has mandated dual gas and electric smart meters for every home and business by 2020. Italy will install smart meters for all of its commercial gas customers and most residents by 2016.

Yet in the U.S., gas metering has not received as much attention -- or as many federal dollars -- as electric smart metering. However, the challenge of managing gas smart grid data can be less complex than electric meter data management, according to DuCharme. As prices continue to drop for the smart meter market, this will benefit the gas market, as well.

Like their electric brethren, gas utilities have struggled with integrating IT and OT when implementing the new metering systems. Capgemini, which has doubled its accounts in the smart energy space to 40, is finding increasing success with gas utilities. In the case of SoCalGas, about 30 different vendors will provide the meters; Aclara is providing the MDM system.

Water is also on the horizon. “The cost of efficiently managing infrastructure in the gas and water industry is extremely important,” said DuCharme. For those who think the electric grid in the U.S. is aging, the water infrastructure in much of the world is downright elderly. One study from Frost & Sullivan estimates the European smart water meter market will be worth $20 billion by 2020 and will see double-digit growth in the next decade.

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Can shale gas lead to reduced greenhouse gas emissions

Some energy analysts say that increased shale gas production can lead to reductions in greenhouse gas emissions because natural gas produces less greenhouse gas emissions as compared to coal, so swapping coal fired power plants with natural gas fired plants would have positive impact on climate change.

This can be only partially true, because cheap and readily available natural gas will likely become a major stumbling block to renewable energy sources as well because natural gas, regardless of the fact that it emits less greenhouse emissions than coal, still emits significant share of harmful greenhouse gases into the atmosphere. What this means is that shale gas can only help our climate with proper policies, the ones that also promote higher use of renewable energy sources.

The truth is pretty simple, namely that natural gas production and consumption has significantly higher emissions than not just renewable energy sources but also nuclear power.

Some other factor also needs to be carefully examined here and this is the entire process of shale gas production. What policy makers must not forget is that extracting, processing and transporting the fuel can result in emissions of methane, a greenhouse gas lot more potent than carbon dioxide. The precise level of these methane emissions is still uncertain, with extensive study yet to be performed and published.

The policy makers need to realize that the increased shale gas production can also lead to displacement of zero-emission sources such as renewable energy sources and nuclear energy. Therefore, the right energy policy in terms of being aimed at the reduction of harmful greenhouse gases needs to find the way to successfully implement both clean energy sources and shale gas, without the displacement of any kind. What is also very important  is also the fact that methane emissions from shale gas production need to be kept low in order to maximize the potential benefits of natural gas.

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Gas prices to double in 20 years as demand explodes Santos predicts

Santos is tipping much higher natural gas prices for Australian consumers and a boom in unconventional gas - Gas prices to double in 20 years as demand explodes, Santos predicts.

The only way to meet a tripling in natural gas demand in eastern Australia is by allowing unconventional gas projects, such as coal seam gas, oil and gas producer Santos says.

Santoss eastern Australia vice-president James Baulderstone told a conference that he expected gas prices to more than double within two decades, driven by demand and linking it to oil prices. Soaring global demand for liquefied natural gas is expected to contribute to Australias wealth and make it one of the worlds biggest exporters of the commodity. ...

The five LNG trains already sanctioned, with more planned, represent a quantum change in eastern Australian natural gas demand, Mr Baulderstone told the Opportunities and Challenges for Australian Gas conference yesterday. Provided natural gas development activity is allowed to proceed at the right pace, and the market is willing to pay the increased cost of extraction, there is sufficient gas in eastern Australia to meet this demand. But he added that it was not viable to develop much of the gas reserves to meet the new demand at current Australian gas prices of about $4 a gigajoule.

Australian gas prices were some of the cheapest in the developed world, Mr Baulderstone said. He predicted prices would move to $6 to $9 a gigajoule.

The Australian (now beginning to paywall itself into oblivion) reports that AGL are already seeing much higher prices - AGL secures east coasts most expensive gas deal.

AGL Energy has snared the east coasts most expensive domestic gas sales contract in what is thought to be a 50 per cent price jump forced by the expected demand from Queenslands coal-seam gas export plants. AGL is believed to have secured a price of about $6 a gigajoule for gas that will be used to supply miner Xstratas Mount Isa operations for 10 years from 2013.

The SMh reports that fracking for coal seam gas now has a new cause for concern - earthquakes - Fracking shock reignites concern.

DEBATE over the safety of fracking in Australia has reignited after a gas project in Britain was named as the likely cause of 50 tremors this year.

A panel of seismic experts has found it highly probable that fracking conducted by Cuadrilla Resources - 41 per cent-owned by Australian drilling company AJ Lucas - was the cause of two significant tremors and 48 aftershocks near the British town of Blackpool in April and May. The findings come after the independent MP Tony Windsor told the federal government this week he would not support its mining tax unless more was done to investigate the safety of fracking in Australia.

Fracking, or hydraulic fracturing, is a controversial gas extraction technique that uses high pressure solutions to fracture rocks deep underground. The process is used in both coal seam gas and shale gas extraction and, if poorly executed, can contaminate groundwater and trigger seismic activity.

Fracking is most common in the United States but is fast spreading to other nations like Australia and Britain, where Cuadrilla hoped to develop a gas source near Blackpool. The company was forced to launch an investigation after tremors of magnitude 2.3 and 1.5 appeared to follow a series of fracks.

The report - commissioned by Cuadrilla - confirmed the fracking was most likely to have caused the tremors but said the region had rare geological factors that were one of many factors which coincided to induce these seismic events.

AJ Lucas services the main coal and coal seam gas basins in Queensland and NSW, including in the Hunter Valley, Bowen Basin and Surat Basin.

The Cuadrilla revelations are not the first time fracking has been linked to tremors, with regulators in the US state of Arkansas expressing concern that two shale wells - now owned by BHP Billiton - were responsible for causing earthquakes.

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45bn coal seam gas projects draw workers from around the world

The Australian has an article on the windfall heading Bechtel’s way as construction looms for 3 coal seam gas LNG projects in Queensland - $45bn gas plan draws workers of the world.

WORKERS from as far away as Ireland will be part of the massive fly-in, fly-out workforce needed to build the $45 billion development turning coal-seam gas into liquified natural gas on Curtis Island off Gladstone, central Queensland.
About 800 people are now working on the mangrove-fringed island on the north side of Gladstone Harbour, but this is expected to rise to at least 6000, housed in specially constructed camps, within two years. There will also be up to 2000 contractors, who will not live on site but will be ferried across from Gladstone every day to help build the three liquid natural gas plants, expected to be operating by 2015.

While protests against coal-seam gas continue in areas such as the Darling Downs, where 40,000 coal-seam wells will be constructed, the export industry is proceeding rapidly. The pipeline that carries the coal-seam gas from the Darling Downs to Gladstone is under construction, and work on the plants that will convert the gas into 38 million tonnes of liquid to be exported to Asia each year is well under way.

Three LNG plants are being built -- by the British-owned BG Group, Santos and Origin -- but all three $15bn plants are being built by US construction giant Bechtel, which owns the intellectual property rights to the technology. Bechtel, one of the worlds biggest contractors with a global workforce of 55,000, is already a big employer in Gladstone, with about 1500 people working at the expansion of Rio Tintos alumina refinery at Yarwun. …

The sheer scale of the three projects is having a debilitating effect on the central Queensland region, already suffering a skills shortage because of the mining boom. While wages for unskilled workers in mining average between $80,000 and $120,000 a year, with up to $150,000 for more skilled workers, labour hire operators estimate the short-term nature and urgency of the jobs on Curtis Island mean the pay on offer is 15-20 per cent higher than in mining industries. ... A mine worker paid $150,000 a year might be able to get $180,000 as the Curtis Island workforce increases.

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Wind Power Makes Hydrogen for German Gas Grid

Proposals to generate hydrogen using excess wind power have been blowing around for quite a few years now, with the hydrogen being a form of "energy storage" that can be subsequently burnt for heat and/or power.

Some systems are now appearing in the wild in countries as diverse as Morocco, Turkey, Argentina and Norway.

Greentech media reports that the Germans are getting in on the act as well, converting excess wind power to hydrogen and feeding it into the natural gas grid (perhaps the combination of hydrogen derived gas and biogas will eventually eliminate European dependence on gas from Russia and the middle east) - Wind Power Makes Hydrogen for German Gas Grid

For the first time on an industrial scale, hydrogen produced using wind power is being injected into the natural gas grid in Germany. It’s a development that could enhance the value of wind power by making it useful no matter when it is produced.

E.ON said the P2G unit in Falkenhagen in eastern Germany, operated in a partnership with Swissgas AG, has a capacity of 2 megawatts and can pump out 360 cubic meters of hydrogen every hour. In a sign of the potential of the technology, its inauguration drew a crowd that included the German economics minister, members of the European parliament and high officials of Brandenburg state.

“One of the biggest challenges of transforming Germany’s energy system is finding ways to integrate the increasing share of intermittent, renewable-source energy,” Economics Minister Philipp Rösler said in the E.ON news release. “To ensure that Germany’s power system remains stable and that our economy continues to have the energy it needs, we not only have to rapidly expand energy networks. We also need innovative solutions like the P2G unit here in Falkenhagen.”

The Falkenhagen facility is essentially a way to store wind power. Instead of turning off the turbines at a nearby wind farm when demand is low (as it can be at night, when the wind tends to blow strongest), or using the power to move water up a hill (effective but site-specific and expensive pumped hydro) or charge a battery (expensive), or try to find a buyer for the power far away (requiring costly transmission), the power is used to turn water into hydrogen by electrolysis. The hydrogen is then shot straight into the area’s natural gas system, displacing a fossil fuel.

What’s especially interesting here is that last step: the use of the hydrogen in the natural gas pipeline. We recently reported on a study commissioned by the U.S. Department of Energy, “Blending Hydrogen Into Natural Gas Pipeline Networks: A Review of Key Issues,” in which the authors sound a fairly optimistic note about the possibility of putting the country’s extensive gas pipeline system to work for clean hydrogen’s benefit. They don’t give a 100 percent endorsement of the idea -- because of the nature of hydrogen, the natural gas system can only take small percentages without extensive reworking -- but their review of the issues says that the pluses appeared significant enough to warrant further study. So while the E.ON project in Germany is fairly small, it should provide valuable insight that will help guide subsequent approaches with the technology.

Other similar approaches include putting hydrogen produced from excess renewables to work in fuel cells, and reacting it with CO2 from bioenergy plants to produce a carbon neutral methane, sometimes known as “renewable methane” or synthetic methane. This synthetic methane could go directly into the natural gas pipeline without the limitations of hydrogen. A 25-kilowatt demonstration plant using just such a system is operating in Germany.

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Renewables now cheaper than coal and gas in Australia

ReNew Economy has a look at a new study from BNEF showing that renewables are now cost competitive with fossil fuels in Australia - Renewables now cheaper than coal and gas in Australia.

A new analysis from research firm Bloomberg New Energy Finance has concluded that electricity from unsubsidised renewable energy is already cheaper than electricity from new-build coal and gas-fired power stations in Australia. The modeling from the BNEF team in Sydney found that new wind farms could supply electricity at a cost of $80/MWh –compared with $143/MWh for new build coal, and $116/MWh for new build gas-fired generation. These figures include the cost of carbon emissions, but BNEF said even without a carbon price, wind energy remained 14 per cent cheaper than new coal and 18 per cent cheaper than new gas.

“The perception that fossil fuels are cheap and renewables are expensive is now out of date”, said Michael Liebreich, chief executive of Bloomberg New Energy Finance. “The fact that wind power is now cheaper than coal and gas in a country with some of the world’s best fossil fuel resources shows that clean energy is a game changer which promises to turn the economics of power systems on its head,” he said.

RNE also has an article on a Greens WA proposal to move to 100% renewables, drawing on work from Sustainable Energy Now and Beyond Zero Emissions - Greens push 100pct renewables plan for W.A..

The Greens Party has unveiled an ambitious new document that outlines possible pathways to turn Western Australia – one of the most energy-intensive states in the world – into one where its stationary energy needs are powered 100 per cent by renewable energy sources in less than two decades.

The Greens offer two principal scenarios to transform the coal and gas-dependent grid known as the South West Interconnected System (SWIS), which includes the capital Perth and the most populous regions. The first involves a heavier reliance on solar thermal and storage technologies currently deployed in Spain, the US and elsewhere, while the second relies more on currently cheaper technologies such as wind energy and solar PV. Both are supported by bio-mass and pumped hydro.

According to Scott Ludlam, the WA-based Senator whose office anchored the report with the help of specialist consultants, the plan seeks to make two important points – one that it is feasible, and two, it will not cost much more than business as usual (BAU).

Indeed, even using somewhat conservative technology cost forecasts for the various forms of solar, and to allow for a safety-first approach to capacity requirements, the study concludes that the levellised cost of electricity in the various renewable scenarios ranges from $208/MWh to $221/MWh by 2029. (We go into detail further down)

The levellised cost of electricity in the BAU case is not much cheaper – $203/MWh. While it has lower up front capital costs – $20 billion vs $60 billion, the balance of the BAU scenario bill will be paid in fuel costs, which for gas and diesel customers in WA is already proving expensive and forcing those on isolated and remote areas in particular to already consider solar alternatives. ...

The document was drawn together by Ludlam’s team, but the detailed technology scenarios were put together by an engineering team from Sustainable Energy Now, and drew on previous work by the likes of CSIRO and Beyond Zero Emissions.

RNE also has an interesting article on the impact of solar PV on peak power demand in South Australia - dramatically dropping summer peak demand from the grid - Rooftop solar reshapes energy market in South Australia.

Rooftop solar continues to have a dramatic impact on the energy market in South Australia – the Australian state with the highest penetration of rooftop solar.

As these graphs provided by Melbourne Energy Institute’s Mike Sandiford illustrate, the proliferation of solar PV is not just having an impact on overall demand in the state, it is also shaving and reshaping the peak demand curves.

The impact of solar PV in South Australia was recognised by a special study by the Australian Energy Market Operator last August. As we reported then, South Australia had some 267MW of rooftop solar as at June 30, representing one in five households. AEMO said rooftop solar was accounting for 2.4 per cent of overall demand, and more than one-third of the PV systems were operating at the time of peak demand at any one time.

These graphs deliver a further illustration of their impact, as they illustrate what happened in the latest months of December and January, traditionally the period of hottest temperatures and highest demand. (If the graphs are not easy to read we suggest you click on them to see them better).

The ones immediately below show the average demand curves in South Australia over the last five years. The pink line shows 2012/13. As Sandiford points out, midday demand in SA this summer is down 15 per cent on where it was five years ago, even though night-time demand is up, confirming the impact of solar PV.

One last article from REN, this one looking at the big picture for renewables - 100 pct renewables: it may be closer than we think.

The stunning set of data, cost profiles and market analysis produced in the first few weeks of calendar 2013 have confirmed what many had long suspected – that the global energy markets are changing faster than anyone had thought possible.

The implications for the incumbent energy industry – be they generators, network operators or retailers – couldn’t be more significant. The business models that supported the ageing infrastructure are broken, and if they can’t adapt to the new environment, they may soon be out of business. The idea of a rapid change to a largely renewable energy grid no longer seems aspirational, it could be inevitable.

Consider what we have learned this week:

- The price of wind energy (and in some isolated cases solar PV), is already cheaper than coal and gas in Australia. This gap is likely to widen considerably in the coming decade.

- By the time new baseload capacity is required in 10 years time, other technologies, including solar thermal with storage, and concentrated solar PV, will also be cheaper than coal and gas. Marine energy and geothermal could be close to parity.

- But not only do we have “grid parity” at the utility level, we also have socket parity, which means that homeowners and businesses can lower their cost of electricity by installing solar panels on their roof.

- the growing impact of large scale renewables, the self consumption market driven by rooftop solar and battery storage, and the impact of energy efficiency schemes, is reshaping the profile of the energy market and the dynamics of the industry. Sometimes in the most dramatic way. Coal and gas fired generators are getting priced out of the market.

As investment bank UBS noted last week, we are facing a “solar revolution” in the energy industry, and another is on the way with battery storage. As we suggested last year, the change is so profound that existing business models appear broken. According to Macquarie Bank, the German energy model is already “kaput”.

As we have seen in Australia, the increase in renewables is pushing down wholesale electricity prices, forcing the closure or mothballing of 3,000MW of fossil fuel capacity. In Germany, the closure rate is so rapid that the electricity authority has had to step in to slow them down.

The more retailers and network operators seek to recoup their investment in the face of lower demand, the more customers will be tempted to look after their own energy needs. Even halting all subsidies for rooftop solar will not stop it, said Macquarie. “The ever-increasing (grid) prices for domestic and commercial customers as well as rapid solar cost declines have brought on the advent of grid parity for German roofs. Thus, solar installations could continue at a torrid pace,” it notes. The same applies for Australia. ... Coal-fired power stations will not get built, for reputational and economic reasons, and gas – the much touted transition fuel – may also not get a look in. “Costs are just falling so quickly and the cost of fossil fuel are so much higher than public perception,” said Kobad Bhavnagri, head of clean energy research for BNEF in Australia. ”We could leapfrog gas as transition fuel.”

Bhavnagri said that by 2020 the “world could look quite different”. The market operator and system will be more experienced and adept at handling intermittency. “The case for gas is not as strong as people assumed a few years ago.”

The upshot of that analysis is that the plants we will be building in the 2020s will be – because they are the cheapest options – large scale solar with storage and other dispatchable renewables. The economic case for existing fossil fuel generators will be further undermined.

This explains why the fossil fuel industry in Germany, and in Australia, have been trying to halt the expanse of renewables. The primary policy goal of generators and fossil fuel industry for the past decade or more has been one of delay – to push back the build up of renewables long enough to extract maximum value from their existing assets, and even to create space so they can build more assets. The extractive industries have the same, simple plan.

All the major Australian utilities made clear in their submissions to the Climate Change Commission that allowing the renewable energy target to stand – and more wind farms and large scale solar PV to be built – would reduce the profits of their generators, quite dramatically. Yet diluting that target would allow them to build more gas-fired generation.

This is also why the utilities have also argued against the Clean Energy Finance Corporation, because it is designed to help usher in those technologies such as solar thermal and ocean energy that will be competitive in a decade’s time. But they can’t be competitive if none are built, and installation and manufacturing costs are reduced.

Many European markets are now at critical junctures with high penetration of wind and solar. This includes Germany, Italy, Denmark, Spain and Portugal. Australia, should it maintain its current renewable energy target, will follow soon enough. Germany, while reducing subsidies, is still increasing its renewables targets – 40 per cent by 2020 and 80 per cent by 2030.

Its biggest challenge is to figure out how to redefine the market rules so that it can provide enough economic incentive to prevent too many closures of fossil fuel plants, and to encourage existing gas to stay open rather than coal. It needs these gas plants to assist with the transition.

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US Gas to Liquid Plant Planned By SASOL May Cost 10 Billion

The WSJ reports that South African coal to liquids company SASOL is looking to build a GTL (gas to liquids) plant in Louisiana, using the (at least currently) cheap supply of shale gas as feedstock - Gas-to-Liquid Site May Hit $10 Billion.

Sasol Ltd., a chemical company long known for squeezing motor fuel out of coal, is now turning its sights on the glut of natural gas in the U.S.

South Africa-based Sasol on Tuesday announced plans to build a plant in Louisiana, at a cost of up to $10 billion, that would convert natural gas into diesel fuel for trucks and other vehicles.

The companys board last week approved an 18-month feasibility study for the project, which would be constructed on land adjacent to Sasols existing chemical facility in Calcasieu Parish, La.

If given the final go-ahead, the plant would be the first in the U.S. to use "gas-to-liquids" technology. Once seen as futuristic, the technology has gained traction in recent years as discovery of gas supplies have outpaced that of oil.

"The initial numbers look positive," said Ernst Oberholster, Sasols managing director of new-business development, who stood alongside Louisiana Gov. Bobby Jindal at the companys Louisiana complex when the decision was announced.

What makes the U.S. an attractive location for such a project is the low level of natural-gas prices in the country. Benchmark futures have hovered between $3 and $6 per million British thermal units for two years, well below prices paid by consumers in Europe and Asia.

Sasol would buy the natural gas from suppliers using long-term contracts, convert the gas to liquid fuel and then sell that fuel to blenders, who wouldthen sell it for the open market.

The project is the latest to address what to do with a surplus of natural gas caused by the boom in drilling in shale-rock formations in places like Texas and Pennsylvania. Energy investor T. Boone Pickens and natural-gas producers such as Apache Corp. have promoted the use of natural gas as a road-transportation fuel, one that would be cleaner burning than oil-based alternatives. In addition, some companies have put forward plans to export gas out of the U.S. in cool-liquefied form.

Sasols idea is one of the most ambitious, because it would essentially put natural gas on par with higher-priced crude oil as a key raw material for transportation fuels. And diesel prices trickle down into the cost of consumer goodseverywhere because the fuel is mainly used in trucking. So far this year, retail diesel prices in the U.S. are up 16%, even as the economy grows more fragile.

Sasol officials estimate that a plant producing 96,000 barrels a day of diesel, and some jet fuel, would cost $10 billion to construct. They say they could opt for a smaller facility, however.

By converting natural gas into a liquid, the fuel could be used without retrofitting vehicles or creating new fueling infrastructure, an issue that would affect motorists using compressed natural gas as Apache and Mr. Pickens have advocated. The proposed site in Louisiana is close to Gulf Coast natural-gas fields and is crisscrossed by pipelines that could be easily linked to a new facility, Mr. Oberholster said.

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