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.That's quite an assertion, considering oil's 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. That's 2 TCF per year of additional natural gas demand in the transport sector, equivalent to 1 million barrels per day of diesel fuel.
I'd be more skeptical about that figure if I hadn't seen a presentation from Dr. Michael Gallagher of Westport Innovations at the Energy Information Administration's 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.
Tuesday, 30 July 2013
Thursday, 25 July 2013
Australia is no stranger to the idea of transnational or even international pipelines when it comes to solving the vexed issue of getting enough gas to its eastern seaboard, home to its biggest cities.Australia currently has two separate gas pipeline networks in the west and east of the country which supply markets of around 1 Bcf/day and 1.6 Bcf/d respectively. A much smaller, also separate, network in central Australia services the Northern Territory capital of Darwin. ...
The latest proposal for a transnational interconnection between Australia’s pipeline networks was initially aired in recent months by former Chief Minister of the Northern Territory Terry Mills, as part of his efforts to secure the future of Rio Tinto’s alumina refinery at Gove. In February, just before being ousted in a party room coup, Mills secured a deal under which Gove would be supplied with gas from Eni’s Blacktip offshore field, heralding a project which would include the construction of a A$500 million pipeline to the plant. ...
That call has now been taken up by Australia’s largest pipeline operator APA Group, manager of 14,120 km of pipeline infrastructure. One of APA’s assets is the 1,600 km Amadeus Basin to Darwin gas pipeline, which was the world’s third-longest when it was completed in 1986 at a cost of just A$380 million. ...
A raft of international oil and gas industry heavyweights have taken a foothold in northern and central Australia’s nascent shale sector over the past few years. Companies including Chevron, ConocoPhillips, Statoil, Total and BG Group have secured farm-in agreements and pledged investments of more than $1.55 billion in Australian shale, according to the US Energy Information Administration. The EIA has estimated that Australia has 437 Tcf of technically recoverable shale gas reserves, ranking the country sixth highest in the world.
Sunday, 21 July 2013
Amidst the constant discussion of plentiful domestic natural gas and its use as a transportation fuel, an unusual technological and philosophical debate has emerged. Those familiar with the industry know that until recently, fleet managers considering the conversion from gasoline or diesel to natural gas had basically two options: compressed natural gas (CNG) was the choice for any return-to-base, short mileage vehicles, and liquefied natural gas (LNG) was the option for long-haul on-highway Class 8 trucks, also known as tractor trailers or semis. The reasoning behind this was relatively straightforward, and more or less a product of a few issues inherent to gaseous rather than liquid fuel (energy density, tank storage capacity, re-fueling time). However, due to a variety of innovations, a paradigm shift may be under way.In comparing alternative fuels to gasoline or diesel, a major consideration is the relative energy density and associated cost, weight and size of on-board fuel storage. For natural gas, when compressed, its energy density is only about a quarter that of diesel, and when liquefied just 60% of the energy density of diesel. Therefore, either option requires greater fuel storage capacity to achieve a comparable range, which means more and/or larger tanks.
Compared to CNG, LNG contains 2.4 times more energy per diesel gallon equivalent (DGE). Moreover, since LNG, like diesel and gasoline, is a liquid, one could achieve comparable refueling speed, whereas the level of compression required to “fast-fill” with CNG is very high (~3,600 psi). As a result, for the long-haul trucking sector, the energy density and associated cost(s), weight and on-board storage capacity of LNG have long been viewed as the more attractive, viable option.
Relatively recent advances in tank storage capacity and “fast fill” refueling technology have allowed room for debate as to whether LNG really is the only natural gas option for the long-haul trucking industry. To best highlight the philosophical nature of this emerging debate, it may be best to look at two of the leading natural gas refueling infrastructure providers, Clean Energy Fuels (CLNE) and Trillium CNG (TEG subsidiary), each of which has taken an opposing view on this topic.
Clean Energy was the first mover in the industry and is now by far the largest provider of natural gas refueling infrastructure in the US. They are betting big on the fact that CNG is the choice for local urban fleets (refuse vehicles, delivery trucks, etc.) but that LNG is the option for long-haul tractor-trailers. Alternatively, Trillium CNG, along with their partners at AMP Americas, a Chicago-based investment firm, strongly believe that CNG should be the choice for all heavy-duty fleets, regardless of distance traveled or route. Without commenting on which approach is better, the following will help to explain each company’s thought process.
CNG and LNG are both proven forms of natural gas storage, with distinct advantages over diesel and gasoline when used as a transportation fuel. To produce CNG, natural gas is taken directly out of the United States' expansive network of natural gas pipelines, whereas LNG must be cryogenically liquefied to -260 degrees F (to become a liquid) and often must travel via ground transportation (tanker truck) to stations across the US. With pipeline access, LNG can alternately be produced from the gas grid through MMLS (movable modular liquefaction system) units. On-site, CNG is compressed immediately and enters a truck in a process that is almost identical to traditional fueling practices, from the driver’s perspective. On the other hand, LNG requires drivers to wear a mask and gloves to protect themselves against cryogenic burns.
For the Class 8 truck sector, Trillium/AMP have made the decision to build CNG stations because, in their words, “it is a cheap, simple and safe way to transport and store natural gas.” They have also found that the additional simplicity of CNG over LNG makes it an easier product to maintain, as well as a less expensive product to produce. For example, according to their general pricing model and marketing materials, on average, “end users of CNG gain a $.48 advantage over LNG, for a product that works equally well, has less associated hazards and a greater built-in infrastructure across the US.”
Alternatively, Clean Energy has invested heavily in LNG infrastructure, including two liquefaction facilities, to supply their network of 150 existing refueling stations and more in the works that they refer to as America’s Natural Gas Highway. While the production and transport of LNG require greater technical expertise and significantly more capital than for CNG, LNG cost savings are realized on refueling infrastructure/operation. This is primarily a result of the high electricity demand/cost required to achieve the compression necessary for a “fast-fill” CNG station. There is also greater flexibility in where a station can be located (no need for natural gas pipeline access) and in future expansion of existing stations.
Monday, 11 March 2013
General Electric Co. (GE) and Caterpillar Inc. (CAT), the world’s largest locomotive makers, are rushing to develop natural gas-powered models in a potential shift from diesel’s six decades as the fuel of choice for railroads.Three of the biggest U.S. rail carriers -- Berkshire Hathaway Inc. (BRK/A)’s Burlington Northern Santa Fe LLC, Union Pacific Corp. (UNP) and Norfolk Southern (NSC) Corp. -- are working with manufacturers on using gas as an alternative power source for freight trains. CSX Corp. is studying the technology.
Tapping the nation’s glut of gas as a transportation power source opens a new front in the global competition between GE and Caterpillar. Liquefied natural gas holds the promise of cutting railroads’ costs, curbing greenhouse-gas emissions and ushering in the industry’s biggest change in fuel technology since diesel displaced steam in the 1950s. “We are entering a new era where natural gas will be a major fuel,” Lorenzo Simonelli, chief executive officer of GE’s transportation unit, said in an interview. “If you believe the price advantage over diesel is going to stay here for the next 10 to 15 years, then LNG is a revolutionary fuel.” ...
“In the last 12 months, there’s been a tremendous increase in activity around LNG within North America,” Simonelli said. “In the not-too-distant future, you’ll see some announcements being made about how we can apply LNG into a locomotive.”
Fuel trails only employee compensation among American railroads’ expenses, spurring a search for cheaper alternatives. Union Pacific, the largest U.S. railroad by revenue, burned 1.09 billion gallons of fuel last year at an average price of $3.22 a gallon, according to SEC filings.
That’s significantly costlier than liquefied natural gas. It costs truckers $2.99 to buy LNG with the same energy content as a gallon of diesel at Clean Energy Fuels Corp. (CLNE)’s Port of Long Beach facility, the world’s largest LNG fueling station, said Gary Foster, the company’s spokesman. That’s before volume discounts that can reduce the price by as much as 30 percent, he said, meaning some customers pay as little as $2.10. Railroads are turning to locomotive makers, including Fairfield, Connecticut-based GE and Peoria, Illinois-based Caterpillar, for engines that can help them take advantage of those savings.
Wednesday, 26 September 2012
Britain's natural gas imports from outside the North Sea will surpass domestic production by 2015 and add more than $11 billion to import costs as domestic supplies dwindle and Norway increasingly struggles to fill the gap, Reuters research shows.Estimates show that Britain's own gas supplies will fall from around 43 billion cubic metres (bcm) per year today to around 16 bcm in 2030 if they continue their average annual 5 percent decline since peaking in 2000, while demand is set to hold steady between 85 and 95 bcm.
Britain was a net exporter of gas until 2004, but a steady decline in output over the last few years has made it more reliant on imports, which have so far mostly come from Norway and, increasingly, Qatar.
Thursday, 13 September 2012
The discovery along Africa's east coast of the world's biggest gas finds in a decade threatens to undo investment plans on the other side of the Indian Ocean. Royal Dutch Shell, BG Group of the UK and France's Total may scale back projects to build liquefied natural gas export plants in Australia and switch to Tanzania and Mozambique, where the new prospects lie and will cost about half as much, according to Jefferies International.The LNG boom in Australia, where $180 billion of planned investment was set to make gas the country's fastest-growing export over the next five years, risks losing strength as labor and material shortages force up building costs. As energy companies consider the next $100 billion of projects, a switch to East Africa would hold back Australia's market share in China and India, where energy consumption is forecast to rise more than 60 percent by 2030.
“Because of the volume that's been discovered in East Africa, the economics look to be able to challenge Australian LNG projects, given the cost inflation they have experienced,” said Peter Hutton, an RBC Capital Markets analyst in London. “All companies will have that on their radar.”
The Asian market for LNG, gas that's chilled to a liquid for shipment by tanker, accounts for about two-thirds of global demand and will grow by 6 percent a year this decade, according to Sanford C. Bernstein & Co. Among six Australian projects scheduled to reach investment decisions in 2013, few will be approved because of climbing costs, Neil Beveridge, a Hong Kong- based analyst at Bernstein, said in a report this month.
Monday, 27 August 2012
The proponents of Australia's massive liquefied natural gas boom are doing the hard yards.Seven enormous projects worth more than $US172 billion ($165 billion) combined are under construction all at once. Already this year two operators - BG Group and Santos - have announced cost blowouts, of $US5 billion and $US2.5 billion, at their respective coal seam gas projects - Queensland Curtis LNG and Gladstone LNG.
Santos's efforts to window-dress the announcement, as a pull-forward of upstream capital expenditure scheduled for post-2015, fell flat.
In the last fortnight, in quarterly earnings calls, Chevron admitted it faced rising costs on its $US43 billion Gorgon project on Barrow Island, and its budget and schedule were under review, and Shell flagged it could delay Australian LNG projects worth $US17 billion.
The head of global gas for energy analyst Wood Mackenzie, the Edinburgh-based Noel Tomnay, says Australia will be ''one big bad news story for the next couple of years, with delays to projects and cost over-runs. It seems inevitable.''
Australia's strong dollar, rising labour and compliance costs are being blamed for the pressures, and competition from lower-cost countries is causing investors to think twice about Australian LNG.
Tomnay says this year's cost blowouts are unlikely to be the last announcements. ''With that in mind, it would be a brave board that went out to investors right now with an investment decision on another Australian LNG project,'' he says. ''Would the market reward another announcement? Probably not. It would be more pragmatic to announce a breather. 'Annual capital expenditure on Australian LNG is going from $US10 billion to $US40 billion, which is highly inflationary. There has to be a hiatus.''
Saturday, 25 August 2012
Oil and gas producer Santos says Australia's first commercial shale gas well is ready to go into production, helping to boost supply and keep prices stable in eastern Australia.Santos said its Moomba-191 well in the Cooper Basin was now producing dry gas after the company reported an increase in underlying first half profit and maintained its full-year production guidance on Friday. ...
Chief executive David Knox said shale gas flows from the Moomba well were a significant milestone in the company's program to unlock the vast unconventional gas potential of the Cooper Basin that straddles the South Australian and Queensland border.
"The shale well result has been an outstanding result for us and potentially for eastern Australia for the very long-term future," Mr Knox told analysts on Friday. ...
"The share price is up because of the surprisingly good flow rate that they're getting at their Moomba 191 shale gas well," Mr Wood said. "You can start to talk about some very large numbers on the back of that, but it's very early days. Certainly this flow rate was better than we were expecting."
Monday, 20 August 2012
Wholesale electricity prices will remain weak for the next couple of years, but domestic gas prices are expected to surge in the future, pushing up electricity bills, as Queensland's export gas projects come on stream.Speaking at a conference earlier today, TruEnergy managing director Richard McIndoe made the forecast, although he expects that eventually the development of shale gas reserves will help contain electricity prices towards the end of the decade.
Weak wholesale prices are a mixed blessing for the large generators and retailers such as AGL, Origin Energy and TruEnergy, since it depresses the profits of their generation units, although it helps to give their retail arms greater flexibility to discount prices to maintain margins and protect their competitive position in the retail market. ...
Over the next three to five years, the launch of export gas projects in Queensland will see domestic gas prices rise, which will push up wholesale electricity prices, he said and it will ‘‘drive the bidding practices of coal-fired generators’’.
Additionally, strong Asian demand for coal, especially from India in the coming years, will keep coal prices high ‘‘and set wholesale [electricity] prices higher’’, he said. These pressures will be especially notable as low-priced coal contracts in NSW roll-off, he said. But further out ‘‘solar and shale gas may bring prices down’’, he said.
Earlier this week, the Australian Energy Markets Operator slashed forecasts for new power generation capacity.
In recent trading, the wholesale electricity price has been holding at around $30 a megawatt hour, and has changed little over the past 15 years.
Thursday, 14 June 2012
It’s on for young and old between the gas supply industry and the major gas users, with the latter continuously ratcheting up the heat.In fact, it is a three-cornered contest now because both the federal government and the Coalition have signalled that they don’t want to intervene to reserve gas supplies for domestic use while the users are enlisting heavy hitters, such as Dow Chemical’s main man, Andrew Liveris, to tell them they are wrong.
In a new fusillade, the Perth-based DomGas Alliance, which started life as a Western Australian lobby group but is now chasing its concerns nationwide, has launched a report claiming that Australia is the only country in the world allowing “international oil companies to access and export natural gas without prioritising local supply.”
It sharpens its thrust by adding that Australia is also the only gas exporting country to experience shortages and sharply rising prices.
In a national economic environment where, no matter how often Wayne Swan exhorts us all to be happy, there are a large number of people unconvinced that they are sharing in the creation of new wealth and where manufacturers are obviously in strife, DomGas is pressing hard to get political knees to jerk at the state and federal level.
The cost-of-living button is always a good one to push in these disputes and DomGas has given it a good nudge with a claim that we are confronted with a rise of $5.3 billion in mainland state annual gas bills. (Why did they ignore poor Tassie, I wonder?)
DomGas bases this assertion on multiplying current gas demand by businesses and households with projected price rises – of $3 per gigajoule in the east and $5.50 in Western Australia.
The debate about higher gas costs (and higher electricity prices flowing from the use of gas by power stations) is not new in the West. It has been ongoing for several years.
However, driving this tale in to the media on the east coast is calculated to really pour on the pressure for the pollies, with a federal election looming and the big three states (in terms of consumers and consumption) all now in Coalition hands and manifestly jumpy about energy bills.
Monday, 5 March 2012
A couple of years ago I wrote a piece (Natural gas, the green choice?) for The Oil Drum looking at the climate change implications of using gas rather than coal. Burning gas to produce electricity produces only around 40% the CO2 emissions of burning coal. However, since methane (CH4) is itself a potent greenhouse gas, its release to the atmosphere without being burnt can quickly compensate for this CO2 advantage against coal. I included this chart to illustrate the point:
On the left, CO2 emissions per kWh for coal and natural gas. On the right, the global warming potential of leaked CH4 expressed as CO2
The key take-away was that if the natural gas leak rate is 3%, the global warming potential of a kilowatt-hour of electricity from gas is equivalent to coal. The details behind the chart are in the original article.
This week the journal Nature has an article (Air sampling reveals high emissions from gas field) presenting measurements from a gas field and suggesting that “Methane leaks during production may offset climate benefits of natural gas.”Led by researchers at the National Oceanic and Atmospheric Administration (NOAA) and the University of Colorado, Boulder, the study estimates that natural-gas producers in an area known as the Denver-Julesburg Basin are losing about 4% of their gas to the atmosphere — not including additional losses in the pipeline and distribution system. ...
Gas is often described as the ‘cleaner’ choice, as a transitional energy source between coal and low-carbon renewables. Gas does burn without emitting the oxides of sulphur (SOx) and nitrogen (NOx), traces of mercury, selenium and arsenic, as well as the particulates associated with coal and doesn’t leave the non-combustible slag. Despite this it is increasingly unclear that gas has a significantly lower climate impact and the fracking process itself is not as clean as conventional gas extraction.
This figure of 4%, their range is 2.3–7.7% loss, with a best guess of 4%, is well inside the danger zone suggesting gas has similar, if not higher, climate impact as coal.
Thursday, 8 December 2011
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 world's LNG—up from less than a tenth today—making it one of the world's 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 dollar's 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 Apache's Kitimat project in western Canada.
For Australia's 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 country's agricultural production. That shouldn't 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 world's 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 - there's 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, Shell's 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.
Sunday, 4 December 2011
Woodside Petroleum's plans to build the $30 billion-plus Browse liquefied natural gas plant near Broome appear to have become less appealing against the alternative of piping the gas 1000km for processing at the North West Shelf plant near Karratha when reserves there run low.
After recent industry developments here and in the US, analysts now put a greater probability on the Browse project's offshore gas fields being turned into LNG at the North West Shelf and say this would give the project a greater value. ...
Credit Suisse analyst Sandra McCullagh said she was now using a North West Shelf option as a base-case scenario. "Woodside maintains a preference for James Price Point, but we expect that competition for skilled labour and recent LNG sales from the US at prices linked to Henry Hub (domestic US gas prices) could see a shift in the company," Ms McCullagh said.
On top of this, development cost pressure, competition for scarce labour from eight other regional LNG plants under construction, no certain gas to extend the life of the Woodside-operated North West Shelf and LNG buyers' preference for expanding existing plants rather than building new ones make a James Price Point plant less likely, according to Credit Suisse.
Credit Suisse has boosted its expected Browse development cost to $US36bn, compared to a development cost of $US26bn to use the gas to backfill the North West Shelf. …
One of the game changers in Credit Suisse's analysis has been a plan to export US shale gas.
Even at US domestic gas prices of $US7 a gigajoule, which is double current prices, it would be profitable to export to Asia at current Asian spot LNG prices.
"Less than 12 months ago, most commentators didn't see much of a threat from North America, but within the space of one month, 7 million tonnes of LNG a year has been sold from Louisiana, earmarked for Asian and European markets," Ms McCullagh said. "We expect unsanctioned Australian LNG projects will struggle to stack up against North American imports."
Thursday, 1 December 2011
The WA Government says there is still "a way to go" before the state will have enough electricity being produced to meet future demand, despite the signing of two major supply contracts.
Electricity producer Verve Energy and retailer Synergy have both signed gas supply agreements with the $43 billion Gorgon Project to take the place of their existing contracts when they lapse within the next four years. The deals are for a combined 125 terajoules of domestic gas per day and will run for 20 years.
Verve's plants supply more than 60 per cent of WA's electricity and rely on a combination of Woodside's North West Shelf gas as well as coal to reach their production targets and keep the lights on.
With Verve's gas supply deal with the Woodside-operated North West Shelf expected to lapse in 2016, the Gorgon deal would cover half of the energy producer's gas needs after the end of its existing contracts, a Verve spokesman said. ... However Verve is still shopping around for a supplier for the other half of its gas needs.
Monday, 7 November 2011
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.
Santos's 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 Australia's wealth and make it one of the world's 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 coast's most expensive gas deal.
AGL Energy has snared the east coast's most expensive domestic gas sales contract in what is thought to be a 50 per cent price jump forced by the expected demand from Queensland's 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 Xstrata's 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.
Monday, 10 October 2011
Nevertheless, some investment banks seem keen to push the idea, for whatever reason (on the plus side it would keep gas cheap on the east coast in the coming years) - I always love when the sources have to remain anonymous, in this case for "compliance reasons" ! - China's LNG demand questioned.
As Australia prepares itself for the economic bonanza that will stem from the construction of LNG projects in Western Australia and Queensland, those keeping a close eye on how China is meeting its energy needs are raising their eyebrows at the Australian plans.
More than $200 billion in LNG projects is planned or already in construction, potentially leading Australia to challenge Qatar for the title of the world's biggest producer. Removed from the hysteria surrounding Australia's LNG construction frenzy, the Asia-based analysts who scrutinise China's energy needs are questioning whether China will be the increasingly LNG-hungry nation the Australian LNG proponents need it to be.
That's not to say China's gas demand isn't growing dramatically. The China Gas Association is tipping a fourfold increase in Chinese gas consumption by 2020, while state-owned energy giant PetroChina is tipping a trebling in demand over the same timeframe. The central government has mandated for China to increase its gas consumption over the coming years, in part on environmental grounds. Gas currently accounts for around 5 per cent of China's energy mix, compared with an average of around 20 per cent in other developed nations.
The problem for Australia, however, is that LNG is but one of a number of potential sources for gas. And when it comes to competing with those other sources, LNG is set to be the most expensive.
While China has been actively lining up sources of Australian LNG, including deals with the Chevron-led Gorgon and Wheatstone projects and a number of coal-seam gas-fed LNG developments in Queensland, it has also been securing a wide number of alternative supplies.
Much of the country's gas is already piped in from the Central Asian nation of Turkmenistan and there is talk of a new pipeline that could bring much more. China and Russia have been in discussions for several years over the prospect of piping gas in from Russia and if and when the deal is done, it will be at a price below that of LNG.
The stunning growth in gas reserves in North America following breakthroughs in shale gas and coal-seam gas technology has raised the prospect of Canada and the US exporting cheap LNG.
And the real wildcard is China's own domestic gas industry, which is looking to tap the same technology and techniques that have turned North American gas markets on their heads. Studies suggest that China could host as much, if not more, gas than North America and this could have a major impact on China's appetite for Australian LNG. ...
Another Hong Kong-based analyst, who cannot be named for compliance reasons, is also scratching his head over the demand picture facing Australian LNG projects. "Should they be worried? Absolutely," he says. "But not only because of the potential for shale in China but also because of gas out of Russia and pipeline gas out of Central Asia and also lower-cost potential LNG out of Canada and the US. All of it can be brought in at far below the rising cost of LNG out of Australia."
Tuesday, 4 October 2011
North Sea gas production has slumped by 25% in the second quarter of the year, an alarming increase in the rate of decline that will cut tax revenues and could put more pressure on government to agree controversial shale gas developments.
Figures from the Department of Energy and Climate Change (DECC) also show a 36% rise in coal imports, but a leap from 6.3% to 9.6% for the amount of electricity generated by wind and other renewables.
The department records that the output of oil and associated gas liquids fell by 16% in the three months to the end of June, compared with a year earlier – the biggest decline since records began 16 years ago.
This left Britain importing 3.6m tonnes of oil in the second quarter, compared with 2.8m tonnes in the same period of 2010, even though total oil demand fell by 1.7%.
