You have to think natural gas producers are doing a pretty good duck imitation these days — calm on the surface, but madly paddling below the water to stay afloat.

Such is the story in a world where natural gas prices in Alberta are struggling to stay above $2 per gigajoule.

Things are no better in the United States, where on Tuesday this week natural gas prices fell by almost eight per cent, marking the largest one day drop in about 18 months and closing at $2.44 per thousand cubic feet US.

What’s going on is a classic mismatch between supply and demand; producers are hurting while those using natural gas as an input are cashing in.

But, in a world where costs remain sticky on the downside, today’s prices mean virtually every natural gas play in North America is uneconomical.

What’s puzzling is that there has yet to be a significant supply response even though ARC Financial’s Peter Tertzakian says the data shows production in the United States has been flat for the past four months — the longest such stretch since 2009.

Yes, Chesapeake Energy and ConocoPhillips recently announced they are shutting in production, but ExxonMobil said Tuesday it was status quo at its shop. Making matters more complicated is the fact players in the U.S. continue to be faced with the “drill to retain” situation whereby they will lose the leases if they stop drilling. Those are the controllable variables.

The uncontrollable one remains the weather, which has proven to be somewhat unreliable in alleviating the record supply levels.

Who’s happy? Anyone using natural gas as an input. That means everyone from consumers, industrial users and power producers.

One has to think, too, that the oil sands players who have to buy production to run their operations are quietly cheering the low prices because all this is happening at a time when other costs related to labour or engineering are rising.

“How can it get better than $95 (US) for oil and $2 for natural gas?” said Martin King, commodities analyst for FirstEnergy Capital Corp.

And if those who follow the industry are right, the low prices are here to stay until there is a drop in production, a significant demand response, meaningful export capacity is built and the weather does what it is meant to do: be cold in the winter and hot in the summer.

In other words, absent significant policy shifts aimed at boosting demand, prices are not expected to recover in the near future. King said that had the EPA’s Cross State Air Pollution Rule passed in the U.S., it would have had a positive impact on prices; it was stayed by the courts on Dec. 30.

Thus the reality remains that prices could hit levels not seen for the past 12 or 14 years. Given that the opportunities to hedge at reasonable prices is also evaporating, it’s clearly not a good time to be levered to natural gas, especially if it is dry gas and even if you happen to be a low-cost producer. And while market watchers might be interested in seeing a supply response in the form of production being shut-in, it’s not so easy. There are third-party processing contracts and pipeline commitments to honour; and, as long as the pipelines are taking the gas, no one is going to be pressing a panic button.

There is no doubt the consequences of the low pricing environment will be felt in 2012 as companies look at ways to manage through reduced cash flows and limited access to capital in the public markets.

One potential outcome from all this could be the temptation to pull “an Encana” and migrate the basin toward an increasing focus on oil production. While this makes some sense in the current context, the basin — as would be the case with most companies — should have a diversified production base. This is particularly true if the export option does move ahead, and production is required to fill it. But amid the gloom and doom, there are a few positive developments.

The boom in shale gas production is fuelling a renaissance in places like Youngstown, Ohio, where new factories are being built to supply the steel tubes used in the hydraulic fracturing process. Some reports suggest it could mean as many as 200,000 jobs in the next three years.

At current prices, natural gas is a cheaper fuel than coal when it comes to power generation. But there is a ceiling in terms of how much power can be switched from coal to natural gas. The low price also means the North American petrochemical business has a renewed competitive advantage. One such plant in Mississippi, which had been closed since 2005, has recently opened its doors and Methanex Corp. reopened a plant in Medicine Hat last year.

Ed Morse, global head of commodities research for Citigroup, recently pointed out that after Qatar, North America is the second most competitive market for natural gas. All this spells opportunity from the perspective of economic diversification, though as Tertzakian warns, it won’t last forever.

“We’re still in a mismatched world where it’s tough for suppliers, but where consumers think this low price environment will last forever,” he said.

It won’t last forever, but it will last a while because adjustments to the supply side take time to work through the system. But with every day that natural gas prices trade below the $2 mark, there is less incentive to produce natural gas. And eventually it will have a meaningful impact on the mismatch currently manifesting itself in low natural gas prices.

Meanwhile, industries that had abandoned any notion of ever being competitive in North America because natural gas prices were too high are in a position to help diversify the economy and create jobs. It can’t be all bad.

GENEVA – The International Energy Agency (IEA) is preparing recommendations for countries to regulate the controversial shale gas industry, to be published in its global energy report in the autumn.

“If you’re going to have golden gas, you have to have golden rules,” IEA Deputy Executive Director Richard Jones said at a conference in Geneva on Monday, referring to a 2011 IEA report entitled, “Are we entering a golden age of gas?”

The development of shale gas extraction is a potential game-changer in world energy markets, offering ample supplies in markets that could otherwise tighten in coming years.

But the hydraulic fracturing, or fracking, technology used to extract shale gas requires large amounts of water and chemicals, and concerns about contamination of water supplies and other potential environmental problems have led some governments to ban its use or put moratoriums in place.

“We feel that a number of countries inside and outside the IEA are interested in improving these technologies, and this is something where we’re working with them to collectively see what rules make sense. But we’re not talking about trying to negotiate any kind of a contract, at least not at this stage,” Jones said.

Instead, the IEA will look at responsible procedures to minimise the environmental damage of the technology in regions where shale gas exploration has potential and then make regulatory recommendations to member states and countries with which the IEA has cooperation agreements.

“The United States is a prominent IEA member country that is pursuing unconventional gas and is already grappling with these issues. Some other countries within the IEA … and also non-member countries with which we have cooperative relations such as China are looking at this question,” Jones said.

Below is an alphabetical list of key countries with shale gas reserves and their governments’ legal positions on the technology.

ARGENTINA

At around 774 trillion cubic feet (tcf) of estimated recoverable reserves, the South American country is likely to have the world’s third-biggest reserves in unconventional gas behind China and the United States, according to the U.S. Energy Information Administration (EIA).

The government has launched its Gas Plus programme, which promises to give a price guarantee for newly discovered gas.

There are about 50 projects approved under the scheme, a large portion of which correspond to non-conventional gas fields.

AUSTRALIA

Australia has 396 tcf of technically recoverable shale gas resources, according to the EIA, equivalent to about 46 percent of U.S. reserves.

Widespread fears about the impact of hydraulic fracturing on water supplies in Australia have resulted in calls for a moratorium on the practice in several states. A temporary moratorium is currently in place in eastern New South Wales State.

Australia’s shale gas industry has grown in the past few years but is still far from becoming a major gas producer as high costs and a lack of infrastructure to access the far-flung assets remain hurdles to the industry.

Although there has been speculation that shale gas may rival Australia’s booming coal seam gas industry, experts say significant production is probably a decade away.

BRITAIN

The UK government suspended domestic shale drilling activity last year after exploration work triggered small earthquakes near Blackpool in northwest England in May.

The government is reviewing a report into the incident commissioned by Cuadrilla Resources, the company responsible for the work, and expects to make a decision soon, a spokesman for the Department of Energy and Climate Change (DECC) said. Applicants for a fracking licence need to obtain environmental, local authority, government and safety authority approvals and have to disclose the contents of fracking fluids used to the Health and Safety Executive.

Britain has some shale gas reserves in northwest England, but reserve estimates have so far to be specified and audited.

BULGARIA & ROMANIA

The Bulgarian government in January banned shale oil and gas exploration through hydraulic fracturing due to environmental concerns following widespread protests.

The government cancelled a shale gas exploration permit to Chevron at Novi Pazar field for which estimates showed reserves of 1 to 3.5 tcf.

Romania’s shale gas industry is still at an early stage, and the country currently has no specific legislation in place and instead uses the same laws that apply to its conventional gas sector.

CHINA

China in January approved shale gas as an independent mining resource, a legal status that may allow more Chinese firms to develop the unconventional energy source.

Foreign companies would not be able to participate in the tenders but could partner with the winning Chinese firms.

The world’s top energy user could hold shale gas reserves around 1,275 tcf, according to the EIA, exceeding those of the United States (862 tcf).

FRANCE

The French government banned the use of hydraulic fracturing last year in the face of concerns about potential environmental damage.

As a result, it has canceled several shale exploration licenses with major energy companies, such as Total SA.

The EIA says France has shale gas reserves of 180 tcf.

POLAND

Poland does not have any law relating specifically to shale gas, but it has launched work on a new tax on shale gas and other hydrocarbons, expected to be ready in the first half of 2012.

The country is pursuing unconventional gas to boost its energy security.

Its estimated shale reserves of 187 tcf are Europe’s biggest of known unconventional gas and could feed domestic consumption for some 300 years.

The government has awarded over 100 concessions to mainly foreign companies.

UNITED STATES

Shale gas drilling in the United States is mostly regulated on a state-by-state basis.

The Environmental Protection Agency is currently studying fracking and its impact on drinking water, with a preliminary report expected this year. The final analysis will be released in 2014.

The Interior Department also is updating rules for fracking on public lands.

A few states do not allow fracking. New Jersey lawmakers recently agreed to a one-year ban on the practice, and New York has a moratorium in place.

Other states have implemented regulations to keep a closer eye on drilling until federal regulators weigh in. Many states, including Texas and Colorado, require at least some disclosure of the chemicals used in fracking.

© Thomson Reuters 2011

© Thomson Reuters 2011

“Much of the growth in natural gas production is a result of the application of recent technological advances and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural gas,’ said the department in its 2012 forecast.

Shale gas production increases from 5.0 trillion cubic feet in 2010, or 23% of total U.S. dry gas production, to 13.6-trillion cubic feet in 2035, or 49% of total U.S. dry gas production.

In fact the current rise in production could mean that the U.S. becomes a net exporter of liquefied natural gas (LNG) in 2016, a net pipeline exporter in 2025, and an overall net exporter of natural gas in 2021.

The outlook reflects increased use of LNG in markets outside of North America, strong domestic natural gas production, reduced pipeline imports and increased pipeline exports, and relatively low natural gas prices in the United States compared to other global markets.

The U.S. will also see its crude oil production rise, reversing a decline that began in 1986. U.S. crude oil

production has risen from 5.1 million barrels per day in 2007 to 5.5 million barrels per day in 2010.

“Over the next 10 years, continued development of tight oil, in combination with the ongoing development of offshore resources in the Gulf of Mexico, pushes domestic crude oil production in the Reference case to 6.7 million barrels per day in 2020, a level not seen since 1994,” said the Department in the report.

Even with a projected decline after 2020, U.S. crude oil production remains above 6.1 million barrels per day through 2035.

Natural gas’s worst start to a year since 2001 has the most accurate forecasters predicting further price declines as surging U.S. shale production threatens to overwhelm the nation’s storage facilities.

Prices may drop below $2 per million British thermal units for the first time since 2002 amid the prospect of stockpiles exceeding storage capacity in October, according to Bank of America Corp., Barclays Capital and Prestige Economics LLC. Inventories will probably end March at 2.15 trillion cubic feet, an all-time high for that time of year, Bank of America says.

“If we exit the winter with such high levels of inventories, there’s a real risk of gas prices coming down very sharply in the fall,” said Francisco Blanch, the head of commodities research at Bank of America in New York and the most accurate forecaster of U.S. gas ranked by Bloomberg in the eight quarters ended Dec. 31. “Gas production has to come down,” he said in a phone interview Jan. 13.

Prices have fallen as profits from oil and gas liquids, such as ethane and butane, have subsidized natural-gas output from shale. Ethane at the Mont Belvieu hub in Texas rose 30 percent last year, while natural gas futures tumbled 32 percent. Gas production grew by a record 4.5 billion cubic feet a day in 2011, the Energy Department said in a Jan. 10 report, while demand lagged behind at 920 million.

Natural gas for February delivery on the New York Mercantile Exchange has slumped 23 percent in 2012 as warmer- than-average weather sapped demand. Prices fell 24 percent at the start of 2001.

Gas rose 0.4 percent to $2.331 per million Btu as of 8:02 a.m. on the Nymex today, trimming a 6.1 percent drop yesterday that drove it to the lowest level in 10 years.

Warmer Weather

Temperatures averaged 36.9 degrees Fahrenheit (2.7 degrees Celsius) in New York City through Jan. 18, 4.4 degrees above normal, according to the National Weather Service. Last month’s average temperature in the U.S. Northeast was 34.1 degrees Fahrenheit, or 5.3 degrees above normal, making it the sixth- warmest December since 1885, according to the National Climatic Data Center in Asheville, North Carolina.

Improved technology has allowed companies to boost shale- gas yields while reducing costs, said Brison Bickerton, a managing director at Freepoint Commodities LLC, a trading company in Greenwich, Connecticut. Producers use hydraulic fracturing, which involves pumping water, sand and chemicals underground at high pressure to extract the fuel from the rock.

Precision Drilling

Companies are also drilling longer wells with monitoring equipment that allows them to pinpoint where to fracture the rock, Bickerton said in an interview on Jan. 13. They can return to existing drilling sites later and place multiple wells in the same area, he said.

“It is fair to say the market has underestimated the extent of the technology shock in the production of shale gas,” he said. “It looks like we’re going to see inexpensive gas for a long, long time.”

Producers may not reduce output by a “meaningful” amount this year even if prices slip below $2 per million Btu, according to Barclays Capital. Companies will probably cut plans for drilling rather than shut wells already in operation, said Michael Zenker, a New York-based analyst at the bank.

“We don’t believe there is a short-term floor for prices,” Zenker, ranked fifth among gas-price forecasters by Bloomberg, said in a telephone interview yesterday.

Turning Bearish

Hedge funds turned bearish on U.S. natural gas last week for the first time in eight weeks as a surplus and warmer-than- normal weather pushed the price of the heating fuel to the lowest level in more than two years, according to the Commodity Futures Trading Commission. The funds and other large speculators switched from bets that futures will rise to a net “short” position of 10,344 futures equivalents in the week ended Jan. 10, the CFTC’s Commitments of Traders report on Jan. 13 showed.

Goldman Sachs Group Inc., Deutsche Bank AG and Bank of America have cut their 2012 natural-gas price forecasts this year, citing growing output and storage. Bank of America reduced its estimate by $1 to $3.30 per million Btu Jan. 10. Production of the fuel will rise 2.2 percent to a record 67.34 billion cubic feet per day in 2012, according to the Energy Department.

Marcellus Shale wells owned by Range Resources Corp. and Cabot Oil & Gas Corp. can generate a 15 percent after-tax return on investment with gas futures below $2.50 per million Btu, Anish Patel, an analyst at ISI Group Inc. in New York, said in a note to clients Jan. 17. The Marcellus covers northeastern states including Pennsylvania and New York.

Lower Costs

“Producers are pumping gas at one-fifth or one-tenth of the cost of the first well they drilled a few years ago,” Bickerton said. “It’s hard to see a rally at any point in 2012.”

Rising output has contributed to surplus inventories over the five-year average, Jason Schenker, the president of Prestige Economics, an energy-advisory company in Austin, Texas, said by phone on Jan. 18. Schenker was third among gas-price forecasters ranked by Bloomberg for the eight quarters ended Dec. 31.

“It would not surprise me to see gas prices below $2,” Schenker said. “If supply continues to outstrip demand in a massive way throughout the year, it’s going to be hard to find a bottom for the market.”

Stockpiles totaled 3.29 trillion cubic feet as of Jan. 13, 21 percent above the five-year average for the week and 20 percent above year-earlier level, the Energy Department said yesterday. The 21 percent surplus to the five-year average was the largest since June 19, 2009.

Rising Supply

Inventories may rise to 4.11 trillion cubic feet in October, 7 billion above the Energy Department’s estimate for the amount that can be held in U.S. storage, Bank of America’s Blanch said.

Demonstrated peak working gas capacity in the lower 48 states was 4.103 trillion as of April 2011, according to the Energy Department. The measure is the sum of the highest inventory level in each storage facility over the previous five years, excluding supplies needed to maintain adequate pressure.

“If we actually hit system-wide storage constraints, gas prices could plummet below $2,” Teri Viswanath, an analyst at BNP Paribas SA in Houston, said in a phone interview Jan. 12. “Energy companies will have to cut their production budgets by 10 to 15 percent across the board before gas prices start to stabilize.”

Reduced Spending

Talisman Energy Inc., a Calgary-based energy producer that has operations in the U.S., North Sea and Indonesia, will cut spending on drilling this year by $500 million because of the decline in North American prices.

Spending will be “slightly over” $4 billion, the company said Jan. 10 in a statement. Output will rise 5 percent, less than the 9 percent increase last year, as Talisman targets oil and gas liquids more valuable than gas.

The number of rigs drilling for natural gas in the U.S. has tumbled 12 percent from a year ago to 791, according to data from Baker Hughes Inc. in Houston. Producers must shut almost 100 additional rigs to bring gas supply and demand back into balance, Cameron Horwitz, an analyst at Canaccord Genuity Inc. in Houston, said in a Jan. 17 note to clients.

Bloomberg News

Natural gas is projected to be the fastest growing fossil fuel globally to 2030 at an average annual rate of 2.1%, BP said on Wednesday.

BP said non-OECD countries would account for 80 percent of the global rise in gas consumption, with growth averaging 2.9 percent a year to 2030.

The report also said that growth would be the fastest in the liquefied natural gas (LNG) sector.

“Global LNG supply is projected to grow 4.5% per annum to 2030, more than twice as fast as total global gas production and faster than inter-regional pipeline trade (3.0%),” the report said.

BP added that LNG would contribute 25% of global supply growth between 2010-2030, compared with 19% for 1990-2010.

The report said that Chinese gas use, at an annual growth rate of 7.6%, would reach 46 billion cubic feet (bcf) per day in 2030, comparable to that of the European Union today.

As for sectors, BP said gas use would grow fastest in the power sector at 2.4% a year.

Gas consumption in the industrial sector would grow by 2.1%, according to the report.

WORLD GAS RESERVES OF 59 YEARS

The world currently has enough gas reserves to cover 59 years of production at current levels, down from a forecast of 63 years in last year’s report, BP said.

“The world had 6,609 tcf of proved gas reserves in 2010, sufficient for 59 years of production at current levels.”

The report said that unconventional gas would account for 63% of North American gas production by 2030 and that North America could become a liquefied natural gas (LNG) exporter of around 5 bcf per day by 2030.

“In Europe we do not expect major unconventional production before 2020. The decline in conventional supply implies a growing import requirement for Europe, up by more than 60 percent, from 26 bcf per day in 2010 to 42 bcf per day in 2030,” BP said.

© Thomson Reuters 2011

Be careful as the natural gas trade unwinds. When panic strikes, it strikes hard and fast.

One just has to look at the last week’s activity in the natural gas market for a relevant example of this. In particular, the NYMEX reference spot price for natural gas sold off over 13% last week reaching a near decade low on concerns over a record supply of natural gas at a time when we are only half way through winter.

We’re not too sure why the light bulb suddenly flashed for a number of investors in the sector as there were plenty of warning signals over the past few months.

Natural gas production is up 10% over last year’s levels and rig counts haven’t abated despite a 32% drop in natural gas prices last year. Domestic consumption has also fallen nearly 15% from last year’s levels primarily due to a lack of heating demand this winter.

Therefore, the supply/demand imbalance has more than doubled in the last 12 months driving U.S. gas storage to currently 3.377 Tcf, which is approximately 13% above last year‘s level and 17% above the five year average.

In our view, this situation is likely to get worse before it gets better as producers still continue to drill for the commodity in complete disregard to economics and profitability.

Consequently, many are estimating a 4% to 5% increase this year in domestic production to an all-time high. Should the remaining winter months be warmer-than-normal, supplies could reach a seasonal record high of over 2.4 Tcf at the end of March and nearly 4.0 Tcf by October. This would likely result in gas-on-gas competition for storage this summer.

Therefore, this is shaping up to be a very troubling year for natural gas levered producers and investors should position themselves accordingly if they haven’t already. That means investors should reduce their exposure and sit on the sidelines until the supply profile improves.

Over the past year, many of the top performing small and mid-capitalisation Canadian oil and gas companies listed on the S&P TSX were those able to post a respectable growth profile. Surprisingly, nine of the top ten performing stocks in this group last year were those with the majority of their growth coming from unconventional liquids-rich natural gas.

These gas focused companies were spending well in excess of their cash flow thanks to investors writing cheques on secondary offerings and/or lenders stepping up with expanded credit facilities. Looking ahead, we have to wonder if investors will continue to step up. We know that lenders are certainly being more cautious with natural gas price forecasts that have recently been cut approximately -25% on average over the next three years.

Perhaps the selloff in natural gas prices over the past two weeks was enough of a catalyst to cause investors in those small and mid-capitalisation Canadian natural gas companies to react. Interestingly, we noticed that those gas companies who were last year’s top performers and thereby trading at lofty valuations were among the hardest hit selling off -10% to -20% last week.

Although we tend to be contrarian with our opinion, there are times like these where it is prudent to either sit on the sidelines or simply invest elsewhere. In our view, despite the recent selloff, there could still be material downside from current levels as investors finally begin to run the numbers and realize just how expensive many of these companies are.

For example, although some pundits cite the limited downside to natural gas prices from current levels, many of the aforementioned gas-focused companies are discounting much higher prices in their valuations. We estimate that under current natural gas prices many of these companies are trading at a whopping 12 to17 times forecasted debt-adjusted cash flow.

The problem is that with less cash flow and potentially a very limited secondary market for new issues many of these companies will be challenged to deliver on their targeted growth profiles this year.

Therefore, in this event it wouldn’t surprise us to see a compression of these company multiples back to more earthly levels as this trade unwinds. To add some perspective as to the magnitude of the potential downside, many of the oil levered producers of similar size are trading at only 8.7 times forecasted debt-adjusted cash flow under $90 per barrel oil prices.

Martin Pelletier, CFA, is a portfolio manager at TriVest Wealth Counsel Ltd., a Calgary-based private client and institutional investment management firm specializing in discretionary risk-managed balanced portfolios as well as specialty offerings including an oil & gas hedge fund.

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Drilling for shale gas in the U.K. won’t cause dangerous earthquakes and poses little risk to the environment given appropriate safeguards, scientists said.

“Most geologists think this is a pretty safe activity,” Mike Stephenson, head of energy science at the British Geological Survey, said at a briefing in London yesterday. “We think the risk is pretty low and we have the scientific tools to tell if there is a problem.”

Hydraulic fracturing, a process using water, sand and chemicals to open fissures in rocks and release natural gas, has made the U.S the world’s largest natural-gas producer while raising concerns that the technique pollutes drinking water and causes earthquakes. Exploration was suspended in northwest England last year after fracturing gas wells caused two tremors.

Fracking, as the process has become known, is unlikely to start earthquakes stronger than magnitude 3.3 on the Richter scale, a level that typically causes no damage to property, and most will be around magnitude 2, said Peter Styles, a professor of applied and environmental geophysics at Keele University.

Scientists have also developed models linking the volume of water used during a fracking injection and the scale of earthquake caused, Bernstein & Co. analyst Bob Brackett said in a Jan. 6 note. An injection of 10 million gallons or less is unlikely to cause an earthquake exceeding magnitude 4, he said, citing U.S. Geological Survey geologist Arthur McGarr.

More Than Iraq

The U.K. could have more shale gas the previously thought, Stephenson said. The British Geological Survey is reviewing its estimates for U.K. onshore shale gas resources. The survey originally estimated that there is about 150 billion cubic meters of shale gas onshore, compared with about 300 billion cubic meters of conventional gas resources.

Cuadrilla Resources Ltd. says it’s found more natural gas trapped in the shale rock around Blackpool in northwest England than Iraq has in its entire reserves.

“There is much more shale than we thought under Blackpool,” the British Geological Survey’s Stephenson said at the briefing, adding more research remains to be done on the impact of fracking.

The debate over shale drilling in the U.S. and Europe has intensified in recent months following tremors near wastewater disposal sites in Ohio and concerns about water pollution in Pennsylvania. The U.S. Environmental Protection Agency is studying the effects of fracking on drinking water with an eye on possible nationwide regulations.

Styles said he has examined seismic data from 30 years of coal mining in the English midlands to assess the threat from fracking. The research suggests there is a “low” probability of unconventional gas drilling operations causing major earthquakes, he said.

Similar Rock

The rock drilled by Cuadrilla, the company that caused last year’s earthquakes, is similar to that found at the country’s major coal-mining sites, suggesting potential tremors will be of a similar or lesser magnitude, he said.

“There’s not an exact analogy to coal mining, but the seismicity is remarkably similar,” Styles said at the briefing organized by the Science Media Center. “If there are going to be others, they will be about this magnitude and because they’re of that magnitude they’re very unlikely to cause damage.”

The first tremor set off by Cuadrilla was on April 1 and measured magnitude 2.3 on the Richter scale. A weaker quake of 1.5 was recorded in May. Earthquakes of magnitude 3.9 or less on the scale are considered minor or micro, while anything under 4.9 is described as light and is unlikely to cause major damage.

Bloomberg News

Undaunted by the environmental and geological challenges, two oil giants signed shale deals in the United States for a combined US$4.5-billion ($4.58-billion) in one day. On January 3, France’s Total SA bought a 25% interest in Chesapeake Energy’s Utica shale play worth US$2.3-billion, while China Petroleum & Chemical Corp., or Sinopec, took up a one-third interest in Devon Energy’s shale projects for US$2.2-billion.

It’s a trend that’s set to continue and go beyond North American borders, says Moody’s Investor Services, as majors catch up with independent developers.

“Independent E&Ps have led the way in shale drilling, developing expertise in natural gas,” Moody’s said in a note. “The majors came late to the game in North America, but have begun pursuing E&Ps for their expertise in the new development techniques. “

Shale activity took off in earnest in 2011: ExxonMobil Corp. bought two companies in the Marcellus basin in Pennsylvania, and Marathon Oil Co. acquired Eagle Ford properties in south Texas from Hilcorp Resources Holdings LP. Mining giant BHP Billiton Ltd. acquired Petrohawk Energy Corp., a major player in the Haynesville and Eagle Ford, plus some Fayetteville shale properties, for US$15.1-billion. Norway’s Statoil ASA spent US$4.7-billion to buy Brigham Exploration Co. with operations concentrated in North Dakota’s Bakken Shale and Three Forks in Montana. Overall, shale acquisitions helped push overseas offers for U.S. oil and gas fields to US$51-billion last year, the most in at least 12 years, according to data compiled by Bloomberg.

“In Canada, the Montney Shale — a large natural gas basin in British Columbia and Alberta — has sparked interest for its proximity to a number of proposed projects to export LNG to Asia, and for potential gas-to-liquids (GTL) plants,” Moody’s says. “Sasol has two JVs with Talisman Energy and has begun studying a future GTL plant in western Canada that would use its proprietary technology. Petronas, Malaysia’s state oil company, created its first Montney JV with Progress Energy Resources — possibly with an eye on exporting LNG to Asia.”

GOING GLOBAL
Despite the ban in promising jurisdictions such as France, major companies are looking outside North America for growth. “These companies will strive to apply their expertise and mature cash flows toward other basins— particularly in Argentina, Brazil, China, Mexico, Poland and South Africa. The NOCs also hope shale development will help them improve energy security and self-sufficiency,” Moody’s says.

On Wednesday, China approved shale gas as an independent mining resource, a legal status that it hopes will encourage smaller Chinese energy firms to develop the unconventional energy source. The energy-hungry giant is expected to announce a new round of shale-gas tenders in early 2012, and although foreign companies can’t participate directly, they can team up with local firms.

Poland, which holds the most active and best areas geologically for shale in Europe, where governments want to diversify their natural-gas supplies away from Russia, is another promising play. The country has drawn investment from JVs involving ExxonMobil/Total, Marathon/Nexen, ConocoPhillips and OMV Petrom, among others.

But Moody’s says the development of these shale resources will not be quick or straightforward, and will face numerous obstacles similar to those seen in North America.

“Hydraulic fracturing has led to widespread environmental concerns over such issues as water contamination, wastewater disposal, land subsidence, earthquakes, and noise pollution. Areas more densely populated than sparsely inhabited North Dakota will present further challenges — particularly in Europe, where resistance to shale development has emerged,” the ratings agency says.

Tracy Davidson

I can show you exactly how I am creating real income with Ignite.

Well, we end the year on a great start with our new business. We have three new associates and many, many new customers. As we start a new year we all think of things we can do to make the new year better than the last. We make promises to ourselves that we are going to save more money, make more money, help more people, etc. and most of the time we all end up doing the same thing that we did last year. Well 2012 will be different for my husband and me. We have been working on our Ignite business for the last two months and we have already started making real money. If you have contacts in Georgia, Texas, Maryland, Pennsylvania, or New Jersey and you want to make a real difference in your life and those around you in the new year, Ignite is the way to do it. If you want to learn more about Ignite visit our site at spadeenergy.igniteinc.biz or call me at (478) 297-0341.

Here’s to a great year!

Nichole

This particular string answers a common question from PECO natural gas customer regarding their price to compare and our deal.

Alphabuyer Customer

Hi, I switched my electricity a few months ago and am very happy with my savings. I was looking at your site to change my Natural Gas but I’m not 100% sure that the rate you are showing is better than what my bill says.

Do you only show offers that are better deals for the specific zip code entered or no? I have PECO and looked at my bill the way you say to do on the website. My bill shows 40 ccfs x .45243 so I’m not sure how to compare it to the $52.50 rate you are showing. Can you tell me what I should be looking at for the comparison?

Thank you!

Alphabuyer Customer Service team member

Hi! Thanks for the note. Sure I can help you out.

On December 1, PECO announced a rate increase. Their rate after Dec 1 is 58.34 cents/ccf as compared to the prior rate of 45 cents (you are probably looking at a bill for the November period)

So, from Dec 1 thru March 1 if you don’t switch you’ll pay the PECO rate of 58.34 cents. If you switch to Rhoads via Alphabuyer you’ll pay 10% less for the supply portion of your bill. Now, keep in mind that the Rhoads deal is variable per month, which means it can also change. But we’ve done our research with Rhoads and they have a strong track record of beating local utility rates.

For an external reference, I suggest you take a look at the PA Office of Consumer Advocate. This is a PA PUC sister program that has created a Natural Gas Shopping Guide.

http://www.oca.state.pa.us/Industry/Natural_Gas/gascomp/GasGuides.htm

Let me know if you have any additional questions. And thank you for being a customer! Tell a friend!

Alphabuyer Customer

Hi,

Thank you for the quick response. I was looking at my November bill so I do understand now what you are saying. As I said, I have been very happy since changing my electricity so I’m confident the Nnatural gas will be just as beneficial now that I understand why my savings didn’t look better. I have already referred two people and actually received my check today so I’m even happier. Have a wonderful New Year.

Alphabuyer Customer Service team member

Hi,

I see your enrollment in the system. Thank you once again. Let me know if you have any additional feedback or ideas you have to make Alphabuyer better.

Thank you again for using Alphabuyer and don’t hesitate to contact us if you have additional questions.

In June, the Halifax-based junior resource company said its former partner in the project, Apache Canada Ltd., the subsidiary of Houston-based Apache Corp., had pulled out.

Corridor said Wednesday it will keep looking for a partner for its prospect near Elgin, New Brunswick, southwest of Moncton.

“The predominant reason given has been the current economic environment, and specifically the current low level of natural gas prices,” the company said in a statement on its difficulty in finding a partner.

Corridor shares, which trade on the Toronto Stock Exchange were down 33%, or $0.60, to $1.22 by 1:30 p.m. Wednesday.

The company’s setback comes as environmental advocates pressure the provincial government to abandon plans for shale gas development, pressure the government is resisting, insisting the industry will be safe and bring with it much-needed economic activity.

Elsewhere in the province, Corridor has natural gas reserves and production in the McCully Field near Sussex and discovered crude oil reserves in the Caledonia Field, also near Sussex. The company is also working in Prince Edward Island and Quebec.

Encana Corp.’s 2011 asset sale account jumped to $3.5 billion on Wednesday with the sale of two Canadian natural gas plants to Veresen Inc. for US$910-million.

The plants serve the Cutbank Ridge area and include its Steeprock plant in northeast British Columbia and its Hythe plant in northwest Alberta, along with compression and associated gathering pipelines.

Encana has been under pressure to sell assets after a $5.4-billion joint venture deal with PetroChina Co. Ltd. to develop northeast B.C.’s gas plays was abruptly cancelled earlier this year.

The company has vowed to replace those partnership funds through smaller divestitures.

“This sale agreement marks the conclusion of the major components in our 2011 divestiture program, which, upon closing of all transactions, will result in proceeds of about $3.5 billion US,” said Randy Eresman, Encana’s president and chief executive, in a news release.

“Although not all of our announced transactions will be completed this year, the expected proceeds will help us achieve our 2011 target range for net divestitures of between $1 billion and $2 billion.”

Research analyst Kam Sandhar of Peters & Co. said Encana got a good price for the Cutbank Ridge assets.

“We were anticipating $700 million and they ended up getting $910 million and that was even excluding one of the gas plants that we had included in our estimates, so pretty good deal I think,” Sandhar said.

Encana stock closed at $20.48, up 35 cents. It’s off almost 30 per cent this year.

Veresen was up two cents at $14.66.

The Cutbank Ridge midstream assets include approximately 516 million cubic feet per day of natural gas processing capacity from the Hythe and Steeprock natural gas processing plants and about 370 kilometres of pipelines.

The deal is huge for Calgary-based Veresen, representing about 20 per cent of its enterprise value of about $5 billion, said president and CEO Stephen White.

“It’s a material part of our enterprise value,” he said. “It provides us the opportunity for a long-term cash flow stream for our shareholders and the opportunity to put a lot more capital to work in the Montney region as the producing community drill that up. It gives us a long-term growth business in that area.

Veresen’s risk is mitigated by a long-term take-or-pay midstream services deal, under which Encana must provide throughput averaging 370 mmcf/d, representing 72 per cent of capacity.

White said the duration of the agreement is not being revealed.

Eresman said proceeds from non-core asset sales are expected to supplement cash flow generation, strengthen the company’s balance sheet and provide financial flexibility.

He said Encana will use the proceeds to reinvest in its core business of developing natural gas and growing liquids production, noting the company has spent about $770 million this year in future growth opportunities.

Earlier this year, Encana sold the Fort Lupton natural gas plant in Colorado for $300 million, the Peceance midstream assets in the same state for $590 million, the Cabin gas plant in B.C. for $215 million and producing properties in North Texas for $975 million, all figures in U.S. dollars.

The Steeprock plant is located approximately 50 kilometres south of Dawson Creek, B.C. and about 10 kilometres west of the Hythe plant, in Alberta.

With file from Rebecca Penty

Royal Dutch Shell Plc, Europe’s largest energy producer, is weighing options for rising North American natural-gas output including exports and making liquid fuels, Chief Executive Officer Peter Voser said.

Shell will double North American gas production in the next three years to the equivalent of 400,000 barrels of oil a day as output from shale deposits rises, Voser said in an interview. Shell may channel gas into chemical production, an export project in Canada, and a program to use the fuel to power trucks, he said.

“We are getting now into production phase in a big way,” Voser said at the World Petroleum Congress in Doha, Qatar. “It’s about the right time to look for further options. We are really looking at the usage of gas in a much wider way in North America.”

Pumping gas trapped in shale rocks has transformed the U.S. into the world’s largest gas producer, cut prices about 75 percent from their 2008 peak and made exports to higher priced markets in Asia and Europe a viable option. The fuel will overtake crude oil to account for more than 50 percent of Shell’s global production next year, driven in part by the development of shale gas fields in Texas and Pennsylvania.

“This percentage goes up over the next years to come as most of our projects are actually gas projects,” Voser said. “Given our huge gas reserves in the U.S. we are looking at a possibility to actually build a gas-to-liquids plant.”

Largest Project

Shell has invested about US$19-billion in its Pearl gas-to- liquids plant in Qatar to make transportation fuel. It’s the company’s largest project to date and it plans to build another “large scale” unit, Andy Brown, Shell’s chief in Qatar, said earlier this week.

The company has gas reserves in North America of 40 trillion cubic feet, about 12% of the continent’s total at end of 2010, based on data from BP Plc’s Statistical Review of World Energy. The company spent US$4.7-billion last year to buy most of East Resources Inc., a shale producer with fields in Texas’s Eagle Ford area and Marcellus in Pennsylvania.

The Hague-based producer is working on the Green Corridor project in Canada to convert gas into 300,000 tons of liquefied natural gas a year to fuel long-haul trucks from next year. The fuel will be offered to operators along western Canada’s busiest truck route from Calgary to Edmonton, said Malcolm Brinded, executive director for exploration and production.

Shell is looking at using the LNG-to-transport technology in China and Europe, Voser said. It will be a smaller market than using gas to fire power plants, “but it’s a good usage of the gas,” he said.

“There is a great appetite for this type of solution,” he said. This market “will be growing. You can think of more, you can use it in the shipping industry.”

LNG Exports

The gap between natural gas and crude oil prices in North America is opening up the prospect of LNG exports to Asia and making chemical projects commercially viable. Today’s gas price is equivalent to about $27 a barrel of crude, while oil is trading at about $100 a barrel in New York.

Shell, together with PetroChina Co. and Japanese and South Korean partners, plans to develop an export facility in British Columbia in Canada to supply LNG to Asia.

In June, Shell announced plans to build an ethylene plant in Appalachia, the first so-called cracker built in the region in half a century, to tap low-cost natural gas for making plastics. The cracker would process gas from the Marcellus shale. The ethylene probably will be converted to polyethylene plastic at a second factory to be built at the site, Shell said.

Bloomberg News

The consultancy firm expects the industry’s progress to be evolutionary rather than revolutionary across the Atlantic.

“While exploration is underway in several countries such as Austria, Germany, Hungary, Ireland, Poland, Sweden and the UK, no shale gas play has yet been brought into production in Europe, and only a fraction of this resource base is likely to ever prove commercial and be produced,” says John Avaldsnes, Ernst & Young’s EMEIA Oil & Gas Sector Leader. “In addition, over half of all estimated European shale gas reserves, which accounts for almost 10% of the global total, are concentrated in just two countries, Poland and France.

“There are some difficult challenges that the industry needs to address. There appears to be no consensus across Europe on shale gas development and government attitudes vary, in some cases markedly. Public opinion on the issue is similarly divided, adding to pressure on governments to take action to either support or restrict shale gas development with most countries adopting a ‘wait and see’ attitude.”

The E&Y report highlights key factors influencing the shale gas industry in Europe:

Geology and resource potential
Each shale basin has its own unique exploration and operational challenges. There are shale gas reserves in 16 countries, though no shale play has been brought into production in Europe.

“The largest estimated reserves in Europe are in Poland with 5.2 Tcm, which equates to 29% of the European total but less than 3% of global shale gas reserves. Poland is closely followed by France, which has estimated resources of 5.0 Tcm, or 28% of the European total. Only a fraction of this resource base is likely to ever prove commercial and be produced,” the report notes.

Gas demand
There appears to be ample supply available to the EU states, as North Amnerica becomes more self-sufficient. Predicted gas demand growth will be an important consideration for oil and gas companies when considering investment in shale gas projects in Europe, says E&Y.

Some of these issues include security of supply, an issue that came to the fore after the Russia-Ukraine dispute in 2009.

The future of nuclear energy has also been questioned after the Fukushima accident in Japan in March 2011, which led to many nuclear plants in Europe being mothballed.

“The uncertainty over the future of nuclear energy, coupled with cost and investment issues with renewables, could lead to a situation where gas becomes the primary energy source in Europe in the next 20 years, rather than being a transition fuel to a low carbon economy.”

Energy prices
Shale gas prices are expected to be around $8-$12 million btu, at least two to three times higher than the United States. While the U.S. shale gas industry has achieved economies of scale and is far more advanced than EU, even with the higher development costs, the relatively higher gas prices that can be realized in Europe mean that shale gas projects in Europe could still be economical.

Competition
Expect Russia to feel particularly threatened by shale gas and ramp up its own conventional gas production. Other countries such as Azerbaijan and Turkmenistan are also in various stage of laying down pipelines to secure.

A significant LNG trains been commissioned to add the supply glut. E&Y says Since 2005, 24 new LNG trains have been commissioned, bringing the total number of LNG trains in operation across the globe to 94 at the end of 2010. There is a significant amount of additional LNG liquefaction capacity coming online between 2011 and 2012 that was sanctioned based on expectations that the US would become a major import market. The shale gas boom in the US has rendered a number of LNG import terminal facilities idle, and some operators are seeking approval to convert their facilities so that they can export LNG.

Environmental and social factors

Public disapproval of ‘hydraulic fracturing’ could lead to greater regulatory controls and restrictions in Europe. The experiences in U.S. show the technique could have a potential impact on drinking water supplies.

A 2011 Duke University study found no evidence of drinking water supplies being contaminated by fracking fluids, although researchers from the US institution did find significantly higher concentrations of methane in wells located within a kilometer of active fracking sites. However, there is no pre-drilling data available so it is uncertain whether the methane was linked to the fracking process or whether it was present before shale drilling commenced.

Still, drilling activity by Cuadrilla Resources was suspended in Blackpool in the UK after it was linked to an a small earthquake. An independent study commissioned by the company concluded that the seismic events was due to the “unusual combination of geology at the well site coupled with the pressure exerted by water injection as part of operations.”

Fiscal and regulatory regimes

Shale gas faces enormous regulatory challenges in Europe characterised by the attitude’s of two countries with the largest reserves – Poland and France.

The French government banned fracking in shale gas projects in June 2011 and canceled three shale gas exploration permits because the holders did not commit to not use fracking to explore the permits.

Poland, on the other hand, has showed public support. “The Polish government plans to introduce special regulations for shale gas

production in its own country, including new fees or even mandatory participation of the state in order to safeguard its budgetary interests, a deputy treasury minister said on 8 September 2011.”

Between these two extremes, the rest of the EU countries have adopted the ‘wait-and-see’ approach.

Producing natural gas from shale will support 870,000 U.S. jobs and add US$118-billion to economic growth in the next four years, according to a report from IHS Global Insight.

Gas from shale, which accounts for 34% of U.S. output, also will contribute US$57-billion in federal, state and local taxes by 2035, or US$933-billion in the next 25 years, according to today’s IHS report, commissioned by America’s Natural Gas Alliance, a Washington-based industry group.

Shale gas is extracted using hydraulic fracturing, a process in which millions of gallons of chemically treated water and sand is forced underground, breaking up the rock to free trapped gas. Industry expansion is adding jobs in an otherwise disappointing economy, said John Larson, a vice president at Lexington, Massachusetts-based IHS, a management consulting company for the energy industry.

“Shale gas combines a capital-intensive industry with a broad domestic supply chain,” Larson said in an interview. “We think that these jobs through 2015 are net new jobs because of high unemployment.

Environmental groups have said the process, also called fracking, has tainted drinking water in states such as Pennsylvania, where almost 4,000 wells have been drilled. About 1,900 people, most opposed to fracking, attended a New York City hearing on Nov. 30 to consider state rules for drilling.

Financial forecasts by IHS include direct jobs in the drilling industry plus an “employment multiplier.” For every direct job added, more than three indirect and induced jobs are created, according to the report

‘Conservative Estimate

The forecast excluded potential drilling in New York, which has placed a moratorium on fracking while it develops drilling regulations, or the impact of U.S. service companies supplying drilling in Canada, Larson said.

“Given those sort of factors, we feel that what we’ve presented here is a very conservative estimate,” Larson said.

The shale-gas contribution to U.S. gross domestic product will triple to $231-billion in 2036 from $76-billion last year, the report found. Lower natural gas prices as shale boosts supply will cut U.S. electricity costs by an average of 10%, the report found. Lower prices will raise industrial production 2.9% by 2017 and 4.7% by 2035.

Environmental groups such as Washington-based Food and Water Watch say fracking has led to groundwater contamination and should be banned. The group found in a November report that projections for the number of shale-industry jobs in states such as Pennsylvania and New York led to a “gross exaggeration” of the gains, said Emily Wurth, the group’s water policy director.

A 2011 report by the Public Policy Institute of New York State, an Albany-based research group, found that by 2018, developing 500 shale gas wells a year in five counties would create 62,620 jobs. After correcting the “flawed” job multiplier, the number was closer to 6,656 jobs, Wurth said.

“Very few people have analyzed these reports,” Wurth said in an interview. “That’s unfortunate because a lot of elected officials take these studies as factually based.”

Bloomberg News

December Promotion

The good things of November have spilled over into December!

Every Associate with a start date between December 1 and December 31, 2011 is eligible for these customer-gathering bonuses:

• Double Quick Start 4 – $200 (30 days)
• Quick Start 6 – $100 (30 days)
• Quick Start 8 – $100 (60 days)
• Double Quick Start 10 – $200 (60 days)

That’s $1,400 for completing 3 and 10, including Double Immediate Income! How’s that for some extra holiday cash?

Let your prospects and new Associates know what’s on the table for December, stoke those entrepreneurial flames within and keep your business boiling throughout the month as we finish out 2011 strong!

For more information on becoming an Ignite associate visit Ignite Business website. See you at the top!

Goldman Sachs is increasingly lonely in a prediction of rising European gas prices next year, with other banks, analysts and utilities forecasting a glut of gas supplies in 2012.

The U.S. investment bank said in a research note on Thursday that it continued to recommend a long position in UK gas prices for delivery in the fourth quarter of 2012.

The outlook comes despite sharp drops in gas prices since last summer, with the benchmark NBP summer 2012 contract down over 16% since the end of August.

“We believe the UK NBP forward curve has been under pressure as a result of weak demand on the back of mild weather and slowing economic activity in Europe,” Goldman Sachs gas analyst Samantha Dart told Reuters.

“Going forward, we assume a return to normal weather as well as a modest recovery in economic activity relative to this winter. As a result, we expect UK NBP price levels to rise relative to the current forward market in 2H 2012.”

SWIMMING AGAINST THE TIDE

Goldman’s views contrast with from those of other traders and banks.

Also in a research note on Thursday, French bank Societe Generale said it expected European gas prices to fall in 2012.

“Gas demand is not likely to reach pre-crisis 2008 levels before 2015. But with the deepening of the euro crisis, we might be too optimistic,” SocGen analyst Thierry Bros said.

“We therefore reiterate our recommendation to sell NBP summer 12 as we believe that increased Libyan exports into Italy will mean ENI has to tackle additional Russian take-or-pay obligations in 2012 and will force the market to admit that the gas oversupply situation is likely to persist in 2012.”

UK investment bank Barclays Capital said in a note in November that “it will take a mighty winter to put the gas market on a bullish path,” and that “a warm winter puts the market on a decidedly bearish trajectory.”

BarCap said that “even a winter that is 10% colder than normal would only push inventory levels down to last year’s end-of-March number, which was not very supportive for prices even though last winter was quite cold.”

NBP gas inventories are filled to over 96%, according to the latest data from Gas Infrastructure Europe, and if inventory levels remain well supplied at the end of the heating season next March, a mild winter would keep bearish pressure on the NBP market much further into 2012, traders said.

Weather forecasters are revising their European outlook for the winter season and expect milder-than-average weather instead of the initially forecast colder-than-normal season.

German competitor Deutsche Bank said in late November that it expected European gas demand to drop in late 2011, and that “this trend could extend into 2012, with consequences for the spot-to-contract discount and oil-indexed pricing arrangements.”

Deutsche’s Mark Lewis said the bank was revising its gas price forecast for 2012.

A major European utility also said it disagreed with Goldman’s view of a bullish gas market next year.

“The final quarter this year is one of the warmest on record, and the one last year was among the coldest ever…so it is reasonable to assume that, based on those outliers, next winter will still see high demand,” a source the utility said.

“But that isn’t our view,” he added.

A recent Reuters analysis found that the European Union’s gas market could be around oversupplied by around 60 billion cubic metres (bcm) in 2011 and 2012.

This compares with a net positive balance of just over 10.5 bcm in 2010, according to BP’s annual statistical review.

© Thomson Reuters 2011

BEIJING – China National Offshore Oil Corp (CNOOC Group) will build the country’s first floating liquefied natural gas (LNG) receiving and storage facility off the northern city of Tianjin, state media and industry officials said.

The project, costing 5.7 billion yuan (US$892.84-million), would be able receive 2.2 million tonnes of the fuel annually and all the LNG will be imported, a CNOOC official said.

China has been adding onshore receiving terminals along its east coast to handle imports of LNG, super-chilled natural gas shipped by tankers, to meet surging domestic demand for the cleaner-burning fuel.

But with competition rising among the main investors — CNOOC, PetroChina and Sinopec Corp — and limited land sites along the coast, companies have shifted to floating facilities.

“It’s all because of increasing difficulties in winning state approval for a land-based receiving terminal,” said the CNOOC official.

CNOOC and its partners will either buy or rent a floating facility for the Tianjin project, which should start operation in 2014, said the official, adding that CNOOC has plans to add several more floating facilities along the coastline.

REGASIFICATION

From there, smaller tankers will ship the fuel to an existing onshore receiving terminal for regasification before being pumped into the city gas grids or being trucked away by the country’s growing fleet of LNG trucks that supply residential areas and small power stations.

CNOOC plans to team up with the Tianjin port authority and the Tianjin city gas company to extend the project into a second phase — to build a 6 million tonne-per-year onshore LNG receiving terminal and four storage tanks with capacity of 160,000 cubic metres each, official news agency Xinhua said on Tuesday.

The companies have set a target to bring these on line in 2015, it said.

China’s LNG imports, which now make up roughly a tenth of its total gas use, rose by a quarter in the first 10 months of this year from a year earlier to 9.4 million tonnes, customs data showed.

CNOOC, the country’s leading LNG terminal developer, has three receiving terminals operating in southern China.

CNOOC is the parent of Hong Kong-listed offshore oil producer CNOOC Ltd.

© Thomson Reuters 2011

Centrica, the U.K.’s biggest residential natural gas supplier, agreed to buy US$1.6-billion of fields in the Norwegian North Sea from Statoil ASA, increasing oil and gas production 25%.

Centrica will acquire stakes in eight fields on the Norwegian continental shelf, the Windsor, England-based company said today in a statement. In a second deal, Centrica agreed to buy 5 billion cubic meters a year of gas from Statoil from 2015 to 2025, equal to 5 percent of U.K. gas consumption.

Adding gas production assets will give Centrica more security in gas supply and offer a hedge against volatile gas prices. For Statoil, the sale will free up capital for development of fields including the Aldous-Avaldsnes discovery, Norway’s largest since the 1980s.

“Diversity of supply is a good thing and you can’t get away from the fact that we need to invest in places that are stable,” Centrica Chief Executive Officer Sam Laidlaw said in a telephone interview. “We had a lengthy discussion on value, but feel very comfortable.

The deal values proved and probable reserves at about $13.90 a barrel of oil equivalent and is “in line with recent North Sea transactions,” according to Evolution Securities analysts Keith Morris and Richard Griffith. The company’s quest to shore up its energy hedge suggests it doesn’t see commodity prices falling, the analysts said.

Qatar Deal

The utility has been seeking to lock in gas supply in the face of rising wholesale prices. It signed a 2 billion pound ($3.14 billion) three-year deal with Qatar earlier this year to deliver liquefied natural gas. U.K. wholesale gas costs are 26 percent higher this winter than a year ago, squeezing margins at the company’s residential business, the company said earlier this month.

Centrica shares rose as much as 0.9 percent to 291.4 pence and were flat at 288.5 pence at 11:24 a.m. in London. The benchmark FTSE 100 index dropped 2.1 percent. Statoil declined 2.3 percent in Norway.

The transaction involves the sale of Statoil stakes in the Kvitebjoern, Heimdal, Valemon, Skrine-Byggve, Fulla, Frigg- Gamma-Delta, Vale and Rind fields. The assets produced about 34,000 barrels of a day this year, adding 25 percent to Centrica’s oil and gas production and increasing its reserves 29 percent.

This “materially increases the size and span of Centrica’s upstream operations,” Credit Suisse AG analyst Mark Freshney said in a note to investors today. “Some may be disappointed that the company is not returning cash, and we need a strategic explanation,” the analyst added.

Redeploy $3.7 Billion

Statoil said will be able to redeploy $3.7 billion in capital to other projects taking into account the sale price and the money it would have spent keeping the fields going

“This is absolutely positive for Statoil and they are proving their ability to divest assets for cash,” said Carl Christian Bachke, an analyst at RS Platou Markets in Oslo. “They want to put this money where their priorities are, that is to continue developing their newly discovered main assets in Norway.”

The deal will boost Centrica’s production by around 25 percent, an increase of about 34,000 barrels of oil equivilant per day. It also lays the foundation for future cooperation in the U.K. and Norwegian sectors of the North Sea, as well as further North in Norway, the executive said.

The new long-term gas sale agreement is an extension of the contract between the two partners, which expires in 2015, Statoil said.

Bloomberg News

BHP Billiton spent nearly $17 billion buying shale gas producer Petrohawk Energy and shale gas assets from Chesapeake Energy CHK.N earlier this year.

“This is going to be a gamechanger around the world and for BHP Billiton not to be part of it would be irresponsible,” BHP petroleum chief executive Michael Yeager said in slides prepared for an investor presentation to allay concerns about the company’s push into shale gas.

BHP said it plans to spend around $5.5 billion a year by 2015, about a billion more than previous estimates, and around 6.5 billion a year in 2020 on U.S. shale.

BHP’s move this year into the relatively new and contentious energy source has worried some investors, particularly with U.S. gas prices depressed by the growing supply of gas from shale. CEO Marius Kloppers, however, has played down the concern, saying the group takes a “multi-decade view on price.”

Yeager said BHP expects to benefit from an increase in U.S. demand for gas, particularly as U.S. efforts to cut greenhouse gas emissions push more buyers to switch from coal to gas.

U.S. gas prices are expected to rise to over $6 per million British thermal units (mmBtu) by 2020, up from around $4 per mmBtu currently, he said.

Evy Hambro, investment chief for natural resources at BlackRock BLK.N, BHP’s top shareholder, recently told Reuters he was “reserving judgment” on the Petrohawk deal ahead of Monday’s briefing, and also expressed general concern over the cheap price of U.S. gas and the potential for environmental issues.

Landowners in Arkansas and other shale gas producing areas have raised concern about the technique used to drill for shale gas, hydraulic fracturing or “fracking,” but BHP has said the technology is safe.

“The technology used here has been proven and used for a long, long time,” Yeager said of the fracking technique, adding that the shale gas industry is tightly regulated and even smaller players are unlikely to take shortcuts.

“We are subject to inspection at any time … I think the opportunity for the industry to cut corners at any level is small.”

Yeager also highlighted the low costs, long life, and advantages of U.S. shale over conventional gas resources, saying that “quantum leaps,” in shale gas extraction technology have allowed the company to boost production.

BHP is targeting U.S. shale production of 545 billion cubic feet equivalent (90 million barrels of oil equivalent) in financial year 2012.

The shale gas projects are part of BHP’s plans to spend $80 billion over five years on expanding production across its iron ore, coal, copper, uranium and petroleum businesses.

BHP’s proximity to the U.S. Gulf of Mexico will also enable it to take advantage of liquefied natural gas export opportunities to Europe and Asia, Yeager said.

There is currently a wide differential between prices in the United States, which stand at around $4 per mmBtu, versus around $10 per mmBtu in Europe and $17 per mmBtu in Asia.

© Thomson Reuters 2011