Monthly Archives: May 2010

Will enhanced oil recovery technique be the savior for oil supply shortage ?

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by Kurt Cobb

To read ExxonMobil Corporation’s website one might get the impression that the world’s largest oil and gas company has begun only recently to employ enhanced oil recovery (EOR) techniques. If that were true, this industry bellwether might have been able to say that these techniques will have a substantial effect on the future flow of oil. After all, the claim for EOR is that it could potentially double the amount of oil we can get out of the Earth–from the current one-third to two-thirds or so of the original oil in place. The implication is that not only will future wells yield more of their oil than previous ones, but that far more oil can now be harvested from existing wells.

The big problem with this thesis is that EOR is already being widely applied–so much so that the Oil & Gas Journal will sell you its most recent worldwide survey of EOR projects for only $330. You can get the full historical database all the way back to 1986 for a mere $1,100. (Hint: Both contain more than a few entries.)

The three main types of EOR are gas injection, steam (both cyclic stimulation and flooding), and chemical injection, and they’ve been around for a long time. The poster child for EOR among the oil optimists is the Kern River Oil Field near Bakersfield, California. Kern was discovered in 1899. As production waned, steamflooding was introduced in 1964. In 1961 production was about 19,000 barrels per day. By 1966 it had risen to 53,000 barrels per day. Production reached its peak at 141,000 barrels per day in 1985. Production continues today at around 80,000 barrels per day.

The Kern River steamflood has proven how well EOR can work in some situations. But as any reader will deduce, the results are already reflected in current production and reserve estimates. Steamflooding has been in use for a very long time.

Natural gas injection is also an old technique used to maintain reservoir pressures. It has been used continuously, for example, at Alaska’s Prudhoe Bay Oil Field which began shipping oil in 1977.

Nitrogen injection is newer, but has been used, for example, since 2000 on the huge Cantarell Field in the Mexican portion of the Gulf of Mexico. Results were excellent at first. But the subsequent crash of production at Cantarell has called into question whether this form of EOR merely hastened production without increasing ultimate recovery.

The same issue has been raised by another technique called maximum recovery contact wells, which is often grouped with EOR. The technique worked superlatively for a while in Oman’s largest oil field only to lead to a precipitous crash in production later.

Carbon dioxide injection has also been used successfully, but supplies are expensive if they are not near the field. The newest of the major EOR techniques involves inoculating reservoirs with microbes that will make the oil flow more freely. It looks promising.

Oil company sources tell me that indeed these techniques are used wherever practical. Limitations include high capital and operating costs. For example, Cantarell’s nitrogen injection system cost $6 billion to build. Other limits may result from the existing infrastructure. For instance, will that infrastructure be able to handle additional production? And, if not, what would it cost to upgrade it?

High costs almost always mean high energy inputs. Even if the capital and expertise is available, it may cost more energy to implement an EOR program than will be gained from the extra oil. Inevitably, the energy return on investment for oil obtained using EOR will be lower, often far lower, than oil obtained using standard methods.

Oil supply optimists often talk about doubling average recovery from oil wells. But B. J. Doyle, vice president of operations for a small Houston-based oil and natural gas exploration company, cautions against such talk. Every reservoir is unique. This means that 1) many reservoirs will simply not benefit from EOR and 2) the increase in recovery when EOR is applied can vary widely.

In addition, Doyle says, there are fields where the techniques won’t be applied until small operators take over. After large oil companies get the majority of oil out of a field, they often find it’s not worth their while to continue pumping. Frequently, they sell their interests to smaller operators who have the willingness and patience to squeeze out the final barrels using a variety of techniques, some of which wouldn’t necessarily qualify as EOR.

In places such as the United States and Canada this happens as a matter of course. That’s why these countries have so many operating wells, many of which pump fewer than 10 barrels a day. But this pattern of exploitation in mature oil fields is only happening in these countries because they allow private ownership of oil rights. In places such as Nigeria, Iran and Saudi Arabia, private companies cannot simply purchase or lease mineral rights from the owner because the owner is the government. In Iran and Saudi Arabia, the government has total control over the oil industry. There is no entrepreneurial class of small operators able to take over largely exhausted fields and revive them. That means that in many of the most oil-rich places in the world, EOR on the scale practiced in the United States and Canada will probably never become a reality.

Energy writer Chris Nelder gives us perspective on what we can expect from EOR. He writes that history shows us that EOR “does not affect the date of the peak, nor the peak rate of production. It typically just extends the ‘tail’ on the back end of the curve and increases the ultimately recoverable total.”

Even with all these caveats, I think we can concede that EOR will add to proven oil reserves in the future and likely cushion the decline in oil production after world output peaks. But given the historical record of EOR, it is unlikely these techniques will prove to be the savior of oil production rates that the oil supply optimists would have us believe.

New Trade Regulation proposals and Oil

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The Federal Reserve gets a greater role to play in overseeing large financial institutions
By MERLIN FLOWER for OIL-PRICE.NET, 2010/02/10

On Jan 21, the US President Barack Obama announced a series of measures to reduce risk in the financial sector. The proposals intend to tighten the regulatory mechanism and prevent a second- or like- sub-prime mortgage crisis. That is, the banks will not be able to put the whole economy at risk-again.

“If these folks want a fight, it’s a fight I’m ready to have” said Obama. The folks are the financial institutions like the banking sector which would have limits on trading activities. Financial institution backed by the government will be prevented from taking huge risks. The move would impact Wall Street’s trade directly.

The proposals have been dubbed as ‘the Volcker Rule’ after the former Federal Reserve Chairman, Paul A. Volcker, who advocated strong financial reform with more regulatory control. The regulations aim to correct the soaring profits and obscene bonuses of certain firms. “We should no longer allow banks to stray too far from their central mission of serving their customers,” were the words of The US President.

Coming on heels of his party’s election loss in Massachusetts, the President has used a populist stance. His move looks like an attempt to stop the slide in his popularity rating. A smart move nevertheless, as it’s no secret that banks are hated by many people, being held responsible for the economic crisis. In addition, the bailouts of the banks using the taxpayer’s money created a huge public outcry. Since then there has been pressure from various quarters to regulate the financial system. The first proposal was thus put forward by President Obama in June 2009. Then on Dec 11, 2009 the House approved the Democratic plan to tighten federal regulations, especially of the Wall Street.

Some proposal that preceded the Volcker rule:New regulator, tentatively called Consumer Financial Protection Agency would oversee credit cards, mortgages and consumer debt. Thus the role of banks become limitedNew rules for transaction to prevent another economic slowdownMeasures to reduce threat of bankrupt companies ruining the economyThe Federal Reserve gets a greater role to play in overseeing large financial institutions

Volcker rule in detail:

These proposals would limit banks and Wall Street firms which own banks from owning, investing in, sponsoring or advising any hedge funds or private equity funds. As sharp move as the US banks have a hefty nine percent share in private equity capital.

The regulations will separate commercial banks from investment banks. Banks trade for profit backed by the deposit insurance, safeguards and guarantees bestowed on them by the government. Obama plans to limit these risks, as they are subsidized by the taxpayer who would suffer if things go wrong.

The president said that he cannot accept a system where shareholders make money on the operations ‘if the bank wins but taxpayers foot the bill if the bank loses’. Thus only commercial banks that stay away from proprietary trading on their own accounts would benefit from the Federal Reserve’s discount window. (The federal discount window or Fed’s use of credit, in short, is a government loan facility which helps the banks to borrow reserves at a discount rate. It helps alleviate the liquidity problems of the banks).

In other words, banks can either engage in proprietary trading or resort to being a traditional bank -not both. Banks like Goldman Sachs and Morgan Stanley would be affected as they will have to forgo their status as commercial banks if they want to continue in proprietary trading. Also, both the banks will have to leave from the private equity businesses. (However, the banks can still return their deposit base-which is small- and withdraw from the federal discount window).

Elsewhere, China too is tightening its monetary policy. Some of its banks have been asked to halt lending for some time. This comes in the backdrop of heavy lending in the first two weeks of the year. Together with Volcker rule and the Chinese move, the stock markets around the world fell with the Wall Street reeling under the worse decline in a day in three months. The banking sector has reacted sharply which found resonance in the stock market and dollar-both fell.

Crude oil and gold prices too fell soon after the Volcker rule announcement. This was based on investor fear that banks won’t be able to trade in crude futures on their own accounts.

Ramifications of the Volcker proposals on oil:Banks have in recent years, invested heavily in risky ventures, which, if one recalls, led to the financial crisis. Major Banks in the US have pumped in billions of dollars speculating on oil and gas contracts. The latest proposal will make it difficult and expensive for the commercial banks to buy gas and oil contracts. Oil prices are driven by speculation, which will take a back seat with banks absent from the scene. Some analysts like hedge fund manager Mike Masters are of the view that the limited role of commercial banks will result in less volatility in the energy market.The ‘Super Contango’ will come to play its part. The oil stored will be offloaded into the market, resulting in more oil availability. (For more details on Contango: http://www.oil-price.net/en/articles/oil-contango-effects-on-oil-prices.php)According to a report of the government, the United States was using less energy than 2009. Though demand is increasing from growing economies in Asia, they may not be able to offset for the lesser demand in the US. Already the effects are to be seen: On Jan 21, IEA said that the country’s gasoline supply increased by 3.9 mbd the previous week in the wake of less demand. The commodity fell to a four-week low after the weekly EIA report revealed that refineries have slashed their operating rates as fuel demand declines. In fact they have also slowed down their operations. Still, due to oil contango there will be oil in the market.

The Volcker rule is yet to be passed by the senate; hence it’s still early to predict the actual trajectory of the oil prices. Indeed, some of the proposals may not even see the light of the day. Still, taken together, the oil prices may not increase to the record levels seen earlier this year. On the face of it, this is good for the consumer who will have to spend less on transportation. However, the oil industry would have to battle the underinvestment. Also, if the banks were to withdraw the investments made, the whole industry would be affected in the long term.

Why Conventional Heavy Oil is a Sizzling Commodity in Alberta and Saskatchewan ?

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As an oil producer, Saskatchewan seems to have it all. The Bakken light oil trend is a play of frenzied activity. So is Cenovus Energy’s carbon injection oil operation at Weyburn (the world’s largest carbon capture and storage facility). But the province’s meat and potatoes – conventional heavy oil production in the Lloydminster and Kindersley areas – are hidden behind these high-profile developments.

The province’s first 2010 land sale tells the story, but it’s only clear if you dig deeply into the numbers.

Out of nearly $40 million in bonus bids, about $26 million went for land in the Weyburn-Estevan – a reflection of the importance of Bakken and Weyburn. Dig a bit deeper into the numbers, though, and you will find that the highest price paid for a single parcel was $2.1 million for a 1,552-hectare exploration licence in the Lloydminster area. One operator, Baytex Energy, paid $6,512 per hectare for a 16-hectare parcel near Maidstone, also in the Lloydminster area – by far the highest bid per hectare.

Between them, the two heavy oil producing regions in Saskatchewan brought in nearly $10 million in bids – not bad for the Cinderella sister of light oil. The message is clear. The resource has been on production since 1946, but despite its longevity is an increasingly valuable asset. This reality applies to conventional heavy in Alberta as much as it does to production in Saskatchewan. In today’s market the commodity is sizzling. Although there was a blip due to low oil prices a year ago, today’s barrel of conventional heavy is almost as profitable as ever before.

Major changes in transportation to the US and modifications to US refineries have made the Canadian commodity extremely desirable. As a result, the differential paid for Canadian light compared to Canadian heavy is holding firm near historic lows. The differential has averaged about C$8 per barrel for the last year. To put that in perspective, as recently as late 2008 conventional heavy sold briefly for 45% less than Edmonton Par. That wasn’t a profitable environment.

By contrast, the market today is a bit like a winery selling this year’s plonk for 14% less than a vintage wine. Like plonk compared to fine wine, heavy oil is intrinsically less valuable than Edmonton Par, the Canadian standard for light oil. In most refineries, after all, heavy feedstock results in less high-value-added gasoline and more low-value-added asphalt.

But the big US refining complexes are changing that. “It’s a matter of adding vessels to the refinery,” according to Steven Paget; he is vice president for energy infrastructure at First Energy Capital. “Those longer-chain hydrocarbons need more work to break up, but new pipelines from Canada are accessing the refineries at Wood River (Illinois) and Cushing (Oklahoma).” Those refining complexes have the capacity to break heavy oil into lighter feedstock. “Therefore the (narrow) differential becomes minimal or close to equivalent to actual operating cost.”

The good news is that the two heavy oil provinces have a lot of plonk left to sell. According to the Canadian Association of Petroleum Producers (see chart), between them the two provinces have more than a billion barrels of established reserves left to produce. More importantly, each has estimated heavy oil in place many times the volume of reserves.

CAPP estimates that initial volumes of heavy oil in place (this includes both conventional and non-conventional heavy) were about 15 billion barrels in Alberta, and 20 billion barrels in Saskatchewan. Established reserves will thus continue to grow, just as new in-place volumes will continue to be found.

The Background

To understand the economics of conventional heavy, cast your eyes back to the industry’s beginnings.

There are three historical reasons for the growing strength of conventional heavy oil. First, since the 1980s operating costs for conventional heavy production have been in relative decline because of improving technology, higher prices and a better understanding of the reservoirs. Second, policies established since 1990 have lowered royalties for the stuff. Third, the volumes of heavy oil in the Alberta/Saskatchewan heavy oil belt are simply huge. Although the reservoirs tend to be thin, the output is large, and production lasts for many years.

Defined as oil below 20° API which can flow from its reservoirs like lighter oils, conventional heavy oil goes back a long way in Western Canada’s economy. The heavy oil belt is a series of thin sand reservoirs straddling the border of the two provinces. The oil is lighter in density (11-18° API) and of much lower viscosity than the bitumen in the oil sands deposits.

The buckle of the heavy oil belt is Lloydminster, the border town. The first conventional heavy discovery occurred in 1938, and modest development began when Husky Oil (now Husky Energy) moved into the area after World War II. Husky began producing heavy oil from local fields in 1946, and by the 1960s was easily the biggest regional producer. In 1963 the company undertook another in a series of expansions to the refinery (to 12,000 barrels per day). To take advantage of expanding markets for Canadian oil, it also began delivering heavy oil to national and export markets. These developments made conventional heavy more than a marginal resource. Within five years, area production had increased five-fold to 11,000 barrels per day. However, production volumes remained small until the 1990s.

The first of two important developments was the completion of two upgraders – the Co-op facility in Regina and Husky’s in Lloydminster. These upgraders, which were subsidized by government to reduce risk during a period of lousy oil prices, created a large local market for heavy oil. In the early 1990s, production from the heavy oil belt had risen to 300,000 barrels per day – one third of that production being upgraded and refined for local markets. Today Husky produces about 75,000 barrels per day of heavy oil – more than 10% of Canada’s total.

More importantly, in 1993 the Alberta government redefined conventional heavy as “third tier” oil, with highly favourable royalty rates. Once Saskatchewan’s New Democrats were removed from power, new governments in that province matched and then exceeded the Alberta initiative – after all, heavy oil is Saskatchewan’s single most important long-term hydrocarbon resource, so the province had good reason to kick-start development. Indeed, in a modification to the royalty system in 2002, Saskatchewan defined “fourth-tier” heavy oil, with very low initial royalties. All these new tier royalties were great kick-starters. However, as the CAPP data show in the chart below, conventional heavy oil production is now in decline despite growing reserves.

OPEC or Infrastructure?

Especially in a market of declining production, the question of whether differentials will remain narrow is critical. And on this score there is debate. Is the differential likely to narrow or to widen?

According to AJM Petroleum Consulting operations vice president Ralph Glass, the basic reason differentials are so low “is an increased demand for the heavier crude oils from US refineries. Over the last few years there has been a movement by US refineries to enhance their ability to handle the heavier crudes. With the downturn in US demand, OPEC cut their volumes. (The volumes cut were the heavier crudes and done to maximize returns from light crudes which receive higher prices). As a consequence, the US refineries found themselves short of heavier crudes to process, and are now paying a premium for Canadian heavier crudes to reduce the shortfall in their systems.”

He suggests that the demand for heavy oil to fill for new pipelines to the US – TransCanada’s Keystone pipeline into Patoka, Illinois and Enbridge’s Alberta Clipper line to Superior Wisconsin – may narrow the differential even more in the short term. However, the return of competition from OPEC will widen the differential, thus making heavy oil production less profitable.

First Energy’s Steven Paget has a more sanguine view. “The reason the differential has gone down is that we have more transportation infrastructure out of western Canada,” he says. “This allows nearly 90,000 barrels per day of crude to access the Gulf Coast refining complex.” Demand for fill for new lines will increase demand over the short term (narrowing the differential), but the more important factor in his eyes is that those new pipelines will provide increased access to markets, making conventional heavy more competitive in US markets. “The narrow margin is likely to continue.”

Ralph Glass takes the more cautious view. In 2011 and 2012, he says, the industry will experience “widening on implied concerns of heavy OPEC production coming online and increased Canadian heavy production.” If he’s right, and if production continues to decline, expect the sector’s salad days to wilt.

Oil War in the Falkland Islands

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The diplomatic battle started hogging the headlines as Argentina began criticizing Britain for its plan to drill for oil and gas in the waters north of the Falkland Islands
By MERLIN FLOWER for OIL-PRICE.NET, 2010/02/18

This could be the script of any Hollywood blockbuster: The recent spat between Argentina and the UK over oil in the Falkland Islands. For, there is a conflict, two or more protagonists, oil, money and drama.

The diplomatic battle started hogging the headlines as Argentina began criticizing Britain for its plan to drill for oil and gas in the waters north of the Falkland Islands. The Argentine foreign ministry in a statement said the government “firmly rejects plans of the United Kingdom to authorise operations of exploration and extraction of hydrocarbons in the area of the Argentine continental shelf under illegitimate British occupation”.

The Falkland Islands also known Islas Malvinas comprise about 340 islands. The majority of the population is British descent. The islands have been under British control since the year 1833. In 1982, a brief war called the Falklands war started when Argentina’s military junta invaded the Falkland Islands, South Georgia and South Sandwich Islands. The war which started on April 2, ended on June 14 after Argentina surrendered to Britain. Though the Falkland Islands is under British rule, Argentina still claims the islands, including them in the Argentine constitution.

For now, Argentina says that it would blacklist the oil exploration companies working in the region. “It’s not accidental that the oil companies involved are British, that is to say, the only ones that can really believe the chimera that the UK is peddling about the alleged legality of these commercial operations”, said official Argentine sources.

On the other side, British reaction has been subdued. The Financial times reported a UK diplomat as saying that the UK Prime Minster, Gordon Brown was anxious to “avoid military confrontation”. A spokesperson for the UK embassy in Argentina said “We have no doubt about our sovereignty over the Falklands Islands and the surrounding maritime area.” And that “The Falkland Islands government is entitled to develop a hydrocarbons industry in its waters and there is a long-standing policy to support this”.

Argentina says that Britain continued to ignore the UN resolution to renew dialogue on the sovereignty of the South Atlantic islands. In 1995, both the countries signed a joint declaration to cooperate on off shore oil explorations around the Falkland Islands. In 2007, Argentina voided the 1995 oil and gas exploration declaration with the UK, which was on suspension for five years. Meanwhile, the UK wants to extend its rights to areas surrounding the islands.

Why the waters around Falkland Islands are important?

The reason is simple to state: The areas around Falkland Islands are said to have one of the world’s largest reserves of oil, mainly in the north basin. There are reserves in the South and East of Falkland islands as well. The British Geological Survey estimates the oil at about 60 billion barrels. The hydrocarbons in the basins were discovered in 1998 itself by companies like Shell and Amanda Hess. But soon after oil prices fell-$12-15 per barrel- and with it ended the efforts to drill for oil.

But now that technology, skill set and oil prices have improved, the companies are able to contract rigs for the exploration with improved resources. Ben Romney, a Desire Petroleum spokesman said, “With the rise in oil prices and the worldwide search for new oil and gas services, it has now become more than commercially viable for this work to begin”. The oil well costs about $25million-$30million in the north basin where drilling depth reach 500m. It would cost $30million-$35million in the south basin as the depths are higher at 3,000m.

The major players:

Six companies hold licence for oil exploration in the region- Desire, Falkland Oil & Gas, Rockhopper, Borders & Southern, Argos Resources and Arcadia (the last two are private companies)

Desire Petroleum PLC (LSE: DES): It has licence in the north basin. The company expects to recover oil worth about 3 billion boe in four wells. Its rig, Ocean Guardian is expected to arrive in Falkland Islands this week, to drill 100 miles offshore.Rockhopper (LSE: RKH): Has licence in north basin. Expecting oil worth 4.3 billion boe. Borders & Southern (LSE: BOR): Licence is in south basin. Not ready to speculate on the amount of oil, yet. Falklands Oil & Gas (LSE: FOGL): associated with BHP Billiton. Licence for drilling in east and south basin. Estimates the oil to be about 60 billion boe

Last June, Phyl Rendell, Falkland Islands Director of Minerals and Agriculture had this to say about the South American influence, “Their political stance and restrictions on our movements are harmful to our economic development. And we are striving to develop our economy with that threat over us”.

Indeed, the potential benefits of oil are huge:The government of Falkland Islands will benefit from the fees, rentals and taxes. The corporation tax has been set at 26% on profit with 9% royalty on production. This makes the Falkland Islands a profitable place to drillIt will benefit the Falkland Islands economy as the oil fields would be one of the largest fields in the world. There would be more investments, flights, international trade, tourism and job creationThough oil, if found, would take time to reach the market, once there, it would keep balance the oil prices. In turn, balanced (not too high or low) oil prices will help the world economy as a whole. It would be good news for the oil industry. Investor confidence would get a fillip and a possible domino effect of more investments for oil exploration would followThe oil in the region can, in a way, erode the monopoly of OPEC (The Organization of the Petroleum Exporting Countries) over world’s oil reservesOther obstacles:Considering the fragile eco-system of the region and with the exploration set to begin in full swing, it might be a challenge for the Falkland Islands government to protect the eco-systemThe exploration for oil in the area is a huge risk. In case no oil is found, the loss would count to billions of dollar

In later developments, the diplomatic salvo between the countries reached a crescendo with Argentina preventing a ship from loading a cargo of pipelines-said to be for oil exploration. The group that owns the cargo, Techint has said that the pipes were heading towards the Mediterranean ports. To which the Argentine foreign ministry stated: “There is evidence that the ship was being used to supply material linked with the oil industry activities that are being illegally promoted by Britain in the Malvinas (Falkland Islands)”.

A bull-blown conflict may not yet be a possibility as Britain’s Foreign Secretary, David Miliband expressed confidence in dialogue. “I think the Argentinean government has got many more areas to co-operate with the UK than to disagree about,” he said. Not to forget, the UK military has base near Port Stanley so security may not be a problem for the drilling companies.

The co-operation between the countries will help in the smooth execution of the exploration process. The demand for oil is growing; the IEA has predicted oil demand to grow by 120,000 barrels per day in 2010. So, every potential field has to be tapped wherever possible-except, if possible, in environmentally sensitive spots. Renewable energy sources are still not in a position to compete against oil, and so oil exploration ought to be encouraged. Investments have started pouring into oil exploration and it has to keep going, starting with the Falkland Islands.

Alange Energy experieced 27% increase in revenues 1Q 2010

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TORONTO, May 26 /CNW/ – Alange Energy Corp. (TSXV: ALE) (“Alange Energy” or the “Company”) announced today the release of its unaudited interim consolidated financial results for the three months ended March 31, 2010, together with its Management’s Discussion and Analysis. These documents will be available on the Company’s website at www.alangeenergy.com and at www.SEDAR.com.

In keeping with its strategy, the Company announced its second consecutive quarter of growth in its share of production from its oil and gas properties since it went public in July 2009, resulting in a 27% increase in revenues in the first quarter of 2010 to $10.5 million compared with revenues of $8.3 million in the final quarter of 2009. With its gross share of production (before deduction of royalties) averaging 2,305 barrels of oil equivalent (“boe”) per day, the Company exited the first quarter of 2010 with a daily production rate of 2,280 boe, up 7% from the end of December 2009. The Company’s daily production rate has since increased to approximately 2,550 boe per day at present and is expected to surpass 3,500 boe per day before the end of the second quarter of 2010. The Company expects to reach the 10,000 boe per day level early in the second quarter of 2011.

Luis E. Giusti, the Company’s Chief executive Officer, stated “the results of the first quarter of 2010 demonstrate our continued focus of our core assets, led by our continuing success in the exploration, appraisal and development campaign at Cubiro. With seven rigs currently active in the field, the second quarter will see the Company continue to execute its growth strategy and expand our resource base within our portfolio”.

For the quarter ended March 31, 2010, the Company generated net operating income from its oil and gas operations of $1.0 million. After exploration, general and administrative expenses and a $3.1 million non-cash foreign exchange loss, the Company reported a net loss of $5.7 million or $0.01 per share in the first quarter of 2010 compared with a net loss of $2.7 million or $0.02 per share in the first quarter of 2009.

The Company has recently succeeded in its efforts to put in place additional debt financing for up to $27.0 million that, together with its $6.6 million of cash and restricted cash balances at March 31, 2010 and cash flow from operations, will be available to fund its $76.0 million capital program planned for 2010. To date, the Company has executed drawdowns totalling $9.0 million from two term loans and expects to receive an additional $15.0 million from a third term loan by mid-June 2010. The Company may also receive up to an additional $3.0 million of proceeds from a second disbursement under one of these term loans. The loans, primarily with local Colombian banks, have terms ranging from two to three years, are repayable in equal monthly blended payments of principal and interest, and are secured by a pledge of oil sales from Cubiro required to meet the monthly term loan repayments.

Management will hold a conference call on Thursday, May 27, 2010 at 9:00 a.m. Eastern Time to provide an operational update and to discuss the first quarter results. Analysts and interested investors are invited to participate as follows:

Toronto & International: 1 (647) 427-7450 North America: 1 (888) 231-8191 Conference ID: 78236703

Playback of the conference call will be available starting two hours after the call’s completion and up to 11:59 pm Eastern Time on June 10, 2010. To access the playback, please call either 1-800-642-1687 (toll free) or 416-849-0833 with the password 78236703.

Alange Energy is a Canadian-based oil and gas exploration and production company, with working interests in 12 properties in four basins in Colombia. Further information can be obtained by visiting our website at www.alangeenergy.com.

Cautionary Note Concerning Forward-Looking Statements

This press release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the company believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates and/or assumptions in respect of production, revenue, cash flow and costs, reserve and resource estimates, potential resources and reserves and the company’s exploration and development plans and objectives) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the company based on information currently available to the company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on the company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; the possibility that actual circumstances will differ from the estimates and assumptions; failure to establish estimated resources or reserves; fluctuations in petroleum prices and currency exchange rates; inflation; changes in equity markets; political developments in Colombia; changes to regulations affecting the company’s activities; uncertainties relating to the availability and costs of financing needed in the future; the uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the heading “Risk Factors” and elsewhere in the company’s periodic reports filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

Information in this press release expressed in barrels of oil equivalent (boe) is derived by converting natural gas to oil in the ratio of six thousand cubic feet (mcf) of natural gas to one barrel (bbl) of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

For further information: Michael Davies, Chief Financial Officer, (416) 360-4653, ext. 224