Fast forward to May and the company has reportedly frozen its Kurdistan contract under pressure from an infuriated central Iraqi government, which insists all oil contracts must go through Baghdad. Worse, it has been excluded from the country’s lucrative fourth oil-and-gas licensing auction, covering 12 new exploration blocks, which could add 29 trillion cubic feet of gas and 10 billion barrels of oil to Iraqi reserves.

Similarly, Repsol YPF SA has seen its 51% stake in YPF, Argentina’s biggest oil company, expropriated by the government, abruptly locking out the Spanish giant from participating in one of the largest shale gas plays in the world.

As major oil companies enter geologically promising but politically challenging jurisdictions to replenish their reserves, they face tremendous regulatory uncertainty. This instability presents the Canadian energy sector with a distinct advantage over emerging markets, as long the country can raise its own regulatory game.

“If you look at the Top Five countries for oil reserves — Saudi Arabia, Venezuela, Iran, Iraq and Canada — Canada is the only one that does not have a national oil company. We are the only one open for business,” said Reynold Tetzlaff, national energy leader at PwC Canada.

Canadian proven crude reserves stand at 171 billion barrels, behind Venezuela (297 billion) and Saudi Arabia (264 billion). Almost 81% of global crude reserves are locked in OPEC countries and managed by state-owned enterprises, leaving major oil companies with a mere sliver of the pie to fight over (see table).

“A lot of the oil is tied up with state-owned companies, so only about 20% of global crude is accessible to non-state owned companies,” Mr. Tetzlaff said. “If you take Canada out of that equation, the number drops to 7% — these large companies need to continue to look for replacement reserves.”

There is another good reason to hunt for fresh acreage: 75% of today’s oil was discovered before 1980, and while new technologies are prolonging the life of aging fields, statistics from BP PLC show the world’s proven crude reserves stand at 46.2 years of global production, compared to 118 years for coal and 59 years for natural gas.

The reserve-replacement situation could worsen as many oil-rich governments experience turmoil and tighten their grip on resources.

“We anticipate that so-called state capitalism will continue to be a negative driver, as it has been since mid-2010, since the poor economic backdrop makes the corporate sector a tempting target for governments wishing to boost their popularity or find additional resources to add to the relatively low levels of social protection across most emerging economies,” said Mehmet Beceren, a strategist at Deutsche Bank.

With countries as diverse as Iran, Venezuela, Libya and Nigeria distracted by political unrest, mature oil markets are back in the spotlight as they experience their own energy boom thanks to a surge in development of unconventional resources.

Indeed, North America will likely be the world’s biggest recipient of energy investments in 2012, with companies expected to spend $392-billion on upstream capital and operating expenditures in the region, a recent IHS CERA forecast says.

“Without a doubt North America and Canada is seen as a business-friendly environment that welcomes foreign investment, and a safer place to do business than other places in the world,” said Wayne F. Chodzicki, Canadian and global head of oil and gas at KPMG.

While Canadian jurisdictions can claim to be more welcoming than places like Iraq and Argentina, at least 50 jurisdictions are rated higher than the Alberta oil patch, according to the Fraser Institute.

The institute’s 2011 Global Petroleum Survey ranked Alberta as the 51st most-attractive jurisdiction worldwide for investment, out of 135 regions, below countries like Chile and Hungary. Saskatchewan (11th), Manitoba (12th) and Ontario (25th) fared better than Alberta, but no Canadian jurisdiction made it into the Top 10.

The Fraser Institute annually queries more than 500 petroleum industry executives on barriers to investment in upstream oil and gas development in jurisdictions around the world.

Gerry Angevine, senior economist at the Fraser Institute’s Global Resource Centre, expects the findings to be similar in the 2012 edition, although there might be some regional surprises.

“Alberta shot itself in the foot with their so-called new royalty framework … the industry became irate and reallocated development dollars to Saskatchewan and British Columbia … When the Alberta government went back to where things were in 2011, we saw some improvement, but Alberta still didn’t get back to anywhere near where it was when we started the survey.”

Similarly, Quebec is ranked 91st as the province “can’t make up its mind” regarding fracking, Mr. Angevine said, citing the example of Talisman Energy Inc., which suspended operations in the Lorraine/Utiaca shale play after the province decided to conduct a two-year review on fracking.

Joe Oliver, the Natural Resources Minister, thinks the country’s regulatory system in “broken” and has initiated a number of reforms to reduce duplication and set a two-year timeframe to decide on projects.

“We certainly hear from our clients about the number of regulatory reviews and the different levels of government and the [desire] for some simplification. The recent announcement is welcomed in the industry,” KPMG’s Mr. Chodzicki said. “But speed to market is very important to unlock the potential revenue streams.”

Opposition to shipping Alberta oil sands via Keystone, Northern Gateway and Trans Mountain pipelines is well-documented, which has delayed efforts to export crude and natural gas to Asia.

To be sure, companies are hedging their bets and looking far and wide for discoveries. From greenfield jurisdictions such as Kenya and newly democratic Myanmar to offshore Mozambique and the Arctic, major players are scouting around for exploration. Clearly, as global oil demand shows no sign of receding, companies are not shying away from the risks associated with some areas of the world, Mr. Chodzicki said.

But countries such as China, India, Japan and South Korea are also conscious of balancing high-risk plays with more predictable suppliers. This especially rings true after they were left scrambling to replace Iranian oil after Tehran was subjected to crippling sanctions by the United States. The hunt for stable jurisdictions is a crucial pillar of emerging markets’ energy security strategy.

“Sure, our energy strategy isn’t as solid as it could be,” Mr. Tetzlaff said. “We have some inter-provincial and pipeline issues going on within Canada, but it’s still probably not enough to scare away companies because they know we are open for business, and they are banking on the fact that we are going to get it figured out. It’s a matter of time.”

“Our gas drilling locations are totally mothballed right now,” George Fink, chief executive of Bonterra Energy Corp. told the CIBC 2012 Energy Conference held in Toronto in mid-April. “You can’t keep losing money when you’re drilling, [and] $2 for natural gas is not sustainable when costs are closer to $5 or $6.”

Mr. Fink’s company is focused on drilling oil wells, while fellow Calgary firm Perpetual Energy Inc. has also moved away from gas in order for its balance sheet to be “substantially restored to health.”

“Our balance sheet has been a concern to our investors and we have taken steps to deal with this,” Cameron Sebastian, vice-president of finance at Perpetual, said in a presentation at the conference. “Our gas marketer is being kind of morbid these days; he wants [natural gas] prices to go as low as they possibly can to get this capitulation over with, [but] we have been waiting for that for the last two years and the price keeps going lower. That is why you are seeing all this diversification now.”

Shallow gas makes up less than 33% of Perpetual’s production, down from 100% in 2007. That production has been replaced mostly with more lucrative oil projects, which the company has grown from just 100 barrels per day in 2010 to more than 3,500 bpd currently.

Even Encana Corp., Canada’s largest gas producer with a $13-billion market cap, has been selling multibillion-dollar assets and focusing on liquids, hoping to compensate for the depressed price of North American natural gas, which hit US$1.98 per 1,000 cu. ft. in New York April 12, the lowest price since Jan. 28, 2002.

“Those kinds of options aren’t always available to the junior sector,” said Gary Leach, executive director of the Small Explorers and Producers Association of Canada.

“The fact is you can’t turn yourself from a gas producer overnight to a crude oil producer, [and] if you are trying to get rid of assets that are natural gas weighted, the prices being paid are low and in many cases there may not be any real buyer interest.”

Such is the situation Birchcliff Energy Ltd. now faces. The Calgary company spent nearly six months on the auction block before chief executive Jeff Tonken terminated the corporate sale process in late March, having received just two non-binding offers; neither of which represented “sufficient value for shareholders,” Mr. Tonken said at the time.

Having seen its share price plummet nearly 40% while it was up for sale, Birchcliff was saved by Seymour Schulich, the billionaire Montreal business magnate who is also the company’s single largest shareholder with a 26% ownership stake. In early April, Mr. Schulich put in another $38-million to help keep Birchcliff afloat.

Meanwhile, lacking any alternative at least for the time being, the company remains committed to developing its natural has assets. Nearly two-thirds of its drilling and development budget for 2012 is allocated for natural gas wells and plans are to double the processing capacity of its Pouce Coupe South natural gas plant from 60 mmcf per day to 120 millions of cubic feet (mmcf) per day by the end of this year. Internal processes to gain regulatory approval to double that figure again to 240 mmcf are already underway.

Yet a sole philanthropic shareholder and some bought deal financing can only support those efforts for so long. In the end, only a turnaround in North American natural gas prices will allow Birchcliff to survive.

Production overall has been dropping. Canadian companies produced 5.9% less natural gas in January 2012 than in January 2011, according to a Statistics Canada report published this month. Crude oil production, meanwhile, grew 8.4% during the same period.

Eventually, the corresponding reduction in supply will set the stage for a catalyzing event to boost demand, which will in turn drive prices higher. That event could still be years away, Mr. Leach said, as it will likely require major changes south of border.

“We are starting to see a trend in the United States of some of the power generation utilities switching to burning more gas,” said Mr. Leach, noting U.S. electrical power is more than 50% generated from burning coal but that many coal plants are capable of running on natural gas as well.

“If there is any glimmer of hope in increasing gas demand in North America on a larger scale it is going to have to come from the power sector and to a lesser extent from the industrial sector.”

Goldman Sachs expects gas prices to return to US$4 per 1,000 cubic feet levels by mid-2013 and recommends investors go long on the sector, though choosing which stock to support will be critical since many producers will be unable prosper until then.

“We are looking at solutions that are going to take 5, 10, 15 years for improvement on the demand side, so how do you get through the next quarter or the next year or the next two years?” Mr. Leach said.

“That is the challenging factor for Canada’s oil and gas juniors.”

The deal may not yield commercial oil production for years, but for Eni it secures a foothold in an untapped and strategically important new province, and for Russia, it brings in the capital needed for long-term projects to keep its oil flowing.

Russia, the world’s largest oil producer, is facing declining output at Soviet-era oilfields and, dependent on energy for over half its revenue, Putin’s government has redoubled efforts to bring in foreign investment in his final days as prime minister before he returns to the presidency.

In the six weeks since he won the presidential election, Putin has approved sweeping tax breaks to attract foreign investors to develop new offshore fields, and presided over a landmark Arctic drilling deal between Rosneft and U.S. ExxonMobil.

Eni, which had a commercial relationship with the Soviet energy industry and started producing gas here last week in a joint venture with two Russian companies, has said “giant projects” in Russia are key to plans to boost overall output.

“Today Eni is moving on to work in Russia in a new quality. We are talking about work on the continental shelf. This is a large-scale and long-term operation,” Putin told a signing ceremony.

“I am sure these offshore projects will be successful, and the Russian government will do everything it can to support these kinds of projects.”

The deal is modelled on the Exxon-Rosneft pact, with Eni taking a minority stake of 33 percent in the exploration venture and shouldering up-front investment costs to develop combined recoverable resources estimated at 36 billion barrels, equal to about 14 months of total global oil consumption.

Rosneft will gain access to Eni projects outside Russia – part of a Kremlin strategy to expand the country’s oil industry abroad and gain know-how to apply to projects at home.

“We have started discussion over possible destinations, which could be of an interest to both parties,” Eni Chief Operating Officer Claudio Descalzi told a briefing after the signing.

“Particularly, we are talking about North Africa, Alaska, the U.S. and Northern Europe. In the next few months we will start discussions over concrete destinations of the cooperation and projects.”

The prize for foreign producers is access to reserves. At 18 billion barrels, Rosneft’s proven reserves are the largest of any listed oil company and enough to sustain its current rate of oil output for 21 years.

But it estimates its hydrocarbon ’resources’ – which have yet to be explored and appraised – at more than 10 times higher at 206 billion barrels.

That would make Rosneft’s offshore resources larger than the 100 billion barrels held in Brazil’s ’pre-salt’ province in the Atlantic basin, which is yielding a production bonanza for state-controlled oil firm Petrobras.

About two-thirds of Rosneft’s resources are in the Arctic offshore, much of it icebound with no infrastructure – a daunting prospect for investors who face tens of billions of dollars in costs to develop the province from scratch.

A QUESTION OF TAX

Putin’s announcement that Russia would lighten the offshore tax burden – by scrapping duties and cutting mineral extraction tax – has triggered a “snowball effect” among foreign majors rushing to seek deals, one industry source said.

The proposed tax regime, which has yet to be made into law, is designed to guarantee investors an economic rate of return on their investment and predictable taxes for 15 years.

“None of this could have happened had you not taken action on the Russian tax system,” Eni Chief Executive Paolo Scaroni told Putin in Russian translation.

Foreign players have long been deterred from investing in Russia by onerous energy taxes that capture 90 cents on the dollar at the margin for each barrel of crude exported.

Only BP has a big onshore presence through its 50 percent stake in Russia’s No.3 oil firm TNK-BP – a troubled but profitable venture that ended up getting in the way of the British major’s own offshore deal with Rosneft last year.

Industry and political sources say Putin’s returning to the Kremlin on May 7 has opened the way for the furious dealmaking by state energy companies.

Deputy Prime Minister Igor Sechin, a Putin confidant, has been behind a push to fix the tax regime and secure deals for Rosneft before Putin names a new team, which may trigger the loss of his formal brief as Russia’s top energy official.

A QUESTION OF TIMING

Arctic oil, however, will be a long time in coming for the Eni-Rosneft venture. While exploration drilling in the Black Sea’s Western Chernomorsky block is due to start in 2015-16, drilling in the Barents Sea will begin in earnest only in 2026.

Eni has had operations in the Norwegian sector of the Barents Sea since 1965, and Scaroni has named the region as a key area for the group’s strategic development.

Eni announced in January that oil and gas had been found at the Havis project, around 200 km off the Norwegian coast, in which it has a 30 percent stake. Norway’s Statoil, with a 50 percent stake, is operator of the project.

Rosneft earlier this year won the right to develop the two Arctic blocks covered by the agreement, called Tsentralno-Barentsevsky and Fedynsky. A third block received at the same time – Perseevsky – was not covered in the deal.

© Thomson Reuters 2012

For the current quarter, the company maintained its production forecast of 190,000 to 235,000 barrels of oil equivalents per day (boe/d) as it expects output at its Long Lake oil sands project to move closer to capacity.

The company is ramping up production at the $6.1-billion Long Lake project, which has never reached its nameplate capacity of 72,000 barrels of bitumen per day.

Under interim Chief Executive Kevin Reinhart, Nexen is also planning to cut downtime at the Buzzard oil field in the North Sea, which has struggled over the past year with reliability issues at the site, resulting in frequent downtime.

The company said it expects total production to continue to rise throughout the year and into 2013.

Nexen posted a first-quarter profit of $171-million, or 32 cents per share, down from $20-million, or 38 cents per share, a year ago.

Net sales rose 3 percent to about $1.69-billion, helped by a 10 percent increase in the realized prices for oil and gas.

Cash flow from operations, a key measure of the company’s ability to fund development, rose marginally to $670-million.

First-quarter total production before royalties fell 12 percent to 202,000 boe/d, the company said.

Nexen said results were hurt by reduced production at its Syncrude oil fields in Alberta due to unplanned maintenance, which is expected to continue into the second quarter.

Nexen shares closed at $19 on the Toronto Stock Exchange on Tuesday. They have lost about 18% in the past year.

© Thomson Reuters 2012

The lawsuit stemmed from the November 2011 collapse of BP’s plan to sell its 60 percent stake in crude oil producer Pan American Energy to Bridas, which owns the remainder and is Argentina’s second-largest oil and gas company. Bridas is half-owned by Chinese oil giant CNOOC Ltd.

According to the complaint filed in U.S. District Court in Manhattan, the sale agreement called for BP to pay the $700 million if Bridas released it from various claims.

The British oil company said it had wired the money after the transaction fell apart, only to have Bridas return it, claiming that the sale agreement was void from the start.

Nonetheless, BP said Bridas later demanded the money “without prejudice to any of Bridas’ legal rights or positions.”

The Argentine company “is seeking to have it both ways,” BP said. “Bridas apparently continues to take the position that it was fraudulently induced to enter into the share purchase agreement and related contracts. That claim is frivolous.”

Bridas did not immediately respond to requests for comment. The Buenos Aires-based company had in November blamed “legal issues and the way BP handled the transaction” for the collapse of the sale.

BP is seeking a court order allowing it to pay the fee and effectively put the failed sale behind it.

Alternatively, BP asked that, if the court voids the sale agreement, it also declare that Bridas does not deserve the fee.

BP said the parties had agreed that disputes could be resolved in a New York court.

A sale of the Pan American stake was part of BP’s push to sell assets and raise cash to cover expected legal and cleanup costs from the 2010 Gulf of Mexico oil spill.

Chief Executive Bob Dudley told analysts last October that the sale was no longer as important to the London-based company and that it was “absolutely fine” if BP held on to the stake.

CNOOC bought half of Bridas from Argentina’s Bulgheroni family for $3.1 billion in March 2010. The brothers Carlos and Alejandro Bulgheroni are together worth $5.1 billion, Forbes magazine said last month.

The case is BP Argentina Exploration Co et al v. Bridas Corp et al, U.S. District Court, Southern District of New York, No. 12-03170.

© Thomson Reuters 2012

The shutdown is likely to cause delays in loading of Forties crude, which is one of the four streams used for the global dated Brent price benchmark and has been hit by repeated output problems at the field since last year.

A spokesman for the UK Health and Safety Executive said: “HSE is aware and an investigation has started”. He declined to give further details.

Calgary-based Nexen could not be reached for immediate comment.

Output of the Buzzard oilfield fell to less than half on Saturday and was shut down completely on Sunday, traders said. The oilfield normally pumps about 200,000 barrels of crude oil per day.

It is expected to return to full production in 24-48 hours, they added.

“We have not heard about cargo delays yet but it is inevitable. At least some minor ones,” one trader said.

© Thomson Reuters 2012

Ministers had been expected to vote on the regulations in June as part of EU efforts to reduce greenhouse gas emissions.

But the official, who spoke on condition of anonymity, said EU member states would not be asked to decide until early 2013 on the scheme, part of the EU’s Fuel Quality Directive, which would rank tar sands oil as more polluting than other fuels.

[np-related]

The fuel ranking plan has triggered intense lobbying from Cananda, one of the world’s largest tar-sands oil producers, as well as opposition from some EU member states whose oil firms are active in such unconventional crudes.

The impact assessment will analyse the consequences of the law on fuel suppliers and other stakeholders, the source said.

“The proposal will not be submitted to the (European) Council before early 2013,” an EU source said, referring to the body that brings together EU member governments.

“We have decided to have an impact assessment before submitting the proposal to the Council,” said the source.

POLLUTING VALUES FOR FUELS

EU member states approved the Fuel Quality Directive in 2009, with the aim of cutting greenhouse gases from transport fuel production by 6 percent by 2020, as part of a wider set of green goals.

But intensive lobbying meant it was not until October last year that the Commission proposed detailed rules for implementing the law.

They include reporting requirements and carbon emission “default values” for difference kinds of fossil fuels for ranking the fuels by their overall greenhouse gas output.

Tar sands have been ascribed a value of 107 grams per megajoule of fuel, making it clear to buyers that it had more impact than average crude oil at 87.5 grams.

A series of technical meetings culminated in February in failure to agree on the plan.

Both Canada and the European Commission declared victory, with EU Climate Commissioner Connie Hedegaard saying at the time that she had feared outright defeat as a result of lobbying.

The EU source said on Friday that the decision to carry out an impact assessment was intended to win over waverers.

“We did not have a qualified majority against or in favour. We want to gain the support of those who are in doubt,” the source said.

“The idea is to address a number of concerns raised by stakeholders and member states.

“I can’t pre-empt the result, but we’re confident it will be favourable. We’re totally committed to getting this proposal through.”

Impact assessments, carried out by independent analysts, are a standard procedure in EU law-making, but the Commission had thought it unnecessary in ranking fuels because it was only the means of implementing a directive that had already been agreed.

The lobbying, however, was so extensive, the EU source said, there was a feeling in the Commission it would be a way to muster support.

Canada has argued the draft law is unfair to Canadian oil and that other fuel sources are also carbon intensive. The oil industry as a whole has said it would be an excessive administrative burden, potentially extremely negative for already struggling EU refineries, for instance.

An independent report carried out by a group of consultancies and published early this week found the cost would be negligible, although over time the law could discourage investment in the most carbon-intensive sources of crude, which environmental campaigners say is entirely appropriate.

© Thomson Reuters 2012

The company said it expects strong growth outside North America, which has been the key profit driver in recent years.

“We maintain our positive view on the international markets and expect the rig count to grow by more than 10 percent in 2012 through strength in exploration and deepwater activity as well as in key land markets,” Chief Executive Officer Paal Kibsgaard said in a release.

Oil companies have moved to tap into reservoirs in ever-deeper waters around the globe in recent years, triggering a boom for the service companies and drillers that can earn billions from the expensive projects.

“We believe the key to the (Schlumberger) story is the acceleration of international and deepwater activity which should escalate in 2013 and beyond,” UBS analyst Angie Sedita said in a note to investors after the earnings release.

Schlumberger said strength in the Gulf of Mexico helped offset weaker onshore business in North America, and it extended contracts to work off Brazil, an area that energy companies believe could hold vast amounts oil.

That deepwater business helped offset some weakness in pricing for hydraulic fracturing services, or “fracking.” Schlumberger warned that pricing pressure in U.S. natural gas basins, where activity is slowing down, had moved to liquids-producing areas as well.

Fracking demand has been a bright spot for the industry in recent years as energy companies tapped into new discoveries across the United States.

But that has helped create a glut of natural gas that has driven down prices for the fuel by more than 60 percent over the past 10 months, “with little likelihood of short-term recovery,” Schlumberger said.

First-quarter net profit rose 39 percent to $1.3 billion, or 97 cents per share, from $944 million, or 69 cents per share, a year earlier.

Excluding a one-time charge, earnings per share of 98 cents a share came in slightly above the analysts’ average estimate of 97 cents, according to Thomson Reuters I/B/E/S.

Revenues rose to $10.6 billion from $8.7 billion a year earlier.

Nearest rival Halliburton Co defied some of the worst predictions by reporting a higher-than-expected profit on Wednesday, and said it expected the downward pressure on frack pricing to ease up later in 2012.

Schlumberger shares, which have fallen 19 percent in the past year, climbed 1.5 percent in premarket trading.

© Thomson Reuters 2012

Encana, Canada’s largest natural gas producer, said in February that it would sell a 40% stake in its British Columbia gas field to Japan’s Mitsubishi Corp in a $2.9- billion deal.

Toyota Tsusho, part of Toyota Motor Corp, paid $100-million and will invest about $502-million over seven years to buy a 32.5% royalty interest in about 4,000 existing wells and 1,500 potential drilling locations.

Encana said in February it would cut spending on some of its North American dry gas operations including the Alberta field.

Front-month U.S. natural gas futures NGc1 slid to a 10-year low early Thursday as record-high supplies pressured prices even though the government reported a weekly inventory build in line with market expectations.

Encana shares, which traded above the $50 mark in 2008, have lost about 14% of their value in the last month. They closed at $18 on Thursday on the Toronto Stock Exchange.

© Thomson Reuters 2012

These and other challenges will be evident in the bottom lines of energy companies as they announce their first-quarter figures from April 25 onward.

So troubling is the issue of Western Canada Selects discounts that it merited a page-and-a-half in the Bank of Canada’s April Monetary Policy Report.

“This evolution has been driven by supply factors and the fact that the price of oil that Canada imports (more closely tied to Brent) has increased, while the price of oil that Canada exports (more closely tied to WTI and WCS) has declined,” the bank said.

Indeed, WCS has been trading at a US$35.50 discount to WTI (37% below the U.S. crude) on average, according to CIBC World Markets Inc. figures. At current levels, the Canadian oil industry would post an opportunity cost of $18-billion a year, or $50-million a day, the bank says.

Price differential was hardly the only concern — in some cases Canadian producers could not get their produce to market due to unscheduled outages.

In mid-February Canadian Natural Resources Ltd. shut down its oil sands plant to complete “an unplanned maintenance” and reduced its 2012 annual production target for the plant. The production disruption reportedly reduced crude oil output by around 100,000 barrels per day (bpd) and may have shaved off 0.1% of Canada’s GDP in February, according to one estimate.

Meanwhile, Suncor Energy Inc. shut an upgrading unit for up to five weeks of unplanned repairs, with daily production averaging 140,000 bpd, less than half of its 350,000-bpd annual production target. Syncrude Canada Ltd. also had a 100,000-bpd upgrading unit down for extended maintenance.

All of this could make for some sober reading come April 25.

“[The outages] had a negative impact on most Canadian oil producers with realized prices expected to be down quarter on quarter,” said Kyle Preston, an analyst at National Bank Financial. “As a result of the modest production growth and lower realized pricing, we are forecasting a 9% decrease in cash flow per share (CFPS) for the seniors and 26% decrease for the intermediates.”

Most analysts expect first-quarter results to be mixed, with producers such as Nexen Inc. and Talisman Energy Inc., which have significant exposure to Brent, set to fare better than their WCS-exposed counterparts Cenovus Energy Inc. and Canadian Natural. Integrateds, such as Cenovus, Suncor, Imperial Oil Ltd. and Husky Energy Inc., should also benefit from their diversity, and as the WCS discounting works in their favour.

“Producers with significant exposure to unhedged natural and heavy oil/bitumen will likely record sharp drops in CFPS sequentially. For instance, we forecast that Canadian Natural Resources’ CFPS will be down approximately 36% from Q4/2011 and that MEG Energy’s will decrease approximately 49%.”

CIBC’s top pick, Suncor, is also expected to beat consensus by approximately 5% and may announce a 20%-to-30% dividend hike on top of its current $2-billion share buyback.

Gas blowout

At least the WCS discounts were on rising prices. For Canadian gas companies, the situation was far worse as natural gas prices on the NYMEX fell to 10-year lows on the back of a gas glut both sides of the Canadian border. First-quarter prices averaged US$2.43 per million cubic feet (mcf), with AECO, the Alberta gas trading price, averaging $2.12 mcf — the lowest on record.

“You can’t have the warmest first quarter on record, or at least back to 1895 — a staggering 21.3% warmer normal for all of the U.S. on average, with a similar impact north of the 49th parallel — and not feel the impacts across the board, be it lower natural gas consumption on utilities, lower natural gas and propane prices, and lower interruptible load on U.S. pipelines,” said Carl Kirst, an analyst at BMO Capital. “Still, for all the bracing of some bad quarterly prints, we see most of the headwinds here as temporal, not structural … ”

But for now, the pain for Canadian gas companies will persist.

Continued robust production levels associated with liquids-rich gas drilling, combined with weak weather-related demand, has pushed storage to record levels in both Canada and the U.S., compelling Barclays Capital to be bearish on the prospects for near-term natural gas prices.

“Our Q2 and Q3 assumptions are sub-$2/mcf and even these figures may prove optimistic,” said BarCap’s Grant Hofer. “Indeed, North American storage levels — and Canada in particular — point to full storage by mid/late Q3, absent a hot summer and significant switching from coal to gas, which is expected to be a major factor balancing the market.”

In fact, Mr. Hofer has done away with any stock-picking among mid-cap gas companies as their cash flows decline close to 20% on average. The analyst thinks ARC Resources Ltd., Bonavista Energy Corp., Enerplus Corp., Peyto Corp. and Progress Energy Resources Corp. may trim spending this year due to the grim gas outlook.

Meanwhile, CIBC analyst Andrew Potter is forecasting Encana Corp., the country’s largest gas company, to generate CFPS of US$1.24 – down 6% sequentially, affected largely by deteriorating gas prices. “We forecast Encana’s production to be 3,392 MMcfe/d, up 2% year on year, but down 6% from last quarter. “

Piped up

Pipeline giants Enbridge Inc. and TransCanada Corp. continue to find themselves in the news this year, after a roller-coaster 2011. For Enbridge, news of upsized Spearhead and Seaway pipelines was tempered with U.S. rival Kinder Morgan Inc.’s announcement that it would double capacity on its TransMountain pipeline, an alternative to the proposed Northern Gateway.

BMO’s Mr. Kirst expects Enbridge Inc.’s results to be lower given weather in Toronto averaging 20% warmer than normal, and quarterly EPS to be 49¢, compared to 45¢ during the same period last year.

TransCanada investors had their share of news to digest: The company benefited from stronger-than-forecast power prices in Alberta and the U.S. Northeast, but was offset by greater outage days at Bruce Power and the expected drop in returns on the Canadian mainline.

Positive signals for the Keystone XL pipeline from President Barack Obama and the Nebraska legislature — although not relevant for the first quarter — ‘de-risks’ the stock.

TransCanada’s pipeline volumes may have fallen below budgeted levels due to the historically warm winter and high storage levels. “Earnings, however, will remain unaffected, and … ultimately this will be settled with a new tariff structure to be put in place by the National Energy Board (NEB), which we expect around year-end,” Mr. Kirst said.

LONDON – The eastern Mediterranean’s promise of energy riches has spurred some encouraging deals between governments, but deeper regional conflicts stand in the way of unlocking one of the world’s largest gas reserves, experts said on Thursday.

There is enough gas to power the region for generations, with exploration results showing over 100 trillion cubic feet (tcf) of reserves could lay untapped under the seabed.

But the findings, so far largely in waters off Israel and Cyprus, have also spotlighted land and maritime border disputes in the region involving Lebanon, Turkey and Egypt.

Some encouraging progress has been made.

Egypt and Cyprus defined their Exclusive Economic Zones (EEZ) in the Mediterranean in 2003, Lebanon and Cyprus theirs in 2007, and Israel and Cyprus agreed on their EEZs in 2010.

But experts say land border disputes will overshadow any wider negotiations over gas exploration for years to come.

“The land rules the seas. If you don’t have an agreed land boundary …you cannot state with any certainty where adjacent maritime boundaries begin,” Richard Schofield, senior adviser at Menas Borders, a territorial and boundary dispute consultancy, told a briefing in London.

“We have problems with almost every boundary in this region,” Schofield said. “None of this maritime stuff is worth a squat without a land border agreement.”

Lebanon has no diplomatic relations with Israel, Turkey does not recognise the Republic of Cyprus, which, along with the European Union, does not recognise Turkish-speaking northern Cyprus.

The longstanding border dispute between governments in Tel Aviv and Beirut stands in the way as maritime zones are usually based on extensions of land borders, Schofield said.

Difficulties with Israel’s claims could grow deeper still should a potential Palestinian state come into being.

“By any definition, the Mari-B gas field should in part go to Gaza and a potential Palestinian state,” Schofield said.

It has an estimated reserve of 1.3 tcf, enough to supply Israel’s gas demand for more than a decade.

The UN’s Convention on the Law of the Sea (UNCLOS), an international agreement from 1982, helps define national rights and responsibilities in maritime issues.

But Turkey and Israel have not officially endorsed it.

And in Egypt, which also hopes to find gas in its waters, there is uncertainty too, following the collapse of its government during last year’s Arab Spring uprisings.

LARGE GAS FIELDS

In Israel, the Tamar and Leviathan gas fields are amongst the biggest offshore findings in decades, with reserve estimates 8.5 and 16 tcf respectively.

Lebanon has said that small parts of the Leviathan field could be in its own waters, a claim Tel Aviv rejects.

Beirut is expected to start its own round of exploration licensing this summer.

The recently discovered Aphrodite gas field, which is estimated at 7 tcf, is largely in Cypriot waters, although some part of it could be in Israel’s EEZ.

But cooperation between Israel and Cyprus works well, with the two governments having a defined EEZ and joint exploration agreements in place.

Cyprus’ problem lies with Turkey.

Ankara has warned against unilateral exploration by the Republic of Cyprus, arguing that any mineral resource revenues would have to be shared with the Turkish claimed North of the island.

Egypt and Turkey have both said they would announce exploration licence tenders soon.

“Egypt and Turkey have been very encouraged by recent findings and they may announce licensing rounds very soon,” said Charles Gurdong, also a managing director at Menas Borders.

Finally, there is Syria which also has potential claims to gas in the region.

“Syria has been incredibly silent in this matter, and I doubt that this will change until the country settles down domestically,” Schofield said.

Thousands of people have been killed in Syria during a year-long popular revolt against President Bashar al-Assad’s rule, internationally isolating the country.

© Thomson Reuters 2012

First-quarter profit rose to $627 million, or 68 cents per share, from $511 million, or 56 cents per share, a year ago.

Excluding one-time items such as a $300 million charge for estimated losses from the BP Plc Gulf of Mexico oil spill two years ago, Halliburton’s earnings per share of 89 cents topped the average analyst estimate of 85 cents, according to Thomson Reuters I/B/E/S.

Chief Executive Officer Dave Lesar said the record North American revenue of $4.2 billion came as new oil drilling activity in the United States helped offset a drop in natural gas drilling.

But Lesar warned that weak U.S. natural gas prices, which have fallen to their lowest level in a decade, and the disruptions caused by shifting supply chains, would contribute to lower margins in the region in the second quarter.

Halliburton is heavily exposed to the U.S. market relative to larger rival Schlumberger, which earned about two-fifths of its 2011 income in North America, compared with more than three-quarters for Halliburton.

Halliburton is the U.S. market leader in pressure pumping, used in hydraulic fracturing to extract oil and gas from shale. New technology has opened up new sources that are likely to keep prices low for years.

Its revenue rose 30 percent to $6.9 billion.

Halliburton’s shares rose 1.7 percent in premarket trading to $33.20.

© Thomson Reuters 2012

Suncor, Canada’s largest energy company, took the upgrading unit down on March 13 to fix a fractionator. It said it did not expect to change its annual production forecast for the 350,000 barrel a day project.

It said in March it had expected to produce an average of 140,000 bpd during the work.

Prices for Canadian synthetic crude surged as much as $10 a barrel to $11 under benchmark West Texas Intermediate when the company announced the unplanned maintenance. On Monday, light synthetic for May delivery was quoted at $1.50-$2 a barrel under WTI.

Syncrude Canada also had one of its upgrading units, the 100,000 bpd Coker 8-1, down for extended maintenance and there was no word yet on whether it had restarted.

© Thomson Reuters 2012

But the real issue facing Canada’s oil and gas service companies is the fact that many are eligible for the program but don’t apply. It’s one of the biggest missed opportunities the Canadian oil and gas industry faces today. And, overall, it’s part of a broader problem. Despite having one of the richest incentive programs in the world, Canadian companies are still playing catch-up to their world counterparts when it comes to improving innovation and increasing productivity. In fact, Canada spends 50% less on research and development (R&D) than the U.S. and 45% less than G7 countries.

Canada’s SR&ED program was originally established in 1984 to reward companies who developed and improved products or internal processes. Today the program provides approximately $3-billion in refundable and non-refundable tax credits annually. Provincial programs across the country also support SR&ED initiatives.

As part of the government’s continued commitment to supporting jobs and growth through innovation, this year’s budget includes a Western Innovation Program that will provide the financial support innovative small and medium-sized enterprises in the West need to stay competitive in a hot market.

On the downside, the basic tax credit for eligible expenditures is scheduled to decrease from 20% to 15% come 2014. This decrease will have the greatest impact on public companies and large private businesses that have only been eligible for non-refundable credits. The other major changes announced include a 5% year-over-year decrease in the overhead component of the program, as well as a 20% decrease to subcontractor costs and the elimination of capital expenditure funding by 2014.

Moving forward, companies will have to manage a $1.3-billion decrease in the SR&ED program over the next four years. That being said, companies serving Canada’s oil and gas sector typically perform their testing in the field or on the shop floor and won’t feel nearly the same force of these changes as those in Canada’s life sciences sector that depend heavily on the funding of capital equipment to complete their R&D work.

On the upside, these decreases will be supplemented by a $1.6-billion investment over five years in early-stage venture capital and funds for commercialization. This means new startups and early-stage growth companies, particularly those manufacturing and fabrication companies that provide the much-needed services and tools to Canada’s oil and gas industry, will have more access to capital funds from savings in the SR&ED program to reach the next level and compete on the world stage.

Canada’s oil and gas service companies can make the most of new and existing SR&ED initiatives by:

• Accelerating any planned R&D projects to take advantage of the full program before 2014
• Purchasing now any capital equipment required for SR&ED work
• Considering putting key self-employed sub-contractors on payroll

In today’s fast-paced, competitive market, Canadian companies can’t afford to miss out on the valuable opportunities for development tax credits available to them — no matter how time consuming or complicated the application process. This is especially true for small to medium-sized enterprises and early-stage ventures contributing to the development of new products and services in Canada’s thriving oil and gas sector.

The government is even going as far as to establish a pre-approval process to improve the consistency of the SR&ED claims process to encourage companies to apply. The benefits are clear: those that embed innovation into the very core of their business will be the strongest horses at the gate come 2014.

Robert Vander Wees is a Senior Manager in Ernst & Young’s SR&ED Tax Services group. He is based in Calgary.

In the latest quarter, the company produced 34,500 barrels of bitumen per day, up from 31,500 barrels per day in the fourth quarter.

Nexen’s $6.1-billion Long Lake project has a nameplate capacity of 72,000 barrels. But a series of technical and operating issues has plagued the project.

The company holds a 65% stake in the project, while China’s top offshore oil company, CNOOC Ltd, holds the remaining stake.

The Calgary-based company also said it has received regulatory approvals to proceed with the development of two drilling sites at Long Lake and Kinosis area.

© Thomson Reuters 2012

The wide-ranging deal will grant Rosneft access to three projects in North America, where Exxon is developing hard-to-recover reserves in West Texas, the Canadian province of Alberta and in the Gulf of Mexico.

The two companies will also seek to transfer know-how from those projects to develop Rosneft’s own vast reserves of so-called ’tight’ oil trapped in non-porous rocks like shale at three of its biggest fields in Western Siberia.

[np-related]

“Today really is a historic day … it marks the beginning of a new and broader relationship between our companies,” Exxon CEO Rex Tillerson told a signing ceremony hosted by Prime Minister Vladimir Putin at his Novo-Ogaryovo residence outside Moscow.

Exxon, the largest listed oil firm in the world, struck an initial partnership with Rosneft last August to search for oil in three blocks of Russia’s Arctic Kara Sea previously estimated by Rosneft to hold 36 billion barrels of recoverable reserves.

Those offshore riches are larger than Exxon’s entire reserve base at the end of last year, which totalled 24.9 billion barrels of oil and its natural gas equivalent.

Finalising that preliminary deal was contingent on Russia introducing a new tax regime that would make it economically viable for oil companies to shoulder the huge up-front costs of offshore exploration.

Putin last week supported reforms to offshore taxation that would eliminate export duties and lower Mineral Extraction Tax, clearing the way for Monday’s signing.

“The new regime will potentially provide the certainty needed to attract foreign investment into the Russian offshore,” analysts at Bank of America Merrill Lynch, led by Karen Kostanian, wrote in a note earlier on Monday.

Rosneft President Eduard Khudainatov said had written to four Russian oil companies – Lukoil, TNK-BP, Bashneft and Surgutneftegas – inviting them to participate in offshore projects.

Rosneft shares earlier rose by 1.8 percent before giving up their gains as Russian stocks weakened late in the session.

CLOSING OUT THE DEAL

For Exxon the partnership secures an Arctic prize that was coveted by British oil major BP before its own talks with Rosneft collapsed last May.

It also marks a turnaround for Exxon, which scaled back its involvement in Russia after its attempt to buy into Yukos – then the country’s largest oil firm – was thwarted by the arrest in 2003 of Yukos owner Mikhail Khodorkovsky.

Khodorkovsky was jailed for fraud and tax evasion, Yukos was bankrupted by back-tax claims and Rosneft snapped up its prime assets at auction to become Russia’s largest oil firm.

The partners confirmed they would invest $3.2 billion initially to search for oil in the Arctic and Black Sea in a venture to be two-thirds owned by Rosneft and a third by Exxon.

Russian Deputy Prime Minister Igor Sechin, an architect of the deal, said investments in the three Arctic Kara Sea blocks could eventually run to $200-$300 billion, and in the Black Sea to as much as $50 billion.

Sechin also said Exxon should be able to book the offshore reserves on a pro-rata basis as minority partner in the exploration joint venture.

Seismic work will begin in the Arctic blocks this year with a view to drilling a first exploration well in 2014. In the Black Sea, seismic survey work should be completed by mid-year and first exploration drilling in 2014-15, the firms said.

Russia, the world’s largest oil producer, needs to develop its offshore energy riches to meet its long-term goal of sustaining output at above 10 million barrels per day as flows from its oil-producing heartland of Western Siberia slow.

Analysts caution, however, that commercial offshore production is years – and possibly decades – away and applying to Russia the modern recovery methods that have boosted on-shore U.S. oil production of late could prove to be a quicker win.

TECHNOLOGY TRANSFER

Under the deal, Rosneft will gain 30 percent stakes in three projects in North America: The first project is developing ’tight’ oil in West Texas, the second covers 20 deepwater blocks in the U.S. Gulf of Mexico and the third is exploiting shale oil in Canada’s province of Alberta.

Seeking to apply that know-how in Russia, the partners will conduct a feasibility study into developing an estimated 1.7 billion tonnes of tight oil at Rosneft’s large Prirazlomnoye, Mamontovskoye and Priobskoye fields in Western Siberia.

The Exxon-Rosneft deal marks a personal milestone for Sechin as Putin – elected as president last month – prepares to form a new administration.

Outgoing President Dmitry Medvedev is expected to take on the role of prime minister in a job switch with his mentor Putin. Medvedev has a history of conflict with Sechin, whom he ousted as Rosneft chairman last year.

Sechin, who has been close to Putin for two decades, could cement his bid to stay on with the Exxon-Rosneft deal, although a move to one of the security structures that report directly to the Kremlin has also been mooted. He will join a briefing for analysts on the deal on Wednesday in New York.

© Thomson Reuters 2012

Researchers from the U.S. Geological Survey said that for the three decades until 2000, seismic events in the nation’s midsection averaged 21 a year. They jumped to 50 in 2009, 87 in 2010 and 134 in 2011.

Those statistics, included in the abstract of a research paper to be discussed at the Seismological Society of America conference next week in San Diego, will add pressure on an energy industry already confronting more regulation of the process of hydraulic fracturing.

“Our scientists cite a series of examples for which an uptick in seismic activity is observed in areas where the disposal of wastewater through deep-well injection increased significantly,” David Hayes, the deputy secretary of the U.S. Department of Interior, said in a blog post yesterday, describing research by scientists at the U.S. Geological Survey.

‘Fairly Small’ Quakes

The earthquakes were “fairly small,” and rarely caused damage, Hayes said.

He said not all wastewater disposal wells induce earthquakes, and there is no way of knowing if a disposal well will cause a temblor.

Last month, Ohio officials concluded that earthquakes there last year probably were caused by wastewater from hydraulic fracturing for natural gas injected into a disposal well.

[np-related]

In hydraulic fracturing — or fracking — water, sand and chemicals are injected into deep shale formations to break apart underground rock and free natural gas trapped deep underground. Much of that water comes back up to the surface and must then be disposed of.

There’s “a difference between disposal injection wells and hydraulically fractured wells,” Daniel Whitten, a spokesman for the America’s Natural Gas Alliance, which represents companies such as Chesapeake Energy Corp. and Cabot Oil & Gas Corp., said in an e-mail. “There are over 140,000 disposal wells in America, with only a handful potentially linked to seismic activity.”

‘Committed to Monitoring’

“We are committed to monitoring the issue and working with authorities where there are concerns, but it should be noted that currently there is no scientific data associating hydraulic fracturing with earthquakes that would cause damage,” he said.

An abstract of the federal study, which was led by William Ellsworth, Earthquake Science Center staff director for the U.S. Geological Survey in Menlo Park, California, was published online earlier this month. A full version of the study wasn’t immediately available.

The area studied included a swath of the country running from Ohio to Colorado and Oklahoma, the study said.

“A naturally-occurring rate change of this magnitude is unprecedented outside of volcanic settings or in the absence of a main shock, of which there were neither in this region,” Ellsworth and his colleagues wrote.

The Environmental Protection Agency is preparing to release rules on air pollution from gas wells and on the treatment of wastewater. Other state and federal rules could force more disclosure of the chemicals used by the drilling companies.

The Interior Department is considering rules to update well-design standards and require disclosure of the chemicals in fracking on public lands.

Bloomberg News

New York is unlikely to enjoy the energy boom that swept neighboring Pennsylvania because a collapse of natural gas prices has dulled the enthusiasm of companies waiting for regulators to permit drilling.

For almost four years, state officials blocked a drilling technique known as hydraulic fracturing, or fracking, that is opposed by some environmentalists. Pennsylvania and Ohio allowed producers such as Chesapeake Energy Corp. and Talisman Inc. to employ the method, and have attracted billions of dollars in investment. Like those states, New York sits atop the gas-rich Marcellus Shale formation and its portion may hold enough gas to supply the U.S. for three years.

Since New York began developing gas-drilling rules in July 2008, prices have plunged more than 80 percent to a 10-year low, making it less attractive for companies. Residents hoping to earn royalty payments of the kind that turned Pennsylvania landowners into millionaires have lowered their expectations, said Gary VanDriesen, spokesman for a coalition of land owners in central New York.

“A windfall they thought they had coming soon is something that’s a memory to them,” VanDriesen said in an interview. “The older ones figure ‘well, my children or my grandchildren will benefit from it.’’

Treated Water

The Marcellus Shale, a formation stretching from New York to Tennessee, may contain a two-decade supply of gas for the U.S. Drillers tap it by pumping millions of gallons of chemically treated water underground to break up rock and free trapped gas.

Companies spent about $20 billion on leases, drilling rigs and royalty payments in Pennsylvania from 2008 to 2010, and fracking in Ohio is forecast to add $5 billion to economic output by 2014.

New York officials say they plan to complete rules for gas fracking this year. However, Talisman, which has about 250,000 acres under lease in New York, is unlikely to be an active driller in the state until prices rebound, said David Mann, a spokesman for the Calgary-based company. Oklahoma City-based Chesapeake has scaled back drilling in Pennsylvania portions of the Marcellus.

‘‘People think that General Patton with an army of drilling rigs is waiting at the border,’’ Tom West, a lawyer in New York’s capital of Albany who represents gas producers, said in an interview. ‘‘That’s not going to happen. It’s going to be a very slow ramp up.”

Draft Rules

Environmental groups and New York City Mayor Michael Bloomberg have said drilling shouldn’t occur near watersheds, including reservoirs that supply 1.3 billion gallons (4.9 billion liters) of drinking water a day to New York City. Bloomberg is founder and majority owner of Bloomberg LP, parent of Bloomberg News.

Those concerns were incorporated by the Department of Environmental Conservation into draft rules, which include a 4,000-foot buffer zone between drilling rigs and watersheds for New York City and Syracuse. The aim is to protect the environment while capturing the economic benefits of drilling, according to department chairman Joseph Martens.

The latest version of the standards released in October were an improvement over prior drafts and may be “the most comprehensive set of rules in the country,” Kate Sinding, a senior attorney with the Natural Resources Defense Council in New York, said. Still, regulators failed to adequately deal with disposal of drilling wastewater or to assess the cumulative impacts in rural areas, she said.

‘Massive Undertaking’

“This is a massive new undertaking,” Sinding said in an interview. “It’s one with a huge variety of potential risks. We don’t think it’s either unusual or inappropriate that it should take a good number of years.”

What happens next depends largely on the price of natural gas, said John Martin, principal consultant with JPMartin Energy Strategy LLC in Saratoga Springs. In July 2008, the month New York said it would begin developing rules for fracking, natural gas averaged $11.068 per million British thermal units on the New York Mercantile Exchange. Gas for May delivery was $2.031 yesterday, down 32 percent this year.

“In 2008 the conditions were all different,” Martin said in an interview. “Investment would have rolled in. I don’t see anybody drilling wells right now.”

Marcellus Shale

The Marcellus Shale may contain 490 trillion cubic feet of gas, enough to heat U.S. homes and power electric plants for two decades, Terry Engelder, professor of geosciences at The Pennsylvania State University in University Park, said. New York may have about 13 percent of the reserves, Engelder said. It’s the world’s second-largest field behind South Pars, shared by Iran and Qatar across the Persian Gulf.

New York’s geology is another hurdle. Based on wells in northeastern Pennsylvania, New York’s shale probably will produce primarily methane or dry gas, said Peter Fasullo, principal at energy consulting firm En*Vantage Inc. in Houston.

Gas that includes liquids such as ethylene, used to manufacture plastics, and propane can fetch twice as much as dry gas.

“The New York play is very lean,” Fasullo said in an interview. “Right now, there’s really no incentive to drill that gas.”

Producers can break even in Marcellus Shale at $4 per million Btu compared with fields in Wyoming and Arkansas, where companies need $5 and $6 to turn a profit, according to an April 2011 report from Goldman Sachs Group Inc.

Early this year, Talisman began shifting resources out of Pennsylvania and into wells in Texas and other fields that also deliver liquids along with gas, Mann said.

Scaled Back

Chesapeake scaled back in dry-gas fields to 24 rigs from about 75, and expects to steer 85 percent of capital to liquids- rich wells this year and next, up from 10 percent in 2009, Senior Vice President Jeff Mobley said at a March 27 conference.

“We expect our dry gas shale production to continue to decline,” Mobley said. “Our growth from this point forward, it’ll be 100 percent focused on the liquids-rich plays. ”

Fracking has been used to drill more than 4,400 wells in Pennsylvania since 2009. Companies spent about $11.5 billion in Pennsylvania’s shale in 2010, including $346 million in royalties to property owners who leased their mineral rights, according to a July report from The Pennsylvania State University College of Earth and Mineral Sciences.

Deeper Utica Shale

In Ohio, companies including Chesapeake, Devon Energy Corp. and Exxon Mobil Corp. are drilling in the Utica Shale, which is deeper than Marcellus. The Utica prospect will support 65,680 jobs and add $4.9 billion to Ohio’s economic output by 2014, according to a Feb. 28 study by the Ohio Shale Coalition.

“The money that would have gone into New York from 2008 to 2012 went somewhere else,” Martin said. “That money is lost.”

Once rules are in place, New York may realize $1.9 billion in gas investment including $152 million in royalties in 2015, according to a June report from the Manhattan Institute, a New York research group. The report was released in June when gas averaged $4.516 per million Btu.

“I don’t believe that the chance was missed at all,” Richard Laskey, founder of the Central New York Landowners Coalition, said in an interview. “It’s inconceivable to me that they’re going to leave all this gas in the ground.”

Bloomberg News

HONG KONG — PetroChina Co Ltd said on Thursday it has signed an agreement to buy a 20% stake in a shale gas project in Canada from Royal Dutch Shell Plc, the latest in a series of overseas acquisitions by Chinese state energy giants.

The deal to buy into Shell’s 100%-owned Groundbirch assets was completed on Wednesday, PetroChina spokesman Mao Zefeng told Reuters, declining to reveal the value of the acquisition.

Citing market talk, FinanceAsia said in a report on Wednesday that PetroChina was planning to buy the Groundbirch stake for more than US$1 billion.

The transaction, the latest in a string of investments by Chinese oil companies in North American shale gas and oil sands, had been approved by both the Chinese and Canadian authorities, Mao said.

According to Shell’s website, the Groundbirch project, located in British Columbia, has the potential to produce 1 billion cubic feet equivalents (bcfe) per day and an estimated producing life of 40 years.

PetroChina and other Chinese state oil giants, including China Petroleum & Chemical Corp (Sinopec) and CNOOC Ltd have been scouring the world for reserves to fuel China’s rapidly-growing economy.

Shale gas and oil sands assets in North America have been a focus in the past year as Chinese companies seek operational experience in the relatively frontier area.

CNOOC completed a $2.1 billion acquisition of Opti Canada Ltd in November, giving China’s top offshore oil company its second stake in a Canadian oil sands property.

China Petrochemical Corp, parent of Sinopec, signed a deal to buy Canadian oil and gas explorer Daylight Energy Ltd for $2.2 billion in October.

In June, PetroChina and Canada’s Encana Corp called off an announced $5.6 billion deal that would have given the Chinese group a 50% stake in some of Encana’s shale gas assets.

© Thomson Reuters 2012

CALGARY — Record production at Imperial Oil’s long-held Cold Lake heavy oilfields in northeastern Alberta drove fourth-quarter 2011 net earnings to just over $1 billion, or $1.18 per share, up 26 per cent over the same period in 2010.

In results posted early Tuesday, the integrated Calgary-based company said it had full year income of $3.37 billion, the second largest on record and 53 per cent higher than in 2010.

The first posted results of the Calgary oilpatch fourth-quarter earnings season beat analyst expectations of around $1.20 per share on cash flow. Imperial Oil had cash from operating activities of $1.2 billion or an estimated $1.44 per share, up 21 per cent from the same period last year.

The company raised its quarterly dividend by a penny to 12 cents per share from 11 cents in the previous quarter.

Higher oil prices provided the boost as overall production fell to 291,000 barrels of oil equivalent per day from 302,000 boe/d in the fourth quarter of 2010, mainly due to lower output from Syncrude, as well as the sale of assets producing about 5,000 boe/d.

Cash generated from operating activities was $1.2 billion, up 21 per cent from the same three months last year.

Capital expenditures were higher, at $1.18 billion compared with $1.06 billion in the fourth quarter of 2010, as Imperial continued to develop its 110,000 barrel per day Kearl oilsands mining project that is expected to start by the end of this year.

Cold Lake averaged 160,000 boe/d, beating the previous annual record of 154,000 boe/d in 2007, as new wells came on stream and technology lifted recovery rates.

Stronger margins at gasoline retail operations were credited for about $65 million of Imperial’s improved fourth-quarter earnings, while lower Syncrude volumes due to planned and unplanned outages lowered earnings by about $100 million. Imperial has a 25 per cent stake in Syncrude and is the operator.

The company is 70 per cent owned by American giant ExxonMobil Corp., which reported fourth-quarter earnings of $9.4 billion US on Tuesday, up two per cent from a year earlier, and full year 2011 earnings of $41.1 billion, up 35 per cent from 2010, reflecting higher crude oil and natural gas realizations, improved refining and chemical margins, and gains on asset sales.

Calgary Herald

“This would require legislation and regulatory changes,” Mr. Oliver told the National Post editorial board. “We have a system which lends itself to potential manipulation, duplication and delays.”

“You look at the possibility of hearing thousands of people — some of them with legitimate reason — but others who are there just to kill the process. You take account of the numbers but you don’t necessarily have to hear everyone who repeats the same canned message. It would never happen in a court setting,” said Mr. Oliver, referring to Enbridge Inc.’s Northern Gateway pipeline hearings, where 4,000 people are expected to speak over the year-long process.

The Minister would not say whether the new legislation would impact Northern Gateway, or indeed when the new legislation may be introduced.

“It’s a priority issue. We need fixed timelines for the entire process, pre-hearing, hearing and post hearing processes. We need a beginning-to-end process that’s actually enforceable. It’s not just an issue of optics… There are thousands of projects that are subjected to delays,” said the Minister.

The provinces are on board with the need for regulatory reform. At a meeting last summer, federal, provincial and territorial energy and mines ministers agreed regulatory upgrades were key to realizing the full potential of Canada’s natural resources, said Mr. Oliver, adding that the oil sands is an issue of national interest beneficial to the wider economy, not just Alberta.

“The oil sands creates business for more than 1,000 Ontario companies alone,” said the Minister.

About 35,000 people in Ontario are working in jobs linked to the oil sands. If projected development occurs, it means an additional 15,000 jobs per year in Ontario over the next 25 years.

The new legislations are also crucial given the urgent need for Canada’s rising energy output to be brought to the market. The current tensions surrounding Keystone XL notwithstanding, the U.S. can’t absorb “all our natural resources” said Mr. Oliver emphasizing Prime Minister Stephen Harper’s visit to China next month to expand Canada’s market beyond its southern neighbour.

But to get to market quickly, the country will need to upgrade the regulatory systems without compromising on environmental standards, and soak up close to $500-billion in new energy investments over the next decade and create much-needed jobs.

OTTAWA – Canada disassociated itself on Thursday from an embarrassing official policy paper that said the country’s independent energy regulator, now studying a controversial oil pipeline, is in fact a government ally.

Critics have long charged the right-of-center Conservative government is trying to pressure the regulator – the National Energy Board (NEB) – to approve Enbridge Inc’s plan to build a pipeline from the Alberta tar sands to the Pacific Coast.

The NEB this month started hearings into the $5.5-billion Northern Gateway pipeline, which the government says is needed to send more oil to Asian markets.

Opponents of the pipeline include green groups and some native Indian bands, who say they fear the consequences of a spill. Ottawa says some critics are foreign-funded radicals and complains the regulatory process will take too long.

Greenpeace on Thursday released a policy paper from April 2011, which listed the NEB as one of the government’s allies. The paper was part of a campaign to counter widespread criticism of the oil sands in the European Union.

The paper – written by bureaucrats at the international trade ministry – also said that among the government’s adversaries on the file were aboriginal groups, also known in Canada as First Nations.

Ottawa is in fact trying to woo the First Nations and this week hosted a summit between Prime Minister Stephen Harper and hundreds of native chiefs to discuss improving the often awful living conditions of Canada’s aboriginals.

“We do not agree with the characterizations. We continue to work together with Canada’s First Nations as we promote our energy interests. The NEB is an independent federal agency,” said Adam Taylor, a spokesman for International Trade Minister Ed Fast.

“The oil sands are a proven strategic resource for Canada. We will continue to promote Canada’s oil sands as they are key to Canada’s economic prosperity and energy security.”

At 170 billion barrels, Canada’s oil sands represent the third-largest crude deposit in the world. Despite concerns about the environmental impact of development, Ottawa touts the resource as one of the country’s great economic opportunities and job creators.

The policy document was obtained by the Climate Action Network group through access to information and then made public by Greenpeace.

“Canadians should be concerned when a supposedly arms-length agency that is supposed to regulate the oil industry, including conducting hearings on Enbridge’s proposed new tar sands pipeline across British Columbia, is listed as an ’ally’,” said Keith Stewart of Greenpeace.

Canadian Environment Minister Peter Kent told reporters in Calgary that while he had not seen the document, the notion Ottawa considered aboriginal groups as adversaries was a “gross misrepresentation of reality”.

He added that he and Natural Resources Minister Joe Oliver would keep pushing back at environmental groups countering the government’s message that the oil sands are being developed responsibly.

Among other allies listed by the policy document were European energy companies, some of which have invested heavily in the tar sands.

© Thomson Reuters 2011

President Barack Obama pushed drilling for gas in shale rock and support for cleaner energy sources to boost the economy in his final State of the Union address before facing U.S. voters in November.

Hydraulic fracturing, the process of injecting water, sand and chemicals underground to free gas trapped in rock, could create more than 600,000 jobs by the end of the decade, Obama said yesterday. The process, called fracking, is among a list of energy policies Obama said would fuel economic growth.

“We have a supply of natural gas that can last America nearly 100 years, and my administration will take every possible action to safely develop this energy,” Obama said.

Obama reiterated support for conservation and cleaner sources of power and pledged more oil drilling as part of an ‘all-out, all-of-the-above’’ policy “that’s cleaner, cheaper, and full of new jobs.” He said domestic energy production is at an eight-year high and imports of foreign oil were declining, prompting criticism from Republicans.

“It’s just a blind accident, if in fact we are producing more oil or natural gas than in previous years, because it’s not because of any of his efforts,” Representative Darrell Issa, a California Republican and head of the House Oversight and Government Reform Committee, said after the speech.

Republicans also sought to contrast Obama’s pledge to use energy policy to create jobs with his denial of a permit to TransCanada Corp.’s Keystone XL pipeline to connect Canada’s oil sands to refineries on the Gulf coast.

Republicans, Keystone

Indiana Governor Mitch Daniels, delivering the Republican response to a nationwide television audience, called Keystone a “perfectly safe pipeline that would employ tens of thousands” and said that Obama has sought to stifle energy production in the U.S.

Keystone would “have done more than any other project to increase our energy security and revive our economy,” Senator James Inhofe, an Oklahoma Republican, said in a statement after the speech.

Obama announced incentives to make industries more energy efficient, and again called on Congress to require that a larger percentage of the nation’s power come from low-pollution sources.

He directed his administration to open up more than 75 percent of potential offshore oil and gas resources for production.

Eight-Year High

“Right now, American oil production is the highest that it’s been in eight years,” Obama said. “Not only that – last year, we relied less on foreign oil than in any of the past 16 years.”

U.S. natural-gas production averaged 1.89 trillion cubic feet a month through October, 13 percent higher than the average during President George W. Bush’s two terms, according to Energy Department data.

Crude oil production is 2 percent higher, the department said.

Greenpeace Executive Director Phil Radford in a statement criticized the emphasis on fracking, which he said poses risks to water supplies. Companies say the process is safe.

Obama said the drive for new drilling would be accompanied by regulations to ensure safe drilling practices. Those would include a requirement that companies operating on public lands disclose the chemicals used in the fracking fluid.

Jobs, Taxes

As Obama backed more domestic oil and gas production, he also pledged support for renewable sources of power, urging Congress to pass clean energy tax credits and a mandate for more electricity to come for cleaner sources of power.

An energy efficiency initiative he’s backing would cut $100 billion from the nation’s energy bills, he said. Obama also pledged that the Defense Department would make the largest renewable energy purchases in history.

Senator Jeff Bingaman, a New Mexico Democrat and chairman of the Energy and Natural Resources Committee, said in a statement that the priorities Obama laid out were a “very good blueprint for how we can accelerate economic growth in our country.”

Dave Foster, executive director of the BlueGreen Alliance, a group that represents labor and environmental groups, said in an interview that Obama was “showing us a path” to how clean energy can increase manufacturing jobs.

Obama also repeated his call from last year to repeal tax credits for the oil and gas industry. That effort failed to win broad support in Congress, after producers said the measures would push more production and jobs outside the U.S.

“Advocating greater energy production but penalizing those who provide that energy is not a sound energy policy, but a contradiction,” Jack Gerard, chief executive officer of the American Petroleum Institute, said in a statement.

Bloomberg News

Excluding one-time items, earnings of $2.02 per share were higher than the $1.76 that analysts had expected, according to Thomson Reuters I/B/E/S.

Conoco, the third-largest U.S. oil company behind Exxon Mobil and Chevron Corp, has been selling off assets to cut its debt and expects to spin off its refining arm in the second quarter.

Oil and gas output in the quarter was 1.6 million barrels of oil equivalent per day.

© Thomson Reuters 2012