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Chesapeake retreat ends American energy land grab

By Edward McAllister
NEW YORK | Tue Jul 10, 2012 1:21am EDT

(Reuters) – About six years ago, an army of agents hired by energy companies started desperately courting landowners across the United States whose farms and ranches happened to sit atop some of the richest oil and gas deposits in the world. And so began one of the biggest land grabs in recent memory.

Those days are over.

U.S. energy titan Chesapeake Energy is quickly cutting back on an aggressive land-leasing program that in recent years has made it one of America’s largest leaseholders, putting an end to half a decade of frenzied energy wildcatting.

Beset by growing governance and financial problems, and a sharp slump in natural gas prices, the No. 2 U.S. gas driller is reducing by half the ranks of its agents, known in the industry as landmen.

With little evidence that its competitors are taking on the role of leading industry lease-buyer, Chesapeake’s new found frugality is expected to usher in a more sedate period of U.S. land buying, and a sizeable cultural shift for an industry that has been acquiring new acreage at almost any cost.

A surge in drilling into rich shale-gas seams from Pennsylvania to Texas has pushed natural gas prices to 10-year lows, forcing producers, including Chesapeake, to cut output and put the brakes on new wells.

Drilling simply to hold on to leases represents about half of U.S. natural gas output, analysts say, which has helped keep production at record highs despite plummeting prices. Leases held by energy companies tend to last about three years, but will typically remain valid indefinitely if an energy company drills wells and produces fuel on the leased acreage.

It should be fairly easy for drillers to re-hire agents and secure more land when prices recover, according to landmen sources, and production is not expected to be affected immediately. But a lull in leasing could briefly affect production longer term, given that it takes up to six months to secure large tracts of land.

“Chesapeake has always been a bellwether for where the next big play is. It would come, lease large blocks and send a signal to the market,” said Adam Bedard, senior director at Bentek Energy in Colorado. “Without them, the pace of land acquisition might slow.”

In a move to mollify disgruntled shareholders, Chesapeake plans to reduce its use of contracted landmen from 1,300 now to 650 by the end of the year, said Chief Executive Aubrey McClendon, who was stripped of his chairmanship last month after Reuters reported a series of governance missteps.

The reduction, which is expected to help reduce towering debt levels, marks an 80 percent decrease from its peak of 3,400 landmen, McClendon said.


The cull has begun. Over the past month, 225 contracted landmen were cut from Chesapeake jobs, said one Ohio-based landman, who, like most in the close-knit industry, would only speak off the record.

“Chesapeake’s activity level in the Appalachian region is minimal now. It has devastated the (landman) industry,” the source said. “The Chesapeake debacle is one thing, but the rest of the industry shortfall is because a lot of the projects are intertwined with Chesapeake,” he added.

The Oklahoma-based company has become one of the largest leaseholders in the United States, amassing more than 15 million acres of land for drilling or an area about the size of West Virginia.

One mid-sized U.S. brokerage that does lease work for Chesapeake has experienced a 15 percent to 20 percent fall in business over the last 90 days due to a slowdown not just in Chesapeake activity but across the board, a manager for operations at its eastern division told Reuters. About 15 percent of that company’s business comes from Chesapeake, he said.

“We are getting to the point where companies are becoming more cautious – that is what we are seeing,” he said, asking that he not be named.

Other major producers, including Encana Corp, Royal Dutch Shell and Chevron, said they are not planning to materially change their strategy of land acquisition or staffing numbers, suggesting a gap might be left as Chesapeake, long the pioneer in drill leasing, retreats.

“We have not reduced our land staff nor have we made any changes in the way we conduct land operations,” said a spokesman for Encana, one of Chesapeake’s main land-leasing rivals. Encana employs an in-house staff of about 170 workers in its land department. Shell also said it was “not planning any major staffing level changes in our land function for leasing activity.”


Landmen in the field reckon companies are now well-placed to increase leasing again when they need to, but it could take up to six months between a decision to lease the land and the drilling, potentially creating a lull in activity, sources said.

While a fall in leasing will affect the landmen, it is unlikely to affect gas output for quite some time given the amount of land already leased and the hundreds of wells drilled that have yet to begin producing.

“The huge land grabs in the gas plays are coming to an end,” said one energy hedge fund manager. “Even without more leasing, however, these companies have backlogged a huge inventory of drilling locations.”

The backlog of 3,500 oil and gas wells in the United States is about 1,000 more than usual, according to Randall Collum, a natural gas analyst at Genscape in Houston.

It could take more than a year to exhaust the natural gas portion of that supply as pipelines come online to connect new producing regions, such as in Ohio, to areas of higher demand, he said. Moreover, the reserves accumulated over the last decade are expected to take longer to dwindle away.

That scenario is likely to put a cap on prices in the near term, with or without Chesapeake.


When U.S. drillers employed new technologies during the last decade to economically tap oil and gas from shale rock, results showed the potential for a massive revival in waning domestic production.

In 2006 and 2007, companies began rushing to acquire new leases. Geologists pored over maps, in search of the sweetest acreage. Landmen were hired like never before, court houses in energy-rich regions filled with workers quickly securing leases. Rural and depressed areas in Pennsylvania, North Dakota, and Ohio became, by geological coincidence, new target areas for energy companies.

Teams of between 50 and 100 landmen were charged with securing hundreds of thousands of acres in a matter of weeks. Some would knock on landowners’ doors, while others specializing in title work would make the lease legally secure and determine, among other things, who receives royalties on the production.

Chesapeake led the charge, spending billions of dollars a year on speculative leasing, helping to push land prices higher in energy-rich regions. In 2011, it became the lead acreage holder in the Utica formation shale in Ohio with 1.5 million acres, and was the first to publish production figures from new wells there.

After Chesapeake arrived, other majors such as Anadarko and Exxon Mobil quickly followed. Much of the best drilling areas have already been swept up in what is now thought – though not fully proven – to be one of the most promising oil and gas plays in the country.

Now, five years after the boom began, natural gas output is at an all time high. The success has, in many ways, backfired. Prices have dropped so far that companies can barely afford to drill in pure natural gas plays. Chesapeake, the self-proclaimed ‘champion’ of U.S. natural gas, is facing a $10 billion cash-flow shortfall this year, forcing it to rein in spending.

“It will slow down the overall aggressiveness if Chesapeake isn’t out there leading the charge,” said Genscape’s Collum. “But it is all about prices. If prices rise then companies will come back in.”

(Additional reporting by Joshua Schneyer in New York and Anna Driver in Houston; Editing by Leslie Gevirtz)

No relief for natural gas producers as Apache’s Kitimat plant delayed

Courtesy of Apache Canada Ltd.
An artist’s rendering of the proposed Kitimat Apache Canada’s LNG facility, which is now delayed for another year

Claudia Cattaneo Jun 20, 2012 – 6:47 PM ET
Last Updated: Jun 21, 2012 7:46 AM ET

Beleaguered natural gas producers in Western Canada are going to have wait a little longer for relief from severely depressed prices. Janine McArdle, the senior executive in charge of the Kitimat LNG project at Houston-based Apache Corp., said the facility’s planned startup will take an extra year as the company continues to look for firm contracts with buyers in Asia.

Apache’s proposed natural gas liquefaction plant on the northern British Columbia coast, which it owns with Encana Corp. and EOG Resource Inc., would be the first in line to ship large quantities of LNG to Asia.

The first cargo is now expected to leave Canada in 2017, a year behind the latest plans. The project has regulatory approval, but Apache needs to be sure it has a market for the gas and that the project is economic before taking a final investment decision, Ms. McArdle, senior vice-president for gas monetization at Apache, North America’s largest oil and gas independent producer, said Wednesday.

Construction of a 10-million tonnes a year plant would then take 50 to 60 months.

“We are moving as quickly as we possibly can given that Canada is new to these buyers, and we are relatively new to the buyers as Apache,” she said on the sidelines of an industry conference.

“We have been talking to multiple markets simultaneously and there is a lot of interest. I always have to remind people that these are 20, 30-year marriages. These things don’t happen overnight.”

Next in line is Royal Dutch Shell PLC’s B.C. LNG project, which is slated for startup in 2019. Shell gave the tentative go-ahead to the project last month with three Asian partners that will secure Canadian gas has customers — PetroChina, Mitsubishi Corp. and Korea Gas Corp. However, the project has yet to obtain regulatory approval.


A handful of other projects are also in various planning stages, but they are further behind.

It’s a tense time for Western Canadian natural gas producers, who are watching closely progress on LNG facilities on the B.C. coast so they can start monetizing reserves already found and look for new ones. The facilities will enable exports to Asia and help alleviate a massive shale supply glut in North America that has depressed prices to 10-year lows.

Asian demand for LNG is expected to increase to 35 billion cubic feet a day by 2020, from 20 bcf today, said Ed Kallio, director of gas consulting at Ziff Energy Group, a Calgary-based gas forecasting firm. He expects demand to outstrip supply in Asia by 2016/2017.

The good news is that there is plenty of gas to keep the projects full. Apache announced last week that it discovered in the Liard Basin a new shale gas field containing as much as 48 trillion cubic feet of recoverable natural gas which it characterized as one of the world’s best.

The find motivates Apache to develop an alternative market for Canada, Ms. McArdle said.

It also further boosts Canada’s 500-trillion cubic feet of natural gas reserves, a number that has ballooned in recent years thanks to shale discoveries such as the Horn River, the Montney and the Cordova, all in British Columbia. To put it in context, the now-shelved Mackenzie Gas Project was underpinned by six trillion cubic feet of reserves in the Mackenzie Delta. The number seemed immense before shale gas was unlocked.

Mr. Kallio, who also spoke at the conference, said it will take a lot more than LNG exports to restore balance to the natural gas market and Western Canadian producers will be stuck in a low-price environment for several years. Demand will have to increase, and supply will come down as production of liquids-rich natural gas runs out of steam with weakening of liquids prices, as drilling promoted by land terms tapers off, and if producers do their part by being more disciplined, he said.

“We had such a rush and we had a bunch of cowboys out there, including Chesapeake [Energy Corp.] and Encana that drilled like crazy, [because] they had nice hedges on through the end of this year. But they have very little hedged next year, and that is why they are selling assets — they are selling fingers, toes, kidneys, prized assets to get the cash flows up” and hang in until the next rising market, Mr. Kallio said.


USA: Encana Inaugurates LNG Fueling Station in Louisiana


Encana Natural Gas, a subsidiary of Encana Corporation, one of North America’s largest natural gas producers, Friday opened the first liquefied natural gas (LNG) fueling station in Louisiana.

Located at The Relay Station in Frierson, the station which will serve the fueling needs of heavy duty truck fleets is open for public use. The station is currently being utilized by Heckmann Water Resources (HWR), an Encana partner in water sustainability in the natural gas industry.

HWR recently ordered 200 new LNG big-rig trucks, 50 of which have been deployed to date. California-based Heckmann Corporation, parent company to HWR, provides water management services to Encana and other producers in the Haynesville resource play.

Encana also recently secured a contract with Pivotal LNG, a subsidiary of AGL Resources Inc. which owns and operates a major liquefaction facility.

We are very pleased to be part of an innovative Canadian and American solution to expand the use of LNG. This new station is a major step towards encouraging companies to convert vehicles to run on affordable, environmentally-responsible natural gas,” said Eric Marsh, Executive Vice-President, Encana Corporation & Senior Vice-President, USA Division.

Encana works with supply chain partners and other external heavy duty fleets by offering fueling solutions to help them better manage fuel usage and realize the cost savings of natural gas. Encana is quickly growing in its efforts to commercially develop natural gas for transportation. Additionally, Encana owns and operates four mobile LNG fueling stations (two in Louisiana) and six compressed natural gas (CNG) stations. In leading by example, Encana has converted nearly half of their fleet field vehicles in Louisiana operations to utilize CNG. They have also retrofitted drilling rig engines to run on natural gas in their U.S. operations, four of which run on LNG.

Natural gas powered cars and trucks are fueled with CNG or LNG and operate similarly to gasoline or diesel powered vehicles and generally have a longer operating life due to the cleaner combustion. Converting freight trucks and commercial vehicles has an immediate impact on saving fuel costs and reducing carbon emissions. Converting one 18-wheeler from diesel to LNG is equivalent to removing the emissions of about 325 cars from the road.


Tuscaloosa shale promising

St. Helena well’s initial production spurs interest


By Ted griggs
Advocate business writer
February 07, 2012

It’s still early in the Tuscaloosa Marine Shale’s development, but energy industry members say a St. Helena Parish well’s initial production, nearly 800 barrels a day, is encouraging.

The Encana Weyerhauser well, completed in November, averaged 784 barrels of oil per day and 309,000 cubic feet of natural gas, according to Encana’s filing with the state Department of Natural Resources.

“This is certainly a key well. There’s no doubt,” said Dan Collins, a Baton Rouge landman who spent much of last year negotiating lease agreements with landowners in the shale.

“You know, 800 of anything coming out of the ground daily is a lot,” Collins said.

That’s especially true when the anything in question fetches nearly $100 a barrel.

Around two dozen wells have been drilled or are being drilled in the Tuscaloosa Marine Shale, an oil-rich formation that covers Louisiana’s midsection. Energy companies have leased more than 1 million acres in the formation, but so far the firms aren’t sharing much of their early production figures.

Kirk A. Barrell, president of Amelia Resources, of Texas, said before the formation can be considered economically viable, 10 to 20 wells will have to be completed.

“You need the initial (production) rates for 10 to 20 wells, but you also need to get 12 to 15 months out and see what the decline of that rate is,” Barrell said.

Still, Collins said it appears the energy companies believe they have something.

Oil companies have proposed a number of wells and discussed putting multiple drilling pads on landowners’ property, Collins said. The shale’s future remains to be seen, but there probably wouldn’t be so much activity if the energy companies didn’t believe their investment is worthwhile.

Encana has leased around 270,000 acres in the play, has completed one horizontal well, and has two new wells under way, according to its investor presentations.

Encana spokesman Alan Boras said he could not discuss any details of the company’s Tuscaloosa wells.

But the company will release more information during its fourth-quarter earnings report, scheduled for Feb. 17, Boras said.

A lot of people think every well in the Tuscaloosa should produce 1,000 barrels a day, but it takes time for drilling companies to figure out the best approach, Barrell said.

Barrell, the author of a blog on the Tuscaloosa Trend, said people forget or don’t realize that the early results varied from wells drilled in the Eagle Ford Shale in Texas.

While there were a few good wells whose maximum production was around 1,000 barrels per day, there were a number of wells whose daily production never reached double figures, Barrell said.

Collins said in order to recover the millions in drilling costs, a well’s initial production has to be pretty strong because the production curve declines pretty rapidly.

Shale wells’ production rates generally fall about 75 percent after 12 months.

“I liken it to a ski slope. We certainly don’t want the black ski slope. We want one of those greens or blues that’s going to … gently drop over time,” Collins said.

Gifford Briggs, vice president of the Louisiana Oil and Gas Association, said the Encana well’s results will encourage additional testing.

But it’s difficult to say how significant the well is without knowing the costs and how long the well will continue producing at the same rate, Briggs said.

In this early phase, Encana and other companies operating in the Tuscaloosa are still trying to answer a number of questions, such as what is the right depth to drill and how to get the most effective fracture, he said.

Wells in the Tuscaloosa are drilled vertically for around 11,000 feet and then horizontally. Drillers then fracture the formation in multiple stages, forcing millions of gallons of water, mixed with sand and/or ceramic and chemicals into the formation to crack the shale. The sand and ceramic materials prop the cracks open, releasing the oil.

Fracking has drawn criticism from environmentalists and some landowners, who say the practice pollutes the air, contaminates water and consumes too much water. The oil and gas industry’s position is that fracking has been used for more than 50 years on thousands of wells with no evidence of groundwater pollution.

Collins said leasing activity in the area has slowed this year as companies have turned to drilling, but Barrell said his firm and its partners are still actively leasing.

Lease prices in the Tuscaloosa Marine Shale, compared to other shale plays, remains a “great, great value,” Barrell said.

Last year, leases were going for around $150 an acre.

Briggs said he has heard that leases are fetching $250 to $500 per acre.


Encana throws cold water on EPA report


Encana has lashed out at what it termed an “irresponsible” official draft report linking water contamination in the US to its hydraulic fracturing activities.

Eoin O’Cinneide 12 December 2011 11:56 GMT

The Canadian gas behemoth lambasted the Environmental Protection Agency (EPA)’s report on water quality at Pavillion, Wyoming as containing “unacceptable inconsistency”, “conjecture” and “numerous flaws”.

On Thursday the EPA released the draft report which claimed that “ground water in the aquifer contains compounds likely associated with gas production practices, including hydraulic fracturing”. The EPA investigation also found synthetic chemicals such as glycols and alcohols, and benzene concentrations “well above Safe Drinking Water Act standards” as well as high levels of methane.

On Monday Encana hit back with a scathing attack on the EPA, pointing to perceived flaws with the body’s drilling methodology and a lack of a qualified opinion.

“Of most concern, many of the EPA’s findings from its recent deep monitoring wells, including those related to any potential connection between hydraulic fracturing and Pavillion groundwater quality, are conjecture, not factual and only serve to trigger undue alarm,” the statement read.

“Encana is especially disappointed that the EPA released its draft report, outlining preliminary findings, before subjecting it to qualified, third-party, scientific verification,” labeling this a “precipitous action”.

The Canadian giant pointed to “numerous discrepancies” in the report which it claimed “ignores well-known historical realities with respect to the Pavillion field’s unique geology and hydrology”.

The company claimed that, as far back at the 1880s, the US Geological Survey (USGS) reported poor quality water at Pavillion.

“More recent USGS reports dating back to 1959 have documented Pavillion water as unsatisfactory for domestic use due to high concentrations of naturally occurring sulfate, total dissolved solids and pH levels which commonly exceed state and federal drinking water standards.”

Encana continued: “Natural gas developers didn’t put the natural gas at the bottom of the EPA’s deep monitoring wells, nature did.

“Conclusions drawn by the EPA are irresponsible given the limited number of sampling events on the EPA deep wells and the number of anomalies seen in the data.”

The EPA had said its draft findings “are specific to Pavillion, where the fracturing is taking place in and below the drinking water aquifer and in close proximity to drinking water wells”. Such production conditions “are different from those in many other areas of the country”, the body claimed.

Last week, Encana spokesperson Doug Hock criticised the report, saying the EPA took “disparate pieces of data” and did not come to a clear conclusion.

“It’s interesting they talk about a ‘likely association’ [to fracking],” he said. “That’s not a conclusion, it’s a probability. They’re hedging their bets.”

The draft report will be available for public comment for 45 days from publication. To see a copy of the report, click here.


Canada: Kitimat LNG Wins Export Licence


Kitimat LNG partners Apache Canada Ltd. (Apache Canada), EOG Resources Canada Inc. (EOG Canada) and Encana Corporation (Encana) has announced that the National Energy Board (NEB) has granted Kitimat LNG a 20-year export licence to ship liquefied natural gas from Canada to international markets.

”The Kitimat LNG project represents a remarkable opportunity to open up Asia-Pacific markets to Canadian natural gas and we’re leading the way in being able to deliver a long-term, stable and secure supply to the region,” said Janine McArdle, Kitimat LNG President.This export licence approval is another major milestone for Kitimat LNG as we move forward and market our LNG supply. LNG customers can have even more confidence in a new source of supply.”

Today marks a historic day for Canada’s natural gas industry and this is fantastic news for our project and the communities where we operate. Kitimat LNG will bring revenues and jobs and the associated benefits to Canada,” said Tim Wall, Apache Canada President. “The Kitimat LNG partners are very pleased with the NEB’s approval of our export licence and we’d like to thank them for their support and confidence in the project.

The Kitimat LNG export facility is planned to be built on First Nations land under a partnership with the Haisla First Nation.

The facility will be served by Pacific Trail Pipelines Limited Partnership’s natural gas pipeline which will run from Summit Lake to Kitimat. The 463-kilometre underground line will provide the terminal with a direct connection to the Spectra Energy transmission pipeline system and excellent access to natural gas supplies in British Columbia.

Kitimat LNG is currently carrying out a Front End Engineering and Design (FEED) study which will provide certainty around project design, construction timelines and costs and labour force requirements. The FEED study is expected to be complete by early in 2012 followed by a final investment decision by the partners.

About the Kitimat LNG facility and the PTP Pipeline

Apache Canada, EOG Canada and Encana plan to build the Kitimat LNG facility on IR#6 Bish Cove, approximately 650 kilometres (400 miles) north of Vancouver. The facility is planned to be built on First Nations land under a unique partnership with the Haisla First Nation. The initial phase of the facility has a planned capacity of approximately 5 million metric tonnes of LNG per annum or the equivalent of nearly 700 million cubic feet per day. PTP is planning to build a 463-kilometre (287-mile), 914-mm (36-inch) diameter underground line from Summit Lake, B.C. to Kitimat. Pacific Northern Gas Ltd. (PNG) will operate and maintain the planned pipeline under a seven-year agreement with Apache Canada, EOG Canada and Encana, with provisions for five-year renewals.

Original Article

Future Looks Bright for Canada Natural Gas Business


Two kilometres beyond an old logging road, workers are building the foundation of the future of Canada’s ailing natural gas business.

Since the summer, crews have blasted the hard rock at Bish Cove on the Douglas Channel, the deepest and widest fjord on the rugged north coast of British Columbia. More than 40,000 cubic metres have already been excavated to reform the land, in preparation for a $5-billion-plus project that would for the first time ship Canadian natural gas to buyers in Asia.

The earth-churning work at Bish Cove is a demarcation point in the history of the Canadian energy business. For the country’s natural gas producers, a door to Asia is a desperately needed lifeline. The industry has been battered by the emergence of abundant shale gas in the United States. Prices and profits have collapsed, and shipments to the U.S., Canada’s only export customer, have been halved. Without an export route to Asia, there is a risk that the major discoveries of shale gas in British Columbia, as well as reserves in Alberta, will be left in the ground.

There is urgency: Serious competition looms on the other side of the world in Australia, where there are some $200-billion of plans to build numerous plants that would triple exports to the same customers Canada is courting. But Canada has an advantage. Shipping times from Kitimat to buyers in Japan, South Korea and northern China are shorter, providing savings on transportation costs, industry officials say.

At a time when battles over environmental concerns threaten to slow down or derail major Canadian oil sands export projects such as TransCanada’s Keystone XL pipeline and Enbridge’s Northern Gateway pipeline, the vision to ship liquefied natural gas to Asia is quietly speeding toward reality.

The gas export plan could mean higher domestic energy prices for residential and industrial customers in the future and would crank up Canada’s greenhouse gas emissions. Yet there has been barely a ripple of protest and nobody risking arrest on Parliament Hill or on the doorstep of the White House.

In fact, the idea enjoys broad support, from politicians of all stripes to the local first nation and other aboriginal groups along a pipeline route that would bring the gas to Kitimat on the B.C. coast, where it would set out for Asia.

The Kitimat LNG project is a three-way joint venture between U.S. energy companies Apache Corp. and EOG Resources Inc. , along with Canadian gas giant Encana Corp. They are expecting to receive a crucial export permit from the National Energy Board within days. A decision to proceed is expected by early next year. Gas could be on ships by 2015.

A green light for the Kitimat LNG project could see the rapid establishment of a regional export hub, one that major global energy players are keen to join. By the end of this decade, three billion cubic feet a day of gas could flow through Kitimat – equal to all of B.C.’s current production and close to 20 per cent of Canada’s current output.

“This is huge. We embrace it. A lot of people are working,” says Ellis Ross, chief councillor of the Haisla Nation in Kitimaat Village across the channel from Bish Cove. “It’s going to be life-changing for us.”

The coming global LNG shortage

Exports of Canadian gas to the U.S. began in earnest in the late 1950s, after the completion of the Trans-Canada Mainline, but by 1970 growth plateaued and was flat through the mid-1980s. After deregulation under Brian Mulroney, the industry boomed and exports to the U.S. quintupled by the early 2000s, bringing vast wealth to Calgary. Indeed, despite oil’s higher profile, gas has long been Alberta’s economic bedrock. It has also bolstered Ottawa’s coffers.

Amid high natural gas prices during the past decade and uncertain future supply, experts throughout the gas industry were convinced the U.S. needed terminals to import gas and several multibillion-dollar facilities were built. They now sit mostly idle. One struggling importer, Cheniere Energy Inc. on the Gulf Coast in Louisiana, received approval in May to export gas, which it hopes to do by 2015.

Underlying the gamble Apache, EOG and Encana are making on LNG are the major positions those companies hold in the Horn River shale gas play in remote northeastern B.C. The resource is among the most promising in North America but remains stymied by its distance from U.S. markets and broad weakness in gas markets, which has already forced Encana to pull back on drilling this year. The company this week said it will drill fewer wells in 2012, even though it’s been tapping huge pools of gas.

As it increasingly draws from prolific domestic natural gas reserves, the U.S. is meeting more and more of its own gas needs, and some speculate that the country will eventually not need any gas at all from Canada. But in Asia the need is great, and the strong demand means prices are much higher.

“Tens of millions dollars are being forfeited each day,” economist Peter Tertzakian of ARC Financial said in a recent report. “Canadians are leaving a lot of coin on the table. … It is disconcerting that it has taken a steep loss in sales to begin acting on market diversification but at least the industry buzz is now all about tapping into a new era of growth.”

A slowdown in the nuclear industry after Japan’s disaster this year has added to the need for more gas in Asia. Buoyed by the region, global demand is predicted to double in the next decade, according to independent research firm Sanford C. Bernstein & Co. It expects the excess of LNG to decline and sees demand sopping up all available gas by 2020.

“While a year ago some market commentators talked of the global glut of LNG, we believe the focus for investors should be on the impending global LNG shortage,” analyst Neil Beveridge of Bernstein said in a recent report.

Royal Dutch Shell PLC , which is pushing gas over oil around the world, feels the pressure to move quickly, too. In 2008, at the top of the continental gas market, it overpaid in its $5-billion purchase of Duvernay Oil, which has large holdings in the Montney shale play in northeastern B.C. The company, chatter in Kitimat suggests, may soon unveil its own LNG plans.

Lorraine Mitchelmore, Shell Canada president, is coy. She concedes that without LNG, the gas Shell bought from Duvernay could be “stranded.” She points to growth in Asian demand, triple the rate of other importing regions, and cites the need to move quickly, noting the competing supply in Australia. Shell is among the players there, moving forward on a floating LNG terminal, which would be the world’s largest ship.

“For [Shell Canada], it’s about Asia. We’re sitting on the doorstep of a great market,” Ms. Mitchelmore said in an interview in Vancouver. “It’s an obvious market for Western Canada gas.”

Apart from its abundant supply, Canada has another advantage. LNG tankers burn some of their product to keep the liquefied gas supercooled at -160 C while in transit. Because of this, the quickest path across the globe is also the cheapest – and ships sailing from Kitimat can get to key Asian markets faster than competitors in Australia and Middle Eastern gas exporters like Qatar, the world’s No 1 in LNG.

“We’ve got it hands down. We’ve got a lot shorter transport time,” Tim Wall, the president of Apache Canada, said in an interview in Calgary. “We can deliver to markets cheaper.”

Apache’s decision to invest in LNG in Canada came after it took a minority stake in Wheatstone LNG, which was approved in September. It’s a giant Chevron Corp. project under construction in Australia. The scale of Wheatstone – $30-billion for everything from gas field development to the LNG plant – speaks to the scope of Canada’s competition. The first gas is to hit the oceans in 2016.

Apache has never built an LNG plant but its Wheatstone position has paid dividends in Kitimat. The company already has marketing teams based in Australia and they have begun the work of selling Canadian gas. Apache has inked deals with two major Japanese power producers and its consortium for Kitimat LNG is in talks with six customers.

The efforts make clear the economic underpinnings for exporting LNG. Sales contracts will span a full 20 years – several lifetimes in the natural gas business – and they bear no relationship to the North American supply and demand dynamics that have so thoroughly depressed prices on this continent. They are instead tied to the price of oil, which has been far stronger in recent years.

That’s not to say a LNG plant will rain profit. Apache initially pegged the Kitimat LNG price at $4.7-billion, with hundreds of millions already spent by the end of this year. But Mr. Wall acknowledges that detailed engineering under way will drive that price up – it’s not clear how much – and suggests margins may be slim.

“There is an economic case,” he says. “But it’s a huge investment – and the payout is going to be somewhat longer. You’re trying to open up markets. There’s a huge prize for Canada, to become a major supplier of energy across the world.”

Competition also looms. Tom Tatham, who runs BC LNG Export Co-operative LLC, has established a 50-50 deal with the Haisla and is proposing a mini-LNG plant. The idea, which would be a world first, is to build a LNG facility on a barge and float it to Kitimat before setting it down against the shore. First gas is targeted to move in 2014.

Widespread support

After the Second World War, the B.C. government wanted to stoke development in the province’s wild and vast northwest. It brought in what is now Rio Tinto Alcan to look at potential hydroelectricity to fuel what became the world’s largest smelter. Kitimat was carved from the wilderness to house workers and the remote town was the Fort McMurray of its time, with some of the highest wages in Canada. “A huge number of men came to work in the pot lines and make a fortune,” says Kieran Leblanc, who was one of the first children born in town, in a makeshift hospital.

For the people of B.C.’s North Coast, the idea of exporting natural gas is not new. In March of 1982, Dome Petroleum signed an agreement to sell liquefied gas to a Japanese company. The company set out to build a major export port just north of Prince Rupert, but the project died when Dome crumpled under a huge debt load. Those who worked on the Dome dream always held hope that, one day, such a project would get built.

“Is now the time? Well, it’s probably closer to the time than when we were doing it,” said J.R. Van Der Linden, who led the LNG project for Dome. He kept a picture of its design on his home wall for nearly two decades, only recently taken down to make room for pictures of grandchildren.

Electrical power will be a big question for Kitimat. Existing BC Hydro infrastructure is inadequate, especially if Shell follows Apache. A third serious name is also looking at Kitimat – Malaysia’s state-owned Petronas, a top LNG exporter. This year Petronas paid $1.1-billion for a 50-per-cent stake in Montney shale gas fields in northeastern B.C. that are controlled by Calgary-based Progress Energy Resources Corp.

Pipelines are yet another issue. To feed gas to Kitimat LNG, a $1-billion, 465-kilometre pipeline, Pacific Trails, is required to link to existing pipelines near Prince George in the province’s northeast, the home of the gas. Owned by the Apache-EOG-Encana venture, it would traverse a route roughly similar to the proposed Northern Gateway oil sands pipeline, which is vehemently opposed by almost every single first nation along its sketched path.

But for gas, first nations have taken a pragmatic position. Fifteen first nations, using $35-million provided by the province, will take an equity stake and are set to receive roughly $550-million over 25 years from the pipeline profits, an average of $1.5-million annually for each nation.

“It’s not the default position of first nations to oppose,” said David Luggi, chief of the Carrier Sekani Tribal Council. “We want to participate in the economy but there are limits. Oil will spill. It’ll end up on the water, whether on the coast, or our rivers, our lakes. I’m not saying gas is completely safe but it won’t pollute like oil would.”

There are hints support could be fragile. Around the northeast BC gas fields, some concerns among first nations have percolated. The fear is controversial fracturing technology – the explosive technique that unleashes shale gas below ground. It has sparked wide public concern and has led to temporary development halts, from France to Quebec and New York state. Any shift in B.C.’s openness to shale gas could have severe consequences for LNG plans.

“We’re certainly not going to promote something that’s harming any of our neighbours,” says Art Sterritt, director of Coastal First Nations, an alliance of groups on the B.C. coast.

For now, however, the support for gas drilling and exports is expansive. Nathan Cullen, NDP MP for the Kitimat region and a leadership candidate to succeed Jack Layton, backs LNG, as does John Horgan, an MLA on Vancouver Island and provincial NDP energy critic.

“The geology’s night and day. We’re drilling three kilometres in to the ground before we’re doing the fracking,” Mr. Horgan said. He’s concerned about water use but his greater worry is global competition. “We need to get going,” Mr. Horgan said. “We’re not the only people who are awash in gas.”

Kitimat was whipped by the global recession. Rio Tinto Alcan halted a $2.5-billion modernization of its smelter and West Fraser Timber, the country’s largest forestry company, shuttered an aging pulp and paper in early 2010. Thom Meier, general manager at 101 Industries Ltd., remembers when a hydroelectric expansion was suddenly halted in the 1990s. A four-line fax bore the news. “ ‘Cease all operations,’ ” Mr. Meier said. “We know the tap can turn off quickly.”

But these days, a burgeoning confidence pervades the town. 101 Industries recently built an aluminum dock that floats on the water at Bish Cove, where workers disembark to ready the gas export site.

With the Kitimat LNG project on the doorstep, and Alcan’s modernization now moving ahead, Kitimat’s three-decade decline could radically reverse. If Shell joins the action, the region could see its population of about 7,000 double as workers arrive to build the facilities.

Joanne Monaghan, the mayor, jokes that her mantle has become “mayor of boom” – a welcome change from “mayor of doom.”

“When I came 40 years ago, I said, ‘This is a giant that will some day wake.’ It’s waking.”

By David Ebner, Nathan Vanderklippe (theglobeandmail)

Original Article

Canada: Encana Optimistic About LNG Exports


Encana Corp. foresees a “renaissance” in natural gas prices once terminals begin to pop up along the West Coast to export the fuel to energy-hungry Asian markets, but others addressing an energy conference on Tuesday weren’t quite so enthusiastic.

We think that the prices are going to stay robust in Asia. You look today in Japan, it’s still $13 US (per 1,000 cubic feet) over there,” Mike Graham, who heads up Encana’s Canadian division, told the Peters & Co. event.

In three to five years, when LNG really starts to pick up in North America, I think you’ll see another renaissance in natural gas prices.”

The huge supplies of gas flowing out of shales throughout North America have been landlocked for some time, resulting in a major supply glut that has kept prices in the anemic $4 range US.

One of the ways Encana Canada’s largest gas producer, seeks to remedy the situation is to tap into Asian markets. It, along with U.S. partners Apache Corp. and EOG Resources Inc. are planning to build a liquefied natural gas terminal in Kitimat, B.C.

There, gas piped in from northeastern British Columbia will be converted into a liquid in extremely cold temperatures. In a liquid state, the liquefied gas, or LNG, can then be loaded onto specialized tankers and sent overseas.

China is going to consume just about all the natural gas that the world can give them. They’ve only got maybe (one billion cubic feet per day) of LNG now, but they’re looking to put in 10 and even grow from there,” said Graham.

I think it’s going to be very robust. I think it’s going to have a tendency to pull oil prices down, and have a tendency to pull natural gas prices up. It does look quite likely that maybe a few years outbound, I think the forward curve will start to reflect LNG over the next couple of years and things will get a bit more robust soon.”

John Langille, vice-chairman of Canadian Natural Resources Ltd. (said he’s not quite so gung-ho.

I’m not quite as bullish, I don’t think, as some of my peer group here in terms of what time-frame,” he said.

Canadian Natural has a large land position in northeastern B.C.’s shales, but has been focusing most of its attention on developing oil- properties in Western Canada and abroad. It has signalled no interest so far in jumping aboard the LNG bandwagon, though Langille said eventually the gas will have to find its way out of North America.

And that will happen, but it’s a five-year scenario before that happens,” he said.

John Dielwart, chief executive officer of Arc Resources Ltd. said he sees prices recovering, but to a somewhat underwhelming extent.

Where we thought we might get back to $6, $7, maybe $8 gas a couple of years ago, now we’re saying $6 will be a pretty good price,” he said.

So I think the level at which gas prices might recover, I would say, has been tempered in many of our views. But the ability to stay where we are now for an extended period of time, year after year after year, I just don’t think that’s on the table.”

But Dielwart said he’s optimistic about demand growth. In Arc’s own backyard — Alberta — more and more power plants are making the switch from carbon-spewing coal to natural gas.

An in terms of LNG, Asian countries are most interested in gas from B.C. because the travel distance across the Pacific is so much shorter than from the Middle East, for example.

We certainly haven’t done any joint ventures, but we certainly talked to a lot of parties who are coming through Calgary. I would say the traffic has increased in the post-Fukushima world,” said Dielwart, referring to the March disaster at the Fukushima Dai-ichi nuclear power plant in Japan.

I think it’s only going to become a growing and growing story and LNG will be going to Asia out of northeast B.C. in the not too distant future.

Original Article

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