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Gulf of Mexico: Quest Offshore Sees Bright Future for Deepwater GoM (USA)

The Gulf of Mexico, more than any other major deepwater region in the world, has experienced massive changes in the last five years with long-term implications for the future of the region and the GoM’s supply & demand effects on the global deepwater oil and gas market, Quest Offshore says in its report.

The worldwide financial crisis and subsequent recession, shale gas’ implications on U.S. natural gas prices and the aftermath of the Macondo incident have led to significant changes in the outlook for the region. Despite those overwhelming obstacles, the U.S. GoM’s future is bright with a pronounced recovery expected in all major market segments from drilling to subsea, floating production and marine construction.

Overall spending in the region is expected to increase significantly starting in 2013 up nearly 30 percent to $40 billion. Total expenditures are expected to reach a significant $167 billion in the 2013 to 2016 period. For the first time, 2012 is expected to represent an investment shift with deepwater CAPEX and OPEX spending surpassing that in shallow water. In the under developed ultra-deepwater frontier areas of the region, challenging technical and reservoir conditions will result in increased spending across the board, a trend expected to continue through the foreseeable future.

Five years ago the region was a mix of major and independent oil companies executing both oil and gas standalone and subsea tieback projects. In 2013 and beyond, Quest sees more oil dominance with offshore gas waning. Large international oil companies will play a larger role with the execution of standalone (hub) projects with niche-focused independents looking to infrastructure-led drilling around existing hubs and mega-independents continuing to grow their strategic portfolios in select basins.

In Quest Offshore’s latest market report, Quest Deepwater Review: Gulf of Mexico 2013 and Beyond, the reader will gain a comprehensive understanding of current trends and expectations from one of the leading deepwater basins, the U.S. Gulf of Mexico.

Leasing Activity Positive for Deep and Ultra-deepwater

Leasing activity is rightly seen as the furthest leading indicator for prospective oil and gas activity not only in the Gulf but throughout the world. Due to the relatively long lead times between leasing, drilling and production, leasing trends can be expected to provide insight on future activity for years to come. With one-third of active deepwater leases, oil majors and national oil companies are expected to continue to be the driving force for pushing the boundaries of the Gulf of Mexico’s development. Excluding Anadarko and Conoco, all recent frontier projects have been undertaken through operatorship’s of one of the majors or national oil companies (BP, Chevron, Exxon, Shell, Total, Statoil, Petrobras), and we expect this theme to persist moving forward.

Drilling Permitting on an Upward Trend

Drilling permit approvals are showing noticeable increases over the past six months with total counts back to pre-Macondo levels. As of the end of September there have been 78 new exploration drilling permits and 36 new development drilling permits approved over the year.

While raw permit counts are showing positive movement this year, the comparison in permits issued per project highlights the underlying cause for such steep increases in the first half of 2012. Multi-well projects (defined as five or more wells) have seen a record permitting pace since late 2011; examples of this trend include Chevron’s Jack/St. Malo Project, Shell’s Mars B Project, Hess’s Tubular Bells project, Chevron’s Big Foot and most recently the BP’s Atlantis North development, while true wildcat exploration permit numbers are still well below levels seen prior to the drilling moratorium.

Drilling Market Accelerating

Notable discoveries of ultra-deepwater fields in the Lower Tertiary continue to increase the reserve and production expectations for the region. The shift in the Gulf is most apparent in the floating rig market with four operators now possessing 50 percent of the contracted rig fleet. Ninety percent of rigs operating are high-spec and rated for ultra-deepwater.

Robust Outlook for Deepwater Development

Since 2008, the U.S. Gulf of Mexico has undergone a shift in project development mix from heavy in small, independent-operated subsea tiebacks to one that is grounded in fewer, larger subsea tiebacks and high-investment standalone developments developed by international oil companies and mega-independents.

This shift towards fewer, larger subsea tiebacks as well as increased FPS units will have profound effects on the future of the subsea sector as the hardware installed evolves as a direct result of fewer gas developments and deeper, more challenging fields. Subsea equipment manufacturers will experience fewer, but larger scope, award opportunities through the forecast period. As these developments move into more challenging areas, the value of these subsea production packages are expected to increase significantly as HP/HT trees and subsea processing become an enabler for these complex, capital-intensive projects.

This next wave of FPS developments is, for the most part, in ultra-deepwater and in more remote areas not currently connected to shallow water or onshore infrastructure. These developments will materially impact the pipeline and marine construction markets (SURF) as these production hubs are connected to existing export infrastructure through 2016 and beyond. The subsea tieback potential for these hubs is most likely to be seen in the latter half of this decade and into the following, with these latest hubs laying the foundation for the next generation of deepwater developments in the region.

Quest Offshore Sees Bright Future for Deepwater GoM (USA)| Offshore Energy Today.

USA: Attorney General Seeks to Prevent Future LNG Terminals Near RI


The Weaver’s Cove LNG terminal project was abandoned over a year ago, in June 2011, but Rhode Island Attorney General Peter F. Kilmartin continues his effort by seeking standards that would help prevent such a project in the future.

On Wednesday, Kilmartin, joined by Massachusetts Attorney General Martha Coakley, renewed a request to the federal government for rules for the location and siting of LNG import and storage facilities. Wednesday’s request comes in the form of an appeal filed in connection with an earlier petition for rulemaking directed to the Pipeline & Hazardous Materials Safety Administration within the United States Department of Transportation (USDOT).

This is the latest step in a petition that was first filed in September 2004. In early February, a lower official in the USDOT had denied the original request.

In support of the request, Attorney General Kilmartin stated, “While the State obviously had concerns about Weaver’s Cove’s proposal to construct an LNG facility in a densely-populated urban environment in Massachusetts, with tanker traffic transiting through actively-used Rhode Island waters, within close distance of populated shorelines, Rhode Island’s motives were – and remain – much more broad. Indeed, these motives apply to any number of other locations in close proximity to populated areas and heavily-used waters of Rhode Island on which future LNG developers may set their sights. The petition expresses concern not just about whether a single project goes forward, but over the need for USDOT to set standards that apply to any number of sites that could put Rhode Island’s citizens and natural resources at risk.”

Kilmartin added that “USDOT has continually failed to establish minimum safety standards for determining the location of LNG facilities and has only established minimum federal safety standards for the design of those facilities. We seek to correct this to prevent another unsuitable proposal like Weaver’s Cove in the future.

The Weaver’s Cove LNG facility was proposed in December 2003 and became the target of an 8-year fight waged by the Attorney General’s office and other state officials to protect Narragansett Bay from hazards and closures.

Kilmartin said, “While that fight reached a successful conclusion when the developer withdrew the proposal in June of 2011, we do not want to have to have a repeat of that threat.



Soc Gen Says China May Look for US LNG Deals in Future


China may look to buy US LNG volumes in the future as an alternative to buying more gas from Russia, one European gas analyst said.

Soc Gen analyst Thierry Bros said in a report Tuesday that, with US Gulf Coast LNG expected to materialize in 2016, China will likely first look into a potential US LNG deal before signing a gas supply agreement with Gazprom.

The bank estimates the minimum breakeven cost for US Gulf Coast LNG delivered into China, taking shipping into account, would work out at around $11.6/MMBtu. This allows plenty of room for negotiations between companies selling US LNG and the Chinese from $13.50/MMBtu — which would allow a minimum of 15% return on investment — and $22/MMBtu — which takes into account full oil indexation — Societe Generale added.

The $13.5 to $22/MMBtu negotiation range translates into a price of oil between $77/b and $133/b, or an oil-indexation formula with a slope between 0.10 and 0.17. This is large enough to match a Russian pipe-gas oil-index price,” Bros said.

As a result, Societe Generale believes China will prefer to look further into US LNG rather than rely on securing an agreement with Gazprom, which could further delay negotiations between Russia and China.

Judging by the seeming lack of any progress in the gas pricing issue during [Russian Prime Minister Vladimir] Putin’s recent visit to China, it seems Beijing is in no particular hurry to sign the contract,” Bros said.

In 2006, Moscow and Beijing signed an initial agreement on gas supplies, when they agreed to construct two pipelines to transport a total of 68 billion cubic meters/year of gas from Russia to China over 30 years. Gazprom and China’s state-owned CNPC in 2010 subsequently signed a legally binding agreement on the supply of up to 30 Bcm/year.

Negotiations since then have not gone as smoothly and have been bogged down by pricing disagreements. Putin’s recent visit to Beijing in October didn’t resolve any of those issues although he said the parties were “on their way to the final stage of negotiations.”

The report published by Societe Generale comes in response to the latest agreement between Cheniere Energy Partners’ Sabine Pass Liquefaction unit in the US and Gas Natural Fenosa announced on Monday.

Under the LNG-sale-and purchase agreement, Gas Natural Fenosa would buy as much as 3.5 million mt/year of LNG. The deal is expected to help facilitate the construction of the first two liquefaction trains at the site, which would produce 9 million mt/year of LNG in the first phase. Construction of the two trains at Sabine Pass is estimated to begin in 2012.



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

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