Wednesday, May 30, 2012

Judge reaffirms, clarifies injunction against Greenpeace on Shell vessels

Tim Bradner
Alaska Journal of Commerce

A U.S. District Court judge in Alaska issued an order late May 29 narrowing and clarifying a preliminary injunction barring Greenpeace USA from interfering with Shell’s exploration efforts to Shell’s drilling and support vessels in the U.S. exclusive economic zone, mainly Outer Continental Shelf waters off Alaska’s Arctic coasts.

Previously the injunction applied broadly to all Shell vessels in U.S. territorial waters or ports.

The new order basically reaffirms the injunction, originally made March 28, for Alaskan waters, but also expands and clarifies it so that activities in the OCS are included and also any parties working in concert with Greenpeace are included in the injunction.

“We are very pleased that the Alaska District Court modified the existing preliminary injunction,” Shell spokesman Curtis Smith said. “Greenpeace activists have consistently endangered the safety of the crews aboard Shell-chartered vessels and this ruling could add an additional measure of safety for our personnel and assets during the summer drilling season,” Smith said.

Greenpeace activists boarded the Shell-chartered Noble Discoverer drillshup in New Zealand prior to that vessel’s departure for the U.S. Activists also boarded Shell-contracted icebreakers in Finland and attempted at-sea boardings off the coasts of Sweden and Denmark, Shell said in a statement.

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Finding a good target; Statoil’s first well in Chukchi Sea will test the company’s Amundsen prospect

Alan Bailey
Petroleum News

Statoil’s first Chukchi Sea exploration well, planned for 2014, will likely target the Amundsen prospect, a large geologic structure that appears to contain rock horizons with oil and gas reservoir potential within what geologists refer to as the “rift sequence,” April Parsons, lead geologist for Statoil Exploration Alaska, told a meeting of the Alaska Geological Society on May 17.

Parsons said that the Amundsen prospect is located in some promising looking geologic structures that Statoil had found from seismic data prior to the 2008 Chukchi Sea lease sale in which the company had purchased its leases. The company has identified two oil prospects within its lease acreage — the Augustine and Amundsen prospects — with the Amundsen prospect, the larger of the two, becoming the primary exploration target.

Statoil operates 16 offshore leases about 100 miles northwest of the Chukchi Sea coastal village of Wainwright.

3-D seismic
During the 2010 Arctic open water season the company conducted a 3-D seismic survey across an area that encompasses its leases, to obtain a more detailed understanding of the subsurface geology and identify drilling targets. Statoil contracted with Fugro GeoServices to use a modern geophysical vessel, the Fugro Geo Celtic, to carry out the survey by towing 12 streamers of seismic recorders, Parsons said. With the 4,000-meter streamers spaced at 100-meter intervals behind the vessel but fanning out to a separation of 125 meters, it was possible to cover the planned survey area very efficiently, she said.

But with only five very widely spaced wells ever having been drilled in the entire Chukchi Sea, there is a severe shortage of geologic data that can be tied into images of the subsurface constructed from seismic data. So, with the closest of the Chukchi Sea wells, the Burger well, lying about 35 miles south of the Statoil leases, in addition to shooting the 3-D survey Statoil elected to shoot a single 2-D seismic line from the Burger well up to the 3-D area. The 2-D line enabled Statoil geoscientists to extrapolate the rock stratigraphy, as determined by well logs and rock samples from the Burger well, to the Statoil prospects.

Kuparuk sandstone
Of particular interest is the fact that a 110-foot sandstone interval in the Burger well demonstrated good reservoir characteristics and is known to contain a major pool of natural gas. The sandstone, equivalent in age to the oil-bearing Kuparuk sandstone in the Kuparuk River field in the central North Slope, lies underneath a regional geologic discontinuity called the Lower Cretaceous unconformity (an unconformity is a geologic feature created during a break in sediment deposition, when strata below the unconformity become eroded and then subsequently covered by younger rock formations).

The Statoil geoscientists were able to identify the Lower Cretaceous unconformity in a seismic cross section constructed from the 2-D seismic line. They then used the unconformity as a marker to trace the reservoir sand from Burger across into the Statoil prospects, Parsons said.

In fact, the detailed 3-D seismic over the Statoil prospects depicts a series of unconformities, thus confirming the fact the region has experienced numerous geologic upheavals during its long history. Particularly prominent, in addition to the Lower Cretaceous unconformity, are a regional unconformity in what is called the Brookian, the youngest and shallowest of the major rock sequences of northern Alaska; an unconformity that marks the boundary between the Tertiary and Cretaceous periods; and another regional unconformity of Jurassic age.

A subsurface image constructed from Statoil’s 3-D seismic data shows some especially spectacular geologic features on the unconformity between the Tertiary and the Cretaceous, with river features such as incised valleys clearly visible on what would have been a land surface about 65 million years ago.

Three-way closure
The seismic shows the Amundsen prospect to be what is called a three-way closure — an elongated dome sloping off in three directions and bounded by a major geologic fault. The detailed 3-D seismic has revealed extensive faulting in the structure.

Within the prospect Statoil wants to drill the complete rift sequence, a package of rocks between the lower Cretaceous unconformity and the older and deeper Jurassic unconformity. The rift sequence package across the Amundsen structure is quite thick and, although the Kuparuk-equivalent sand traced from the Burger well is Statoil’s main target, there is potential for finding oil and gas reservoir rocks at various levels within the sequence, Parsons said. Statoil is primarily seeking what are called structural traps, locations where the folding and faulting of the strata have created situations where oil could have accumulated.

The planned first well would penetrate a flank of the Amundsen structure rather than the structure’s crest, to enable Statoil to evaluate oil volumes using a single well, should the well encounter hydrocarbon resources, Parsons said. The well would need to reach a maximum depth of a little less than 10,000 feet to reach the Jurassic unconformity, she said.

Shublik source
Statoil anticipates the Shublik formation, of Triassic age and a prominent source rock in northern Alaska, to be the likely source of any oil and gas in its Chukchi Sea prospects — assessments of regional thermal maturity indicate that the Shublik would likely generate oil at an appropriate location to feed Statoil’s prospects. Statoil wants to find oil rather than natural gas in its Chukchi Sea exploration, Parsons said.

The Shublik lies in an older and deeper rock sequence known as the Ellesmerian, below the Jurassic unconformity. Strata within the Ellesmerian contain several of the major oil fields in the central North Slope, including the giant Prudhoe Bay field. However, although the geologic structures at the Amundsen prospect extend downwards into the Ellesmerian, Statoil does not plan to penetrate and test the Ellesmerian with its first Chukchi Sea well, Parsons said. After drilling that first well and after having gained a better understanding of factors such as the subsurface pressures, Statoil may drill some subsequent wells into deeper structures, she said.

Although at Burger a thick sequence of Cretaceous rock extends all the way from above the lower Cretaceous unconformity to the seafloor, in the Statoil leases there is a thick sequence of younger, Tertiary strata above the Cretaceous. The Brookian sequence above the lower Cretaceous unconformity in the leased area does not appear to contain any significant geologic structures and does not appear to be particularly prospective for oil and gas, Parsons said.

Site surveys
During the open water season of 2011 Statoil checked out some potential drilling sites in its leases by conducting shallow hazards surveys, primarily by gathering shallow, high resolution seismic data. The company also gathered shallow rock cores, to determine the nature of the seafloor at those sites. The seafloor in the area is really hard and quite level, with an almost constant sea depth of about 120 feet, Parsons said.

The most interesting feature on the seafloor is a series of crisscrossing ice scours. But, especially given the general absence of recent sediment on the seafloor, there is no good way of assigning ages to the scours, Parsons said.

However, the 2011 surveying did not find any potential hazards at any of the planned drill sites, she said.

Shell launches LNG plans; Lifts curtain on largest of Canada’s ventures, warning there is no time to lose

Gary Park
For Petroleum News

Royal Dutch Shell is leading three Asian firms in rolling out plans for by far the largest of the projects to export LNG from British Columbia.

The newly titled LNG Canada venture, carrying an estimated cost of C$12.3 billion, is tentatively scheduled for startup late this decade, with initial capacity of 12 million metric tons a year of capacity.

That target easily outstrips the Apache-operated Kitimat LNG project at 5 million metric tons a year and the BC LNG Export Cooperative at 1.8 million metric tons a year — the only two proposals that currently have 20-year export permits from Canada’s National Energy Board.

With Korea Gas Corp. (Kogas), Mitsubishi and PetroChina each holding 20 percent stakes, LNG Canada is now in the final stages of engineering work, preparing for environmental assessments and consulting with various stakeholders.

The plans set the stage for the British Columbia government of Premier Christy Clark to have three LNG export operations up and running by 2020.

What isn’t clear is whether growing opposition from environmentalists and First Nations to proposals by Enbridge and Kinder Morgan to ship Alberta oil sands crude from the British Columbia coast to Asia will start spilling over to the LNG sector.

But the Canadian government has promised to streamline its environmental reviews to end what it regards as unnecessary opposition to its efforts to diversify oil and gas markets beyond the United States.

Shell: LNG complex

Lorraine Mitchelmore, president of Shell’s Canadian operations, said LNG is a very complex undertaking requiring a multitude of permits and faces considerable uncertainty.
“It’s going to take a lot to bring that to the final investment decision,” she said.

Mitchelmore warned that delays in proceeding with LNG Canada could put at risk the British Columbia government’s chances of collecting C$600 billion in royalties over the next 25 years if it can arrange buyers for its vast shale gas resources.

She said the 12 million metric tons a year of LNG currently planned for LNG Canada represents about 15 percent of Japan’s market, “which is the largest market in the world.”

“We sit in a magnificent position. … We are now on the doorstep of the fastest-growing market in Asia,” she said, noting that the Asian region could add another 80 million metric tons a year of LNG demand by 2020.

Mitchelmore said Shell does not believe that even China, which owns huge gas resources, will be able to develop those supplies fast enough to meet its demand.

But she conceded that although Canada currently has a “unique opportunity,” the longer-term picture is fuzzy.

“We understand our competition now and we understand that we have a very competitive supply,” Mitchelmore said. “But we need to make it happen.”

Manley: Agreements needed

Joining the chorus of industry and political leaders raising concerns about the barriers standing in the way of Canadian LNG development, former deputy Prime Minister John Manley, now head of the Canadian Council of Chief Executives, said there is a danger that Canadians feel too smug about their ability to open up new export markets.
“We just feel way too good about ourselves,” he told a Calgary audience. “I don’t think we have a sense of urgency about seizing the opportunities that global dynamics are presenting to us and I think our greatest enemy now is not the European financial crisis of the U.S. deficit. It’s hubris, complacency.”

Manley said Canada should start to view itself as a Pacific nation and start negotiating trade and economic agreement that will help crack Asian markets.

The eagerness among the Asian partners to move ahead with LNG Canada was underscored by Kogas which said it has secured 2.4 million metric tons a year of the project’s capacity.

Kwon Yong-Shik, in charge of LNG supplies at Kogas, said LNG Canada is designed to “ensure stable supplies and diversify import sources for South Korea which has heavily depended on the Middle East.”

“We hope the joint project will pave the way for Kogas to have an independent LNG project in Canada,” he said.

Report urges diversification

A May 10 report by the accounting and consulting firm of Ernst & Young said Canada, faced with low gas prices and a shrinking U.S. export market, urgently needs to diversify its sales outlets.
“We really don’t think that Canada has a choice,” said Lance Mortlock, senior manager of the firm’s oil and gas advisory practice. “The opportunity window will be open for a finite period of time.”

Ernst & Young forecast that Canada could have about 12 million metric tons a year of LNG export capacity in place by 2015, depending on whether U.S. Gulf Coast proponents and other worldwide competitors gain an edge.

It also estimated that Canada will need to overcome environmental and First Nations’ concerns and invest C$50 billion in LNG infrastructure over the next decade to answer the “powerful threats” posed by rival supply sources.

Spectra Energy said in a statement earlier in May that it is poised to invest an additional C$4 billion-C$6 billion in British Columbia beyond 2015 in pipelines for anticipated LNG export facilities and to unlock development of the Montney, Horn River and other resource areas.

Currently working on a C$1.5 billion expansion program in British Columbia over the 2009-13 period, Spectra is eager to expand its horizon beyond domestic needs to ensure diverse and stable supplies for Asia, said Doug Bloom, president of the company’s Western Canadian operations.

Tuesday, May 29, 2012

Making the Grade (Or Not): Business Groups Rate Lawmakers; Lawmakers get their report cards from the business community

9th Circuit gives final approval to Shell exploration plan

Tim Bradner
Alaska Journal of Commerce

A federal appeals court upheld the government’s approval of an exploration plan filed by Shell to explore its outer continental shelf leases in the Arctic in 2012.

The unanimous May 25 decision was by a three-judge panel of the 9th Circuit Court of Appeals.

Greenpeace, the Sierra Club, the Wilderness Society and two Alaskan Inupiat groups had appealed the approval of the Beaufort Sea and Chukchi Sea drilling plans given by the Bureau of Ocean Energy Management last August.

The challengers had claimed that Shell's proposal for a well-capping stack and containment system in the event of an oil spill was incomplete and that it had failed to fully inform the government about its oil spill response plan.

Shell spokesman Curtis Smith said the company was expecting a favorable decision by the court.

“There are other appeals still pending, such as those of our air quality permits, but the favorable ruling on the exploration plan is a substantial boost for us,” Smith said.

A similar exploration plan by Shell had been before the same judges on the appeals court in 2010, and was approved.

Shell is now mobilizing its fleet to do exploration in both the Beaufort and Chukchi seas this summer. The drillship Noble Discoverer and the Kulluk, a conical, mobile drilling structure, are both in a Seattle shipyard undergoing final refitting and preparing to depart to Dutch Harbor in mid-June along with support vessels.

Smith said the air emissions systems for the Kulluk were upgraded in Seattle. The Kulluk is actually owned by Shell and is, interestingly, the only drilling unit owned by the company.

Similar upgrades to air emissions system of the Noble Discoverer were made in a Singapore shipyard, but in Seattle additional “winterizing” modifications, such as the addition of wind shields, are being done.

An oil spill response vessel and a second support ship have been in Valdez where crews are undergoing spill response training.

Plans are for all the vessels to be in Arctic waters in August to begin drilling, which must be completed by late fall, when ice moves into the exploration areas.

Environmental groups have also filed appeals to the 9th Circuit court of final government approvals of federal air quality permits for the drillships, but Smith said Shell expects those to all be approved as well.

The permits were issued by the U.S. Environmental Protection Agency and withstood appeals by environmental groups to the EPA’s internal Environmental Appeals Board.

Traditionally, courts defer to the executive branch in regulatory matters as long as the agency decisions were within the scope of law, and normal procedures were followed.

Read more:

Governor speaks out on the Dan Fagan show

Thursday, May 24, 2012

Governor Parnell speaks about the Sackett case against the EPA

PUBLIC COMMENT - Wood-Tikchik State Park

Dear Alaskan,

The Department of Natural Resources, Division of Parks and Outdoor Recreation, has received an application from Nuvista Light & Electric Cooperative, Inc. to perform a variety of scientific field studies for Summer/Fall of 2012, at locations in and around Chikuminuk Lake and Allen River, located in the northern area of Wood-Tikchik State Park. The field studies are related to the proposed Chikuminuk Lake Hydroelectric Project. You are invited to review the attached application materials and provide comment. If authorized, the term of the Special Park Use Permit would begin June 1, 2012 and expire December 31, 2012; and would authorize a variety of field studies to include: geophysical, geotechnical, survey and mapping, hydrology and water quality, terrestrial and aquatic biology, and recreation.

To submit comments, please write to the Director’s Office of the Division of Parks and Outdoor Recreation within 30-days of this notice. Please direct written comments to David Griffin, or send an email to, before close of business 5pm, Monday, May 14, 2012. You need not respond if you do not have any recommendations. The purpose of this notice is to gather input before a final determination is made to ensure that issuance of the proposed permit will be in the best interest of the State of Alaska.

If you have any questions please call Monday through Friday, 8:00AM-5:00PM at (907) 269-8696.

Friday, May 18, 2012

Consultant: nimble footwork on gas exports, energy rethink needed

—Alan Bailey
Petroleum News

Although the fundamentals of energy supply and demand still underpin the long-term future of the oil and gas industry, the pace of change in the energy scene has been accelerating, Edward Chow, senior fellow of energy and national security at the Center for Strategic and International Studies, a Washington, D.C., think tank, observed to the Alaska World Affairs Council on May 11. This rapid change and the resulting uncertainty creates difficulties for an industry that needs to invest in projects that may take 10 to 15 years to pay off, Chow said.

Price volatility

“We don’t know where all of this is actually leading,” Chow said. “The most obvious indicator of that (rapid change) is price volatility in the oil and gas market.”

Things that used to take decades to work through now seem to happen in days or even hours, he said. The price of oil more than doubled between the summer of 2007 and the summer of 2008, hitting a peak of $147 before crashing back to $32 and then climbing back up again.

“Last year, 2011, was the highest average price in the history of the petroleum industry,” Chow said.

Chow said that there is probably now a $20 risk premium factored into the oil price, reflecting oil traders’ concerns over possible supply disruption because of issues such as the Libya uprising last year and the Iranian situation this year.

And at the moment market psychology has taken over from supply and demand fundamentals in oil futures trading, Chow said.

“People are speculating on sentiment, as opposed to speculating on supply and demand. It’s no longer strictly a hedging phenomenon,” he said.

At the same time, oil demand is sluggish to respond to price changes — people do not immediately change their cars when prices go up. And it takes the oil industry a long time to respond to high prices because of the lead time involved in bringing new oilfield projects to fruition.

Debunking peak oil

However, the high oil prices have brought to light the weakness of a theory that the world is about to pass an unsustainable peak in oil supplies. New oil and gas resources have magically appeared in improbable locations such as Uganda, offshore Mozambique and the eastern Mediterranean, Chow said.

“The other thing that we’ve learned in the last few years … is the peak oil theory is bunk,” he said.

It turns out that the availability of oil and gas supplies is determined by people’s imagination, their ability to harness innovative technology and by the amount of investment that people are willing to risk, and not so much by geology, he said.

Shale gas

Nothing perhaps illustrates this phenomenon better than the spectacular resurgence of North American natural gas production as a consequence of new technologies for shale gas development.

“If you had told me five or seven years ago that the United States would be producing more gas than Russia I would have thought you were crazy,” Chow said.

High gas prices at around $13 per million British thermal units originally drove the shale gas revolution, but as North American gas prices have dropped, now to around $2, the shale gas technologies have improved and become cheaper.

There are large disparities in the price of natural gas and liquefied natural gas, or LNG, around the world. Gas is currently worth $16 to $18 per million British thermal unit in Japan and $8 to $10 in Europe, Chow said. But with the United States moving into a position where it can export LNG and with regional gas markets becoming increasingly linked by the global LNG trade, in the next 10 to 15 years the international gas market will probably converge, becoming more like the globally connected oil market, rather than be dominated by gas supply contracts indexed to the price of oil, Chow said.

Asian opportunity

Meantime there is such a price premium in the northeast Asian gas market that someone is going to capture that market before the window of opportunity in that market closes.
“There is a window of opportunity for Alaska gas, perhaps in Asia, but it is not an infinitely wide window of opportunity,” Chow said. “You need to move quickly in order to seize that opportunity.”

In a few years Australia will be exporting more LNG than Qatar, world-class discoveries in Africa will go into the LNG market and China is talking about producing more gas, including shale gas. If the shale gas revolution can be replicated internationally, then the Chinese will do it, Chow said.

But Chow cautioned against the state taking on the business risk involved in a project such as bringing Alaska gas to market. In a free market investors need to take the risks, with government providing the appropriate conditions to encourage investment, Chow said.

Oil vulnerability

Despite the renaissance in the U.S. oil and gas industry, Chow said that the continuing high level of U.S. dependence on oil makes him less optimistic about the situation than some observers. The 4.9 million barrels of oil spilled into the Gulf of Mexico from BP’s Macondo well is equivalent to six hours of U.S. oil consumption every day, Chow said.

“We have 4 percent of the world’s population and we consume more than 20 percent of the world’s oil,” he said.

And, although the U.S. has plenty of domestic coal, hydropower, nuclear energy and natural gas, the country has to import substantial volumes of oil. The world as a whole consumes 8 million to 9 million barrels of oil per day, Chow commented while also questioning the sustainability of the continuing rise of this consumption rate.

“It’s oil where the vulnerability is,” Chow said.

Transformation needed

The preponderance of oil consumed in the U.S. goes as liquid fuels into the tanks of private vehicles — there are 240 million passenger vehicles registered in the country, Chow said. The U.S. needs to transform its energy usage, with a different transportation system and a rethink on issues such country living and the need to commute to work. But such a transformation would take decades to bring about.

“In order to do this we need a national dialogue about the challenges that are involved, an honest dialogue, not one that is marked only by slogans,” Chow said.

That will take brave politicians who are willing to talk about these issues in a serious way, he said.

Gasoline tax

Chow said that he personally favors a major hike in the federal gasoline tax — by at least 50 cents or perhaps by a dollar or more — as a means of dampening oil demand. A price signal such as this is a better means of guiding consumer and producer behavior than government mandates or regulations, he said. And the regressive aspects of a gasoline tax — the way in which it would hit the poorer members of society harder than those better off — could be offset by tax rebates, say on the social security tax, for the working poor.

Right now high oil prices are producing a surplus economic rent that is going to oil producers such as Russia and Venezuela, rather than to the United States. Directing that economic rent into the U.S. through the gasoline tax could help reduce the federal deficit and reduce concerns about the viability of programs such as social security, while at the same time achieving a public policy objective, Chow said.

However, no one who favors higher gasoline taxes will be elected into office, he admitted.

But, Chow said, it is a role of think tanks such as his to ask the sometimes uncomfortable questions that people need to address, even if that means saying unpopular things.

“If we are going to wander foolishly into an unsustainable path, at least some of us are raising the alarm bell,” he said.

Wednesday, May 16, 2012

Modest bids in Cook Inlet sale; none for Alaska Peninsula leases

Tim Bradner
Alaska Journal of Commerce

There was only modest bidding May 16 in a Cook Inlet oil and gas areawide lease sale, and an offering of leases on the Alaska Peninsula in southwest Alaska at the same time brought no bids in the sale.

State oil and gas director Bill Barron said the total of apparent high bids was $6.86 million with 44 tracts sold to three independent companies and one individual submitting bids. All 44 tracts offered in the Cook Inlet sale received bids, which covered 200,320 acres.

Most of the bids were near the $25 per acre minimum bid price but Cook Inlet Energy offered several bids substantially higher than the minimum, the highest at $82 per acre.

Barron said the sale results reflected a continued interest by the industry in the Inlet.

“It has been very busy in the last couple of years, with new companies like Apache, Hillcorp, Cook Inlet Energy and Buccaneer exploring,” Barron said at the lease sale.

Cook Inlet Energy, subsidiary of Tennessee-based Miller Energy, is the apparent winner on most leases sold with high bids on 18 tracts acquired followed by Texas-basd Hillcorp, which submitted high bids on 17 tracts. Apache Corp. submitted high bids on eight leases.

Tracts receiving high bids were mostly near existing producing areas on the east and west side of Cook Inlet. William Crawford submitted the lone by an individual for one tract in the Matanuska-Susitna Borough north of Anchorage.

There were seven leases that brought more than one bid. On six of them Cook Inlet Energy beat out Apache Corp. On the seventh contested lease Hilcorp beat out a bid by Buccaneer Energy, another independent exploring in the Inlet. Buccaneer submitted only one bid for a lease.

All three independent companies submitting bids are current leaseholders in the region. Hilcorp acquired producing assets Chevron Corp., mainly offshore oil and gas producing platforms. Cook Inlet Energy is producing oil and gas from the small field on the west side of the Inlet.

Apache is not a current producer but is now the largest owner of leases in the Cook Inlet region and is engaged in a major multi-year exploration program.

Barron said all high bids are apparent at this point and that final results will be published on the Division of Oil and Gas website Thursday.

The lack of bids in the Alaska Peninsula region was no surprise. The acreage is offered every year as part of the annual Cook Inlet areawide sale, and there have been no bids for Alaska Peninsula leases in recent years.

This article appears in the May Issue 2 2012 issue of Alaska Journal of Commerce

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Saturday, May 12, 2012

China ready to wait; Some C$20B invested in Canada; investment could grow 10-fold over 10-15 years

Gary Park
For Petroleum News

China’s stable of state-owned energy companies has invested about C$20 billion in Canada’s oil sands and shale gas assets — proof positive that Beijing is ready to ride out a stormy passage for pipelines from Alberta, across British Columbia to ship production across the Pacific, says Zhang Junsai, China’s ambassador to Canada.

The delays in approving the key infrastructure elements will not deter China from seeking a key role in the development of those resources, he told reporters in Calgary.

Typifying the Chinese reputation for taking a long-range view of its investments, he said China has access to ample imports of oil and natural gas from Australia, Qatar and Russia, so, if necessary, supplies from Canada can wait.

“There`s investment opportunity because Canada is open for international investment,” Zhang said.

Read more

“If there’s opportunity, Chinese companies will come to take some shares, as I say, to learn from Canada.

“We buy our resources, our energy, from other channels. There are a lot of channels. But we’ll work on Canada’s exports to China or oil and gas. That will happen in the next few years.”

He said the investment to date is primarily directed at improving China’s knowledge of developing unconventional resources and turning a profit.

Prime Minister Stephen Harper has pledged to turn Canada into a global energy superpower by diversifying exports of Canadian oil sands crude and LNG to Asia, but opposition to plans by Enbridge and Kinder Morgan to build pipeline from Alberta’s oil sands to tanker terminals on the British Columbia coast has raised concerns about Harper’s chances of achieving his goal.

However, on the first anniversary of his weeping election victory, Harper said Canada must align itself with the economic winners of the world to ensure continuing prosperity.

“The financial and debt crisis of the past few years may not in many countries be a passing phenomenon,” he said.

“World economic power and wealth are shifting in a way that is historic and we as Canadians must decide that we will be on the right side of that history.”

Harper said the latest federal budget, which contained provisions to streamline regulatory approval of major energy projects, is aimed at sustaining a “vibrant, growing economy for all Canadians, while protecting our environment.”

He said the government’s economic plan looks at the bigger picture and focuses on the longer term.

Investment growth expected
The importance of winning over the Chinese was emphasized by Gordon Houlden, director of the University of Alberta’s China Institute.

He said Chinese investment could grow ten-fold from the current level of C$20 billion over the next 10 years to 15 years.

Beijing-based lawyer Robert Kwauk of Blake, Cassels & Graydon, said that if Enbridge’s Northern Gateway project is approved it is likely Chinese investments in Canada’s energy sector will top the largest single deal so far, when Sinopec acquired ConocoPhillips’ 9 percent stake in the Syncrude Canada oil sands consortium for C$4.65 billion.

“The ball is really in our court to get that pipeline built,” he said.

Xu Xiaojie, a senior researcher at the Beijing-based Institute of World Economics and Politics, said China’s firms want to profit by taking cheap Canadian gas and building LNG pipelines and export facilities and selling the LNG to Asian buyers — not just those in China — who are willing to pay eight times more than North American buyers.

He noted that the gap between supply and price in Asia is currently running as high as US$16 per million British thermal units.

Firm: Big 3 oil producers not always in control

Bob Tzacz

Alaska’s three oil giants are often seen as masters of the energy universe, not only controlling their own fates but also sometimes bending governments to their wills. ExxonMobil, ConocoPhillips and BP are among the mightiest business entities that ever crossed a trading floor, but a legislative review of their global portfolios showed that they also struggle with market evolution and the results of their own decisions.

BP, for example, is “a company that is fighting (production) decline” and all three are “in the throes of pretty fundamental change,” according to Tony Reinsch, a senior director for PFC Energy, the legislature’s consultant on oil and gas issues. The company provided technical expertise for this year’s regular and special session’s and continues under a $250,000 contract extension approved during last month’s term.

Reinsch provided a capital allocation and global portfolio review for each company at an April 24 hearing of the House Resources Committee.

With production of 4.5 million barrel of oil equivalence (mboe) per day, 24.9 billion (mmboe) in reserves and an April 2012 market capitalization of $402 billion, ExxonMobil is larger than the other two combined.

BP’s market capitalization was $133 billion, with 2010 production of 3.4 mboe and 17.3 mmboe in reserves. ConocoPhillips is a distant third at 1.6 mboe, 8.3 mmboe and $3.3 billion market capitalization.


Despite ExxonMobil’s size, Reinsch said, it was “in a bit of a box” in 2009 after Qatar imposed a moratorium on new development of its gas resources.

“People find it difficult to imagine a company like this could ever be in trouble, be conflicted or in a position where it was unable to move forward, but that was the situation they were in 12 to 18 months ago,” he said.

The moratorium was ordered because the sheikdom was “struggling” to make use of its massive revenues, Reinsch noted, but Qatar accounted for more than 20 percent of ExxonMobil’s 2010 production; and while production from existing wells continues, a major growth engine had been shifted to neutral.

ExxonMobil also missed the opportunity to develop a new field off the coast of Brazil when the country’s national oil company, PetroBras, was awarded the project. In response the company made two big moves

One, which Reinsch said was “absolutely unique” in its history, was the decision to buy XTO Energy, a specialist in production of unconventional oil and gas, and then to allow the company to operate, in effect, as an independent subsidiary. The $41 billion purchase in 2009 and other properties made the United States the leader among the 41 countries where ExxonMobil has production or upstream operations.

Reinsch said that ExxonMobil has provided little guidance on its plans for XTO and the market is waiting to see if it will be able to retain its position as the most profitable energy producer after repositioning in unconventional resource production. He also noted that ExxonMobil has the ability to hold off of gas project development in North America because of current low prices.

ExxonMobil’s second “big move” was the commencement, in 2011, of a partnership with the Russian company Rosneft to gain access to Arctic resources.

“If you’re looking for where Alaska fits with ExxonMobil it would be this,” Reinsch said.


After the April 2010 Deepwater Horizon well blowout in the Gulf of Mexico, BP faced a financial calamity that less than a half a dozen corporations in the world could have survived, but appears to be emerging from the episode as stronger company, according to Reinsch.

The Macondo well explosion was followed other costly problems including the fatal refinery fire in Texas in 2005 and the 2006 North Slope spill.

“I think there have been enough, or a series of incidents, one after the other that have raised red flags to which BP is now responding,” Reinsch said.

BP sold $30 billion in assets but acquired another $28 billion as it “rationalized” its portfolio.

“From being outside,” the company’s boardroom, Reinsch would have expected BP’s Alaskan properties to be on the auction block, but he said he had no indication that divestiture of assets here was ever considered.

“While the company did not plan on the depth of portfolio rationalization undertaken to date, this is a rare opportunity to high-grade assets holdings with the blessing of shareholders and analysts alike,” Reinsch said.

He noted that the structure of the joint operating agreement among the three North Slope majors, “would be a blocking factor to divestiture,” for any of them.

Of the 26 countries where it has operations or investments, BP’s largest producer is Russia. It accounted for roughly 29 percent of BP’s 2011 output, up from 26 percent a year earlier, and a significant portion of its headaches.

In 2003, BP entered TNK-BP, an apparently exclusive joint venture with a group of Russian billionaires. The oligarchs threatened to sue when BP attempted to partner with Rosneft on the deal that ExxonMobil eventually got.

In April, Reinsch said the episode would likely restrict BP’s Arctic ambitions, but earlier this month, a report in British newspaper The Telegraph said Rosneft has invited TNK-BP to participate in its Arctic projects.


While its fortunes are more closely tied to Alaska, ConocoPhillips is also a company in “substantive transition,” according to Reinsch.

ConocoPhillips began a “shrinking to grow” strategy in 2010 with a target of $15 billion in divestitures. To date it has sold about $7 billion, including what had been a 20 percent equity interest in Lukoil. The shift reduced its Russian production from 21 percent of world output in 2009 to three percent in 2011.

ConocoPhillips also restructured with the creation of Phillips 66, a downstream, or refining entity, leaving it with a “pure play” exploration and development focus. Despite the reorganization ConocoPhillips has not yet emerged from its identify crisis, according to Reinsch.

The company may be too large to compete with smaller and more nimble wildcatters but too large to enjoy the same global efficiencies of other majors.

A ConocoPhillips trademark is its reliance on Organization for Economic Co-operation and Development for its production, about 72 percent in 2010. The OECD includes the 34 most industrialized countries in the world. They offer political stability but are also maturing, high-cost basins.

While it replaces its Russian assets, ConocoPhillips’ world production is expected to decline through 2015. North America is the company’s largest producer with Texas shale gas and Canadian tar sands leading the way.

“Alaska is an area that is, right now, core and material to the company and expected to be so in the future,” Reinsch said.

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Friday, May 11, 2012

Oil, gas from old assets; Independent Hilcorp reworking Cook Inlet wells, fields, formerly held by Chevron

Kristen Nelson
Petroleum News

Hilcorp Alaska is focused on finding and producing more oil and natural gas from legacy Cook Inlet assets. It acquired Chevron’s Cook Inlet assets last year and is in the process of acquiring Marathon Oil’s inlet assets.

Producing from old wells and fields is the company’s strength, John Barnes, Hilcorp’s senior vice president for Alaska, told the Regulatory Commission of Alaska May 9 and the Alaska Support Industry Alliance May 10; this story combines comments from both presentations. Barnes said there are lots of opportunities in Cook Inlet, and Hilcorp is a fast-moving independent with enough financial clout to do the work that needs to be done.

Among the challenges Hilcorp is working on, he said, are predictable permitting timelines — with predictability the real issue, not how long it takes.

“If it takes a year, you’d better have an inventory that lets you plan out a year ahead of time; if it’s a week, that’s great,” Barnes said.

He said the biggest obstacle he sees is caused by the decline of the service industry in the inlet.

Hilcorp “can’t move fast enough because we have to get the service industry moving with us.”

The problem is that the service industry needs to know its crews will be working day in and day out on “continuous drilling programs,” which will allow both the service industry and Hilcorp to be more efficient.

Urgency is one of Hilcorp’s core values, Barnes said, noting he’d recently told his managers that if their plates were full now, they’d better get platters, because things would get busier.

The same would apply to the service industry, he said.

Increasing production the goal

Houston-based Hilcorp Energy Co. is the “third largest privately held oil and gas producer in the United States,” giving it the financial strength to do the work that needs doing on the Chevron Cook Inlet assets it acquired last year and on the Marathon Cook Inlet assets it is in the process of acquiring, Barnes said.
The focus is not on new drilling: In all its operations Hilcorp drilled 60 new wells last year; but it did 1,500 workovers.

“That’s the hard work to get production going,” he said.

He told RCA commissioners clearly concerned about declining Cook Inlet natural gas production that Hilcorp’s production in the Lower 48 has gone up year after year.

“And it goes up because of hard work and capital being spent in existing legacy assets. That’s one opportunity that exists in the inlet; that’s one that we are choosing to pursue primarily.

“I can’t probably overemphasize the amount of work that’s actually required to try to take the risk and spend money and try to improve recovery from these fields,” Barnes told the commissioners.

Offshore drilling

Hilcorp has a “derricks’ down” project under way, with derricks being taken off three platforms in the Trading Bay unit and from the Granite Point platform.
Those derricks were old technology, he told the Alliance audience.

“One way or another we’re going to get a modern drilling rig here,” whether Hilcorp builds it or someone else builds it. It’s similar to the model Marathon used, he said, where you get a rig with modern technology and just knock out wells; Hilcorp will do the same thing with a workover unit, he said.

The company will also be drilling onshore.

Barnes told the Alliance it’s embarrassing, but the company is excited about just running a workover rig in the Swanson River field. “That’s how low the bar is,” he said.

Drift River

Barnes said Hilcorp has a C-plan, an oil discharge prevention and contingency plan renewal, out for public comment which references work at the Drift River Terminal. The company plans to raise the berms protecting the tanks this summer and install some new ones, with a goal of storing oil at Drift River again.
Storage of oil stopped at Drift River due to activity at the Mount Redoubt volcano, but the berms around the tanks did what they were supposed to do and protected the tanks, Barnes said.

Hilcorp is working closely with the Department of Environmental Conservation on the C-plan, he said.

“It’s very important to try to get that terminal open again so that you’re allowed to manage your tanker traffic more effectively in the inlet,” Barnes said. Right now oil has to be stored at production facilities where there is a finite amount of storage “and it can result in tankers being curtailed, production shut-in, when you run out of storage.”

It’s not the way Hilcorp wants to manage oil storage, he said.

In response to a question about an alternative for storage at Drift River, Barnes told the Alliance audience that there has been discussion about a subsea pipeline, but sizing it would be a problem.

Because Hilcorp intends to grow production, “I don’t know how to size it yet,” Barnes said.

It’s the Goldilocks’ problem, he said: You don’t want it too small and you don’t want it too large.

A subsea pipeline may be a consideration for the future, but Barnes said Hilcorp needs to “establish a track record of getting production up” so that it could better determine a pipe size for such a project.

Gas production down

Barnes showed the commission recent Cook Inlet natural gas production figures. From 2008 to 2011 production declined from more than 400 million cubic feet per day to just over 300 million last year, he said.
“That represents about a 23 percent decline and I think we’re all aware that most majors have significantly slowed their spend in the Cook Inlet and that is not surprising because of this decline.”

But others are coming into the inlet, he said, calling it “an opportunity for companies to come in and try to perform and make a business.”

Different companies play to different strengths, Barnes said, mentioning Apache’s large lease position and extensive exploration program.

“Hilcorp’s strength is we acquire old assets,” he said.

About half shut-in

The Marathon assets Hilcorp is acquiring include 157 wells, 75 producing and 74 shut-in.
“Hilcorp looks at those shut-in wells as assets,” Barnes said. “We’re very much about trying to stare into every well, every wellbore and look at every sand and maximize production from the assets that we’re acquiring.”

Marathon is exiting the Cook Inlet basin, and that was important for Hilcorp in the acquisition, Barnes said, because, “It’s a chance for us to consolidate interests in legacy fields, which we believe present tremendous opportunities for additional work and additional development.”

Barnes noted that McArthur River and Ninilchik represent about 50 percent of Marathon’s production, and those are both fields in which Hilcorp already has an interest. Consolidation of ownership in fields which are late in life allows for commercial alignment which may not exist with multiple owners, he said.

Barnes said Hilcorp’s long-range plan is “pretty simple: It’s all hard work.”

“You want to invest significant amounts of capital to exploit the assets that we will be acquiring and in in-fill drilling, recompletions and workovers and compression.”

As for what Hilcorp will be doing in Cook Inlet, Barnes said, “We are not a company that will be performing lots of big projects: We make our living through lots of small projects and ... working every wellbore, every sand and seeing what’s there.”

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Capital budget helps Fairbanks make headway on LNG

Jonathan Grass
Alaska Journal of Commerce

The two largest energy companies in Fairbanks are moving forward in their efforts to expand the borough’s liquefied natural gas customer base.

Golden Valley Electric Association and Flint Hills Resources have been working on a joint venture for LNG and the design phase for storage plants in North Pole and the North Slope are now under way with some state help from the capital budget passed April 15.

Golden Valley Electric Association was given $3.75 million for engineering and design for a liquefied natural gas storage facility on the North Slope. A separate appropriation gives the Fairbanks North Star Borough $3 million toward a natural gas distribution system.

Both appropriations must still be signed off by the governor, and neither are anywhere near what the projects will cost. However, GVEA President and CEO Brian Newton said this draws them closer to getting the two plants operational. He said Senate Bill 23, which has passed but must also be signed, would get the company around $30 million in grant money to offset the storage costs.

The plan is for two storage units: one in North Pole and another in Prudhoe Bay. The Prudhoe Bay facility would require the gas to be trucked across the Dalton Highway to Fairbanks.

Newton said the two plants would constitute 9 billion cubic feet annually with each company taking around 3.5 bcf and an additional bcf to be made available for sale.

To explore the justification for a new LNG distribution system, the borough commissioned the Fairbanks Economic Development Corp. to manage a distribution study. While the final report is due this month, the preliminary summary states that the residential, commercial and industrial sectors consisting of 26,35 units that would have an estimated combined demand of 20.9 bcf per year. Almost 25,000 of this estimate are residential units needing 5.7 bcf.

The preliminary report states pipeline costs could be anywhere between $309 million and $662 million.

The personal cost to consumers can vary just as much, according to the report. It states that residential homes can spend as little as $1,000 to replace a burner gun to $20,000 to replace a boiler with a natural gas system.

FEDC President and CEO Jim Dodson said two things are paramount for LNG distribution: to lower Fairbanks’ cost of energy and finding a cleaner energy source while being proactive in cleaning the air quality to keep up with federal standards.

“If those are the two overarching issue, then you have to address the issue of distribution beyond the 1,100 customers so that’s what we’re studying,” Dodson said.

GVEA and Flint Hills both currently use oil for energy at extreme costs. Dodson described energy costs as an “economic disaster of this community”

Although an exact figure isn’t yet known, Newton said the project could mean an estimated for $25 million to $30 million per year in savings for the company, which would be passed on to the consumers.

Current natural gas prices are $23.35 per million cubic feet.

Fairbanks’ winter conditions force use of oil-burning stoves that exacerbate air quality problems, which more LNG stoves could remedy. The report states that other developments can encounter permitting difficulties in the area if they will exceed air quality standards.

“What we simply need to do is convert burning diesel heating oil to burning natural gas and that would dramatically lower the emissions, the (air quality) problem that we have,” Dodson said.

The exact costs of the project aren’t yet known either, but Newton estimates it could be between $200 million to $250 million project, which would be split between GVEA and Flint Hills. He said the engineering portion should be completed close to the end of the year, at which point the Board will consider it.

“If it were to move forward, it would have first gas to Fairbanks in the first part of 2015,” he said.

Dodson feels the plan may need more work and that the estimated amount may not allow system growth within the community.

The current distribution system reaches about 1,100 customers in the area, which Dodson said consume about 1 bcf. Of those customers, about 600 of those are commercial buildings with the rest being residential. These customers currently get their LNG from the smaller outfit, Fairbanks Natural Gas LLC. President and CEO Dan Britton said the company has been working on a separate project to explore expanding the customer base. He said they have been limited by the Cook Inlet supply in the last number of years and so are also exploring LNG opportunities on the North Slope.

Britton said many consumers want LNG and so solving this supply problem could fill a larger customer base rather quickly. He said this has been in development for four years and that permits are in place but establishing this larger customer base is necessary to justify project costs.

FNG had originally explored possibilities with GVEA and Flint Hills but they ultimately went into separate projects.

Britton said residential customers save an average of 23 percent on their heating bills with LNG.

Dodson said the current distribution system only reaches about 5 percent of the 28,000 buildings in the borough community.

Newton said a possible option for the estimated additional gas could be used by FNG to double its customer base. Britton said there is no deal in the works as of now.

“The overarching mission is to supply affordable energy to as much of the borough buildings as possible in the shortest time possible and also deal with the air quality issue,” Dodson said.

Jonathan Grass can be reached at

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With ‘skin in game,’ Homer hopes for Parnell approval on gasline

Michael Armstrong

After a weekend of teeth grinding by city of Homer officials when the Alaska Senate failed to include in its capital budget sent to the House an $8.1 million grant to build a natural gas pipeline from Anchor Point to Homer, locals breathed a sigh of relief when the House of Representatives added the grant and both houses approved the revised capital projects budget.

“I’m really pleased,” Rep. Paul Seaton, R-Homer, said Monday. “It’s really tough to get an $8 million project on the House side when it’s not in the budget coming over.”

Of the city’s top-15 items on its capital improvement project list, only two other items survived. One, a $1.1 million grant to fix the Homer High School track, also was a Kenai Peninsula Borough priority. The Legislature also approved a $100,000 grant to dredge the Nick Dudiak Fishing Lagoon, a popular local and tourist fishing spot on the Homer Spit.

Not making the cut were sewer treatment plant and harbor improvements.

“It’s good news over all,” said Homer City Manager Walt Wrede. “We’re disappointed in some ways. There’s always something we wish were in there, but I think the gas pipeline is a big deal.”

One obstacle remains in getting funding for a long-awaited natural gas service line to Homer: getting Gov. Sean Parnell to sign off on it — or, not veto it. In the first year the grant was passed by the Legislature, Parnell cut all but $450,000, which built a pressure reduction section and a line from the North Fork Road to Chapman Elementary School on the Sterling Highway in Anchor Point. Last year, Parnell vetoed the whole grant.

Officials sought a grant that would avoid another veto. Parnell said he wanted to see some “skin in the game” with local contributions. Part of the project, to be built by Enstar, will be financed with a $1 per million cubic foot tariff on Homer gas customers. Anchor Point does not pay the tariff. The city of Homer also passed resolutions supporting the tariff, as well as changes to creating special assessment districts and using rights-of-way for a gas line, all actions showing a local commitment.

“I’m hopeful,” Wrede said of Parnell approving the grant. “I think there’s a good chance. (Parnell is) sending out positive signals. I’m optimistic the third time is going to be the charm.”

Local officials also made a calculated decision not to ask for any other big-money projects. In making his veto last year, Parnell noted Homer got grants for a new solid waste transfer facility and cruise ship passenger facility improvements.

The lower peninsula did well in projects outside the city, including $2.5 million for Sterling Highway road rehabilitation, $1.2 million for borough road improvements, $1 million for Seldovia harbor improvements, $100,000 for a Kachemak Emergency Services fire truck storage building on Diamond Ridge Road, $2 million for a Ninilchik fire station and $244,000 for improvements to the Anchor Point Senior Center parking lot.

The city had hoped that Homer Harbor Deep Water-Cruise Ship dock improvements would have been included in a proposed bond for port projects around the state. That didn’t happen.

Harbor improvements could have been funded by a harbor improvement fund if the city had put together proposals that had a 50-percent funding match. Wrede said the city wasn’t prepared to make that application because it would have had to identify the 50-percent match from the harbor depreciation fund — something the city didn’t feel comfortable doing, he said.

The city is preparing a proposal to fund harbor improvements, and apply for the 50-percent funding match for next year, that would come out of a bond resolutions and increased harbor fees. The city has to make sure a bond sale would go through and mariners will support fee increases.

As for the gas line, the next step for the city council is to seriously discuss if it wants to finance a build-out — if Parnell doesn’t veto the grant — and how the council wants to go about doing that.

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Saturday, May 5, 2012

Alaska oil boomerangs; Due to refinery crunch, tankers return to Valdez with some crude still aboard

Wesley Loy
For Petroleum News

Normally Alaska North Slope crude oil flows one way — south, toward refineries on the West Coast.

In recent weeks, however, something odd has happened. Tankers have returned to the terminal at Valdez still partially laden with Alaska oil. Usually, the tankers come back empty.

So what’s behind this curious trend?

It appears to be a mix of oil inventory management decisions, cost considerations and reduced capacity at some West Coast refineries.

“It’s an unusual situation,” Steve Rinehart, spokesman for BP Alaska, told Petroleum News.

Five back-haul events

A number of tankers carrying oil for BP, which operates Prudhoe Bay and other North Slope fields, have returned to the Valdez Marine Terminal with some oil still aboard.

No other company’s oil tankers are known to have made similar returns.

Anil Mathur, the president of Alaska Tanker Co., the Beaverton, Ore., company that carries BP’s oil, declined to specify how much oil his ships have back-hauled. His company operates four double-hull tankers to carry BP oil between Valdez and West Coast ports.

A nonprofit organization that monitors the Valdez terminal and tanker operations has been keeping track of the back-hauling. The Prince William Sound Regional Citizens’ Advisory Council says that since late February, five ATC ships have returned to Valdez still partially filled after having not delivered their full cargoes to Lower 48 refineries.

Here are the five back-haul events, including the arrival date, ship name and volume of oil aboard:

• Feb. 27, Alaskan Explorer, 81,000 bbl

• March 20, Alaskan Frontier, 175,000 bbl

• April 11, Alaskan Explorer, 300,000 bbl

• April 28, Alaskan Frontier, 200,000 bbl

• May 2, Alaskan Explorer, 140,000 bbl

In-bound ships with oil aboard receive the same tug escort as fully loaded ships sailing out of Port Valdez into Prince William Sound.

Factors behind oil returns
Each ATC tanker has a capacity of 1.3 million barrels.

The tankers don’t offload oil at Valdez, ATC’s Mathur said. Rather, the tankers are topped off with more oil and then sent south again.

As to why ATC ships are returning with some cargo still board, Mathur said BP simply tells his company “what oil they want us to carry where.”

The back-hauling of oil to Alaska “has happened before,” he said, “but it’s not common.”

Although it seems odd, back-hauling actually makes sense under certain circumstances.

“The incremental cost of doing so is not that much,” Mathur said. The tankers are going to return to Alaska regardless of whether they’re empty or carrying some crude, he said, and the oil can act as ballast for the ships.

Leaving some oil aboard ship is not ideal, but it can give the owner “more flexibility” in placing it, Mathur said.

“Ultimately, all the oil gets placed in the Lower 48,” he said.

The major problem appears to be a capacity crunch at refineries that take a lot of North Slope crude.

BP’s Cherry Point refinery at Ferndale, Wash., remains down due to a Feb. 17 fire and a major spring maintenance turnaround.

Another big delivery point for North Slope oil is BP’s Carson refinery near Los Angeles. It also has undergone maintenance recently.

Complicating matters was some extensive maintenance at the ConocoPhillips refinery at Ferndale.

All these refinery constraints are important considerations as BP, ConocoPhillips and others continue to produce oil daily from the North Slope. That oil must go somewhere, so storage must be assured from the Slope to the Valdez terminal to the tanker fleet and ultimately at the refineries.

The refinery issues are expected to clear up soon. Spokesmen for BP Cherry Point failed to return phone calls seeking a status update. But a local newspaper report quoted one spokesman as saying the refinery is expected to resume normal operations in early May.

No Slope proration

In effect, keeping some oil aboard tankers is “storage in motion,” BP’s Rinehart said.

Managers have decided it’s the best and safest option in some cases, he said.

“This is basically managing inventory,” Rinehart said. “We expect it to be short-term.”

Joyce Lofgren, a petroleum economist with the Alaska Department of Revenue, sees a reasonable explanation for BP back-hauling oil.

“The economics of storing the crude in the tanker for a trip back to Alaska must have been better than the price required to offload,” she said.

Lofgren also believes the “larger market situation” is at work, with high oil prices driving soft domestic demand and oversupply.

“Less consumption and more supply sends crude to storage, inventories build and refineries adjust their operations,” she said.

At the Valdez Marine Terminal, the crude working inventory since March has ranged from 41 percent to 90 percent of storage capacity, said Michelle Egan, spokeswoman for Alyeska Pipeline Service Co., which runs the terminal.

The good news for industry is that no proration, or curtailment, of oil production on the North Slope has been necessary this year, she said.

Friday, May 4, 2012

Senate bails, followed by House; oil tax, in-state line left hanging

—Kristen Nelson
Petroleum News

There were a variety of reactions in Juneau following Gov. Sean Parnell’s April 25 withdrawal of oil taxes from the call for the special session of the Alaska Legislature which began April 18.

The adjournment of the Alaska Senate April 26 generated debate as well.

The Senate Bipartisan Working Group — 10 Democrats and six Republicans — challenged Parnell’s right to withdraw an item from the special session call and said the administration had not adequately defended the governor’s oil tax proposal.

On April 26 the Senate voted 14-2 to adjourn sine die, after voting 14-2 to adopt a “sense of the Senate” that by withdrawing one of the items on the special session call, the governor had, in effect, ended the special session.

The Senate’s small Republican minority, in debate and votes on the floor, opposed the Senate’s interpretation of the governor’s ability or inability to remove items from the call, and that body’s subsequent adjournment.

House Bill 9 remained on the call for the special session.

The House majority — Republicans and Bush Democrats — said the Senate had refused to work on the proposal in HB 9 to move an in-state gas pipeline project ahead.

The House Democratic minority opposed both the oil tax change and HB 9.

The House struggled to continue after the Senate left, but without the oil tax the only issue remaining was HB 9 which had been in the Senate since before the end of the regular session in mid-April. After efforts to redraft HB 9, the House followed the Senate out of Juneau April 30, adjourning sine die.

In a statement following House adjournment the governor said he supported the House decision to gavel out “after the Senate Majority failed to address the state’s energy needs.”

“By failing to consider HB 9, the Senate Majority has delayed shipping gas from the North Slope to Fairbanks and the Railbelt for at least one to two years,” Parnell said.

House Democrats
House Minority Leader Beth Kerttula, D-Juneau, said April 26 that she believed the governor “needed to fish or cut bait on the oil tax and it was kind of a shock last night when we all saw him cut bait.”

She called it “a good day for Alaskans. There was no reason to have a $2 billion a year giveaway that gives away roads, schools, our ability to see good strong jobs for Alaskans.”

Minority Whip Berta Gardner of Anchorage said “the administration simply failed to make the case” for its oil tax changes. She said administration officials “were unprepared to answer obvious questions; they answered inaccurately; they said they’d get back to us and failed to do that; and lastly they told us to ask the oil industry.”

Rep. Pete Petersen of Anchorage said he was surprised by the governor’s withdrawal of oil taxes, but said “we have been making the case the entire session — we didn’t feel that there was a need to lower oil taxes, especially on the legacy fields.”

On HB 9, Rep. Scott Kawasaki of Fairbanks said energy relief is a concern for Fairbanks, but that area also wants to make sure it’s at an affordable price, “and House Bill 9 as it crossed over to the Senate was a plan that missed Fairbanks by 40 miles, would have added an extra billion-dollar straddle plant so that Fairbanks, once again, is helping to pay for a line that’s not economic” with gas from the line more expensive in Fairbanks than it would have been in Anchorage.

Petersen said that with the tax credits the Legislature passed for Cook Inlet exploration and additional rigs posed for drilling there this year, “I believe we need to give the explorers a chance to use those credits and find more natural gas in Cook Inlet.”

The Senate’s view
Members of the Senate Bipartisan Working Group met with the press after the Senate adjourned April 26.

Senate President Gary Stevens, R-Kodiak, said that since the governor had removed oil tax legislation from the special session call, “I see little option for the Senate other than to bring this session to an end.”

He said the Senate was holding hearings on the governor’s oil tax bill, but was “disappointed in the administration’s poor performance throughout this special session. They could not adequately defend the governor’s plan.”

On HB 9, in the Community and Regional Affairs Committee, Stevens said the chair of that committee, Sen. Donny Olson, D-Golovin, said there weren’t the votes in the committee to move the bill. Stevens said he didn’t think there were the votes in other committees or in the majority caucus to pass the bill out of the Senate.

Stevens said the Senate Bipartisan Working Group did not “set out to oppose the governor at every turn — that’s not the case at all. It is that we honestly and respectfully disagree.”

He said the administration had not proved its case for an oil tax change.

“We are fairly being blamed for asking tough questions — but that’s our job,” Stevens said. “And it’s the administration’s job to answer those tough questions.”

There are billions and billions of dollars at stake, he said, “We just have to be convinced with expert testimony, with adequate defense of the governor’s bill, with answers to basic questions, with study and analysis.”

The governor’s tax bill was in Senate Resources during the special session, and the co-chair of that committee, Sen. Joe Paskvan, D-Fairbanks, said he’d requested that the committee hear “from Gaffney Cline, the governor’s advisor.” He said Gaffney Cline “is well respected and we were hoping to engage in the policy discussion with the advisors to the governor.”

Since the Senate asserted that the governor did not have the ability to withdraw a subject from the call, they could have continued on, but since the governor had withdrawn oil taxes from the call, “it’s unlikely that we’re going to receive access to the governor’s advisors” for a policy discussion, Paskvan said.

House majority view
Following the Senate’s adjournment on April 26, the House majority held a press conference — it held another one April 30, after the House adjourned sine die.

On April 26, House Speaker Mike Chenault, R-Nikiski, said he was disappointed that the Senate “refused to take up House Bill 9 in any credible manner.”

By leaving without addressing HB 9, the Senate “has delayed in-state gas by in my estimation of minimum of a year and probably longer,” he said.

HB 9 was a complicated bill which included giving the Alaska Gasline Development Corp. access to pre-approved funding to get through an open season and exemption from Alaska’s public information requirements in business dealings.

Chenault said there was a committee substitute proposed to the Community and Regional Affairs chair that would have allowed AGDC “to build a line from Cook Inlet to Fairbanks” and said the Senate, “by their inaction ... effectively killed any opportunities for Fairbanks to have a gas pipeline anytime in the near future.”

Rep. Mike Hawker, R-Anchorage, co-sponsor of HB 9, said opponents of the bill have played “awfully loose” with the facts.

He said statements that Cook Inlet is “awash in gas” are difficult to support with Southcentral utilities “developing plans to build LNG import plants” just to meet baseload natural gas needs in the area.

As for U.S. Geological Survey projections that there may be as much as 19 trillion cubic feet of natural gas in Cook Inlet, he noted USGS recently cut its estimation of oil in the National Petroleum Reserve-Alaska “by over 90 percent.”

He said he and Chenault “don’t want to bet our communities” on the possibility of 19 tcf of natural gas.

Chenault said some have claimed that bringing North Slope natural gas to Cook Inlet would kill Cook Inlet exploration. He said he has letters from Cook Inlet explorers saying they don’t think a line to Cook Inlet would hurt exploration, and in fact, that a line with some sort of export facility would give them an opportunity to sell gas that they find.

Hawker noted that HB 9 had “a number of critical elements that would be universally applied to all gas pipeline development in the state.” The regulatory structure in the bill would apply to a standalone pipeline under the auspices of AGDC or a larger line under the Alaska Gasline Inducement Act, AGIA, he said.

Hawker said the Senate refused to consider the work the House did on House Bill 110 in 2011.

So the Legislative Budget and Audit Committee engaged consultants to support work in the Senate.

“Over the course of the past three months, our friends in the Senate have spent nearly $650,000 with those consultants to develop a new method of calculating progressivity,” he said, a method based on the gross value of oil.

But the tax on new oil only that the Senate sent the House on the last day of the regular session, “reverted back to net progressivity,” Hawker said.

That mechanism was never stress tested by consultants engaged to support the Senate, he said.

Hawker said he did some rudimentary stress testing and found that for frontier basins at oil prices of about $100 a barrel, “those basins had no taxes for a long time.”

“Now to me, that’s a real giveaway,” he said. “We’re basically giving away more upfront tax credits but still not getting any long-term production in this state.”

Wednesday, May 2, 2012

State agencies approve shift to large-diameter LNG line

Alaska Journal of Commerce

The State of Alaska has approved a project plan amendment to allow TransCanada to shift its focus from a gasline to Alberta to a large-diameter line from the North Slope to Alaska tidewater.

State approval by Department of Revenue Commissioner Bryan Butcher and Department of Natural Resources Commissioner Dan Sullivan was necessary under the Alaska Gasline Inducement Act, or AGIA, because TransCanada was required under the law to file a certificate application with the Federal Energy Regulatory Commission this October.

Under the project plan amendment approved Wednesday, that date has been deferred to October 2014 and according to a statement from DNR, “In early 2013, the state expects TransCanada to provide an updated, more comprehensive PPA (project plan amendment) request that will reflect the details of the LNG project and its associated timeline.”

That PPA will also require approval by Butcher and Sullivan.

“A key benefit of the PPA is that it enables all parties – the North Slope producers, the State and the AGIA Licensee – to come together for the first time to work on commercializing North Slope gas,” said Kurt Gibson, director of the Alaska Gas Pipeline Project Office, which oversees work by TransCanada Alaska on the Alaska Pipeline Project.

TransCanada, ExxonMobil, ConocoPhillips, and BP announced March 30 that they will work together on commercializing North Slope gas, focusing on large-scale liquefied natural gas exports from Southcentral Alaska.

The glut of natural gas in the Lower 48 made the Alberta pipeline uneconomic, and surging Asian export markets such as Japan and China make a large-diameter line to Alaska tidewater the most viable project.

The DNR, in its release, noted a report released Wednesday by the Brookings Institution that found Alaska was in a strong competitive position for a global LNG project.

TransCanada, had $500 million worth of its expenses covered under AGIA, and according to DNR “approximately half” of the work it has already done on the route to Alberta would be applicable to a large-diameter LNG line.

The DNR release stated that, “some of the Alberta work will continue under the current PPA, either as dual use for an LNG project or to preserve work on the Alberta option for potential transfer to the State under terms of the license. This PPA will prevent unnecessary spending on the Alberta option while the LNG project is being developed.”

Under the Point Thomson litigation settlement also announced March 30, the Slope producers can earn additional acreage at Point Thomson if they sanction an LNG project between now and 2016. If the producers don’t agree on a gasline concept before then, they will be required to increase liquids production at Point Thomson.

“The agreement does not guarantee a major gasline, but moves us a significant step forward,” Sullivan said at the time.

Gov. Sean Parnell said March 30 that part of his commitment to the CEOs in exchange for their alignment on commercializing Slope gas through an LNG export project was to address natural gas taxes in the 2013 legislative session.

The March 30 letter from the Slope producer CEOs stated, “Unprecedented commitments of capital for gas development will require competitive and stable fiscal terms with the State of Alaska first be established.”

This article appears in the April Issue 5 2012 issue of Alaska Journal of Commerce

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