It's About Energy

LNG market grows, uncertainties persist

2011-11-20T18:15:00.000-08:00

Discussion at London liquefied natural gas conference driven by US shale gas production, Japanese tsunami’s affect on nuclear power

By Bill White

Researcher/writer for the Office of the Federal Coordinator
Driving much of the discussion at a liquefied natural gas conference in London were two relatively recent events that have rattled how the global LNG industry views its short-term future.
The events help explain the unusual LNG pricing trends of late, underscore some of the volatile dynamics of supply and demand, and amplify the uncertainty forecasters have of their own predictions.

The first event was the rise of U.S. shale-gas production over the past five years, sweeping aside the world’s biggest gas market — North America — as an LNG customer. Companies mistakenly targeted billions of dollars for construction of new gas liquefaction capacity and U.S. import terminals. The lack of U.S. customers cast adrift that new LNG production, which needed to find a new destination and did so in Europe, helping soften short-term and spot LNG prices there. The continued rise of Lower 48 shale-gas production also has engrossed the LNG industry in a guessing game: Will the United States export some of its new-found gas bounty as LNG?
Event two: A tsunami stifling nuclear power production at Japan’s Fukushima plant last March. This boosted short-term LNG demand in Japan, raising prices there and diverting to Asia spot shipments that had been aimed at Europe.

Two currents at congress

Shale gas and Japan were two currents flowing through presentations at the LNG Global Congress held in London during the last week of September. I was invited to present on Alaska natural gas and to learn the latest developments in an industry undergoing rapid change.
A key message from the conference is that the spectacular expansion of LNG supply and demand worldwide should continue over the next decade, although LNG traders, analysts and consultants offered no consensus on the exact timing and details of that growth.

The LNG conference covered a breadth of other topics, from the rise of Qatar and Australia as gas liquefiers, to China’s energy appetite, the prospect of U.S. LNG exports, whether North America’s shale-gas revolution will be replicated elsewhere, and how a wider Panama Canal and a new technology called floating LNG might be game changers for the industry.

Optimism about LNG

Conference attendees gushed optimism about the LNG industry, while mumbling uncertainty about how exactly the future will unfold.
Alaska helped pioneer the world of LNG exports when the Nikiski liquefaction plant opened in 1969 to supply Japanese utilities with natural gas from the new Cook Inlet discoveries. Alaska since has been eclipsed as an exporter by Indonesia, Malaysia, Egypt, Trinidad & Tobago and, more recently, by such countries as Qatar, Yemen, Russia and Norway.
People attending the conference were generally aware that Alaska is about to exit the game, with the last LNG shipment expected to leave the Nikiski plant this fall.

Why Alaska would drop out just as Japanese demand is spiking did puzzle them, however. They didn’t understand that the historic Cook Inlet fields are petering out. I explained that some Alaskans hope the state can re-enter the fray within a decade by exporting North Slope gas from a resuscitated Nikiski plant or a new mega-plant at Valdez, if a proposed pipeline from the Slope gets built.
Here’s a snapshot of themes discussed at the conference.
Supply and demand

The LNG market has been defined for decades by long-term contracts between LNG makers and buyers of the gas. LNG makers needed these 20-year-plus deals to underwrite the huge upfront cost of building plants to liquefy gas — superchilling it to minus 260 degrees Fahrenheit transforms methane into a liquid that is more compact and economical to transport via special tankers.

But thanks to their rapid expansion in recent years, the world’s LNG exporters now have far more capacity to liquefy natural gas than is needed to fulfill current demand. This imbalance has given rise to short-term contracts and spot sales, which last year comprised about 20 percent of the LNG volume traded. That’s roughly akin to the percentage of oil under short-term and spot deals, said Kasper Walet, principal with Amsterdam-based energy consultant Maycroft. But he noted that these spot and short-term deals, while 20 percent of the LNG trade, comprised just 2 percent of all natural gas movement. Most speakers said they expect long-term deals to continue to characterize the industry.

Japan needed 110 billion cubic feet of additional LNG this year after Fukushima, and it got about 48 billion of it on the spot market, buying from Algeria, Egypt, Yemen and Nigeria, said Frederic Deybach, an LNG executive with European energy conglomerate GDF Suez.
The imbalance will end soon, as demand catches up with the capacity to supply LNG. When? The presenters’ estimates ranged from 2012 to 2015.
Key unknowns

Here are key unknowns that make this future so hard to predict:
Will low coal prices tilt China and other emerging Asian economies away from natural gas for future fuel supplies?
Will Japan and Germany phase out nuclear power and need more natural gas (as well as coal and oil) to make electricity, and if so, how quickly will the phase-outs occur? Will the world economy double-dip into another recession, or even triple-dip?
Will geopolitical events disrupt LNG supply, as they did this year in Libya, a gas exporter, and could do in unstable Yemen, another LNG exporter?
After 2015, start-up of new liquefaction plants — particularly in Australia but also in Papua New Guinea, possibly Canada and other locations — probably will ease any worries about LNG supply shortages for several years.
But timing is everything. If capacity comes on slow and demand rises fast, expect to see LNG prices rise, several speakers said. Prices could fall if liquefaction capacity gets built faster than demand rises.

Andre Mernier of Belgium sees a bright future in Asia for LNG because of its geology and geography. Geology — not enough of its own gas reserves and generally too distant for gas deliveries through pipelines. Geography — lots of need for electrical generation fuels in coastal population centers, where deliveries can be made easily. Mernier is secretary general of the Energy Charter Secretariat, a group with 53 member countries that upholds international laws to ensure the smooth flow of energy between exporters and importers.
Deybach of GDF Suez, said much of the expected new demand for LNG imports to 2020 will come from nations “where demand uncertainty is greatest.” These importers include developing nations in Asia, the Middle East and Latin America.
Ship charter rates soar

The LNG fleet has expanded rapidly in recent years, from 195 ships at the end of 2005to 360 ships at the end of last year, according to the International Gas Union.
That expansion hasn’t been fast enough, said Walet of consultancy Maycroft. Most tankers are sailing under entrenched contracts. The few available for short-term hire are demanding premium rates.
The rate for chartering an LNG tanker last year averaged $41,000 a day. That price jumped to $80,000 in the first half of this year, particularly after Japan’s Fukushima disaster boosted that nation’s short-term need for gas, Walet said. Claire Wright, principal gas analyst with Lloyd’s List Intelligence, said some spot-shipment rates have reached $100,000 a day.
Chris Meyer, a European LNG consultant with Poten & Partners, said shipyards are busy building tankers, and that day rates will fall within 18 to 24 months, after the new boats get launched. About 60 new ships have been ordered, Wright said.

Hot commodity

Worldwide demand for natural gas last year rebounded from the drop in demand caused by the 2008-2009 global recession. Overall demand leaped 7.4 percent, with LNG demand up 21 percent, said Hideomi Ito, natural gas analyst for the International Energy Agency. (LNG tends to be a niche product desired by places like Japan, South Korea and Taiwan that lack the option of pipeline deliveries. As was mentioned, less than 10 percent of the world’s gas consumption involved LNG last year.)
Growth in gas demand should slow over the next five years to perhaps 2.4 percent a year, Ito said, with LNG demand growing faster than that because it would help fuel hotter economies such as China and India.
Christof Ruehl, chief economist for BP, said European demand for LNG might even fall next year although he expects it to grow over time.

China’s big appetite

Natural gas comprises 4 percent of China’s energy needs now, Ruehl said. Coal provides 70 percent. China consumes less than one-tenth the amount of gas that Europe uses.
But China is just getting going as a natural gas consumer, Ruehl said. By 2030, China will consume far more energy than today, and natural gas will supply 9 percent of it. Within 20 years, China will consume as much natural gas as all of Europe consumes now, he predicted.

China will get about half of its gas in 2030 from domestic production, particularly tapping shale and other unconventional reservoirs, and it will import the other half via pipelines and LNG tankers, Ruehl said.
Ito noted that China has been investing furiously to secure new supplies. These investments include developing conventional, shale and coal-bed methane resources within China; securing long-term LNG-supply contracts with Australia, Qatar and Papua New Guinea; opening of an almost 4 billion cubic feet a day pipeline from Turkmenistan in late 2009 (expected to reach full capacity next year); and building a 1.1 bcf a day pipeline from Myanmar that should start in 2013.
Ito said China’s total gas demand could rise from about 10 bcf a day on average last year to 25 bcf a day in 2015, with LNG sating some of that growth.

Australia — boom towns, boom nation

Australia is the Wild West of LNG — a brawny frontier toward which the industry’s future is migrating.
Alan Copeland of the Australia Bureau of Resources and Energy Economics said his nation exported about 19 million metric tons (2.5 bcf a day on average) of LNG last year from two plants. That’s about the same LNG volume Alaska would export from Valdez if that idea ever catches on.

But that volume is dwarfed by what’s planned for Australia: Seven projects totaling 57.1 million metric tons (7.5 bcf a day) at some stage of development (a combined price tag of $144 billion), plus another six totaling 44.4 million metric tons (5.8 bcf a day) proposed but not under way.
The seven projects are supposed to be done by 2016. Can Australia really pull that off? Copeland called it “a huge challenge, an enormous task,” but noted the companies involved are sticking to their start dates. Others at the conference said start-up delays are all but certain.
Still, nearly everyone expects Australia will become the world’s No. 1 LNG exporter by 2020. Last year it was No. 4, behind Qatar, Indonesia and Malaysia. Qatar exported 56 million metric tons of LNG, the equivalent of 7.4 bcf a day on average.

Australia is developing gas fields relatively close to its East Coast population center. These include coal-bed methane fields that some local farmers oppose, Copeland said. But the giant plays are in remote areas, including in deep water far off the nation’s northwest coast. Australia, through a Shell project called Prelude, is pioneering the emerging technology called “floating LNG,” where liquefaction occurs at sea rather than piping the offshore gas to an onshore LNG plant.
The rapid build-out of Australian LNG is straining the country. An LNG development called Wheatstone plans to bring 3,500 workers to a town of 800 people — raising issues of where to house them, how to feed them and what they will do for fun. Some projects have adopted a work schedule familiar to those who labor at Alaska’s North Slope oil fields: one or two weeks of 12-hour days followed by extended time off.
With coal and iron ore developments occurring as well in Australia, engineers and equipment are in short supply, Copeland said. A big winner is the average laborer, who is pulling in wages of $225,000 to $300,000 a year on remote LNG projects, Copeland said. The audience gasped when Copeland mentioned this.

U.S. LNG exports

Several speakers said U.S. exports of LNG are inevitable. The United States will have the supply, due to fast expanding shale-gas production. And if the big gap between gas prices in North America and those in Asia linger, liquefying U.S. gas production could be very profitable.
Deybach of GDG Suez noted that a race is afoot within the Lower 48 by companies positioning themselves to make and export LNG. One or two of them will win. Possibly three.
Simon Bonini, a consultant and former LNG director for Centrica, a British utility, said that of course the United States will export LNG. “I’m a firm believer that if you can have a stampede into Queensland (one of Australia’s gas hotbeds), you can have anything.”

Leslie Palti-Guzman, a New York-based analyst with political-risk consultant Eurasia Group, said at least six serious LNG export proposals are in play in the United States and Canada. If they all came together they could export 70 million metric tons of LNG, or 9 bcf a day. That’s twice the volume TransCanada and ExxonMobil hope to flow into the Lower 48 from Alaska’s North Slope. Asian utilities or governments are involved directly or indirectly in the push for North American LNG, Palti-Guzman said.
“In practice only half of that amount at best will be expected to be exported but that is still a significant volume,” she said.
U.S. projects that are finished by 2016 could “hit a window of opportunity” if Australian projects fall behind schedule and LNG demand grows as some expect, Palti-Guzman said.
She noted the opposition to exports from the U.S. petrochemical industry, which uses natural gas as a feedstock and wants a supply glut to hold down prices. But, she added, “U.S. LNG export is definitely going to happen.” The exports would reduce the nation’s trade deficit, providing political reason to allow gas to leave the country, she said.

The current price gap between North American gas and Asian LNG is about $12 per million Btu. U.S. gas can be liquefied and shipped from the Gulf Coast to Asia for about half that price, Palti-Guzman said. The economics are even better for LNG from British Columbia — as long as the price gap holds, a risky assumption, she said.
Lower 48 natural gas prices could rise by $2 to $2.50 per mmBtu if the nation starts exporting significant volume, she predicted.
Some analysts believe U.S. LNG exports, and the resulting price rise, would heighten the Lower 48’s need for North Slope gas from Alaska.

Panama Canal

Palti-Guzman said expansion of the Panama Canal will help U.S. LNG exports to Asia.
LNG tankers traversing the Panama Canal can sail from the U.S. Gulf Coast to Asia in 22 days, shorter than a trip around South America or Africa, she said. Proposed LNG projects in British Columbia would hold a travel advantage, however: an eight-and-a-half-day trip to East Asia, she said.
Right now, only 6 percent of the LNG fleet of under 400 ships can squeeze through the canal, and none of them try, said energy consultant Walet.

But when the Panama Canal expansion is done, scheduled for 2014, 80 percent of the fleet will fit through the canal.
“It should be a real game changer,” Walet said.
The canal will transform how LNG flows around the world. In particular, diverting a cargo load in the Atlantic over to Asia will become more cost effective.
Shale gas globally?

Can the U.S. shale-gas revolution be duplicated elsewhere in the world?
Not easily, several speakers noted.
The United States is the perfect setting for shale gas. The country has lots of independent producers and service companies. A skilled labor force exists. Regulators generally understand gas production. Technology such as hydraulic fracturing and horizontal drilling are easily disseminated and improved on. The pipeline network to move production to market is vast.

China is estimated to have even greater shale-gas resources than the United States, but it falls short of the U.S. on know-how, competitiveness and market structures, said Madjid Kubler, owner of energy analyst Team Consult. Germany falls far short of China, he said, particularly on competitiveness and the regulatory/social environment for accepting unconventional gas development.
Will floating LNG sink or swim?
A new idea that many are watching to see how fast and how well it catches on is called floating LNG.

Shell is the first mover with this technology, approving a FLNG vessel to be built in South Korea and deployed to the company’s $10 billion Prelude development far offshore Northwest Australia. Shell estimates the field will start up in 2016, with 3.6 million metric tons of annual output (processing about 500 million cubic feet a day of natural gas).
A company called Flex LNG is involved in a smaller proposal off Papua New Guinea — an onshore field with offshore liquefaction, unlike Prelude where the entire operation will be offshore. Other projects are envisioned, including a couple more off Australia’s coast.
The attractions: FLNG fields could be developed more quickly for less cost, with no long-distance pipelines, fewer environmental challenges and less bureaucratic red tape ... if the concept proves itself.

The actual cost of building and operating FLNG units is unproven. This is causing some in the financial industry to wait and see, some speakers said.
But Wouter Pastoor, business development vice president with Flex LNG, said the technology is custom-made for small and medium-scale LNG production — 2 million metric tons a year (260 million cubic feet a day) in production or less, a bit more than the peak output from the ConocoPhillips/Marathon plant at Nikiski that is closing. This will let smaller countries and smaller fields get into the LNG business, and smaller volumes are easier to market, he said.
However, he noted that FLNG is “a novel idea whose risk profile is being defined.”

Energy Fact of the Week: Trains and Gains

2011-11-04T19:55:00.000-07:00

Energy Fact of the Week: Trains and Gains

Even Cuba Understands What's to Gain from Off-Shore Drilling

2011-10-23T14:22:00.000-07:00

By DANIEL KISH

One year ago, the Obama administration ended it's blanket offshore drilling ban. But it replaced its drilling moratorium with a permitorium. The bureaucrats said they were allowing drilling, but they granted very few permits and it took months to issue a permit for new drilling.
While the Obama administration is not keen on producing energy domestically, the Cubans of all countries are going to use the technology developed by American companies in the Gulf of Mexico to access their energy resources less than 100 miles from the coast of Florida. When Cuba recognizes an economic opportunity that the administration does not, we should pay attention.
[See a collection of political cartoons on energy policy.]
Even though one year has passed since the end of the moratorium, the administration is still issuing a reduced number of permits. Before the moratorium, the administration was issuing 72 permits per month and now, a full year after the moratorium supposedly ended, they are only issuing 52 permits per month.
Not only has the rate of issuing permits slowed, but the paperwork required to satisfy the administration's bureaucrats has increased exponentially. Before the moratorium, the average permit application was 30-40 pages long. Now a permit application is 3,600 pages long. This dramatic increase in bureaucratic paperwork will create some jobs—but only jobs for more lawyers and more bureaucrats. Creating more work for attorneys and bureaucrats does not help the economy grow.
The administration's byzantine permitting requirements have lead to drilling rigs leaving U.S. waters for countries that welcome energy production. Nearly 40 percent of the deepwater rigs that were in the Gulf of Mexico before the moratorium have left. These rigs could have drilled an additional 60 wells, created 11,500 jobs and generated $6.3 billion in private sector spending. Instead of realizing these positives, the Obama administration is exporting those jobs to other countries.
[Read: How Much Oil Is There?]
The economic benefits of energy production are clear. If Congress permanently lifts the moratoria on energy exploration and production in the Outer Continental Shelf, access to these vast resources would generate:
• $8 trillion in additional economic output (GDP);
• $2.2 trillion in total tax receipts;
• 1.2 million new, well-paying jobs annually across the country; and
• $70 billion in additional wages each year.
But while the Obama administration does not seem to grasp the benefits of job creation and economic growth created by energy production, the Cubans apparently do. According to NPR, geologists estimate there may be 5 billion to 20 billion barrels of oil off the coast of Cuba (between Cuba and Florida). In the past, these resources have been out of reach, but because of the deepwater drilling technologies developed by U.S. workers in the Gulf of Mexico, Cuba will be able to access these resources for the first time. A drill rig is en route from China to Cuba and could start drilling as early as November.
It's not too often that you can say that we should look to Cuba for taking advantage of an economic opportunity, but when it comes to creating jobs and lowering the cost of energy through energy production, we should pay attention. Thousands of hard working Americans are out of work in the Gulf states because the administration isn't following Cuba's example. Now is the time to get these people back to work creating energy.

Proud to be part of the industry

2011-10-16T13:27:00.000-07:00

By Chris John

Last month, the Joint Investigation Team of the Bureau of Ocean Energy Management, Regulation, and Enforcement and the U.S. Coast Guard released their final report analyzing the Macondo incident that occurred in 2010.
Within the detailed and thorough report, there were recommendations made on how best to upgrade and enhance the regulatory structure and industrial prowess for offshore drilling at the BOEMRE. In reading these, I was struck by the similarities in the suggestions made in the report and the overhauls already enacted at the BOEMRE and the additional, voluntary requirements industry has adopted.
Throughout what I still consider to be an unnecessary six-month moratorium, the oil and gas industry remained committed to the highest levels of safety by voluntarily creating and designing the Marine Well Containment Company. This is part of an effort to improve prevention, well-intervention and spill response. When it became evident that the permit process needed drastic improvement, the industry and state government officials worked with the BOEMRE to improve the efficiency of the permit review process. While we are still not happy with the pace of things by any stretch of the matter, they are getting marginally better.
Despite this slowdown, the industry is getting back to work.

For example, just last month, Chevron announced a major discovery in the deepwater Gulf of Mexico on a well it began drilling in early 2010. Also last month, BP submitted its first deepwater exploration plan since Deepwater Horizon. Its 212-page plan includes a number of measures that go above and beyond current BOEMRE requirements. This indicates BP’s confidence in its lessons learned from its detailed analysis of what led to the Macondo incident. BP’s pledge and singular focus to doing the job safely are guiding it through the next steps as it returns to the Gulf of Mexico.

Week after week, more and more companies are getting back to work in the Gulf of Mexico, and this commitment to the region underscores its importance to this country’s energy mix. I am proud to be part of an industry that is answering the call in a responsible and safe way, all while continuing to provide good, high-paying jobs that fuel Americas’ energy security.

http://www.dailycomet.com/article/20111013/LETTERS/111019824?p=1&tc=pg

Alaska leaders make the case for ANWR — again

2011-10-02T20:48:00.000-07:00

Congressional hearing focuses on coastal plain as a source of jobs, energy and revenue; critic calls it ‘kowtowing’ to industry

It’s long been the case that Alaska’s top elected officials, regardless of party, have supported opening the coastal plain of the Arctic National Wildlife Refuge to oil and gas development. ANWR
The state’s current crop of leaders again demonstrated that stance during a Sept. 21 congressional hearing that one witness panned as “political theater.”
The House Natural Resources Committee and its Republican chairman, Rep. Doc Hastings of Washington state, convened the hearing to discuss ANWR in the context of jobs, national energy supply and reducing the deficit with leasing and royalty revenue.
The witness list was stacked with supporters of opening the coastal plain to drillers. They included Alaska’s three-member congressional delegation, Gov. Sean Parnell, a prominent resident from a village along the ANWR coast, and a truck driver who hauls freight to the North Slope oil fields.
They said opening the coastal plain could sustain or create scores of jobs and work economic wonders for the state and nation.
Murkowski ‘insulted’
Alaska’s senators, Democrat Mark Begich and Republican Lisa Murkowski, each expressed support for opening the coastal plain.
“With gasoline prices averaging $3.65 in the lower 48 states and unemployment around 9 percent, Alaska is here to help,” said Begich, according to the text of his testimony. “We can offer relief to consumers at the pump, provide well-paying jobs in Alaska and the Lower 48 and help reduce our $14 trillion deficit.”
Murkowski focused on the Obama administration’s consideration of designating practically all of the refuge — including the potentially oil-rich coastal plain — as wilderness. Such a move, which would take the consent of Congress, would pretty much foreclose the possibility of drilling.
“I find it to be both misguided and, as an Alaskan, somewhat insulting when federal agencies continue to look for ways to lock up additional wilderness in Alaska when Alaska doesn’t want it and when the law says, plainly, ‘no more,’” Murkowski’s written testimony said.
She was referring to the U.S. Fish and Wildlife Service effort write a new “comprehensive conservation plan” for ANWR. Murkowski argues the Alaska National Interest Lands Conservation Act of 1980 prohibits agencies from undertaking studies for new wilderness areas without congressional authorization.
“When an agency’s response to our Nation’s current debt and jobs crisis is to seek more ways to twist the law just to keep money buried in the ground, our priorities have spun out of the realm of rationality,” said Murkowski’s written testimony.
Young, governor weigh in
Alaska’s lone congressman, Republican Don Young, also cited the high price of gasoline in his testimony. It’s because domestic oil production hasn’t kept pace with demand, he said.
He gave a nod to those who fear oil and gas activity would compromise what has been described as ANWR’s pristine character.
“Let’s be honest and say that there will be some consequences to exploring and producing in ANWR,” said Young’s written testimony. “But let’s also be honest and say that if we import the oil it will arrive in the U.S. in foreign ships that sometimes are not up to our standards. And our environmental safeguards for oil production are much more stringent than theirs are. So if you are really concerned about the environment you should prefer oil to be produced here rather than somewhere else in the world. Just a few short weeks ago news broke of a deal that will partner Exxon and Russia to drill in the Arctic. Do we really trust that Russia can protect the Arctic better than we can?”
Gov. Parnell, a Republican, spoke to the committee via video conference.
“Look at the states doing relatively well in this economic downturn — they are America’s major energy producers,” he said. “And Alaska is one of those states. Yet we are held back from contributing more affordable energy to other Americans by federal regulators who want to keep federal lands off-limits to oil and gas exploration.”
Parnell told the committee the viability of the trans-Alaska pipeline is threatened by declining oil production. His goal is to boost throughput to 1 million barrels a day, well above the current level of around 600,000 barrels.
With modern technology, the governor said, the oil industry’s “footprint” could cover less than 2,000 acres of the refuge, which is nearly the size of South Carolina.
“For most of the year, the coastal plain is frozen. It has low biological activity,” Parnell said. “Experience shows that seasonal restrictions and other environmental stipulations can be used to protect caribou during their six-week calving season each summer. Appropriate restrictions can also protect migratory birds and fish. Our experience with other North Slope fields shows it can be done.”
A villager and a trucker
The U.S. Geological Survey, in a 2005 paper, estimated the coastal plain’s undiscovered, technically recoverable crude oil at 5.7 billion to 16 billion barrels, with a mean of 10.4 billion.
Fenton Rexford, a member of the Kaktovik City Council and a candidate for mayor of the North Slope Borough, told the committee that people in his village support responsible development on the coastal plain.
“I am a life-long resident of Kaktovik and I intend to grow old there,” his written testimony said. “I can compare what life in Kaktovik was like prior to oil development on the North Slope to the quality of life we have today because of my personal experience.”
He said ANWR development means a continuation of modern life for villagers: running water and flush toilets, a local school, police and fire services.
The Inupiat villagers wouldn’t favor development, Rexford said, unless they were confident development wouldn’t hurt their subsistence way of life.
The committee also heard from Carey Hall, a truck driver for Carlile Transportation Systems. He said he works on the “ice roads” hauling freight to and from the North Slope.
Finding new oil in places such as ANWR is crucial, he said.
“The oil and gas industry represents the cornerstone of our business,” he said. “It is not only important to contractors and vendors such as trucking companies but to all our citizens in the state of Alaska and as a nation. It produces jobs, lots of jobs, and we need jobs.”
The critics
Two witnesses invited by the committee minority had a markedly different view on using ANWR as a tool for creating jobs and fighting the national debt.
Gene Karpinski, president of the nonprofit League of Conservation Voters, said he is fighting for permanent protection of the coastal plain. He characterized the hearing as “nothing more than political theater.”
“Drilling in the Arctic Refuge is and always will be a political hot potato that has been voted on 20 times in the past 30 years, in the House of Representatives alone,” said the written text of Karpinski’s testimony. “Over and over again, pro-drilling members of Congress have trotted out our nation’s last great wilderness place as a panacea for everything from the budget deficit and high unemployment to providing heat for the poor, relief to hurricane ravaged states, support for our troops and health benefits to coal workers.
“Through it all, every attempt to drill the Arctic Refuge has ultimately failed because of the continued strong support of the American people who see this never-ending political spectacle for what it is — a kowtow to the wealthiest corporations in the world, the only ones who will actually benefit from opening the Arctic Refuge to drilling.”
David Jenkins, of Republicans for Environmental Protection, questioned the idea of the industry disturbing only 2,000 acres. Citing the USGS, he said any oil is likely to be scattered in small pockets across the entire plain.
“Oil development would necessitate a massive spider web of pipelines throughout the area,” he testified.
Rosy job projections on ANWR’s unproven oil reserves are overblown, and even a major oil find would be unlikely to significantly improve the nation’s energy security or reduce gasoline prices, Jenkins said.

Point Thomson: Field fight over?

2011-08-20T22:27:00.000-07:00

Field fight over?

Alaska, Exxon have ‘resolution in principle’ on Point Thomson, Sullivan says

For Petroleum News

A top Alaska official signaled strongly Aug. 15 that the six-year fight for control of the Point Thomson oil and gas field might soon be over.

Dan Sullivan, commissioner of the Alaska Department of Natural Resources, told a legislative committee the state and ExxonMobil, the Point Thomson unit operator, have reached “resolution in principle” on terms to settle the legal conflict.

“We believe that this is a resolution that advances the state’s interests,” Sullivan told the Senate Resources Committee, meeting in Anchorage. “ExxonMobil now is discussing the provisions of the settlement with other working interest owners of the unit, who are also the other litigants in the current lawsuit.”

Terms of the settlement remain confidential, Sullivan said.

He noted the matter is more involved than simply the state and ExxonMobil reaching a deal, as the Point Thomson WIOs also are working out “internal commercial terms between themselves.”

Sullivan’s remarks are the most significant sign yet that the struggle over the rich but undeveloped field is coming to a close, heading off what easily could be years more litigation between DNR and the major Point Thomson stakeholders. Besides ExxonMobil the major players include BP, Chevron and ConocoPhillips.

Alaska economic development boosters are anxious to see the legal cloud lifted from Point Thomson, as it contains roughly a quarter of the North Slope’s 35 trillion cubic feet of natural gas. Many believe that all the gas, including the Point Thomson reserves, are needed to make a North Slope gas pipeline a viable project.

A settlement also conjures intriguing possibilities for how the field’s considerable endowment of oil and other hydrocarbon liquids might be exploited. Full-blown development of these resources could generate a boomlet of industry activity on the Slope.

Private briefing offered

DNR began taking firm steps to break up the Point Thomson unit and reclaim the state-owned acreage in 2005, during the administration of Gov. Frank Murkowski.
The state’s beef is the lack of any production to date from Point Thomson, despite its discovery decades ago in the late 1970s.

The field is located along the Beaufort Sea coast next to the Arctic National Wildlife Refuge.

The oil companies went to court to block the state’s effort to break up the unit, and today the case rests before the Alaska Supreme Court.

In recent weeks, DNR and the oil companies have filed heavy legal briefs, suggesting that no out-of-court settlement was near.

Yet the two sides have been negotiating for a year or more, with Gov. Sean Parnell and ExxonMobil executives stating publicly they wanted to settle the dispute.

Sullivan offered to brief legislators on the settlement terms “in a confidential setting.”

“Thank you, commissioner, I think that we would probably seek to take advantage of that offer because I think ... it is a material step forward,” replied Sen. Joe Paskvan, a Fairbanks Democrat and committee co-chairman.

Sen. Hollis French, D-Anchorage, asked Sullivan whether it was “fair to say that the state and Exxon are through negotiating and that negotiations that are taking place now are between Exxon and its partners. In other words, we made sort of our last best offer.”

Sullivan: “I think it’s fair to say.”

During the court proceedings, some friction emerged among the Point Thomson working interest owners, with Chevron, BP and ConocoPhillips complaining that they had been shut out of the negotiations between the state and ExxonMobil.

Deal timing unclear

ExxonMobil was measured in its response to Sullivan’s remarks. The company provided this statement via e-mail to Petroleum News and other media outlets:
“We’re aware of the State’s testimony on August 15, 2011 at the legislative committee hearings. We remain committed to working with Governor Parnell’s administration and the other working interest owners to finalize a settlement.

“Settling Point Thomson litigation and securing necessary local, state and federal permits is imperative to maintain the pace of Point Thomson development.”

The question naturally came up at the legislative hearing as to when a settlement could be finalized.

“When would you anticipate that the deal would be official and could be made public?” Paskvan asked Sullivan. “What’s the timeline on that — is that 90 days, 45 days?”

Sullivan replied: “You know, Mr. Chairman, I really don’t know. Our interest would be soon. In some ways those discussions right now are ... the timeline of those, we’re not necessarily driving that anymore.”

The other committee co-chairman, Republican Sen. Tom Wagoner of Kenai, said he’s been involved with the issue of Point Thomson development through three administrations, and he congratulated Sullivan on getting this far.

“I know it’s been a real battle that started with the Murkowski administration and went right on through,” Wagoner said. “Well, it’s very, very essential to the completion of the large pipeline.”

“Sen. Wagoner, we’re not, it’s not over yet,” Sullivan said. “As you know, anytime you work on settling litigation it’s never easy. You never get fully everything you want.”

What sort of development?

Sullivan noted that, while Point Thomson gas is considered important for a North Slope gas pipeline, the field also is rich in petroleum liquids, and production of those liquids could help stem the oil throughput decline on TAPS, the trans-Alaska pipeline system.
While construction of a gas line appears far from imminent, with no project yet confirmed, ExxonMobil itself created an incentive for wrapping up a Point Thomson deal as quickly as possible.

The company has pledged to begin production of 10,000 barrels a day of natural gas condensate, a liquid hydrocarbon, from Point Thomson by year-end 2014.

Already, the company has drilled two wells at Point Thomson, having obtained special permission from DNR in 2009 to sink the holes on two of the unit’s 31 leases. ExxonMobil and its partners proceeded with the drilling as part of a strategy to hang onto the field, which is worth billions of dollars.

But the Nabors 27-E rig used to drill the wells has been demobilized, and ExxonMobil would appear to have a tight window now for installing facilities to produce the condensate by the 2014 deadline.

A 22-mile pipeline also must be built to connect the remote Point Thomson field to the Slope’s existing pipeline network.

Of course, the deal now on the table between DNR and ExxonMobil might feature a whole new development scenario.

“The settlement is focused on the development of the Point Thomson unit which contains both hydrocarbon liquids and gas and we believe that the settlement of this litigation should help advance the strategic goals of filling TAPS and commercializing North Slope gas,” Sullivan told legislators.

10 Things That Must Change

2011-08-09T13:50:00.000-07:00

10 Things That Must Change
By Doug Kass

This blog post originally appeared on RealMoney Silver on Aug. 3 at 8:25 a.m. EDT.
It is said that confidence is contagious and so is the lack of confidence. And these days, this statement applies directly to our Representatives' rancor and overall behavior over the past month in Washington, D.C.
A domestic economic recovery on a slow trajectory path is exposed to policy mistakes and external shocks (e.g., geopolitical, oil spike, etc.). It is now clear that confidence has been sufficiently eroded, in part, by the Washington circus -- and this has, in part, served to undermine growth and has jeopardized our equity markets.
I have written extensively about investors' consternation toward our country's politicians. Over the past few weeks, in "My 'Fast Money Halftime Report' Recap" and "Partisanship Trumps Progress," I have described the potential headwinds to economic growth and stock market appreciation instilled by the lack of confidence (on the part of businesses and consumers) caused by the ineptitude and bitterness in the latest debate over the debt ceiling and budget issues.
Indeed, back in late 2010, my surprise list for 2011 included two surprises on the manner in which partisan politics would inhibit economic growth and limit the upside to equities.
Surprise No. 2:
Partisan politics cuts into business and consumer confidence and economic growth in the last half of 2011.
Increased hostilities between the Republicans and Democrats become a challenge to the market and to the economic recovery next year....
The resulting bickering yields little progress on deficit reduction. Nor does the rancor allow for an advancement of much-needed and focused legislation geared toward reversing the continued weak jobs market.
Surprise No. 9:
A new political party emerges. Screwflation becomes a theme that has broadening economic social and political implications. Similar to its first cousin stagflation, screwflation is an expression of a period of slow and uneven economic growth, but, in addition, it holds the existence of inflationary consequences that have an outsized impact on a specific group. The emergence of screwflation hurts just the group that authorities want to protect -- namely, the middle class, a segment of the population that has already spent a decade experiencing an erosion in disposable income and a painful period (at least over the past several years) of lower stock and home prices.
Importantly, quantitative easing is designed to lower real interest rates and, at the same time, raise inflation. A lower interest rate policy hurts the savings classes -- both the middle class and the elderly. And inflation in the costs of food, energy and everything else consumed (without a concomitant increase in salaries) will screw the average American who doesn't benefit from QE2.
Stagnating wages and ever higher food and other costs energize Middle America, the chief victim of screwflation, and a new party, the American Party, emerges chiefly through a viral campaign begun on Facebook. This centrist initiative initially is endorsed by several independent Republican and Democratic Congressmen, but a ratification by Senator Joe Lieberman (Connecticut) leads to several Senatorial endorsements as it becomes clear that the American Party's ranks are growing rapidly. (Both the Tea Party and Sarah Palin abruptly disappear from the public dialogue.)
By the end of 2011, between 5% and 10% of all U.S. voters are believed to be members of the American Party. With its newfound popularity, the American Party asks New York City Mayor Bloomberg to become its leader. By year-end 2011, he has not yet made a decision.
This morning I want to change my stripes; instead of focusing on and being critical of the disruptive impact of the deliberations in Washington, D.C. last week, I want to propose some solutions (a hat tip to Omega's Lee Cooperman who helped me on some of these suggestions).
So, if I were king of the forest, here are 10 changes I would immediately enact:
1. Establish term limits for all our representatives.
2. Limit government spending. Set a specific limitation on the annual gains in spending to be less than the increase in consumer price index.
3. Develop a comprehensive jobs plan.
4. Fix housing. Over 15 million homeowners are underwater with their mortgages, the shadow inventory of unsold homes is a drag on a housing recovery, and we must find a way to find a way to reemploy over 2 million former housing-related workers. We need a Marshall Plan for housing. I would suggest that the Obama administration reach out to the two most knowledgeable and smartest guys in the residential real estate markets, Eli Broad and Bob Toll. I would have them all meet in a locked room with Fed Chairman Ben Bernanke, Treasury Secretary Geithner and President Obama (and his economic team).
5. Raise taxes on the rich. Put a three-year income tax surcharge (of 10% to 15%) on incomes above $500,000.
6. Create a health care czar and tackle our health care industry's delivery and costs.
7. Mean test entitlements, freeze entitlement payouts and gradually increase the social security retirement age to 70 years old.
8. Exit Afghanistan and Iraq immediately. More effectively rationalize the defense budget and provide returning soldiers full tuition to vocational schools and colleges as they have sacrificed much.
9. Build infrastructure. Set up an infrastructure bank, and place the money saved on defense into a massive build-out and improvement of the U.S. infrastructure base.
10. Create energy self-sufficiency. Develop a comprehensive plan designed to rapidly develop all of our energy resources.

Energy Tomorrow - State of American Energy

2011-07-10T11:21:00.000-07:00

Energy Tomorrow - State of American Energy

One-third of Alaska energy use is for jets

2011-06-12T14:09:00.000-07:00

Jet fuel supplies for international transportation are one of the biggest uses of energy in the state; oil dominates energy production

By Alan Bailey

Petroleum News

For residents of Alaska, the cost of electricity and fuel for heating, lighting and driving cars provides a constant reminder of the energy consumption that underpins life in “the last frontier.” In 2008, however, 30 percent of the state’s 444 trillion British thermal units of annual energy consumption actually consisted of jet fuel use, powering the international transportation of passenger and freight to and from other regions, according to a report published recently for the Alaska Energy Authority by the Institute of Social and Economic Research.

The report, titled “Alaska Energy Statistics 1960-2008,” pulls together data from a variety of sources to provide factual information about Alaska energy production; energy consumption; and the flow of energy into, through and out of the state.

Other fuels

The report says that, in addition to the use of jet fuel, about one-third of Alaska energy consumption in 2008 consisted of the use of other liquid fuels such as gasoline and diesel fuel. The use of natural gas amounted to 11 percent of total energy consumption, electricity 5 percent and coal 2 percent.
About 10 percent of the energy consumed was used for electricity generation, with about 61 percent of power generation using natural gas as a fuel. Hydropower accounted for 17 percent of electricity generation, oil products for 16 percent and coal for 6 percent. Rural communities predominantly used diesel fuel for power generation, although significant wind power capacity has been implemented in rural Alaska since 2008.

The Alaska Railbelt used about 80 percent of the total electricity generated, with that electricity mainly coming from power stations fueled by natural gas.

Data on the energy balance for electricity generation in Alaska illustrates the relative inefficiency of the state’s aging gas-fired power stations: During 2008 power utilities used 45 trillion Btu of energy but only sold 22 trillion Btu of generated power to electricity consumers, the report says.

And an analysis of carbon dioxide emissions from Alaska power generation indicates that gas-fired power stations emitted a total of 2.3 million metric tons of carbon dioxide in 2008, an emissions figure that could drop to 1.5 million metric tons if power station efficiency were improved to be closer to the U.S. national average, the report says.

Oil dominates production

Not surprisingly, 90 percent of the energy produced in Alaska in 2008 consisted of crude oil, with about 85 percent of that oil being exported from the state. Curiously, on an energy equivalent basis, the amount of natural gas extracted from the state’s oil and gas fields was double the amount of oil produced, but most of this gas was re-injected into the oil fields to drive increased oil production, with the gas presumably being repeatedly cycled through injection and production wells.
Total crude oil production in 2008 amounted to 1,449 trillion Btu of energy, the report says. However, the state did also import crude oil representing 24 trillion Btu of energy, presumably as part of the feedstock for the oil refinery at Nikiski on the Kenai Peninsula, for the production of gasoline and other products used in Southcentral Alaska.

Excluding natural gas re-injected into oil fields, gas represented 8 percent of total 2008 Alaska energy production, with coal production coming in at 2 percent and wind and hydropower at less than 0.5 percent. However, much of the state’s current wind power capacity has been developed since 2008, the year for which the data were assembled, the report says.

Rising prices

Alaska residents will not be surprised by the study’s finding that the prices of most forms of energy have increased significantly in past decades, with natural gas prices increasing 80 percent between 1970 and 2008 in terms of 2008 dollars, and with gasoline prices increasing by 65 percent in that same period. However, average electricity prices actually declined by 14 percent, perhaps as a result of the replacement of some diesel power generation by hydropower.
But what about the price of that jet fuel that’s pumped into airplanes carrying people and goods across the globe? Jet fuel increased in price by a whopping 455 percent between 1970 and 2008, the report says.

Company filing plans to drill up to 10 wells in the Arctic OCS starting in 2012

2011-05-08T20:50:00.000-07:00

By Alan Bailey

Petroleum News

After several years of frustration in its attempts to start an exploration drilling program in Alaska’s Beaufort and Chukchi seas, Shell is in the process of filing new exploration plans for the drilling up to 10 wells, starting in the open water season of 2012.
The plans will entail the drilling of up to two wells per year in the Beaufort Sea and up to three wells per year in the Chukchi Sea, using the drillship Noble Discoverer and the Kulluk floating drilling platform, Shell spokesman Curtis Smith told Petroleum News in a May 2 e-mail.
The company filed its Beaufort Sea plan on May 4, with the Chukchi Sea plan expected to follow within a few days.
Two prospects
According to the Beaufort Sea exploration plan, Shell proposes drilling two wells in its Sivulliq prospect and two wells in its Torpedo prospect, with both prospects being located on the west side of Camden Bay, east of Prudhoe Bay. Sivulliq is the location of a known oil field, previously called Hammerhead.
“As with any Arctic exploration drilling program, weather and ice conditions, among other factors, will dictate the actual sequence in which the wells are drilled. All wells are planned to be vertical,” the exploration plan says.
Shell has two drilling vessels available for use — the drillship Noble Discover and the floating drilling platform, the Kulluk — but says that it has not yet made a final decision on which of these vessels to use in the Beaufort. In March, Pauline Ruddy, Shell regulatory affairs team lead, told the National Marine Fisheries Service Open-water Meeting that the company would likely use the Kulluk for drilling in the Beaufort Sea and the Noble Discoverer for drilling in the Chukchi Sea.
Discharges to be removed
Under the terms of an agreement with the North Slope communities, Shell plans to barge some of the Beaufort Sea waste streams out of region, rather than dispose these waste streams into the ocean. Waste stream to be barged out consist of sanitary waste; domestic waste; bilge water; ballast water; and drilling mud and cuttings from drilling operations below the depth of a well’s 20-inch conductor shoe.
Shell also plans to upgrade the Kulluk’s emissions technology to meet air quality standards.
The drilling vessel would be attended by a minimum of 11 support vessels for ice management, anchor handling, refueling and other tasks, the exploration plan says.
Exploration drilling would start around July 10 and continue through October 31. However, operations would be suspended, with all vessels departing the drilling area, during subsistence whale hunts that would start in late August.
Whichever vessel is used in the Beaufort, the other vessel would be available for relief well drilling, in the unlikely event of a well blowout. Shell has also been planning the construction of a containment dome that could be placed over an Arctic offshore well to contain any oil leak in the event of a well control problem.
Burger prospect
During the NMFS Open-water Meeting Ruddy said that in the Chukchi Sea Shell plans to target the Burger prospect, a 25-mile-diameter structure that is known to hold a major natural gas pool some 80 miles offshore the western end of Alaska’s North Slope.
For its Arctic drilling program, Shell still needs air quality permits from the Environmental Protection Agency. These permits are still on remand from the Environmental Appeals Board, following an appeal by Native Village of Point Hope and eight environmental organizations against the issuance of the permits.
There is also legal uncertainty regarding Chukchi Sea drilling because of an unresolved appeal case in Alaska district court against the 2008 Chukchi Sea lease sale in which Shell purchased its Chukchi Sea leases. The Bureau of Ocean Energy Management, Regulation and Enforcement is in the process of developing a supplementary environment impact statement for the lease sale, in response to a court order in that appeal.

BP puts test horizontal well into operation

2011-05-01T14:10:00.000-07:00

Heavy oil starts
BP puts test horizontal well into operation in the Ugnu at Milne Point

By Petroleum News

Following a lengthy delay after the completion of a $100 million heavy oil test facility on Alaska’s North Slope, BP has now put a heavy oil test well into operation — at 6 a.m. on April 22 a change in torque in the well’s down-hole pump finally signaled the flow of oil through the well, something of an historic event for the North Slope oil industry, Eric West, manager of BP’s Alaska renewal team, told Petroleum News April 27. For a couple of days the well had been producing brine, injected into the oil reservoir during the drilling of the well, but the torque change indicated that oil had finally reached the well bore, West said.

West said that since the morning of April 22 the well has been producing oil at a rate of 350 barrels per day and that the test facility had delivered more than 1,000 barrels of heavy oil to the Milne Point processing facility since the oil started flowing.

“But what pleases us so much is that there has been no upset to the well,” West said. “It has produced steadily at that rate.”

And the well is only producing small amounts of sand, with sand coming up the well in quantities ranging from trace amounts to about 2 percent by volume, he said.

BP is carrying out its testing of heavy oil production from the relatively shallow sands of the Ugnu formation, to ferret out the production characteristics of the resource, with an objective of determining whether commercial-scale heavy oil production on the North Slope will be feasible both from a technical and from an economic perspective, Erik Hulm, heavy oil appraisal team leader for BP Alaska, explained to the Alaska Geological Society on April 22. Companies have been producing heavy oil elsewhere, in Canada and Venezuela for example, but no one knows whether production will prove practical in the challenging Alaska Arctic environment, Hulm said.

But the potential prize is huge, he said.

Billions of barrels

Of the 70 billion or so barrels of oil so far discovered in the central North Slope, only about 40 billion barrels consist of conventional light oil that readily flows up a well bore and through a pipeline. The remaining 30 billion barrels are relatively viscous, thus requiring specialized production techniques, Hulm said.
Within the thicker grades of oil, BP distinguishes between what it calls viscous oil, with a consistency of syrup, and heavy oil, with a consistency of honey or molasses. On the North Slope, BP and ConocoPhillips have in recent years started to produce viscous oil from the sands of the Schrader Bluff/West Sak formation, using horizontal wells and waterflood techniques. But no one has yet attempted to tap into the estimated 12 billion to 18 billion barrels of heavy oil in the shallower Ugnu formation — heavy oil is generally too viscous to flow unaided through a pipe.

Being quite depleted in hydrogen relative to light oil and also being difficult to flow, heavy oil is less valuable than light oil. On the other hand, with high oil prices and with North Slope light oil production declining, companies are moving across the oil viscosity spectrum, seeking new commercial opportunities with more difficult resources. And, with BP hoping to use North Slope light oil to dilute the heavy oil for pipeline transportation, the company wants to see if it can achieve success in heavy oil production before light oil production rates decline to a point where it becomes impractical to ship the heavy oil to market — refining the heavy oil into a less viscous fluid on the North Slope for export by pipeline would be prohibitively expensive, Hulm said.

Two methods

For its test production, located on S pad in the Milne Point field, BP is using two techniques, both involving the pumping of oil into a heated tank at the surface, where sand is separated from the oil for disposal through the Prudhoe Bay grind-and-inject facility. The Ugnu sands, rather than being a conventional solid rock, are unconsolidated.
The first technique, called cold heavy oil production with sand, or CHOPS, involves drilling a vertical well through the Ugnu reservoir and then using what is called a progressive cavity pump, a down-hole pump with an augur-like rotor spinning at high speed, to draw the sand-oil mixture into the well and up the well bore. Small holes, known as wormholes, propagate from the well, out through the reservoir sand, increasing the exposed surface area of sand from which oil can be sucked and providing channels for the oil to flow into the well.

A rod passing down the well bore from the surface turns the pump’s rotor.

In 2008 BP successfully demonstrated the extraction of some oil from the Ugnu using a single CHOPS well, as a precursor to investing in the heavy oil test facility that it has since built.

The second technique involves the drilling of a horizontal well through the reservoir, with slots in the steel well liner creating a large area of contact with the reservoir, allowing oil to enter the well, as in a conventional oil field. A progressive cavity pump located downhole, in the area where the well bore steepens from the horizontal en route to the surface, will push the thick oil up the well. The pump will also draw down the pressure in the horizontal section of the well thus reducing the reservoir pressure — the drop in reservoir pressure should cause gas to effervesce from the oil and drive the oil towards the well, West explained.

Geologic investigation

Hulm explained that BP had arrived at the location and design of its heavy oil test after an exhaustive investigation of the geology of the Ugnu and an evaluation of various heavy oil production techniques.
Quite a lot of information about the Ugnu can be gleaned from the various wells that have passed through this formation en route to drilling targets in the established oil reservoirs deeper below the North Slope, Hulm said. Rock cores pulled from some of these wells provide evidence about the detailed nature of the Ugnu deposits, while well log data enable the extrapolation of rock information to wells from which well cores were not obtained. And seismic data provides a regional picture of the geometry and extent of the Ugnu formation.

Piecing together data from these various sources, geologists have determined that the Ugnu sands commonly fill what must have been meandering river channels within ancient river delta systems during the late Cretaceous and early Tertiary. The most promising looking oil reservoir units consist of multiple sand-filled river channels, stacked together to form large sand bodies in the subsurface.

The entire formation slopes west to east, lying about 2,000 feet below the surface on the western side of the central North Slope and being 5,000 feet deep to the east. Many geologic faults cut through the strata, breaking the reservoir into a multiplicity of compartments but also trapping oil in the sand bodies by juxtaposing the sand against more impervious rocks.

The heavy oil in the Ugnu has formed as a result of bacteria eating the originally formed light oil. And, with the bacteria becoming increasingly active at lower temperatures, the oil at the relatively cold, shallow western end of the Ugnu is heavier and thicker than the oil at the deeper and less cold eastern end, Hulm said.

Choice of technique

That variation in depth and oil type from one part of the Ugnu to another has a critical impact on the choice of technique used to extract oil from the Ugnu sands.
Hulm described a hierarchy of heavy oil extraction techniques, some of which have a multiyear track record of successful use and some of which are more hypothetical in nature. Methods that have seen success in some parts of the world can be broadly categorized as mining, hot extraction and cold extraction.

The direct mining of heavy oil deposits can be eliminated as a possibility for heavy oil production on the North Slope, in part because of the depth of the Ugnu sands and in part because of unacceptable environmental impacts, Hulm said. Hot extraction, typically involving the injection of steam into the underground sand to reduce the oil viscosity, has been used with success in Canada and is a possible candidate for North Slope use. Both CHOPS and the use of horizontal wells are examples of cold oil extraction techniques and both have track records of success in some places.

But the best technique to use in a particular situation depends on the particular combination of oil and rock properties that a would-be heavy oil producer is dealing with, Hulm said.

“It’s actually the rock and fluid properties that dictate which of these methods is going to work,” he said.

For its North Slope heavy oil production test, BP determined that cold techniques — CHOPS and horizontal wells — would be most appropriate. These techniques seemed suitable for the reservoir depths, sand qualities and oil viscosities within the North Slope units where BP is operator, Hulm explained. And the use of cold techniques would avoid some engineering challenges potentially associated with pumping hot steam through well pipes in the North Slope permafrost, he said.

However, it is likely that a hot, steam-driven technique would be more appropriate in the shallower and heavier oil deposits, more toward the western end of the Ugnu, he said.

Risk assessment

Using the results of its geologic analysis, BP developed a set of maps depicting the relative risks to successful cold heavy oil production at different places, using parameters such as the rock porosity, sand thickness and oil quality. The maps led BP to the selection of the Milne Point S-pad as a suitable test location. The location sits over stacked, Ugnu channel sands and is within reaching distance of several reservoir zones and a couple of faulted reservoir compartments, Hulm said.
And BP sees the possibility of 7 billion barrels of oil in place in reservoir areas earmarked as candidates for cold production. If cold extraction works the recovery factor would likely be around 10 percent, but could approach 20 percent, Hulm said.

As a proof of concept exercise, BP is trying out two horizontal wells and two CHOPS wells in an initial test phase, West said. It will take about a week to draw down the pressure in the horizontal well that has gone into production, after which the heavy oil team will monitor the well for a week before starting up the first CHOPS well, he said.

But extracting heavy oil from a reservoir below 2,000 feet of permafrost in the Arctic represents a move outside the envelope of industry experience of using cold heavy oil extraction techniques, Hulm said. And the production characteristics of the Ugnu reservoir and oil are unknown. Moreover, the use of surface-driven rods to spin the progressive cavity pumps at the bottoms of wells necessarily deviated far from the vertical in the North Slope’s drilling-footprint-conscious environment will present some particular technical challenges.

Depending on the test results, BP could determine that some other production technique is required, Hulm said. However, at some time in the future heavy oil production will hopefully deliver a substantial new resource to market and bring a new source of revenue to Alaska, he said.

http://www.petroleumnews.com/pntruncate/40812990.shtml

The Green Thing

2011-04-21T11:03:00.000-07:00

In the line at the store, the cashier told the older woman that she should bring her own grocery bag because plastic bags weren't good for the environment. The woman apologized to him and explained, "We didn't have the 'green thing' back in my day."

The clerk responded, "That's our problem today. The former generation did not care enough to save our environment."

He was right, that generation didn't have the green thing in its day.

Back then, they returned their milk bottles, soda bottles and beer bottles to the store. The store sent them back to the plant to be washed and sterilized and refilled, so it could use the same bottles over and over. So they really were recycled.

But they didn't have the green thing back in that customer's day.

In her day, they walked up stairs, because they didn't have an escalator in every store and office building. They walked to the grocery store and didn't climb into a 300-horsepower machine every time they had to go two blocks.

But she was right. They didn't have the green thing in her day.

Back then, they washed the baby's diapers because they didn't have the throw-away kind. They dried clothes on a line, not in an energy gobbling machine burning up 220 volts - wind and solar power really did dry the clothes. Kids got hand-me-down clothes from their brothers or sisters, not always brand-new clothing.

But that old lady is right, they didn't have the green thing back in her day.

Back then, they had one TV, or radio, in the house - not a TV in every room. And the TV had a small screen the size of a handkerchief, not a screen the size of the state of Montana. In the kitchen, they blended and stirred by hand because they didn't have electric machines to do everything for you. When they packaged a fragile item to send in the mail, they used a wadded up old newspaper to cushion it, not styrofoam or plastic bubble wrap.

Back then, they didn't fire up an engine and burn gasoline just to cut the lawn. They used a push mower that ran on human power. They exercised by working so they didn't need to go to a health club to run on treadmills that operate on electricity.

But she's right, they didn't have the green thing back then.

They drank from a fountain when they were thirsty instead of using a cup or a plastic bottle every time they had a drink of water. They refilled their writing pens with ink instead of buying a new pen, and they replaced the razor blades or bought a blade sharpener for a razor instead of throwing away the whole razor just because the blade got dull.

But they didn't have the green thing back then.

Back then, people took the streetcar or a bus and kids rode their bikes to school or rode the school bus instead of turning their moms into a 24-hour taxi service. They had one electrical outlet in a room, not an entire bank of sockets to power a dozen appliances. And they didn't need a computerized gadget to receive a signal beamed from satellites 2,000 miles out in space in order to find the nearest pizza joint.

But isn't it sad the current generation laments how wasteful the old folks were just because they didn't have the green thing back then?

http://www.freedomsledder.com/forums/index.php?showtopic=45567

DNV Macondo BOP Final Report

2011-03-28T17:27:00.000-07:00

DNV Macondo BOP report - Drill pipe at an awkward angle
DNV has released its final report into what went wrong with the Blow Out Preventer above the Macondo well - it was drill pipe not being cut properly, due to being at an awkward angle when the rams tried to cut it.

At the time of the accident, there was a drill pipe tool joint between the upper annular ram and the upper variable bore ram. When both of these rams were closed around the drill pipe, forces from the flow of fluids pushed the tool joint into the upper annular ram.

This meant that the when the blind shear ram was closed, it did not close the drillpipe smoothly, but pushed the pipe at an awkward angle, which meant it did not seal.

Note - it was not a problem of a tool joint being positioned between the blind shear rams at the time they were activated and the rams not being able to cut them (as many people thought it might be) - but the tool joint being in a position such that the rams could not cleanly cut the drill pipe.

An additional contributing factor was the fact that the upper annular ram, which closes around the drillpipe but does not squash the drillpipe, was closed at the time, because of the negative pressure tests which were carried out.

So the drillpipe did not have freedom to move - this also means that the rams were trying to close the drill pipe in a scenario which might have not been previously tested.

The liquids flowing through the well made it buckle between the upper annular and upper variable bore rams, which also led it to squash in an awkward way.

So as the blind shear rams closed, part of the drill pipe cross section ended up being trapped between the ram block faces, so the blocks did not fully close.

The evidence suggests that the blind shear rams were activated on the morning of April 22nd (the date the rig sank) - at this date the hydraulic plunger to the autoshear valve was cut, DNV says - although there is no way to be sure exactly when it closed, it could have been activated earlier by the deadman / automatic mode failure system.

When the drill pipe was sheared on April 29 with the casing shear rams, the flow just found a different route, going through open drill pipe at the casing shear rams, and up the wellbore to the blind shear rams.

DNV recommends that the industry makes further studies what effect flow through the drill pipe tubing and blow out preventer components can have on the ability for the BOP to close, with possible buckling of the drill pipe.

It also recommends that the industry should study the effects of tubulars being fixed or constrained in the blow out preventer as the rams close.

DNV recommends that the industry should also look at potential effects of certain activities (for example conducting negative pressure tests) can have on the ability for a BOP to operate in an emergency.

Kenai LNG plant set to close this spring

2011-02-20T10:33:00.000-08:00

ConocoPhillips, Marathon to mothball facility due to weak market conditions; plant has been shipping to buyers in Japan since 1969

By Eric Lidji
For Petroleum News

With news that ConocoPhillips and Marathon Oil plan to mothball their liquefied natural gas plant on the Kenai Peninsula this spring, Alaska is left standing on a bridge without a keystone. Since making its first shipment in 1969, the Nikiski export facility has held the Cook Inlet natural gas market together, even as that market began to change with age.
In its first few decades in operation, the facility justified the production of large Cook Inlet gas fields for local use by providing a large market outside Alaska. In the 2000s, it provided backup for utilities as local deliverability declined. Now, the plant could theoretically be converted to an import facility to bolster declining local production.
ConocoPhillips and Marathon made their decision based on market conditions, but those conditions aren’t easily delineated. As recently as last summer, the owners felt confident enough about the Asian market to apply for another two-year extension of their export license, but it appears the companies could not secure contracts through April 2013.
The reasons abound. The plant used to be the sole supplier to Japan, but now supplies only one half of one percent of that market. The LNG shipments leaving Alaska were once the largest in the world, but are now among the smallest. Supply contracts between Alaska and Japan used to run for 15 years, but have recently run for two-year terms.
Now, the future of the plant is uncertain.
“Right now, our intent is to get the plant preserved. We’re going to be evaluating options,” Dan Clark, ConocoPhillips’ manager of Cook Inlet assets, told Petroleum News. Those options range from closing the plant, to reconfiguring it, to selling it.
The bad news ripple effect
While Asian markets don’t appear to be mourning the news, the closure’s impact on Alaska markets will be wide ranging because of the unique role the LNG facility plays.
Once the plant is mothballed in April or May, it will jeopardize more than 100 direct and indirect jobs and tens of millions in taxes and royalties for state and local governments.
With the coldest months over by then, Southcentral should be no worse off than expected for this winter, but peak demand will be a critical issue next winter. Although Enstar Natural Gas, through Cook Inlet Natural Gas Storage Alaska, is building a new third-party storage facility, it won’t be ready until 2013. Even once it comes online, it won’t make up for the combined loss of the plant and declining Cook Inlet production.
“This storage facility is not intended to be a be-all end-all solution for Cook Inlet,” said John Sims, a spokesman for Enstar Natural Gas, the largest consumer in Alaska.
While Enstar expects to start getting firm shipments from the North Fork unit starting in March, those deliveries won’t fill the shortfall Enstar is facing in the coming years.
“That insurance policy that we had is lost,” Sims said. “And that’s a big one.”
Some wells to be shut-in
Until storage is available, ConocoPhillips will have to shut-in some wells once local demand drops in the summer. Because of the aging nature of Cook Inlet reservoirs, it’s unknown how those wells will produce once ConocoPhillips brings them back online.
(However, ConocoPhillips will continue to operate the Tyonek platform at the North Cook Inlet unit. While that unit primarily feeds the export facility, it is not isolated from the grid. North Cook Inlet and Beluga River will now be used to fill local contracts.)
The closure could also dampen exploration in Cook Inlet.
Through a deal with the state, ConocoPhillips and Marathon Oil bought third-party natural gas at their export facility, creating a market for explorers. Even though Alaska is craving natural gas, the local market might still not be large enough to support all of the potential production from the Cook Inlet leaseholders currently interesting in drilling.
The loss of an overseas market could also jeopardize plans to bring North Slope natural gas to Southcentral. Various plans for an in-state pipeline require an “anchor tenant,” like the export facility, to keep residential and commercial customers from bearing the full cost of the project. Meanwhile, an “all-Alaska line” from Prudhoe Bay to Valdez is based on exporting LNG, although the larger volumes available from the North Slope could change the market dynamics, allowing Alaska to better compete against other basins.
A plant in gradual decline
The closure of the plant is not entirely unexpected.
The last decade brought fundamental changes to the operation of the plant.
Phillips Petroleum and Marathon Oil built their facility at the dawn of the global LNG trade, only a few years after Great Britain began importing it from Algeria in 1964.
The Kenai plant started its life as a pioneering infrastructure system: a liquefaction plant in Alaska and a re-gasification plant in Japan, the two largest LNG tankers ever built and the new offshore Tyonek platform along with new pipelines and wells to support it.
The facility originally operated on long-term contracts with two Japanese utilities, Tokyo Electric Power Co. Inc., and Tokyo Gas Co. Ltd. The first export license ran from 1969 to 1984 with a five-year extension. The second license ran from 1989 to 2004.
Starting in the mid-1990s, the idea of shipping gas overseas caused heartburn at home.
In 1996, Phillips and Marathon applied for a five-year extension, through 2009, but local utilities and producers argued that continued exports would cause shortages in Alaska.
The U.S. Department of Energy approved the extension, but the issue reared its head again when ConocoPhillips and Marathon asked for a two-year extension through 2011.
The State of Alaska only backed the request after the companies agreed to certain concessions, like meeting local needs, increasing drilling and buying third party gas.
Utilities supported last extension
Last summer, when ConocoPhillips and Marathon requested another two-year extension, though 2013, the changing nature of the Cook Inlet changed the nature of the opposition.
Aside from a group of Democratic lawmakers worried about local supplies meeting local demand, the request got wide support from utilities, producers and the State of Alaska.
That happened for two reasons. First, ConocoPhillips and Marathon asked only for more time to ship volumes already approved for export. Second, storage and deliverability became more immediately pressing issues in Southcentral than production.
In the past decade, though, the plant and Cook Inlet began to show their age.
A 2006 report estimated that the plant would need significant investments to continue operating beyond 2011. ConocoPhillips recently put the cost of that investment in the range of several hundred million dollars. Except for an expansion in the mid-1990s, the plant, including its two turbines, has been in service since operations began in 1969.
(Reconfiguring the plant for imports would create additional costs.)
In 2007, Agrium mothballed its nitrogen fertilizer operations on the Kenai Peninsula after years of declining gas purchases because it could no longer secure a supply contract.
In April 2009, ConocoPhillips and Marathon cut their tanker fleet in half, reducing the volume of shipments. “Looking back on it, that was sort of the first step,” Clark said.

AGIA an issue in Juneau

2011-02-13T20:01:00.000-08:00

House Bill 142 says line uneconomic without firm commitments by summer
Kristen Nelson Petroleum News

Is it time to declare AGIA dead? That’s the question some Alaska legislators are asking.
The TransCanada-ExxonMobil Alaska Pipeline Project, one of two projects to move Alaska North Slope gas to market, was licensed by the state under the Alaska Gasline Inducement Act.
Tony Palmer, vice president of Alaska development for TransCanada, said after the close of the July 30 open season last year for the Alaska Pipeline Project that “we have received multiple bids from major industry players and others for significant volumes.”
The next step, he said, is to work with potential customers to resolve conditions on the bids: “That’s what we’ll be doing over the next several months.”
Palmer told Petroleum News just prior to the close of the open season that the goal was to have precedent agreements signed by the end of the year. If conditions are simpler, it may take less time, he said.
On the other hand, “If we get many complex conditions we may not be able to achieve it in 100 business days,” extending beyond the end of the year when precedent agreements could be signed, Palmer said.
Because year-end has come and gone without signed precedent agreements, some members of Alaska’s Legislature are now concerned that the AGIA-licensed project is a failure and they want to legislate a way for the state to get out of its contract.
State required continuation
Under AGIA, the state required that in the event of a failed initial open season — no bidders for pipeline capacity or not enough bidders — the licensee would be committed to continue through certification by the Federal Energy Regulatory Commission.
That was one of the must-haves in AGIA, which in return provided a number of incentives, including $500 million in state matching funds for work on the project through FERC certification.
Palmer told legislators during the 2007 debate over AGIA that TransCanada preferred — in the case of a failed initial open season — to focus on obtaining customers “as opposed to doing the engineering and regulatory and legal work to capture a FERC certificate.”
Palmer said that even though the state offered a higher cost-share match after an open season, that TransCanada would prefer not to pursue the certificate “until we had customers or credit.” Told that fellow Canadian pipeline company Enbridge had told legislators “no producers, no pipeline,” Palmer said in his view it is “no customers, no credit, no pipeline.”
The Legislature passed AGIA in 2007, and despite its concerns over the FERC certification requirement, TransCanada submitted an AGIA application and received the AGIA license in 2008.
Both the Alaska Pipeline Project and the competing BP-ConocoPhillips Denali project held open seasons last year. Both reported receiving bids; neither project has completed negotiating precedent agreements.
HB 142 introduced
Which brings us to the new session of the Alaska Legislature, and concerns by some House Republicans that since precedent agreements have not been signed the AGIA-licensed project may not be economic and may not result in a pipeline, while the state is committed to reimbursing TransCanada up to $500 million.
The sponsors of House Bill 142, introduced Feb. 4, say the bill would provide an exit strategy for the state if there are insufficient firm transportation commitments resulting from the initial open season.
House Speaker Mike Chenault, R-Kenai, speaking at a Feb. 7 press conference, said the Legislature is in the dark.
“We’ve heard from TransCanada after the open season that gas was bid,” but don’t know if there is enough gas for a pipeline, he said.
Chenault also said “our perception of natural gas supplies in the Lower 48 at the time of the AGIA process are considerably different than what they are today,” with shale gas production growing at a rapid rate.
Rep. Mike Hawker, R-Anchorage, said the goal of the legislation is “to create a sense of urgency about moving forward with the AGIA process.” That urgency was “not mandated in the original AGIA legislation and … I think it was an oversight in the original AGIA legislation,” he said.
The bill creates “a rebuttable presumption that the project licensed under the Alaska Gasline Inducement Act is uneconomic because of insufficient firm transportation commitments during the first open season,” gives TransCanada until July 15 to disclose that it received firm transportation commitments sufficient to support construction of the project, and requires the commissioners of Natural Resources and Revenue to notify the Legislature before Aug. 1 whether firm transportation commitments were disclosed to them prior to July 15.
The commissioners would have until Aug. 15 to submit a report to the Legislature that there are sufficient firm transportation commitments for the project to go forward, or that the project has credit support sufficient to finance construction and predicted costs of transportation “would result in a producer rate of return that is not below the rate typically accepted by a prudent oil and gas exploration and production company for incremental upstream investment that is required to produce and deliver gas to the project.”
TransCanada, administration, respond
Palmer told Petroleum News Feb. 8 that TransCanada “is confident that we have done everything we can do to advance the project and meet the obligations we have to the State of Alaska; and to date the State of Alaska has met their obligations to us as the licensee.”
He said he wouldn’t prejudge what might happen with the bill, but will “participate as requested and we’ll see how that plays out.”
The Associated Press is reporting that the administration plans a legal review of the bill.
Deputy Commissioner of DNR Joe Balash told AP there are concerns about “impacts and potential exposure” from the measure.
Larry Persily, federal coordinator for Alaska Natural Gas Transportation Projects, told Petroleum News in a Feb. 8 e-mail: “I understand Alaskans’ frustrations with the pace of the gas pipeline project and I know people want to see some positive news about the open seasons. I only ask that people not confuse the debate over AGIA with the project itself. The pipeline is possible, the project would be good for the state and the nation, and the federal government is ready to work with whichever company or companies are willing to risk the tens of billions of dollars needed to finance the pipeline.”
Legislative reactions
Members of the Senate Bipartisan Working Group had mixed reactions to the bill.
Senate President Gary Stevens, R-Kodiak, said in a Feb. 8 press availability there were some concerns in the Senate about whether the state has given the process enough time, and said he didn’t “anticipate a similar bill on the Senate side, but we’ll see how things progress on the House side.”
Sen. Bert Stedman, R-Sitka, said he thinks discussion is timely, and said he’s “concerned that we could be tied up in the contractual obligations for years into the future.”
Sen. Tom Wagoner, R-Kenai, said he thinks the Legislature needs to wait to see the results from the open season “and then sort it out at that time.”
House Democrats, speaking at House Minority press availability Feb. 8, were opposed.
Minority Leader Beth Kerttula, D-Juneau, said she thinks “the State of Alaska should be taking down barriers to entry instead of putting them up and I think that unfortunately what the new AGIA bill would do is break our deal to get a gas line.” She said she thinks the bill would produce a lawsuit by “breaking our deal and setting an artificial deadline.”
The bill has been referred to only one committee, House Finance, and Kerttula said she intended to talk to Chenault about that.
Rep. Scott Kawasaki, D-Fairbanks, a member of House Resources, said “certainly AGIA and the whole concept of AGIA is a Resources issue” and should be heard by that committee.

Alaska lawmakers propose ditching Palin's pipeline plan

2011-02-05T09:46:00.000-08:00

JUNEAU – Leading state lawmakers introduced legislation Friday to abandon a centerpiece of former Gov. Sarah Palin’s administration: a state-sanctioned effort to advance a major natural gas pipeline.

The measure from Alaska House Republicans underscored the impatience and skepticism that many lawmakers have expressed about the current process and a belief the state is no closer than it was several years ago to realizing the long-hoped-for line.

Under the Alaska Gasline Inducement Act championed by fellow Republican Palin, the state promised TransCanada Corp. up to $500 million to advance a line. TransCanada won the exclusive license in 2008.

The state has reported that reimbursements so far have topped $36 million.

The company missed a self-imposed target for reaching agreements with shippers at the end of 2010 but has cautioned against reading much into that, noting that negotiations are complex and continuing.

But a number of lawmakers are losing patience — and faith — that this process will succeed in getting a line built this decade, if ever. The measure Friday was the first such introduced by the Legislature.

The bill, introduced by Republican Reps. Mike Chenault, Mike Hawker, Craig Johnson and Kurt Olson, would presume the project is uneconomic if TransCanada cannot show proof to Gov. Sean Parnell’s administration before July 15 that it has received firm shipping commitments.

Parnell has stood behind the process, saying he supports efforts by private industry to build a line that could carry gas from the North Slope to market.

Read More

Alaska pipeline restarted, oil flowing

2011-01-17T19:41:00.000-08:00

by Mary Pemberton / The Associated Press Fairbanks Daily News Miner

ANCHORAGE, Alaska - Oil began flowing again Monday through the trans-Alaska pipeline after workers installed a pipe to bypass a leak at a pump house station on the North Slope.

Alyeska Service Pipeline Co. said it hoped to increase the amount of oil in the 800-mile pipeline to 500,000 barrels during the next 24 hours.

The pipeline was carrying about 630,000 barrels a day before the leak was discovered on Jan. 8 in an underground pipe encased in concrete.

"We are really monitoring the pipeline and the equipment very carefully as we bring it up," said Michelle Egan, a spokeswoman for Alyeska, which operates the pipeline.

The pipeline delivers about 13 percent of the nation's daily domestic oil production to tankers for West Coast delivery.

The oil began flowing again after crews completed a 157-foot bypass.

"It is a complicated process," said Rachel Baker-Sears, a spokeswoman for the Joint Information Center set up in Fairbanks to handle the crisis.

She said the restart went smoothly, but it could take a few days for the pipeline to return to previous pumping levels.

During the initial shutdown, the flow was scaled back to 5 percent of previous levels and oil was collected in two large storage tanks at Prudhoe Bay.

The pipeline was temporarily restarted after four days but was shut down again on Saturday so the bypass pipe could be installed.

During the shutdown, a containment vault was used to collect the estimated 13,326 gallons of oil that leaked from the pump station pipe.

Egan said there had been no known harm to wildlife or the environment.

Read more: http://newsminer.com/view/full_story/11037545/article-Alaska-pipeline-restarted--oil-flowing?instance=home_news_window_left_top_1&sms_ss=twitter&at_xt=4d34ca2241ee526e,0

TAPS Shut Down Because of Leak

2011-01-17T19:38:00.000-08:00

TAPS shut down at midnight Friday for replacement pipe installation
Anchorage (Platts)--
Alyeska Pipeline Service Company began a planned 36-hour shutdown of the Trans Alaska Pipeline System as expected overnight to install new piping at Pump Station 1, bypassing a section of damaged pipe that caused TAPS to shut down last Saturday. The shutdown began at 12:07 a.m. Alaska Standard Time (0907 GMT) Saturday. The company is installing 157 feet of 24-inch pipe that had been fabricated in Fairbanks and moved to the North Slope earlier in the week. Federal and state regulators had allowed TAPS to do a temporary restart Tuesday night so that warm crude oil moving in the line would keep critical systems functioning and prevent a freezeup in winter conditions. TAPS was carrying about 630,000 b/d of crude when it was shut Saturday.

Pump station leak shuts down TAPS

2011-01-08T22:18:00.000-08:00

Pump station leak shuts down Trans Alaska Pipeline System

By CASEY GROVE

Published: January 8th, 2011 07:23 PM

The 800-mile trans-Alaska oil pipeline is shut down due to a leak at Pump Station 1 on the North Slope.

tool nameclose tool goes here North Slope oil producers have been asked to cut their production to 5 percent of normal.

An oil line encased in concrete leaked an unknown quantity of crude oil just outside a booster pump building, according to Alyeska Pipeline Service Co. spokeswoman Michelle Egan. Alyeska operates the line and its pump stations.

A crew doing a routine inspection noticed the leak this morning and Alyeska shut down the pipeline at about 9 a.m., Egan said.

"There's no visible oil on the tundra," Egan said. "We believe it's all inside that casing."

While Alyeska staff believe the leak is contained, Egan said, they wouldn't know for sure if it had escaped that concrete structure until crews had a chance to excavate around the pipe. Crews are working to determine how to fix the line and get the pipeline running, Egan said.

Alyeska is unsure when oil might start flowing, she said.

"We want to make sure that we aren't going to make the situation worse by restarting, so we're being very careful and methodical about that," Egan said.

BP is in the process of cutting off production at the fields it operates, said Steve Rinehart, Alaska spokesman for the oil company. It will take time for wells to be shut in and pipelines and other facilities to be freeze protected.

Normal production from the North Slope fields averages around 630,000 barrels a day of oil. A 5 percent production level would be about 31,500 barrels a day. The oil fields have limited storage capacity, and the production that occurs will go into storage while the trans-Alaska pipeline is shut off.

BP runs most of the oil fields on behalf of itself and the other leaseholders. Conoco Phillips and Pioneer Natural Resources also run fields. BP, Conoco and Exxon Mobil are the major producers on the North Slope.

Rinehart said it was unclear how long the pipeline shutdown would last.

The pipeline runs from the North Slope to a tanker port in Valdez. Pump Station 1 is at the beginning of the pipeline. Alyeska runs the pipeline for the five oil companies that own it: BP, Conoco, Exxon, Koch Industries and Chevron.

Deep-water drilling in the Gulf of Mexico could resume within weeks

2011-01-04T20:59:00.000-08:00

Path Clears for Deep-Water Drilling

By BEN CASSELMAN And DANIEL GILBERT
Deep-water drilling in the Gulf of Mexico could resume within weeks under a policy announced Monday by the Obama administration, which has come under increasing criticism from the oil industry and politicians in the region over the impact of the drilling halt.

Oil and gas exploration in the Gulf's deep waters has been stopped since May, when President Barack Obama announced a six-month drilling moratorium in the wake of the April explosion of the Deepwater Horizon drilling rig, which killed 11 workers and set off the worst offshore oil spill in U.S. history.

The administration lifted the ban in October—a month ahead of schedule—but hasn't issued any permits for new deep water oil wells.

On Monday, The Wall Street Journal reported that the delay has hurt both the oil industry, which has seen billions of dollars in projects put on hold, and the Gulf Coast's economy, which has been hit hard by the slowdown.

The administration said Monday that it would clear the path for 13 companies, including Chevron Corp. and Royal Dutch Shell PLC, to resume work on a handful of wells that were already approved and under way when the moratorium took effect. The 16 projects must still comply with strict new safety rules announced after the Deepwater Horizon disaster, but in most cases won't be subjected to new environmental reviews.

The announcement means that some drilling could resume in a matter of weeks, although the exact timing remains unclear. But the policy doesn't affect the more than a dozen permit requests that were pending when the moratorium took effect or have been filed since. Those must still undergo enhanced environmental reviews.

GE Bets on Deep Water Oil With $1.3 Billion Wellstream Bid Access thousands of business sources not available on the free web. Learn More Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement, the newly formed federal agency in charge of offshore drilling, said projects that were interrupted by the moratorium deserved special consideration.

"For those companies that were in the midst of operations at the time of the deep-water suspensions, today's notification is a significant step toward resuming their permitted activity," Mr. Bromwich said in a statement.

Oil companies in recent weeks had become increasingly pessimistic about a quick resumption of drilling in 2011, with some predicting that the wait would last into the second half of the year. On Monday, the industry praised the decision but said more details were needed.

"It appears to be a step in the right direction," Randall Luthi, president of the National Ocean Industries Association, a trade group, said in an interview. However, he said, "there are still major questions and some confusion among the companies about what is being required."

Elgie Holstein, a staff expert for the Environmental Defense Fund, an environmental group, said he didn't see any reason for projects halted by the moratorium to be treated as special cases. But he said the new policy was reasonable as long as regulators enforced the new safety and environmental rules. "I actually thought it was a balanced response," Mr. Holstein said. "It does relieve some of the pressure that the Gulf Coast has been feeling from an economic standpoint."

The administration has come under increasing pressure from Republicans and some Gulf Coast Democrats to allow drilling to resume. On Monday, lawmakers reacted cautiously to the announcement. Sen. Mary Landrieu, a Louisiana Democrat who has been a vocal critic of the administration's drilling policy, said some projects could still be thwarted.

"We need to know more about the conditions under which drilling will be allowed to resume and make sure those conditions don't actually undermine the intent," Ms. Landrieu said in a statement.

Doc Hastings, the Washington Republican who is incoming chairman of the House Natural Resources Committee, was also skeptical.

"Today's announcement by BOEMRE only ensures the possibility that previous drilling activity can resume at some point in the future if certain requirements are met," Rep. Hastings said in a statement. "The Obama administration can prove it's serious about resuming drilling in the Gulf by actually issuing permits and allowing people to return to work."

—Siobhan Hughes and Tennille Tracy contributed to this article.

Ethanol Idiocy Will Not Die

2010-12-14T09:56:00.000-08:00

When Al Gore drops an environmental fad, it has truly reached its expiration date.

By Rich Lowry

In his wisdom, the Goracle recently acknowledged what almost all disinterested observers concluded long ago: Ethanol is a fraud. It has no environmental benefits, and harmful side effects. The subsidies that support its use are an object lesson in the incorrigibility of Washington's gross special-interest politics. It is the monster that ate America's corn crop.

"It is not good policy to have these massive subsidies for first-generation ethanol," the former vice president and Noble Peace Prize recipient said, referring to corn-based ethanol. He called the fuel "a mistake," and confessed one reason he fell so hard for it is that he "had a certain fondness for the farmers in the state of Iowa." These farmers vote in the First in the Nation caucuses and practically insist that their favored presidential candidates drink ethanol at breakfast and hail it as the nectar of the gods.

Gore's ethanol apostasy is a symptom of a left-right coalition that has arisen to expose the former wonder fuel. (The Gore of old insisted that "the more we can make this home-grown fuel a successful, widely used product, the better off our farmers and our environment will be.") But common sense, even cross-ideological, bipartisan common sense with all the evidence on its side, is no match for Congress' boundless appetite for expensive favors for powerful lobbies and constituent groups.

Tom Harkin and Chuck Grassley, the Democratic and Republican senators from Iowa, stand at the doors of Congress declaring: Ethanol now, ethanol forever. They have graced the Obama-McConnell tax bargain with an extension of a tax credit for ethanol that costs about $6 billion a year, and with an extension of a tariff on ethanol imports. Ethanol is so uneconomical that Congress supports it three different ways -- with a mandate for its use, a tax credit to subsidize it and a tariff to keep out competitors. Rarely are so many levers of government used to prop up one woeful product.

During the last decade, ethanol enjoyed a good run as a notional part of the solution to global warming. Then, environmentalists began to realize it might actually increase greenhouse emissions. Ethanol releases less carbon dioxide per gallon than gasoline. Once the emissions necessary to convert land to corn production and then grow and process it are taken into account, though, ethanol doesn't look so green anymore.

So much corn -- about 40 percent of the US crop -- is feeding into the maw of government-created demand for the fuel that it could be increasing world-wide food prices. In short, in exchange for not reducing greenhouse emissions, ethanol reduces the availability of food to the poor.

The multiple layers of subsidization have their own perversity. Since there's already a mandate to blend ethanol into gasoline, the tax credit is giving away money for something that would happen anyway. Environmental groups say this pads the bottom line of Big Oil. Harry de Gorter of the free-market Cato Institute has a more complicated take -- the subsidy decreases the cost and therefore the price of gasoline, effectively subsidizing its consumption. Your Congress at work.

But who cares about the facts? Once we have fired up a vast machine that from cornfield to distilleries produces 38 million gallons of ethanol a day, it will be nearly impossible to turn it off. Too many people will have a vested interest in continuing the scam, and its supporters -- like Harkin and Grassley now -- will always argue that any change is too disruptive. We'll still be mandating ethanol long after the internal-combustion engine is obsolete.

The ethanol experience should counsel against blithely creating new government-supported industries on the basis of dubious promises of cost-free environmental benefits. Judging by the tax bargain, festooned with all manner of other green subsidies and credits, it's a lesson ignored. In Washington, the boondoggles may lose their luster, but they never die.

http://www.realclearpolitics.com/articles/2010/12/14/ethanol_idiocy_will_not_die_108241.html

Still hope for gas pipeline

2010-11-28T15:39:00.000-08:00

Study for DNR suggests future L48 gas prices will support gas from North Slope

Alan Bailey

Petroleum News

Amid current speculation about the future of the Alaska oil and gas industry, as oil production from the North Slope slows down and exploration drilling comes to a near standstill, it has become popular to add what some view as fading hopes for a future North Slope gas line to a general list of woes.

For, as the burgeoning development of plentiful supplies of so-called shale gas in the Lower 48 has caused a paradigm shift in the North American gas market, the price of Lower 48 gas has plummeted to levels below the projected transportation rates on a gas line from the Arctic, perhaps rendering the gas line uneconomic.

Objective analysis

In the interests of taking a rational look at the prospects for future Lower 48 gas prices, to replace worry-driven conjecture by objective analysis, the Alaska Department of Natural Resources commissioned consulting firm Black & Veatch to prepare a report on the future of North American gas prices in the context of the new shale gas revolution.
And the Black & Veatch analysts have found that, although there are major uncertainties around future North American gas markets, it is likely that gas prices in Alberta, Canada, will climb to somewhere between $5 and $7 per thousand cubic feet by 2020, with prices continuing to climb thereafter. And with a possible fee of $3.50 per thousand cubic feet for treating North Slope gas and carrying it by pipeline to Alberta, those gas prices could make a North Slope gas line viable, Antony Scott, a commercial analyst with Alaska’s Division of Oil and Gas, told Petroleum News Nov. 22.

DNR wanted an authoritative set of data, against which to benchmark the gas line project and had obtained funding from the Alaska Legislature for the Black & Veatch study, said Mark Myers, Alaska Gasline Inducement Act coordinator.

“This is a very robust study,” Myers said. “It’s like no other study we’ve seen out there in the literature.”

And Scott emphasized that the study tried to be unbiased in its views of future gas markets and, if anything, had underestimated the future cost and pricing of shale gas.

Technical breakthrough

Shale gas technology involves the extraction of natural gas from the impervious rocks where gas forms, rather than using the conventional approach of drilling into porous and permeable reservoir rocks that have trapped gas as it bubbles through subsurface rock strata. The use of high-tech horizontal drilling techniques that allow a well bore to pass for long distances through a shale gas horizon, coupled with the use of water and chemicals to fracture the rock, thus releasing the gas from the rock lattice, have been key enabling technologies in shale gas development.
The coupling of technical breakthroughs in shale gas production with the realization that vast areas of gas shale underlie various regions of the United States and Canada has triggered the shale gas revolution and caused a massive uptick in estimates of North American natural gas resources.

However, despite much hype about shale gas, with implications of vast gas supplies at rock-bottom prices, shale gas development still only has about a 10-year track record, with most of that record relating to one shale unit, the Barnett shale in Texas, Scott explained.

“It’s really important to recognize that outside of the Barnett we’re in extremely early days of the shale gas story,” Scott said.

But, after assessing various natural gas scenarios, the Black & Veatch analysts have concluded that shale gas production would figure large in any future North American natural gas supply situation.

“No matter what, there’s an awful lot of shale gas that is going to be relatively inexpensive to produce,” Scott said.

Price impact

The arrival of shale gas in the North American gas market, converting tightening production from conventional gas fields to a growing gas glut, caused gas prices that had climbed to levels approaching $8 per thousand cubic feet by 2008 to suddenly collapse, dropping to below $4 currently.
And the import of liquefied natural gas into the Lower 48, thought just a few years ago to be an inevitable growth industry as domestic supplies of natural gas decline, has now been pushed into the background.

“If you look at the price environment … it becomes hard to tell a story in which LNG finds an attractive home in North America,” Scott said.

Key drivers behind Black & Veatch’s view of future Lower 48 natural gas markets are the assumptions that the now-known abundant supplies of North American natural gas, coupled with an environmental preference for the use of gas rather than coal as a fuel, will push up the use of natural gas for electricity generation. On the other hand, while there are major uncertainties regarding future gas demand levels, there are also major uncertainties in estimates of the future costs of developing new shale gas resources.

For example, the supply of water for shale fracturing and the subsequent treatment and disposal of water produced from gas wells has represented a fairly modest cost element in the development of the Barnett shale, but will likely become a major cost factor in the development of shale gas in other basins.

Inconsistent data

But inconsistencies in the way in which finding and development costs for shale gas are reported make it difficult to assess whether those costs are compatible with current gas price levels, and Black & Veatch thinks that current prices may be artificially low.
“Current market prices for natural gas in North America may not provide adequate return for full development of shale resources in North America,” the Black & Veatch report says. “Significant levels of current shale production appear to be driven by requirements to drill to maintain acreage positions.”

Published shale gas finding and development costs in the Lower 48 range from $2.06 to $2.35 per thousand cubic feet, but these numbers do not appear to include factors such as land lease costs and water costs. Estimated costs of $3.25 to $4.25 per thousand cubic feet in western Canadian basins are likely nearer the full cost, although there are differences between cost reporting rules in Canada and the United States, Black & Veatch says.

And an examination of the production history of the Barnett shale provides some revealing insights into possible future shale-gas cost trends.

Essentially, Barnett shale production has seen a series of significant technical breakthroughs, each of which has caused a sudden jump in gas production. But the rate of increase in production has dropped back sharply after each technology-induced spike. And, contrary to popular belief, the cost of finding and developing additional volumes of Barnett shale gas appears to have increased rather than decreased over time.

Rising cost

The explanation for this conundrum seems to lie in the production characteristics of shale gas resources. In essence, a shale gas well achieves high initial production rates as the fractured shale rapidly releases its gas content. But, with the rock being relatively impermeable, that initial production rate drops off quite rapidly, requiring increasing effort to stimulate existing wells and the drilling of new well bores to sustain overall production levels.
The result is a production cost profile that curves upwards as more and more of the gas resource is accessed, until a law of diminishing returns places an upper cap on the total volume of gas that can be viably extracted from a particular shale gas resource, the Black & Veatch analysts concluded.

Recognizing the importance of individually considering the unique characteristics of each shale gas basin, the Black & Veatch analysts applied the upward curving cost model to each of the various U.S. and western Canada basins, to assess future gas production costs in different basin scenarios. Estimated water costs factored high in the distinctions between the scenarios — potential situations ranged from unlimited water access and the disposal of untreated water down wells, as for a Barnett shale development, to limits on water supplies and the need for the treatment of produced water, as would be required for developments in the Marcellus shale in Pennsylvania.

Additional costs, all subject to significant uncertainty and regional variation, include land access and government taxes.

Rising demand

But future demand for natural gas in North America should support the anticipated gradual rise in shale gas costs.
Black & Veatch has its own Lower 48 gas demand forecast that assumes gas demand for electricity generation will rise at an annual rate of 3.2 percent, with greenhouse gas regulation tending to drive the replacement of coal-fired generating capacity by gas-fired power plants. In 2010 the Energy Information Administration, apparently barred from considering potential changes in government energy policies, came up with a lower growth rate of 0.5 percent, on the assumption that there would be no future restrictions on greenhouse gas emissions.

And although the Black & Veatch projection of total demand from all uses of gas through to 2035 also exceeds the equivalent EIA projection, the Black & Veatch projection is “within the fairway” of several independent gas demand forecasts, Scott said.

“Power generation demand is going to be a really big story,” he said. “It’s going to matter a lot.”

Then, when it comes to the interplay between gas costs, gas demand and gas prices, the actual level of gas demand and the actual finding and development costs would appear to be the likely dominant future drivers of gas prices. And Black & Veatch assembled low, medium and high gas price scenarios, using a standard North American gas model to project, for each scenario, likely annual gas prices at different market hubs, together with likely annual production volumes from each shale gas basin, through to 2040.

Price scenarios

The low-price scenario assumes the relatively low EIA projection of future gas demand, together with low water costs; low finding and development cost escalation, along the lines of conventional gas fields; and modest tax rates. The medium-price scenario uses Black & Veatch’s shale-gas cost escalation model, together with Black & Veatch’s projection of future gas demand. The high-price scenario adds in increased environmental restrictions over access to shale gas resources, somewhat higher tax rates and relatively high water costs.
The low-price and high-price scenarios projected into 2020 result in the $5 to $7 per thousand cubic feet price range that may come into play in Canada at around the time when completion of a North Slope pipeline could be in the offing.

“Except in very extreme events we believe the Alaska (gas line) project — given what we know about the tariff structure today, the cost of producing gas at Prudhoe and Point Thomson — it looks like it should work,” Myers said.

http://www.petroleumnews.com

Cap-and-trade will not pass this Congress

2010-11-14T14:38:00.000-08:00

Ben Nelson: Cap-and-trade will not pass this Congress
By Michael O'Brien - 10/30/09 10:35 AM ET

A cap-and-trade bill to address climate change cannot pass the Congress this session, Sen. Ben Nelson (D-Neb.) claimed Friday.

Nelson, a centrist Democrat whose vote is key to leaders wielding its 60-vote majority in the Senate, said he and his constituents had not been sold on the cap-and-trade system proposed in House and Senate bills to address global warming.

"No," Nelson simply responded when asked if those cap-and-trade bills can pass through this Congress during an interview on CNBC.

"I haven't been able to sell that argument to my farmers, and I don't think they're going to buy it from anybody else," Nelson said. "I think at the end of the day, the people who turn the switch on at home will be disadvantaged."

The pessimistic assessment makes Nelson a thorn in the side of his party's leaders on climate change legislation, one of their top priorities, as they assiduously court his vote on another key proposal, healthcare reform.

On that issue, Nelson was reluctant to fully stand behind the Senate health bill as has currently been proposed, but said he is working to find a way to support the legislation.

"I don't know that we should conclude that some form of healthcare reform won't pass. I believe that some form will pass," he said. "I'm looking to find a way to vote for healthcare reform because we need it."

Source:
http://thehill.com/blogs/blog-briefing-room/news/65615-ben-nelson-cap-and-trade-will-not-pass-this-congress

Alaska Candidates: Oil is declining, so what do we do?

2010-10-02T15:12:00.000-07:00

Tim Bradner
adn.com Economy

When the debate topic turns to state economic policy in the governor's race, the first thing out of the chute is usually petroleum policy and oil taxes, and what we can do to stimulate this industry, which many fear is declining.
Oil is vital to Alaska. Royalties and oil taxes pay for 90 percent of the state budget, the Department of Revenue says. Overall, the industry supports about a third of Alaska's economy directly and indirectly, according to University of Alaska studies.
However, the trends in this vital industry are headed the wrong way. Production is declining, employment is down and new exploration may hit a record low this year.
Don't think a gas pipeline will bail us out, either. State revenues generated by gas will be very modest compared with oil and a pipeline is 10 years away, if then.
What do our governor candidates say about this? Sean Parnell, the incumbent, talks about expanding targeted tax credits for field work. His major opponent, Ethan Berkowitz, talks about negotiation of special fiscal terms for new fields as a way of inducing development.
Both ideas have merit and both are done in Alaska today on a more modest scale, and with success. But neither packs the punch to really turn this industry around. The big problem, which no major party candidate will talk about, is that Alaska's oil taxes are just too high, period.
Retired state economist Roger Marks has authored a new paper showing that Alaska's marginal oil tax rate, in essence the tax rate on profits from new investment, can exceed 80 percent. Alaska now has the dubious distinction of having one of the heaviest tax rates among major oil producing regions of the world, Marks says.
With production, drilling and jobs declining, is this where we want to be? I want to hear some discussion from candidates that we may have overshot in 2007 when we did major surgery on the state oil tax law and adopted a very aggressive tax formula. Do our politicians have the stomach to admit they possibly made a mistake? The proof of this is in the declining production and drilling. Only Ralph Samuels, a candidate in the Republican governor's primary, had the guts to talk about this.
Some legislators raised this in Juneau earlier this year, State Rep. Craig Johnson among them. Most lawmakers weren't interested in taking the issue on, however.
It's not that political leaders are clueless. In fact, our state has adopted some very innovative incentives with very generous investment tax credits for exploration and special royalty terms for development that have brought new companies here, most recently Apache Oil.
These help, particularly for small independent companies, but the problem is that the high overall tax rate really dampens the economics of major exploration projects, the very high-cost, high-risk ventures aimed at making really big discoveries. These are the kind that can really turn things around.
When exploration managers model their risk/reward balance with a new exploration project, for example in a high-cost, remote area, they seek a balance between the small chance they could make a very profitable find and the high probability of failure. The high state tax on a profitable discovery skews this balance, in that if the company wins its gamble the state takes almost all the gain, as Roger Marks shows. The state's current drilling incentives help ease the risk a bit but not enough to overcome the disadvantage of the high tax rate.
We need more discussion of this. Gov. Parnell says he likes targeted investment tax credits because no credit occurs unless the investment is made. He worries that there is no guarantee investment dollars will follow if a general tax reduction is made. Parnell's challenger, Berkowitz, basically follows a similar safe strategy: Unless a company agrees to invest in a negotiated deal, no fiscal agreement occurs.
Again, nothing is wrong with these tried-and-true strategies but they're too cautious. We need something more daring to turn things around. The Legislature had real guts last session in offering up a radical incentive for new drilling in Cook Inlet, a state offer to pay most of the costs of the first three test wells drilled with a jack-up rig. As a result we now have new companies investing in the Inlet. We need something similar for the North Slope, our largest oil basis, and we should engage the discussion now.

Conoco to reassess Alaska gas pipeline

2010-09-28T21:50:00.000-07:00

According to London's Financial Times, ConocoPhillips' chief executive Jim Mulva said recently that the company would reassess the economics of the Denali project, a $30 billion gas pipeline from Alaska to Alberta it is considering building along with partner BP. The reconsideration is coming because a glut of natural gas in North America, being driven by unconventional shale gas plays, is keeping forecast commodity prices low. The current price is so low that Conoco has even shut in some of its North American gas wells (as have other companies). Mulva candidly explained the decision: "We’d rather keep it in the ground for when it will have a greater financial impact.” The report doesn't mention whether or not that statement applies to Alaska's natural gas as well as the shut-in wells, but read much more, here. Alaska Beat thinks it's worth noting that the industry pretty much agrees that gas prices will likely stay low in the short term, but there has been quite a bit of uncertainty over what they would do in the long term. At the very least, Mulva's comments and Conoco's plans to reevaluate Denali's particulars indicate that doubts over the long-term price of gas are coming into greater focus and are significant enough to attend to.

Read More

No timeline for AK

2010-09-12T15:09:00.000-07:00

Salazar says he needs confidence in safety before allowing OCS drilling

By Alan Bailey
Petroleum News
The Department of the Interior will not decide whether to allow exploration drilling for oil and gas in the Alaska Arctic outer continental shelf until it has completed a review of safety issues relating to offshore drilling activities, Interior Secretary Ken Salazar told a press conference in Anchorage on Sept. 3.
The briefing came at the end of a 48-hour visit to Alaska by Salazar and Deputy Interior Secretary David Hayes to meet with Alaska communities, energy industry officials and others, and to view areas of the state impacted or potentially impacted by oil and gas development.

Prohibited Shell drilling
Following the Deepwater Horizon disaster in the Gulf of Mexico, Interior prohibited Shell from proceeding with a planned 2010 drilling program in the Beaufort and Chukchi seas — the company now hopes to carry out that program in the summer of 2011. But, although Interior is aware that Shell needs to know in late 2010 or early 2011 whether it will be allowed to drill in 2011 to give the company sufficient time to mobilize its drilling fleet, Interior cannot make specific time commitments on a decision whether to authorize the drilling, Salazar said.

“I put those exploration plans on hold this year until we learn more from the experience that we’ve had dealing with the Macondo well in the Gulf of Mexico,” Salazar said. “Until we are confident that drilling can be conducted (safely) in the Chukchi and Beaufort seas we will not be allowing that program to go forward.”
Much will depend on the outcome of a report on offshore drilling that Michael Bromwich, the new director of the Bureau of Ocean Energy Management, Regulation and Enforcement, is preparing, and on the results of a Marine Board investigation of the Deepwater Horizon disaster, as well as on a pending Deepwater Horizon report from the National Academy of Engineering, Salazar said. Bromwich has been traveling around the United States gathering input for his report, which he anticipates delivering to Salazar by Oct. 31 at the latest.
“It’s a dynamic situation and we will make our decisions based on information when it comes forward,” Salazar said.

Three questions
Salazar said that the Deepwater Horizon disaster had raised three central questions for the United States when it comes to offshore oil drilling: workplace safety, the ability to contain oil from an out-of-control well and the feasibility of conducting an adequate response to an oil spill.
With regard to the issue of workplace safety, Interior is issuing new safety-related regulations that address questions such as blowout preventer requirements; well cementing and casing standards; and several other issues.
“There’s a bucket of issues around drilling safety and worker safety that we’re looking at,” Salazar said.
And when it comes to containing oil from a subsea well blowout, multiple failed efforts to capture oil from the Macondo well, including a failed containment dome, a failed “top kill” and a failed “junk kill,” illustrated the difficulty of dealing with a subsea blowout, even for one of the largest companies in the world, Salazar said.
“It is something which we will address before we allow drilling to continue,” Salazar said, while also commenting that Shell and the oil industry are trying to deal with this issue.
In addition, BP’s Gulf of Mexico oil spill response plans, despite being specified for a larger oil flow than that from the Macondo well, had proved inadequate, resulting in 1,200 miles of Gulf of Mexico coastline being impacted by oil and in damage to natural resources, Salazar said.
“And so one of the major questions that we are facing is what will we require of companies with respect to having an adequate spill response plan, and that question is very applicable to the Arctic Circle area,” Salazar said. “What happens if you have an oil spill in the Chukchi and Beaufort? How is it going to be contained?”

Moratorium applies in Alaska
The question of whether drilling on Alaska’s Arctic outer continental shelf is subject to a six-month drilling moratorium imposed by the U.S. Department of the Interior following the Deepwater Horizon disaster has been a subject of confusion and, at times, acrimonious debate since imposition of the OCS moratorium in May.
“The moratorium does in fact apply to Alaska,” Salazar said, contradicting a Nov. 26 statement by Bromwich that there “is not a moratorium per se in Alaska.”
Salazar said that he is applying the moratorium in Alaska because the three central questions over OCS drilling apply as much in the context of Arctic offshore drilling as they do in the Gulf of Mexico.
The moratorium imposed in May applied only to water depths greater than 500 feet and did not make any mention of the Arctic OCS, where the waters in areas of oil and gas interest are substantially shallower than that 500-foot limit. But Salazar said that he had notified Shell that Interior would not issue drilling permits for Shell’s 2010 program and that he viewed this de facto moratorium as, in effect, an extension of the deepwater moratorium.

Applied differently“The moratorium on the Arctic essentially is imposed in a different way. … I withheld the (drilling) authorization because of the fact that that some of the same questions that I am looking at in the Gulf of Mexico are central to the question of whether we allow an exploration well,” Salazar said. “If you look at the Chukchi, nothing or very little is known about the reservoir pressures that would be encountered. And if you look at the Chukchi you know that it will be very difficult to mount the kind of oil spill response that has been mounted in the Gulf of Mexico.”
On July 12 Interior issued a new drilling moratorium, replacing the May moratorium and banning all OCS drilling done from a floating drilling facility using a subsea blowout preventer. Again, the moratorium did not mention the Arctic and Bromwich, in his Aug. 26 statement, emphasized that the moratorium applied to specific equipment usage, rather than water depths or geographic locations.
But Shell’s planned Arctic drilling, using a drilling vessel and blowout preventers in well cellars in the seafloor, would presumably have been banned under the terms of the July 12 moratorium.

Court injunction
However, a court injunction actually applies to the drilling moratorium as a consequence of an appeal by several Gulf of Mexico oil service companies against the original May drilling ban. In June a judge in the Louisiana District Court ordered the injunction, saying that Interior’s application of a blanket moratorium on all deepwater drilling on the OCS would likely be viewed by the court as “arbitrary and capricious.” And on Sept. 1 the court threw out a claim by Interior that the July 12 moratorium had rendered moot the appeal case.
The case has now gone back to the Court of Appeals for the 5th Circuit, where Interior had appealed the injunction.
But, as far as the Alaska is concerned, the injunction really is in practice moot, since at this late stage in the annual open water season there is no possibility of anyone drilling for oil in the U.S. Arctic OCS this year.
The real question is whether an Arctic drilling moratorium, de facto or otherwise, will apply in the summer of 2011.
Wednesday, In the lead testimony, it was said, "Secretary Salazar has created an imperial throne of his administrative position. He has not acted in response to the law but – in Plato’s words – has attempted to make the law subject to his own authority. Your clear-headed recommendation could help set the Interior Department back on a steady course consistent with the rule of law, respectful of due process and serving the interest of the American public.

I am advising you tonight –via several bullet comments—under your second mission of considering ‘economic consequences’ of the Department’s decisions.
• The Secretary’s moratorium applied to deepwater development. Yet, without public notice or notice to affected parties he told the Senate Appropriations Committee on June 23 that the Moratorium did apply to Alaska. Just like that. No due process. Done on his own authority. He repeated his verbal extension of the moratoria last week while he was in Anchorage. He said he had other reasons than ‘deepwater concerns’ for applying the moratorium on his own authority to Alaska. He said he had applied this moratorium to Alaska on his own authority by causing various approvals to be withheld.
• The Secretary’s blunt use of power under the authority of his own word without notice or due process has significantly harmed Lessees, the State of Alaska and the people of the state. Chukchi and Beaufort Sea exploration was on course for his approval early in the year, following several years of preparation by exploration companies and the expenditure of billions of dollars. The Secretary’s actions have cost companies hundreds of millions or billions of dollars in delays and lost opportunities. His actions have endangered the economic survival of the State, dependent as it is on declining throughput of the Trans Alaska Pipeline--waiting for new volumes of OCS or ANWR or National Petroleum Reserve-Alaska throughput. His actions have erased job opportunities this very summer for hundreds of Alaskan citizens."

BP Doug Suttles Tours the Oil Spill Site

2010-08-08T13:27:00.000-07:00

Doug Suttles, Chief Operating Officer, BP Exploration and Production, returns to the site of the oil spill to see the progress that has been made in the fight against the oil spill. "The things people have done here are mind-boggling." To learn more about BP's response in the Gulf of Mexico, visit http://bp.com/gulfofmexico

Static Kill Overview

2010-08-08T13:22:00.000-07:00

In this video, BP Sr VP Kent Wells explains key differences between the Top Kill, which was unsuccessful, and the Static Kill procedure proposed to kill the MC252. Wells covers both the Static Kill and Bottom Kill procedures being planned for killing and cementing the MC252.

Static Kill Demonstration

2010-08-03T21:36:00.000-07:00

A demonstration shows what engineers will attempt on the temporarily-capped BP well.

Static Kill Injectivity Testing Commences on MC252 Well

2010-08-03T21:04:00.000-07:00

Release date: 03 August 2010
HOUSTON - BP started injectivity testing today at 19:05 (UK) and 13:05 (CDT) in advance of static kill operations. Based on the results of the injectivity test, pumping of drilling mud for the static kill could commence later today, following which a decision on the best way to cement the well will be determined. All operations are being carried out with the guidance and approval of the National Incident Commander. The aim of these procedures is to assist with the strategy to kill and isolate the well, and will complement the upcoming relief well operation.
The relief well remains the ultimate solution to kill and permanently cement the well. The first relief well, which started May 2, has set its final 9 7/8-inch casing. Operations on the relief wells are suspended during static kill operations. Depending upon weather conditions, mid-August is the current estimate of the most likely date by which the first relief well will intercept the Macondo well annulus, and kill and cement operations commenced.

Read More

A Common Practice in Photo Production Made an Integrity Issue By Media

2010-07-23T12:08:00.000-07:00

BP announces oil leak has stopped

2010-07-15T23:25:00.000-07:00

BP announces oil leak has stopped in Gulf of Mexico for first time in 3 months (see live video)
Cindy Adams - US Headlines Examiner

BP oil spill update: Testing on new cap begins, spill should be contained by July 19

BP announced Thursday that oil has stopped leaking into the Gulf of Mexico for the first time since its rig exploded on April 20.

Undersea robots worked through the night on a leak that was found after BP began testing its new well cap Wednesday afternoon. The test was conducted by turning off pipes that send some of the oil to surface vessels so the full force of the oil was centered on the cap. After two of the three valves on the cap had been closed, it was determined that one was still leaking.

BP PLC Vice President, Kent Wells, said the new leak was repaired by replacing the assembly, or choke line, on the suspect pipe.

ABC News reports that the cap remains a temporary fix and the leak will only be permanently quelled after two relief wells that are currently being drilled can reach the leak and permanently plug it with cement and heavy drilling mud. BP has stated this will likely occur mid-August.

To see live video of the well and the repairs being done, click here.

Now that the leaky pipe has been replaced, BP will have to begin retesting by letting additional oil leak out of the cap temporarily and once again turning off a pipe that is sending oil to a surface ship, in order to determine whether the new cap can withstand the full force of the erupting oil.
Read More

New cap, ships could contain Gulf leak by Monday

2010-07-09T13:36:00.000-07:00

By TOM BREEN
Associated Press Writer

NEW ORLEANS (AP) -- The federal official leading the Gulf oil spill cleanup said Friday a new containment cap and an additional ship collecting oil could effectively contain the spill in the next three days.

The work to replace a leaky containment cap on the well head with a tighter one will begin Saturday, National Incident Commander Thad Allen said. At the same time, a ship connecting to a different part of the leak is expected to come online Sunday.

Oil will flow unimpeded into the Gulf during the cap switch for at least part of the weekend.

If all goes according to plan, the combination of the cap and the new vessel could collect all the leaking oil by Monday, stopping it from escaping into the Gulf of Mexico for the first time since April 20.

"I use the word 'contained,'" Allen said. "'Stop' is when we put the plug in down below."

Work continues on what officials hope will be the final plugging of the well - drilling on two relief wells through which mud and cement will be pumped to stop the leak once and for all. That's expected to happen sometime in mid-August.

The new containment cap is expected to form a better seal over the well head, to allow more of the oil to be collected and sent up to ships on the surface for collection or burning.

"Technically it's pretty achievable," Allen said. He said if the new cap can't be placed on the well, the old cap will be put back and there are multiple backup caps available in case any one cap fails.

The new, tighter cap should be in place early Monday. Allen said the ship Helix Producer, which is to be hooked to a different part of the leaking well - lower than the new cap - will start collecting oil Sunday and be fully operational Tuesday. He has previously said that the full system should be able to collect 60,000 to 80,000 barrels a day.

The schedule for both efforts has been accelerated to take advantage of what could be a rare window of good weather. The hookup of the Helix Producer was delayed this week by poor weather. But an unexpected break in weather patterns creating choppy seas provides a window of a week or so with waves of only 1 or 2 feet.

"Everybody agrees we got the weather to do what we need," he said.

Containing the leak is not the same as stopping the environmental catastrophe that began April 20 when the Deepwater Horizon oil rig exploded, killing 11 workers.

The relief wells remain the best option for a final plug to the leak, at which point cleanup and restoration become the main focus.

Though officials said the first relief well could be finished by the end of July, weeks ahead of schedule, they are quick to point out that such an optimistic timetable would require ideal conditions every step of the way.

That is something that has rarely happened since the leak began.

Costner's Centrifuge

2010-06-24T11:03:00.000-07:00

Kevin Costner Ocean Therapy Press Conference

Ocean Therapy Solutions and BP news conference and update on the ongoing efforts to deploy Ocean Therapy's oil separating centrifuge devices in the Gulf of Mexico to clean up the Horizon oil spill.

BP has created this YouTube channel to engage the public in an informative conversation and dialogue about our efforts associated with the oil spill in the Gulf of Mexico. We want our page to be an appropriate forum for everyone. For more information on our Commenting Policy, please see the Latest News section on our main page: http://youtube.com/bp.

http://www.youtube.com/user/BPplc#p/u/8/tlse59oyY3A

For the latest updates and to join the conversation on the Gulf of Mexico oil spill, please visit our Facebook Page: www.facebook.com/BPAmerica.

For more information, please visit: www.bp.com.

BP: A significant step forward

2010-06-05T00:07:00.000-07:00

Adm. Thad Allen calls it "a significant step forward"; BP has successfully sliced off the top of a damaged riser.

'Top kill' method 'slows BP oil leak' in Gulf of Mexico

2010-05-27T09:50:00.000-07:00

Oil has been gushing from the well for the past five weeks BP has slowed the flow of oil and gas from a ruptured well into the Gulf of Mexico, a US official told local media.

The company's "top kill" effort has "stabilised the wellhead", Coast Guard commander Admiral Thad Allen said.

But he cautioned it was too early to declare success. This is the first step in BP's plan to seal the well for good.

'Low pressure'
Footage from BP's underwater camera
Adm Allen told US media the "top kill" procedure, which began on Wednesday, has pumped enough drilling fluid to block some of the oil and gas escaping from the well.

Adm Allen told National Public Radio that BP engineers had "been able to force mud down and not allow any hydrocarbons to come up."

It was the first positive official assessment of BP's latest attempt to plug the well, after previous efforts failed.

BP shares were up more than 5% in London trading following the announcement.

BP has not yet commented in detail on the situation, saying merely that its "subsea efforts [were] advancing on several fronts".

Live Feed Ocean Floor from BP

2010-05-27T09:22:00.000-07:00

BP: Top Kill Operation - Animated - May 26, 2010

2010-05-27T08:55:00.000-07:00

Animation showing the Top Kill process designed to stop the flow of oil from the well. Heavy "kill mud" is pumped down a drill pipe, then through hoses that go through the manifold on the seafloor. The mud then moves through another set of hoses attached to the Deepwater Horizon blow-out preventer's choke and kill lines, then into the well.
Animation showing the Top Kill process designed to stop the flow of oil from the well. Heavy "kill mud" is pumped down a drill pipe, then through hoses that go through the manifold on the seafloor. The mud then moves through another set of hoses attached to the Deepwater Horizon blow-out preventer's choke and kill lines, then into the well.
Click here to see animation on YouTube.

Deepwater Horizon Response

Kevin Costner oil spill cleanup idea interests BP

2010-05-23T16:07:00.000-07:00

By Mark Guarino

Film star Kevin Costner is joining the ranks of scientists, engineers, and lawmakers in an international effort to figure out how to contain and clean up oil streaming into the Gulf of Mexico at the rate of 210,000 gallons a day.
Mr. Costner appeared in New Orleans last week to demonstrate a $24 million oil extraction device he is pitching to BP and Coast Guard officials. Costner says the device will clean oil from the water at a rate of 97 percent. BP Chief Operating Officer Doug Suttles said Wednesday that his team will test the device next week.
Costner's involvement in helping solve oil spill crises is not new. The 1989 Exxon Valdez oil spill disaster in Alaska motivated the actor to help fund a consortium of scientists to develop technology that mitigates oil-infected water before it hits the coast. The technology is ready to combat the BP spill, he told reporters last week.
"It's not anymore about talk," Costner told WWL-TV in New Orleans. "It's about doing the walk, and that phrase was probably invented down here."
Costner's company, Ocean Therapy Solutions, provides multiple machines designed to address spills of different sizes. The largest can clean as many as 200 gallons per minute, Costner said. The company reports it has 20 such machines ready to be employed.
"The machines are basically sophisticated centrifuge devices that can handle a huge volume of water and separate [the oil] at unprecedented rates," Ocean Therapy Solutions CEO John Houghtaling said last week.

Costner said the machines work by drawing in the infested water where it then breaks it down, allowing the oil to discharge through a separate pipe. His audience, a gathering of local parish presidents, appeared eager to get the device to the Gulf.
"To me, this is a major tool for a tool box that should be tested," said Craig Taffaro, St. Bernard Parish president.
Besides saying that Costner's device will be tested next week, BP's Suttles said his company and the Coast Guard have been collecting ideas from the public since Day One of the crisis. The command center receives 100 ideas a day, Suttles said.
Costner said his decision to fund the technology was a result of needing to use the wealth he was "lucky" to accumulate instead of "piling it" for no real purpose.
"We all make decisions about what we want to be a part of. I'm just one person focusing on a specific problem and throwing a little resources to a lot of talent and manpower ... to come up with what is a [solution]," he said.

Read More

Gulf Spill: The Blame

2010-05-19T16:10:00.000-07:00

May 19, 2010: While politicians and environmental groups step up to posture in the face of the Deep Water Horizon disaster, the company who is taking the brunt of the criticism has not been afforded the right to a fair hearing of facts in the press.

Since the well blew in the Gulf of Mexico on April 20th, several things have happened that warrant a clear and concise explanation.

In what stands to be one of the biggest oil spills in the history of the United States, the cause of the spill now appears to be an unauthorized modification of the blow out prevention (BOP) valve.

The Blame

BP's Deep Water Horizon oil rig exploded and sank off the cost of Louisiana last month. Eleven rig workers are missing, which was operated by Swiss-based Transocean Ltd, the largest independent driller in the world.

Meanwhile, the BOP failed to stop the flow of oil as it should have after the explosion and allowed oil to pour into the Gulf of Mexico. Fingers are being pointed at BP, even though Transocean was the sub-contractor.

Eventually, BP will be exonerated. But first we will all have to play a game of cover our asses.

From the subcontractor who reportedly modified the BOP without the knowledge or permission of BP, to the government regulators who okayed the modified BOP, to the Obama administration who wants to look tough on BP even thought they had no culpability, everyone is running for cover.

After the BOP was installed, the modifications made after the fact are assumed to have prevented the part from operating properly.

These modifications were discovered by remote operated vehicles whose pictures transmitted to engineers trying to find out why the BOP didn't activate, showed the part had been altered.

Government Response

Meanwhile, the Federal Government responded by splitting up the regulating and revenue collecting functions of the Minerals Management Agency, to as President Obama described, break up the cozy relationship between regulators and the oil industry.

However, the action to split up the functions draws attention to just who was responsible for permitting the BOP that failed to work. Could it have been that an MMS inspector didn't properly follow through with the BOP test monitoring?

BP's Safety Record

Much has been written since the well blew four weeks ago about BP's safety record. But that says nothing about the company today and the focus on safety they have made the last two years.

While many press accounts recall the explosion at BP's Texas City refinery in 2005, and the spill at Prudhoe Bay a year later, those incidents occurred before BP's current CEO Tony Hayward assumed control.

Since the spill, Hayward has been a visible point man for BP. He wasted no time in appearing on major network news shows to describe the situation on the ground. He has mobilized 2,500 workers to the site, including several from Anchorage, and he has accepted full responsibility for the disaster.

This shouldn't be surprising. After all it was Hayward, who in 2005 won accolades from BP employees for speaking out against the way the company was handling the Texas City disaster, criticizing his bosses for "a leadership style that is too directive and doesn't listen sufficiently well."

The Politics

The politics are bare knuckle.

The spill has given fodder to environmentalist to once again raise a ruckus about offshore oil & gas drilling. Congressmen, one right after another, attempting to look tough, are demanding answers from BP they already have received. And the White House continues to posture on the real issue which is; energy supplies come at a risk.

But the fact is the Gulf of Mexico accounts for almost a third of America's oil production and has been where most of the new finds have been for oil companies.

Furthermore, before the April 20th disaster, there hadn't been a leak from an offshore well in 40 years.

As the Economist recently opined, "If Americans do not want to hand more money and clout to the likes of Iran, Russia and Venezuela, the argument runs, they should not curb offshore drilling."

The impacts have reached Alaska. The spill has set off another round of opposition to offshore drilling in Alaska and age old worries about a spill in the Arctic conditions. But these concerns are unfounded.

Currently, as a result of the 1989 Exxon Valdez spill, Alaska has the toughest regulations in the world. Companies like Shell Oil who are exploring off Alaska's shores are required to abide by and held to a much higher standard of prevention and response then anywhere on the globe.

The more and more you hear of the Deep Water Horizon tragedy the more you'll learn that it was a careless contractor who set the stage for the disaster. And as I said, at the end of the day BP will be exonerated in my opinion.

Let's hope for the future of our nation's energy security we don't use one bad incident in 40 years as an excuse to stop offshore drilling.

And let's hope we get bp: beyond posturing.

Andrew Halcro's blog

Lowering the Cofferdam

2010-05-16T10:33:00.000-07:00

Obama scolds BP

2010-05-14T18:57:00.000-07:00

President Obama vented his frustration Friday during a statement to the press he issued from the White House Rose Garden.

Flanked by cabinet members and other administration officials overseeing the federal response to the blow-out, he lit into industry representatives who appeared at congressional hearings on the spill earlier this week.

"I did not appreciate what I consider to be a ridiculous spectacle during congressional hearings into this matter," he said. "You had executives of BP and Transocean and Halliburton falling over each other to point the finger of blame at somebody else."

Nor did federal regulators escape the tongue-lashing. The president criticized what he termed "a cozy relationship" between oil companies and federal regulators in which "permits were too often issued based on little more than assurances of safety from oil companies" and oil companies exploited loopholes that "allowed some oil companies to bypass some critical environmental reviews," Obama said.

Part of the challenge – and the frustration – in coping with the blow-out lies in determining just how much oil the submarine gusher is releasing.

Official estimates from the federal government and BP, which owns the oil lease the Deepwater Horizon was working, place the leak rate at some 5,000 barrels (210,000 gallons) of oil a day. That alone is has been enough to trigger a regional emergency response.

But independent experts say the leak rate is likely to be much larger.

A week ago, Florida State University marine scientist Ian McDonald put the leak rate at around 25,000 barrels a day.

And in a report Friday morning, National Public Radio cited estimates from three independent scientists who say at least 50,000 barrels of oil a day are flowing into the Gulf waters. That would imply that the Deepwater Horizon disaster could be releasing at least the equivalent of one Exxon Valdez spill every five days.

These estimates have wide margins of error, cautions Timothy Crone, a scientist at Columbia University's Lamont-Doherty Earth Observatory in Palisades, N.Y.

In an email exchange, Dr. Crone, one of the three scientists NPR contacted, noted that his approach honed on estimating the material spewing from deep-sea hydrothermal vents.

He says that videos of the blow-out taken by robotic cameras at the well head lack the detail needed for more precise estimates of the flow. Moreover, the material emerging from the well head is a mix of methane, mud, and oil.

Taking all that into account, he puts the flow rate at roughly 50,000 barrels of oil a day.

"My numbers should be viewed with caution," he warns, but adds, "the flows are almost certainly higher than 5,000 barrels a day."

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Hayward applauds President's statement on oil spill
Release Date: 02 May 2010
“The US government leadership here has been excellent since day one. I agree with the President that the top priority right now is to stop the leak and mitigate the damage. I reiterated my commitment to the White House today that BP will do anything and everything we can to stop the leak, attack the spill off shore, and protect the shorelines of the Gulf Coast. We appreciate the tireless efforts of the many federal, state and local responders and the volunteers, men and women who have worked tirelessly since the date of the accident to mitigate the damage. Our teams are working hand in hand and we look forward to hearing more recommendations for action from the President’s visit today.”

-Tony Hayward, from Houma, Louisiana

Hayward Comments on President Obama's Statement
Release Date: 14 May 2010
Tony Hayward, BP Group Chief Executive, today said:

“We absolutely understand and share President Obama’s sense of urgency over the length of time this complex task is taking. We want to thank the President and his administration for their ongoing engagement in this effort.

“BP - working closely with scientists and engineers from across the whole oil industry, from government agencies and departments, and with local officials along the Gulf Coast - is focused on doing everything in our power to stop the flow of oil, remove it from the surface, and protect the shoreline. We are working with state and community leaders to mitigate the impact on the lives and livelihoods of those who have been affected.

“And while we continue in these efforts, we are participating fully in investigations that will provide valuable lessons about how to prevent future incidents of this nature.”

Riser Insertion Tube

2010-05-12T15:21:00.000-07:00

Graphic depicting the Riser Insertion Tube method to contain oil leaking from the riser of the Deepwater Horizon Well. This technique is one of several that technicians and engineers have developed to slow or stop oil from leaking into the Gulf of Mexico.

For information about the response effort, visit www.deepwaterhorizonresponse.com.

BP says Gulf blow out preventer had been modified

2010-05-12T10:34:00.000-07:00

WASHINGTON, May 11 (Reuters) - The blow-out preventer that was supposed to help protect against the oil spill disaster in the Gulf of Mexico had been modified, BP America Inc (BP.L: Quote, Profile, Research) President Lamar McKay told a senate panel on Tuesday.
"I have reason to believe the BOP had been modified," McKay told the Senate Committee on Energy and Natural Resource, which held its first hearing into the causes of the spill that killed 11 workers and caused a leak that is still releasing thousands of barrels of oil per day.

Steven Newman, the president and chief executive of Transocean Ltd (RIGN.S: Quote, Profile, Research) said the blowout preventer had been modified in 2005 at the request of BP.
Read More

WASHINGTON – Rep. Henry Waxman says that his committee's investigation into the Gulf oil spill reveals that a key safety device, the blowout preventer, had a leak in a crucial hydraulic system.

The California Democrat said in a hearing Wednesday that the investigation also discovered that the well had failed a negative pressure test just hours before the April 20 explosion.

He cited BP documents received by the Energy and Commerce Committee that showed there was a breach in the well integrity that allowed methane gas and possibly other hydrocarbons to enter the well.

Gulf of Mexico Oil Spill Response

2010-05-07T09:59:00.000-07:00

Keep Up with the latest progress on the response efforts in the gulf.

Deep Water Horizon Oil Spill Response

BP stops one of three Deepwater Horizon oil leaks

2010-05-05T13:36:00.000-07:00

"We made good progress yesterday, including the cap on the drill pipe," BP spokesman John Curry wrote in an email, referring to shutting off one of the leaks.

Doug Suttles, BP chief operating officer, had said on Tuesday that although the undersea repair work on the riser pipe was expected to plug one of the three leaks, "I don't believe that will change the total amount leaking".

US authorities and BP are racing to try to contain a huge oil slick from the ruptured well that is threatening four Gulf coastal states.

BP stems one of three Deepwater Horizon oil leaks, US coastguard saysWork unlikely to reduce overall oil flow into the Gulf of Mexico, but will ease efforts to contain the slick

Boats with oil booms try to contain oil spilled from the explosion and collapse of the Deepwater Horizon rig in the Gulf of Mexico Photograph: Gerald Herbert/AP

The US coastguard says BP has managed to cap one of three leaks from its stricken deepwater oil well, but the work is not expected to reduce the overall flow of oil into the Gulf of Mexico.

The work should reduce the number of leak points that need to be fixed on the ocean floor, making it easier to drop a containment dome to bottle up the disastrous oil spill threatening sealife and livelihoods along the Gulf Coast.

Since an explosion on 20 April, 50 miles off the coast of Louisiana, the Deepwater Horizon well has been spewing at least 800,000 litres a day.

Experts say the best short-term solution is to drop a specially built giant concrete-and-steel box designed to siphon the oil away over the breach.

Crews for Wild Well Control, a contractor, are putting the finishing touches on the 100-ton containment dome, which is expected to be taken to the leak site today. John Curry, a BP spokesman, said it would be deployed on the seabed by tomorrow.

It's the latest attempt by BP engineers to stem the oil from the rig, which killed 11 workers when it exploded. It sank two days later, and oil started pouring into the Gulf. BP is in charge of the cleanup and President Barack Obamasays the company is responsible for the costs.

Officials said that capping one of the three leaks was a step towards stemming the flow. "It doesn't lessen the flow, it just simplifies the number of leak points they have to address," David Mosley, a coastguard petty officer 1st class, said.

A rainbow sheen of oil has reached land in parts of Louisiana, but the gooey rafts of coagulated crude have yet to come ashore in most places. Forecasts showed the oil wasn't expected to come ashore until at least tomorrow.

"It's a gift of a little bit of time, I'm not resting," said Mary Landry, a US coastguard rear admiral.

In their worst-case scenario, BP executives told members of a congressional committee that up to 9.5m litres a day could spill if the leaks worsened, though it would be more like 6.5m litres.

The worst oil spill in US history resulted from the 1989 grounding of the Exxon Valdez oil tanker in Alaska. It leaked nearly 11m gallons (41 million litres) of crude.

Containment domes have never been tried at this depth, about 5,000ft (1,500m) because of the extreme water pressure. The dome, if all goes well, could be fired up early next week to start funnelling the oil into a tanker.

It was not clear whether the equipment would work, said Bill Salvin, a BP spokesman. "What we do know is that we have done extensive engineering and modelling, and we believe this gives us the best chance to contain the oil, and that's very important to us."

Yesterday seas calmed allowing more conventional methods to contain the spill to get back on track as businesses and residents kept an eye on the ocean currents, wondering when the sheen washing ashore might turn into a heavier coating of oil. Crews put out more containment equipment and repaired some booms damaged in rough weather over the weekend. They also hoped to again try to burn some of the oil on the water's surface.

Chemical dispersants piped 1,500m to the main leak have significantly reduced the amount of oil coming to the surface, BP said. The company also hoped to shut off one of the smaller of three leaks, though it may not reduce the flow very much, said Doug Suttles, BP's chief operating officer.

From the air yesterday, the site of the Deepwater Horizon explosion looked similar to a week ago, except for the appearance of a massive rig brought in to drill a relief well to shut off the spewing oil. However, that would take months.

People along the Gulf Coast have spent weeks living with uncertainty, wondering where and when the oil may come ashore, ruining their beaches and their livelihoods.

The anxiety is so acute that some are seeing and smelling oil where there is none. And even though the dead turtles and jellyfish washing ashore along the Gulf of Mexico are clean, and scientists have yet to determine what killed them, many are sure the flow of crude is the culprit.

The rig was owned by Transocean. Some of the 115 surviving workers aboard when it exploded are suing the company and BP. In lawsuits filed yesterday, three workers say they were kept floating at sea for more than 10 hours, while the rig burned uncontrollably. They are seeking damages.

Guy Cantwell, a spokesman for Transocean, defended the company's response, saying 115 workers got off alive. Two wrongful death suits have also been filed.

Read More

A subcontractor Transocean reportedly modified the BOP without the knowledge or permission of BP

2010-05-01T10:34:00.000-07:00

Exclusive from Andrew Halcro

In what stands to be one of the biggest oil spills in the history of the United States, the possible cause of the spill now appears to be an unauthorized modification of the blow out prevention (BOP) valve.

Oil rig explosionBP's Deep Water Horizon oil rig exploded and sank off the cost of Louisiana last week. Eleven rig workers are missing, which was operated by Swiss-based Transocean Ltd, the largest independent driller in the world.

A subcontractor Transocean reportedly modified the BOP without the knowledge or permission of BP, to the government regulators who okayed the modified BOP, to the Obama administration who wants to look tough on BP even thought the company had no culpability, everyone but BP is running for cover.

New evidence shows BP will eventually be exonerated.

Read More

This document is also packed full of information concerning the blast aa well as pictures of the Horizon

PLAN B- When AGIA Fails

2010-03-21T19:27:00.000-07:00

There is no doubt that the long-desired pipeline to carry gas from Alaska, through Canada, to the Lower 48 -- the so-called "Big Line" -- is in significant trouble.

To be sure, the Parnell administration has attempted to convince Alaskans otherwise to justify the state government's continued $500 million subsidy of TransCanada's project under the Alaska Gasline Inducement Act. However, the observations of as diverse a group as the highly respected Potential Gas Committee, the federal Energy Information Administration and long-time and widely regarded consultant (sometimes to the Alaska government) Daniel Yergin clearly demonstrate the gravity of the situation.

In a November article in The Wall Street Journal that summarized the effects of what Yergin terms the shale gas "revolution," he concluded, "[a]t current levels of demand, the U.S. has about 90 years of proven and potential supply -- a number that is bound to go up as more and more shale gas is found." Against those numbers, is it realistic to think that producers will risk the $25 billion to $30 billion necessary to build an Arctic pipeline to attempt to penetrate an already oversupplied Lower 48 market? Not really.

So what happens to North Slope gas -- which is almost as important going forward to the Alaska economy as incentivizing continued development of Alaska oil -- if the Big Line fails (or to use the EIA's gentler term in a November study, if it is "significantly deferred")? Because the groundwork is in the process of being laid now, Alaskans should focus on -- and ask those who propose to lead them -- what is "Plan B?"

Three scenarios -- all led by various government components -- are materializing. The first two focus on other methods for developing a market for Alaska's North Slope gas. Oddly, the third scenario goes in reverse, and proposes steps that undermine monetizing Alaska's North Slope gas.

The two that develop a market for Alaska's gas are the Alaska Gasline Port Authority's Valdez liquefied natural gas project, which is the centerpiece of Bill Walker's campaign for governor, and the North Slope to Southcentral bullet line, most recently in the news as a result of Harry Noah's resignation from the Department of Natural Resources.

Of these, the bullet line clearly creates the best future for Alaska in a Plan B world.

Why is the bullet line the best? That is easy. The bullet line bundles a number of markets together in one project, and by doing so achieves the lowest cost for all users. It supplies gas to Fairbanks -- which needs a cleaner fuel to address the area's increasingly worrisome environmental issues. It brings gas to Southcentral -- which even the Parnell administration is now beginning to admit needs new gas supplies to offset declines in Cook Inlet production.

The Bullet line also creates the potential for a value-added industry in Alaska, such as the proposed, large scale gas-to-liquids project, which depends on the Cook Inlet's depleted oil and gas reservoirs to store the carbon dioxide produced from the process. The bullet line additionally brings a supply of gas to the Pebble Project, which because of the size of its demand for gas, would significantly reduce the transportation costs borne by other Southcentral consumers. Also, the bullet line provides a means for monetizing Alaska's North Slope gas on a large scale by moving it to tidewater (albeit the Cook Inlet), paving the way for an LNG export project.

By bringing all of these requirements together, the bullet line produces the lowest cost transportation option for all users, and, in doing so, creates the greatest potential that each project it touches clears its economic hurdles.

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So far, Parnell looks like Palin Lite

2010-01-17T23:53:00.000-08:00

I had high hopes for Sean Parnell when he took office last July. After Sarah Palin, it seemed a bright young governor who had a positive relationship with the oil and gas producers would be an improvement.

But so far, Parnell has looked more like Palin Lite, a charisma-free copy of his predecessor. He still has time and opportunity to redeem himself, notably if he kills that foolish attempt by Tom Irwin and Marty Rutherford to cancel the Point Thomson oil and gas leases held by Exxon and its partners.

It should be an easy decision. After all, if state lawyers get the Superior Court judge’s decision overturned and Natural Resources Commissioner Irwin’s attempt to cancel the leases is upheld, they could kill the gas pipeline. It really is as simple as that.

The state’s tussle with Exxon over development of Point Thomson goes back a long time. The company appeared to be dragging its feet on drilling and development for years, though there was no pipeline to take the gas away and the high-pressure field has tremendous engineering challenges, on which it spent many millions.

In 2006, Gov. Frank Murkowski decided to poke his finger in the corporate giant’s eye and moved to cancel the leases. Asked later why he did it, Murkowski said he wanted the Exxon people to come back with a better development plan and a firm commitment to carry it out. “And they did,” he said.

But Palin, Irwin, Rutherford and now Parnell have continued the fight and carried it to ridiculous extremes, putting Alaska’s economic future at great risk. Last summer, Irwin said he didn’t trust Exxon to fulfill its promises, so the commissioner’s uneasiness keeps the legal battle raging. He should try taking a Valium.

The gas pipeline is no sure thing by any means. And Point Thomson contains more than 8 trillion cubic feet of gas, a volume needed for pipeline viability. If those leases get tied up in a decades-long legal hassle — to ease Irwin’s worries — the gas could be nearly worthless by the time the mess gets untangled.

Irwin and his deputy Rutherford are both good people, but they have a doggedly negative attitude toward the North Slope producers that should disqualify them for their jobs. If they persist in the attempt to get the leases canceled, and Parnell goes along with it, this state may find itself back where it was at statehood in 1959, but without the bright prospects.

Idiotic public policy sometimes seems a way of life in Alaska. And that aimed at Exxon in retribution for the 1989 tanker disaster — plus the Palin-Irwin-Rutherford claim that Alaska didn’t get a big enough share of the North Slope pie — is classic dog-in-the-manger politics.

Oil money has funded this state’s government for two generations, Alaska did away with its state income tax 30 years ago and we have a free-money program that sends just about every living soul here a nice check every October.

State leaders came to terms with the companies exploring and developing the North Slope years ago. As a result, billions in investments were made, billions in taxes and royalties were collected. But now some of our leading lights want more. If this were 1898 and you tried that on a gold mining partner, you would be asking for a necktie party.

Sure, it’s politically incorrect in Alaska to say good things about Exxon. I don’t know any of the current bunch, but some of the finest people I’ve ever met were Exxon employees. That includes Otto Harrison, who headed up the Exxon Valdez cleanup; many of the engineers and managers who worked for him and those that helped build the trans-Alaska oil pipeline; and the late Max Nalley, who was the company’s public affairs manager for several years.

The list also includes my old hunting and fishing buddy, Hank Rosenthal. Hank was delivered to Alaska by the icebreaking tanker Manhattan, which reached Prudhoe Bay via the Northwest Passage. He was the public relations guy on the project. I was in public affairs at ARCO in those days and Rosenthal became my Exxon counterpart (actually the company was named Humble Oil & Refining in those days).

Hank and I both had statewide responsibilities and could always come up with a reason to meet with people in Unalaska when the geese were in at Cold Bay, Southeastern Alaska when the ducks were flooding in there, and in summer anywhere the salmon were running.

Hank left Exxon sometime in the 1970s and took my job at ARCO when I decided to bail out in 1980. (I gave him a heads-up before I told my boss I was quitting.) He came back to Alaska and married one of my favorite liberals, former Assemblywoman Heather Flynn. Hank fought in the Korean War and survived fighting at the Chosin Reservoir, but was killed in 2003 by a curb-jumping taxi while on vacation in Prague.

So don’t bad-mouth Exxon people around me, friend. Say what you want about Joe Hazelwood and the company’s lawyers, but there are a lot of good people at Exxon. I’ve known many of them.

If Sean Parnell and Tom Irwin don’t smarten up about Point Thomson and drop that stupid lawsuit, I just might say bad things about them.

* * *

I’m a humanitarian kind of guy. For instance, I think we should treat attempted undie-bomber Umar Farouk Abdulmutallab humanely. Police should give him a clean pair of exploding shorts, light his fuse and send him on his way, perhaps into an unoccupied field of clover.

Of course, that won’t happen. The United States is teaching the terrorists about democracy a little at a time. Their latest lesson, for instance, is that when things go wrong, lawyer up and demand your rights as a non-resident attempted mass murderer. Don’t forget to ask the policeman to read you your Miranda rights.

Terrorists also learn quickly that — if things go wrong — they are most likely to become guests of the American government, be sentenced to three nutritious meals a day and a comfortable bed, and given access to exercise equipment and lots of television, movies and other forms of scandalous entertainment. Unless sent back home to attack America again, they will suffer such infidel indignities for the rest of their lives.

I like my way better.

--------------------------------------------------------------------------------

Tom Brennan is author of The Snowflake Rebellion, a tongue-in-cheek novel about Alaska seceding from the union, and three other books. His Website is: http://arcticternbooks.com/

Russia-Belarus Oil Dispute Threatens Europe’s Supply

2010-01-03T22:04:00.000-08:00

By ANDREW E. KRAMER
MOSCOW — Russia and Belarus have failed to renew an agreement on crude oil export tariffs that expired on New Year’s Eve, raising the prospect that yet another otherwise unremarkable energy pricing dispute between Russia and a neighbor could unravel into a midwinter fuel shut-off on the Continent.

Just a year ago, Europeans shivered through a politically tinged dispute that went on for weeks between Russia and Ukraine over natural gas prices and transit fees.

This year, the crude oil pipeline that is the focus of disagreement is integral to exports of Siberian petroleum to Western Europe as part of the Soviet-era Druzhba pipeline system.

As is the case with natural gas pipelines in Ukraine, about 1.3 million barrels of oil per day shipped along the Belarussian spur of the Druzhba pipeline supply both the internal market in Belarus and the more lucrative markets in the European Union, like Germany and Poland.

On Sunday, Reuters cited two oil traders as saying that Russia had begun curbing supplies to the domestic market by cutting the flows to two refineries, Naftan and Mozyr. In Ukraine last January, that was a first step toward a more general shutdown.

Russian officials took pains to emphasize that the export volumes would continue to flow, while either refusing to confirm or denying the report of a local shut-off in Belarus.

A Russian Ministry of Energy spokeswoman, Irina F. Yesipova, said the transit flow en route to Western markets, a supply big enough that its disruption could raise global oil prices, had not been and would not be halted. She declined to comment on the domestic supplies in Belarus.

A senior official at Transneft, Russia’s state oil transport company, said in a telephone interview that the company continued to supply both the internal Belarussian market and export markets at full volume.

“We have not stopped pumping, not to Belarus, not for export,” said the official, who was not authorized to speak publicly.

A duty officer at the Belarussian Foreign Ministry referred questions to the Ministry of Energy, whose phones were not answered on Sunday.

Belarus is one-half of a loose confederation with Russia that was supposed to eventually lead to a common currency and customs zone. Yet in the oil business, so vital to Russia’s economy, Belarus was treated with privilege but as less than a fully integrated partner.

Refineries in Belarus paid a fraction — 35.6 percent — of Russia’s standard crude oil export tariff. The Belarussians, though, were able to re-export the gasoline, diesel, bitumen and other products to Europe at a healthy profit. This trade helped prop up the government of Aleksandr G. Lukashenko, the Belarussian president, at Russia’s expense.

The oil agreement with Moscow expired Dec. 31. Russia’s deputy prime minister for energy, Igor I. Sechin, had said that lacking a new deal, Belarus should pay the full export tariff on Russian crude, the Russian state RIA news agency reported.

Belarussian officials responded that their country should pay no tariff because it had renewed its commitment to a customs union with Russia just last year, according to a statement posted on the government’s Web site.

Before the New Year, the Belarussian delegation left Moscow, and the government in Belarus posted a statement saying that they had been subjected to “unprecedented pressure” to acquiesce to Russia’s demands. Both sides, however, said Sunday that negotiations were continuing.

Last January, the Russian natural gas monopoly Gazprom first tried to halt supplies to Ukraine’s domestic market in a pricing dispute. It then shut down the pipeline entirely, accusing the Ukrainians of continuing to supply their own needs by siphoning gas intended for export.

Climate change is pushing U.S. energy policy into the background

2009-12-27T22:03:00.000-08:00

Congressional focus on greenhouse gases and climate change is pushing U.S. energy policy into the background, lawyer says
Alan Bailey
Petroleum News
While debate in the U.S. Congress centers on greenhouse gas emissions and climate change, energy policy and U.S. energy security have become somewhat neglected, Tom Roberts, a member of Washington, D.C., law firm Van Ness Feldman P.C., told Law Seminars International’s Energy in Alaska conference Dec. 7.
“The fact is that climate change and energy are inextricably tied together,” he said. “The only way we are going to get a handle on our greenhouse gas emissions is to do things that affect the way we produce, transport and use energy.”
But climate change considerations are apparently driving the pace of progress of some key pieces of energy-related legislation currently wending their way through Congress.
House ACES bill
The Waxman-Markey bill, otherwise known as the American Clean Energy and Security Act, or ACES, that has narrowly passed the House of Representatives, has rolled together earlier bills that individually considered climate change, renewable energy and energy efficiency, and now contains two titles with provisions for renewable energy standards and for energy efficiency, in addition to major legislation that would enact a greenhouse gas cap-and-trade system.
The renewable energy standards in the bill apply to electricity utilities that generate more than 4 million kilowatt-hours per year, a size threshold that probably excludes any utilities operating in Alaska, Roberts said. By 2020 utilities of the appropriate size have to demonstrate that 20 percent of their sales come from renewable energy, with the possibility of demonstrating energy efficiencies as a contribution to that goal. But a limit imposed by the bill on the extent to which efficiency gains can be used to meet the standard suggests that the proposed standard has more to do with creating a market for wind and solar power than being more efficient, Roberts said.
It’s driven by the environmental community, and the wind and solar energy industries, he said.
The concept is that a utility can earn renewable energy certificates for submission to the U.S. Department of Energy, with the possibility of trading or banking for the future any certificates in excess of what the utility needs to meet the standard.
Two Senate bills
The Senate has two separate bills that together correspond to ACES, with the Clean Energy Jobs and American Power Act, or Kerry-Boxer bill, dealing with climate change and the American Clean Energy Leadership Act, or ACELA, dealing with energy. ACELA has bipartisan support but has been on hold for six months, waiting for action on climate change legislation, Roberts said.
ACELA contains a renewable energy standard for electricity generation, very similar to that in the ACES bill, with an identical threshold for the size of utility impacted but with a requirement for 15 percent of power to come from renewable sources by 2021. ACELA allows slightly more of the standard to be met from improved energy efficiency and the bill contains some types of renewable energy credit not available under ACES.
And both ACES and ACELA have buy-out provisions, allowing utilities to purchase renewable energy credits from the U.S. Department of Energy, if necessary, Roberts said.
Carbon capture and sequestration, a set of technologies aimed at removing and disposing carbon dioxide generated from fossil fuel use, also figures in both bills, with each bill spelling out a major program to help develop and demonstrate the CCS technologies. The carbon capture and sequestration provisions within ACELA include government indemnification of carbon dioxide storage site developers against future carbon dioxide leakage, one of the big CCS liability unknowns.
Both bills give the Federal Energy Regulatory Commission a new role in the oversight of electrical transmission line development, to facilitate the construction of interstate lines in support of renewable energy sources. And the bills include new energy efficiency standards for electrical appliances and other equipment.
ACELA also has a provision to establish a new quasi-independent agency within DOE to handle government funding support for energy development projects. The agency is supposed to be supplied with $10 billion of initial capitalization.
“This is a very far-sighted, aggressive approach,” Roberts said. “Whether it ultimately makes it in the end will be something to watch. If it does, it will drastically change the way the federal government supports energy project development, energy technology development.”
Oil and gas provisions
ACELA proposes the relaxation of some restrictions on oil and gas drilling in the eastern Gulf of Mexico and directs the Secretary of the Interior to establish an Alaska outer continental shelf lease and permit processing office. The bill also includes some amendments to the federal loan guarantee program for the Alaska natural gas pipeline — those amendments include an increase in upper limit for the loan guarantee from $18 billion to $30 billion and a guarantee that 80 percent of the total project cost will be covered, up to that $30 billion.
There is also a specific authorization to issue a right of way through non-wilderness areas of Denali National Park for an Alaska in-state natural gas pipeline.
However, as long as energy legislation remains tied to climate change it’s going to be a long time before any of the energy legislation passes into law, Roberts said.
“Right now the majority leader has kicked the climate-change can down the road until at least spring in the Senate,” he said.
And in 2010 it is unlikely that Congress will do much more than pass the annual appropriations bills ahead of the election that year — fear of unpredictable impacts on the U.S. economy of a cap-and-trade system will make passing climate change legislation in the Senate especially difficult, he said.
Some senators, including Sen. Lisa Murkowski, have been pushing to move an energy bill forward as standalone legislation, Roberts said.
And Roberts endorses that approach. It’s time to stop neglecting the energy stepchild, he said.
“Any study you look at shows you can get significant greenhouse-gas reductions from just simply doing energy things,” Roberts said. “… Let’s do some energy legislation. Let’s make a down payment on what we want to achieve on the greenhouse gas side and see what happens.”
Then people can expend time and energy working on climate change legislation, he said.

Tax program for oil industry makes exploration less attractive

2009-12-14T22:10:00.000-08:00

Letter to the ADN editor:

Tax program for oil industry makes exploration less attractive
Some say Alaska's tax program, ACES, benefits the oil industry. Industry executives say while innovative technology opens opportunities, ACES takes away "the up-side" and Alaska is no longer attractive for oil exploration. What should Alaskans believe?
Alyeska Pipeline's reality is based on one thing: pipeline throughput. Setting aside debate over policies, taxes and regulations, Alaskans should be concerned that the Trans Alaska Pipeline System now carries just one-third of peak throughput. Since 1988, throughput has declined from 2.1 million to 700,000 barrels per day and should dip below 300,000 barrels a day within 15 years.
What does future declining throughput mean for Alaskans? Fewer jobs. Lower state revenue. Reduced services. Tougher economic times for all.
Alyeska is making dramatic changes to manage decline. Our 2010 budget is 14 percent lower than 2009. We have cut 60 well-paying Alyeska and contractor positions and are spending less with local businesses. Seeking efficiencies, we will likely close some facilities and relocate jobs to Anchorage.
These difficult changes will impact individuals and communities. But every change is designed to extend the pipeline's life. While we increase efficiency, we will still invest in pipeline renewal and maintain our keen focus on safety, integrity and environment.
Pipeline throughput is a harbinger of things to come in Alaska. Alaskans must pay attention to Alyeska's reality. We are carefully changing our processes, culture and operations so TAPS can stay viable despite declining oil throughput. Alaska, its communities and its citizens would be wise to do the same.
-- Kevin Hostler
President and CEO
Alyeska Pipeline Service Company
Anchorage

Horizontal Wells and Gas Shales

2009-11-15T11:39:00.000-08:00

This post is one of my series of tech talks, describing some of the ways in which fossil fuels are produced. In the current part of the series we are focusing a little more on the procedures that are being used to recover natural gas from formations such as the Barnett, Fayetteville, Marcellus, Haynesville and Woodford shales. In this particular post I am going to concentrate more on the benefits of horizontal drilling through these shale reservoirs, rather than using the more conventional vertical wells that were used historically. This, and the next three posts in the series are likely to be a bit more technically dense than earlier posts, but I am trying to illustrate some of the problems of production, and some of the gains that technology is bringing to help solve some of them. And while the reason for the horizontal wells can be simplified in this graph from Chris McGill, there are a lot of other things that have to be considered in deciding whether or not the horizontal well is going to be worth developing.

Comparative production from a vertical and horizontal natural gas well (Chris McGill).
Full Article

Alaska's Natural Gas Pipeline: A Reality Check

2009-10-18T22:31:00.000-07:00

Alaska poorer for outdated oil attitude

2009-10-11T15:48:00.000-07:00

COMPASS: Other points of view

By BRAD KEITHLEY Brad Keithley heads the oil and gas law practice at Perkins Coie, LLC, from its Anchorage offices.

(10/07/09 19:31:30)

A recent New York Times article should make Alaskans think. The headline was "The Oil Industry is on a Roll This Year with New Discoveries."

The first sentence captures the thrust: "The oil industry has been on a hot streak this year, thanks to a series of major discoveries that have rekindled a sense of excitement across the petroleum sector, despite falling prices and a tough economy." The article reports 200 significant discoveries so far this year in dozens of countries, including Australia, Brazil, Norway, Ghana and Russia.

Alaska receives mention only as a historical footnote.

Why has Alaska become an historical footnote? Perhaps unintentionally, the article provides the answer. As explained by an oil company CEO, "That's the wonderful thing about price signals in a free market -- it puts people in a better position to take more exploration risk."

To put it bluntly, for the past several years, Alaska's exploration signals to the industry have said "go elsewhere."

Recent legislative enactments, such as the Alaska Gasline Inducement Act and the ACES oil tax, come to mind as examples. The root cause runs deeper, however.

Alaska has become smug and arrogant about the industry legislatively, administratively and even on the editorial pages of some newspapers. A good example is the attitude expressed earlier this year by one of the governor's "energy" advisers, Joe Balash.

In a recent international survey conducted by a Canadian institute, Alaska ranked 78th out of 143 states and governments in an assessment of policies designed to encourage oil and gas production. When asked to comment on the results, Balash said, "Alaska is right where it ought to be. 'We ... have tough terms; we set the bar high. ... We have world-class resources. Arkansas and Mississippi don't.'"

Unfortunately, that worldview is outdated. Alaska has 35 trillion cubic feet of reserves on the North Slope. To pick an example, recent discoveries of shale gas from Arkansas' Fayetteville shale formation alone are estimated at 20 Tcf, and additional amounts exist in the Woodford shale formation in eastern Arkansas and the potentially gigantic Haynesville shale formation located, in part, in southern Arkansas.

That story repeats across several states and the globe generally. Against these alternatives, Alaska's "tough terms" have shot Alaskans in the foot.

This situation poses a serious threat. Ninety percent of Alaska's general state government revenues and one-third of Alaska jobs derive from the oil industry. Undeniably, Alaska's economy runs on oil.

But, this linchpin is on a very steep decline. At its peak, the North Slope produced in excess of 2 million barrels per day; now, it produces roughly 700,000 barrels per day and is declining rapidly at the rate of 10 percent per year. The two new high-profile projects currently under development will not offset even one year's reduction. At its peak, BP's Liberty project is estimated to produce 40,000 barrels a day; Port Thomson is estimated to produce 10,000 barrels a day of liquids.

To overcome these declines -- and preserve its economy -- Alaska must renew its commitment to encouraging oil development; Alaska's "price signals" must indicate Alaska is open for business.

One question often asked is "who's responsible" for maintaining the "revenue side" of Alaska's economy. Sometimes, Alaskans assume it is the oil industry's responsibility. The correct answer, however, is that we -- Alaskans -- are. Alaska's political leaders set the "price signals" for development in Alaska; industry only responds to them.

The upcoming Legislature session and 2010 elections are critical. Without maintaining oil revenues, state services will decline, income and sales taxes will become a reality, and current residents will leave the state in large numbers, resulting in the collapse of housing prices and the economic well-being of scores of Alaska's businesses.

The revenue side of Alaska is on the line. Alaska's founding generation set the right price signals to sustain Alaska's first 50 years. The current generation must step up to put Alaska on track for the next 50.

Peak Oil- How will you ride the slide?

2009-09-26T10:52:00.000-07:00

ExxonMobil: Green Company of the Year

2009-08-08T16:35:00.000-07:00

Oil from algae? Just a sideshow, Exxon's real thrust into green energy is a big bet on natural gas.

Sea of green: In Qatar, Exxon is building the world's largest plants to make liquefied natural gas.

Christopher Helman, 08.05.09, 06:00 PM EDT Forbes Magazine dated August 24, 2009
Oil from algae? Just a sideshow, Exxon's real thrust into green energy is a big bet on natural gas.
Sea of green: In Qatar, Exxon is building the world's largest plants to make liquefied natural gas.
There are two ways for a big oil company to go green. There is the political approach and there is the engineer's approach.

Purely political: the grand announcement in July that ExxonMobil would put $600 million into algae farms that would turn sunlight into automotive fuel. It takes a leap of faith to think tanks of algae can compete with oil wells, even allowing for the advantage that biofuels would have in a world of carbon permits (or carbon taxes). But the algae project buys ExxonMobil some peace with environmentalists. Since taking the helm in 2006, ExxonMobil boss Rex W. Tillerson has worked hard to soften the company's stance on climate change; he is not as gruff and forceful as his predecessor Lee R. Raymond in dismissing global-warming alarmists.
The engineering solution to the matter of carbon in the atmosphere: Drill for natural gas. Per unit of energy delivered, methane releases 40% to 50% less carbon dioxide than coal and a quarter less than petroleum. Coal fuels half of U.S. power generation. Replacing all of it with methane would cut CO2 emissions by 1 billion tons a year. Could windmills come close to that in reducing greenhouse gases? Not easily. To get the same emissions reduction you would have to replace half of power plant coal with 80,000 giant turbines covering 400,000 acres of ground. "Natural gas is the answer to green-energy low-carbon concerns," says Neil Duffin, president of ExxonMobil's project development company.
ExxonMobil's bet on natural gas best comes into focus 7,900 miles away from its Irving, Tex. headquarters, in the Persian Gulf state of Qatar. There ExxonMobil is nearing completion of a $30 billion project to develop the world's biggest natural gas field. Four giant plants, the biggest of their kind, will chill the gas into liquefied natural gas for loading onto thermos-bottle tankers (also the biggest) and shipment to ports around the world.
The Qatar megaproject will by next year boost ExxonMobil's gas production 12% to 9.9 billion cubic feet a day, and vault the company into first place as the world's biggest natural gas producer not controlled by a government. Qatar volumes will help increase total oil and gas output roughly 5% to the energy equivalent of 4.3 million barrels of oil a day. The country will contribute an estimated 7% of ExxonMobil's pretax earnings (which were $55 billion in the last 12 months). All the big oil companies are drifting away from petroleum into natural gas, and for the same two reasons that Exxon is: Gas is cleaner-burning and still plentiful. With Qatar, Exxon has gotten ahead of its competition.
At the moment natural gas looks like a terrible business. The recession has led to a 10% drop this year in industrial demand. In the U.S. the price of gas has plunged to $3.50 per million British thermal units (more or less the same as 1,000 cubic feet), from a peak of $11 a year ago. This contributed to Exxon's 66% plunge in second-quarter earnings. A surge in supply could send prices even lower. New projects in such countries as Yemen, Russia and Indonesia are expected to push up volumes of liquefied natural gas 50% in the next two years. At that point LNG will account for 12% of global gas supply. Meanwhile, drillers are using innovative rock-cracking techniques in the tricky shale deposits of Texas, Pennsylvania and elsewhere; in five years they've found at least 500 trillion cubic feet of recoverable gas, roughly 20 years of U.S. demand.

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Twelve Principles to Guide U.S. Energy Policy

2009-08-03T10:52:00.000-07:00

Americans are growing increasingly concerned about energy. Their demand for energy is increasing faster than secure supplies. Much of the world's supply of oil is delivered in a restrictive market dominated by unstable or hostile nations, some of which are using energy as a tool to frustrate U.S. national security and foreign policy objectives.
Meanwhile, many Americans harbor misunderstandings and myths about energy and market forces. They want low energy prices and plentiful supply but resist the steps that energy companies must take to achieve these goals. This confusion leads their representatives in Congress to enact conflicting policies that harm America's ability to meet its energy needs. This has to change.
Sound national energy policies must enable America to obtain energy supplies from a wide range of sources in a way that is best for the economy and at the same time addresses homeland and national security considerations. An abundant, diverse energy supply is central to America's freedom and prosperity.
The guiding principles for an energy strategy that advances freedom and prosperity should emphasize three themes:
Unleashing free enterprise,
Protecting America's energy interests, and
Advancing free global energy markets.
Unleashing Free EnterpriseU.S. energy policy should recognize that the creativity of free enterprise is best suited to building the infrastructure that is needed for exploration and distribution, producing domestic supplies safely, and developing viable new energy sources.
To unleash American entrepreneurship, Congress and the Administration should let the free market do its job. Central planning frustrates the functioning of markets and undermines security by limiting opportunities to adapt and innovate. Washington must clear away the red tape that obstructs energy production and innovation while also assuring safety and appropriate environmental protection.
Specifically, Congress and the Administration should:
1. Avoid costly environmental regulatory mandates that will achieve little environmental gain. Numerous costly regulations have been proposed or implemented to address various environmental goals, from water quality to global warming. However, past experience—such as with the morass of gasoline regulations that push up the price at the pump and the requirements that have stopped construction of any new coal-fired power plants for the past 15 years—shows that mandates can be expensive and economically harmful while making only marginal progress toward environmental goals. The full cost of current and proposed regulations and mandates, including the economic and security impact, should be evaluated and compared with the likely environmental gain.
2. Rely on the private sector's research and development capabilities. The competitive private sector is best able to improve fuel efficiency and develop the next generation of fuels. There are many guesses as to what the “new oil” might be, but no one knows for certain—least of all the federal government. We do know, however, that finding and commercializing these new fuels is crucially important to our economic future. The best way to secure abundant energy sources in the future is to encourage entrepreneurs to discover them, not for agencies and congressional committees to try to pick winners with directed research, regulations, mandates, and subsidies. Entrepreneurs need a regulatory, trade, and tax system that creates the best climate for private-sector innovation.3. Urge government agencies to learn from the private sector. The U.S. government is one of the world's largest consumers of energy. In particular, the Department of Defense is one of the world's biggest customers for petroleum products, but it does a poor job of thinking about long-term energy costs. It relies heavily on legacy equipment that is very energy inefficient, assumes that it will always have plentiful supplies of petroleum products to support operations at reasonable prices, and does not adequately consider the life-cycle energy costs associated with developing, procuring, and maintaining new military capabilities. The military and the rest of government should adopt the best practices of the private sector to enable them to make smart buying decisions.
Protecting America's Energy InterestsIn today's dangerous world, policymakers must take steps to secure America's energy sources and protect the nation's energy infrastructure. However, they also need to keep down the economic cost of achieving security by enabling the energy production and distribution market to operate as efficiently as possible. Markets function most efficiently when they are transparent and predictable and when businesses can respond to market incentives.
Therefore, while pursuing the goal of security, government should:
4. Make all sources of energy within U.S. borders accessible.The federal government has placed too many restrictions on domestic oil and natural gas production. Failure to make full use of these domestic energy resources exacerbates the security and cost problems caused by geopolitical events and makes America more vulnerable to supply disruptions and price increases. All U.S. lands and waters should be made accessible for appropriate exploration and production, which could be done using technologies that are far safer and more efficient than those that were available in the past.
5. Remove artificial constraints on the domestic energy infrastructure, including unnecessarily severe environmental regulations.Red tape has restrained the expansion of refineries, construction of new pipelines and electricity transmission lines, and construction of new power plants. Several key domestic energy sources, particularly coal and nuclear power, can fulfill their potential and thus help to achieve energy security only if costly regulations and procedural requirements are revised or eliminated. Thus, new legislative initiatives such as streamlining requirements under the Clean Air Act and rethinking requirements for reprocessing nuclear fuel and the storage of nuclear waste should be considered.
6. Ensure that any effort to reduce reliance on foreign oil is grounded in policies that are best for the economy. Reducing oil imports from unstable or unfriendly regimes should be done in a way that minimizes the economic cost to Americans. Policies such as raising taxes on gasoline while mandating or subsidizing expensive or unproven alternative fuels and vehicles lead to large costs with marginal—or even negative—results. The first steps in reducing reliance on foreign oil are to make full use of domestic petroleum reserves and to remove disincentives to investment in oil production from friendly nations. These should be coupled with efforts to encourage diversification away from petroleum, which will be best achieved not by government fiat, but by the private sector–led development of alternatives that can compete in their own right. Domestically, the federal role should be limited to conducting basic research and removing regulatory and tax barriers that impede private-sector innovation. In addition, restrictions on international growth in alternatives, such as the tariffs that limit ethanol imports into the United States, should be eliminated.
7. Manage risks to critical energy infrastructure as a responsibility shared jointly by the government and the private sector. Assessing the risks to critical infrastructure is a task that should be shared jointly by government, which best represents the national interest, and the private sector, which best understands how to deliver goods and services efficiently and effectively. Government can best understand threats and take steps to reduce them, while businesses can best assess their own vulnerabilities and address them effectively. Government should establish reasonable due-diligence standards for safety, security, and environmental concerns. This will require a high degree of transparency and effective information-sharing between government and industry, a mechanism to assess compliance and performance, and a non-bureaucratic way to enforce regulations. Optimal requirements would be performance-based (i.e., setting clear standards and allowing the private sector to determine how best to achieve them).
8. Establish effective risk communications for energy issues.Educating Americans on the facts is essential. In particular, Americans should be better educated about energy policy and the changes likely in the pattern of energy supply and prices before disruptions or crises occur. In the event of a crisis, information that is credible, understandable, and actionable should be provided to Americans so that they can make the best-informed decisions.
9. Develop foreign policies that thwart the capacity of coercive regimes to employ energy supplies as an economic weapon. America should be concerned not only about the dependability of its own energy, but also about that of its friends and allies. Regimes that withhold or restrict energy supplies as an instrument of national policy threaten not only regional stability and prosperity, but also the economy and national interests of the United States. The United States should develop strong bilateral measures to deal with efforts by coercive regimes to wage economic warfare. These might include joint contingency planning, public–private initiatives, and research and development initiatives.
Advancing Free Global Energy MarketsAmerica cannot ensure freedom solely from within its own borders. It must be willing to engage internationally to create the conditions for free enterprise to prosper.
This means that the government must act to:
10. Sustain access to the global marketplace.Remaining an integral part of the global economyis vital to long-term U.S. national security and the country's continuing economic competitiveness. Rather than attempting to defend, protect, or secure any means of domestic or global production, the greatest degree of security comes from having access to the global marketplace and obtaining goods, resources, and services based on market decisions from friendly suppliers. It is in the vital interest of the United States to uphold the principle of freedom of the seas and to promote and protect the ways and means of free trade among nations acting in accordance with the rule of law.To accomplish this, the United States should retain the capability to use all of the instruments of national power—including military, diplomatic, law enforcement, intelligence, economic, and informational power—in any theater where U.S. interests could be at risk.
11. Discourage restrictive international regimes.OPEC and non-OPEC countries with restrictive foreign investment laws, state monopolies, and excessive government intervention undermine the U.S. effort to promote free markets. U.S. economic and foreign policy should seek to discourage these practices.
12. Recognize that not all trading partners are equal.Free people have the right to decide with whom to conduct business, but trade in critical but vulnerable goods and services is best conducted with other free peoples. America's closest friends and allies should be viewed as the most reliable trading partners for supplying oil and other energy supplies. Geostrategic military and economic alliances will change, of course, and the U.S. should be prepared to adapt, but Americans should seek to conduct energy business with countries that respect the rule of law, combat corruption and terrorism, and foster economic opportunity, democracy, and justice.
ConclusionAmericans clearly understand that freedom, opportunity, and their very quality of life suffer when abundant, affordable energy supplies are threatened. They expect Washington to enact policies that protect their interests. Congress and the Administration would do this best by following these 12 principles to unleash the power of free enterprise, protect America's energy interests, and advance freedom in energy markets not just at home, but worldwide.
Stuart M. Butler, Ph.D., is Vice President for Domestic and Economic Policy Studies, and Kim R. Holmes, Ph.D., is Vice President for Foreign and Defense Policy Studies and Director of the Kathryn and Shelby Cullom Davis Institute for International Studies, at The Heritage Foundation.

Exxon & TransCanada: Back to the Future

2009-06-18T13:32:00.000-07:00

Exxon & TransCanada: Back to the Future
Welcome to the strange days of pipeline politics that provides a twist to the old saying, "there are no permanent friends only permanent interests."

In April of 2007, I sat in an airport conference room with Department of Revenue Commissioner Tom Irwin and Deputy Commissioner Marty Rutherford so they could explain their AGIA concept.

During the two hour sit down, I asked Commissioner Irwin why he didn't believe Governor Sarah Palin was capable of sitting down and negotiating with the producers over pipeline terms. After all, the governor would be the perfect ambassador coming to negotiate armed with a reservoir of goodwill and trust from fellow Alaskans and the desire to strike a deal.

Irwin's face went blank almost as if I had said something unkind about his mother.

"Do you know how Exxon negotiates," Irwin asked rhetorically. They're the worst, they squeeze and squeeze, they keep asking for more and more he said. When they don't get what they want, they'll get up and walk away from the table. Then, in order to dramatize his point, Irwin abruptly abruptly stood up from his chair and walked away from the conference table thus punctuating the message.

Across the table, Lt. Governor Sean Parnell just shook his head and said yeah they're tough.

It was clear from my two hour meeting that whatever dynamic existed between Irwin and Exxon, his dislike for the Houston based oil giant was personal.

It was also clear that Irwin's AGIA was specifically designed to avoid face to face negotiations with companies like Exxon.

The ongoing war between Exxon and the Palin administration seemed to escalate over the last year with tough exchanges regarding both AGIA and the on going litigation surrounding Exxon's Point Thomson development.

In April of 2008, Commissioner Irwin rejected Exxon's proposal to bring Point Thomson under development saying he couldn't trust Exxon while accusing them of misleading Alaskans about their Point Thomson intentions.

The intense dislike held by the Palin administration for Exxon was put on public display when emails were released as part of a legal filing in the Point Thomson court case. Internal DNR emails revealed state oil & gas executives were slow rolling Exxon's permitting requests while openly mocking the company's commitment to develop Point Thomson. Governor Sarah Palin also criticized Exxon, saying the company shouldn't let the door hit them on their way out.

Meanwhile, Exxon was critical of Palin's gas pipeline plan, AGIA.

During the two years of legislative testimony on AGIA, Exxon repeatedly warned the Palin administration that AGIA would not work. "AGIA does not provide for a commercially viable project," Exxon's Marty Massey testified over and over again during hearings on AGIA.

Massey along with other producers all testified that those hurdles to development included fiscal certainty, unrealistic terms regarding rolled in rates and ownership issues concerning the pipeline itself. The concerns voiced by Exxon and the other producers were the same reasons why none of the producers bid on AGIA to begin with.

Last week the news broke that Exxon had joined TransCanada while declaring that AGIA was the way to the promised pipeline land. Some interpreted the announcement as much to do about nothing while the Palin administration referred to it as an historic event.

At the press conference announcing the new partnership, DNR Commissioner Irwin spoked glowingly about Exxon's professionalism and then appeared is if he might just reach out and give Exxon's Massey a bear hug. Meanwhile, the governor was issuing a press statement lauding Exxon and saying how this proves AGIA is working.

Exxon's Massey then stepped to the microphone to announce the partnership with TransCanada and then proclaimed that AGIA was the best way to get a successful natural gas pipeline project in their mind.

So what happened to the distrust that the Palin administration held for Exxon and the economic concerns that Exxon held for the Palin administration's AGIA?

According to an Anchorage lawmaker, during a briefing on the new partnership an Exxon representative was asked if their new found support for AGIA represented a retraction of their legislative testimony that AGIA is not a commercially viable approach to getting a pipeline built. The response from the company representative was that Exxon stood behind their legislative testimony 100%.

A twist if you'll allow me;

there are no permanent enemies, only permanent interests.

Permanent Interests

For Exxon this is a brilliant business move and one that should be understood in complete context of protecting their permanent interests.

During Exxon's press conference, company executives stressed one of their permanent interest quite clearly; the state must negotiate a fiscal framework with gas shippers so Exxon can accurately evaluate the projects economics. An Exxon spokesman said during the news conference that "predictable and durable" tax terms with the state will have to be dealt with before Exxon becomes a full participant.

During the State's press conference, Palin's gas line team stressed their permanent interest; AGIA was working and the state's pipeline mandates were still in place with the new partnership between Exxon and TransCanada. Even the governor's press release threw a little AGIA bone to the faithful, “Alaskans will also be pleased to know that TransCanada’s obligations to the state as the AGIA licensee are 100 percent intact and unaltered by this alignment with ExxonMobil.”

AGIA was specifically created by the Palin administration to lock producers out of pipeline ownership while avoiding ever having to negotiate fiscal terms.

After all, it was DNR's Irwin and his Deputy Rutherford who famously said that the state was “outclassed” at the negotiating table and that was why the AGIA mandates were so critical.

However Exxon's reiteration that fiscal terms must be agreed upon to move the project forward is a clear sign that their engagement with TransCanada is simply a new approach to getting back to where Frank Murkowski left us four years ago; needing to negotiate a fiscal framework with the companies that will assume the risk of building the largest oil & gas project in the world.

Before last weeks announcement of a joint cooperative agreement between Exxon and TransCanada, the AGIA process was beginning to draw criticism. Concerns had been growing from various corners of the political landscape about the slow pace of work and the overall attractiveness of the project with stagnant natural gas prices and increasing reports of a glut of natural gas in the lower 48.

Exxon comes along at a time when TransCanada needed a friend with deep pockets and the Palin administration needed some positive news to tell about AGIA.

With Exxon joining TransCanada they now have a seat at the table and can basically control the ground game preparing for scheduled open season in July of 2010. The agreement between the two companies as introduced last week was fairly vague but the intent was clear.

Exxon will control the work behind the scenes as a subcontractor managing the project design and costing while TransCanada wears the public face of the AGIA license holder.

In 2000, Exxon was partners with BP and Conoco in a pipeline working group when they spent roughly $120 million studying costs for the natural gas pipeline. Industry insiders have said that TransCanada has been actively pursuing the producers with an offer to buy the 2000 study materials.

Exxon's contribution to TransCanada will more than likely include dusting off these studies, updating the information and then selling it to TransCanada. The irony is that according to AGIA, if this represents a qualified expense, the state could end up paying for 50% of the cost.

According to their agreement, “TransCanada can progress the project independently if it so elects, using all jointly developed assets/information.” This means that when open season fail to attract firm gas commitments next summer, it will be TransCanada who will then be forced to carry on to FERC permitting according to their AGIA requirements.

You might remember two years ago when DNR Commissioner Irwin told a room full of lawmakers that the strategy was to have a failed open season for AGIA, so the administration could use public, government and stockholder pressure to force Exxon, BP and Conoco into playing ball.

But now all of the producers are in the game, all slugging away with their play. This means there is nobody left on the sidewalk for the Palin administration to blame or threaten when TransCanada's open season fails next July.

If TransCanada's open season fails it won't be because Exxon didn't play, it will be because the state's AGIA mandates don't provide for a commercially viable project.

If Denali's open season fails it won't be because BP and ConocoPhillips didn't play, it will be because the state's AGIA mandates don't provide for a commercially viable project.

And while many of you might say, "Whoa Andrew, Denali is outside of AGIA so there will be no mandates," lest you forget that one of AGIA's mandates will prohibit the state from negotiating with a competing project (Denali) at the risk of having to pay TransCanada treble damages.

Even ignoring the fact that all three producers will have to all be in agreement in order to greenlight the $30 plus billion project, if Exxon did step out and commit gas to the AGIA based project on their own, they'd tag on a massive contingency; the state must negotiate viable commercial terms before project commencement.

The same contingency will accompany any gas commitments to the Denali pipeline project from BP and Conoco as well.

The problem for the Palin administration is that adopting what the producers need to commit gas and build the pipeline would mean gutting AGIA, thus rendering the entire exercise meaningless.

Meanwhile, with a new partnership with TransCanada and a key role in managing design and engineering work, Exxon will be able to walk away with a much clearer understanding of just how much the AGIA mandates will impact their bottom line while at the same time gaining a higher comfort level with the project cost estimates since they had a hand in developing them.

Value Added

Since the day TransCanada has been announced as the only AGIA applicant that made it through the process, producers have been asked repeatedly if they envisioned a time when they might join up with the Canadian pipeline building company under AGIA.

“We're interested in any partner who can bring value to the project,” has been the standard industry reply. The problem for TransCanada is they don't bring any value to the project.

TransCanada has world class pipeline building skills but so do the producers. But more importantly, the producers have what TransCanada does not; deep pockets and natural gas supplies. In fact TransCanada offers little more than a shaky claim to decade old Canadian permits.

In an interview on the Dan Fagan Radio Show, Revenue Commissioner Pat Galvin said that Exxon was going to participate via subcontractor status by taking the lead role in designing and engineering the gas treatment plant. This isn't a surprise, because the gas treatment plant is traditionally oil field equipment, not pipeline equipment.

Just one bit of irony.

Back in February, Governor Palin was informed by a reporter at the beginning of a press conference that Denali had just announced awarding a contract to a local engineering firm to design and engineer the gas treatment plant. Big deal Palin said, it's just a contract to design not a contract to build. Four months later, TransCanada announces their subcontractor and the response from Palin is dramatically different.

But in this partnershop, TransCanada offers Exxon some excellent short term value. TransCanada provides Exxon with a lane to drive in during the journey towards AGIA's scheduled open season.

With BP and Conoco driving their Denali project ahead, Exxon needed a seat at the wheel and TransCanada desperately needed a driver.

With Exxon's new partnership based on their assets and management policies, even though on the outside it's being packaged as TransCanada is still in command, the tiger is actually driving the bus.

Not to mention the fact that Exxon is now in a position to get reimbursed for half of the costs of its pipeline design and engineering studies under the terms of AGIA.

And while Exxon scores positive press for siding with the state and progressing the pipeline project, they have left themselves plenty of room to jump off the AGIA train before the crash.

Looking ahead, after the two failed open seasons in 2010, the next move in the quest for a natural gas pipeline will land Alaska and the producers right back at square one where Frank Murkowski left us four years ago; negotiating a fiscal framework with those that will assume the risk of building the largest oil & gas project in the world.

And it will have only taken us four years to come full circle and make it right back to where we began.

Feds will take over gas line - Palin's socialistic policy makes it easy

2009-06-05T11:03:00.000-07:00

Alaska lawmakers are concerned feds will take over gas line - Palin's socialistic policy makes it easy to do so.

Forget “Drill, baby, drill.” Sarah Palin says she’s building a $40 billion gas pipeline, which even President Obama wants. The only problem: It isn’t there. And it’s her fault.

“I fought to bring about the largest private-sector infrastructure project in North American history,” Palin said at the Republican convention. “And when that deal was struck, we began a nearly $40 billion natural-gas pipeline to help lead America to energy independence.”

During the vice-presidential debate, she said it again: “We’re building a nearly $40 billion natural-gas pipeline, which is North America’s largest and most expensive infrastructure project ever.”

And to Katie Couric, she said, “We should have started 10 years ago, but better late than never.”

To many outside of Alaska, it may therefore come as a surprise to learn that not only does such a pipeline not exist, but—even as Alaska’s deep winter darkness gives way to the first light of spring—the prospect that it will be built within Sarah Palin’s lifetime grows dimmer by the day.

Palin does not play well with others

2009-04-17T14:48:00.000-07:00

More Legislature vs. Palin

Posted: April 17, 2009

The antagonism between legislators and Gov. Sarah Palin doesn’t end. Hours after the Legislature voted down the governor’s nominee for attorney general, House Finance Committee members tonight slammed the governor’s aides for not briefing legislators on Palin’s plan for an in-state gas pipeline.

“I’ve had a lot of friction with the governor this year on her lack of connection, frankly the appearance that she’s more concerned about her national ambitions than what’s going on in the state,” Anchorage Republican Rep. Mike Hawker, co-chair of the finance committee, told Palin budget director Karen Rehfeld.

The committee was deciding on a request by Palin for $9 million to help develop a private in-state natural gas pipeline from the North Slope down to the Kenai Peninsula. Hawker and the other co-chair said Palin staffers spoke to legislative leaders about the money -- but several other finance committee members complained this was the first they’d heard of it.

“Nobody from the (Palin) administration has been to my office at all…I see a number of different legislators all shaking their heads, same thing, nobody’s been in their office,” said Kodiak Republican Rep. Alan Austerman.

Haines Republican Rep. Bill Thomas said nobody has spoken to him about gas plan either. Anchorage Democratic Rep. Les Gara -- who questioned if this is a set up to benefit the Enstar "bullet line" project -- said he’s being asked to approve a $9 million plan with no one ever describing to him what it is about.

Hawker said it’s an insult if Palin staffers were only talking to legislative leadership about it and not following up with other members of the state Legislature about something that is supposed to be a high priority for the governor.

“I would offer some counsel and instruction to the (Palin) administration. If this was your highest priority, it is beyond me… 11 people have been sitting at this (finance committee) table all year, you are looking for support for an appropriation and it is just beyond me that you folks didn’t have someone, quite frankly it just never occurred to me that you wouldn’t have talked to everybody on this table,” he said.

Palin budget director Rehfeld responded she is clearly sensing the frustration at the committee.

“We have had this appropriation in our budget for in-state gas since December…it has evolved, but the discussion and the interest and the desire to move forward on in-state gas has been very clear from the administration and we have talked with the committee about the budget request. So the specific design now going through the governor’s office is different, yes, than what we had proposed but I think clearly the governor has been very consistent in her discussion of in-state gas,” Rehfeld told the finance committee.

CNN exposes Palin on building pipeline claim

2009-03-23T21:07:00.001-07:00

CNN exposes Palin on building pipeline claim

Posted using ShareThis

Is Palin really the biggest obstacle to a gas pipeline?

2009-03-16T18:57:00.000-07:00

Here's the press release on McGinniss' story. After that is McAllister's response to the press release. And lastly is a zinger -- a little tidbit about Palin and Exxon meeting the other week.

CONDÉ NAST PORTFOLIO ON SARAH PALIN, BIG OIL,
AND THE PIPELINE TO NOWHERE
New York-Joe McGinniss, bestselling author of Going to Extremes, a nonfiction account of his year in Alaska, returns to the state in search of the $40 billion natural gas pipeline that Sarah Palin has said she is building. But McGinniss finds that not only is the pipeline not being built, but Palin herself is the biggest obstacle in its path. ("Pipe Dreams" p. 50). "Everything she is doing is the opposite of ‘Drill, baby, drill,' " former governor of Alaska Tony Knowles tells McGinniss. Despite pressure from the Obama administration to get pipeline construction underway, the prospect of its ever being built looks dimmer by the day. McGinniss reports how Palin has virtually ignored the pipeline issue since returning to Alaska in November to focus instead on her 2012 presidential campaign strategy. McGinniss notes her absence from major oil-company summits, and hears from a rising chorus of critics, including some of her former supporters. Alaska Republican Mike Hawker tells McGinniss, "The only thing standing in the way of an Alaska gas pipeline is the Sarah Palin administration." Palin's biggest blunder? Locking the state into an exclusive contract with a Canadian pipeline company (TransCanada) that has no access to Alaska's natural gas. Now BP and ConocoPhillips--two companies that do have gas--have launched a rival project. McGinniss writes that despite her repeated claims that she'd already gotten the project underway "What Palin had done... was contrive to pay as much as $500 million to a foreign company to look into the possibility of someday building a line." Since the election, the price of oil and gas has continued to plummet and Alaska's budget deficit has soared. McGinniss argues that Palin's $500 million commitment to TransCanada looks increasingly like money wasted. Even Hal Kvisle, the CEO of TransCanada, concedes, "I don't know whether we're going to see this [pipeline] get built or not."

*****

Here is Bill McAllister's response on the McGinniss press release:

It seems to expect people to be surprised by the fact that the pipeline is not under construction. That's not much of an "aha." Obviously, anyone paying attention knows this will be years in the making.

"Palin has virtually ignored the pipeline issue since returning to Alaska in November to focus instead on her 2012 presidential campaign strategy." Show me one shred of proof for either part of that statement. The governor had a nearly daylong meeting with her gas line team the week after the election, and of course those consultations have continued. In early December, she arranged an event in Fairbanks to present the AGIA license to TransCanada. She has gas line-related funding requests pending before both the Congress and the Legislature. This is "ignoring"?

McGinniss notes "her absence from major oil-company summits." She had Exxon in her office last week. Not sure what his point is there.

McGinnis calls AGIA a blunder, but every lawmaker but one voted for it, and a majority voted to stay the course over a year later and give TransCanada a shot. The governor campaigned in 2006 on getting Alaska's terms for its gas, in contrast to the Murkowski contract that ceded tax sovereignty, judicial sovereignty and regulatory sovereignty. AGIA was a game-changer, a new paradigm.

*****

And here's a follow-up exchange between Alaska Dispatch and McAllister about the Palin-Exxon meeting:

Alaska Dispatch: Gov. Palin met with Exxon? Can you tell me more about that meeting and the date it occurred? Why did she meet with Exxon? For Pt. Thomson? The gas line? Something else? What was the result of the meeting?

McAllister: I don't have details. I just saw them go into her office. I didn't ask her about it afterward. But hey, that wasn't the first time since the election. That's what's so off-base about McGinnis. He obviously doesn't have a clue what she does.

*****

And now we end with a few questions for you to chew on in the comments section:

1) Was AGIA nothing more than a ploy to get the industry to move on the gas line project?

2) Can Alaskans trust BP and Conoco to follow through with their Denali pipeline?

3) Should the state continue down the AGIA path, including subsidizing TransCanada, especially during these lean economic times/lower oil prices?

4) And is Palin really the biggest obstacle to a gas pipeline?

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Obama's Oil & Gas Tax Plan: Alaska's precarious position

2009-03-03T09:56:00.000-08:00

(3/03/09) On Saturday, President Barack Obama detailed his fy2011 federal budget proposal by saying he would eliminate $30 billion in oil & gas company tax credits and use the money to pay for government services.

Lets face it; oil & gas companies are an easy target with the profits they've been reporting. But unlike other industries that have decimated wealth such as insurance (think AIG) and finance (think Lehman Brothers), the profits from oil and gas companies have actually helped buffer the dramatic liquidation of wealth in Americans retirement accounts.

SEC data on the ownership of U.S. Oil and natural gas companies shows that 70% of the shares of these companies are held by institutional investors (Ak Perm Fund Corp eg.) especially asset management companies, and predominantly on behalf of middle-class American households who on shares through mutual funds, pension funds and retirement accounts.

Individual investors who manage their own portfolios and are not company insiders account for almost 30% of all industry ownership, which again includes significant numbers of middle-cass households holding IRA and other personal retirement accounts.

A recent report on the subject found, “The data strongly suggest that most of those profits go to the industry’s majority shareholders, who are middle-class U.S. Households with mutual fund investments, pension accounts, other personal retirement accounts, and small personal portfolios.”

But still, it's seems politically fashionable to go after one of the only industries in the country that is making a profit.

Seems ironic in a day and age where government is spending hundreds of billions in taxpayer money to bail out failing companies who have managed themselves into the ground.

Today AGI announced the largest single quarter loss in corporate history at $67 billion and what happened? Uncle Sam rushed in with $30 billion in taxpayer money to help them out. I'd wager that if Exxon or BP were to lose that much, Uncle Sam would be as absent as mink stoll at a PETA function.

The problem closer to home for Alaskans is that President Obama's proposed tax changes represent a threat to Alaska's financial life line; oil & gas development on the North Slope.

In November of 2007, Governor Sarah Palin and the Alaska State Legislature increased taxes significantly on the oil & gas industry. The one saving grace for many producers was that in some cases, they could deduct their state taxes from their federal taxes.

President Obama's plan calls for eliminating these credits and if they become law, producers will take their capital and flee to more tax friendly countries who will be begging for investment given the global economic meltdown.

Already there are growing signs of concern on the North Slope.

In January of 2008, the governor put out a press release announcing a major new project on the North Slope:

"Governor Sarah Palin today commended the major investment announced by Italian oil giant Eni. The company will invest $1.45 billion developing the Nikaitchuq oil field. Eni expects to drill 70 wells to recover 180 million barrels of oil."

In December of 2008, Department of Natural Resources Commissioner Tom Irwin, used the Eni project in a column in the Anchorage Daily News to support his contention that activity up on the North Slope was humming along.

"Our commitment to development is further demonstrated through the royalty modification program and has resulted in major activity. Through a cooperative cost- and risk-sharing effort between the state and industry, this world-class field is being developed. Likewise, Italian energy giant Eni has sanctioned some $2 billion in project capital for the development of the Nikiatchuq field, neighboring Oooguruk."

Last week however, Eni notified sub-contractors that it is suspending all work until further notice.

According to one oil company executive, this is a significant loss of jobs.

To add insult to injury, Conoco Phillips announced they were cutting their capital budget in Alaska. Conoco has announced a $12.5 billion capital spending program for 2009, which pencils out to a 20 percent reduction in capital spending in Alaska for the coming year.

Capital spending covers exploration and oil field development costs, which have always been viewed as the marker for determining the economic health on the North Slope.

According to Eric Lidji at the Petroleum News, Conoco earned $2.3 billion in profit on $9.2 billion in revenue in Alaska last year and paid $3.4 billion in non-income taxes. Conoco paid $1.7 billion in non-income taxes in Alaska in 2007.

Conoco paid $33.83 in non-income taxes on each oil-equivalent barrel produced in Alaska last year, up from $15.27 in 2007. The figure is significantly higher than all other areas listed in the report, except for the $50.14 reported for a region marked "other areas." The company paid $4.20 in non-income taxes per barrel in the Lower 48 last year.

The dramatic increase in non-income tax per barrel is due to the state's dramatic increase in productions taxes adopted in 2007.

In fact, the news from the North Slope of late has made one thing perfectly clear; a continued refusal by DNR Commissioner Tom Irwin to delay Point Thomson development even more than he already had, would have caused an even wider spread of pain on Alaska's economy.

The global economic recession will continue to present challenges for Alaska's resource development, but the combination of Alaska's high tax structure and Obama's proposal to end federal tax breaks for producers of domestic sources of oil & gas will have tremendous consequences on Alaska's North Slope development.

Advanced Drilling Technology

2009-02-22T18:39:00.000-08:00

Healy Clean Coal: Rewarding cheats and con men

2009-01-08T10:00:00.000-08:00

Healy Clean Coal: Rewarding cheats and con men

After twenty years of screwing both the State of Alaska and the US Department of Energy over a clean coal plant that they wanted built in the first place, it looks as if the Palin administration is on the verge of allowing Golden Valley Electric Association to screw the state one more time.

According to sources, the Palin administration is reportedly close to a deal that would have AIDEA, the state's economic development arm, basically give away the $300 million clean coal plant completed in 1999 to GVEA, the very same utility which backed out of paying for the plant and cheated the state out of tens of millions.

Over the last eighteen years, GVEA has used one excuse after another in refusing to accept responsibility and management for a plant that they were hoping to get for free at taxpayers expense. Instead, over the last ten years the plant has been sitting idle, with GVEA putting up roadblocks in front of AIDEA's attempts to utilize the asset.

Finally in November of 2005, the Murkowski administration had enough of GVEA's stalling tactics and filed legal action.

But then along comes Palin and after stacking the board with her cronies, is now proposing to let GVEA be rewarded after screwing the state for the last twenty years, for her own political gain.

Funny, if GVEA were Exxon, something tells me this wouldn't be happening.

Whats worse is when you look at the cast of characters involved in this giveaway of a state asset, you can't help but be alarmed.

Since Governor Palin has come into office she has replaced the head of AIDEA with a fellow Wasilla crony and planted her resident babysitter and former administrative problem child, Ivy Frye, at AIDEA. Inside sources confirm she seldom attends work, preferring to hang out in the Governor’s suite.

But the biggest red flags are those who have something to gain with the GVEA giveaway.

In March, Palin appointed Steve Haagenson as the head of the Alaska Energy Authority and as the State Energy Czar.

So what was Haagenson's prior job?

He was CEO of Golden Valley Electric Association (GVEA).

In his brief stint as State Energy Czar, lawmakers have complained that he has totally botched the renewable energy grant program and has so far failed to deliver the statewide energy plan on December 17 as he promised a week earlier while speaking to the Anchorage Chamber of Commerce.

Sources say the delay in releasing the energy plan was due to criticism about the plan Haagenson described to Chamber members on December 8, wasn't a plan at all, it was simply a menu of options. The delay was necessary in order for AIDEA to rush this giveaway of the coal plant through to try and add substance to a weak energy plan and to provide cheerleading material for Palin's state of the state speech.

Multiple sources confirm that Department of Revenue Commissioner Pat Galvin, who is an AIDEA Board member, and Fairbanks Representative Mike Kelly have engineered a sweetheart deal giving away the HCCP to GVEA.

According to my sources, Kelly has long promised to right this situation and resolve the issue in favor of GVEA.

So what was Kelly's former job before he landed in the legislature?

Like Haagenson, Kelly is a former CEO of Golden Valley Electric Association (GVEA).

HCCP was built by AIDEA for GVEA in a deal when Kelly was CEO of GVEA. The HCCP cost AIDEA $300 million to construct and after years of GVEA refusing to accept the plant or pay for it, it has been written down on the AIDEA books in 2002 to some calculation around $180 million. In the 2005 lawsuit filed under the Murkowski administration, the state was suing GVEA for $167 million in damages.

So because Kelly was CEO during the time the coal plant was being built for GVEA, he has had this albatross hanging around his neck for the last decade. It has long been rumored that Kelly and the GVEA Board are still working to save face over a deal gone wrong years ago with the state now picking up the tab.

Galvin and Kelly’s deal basically gives HCCP to GVEA. Cost will be $50 million, with 100% long term financing at 5% interest by AIDEA. AIDEA immediately pays $45 million in “restart” costs. That means the state nets out $5 million while GVEA gets a plant that will provide a profitable long term revenue stream.

Documents obtained by a legislator explicitly confirm reports from an outside source that Galvin and Kelly have told the GVEA board and management that the deal must be done “before Mike Chenault takes over as Speaker of the House," on January 19,2009.

Why the rush to get this deal done so fast?

One reason is that Chenault represents the Kenai Peninsula where Homer Electric Association already has an offer on the table of $85 million to purchase the plant from AIDEA.

Sources outside the legislature have alleged that Rep/ Kelly used his position as Budget Subcommittee Chairman for DCCED with administrative authority over AIDEA to obtain confidential information about the HEC offer that he took to an executive session of the GVEA Board.

There are rumors that Kelly counseled GVEA Board against negotiating or agreeing to any HCCP settlement plan until he derailed the HEC proposal and put the fix in with the administration who would do his bidding.

The second reason for urgency is the administration wants a deal closed by the State of the State which is scheduled to be given by Governor Palin on January 20.

This will give her something to offer as an accomplishment since her administration has done very little in the last twelve months.

AGIA, ethics reform, increasing oil taxes...she claimed credit for all of those during last years state of the state. In fact one source told me yesterday that in this year's accomplishments sent out to employees, the administration listed the Santa visits to rural Alaska as an accomplishment.

Then there is our dear friend Tom Irwin, who was fomerly a public relations executive at GVEA after he dropped out of the Murkowski administration.

So that makes three Fairbanks neighbors and former GVEA executives that quite possibly have a hand in handing over a $300 million state asset to their former employer for a reported $50 million, minus the start up costs.

But wait, according to my sources there is more. The HCCP will be transferred to a new entity controlled by GVEA, but GVEA will not provide any guarantee of the $50 million debt. How’s that for bankruptcy protection and leaving the creditor totally exposed?

From what I understand the deal is done and AIDEA is only waiting for its next board meeting to approve the giveaway of the Heally Clean Coal Plant.

According to the AIDEA website, their next board meeting is January 15, 2009.

To read the AIDEA press release from 2005 regarding the filing of a law suit against GVEA as well as a detailed time line of the Healy Clean Coal Plant history, click on link:
http://www.aidea.org/PDF%20files/HCCP/AIDEA%20sues%20GVEA%20over%20HCCP.pdf

2008-11-20T14:01:00.000-08:00

Politics and the Pipeline

"Even in my own energy producing state, we have hundreds of trillions of cubic feet of clean green natural gas, and we're building the nearly forty billion dollar natural gas pipeline, which is North America's largest and most expensive infrastructure project."
Governor Sarah Palin - Vice Presidential Debate - 10/2/08

Andrew Halcro's blog | read more

AP INVESTIGATION: Palin's Pipeline Terms Netted 1 Viable Bid, From Firm With Inside Ties

2008-10-25T12:51:00.001-07:00

AP INVESTIGATION: Palin's Pipeline Terms Netted 1 Viable Bid, From Firm With Inside Ties

TIES THAT BIND

Palin's team was led by Marty Rutherford, a widely respected energy specialist who entered the upper levels of state government nearly 20 years ago. Rutherford solidified her status when, in 2005, she joined an exodus of Department of Natural Resources staff who felt Murkowski was selling out to the oil giants.

What the Palin administration didn't tell legislators _ and neglected to mention in its announcement of Rutherford's appointment _ was that in 2003, Rutherford left public service and worked for 10 months at the Anchorage-based Jade North lobbying firm. There she did $40,200 worth of work for Foothills Pipe Lines Alaska, Inc., a subsidiary of TransCanada.

Foothills Pipe Lines Alaska Inc. paid Rutherford for expertise on topics including state legislation and funding related to gas commercialization, according to her 2003 lobbyist registration statement.

Read More

Sarah, Oil and Gas Expert?

2008-09-26T13:12:00.000-07:00

Sarah Palin, energy expert?

2008-09-22T01:01:00.000-07:00

Remember those times in college when instead of doing the reading for your class the next day, you went out partying with your friends? And remember how when your professor asked you about the material you didn't read, you stammered, and hemmed and hawed, and finally just said whatever came to your mind, hoping beyond hope that it was at least mildly coherent?

Apparently, six colleges later, Sarah Palin does too.

At a town hall on Wednesday night, Palin was asked how she would keep domestically produced oil and coal in the U.S. Here's her answer:

Of course, it's a fungible commodity and they don't flag, you know, the molecules, where it's going and where it's not. But in the sense of the Congress today, they know that there are very, very hungry domestic markets that need that oil first. So, I believe that what Congress is going to do, also, is not to allow the export bans to such a degree that it's Americans who get stuck holding the bag without the energy source that is produced here, pumped here. It's got to flow into our domestic markets first.

One courageous blogger, Hilzoy at Obsidian Wings, attempted to decipher Palin's response. Hilzoy thinks, with good reason, that Palin might have been suggesting a ban on oil exports.

That seems like a bad idea.

While Canada and Mexico are the two largest importers of U.S. crude oil and petroleum products, they're also our two largest suppliers. It's probably not smart to risk a trade war with them.

So perhaps John McCain overstated the case just a bit when he said that his running mate "knows more about energy than probably anyone else in the United States of America."

― Vincent Rossmeier

Congressional craziness

2008-09-21T18:49:00.000-07:00

Congressional craziness keeps United States in much hot water

WE KEEP LOOKING for an expert to explain why the economy is such a mess, but haven't seen anything thoughtful and comprehensive yet. So we'll offer our own. At least two big problems can be blamed in large part on foolish government decisions.

Why are energy costs so high, triggering inflation throughout the marketplace? Why, indeed, since the United States has huge untapped energy resources in oil, gas, coal and tremendous potential in nuclear energy. Then there are renewable sources like hydroelectric, wind and moving water energy.

Some of the problems are in developing technologies, but the nation's vast oil, gas and coal resources are largely off limits to exploration and production because Congress (with a little help from presidents like Bill Clinton) made them that way.

That makes the nation dependent on foreign sources, especially the Middle East, which is now an economic lifeline and must be defended with the lives of young soldiers and the fortunes of average taxpayers.

Many politicians have sold their souls to environmental activists and fight to block oil and gas drilling and coal mining within and around the country's borders. When the subject comes up of drilling in ANWR, a huge oil and gas reservoir, critics argue that it will take 10 years to tap ANWR. "That won't help today," they say. But legislation opening ANWR was passed by Congress in 1995, more than 13 years ago. The field could easily have been in production by now.

And why does it take 10 years to get a new field into production? Mostly government regulation and red tape. It's impossible to believe that process couldn't be speeded up and due consideration still given to environmental protection and public opinion.

Then there are the stock market gyrations triggered by a collapse in the mortgage lending field. Why did that happen? Because Congress mandated that poor people should be able to buy houses whether they could afford them or not. And the rules were loosened enough that liar's loans allowed even middle class people to buy larger and better houses than they could really afford if they wanted to bet that their income was going to go up later on.

Those who sold mortgages to people who couldn't afford the payments or were at risk of defaulting made their money on the paperwork. Afterward they laid off the loans on larger lenders who tried to make their money by buying mortgage paper in large amounts. It should be no surprise that eventually the system collapsed.

These things are all craziness, folks. They just should not be. The United States could be a wise shepherd for its natural resources and still extract them in a timely fashion without damaging the environment. Doing so would create millions of jobs as well as provide the nation with major sources of energy on its own soil.

America needs reform, all right. Most of these problems stem from congressional idiocy. How you fix that is a difficult question. We don't have the answer, just the question.
Read More

Palin requests a conference call with oil executives

2008-09-07T16:46:00.000-07:00

Governor Sarah Palin has requested a conference call this week with the CEO's of the major oil companies playing a role in the potential development of Alaska's natural gas pipeline.

The requested participants include Tony Hayward from BP, James Mulva from ConocoPhillips, Rex Tillerson from Exxon along with others. According to my source, no one knows exactly what the purpose of the call is, but some have never the less speculated.

Last week in her address to the nation, Palin stepped far over the line of truthiness (thanks Steven Colbert) when she told the country, "I fought to bring about the largest private-sector infrastructure project in North American history. And when that deal was struck, we began a nearly forty billion dollar natural gas pipeline to help lead America to energy independence."

Nothing could be further from the truth.

In fact the state has done little more to move the gas pipeline forward over the last twenty months than to grant a Canadian company $500 million to push paperwork with no guarantee a pipeline will be built.

Anchorage Daily News reporter Wesley Loy reported last month;

Palin said in her press conference that the state never before had commitments to build this line. Now we do. That's incorrect.

TransCanada has not promised to actually build the gas line, one of the state's grandest and most frustrated economic development dreams.

The state license, awarded under the Alaska Gasline Inducement Act, or AGIA, which the Legislature passed at Palin's request last year, is not a construction contract and does not guarantee a pipeline will be built."

Since becoming Alaska's governor in December of 2006, Palin's administration has had a very combative relationship with the oil & gas industry in Alaska and has ignored any attempts to communicate with them on development issues.

When the Alaska Gasline Inducement Act (AGIA) was introduced and passed by the legislature in 2007, the administration refused to entertain suggestions from the producers to make the process more commercially viable. At the end of the day the state had crafted a proposal that ignored all legal and fiscal realities.

So instead of negotiating with the producers, the administration said they'd rely on public and share holder pressure to force three of the largest oil companies in the world to commit to paying for the most expensive privately financed project in the history of the United States.

Even United State Senator Ted Stevens raised serious concerns about the process back in March saying; "financing terms won't be set by the legislature, the governor or the Congress. They're going to be set by the people who manage the money."

Today, the state has awarded a $500 million inducement and exclusive rights to TransCanada, while their CEO is on record as saying that they cannot order one piece of steel pipe without first gaining the financial support from the oil companies. "Nothing goes ahead unless Exxon is happy with it," CEO Hal Kvisle told the Toronto Globe and Mail in August.

So what could the agenda be on this requested phone call by Governor Palin?

Read More

Oil reserve totals depend on price

2008-08-16T22:52:00.000-07:00

By RICHARD W. RAHN

If you had to bet whether the price of oil would be higher or lower 10 years in the future, what would you say?

Some argue that the world is running out of low-cost oil and that oil prices will get higher and higher. Others argue that the current high price of oil will cause a flood of new oil, much of it from nonconventional sources; hence, prices will fall significantly (provided the political class in Washington, D.C., does not continue its energy and environmental death march policies).

The case for much lower oil prices is as follows. There are hundreds of years of oil supplies (at present and projected consumption levels) if oil in oil sands and shale is properly included in reserves. In some places, such as Saudi Arabia and Iraq, there is still much low-cost oil ($15 a barrel or even less) that can be produced for decades, but not in an amount sufficient to meet the world's demand; hence, much higher-cost oil is also pumped. This higher-cost oil includes much of the offshore oil (the huge cost of the mammoth drilling rigs has to be amortized over each barrel of oil produced) and on-shore oil in hard-to-reach places and/or produced from low-production wells.

Oil reserves are largely a function of price. Global proven reserves of conventional oil obtainable at prices of less than $40 per barrel are estimated at more than 1.3 trillion barrels, with much of it concentrated in the Middle East. Additionally, reserves of so called "heavy oil," the largest reserves of which are in Venezuela's Orinoco area, are estimated at 1.2 trillion barrels, and most of this . . .

could probably be recovered for less than $50 per barrel.

The reserves of oil sands, which are actively being mined in Canada's Alberta Province, are estimated to be 1.8 trillion barrels. Experts estimate that much of this can be produced for $45 per barrel or less. Global reserves of oil shale are estimated at more than 3.3 trillion barrels, with 70 percent in the United States (primarily in Colorado, Utah and Wyoming).

Shell Oil Co. last year announced it has developed a process for extracting the oil from the shale, without mining, at a price of roughly $35 per barrel. The United States also has the world's largest reserves of coal — enough for hundreds of years of production at present levels. Coal also can be turned into liquid petroleum (as the Germans and South Africans proved decades ago). Current estimates of the conversion cost are as low as $35 per barrel.

Does it seem a bit odd that the current price of oil is more than twice the cost of producing all the oil the world presently needs and will need long into the future? The reason the price is so high is that the supply has been artificially constrained by governments. Most (88 percent) of the conventional oil reserves are owned by governments, and these governments have underinvested in new production. As is well-known, the U.S. government has restricted offshore and onshore drilling, shale development, and coal conversion.

Some politicians argue, even if the U.S. government started to allow increased production, that it would be seven to 10 years or more before there would be additional output. This is nonsense. Oil wells can be drilled at an average rate of 1,000 feet or so per day, which means that the average U.S. well can be drilled in a week. It does take a few weeks to set up the pump and install the separation tanks, etc., but new land wells can be producing within months, even if the product has to be trucked rather than piped away.

Drilling in the Arctic National Wildlife Refuge in Alaska would not take all that long for some production to get started. Politicians often confuse the time it takes to get peak production from a field as compared to some production — each additional well takes time, plus the necessary new piping collection infrastructure for each additional well.

Offshore wells do take a lot longer, but most of the time involved is the government permitting process, not the physical production of the rigs, drilling and so forth. If the government gave a full green light to production of oil shale in the Rocky Mountains, it might take several decades to reach full production, but some production would be accomplished in the next couple of years.

The very same politicians who claim we cannot increase oil production quickly are often the same ones who tell us we need to move to alternative forms — windmills and solar, etc. — without seeming to understand these desirable technologies will take far more time to meet the goals of "energy independence" than ramping up oil production. Speaker of the House Nancy Pelosi said she would not allow a vote on more drilling because she wanted "to save the planet," without seeming to understand, if increased oil production does not take place in the United States with all its environmental safeguards, it will take place where U.S. environmental law cannot be enforced — and that is not healthy for the planet.

Fortunately, the people are beginning to understand they are paying twice more for a gallon of gasoline than is necessary, and the global environment is not benefiting. Less expensive energy and a cleaner environment are most likely to be achieved quickly not with alternative energy sources but with an alternative set of congressional leaders.

Interesting Times for Alaska

2008-08-08T17:38:00.000-07:00

ANOTHER ITEM from the Globe and Mail interview with TransCanada CEO Hal Kvisle got lost in the smoke and steam resulting from Kvisle's comment that "nothing goes ahead until Exxon is happy with it."

Kvisle also suggested in an interview last Sunday with the Toronto-based newspaper that Denali and TransCanada are likely to join forces sometime in the next two years.

At least that is the apparent implication of his statement . . .

that it's unlikely more than one open season will be held in 2010. "This is not about TransCanada dreaming up the project we think will work," he said. "It's about the five key parties getting together and crafting something here." The five parties are apparently the three big producers, TransCanada and the state of Alaska.

Kvisle noted that plans at this point call for both Denali, the company formed by ConocoPhillips and BP to build a gas pipeline, and TransCanada to hold open seasons in 2010. The open season is when customers are solicited to ship their gas through a pipeline.

The Globe and Mail reporter said Kvisle told him it's unlikely two open seasons will be conducted. That makes sense, since TransCanada couldn't really compete with a line being built by the companies that control North Slope gas — nor could it woo the companies away from using their own pipeline.

But it would mean at least one of the two entities would either delay an open season — TransCanada is obligated by its contract with the state of Alaska to hold an open season in 2010 and Denali is ahead of TransCanada — or Kvisle expects both sides to join forces sometime in the next two years.

So unless natural gas prices go in the tank sometime soon, which doesn't seem likely, the next two years should be an interesting time in Alaska.

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The true economically viable option Denali Alaska Gas pipeline

2 Days after Alaska's incompetent Legislators pass AGIA

2008-08-04T15:44:00.000-07:00

ENERGY- Alaska Goofs It Again

Exxon key to Alaska pipeline
DAVID EBNER

August 4, 2008

VANCOUVER -- TransCanada Corp. has won support from Alaska to build a $26-billion natural gas pipeline, but ground won't be broken until Exxon Mobil Corp. signs on, says TransCanada chief executive officer Hal Kvisle.

Calgary-based TransCanada, which secured Alaska's official backing Friday, is in competition with BP PLC and ConocoPhillips Co. to build a pipeline that would connect large untapped gas reserves on the north slope of the state to consumers in the continental United States.

But Exxon, the company that controls the most gas in Alaska, hasn't yet backed either of the competing proposals, though it has an active Alaska team monitoring the pipeline race.

"Nothing goes ahead until Exxon is happy with it," Mr. Kvisle said in an interview yesterday.

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For TransCanada to proceed, it will also need to attract the shipping business of rivals BP and Conoco, which control part of the natural gas.

"This is not about TransCanada dreaming up the project we think will work, it's about the five key parties getting together and crafting something here," Mr. Kvisle said.

That presents some big challenges. All of the companies would likely seek a longer-term deal with Alaska on such issues as taxes before deciding to make a long-term commitment to a pipeline.

Reaching such a deal could be an uphill battle because the relationship between the firms and Alaska is frayed after a previous pipeline proposal fell through two years ago. Further, while it looks like it's BP-Conoco versus TransCanada in Alaska, the relationships are much more tangled.

London-based BP is TransCanada's largest customer on its sprawling gas pipeline network, and Conoco, based in Houston, and TransCanada are partners on a major new oil sands pipeline.

In this foggy and seemingly fractured picture, Calgary-based TransCanada is positioning itself in the role of intermediary, hoping to own part of the pipeline while getting closely involved in its design and construction by pitching its pipeline expertise as an important card.

An ownership stake in any pipeline is something the producers want if they are to sign long-term contracts, Mr. Kvisle said.

But TransCanada also has the right, under federal Canadian legislation from the late 1970s, to build the Canadian portion of the line, the company says.

Mr. Kvisle said he thinks TransCanada can figure out a deal that will work for everyone and offer advantages such as savings amounting to several hundred million dollars with technology that eliminates the need for pressure-testing the pipeline.

Late Friday, the Alaska Senate approved a licence for TransCanada to start preliminary work with $500-million from the state - but also a long list of requirements to ensure that the line benefits Alaskans. The licence was issued under the Alaska Gasline Inducement Act, a process that Exxon, BP and Conoco rejected as unreasonable, and led BP and Conoco to independently propose a $30-billion pipeline called Denali.

TransCanada's new pipeline licence does not affect Denali, said Bud Fackrell, a BP executive who is now president of the venture, in an interview with Bloomberg News on Friday.

Mr. Fackrell added that an open season for contracts to ship gas on Denali will be conducted in 2010. It's the same year that TransCanada plans to do the same, as required by its licence, but Mr. Kvisle said it's unlikely two open seasons will be conducted.

While Alaska inches ahead, the proposed $16-billion Mackenzie Valley pipeline - whose lead backer is Exxon - in the Northwest Territories is much further along and is nearing the end of a long regulatory review.

Mr. Kvisle doesn't think the two ventures are in competition and said construction on Mackenzie could begin in 2010 while Alaska likely won't break ground before 2015.

And in Alaska, Exxon remains the deciding factor.

"Things aren't always as they seem," Mr. Kvisle said. "Exxon is not the front-and-centre party in the press but I know for a fact that they've got very hard work going." Rean More

Energy Rhetoric vs. Reality

2008-07-29T00:53:00.000-07:00

Energy Rhetoric vs. Reality
Policymakers are talking a lot about energy and energy policy. Some of the debate is thoughtful. But much of it displays a lack of understanding of energy markets and the factors that influence price. Many of the proposals offered fail to address the critical question we face: How do we meet growing energy demand both in America and around the world?

API has compiled some of the most frequently heard claims and proposals, along with the realities that need to be considered when evaluating them.

Policymakers are talking a lot about energy and energy policy. What follows are some of the most frequently heard claims and proposals emanating from the campaign trail, along with realities that need to be considered when evaluating these claims.

RHETORIC: Oil Companies are to blame for the high price of gasoline.

REALITY: There are many factors affecting the price of gasoline.

More than 80 cents of every dollar spent at the pump goes to the price of crude and taxes. The price of crude oil is set on global markets, not by oil companies, and it accounts for more than 70 cents of every dollar of gasoline price. And the government takes nearly twice as much in taxes (13 cents) as the industry makes in profit (fewer than 8 cents).
While gasoline prices have increased dramatically this year, the price of crude oil has increased by $1.21 per gallon in 2008, compared with the price of gasoline, which is up 80 cents per gallon.
Demand is strong in both mature economies and the developing world, especially in China, India and the Middle East. The market impact of tight supplies has been exacerbated by political instability, resource mismanagement and weather. Finally, the decline in the value of the dollar against other currencies has put American consumers at a disadvantage.

RHETORIC: Oil and natural gas companies are demanding greater access to America’s resources even though they own leases on millions of acres of federal lands that are already open to drilling. They would rather sit on these idle leases and make record profits than increase production. If they’re not willing to produce on these idle leases, they should hand them over to someone who will.

REALITY: Just because a lease is not producing oil or natural gas doesn’t mean it’s idle. Companies are actively exploring and developing the majority of their leases, but the entire process takes years and requires many steps, including securing government permits, analyzing seismic data and installing the machinery needed for drilling and production. Many leases prove not to contain enough oil and natural gas to be commercially viable, and companies can’t produce oil and natural gas where it does not exist. Over the past five years, American companies have paid billions to obtain federal leases, and if they don’t develop leases within a certain period of time, they return them to the federal government, forfeiting all investments.

Oil and Natural Gas 101

2008-07-16T18:32:00.000-07:00

Related Video
Building Block of Everyday Life
From our livelihoods to our lifestyles, the oil and natural gas industry improves the lives of Americans every day. This video highlights the uses of petroleum in our daily lives, as well as the many applications of petrochemicals. More >>

From the ground to the pump… or the playing field… or the medicine cabinet... each and every day Americans rely on the products created by oil and natural gas. And behind this vital product is an important story that needs to be told. Whether it’s:

Learning the value of oil and natural gas in fueling our way of life,
Recognizing that energy efficiency has its benefits,
But a rapidly growing world still needs greater supply; or
Developing a better understanding of how company performance contributes to the average American’s retirement portfolio;
We should all know the intangibles of this irreplaceable product.

In just one 24-hour period, the oil and natural gas industry delivers:

Enough energy to heat 80 million homes
382 million gallons of gasoline to service stations, enabling 200 million drivers to get to work, take their kids to school, and take vacations-- traveling 7.5 billion road miles every day
67 million gallons to airport terminals, enabling 30,000 flights to travel around the world
Every day, the industry employs 1.9 million people directly, and many more indirectly.