Alaska Oil| Is the Governor undermining SB 21 …

By Brad Keithly As thoughts begin to turn to the now-certain referendum on SB21 it is important to understand that there is one scenario under which the Governor himself could end up significantly undermining a key argument for maintaining the statute. The scenario relates to the interplay between SB 21 and the budget. Interestingly, the Governor likely has complete control over whether the adverse scenario develops. Unfortunately, current indications are that he is headed down the wrong path. The Reasons Supporting SB 21 On the surface, there are two major arguments supporting SB 21. The first is that it produces greater long term value to Alaskans from oil than ACES, the Continue reading →http://bgkeithley.com/

Anchorage Democrat (who supports Sarah Palin's centerpiece legislation to tax private industry and give awzy $500M) calls SB 21 a massive giveaway!

Anchorage Democrat calls SB 21 a massive giveaway, says state stands to lose too much under Gov. Parnell’s new tax regime By Steve Quinn House Rep. Les Gara has never been shy with his opinions, especially when it comes to the longstanding debate over oil taxes and efforts to rewrite the 2007 tax code Alaska’s Clear and Equitable Share, or ACES. Well, with ACES rewritten Gara remains vocal and believes a referendum to overturn Gov. Sean Parnell’s SB 21 not only has merit, but also has a chance of winning at the polls next August. Those supporting the referendum say they collected more than 50,000 signatures, nearly 20,000 more than needed. Gara believes the Legislature went too far, well beyond the intent of making a tax policy fair at high and moderate market prices. Gara spoke to Petroleum News about the prospects of a successful referendum and what he would like to see in advancing a natural gas pipeline project. Petroleum News: What is the thinking or the strategy behind the referendum to overturn SB 21? Gara: My view is SB 21 is a disaster for the state. It’s going to result in massive layoffs across the state. The give to the oil companies is way more than was necessary. We should have incentivized more with a better piece of legislation. So if the SB21 referendum passes, hopefully the Legislature will get the message, and Gov. Parnell will get the message, that giving away somewhere between $800 million a year to $2 billion a year to Exxon, Conoco and BP, the way they did it isn’t the way to do oil tax reform. It’s going to hurt the economy in the long run. After the referendum passes, obviously we need to go back and write something that makes sense. Instead of the provisions of SB 21 that basically give the money away on the premise that it hopes the oil companies will invest all of that back in Alaska, and invest enough money to offset what we are going to lose, so we at least break even. We can do something smarter. Something smarter is you get investment credits if you invest in Alaska. The biggest problem is you get a huge tax break – upwards of $1 billion to $2 billion a year – even if you don’t invest that money in Alaska. Petroleum News: Critics of the referendum say that this could have a chilling effect on investment. What are your thoughts on that? Gara: SB 21 is a huge disaster for our state. We need to come out from under this. We are not going to have money for schools. We’re not going to have money for new construction and energy projects around the state. You can’t pass something that is harmful to the state and say gosh we better not change this. Petroleum News: OK, but how do you answer the criticisms that the referendum will have a chilling effect on investment? Gara: People are just coming up with arguments. The pro-SB 21 people will say anything they can to stop the initiative. They claimed credit for production that was already going into effect. Mustang, that was a project by Brooks Range Petroleum. They announced two years ago they were going to produce that oil. The pro-SB 21 people say, hey Brooks Range is coming on line because of SB 21. Repsol announced two years ago they were going to invest at least three quarters of a billion dollars in Alaska, and if they found oil, more than that. Well they found oil in the spring and the governor said, hey this is because of SB 21. Folks who are going to try to stop the referendum will say anything they can. Petroleum News: What other provisions do you not like about SB 21? Gara: We went from roughly an effective production tax rate at 37 percent — something that was too high at high prices, and that should have been fixed — we went from that to a production tax on new oil that is going to be in the $110 somewhere at 10 to 14 percent. This state cannot run on 10 to 14 percent oil tax. At some point all oil will qualify as new oil. We will have a whole generation that will not have the schools, not have the services they need in the state because we will have vastly under-taxed the state’s oil resource. A 10 to 14 percent tax on $110 barrel of oil makes no sense. That’s a giveaway. That’s the second part of the giveaway. The first part is you get $800 million a year to $2 billion a year that goes to Exxon, Conoco and BP just for existing. They don’t have to invest in Alaska. Those are two major parts of the giveaway that need to be changed. The rate of 10 percent to 14 percent is way too low, and the give away of $800 million to $2 billion a year depending on whether oil is $100 or $130 a barrel. Those two parts are going to harm the state immensely. In other words, under SB 21, if prices are the $100 range, the state loses about $800 million a year in revenue compared to ACES. If prices are in the $120 barrel range, then we lose about $2 billion a year. That’s all related to the elimination of the state’s windfall profit share that says when companies are making record profits, the state should share in a more fair tax rate. We should have done smart oil tax reform. Petroleum News: Both sides of the argument say their position is driven by the constitution. How do you reconcile that? Gara: (Former Gov.) Jay Hammond would say the constitution is the first place you look. You’re supposed to get maximum benefit for our resources. The constitution doesn’t require any particular statute. My view is it should be driven by logic. Logic says we shouldn’t tax too high. We should tax in a way that requires investment in Alaska if you’re going to give incentives. We should tax in a way that is fair to the industry and fair to the people of Alaska. We could have done that. Many people in the hallways – Republican and Democrat – said we should have tweaked ACES instead of gone with this brand new system that frankly is a giveaway. The oil companies used to say the only problem with ACES was that at high prices the tax was too high. And I agree, at very high prices – $130, $140, $150 a barrel – we taxed a little too high. We should have tempered that down. All of the sudden the story changed this year, and we had a bill that had nothing to do with reducing taxes at high prices. It reduced the rate at almost all prices. We reduced it from an effective rate (minus credits and deductions) of about 37 percent to an effective rate on legacy field oil of about 20 percent, and an effective rate on new oil of about 10 to 14 percent on $110 a barrel. That’s going to hurt the state badly. Petroleum News: If that’s how it played out, then how do you think it got this way if the initial issue was the progressivity? Gara: We have a governor who sees things the same way as the oil company executives at the oil companies. He got rid of experts who would have treated Alaska more fairly. They were never allowed to show up in the Capitol (Bob George and Rich Ruggerio). They state had them on contract so nobody else could hire them. They hired folks who promoted a much lower tax, someone whose view was taxes can never be low enough, so what we had was a race to the bottom. Petroleum News: Do you believe there was an honest debate over the issue of oil tax reform? Gara: I feel the legislators had a very honest debate. I don’t feel like the administration’s expert (Econ One’s Barry Pulliam) was very forthright. I found him to be very evasive. I found him be very argumentative. I found him to be wedded to promoting what the administration wanted instead of being wedded to providing the Legislature with accurate information that was objective and balanced. They hired an advocate, not someone who objectively consulted with the Legislature. Petroleum News: How much faith can you place in a referendum effort when you think of how the coastal zone management ballot failed so handily? Gara: If we had a vote today, the referendum would pass. The public understands this was a giveaway. If you’re Exxon, Conoco and BP, and (you) see new oil tax at $120 a barrel, which is a reasonable high-end price that we can expect the next couple of years, then this bill gives them about $2 billion in tax breaks even if they do nothing in Alaska. For $2 billion, and if you’re an oil company, you’re going to find a way to spend millions and millions of dollars to convince the public to defeat the referendum. And we know in this world of political advertising, they tend to be very misleading. Political ads, by and large, especially when money is involved, tend to be deceptive. I think we are going to see a lot of deception over the next year and a half. Right now the polling I’m seeing is that the public does not support this oil tax giveaway. They understand that an oil tax giveaway gives money to companies who don’t have to reinvest in Alaska and can take their money to another country like Libya and Azerbaijan and Russia. They understand it’s not a good idea. That’s today. Even next August is a long time from now and memories fade. The folks who want a fair oil tax for the people for Alaska, we are not going to have a huge amount of money, so we’re going to have to try and educate the public without much money against the money Exxon, Conoco and BP, and their allies can. Their goal is going to be to sway the public to their side and that can happen with money. Petroleum News: Moving onto natural gas, what would you like to see happen to advance a pipeline project? Gara: If we can make the big line work, that is the thing that helps Alaska the greatest in terms of lower gas prices for Alaskans and revenue for Alaskans. The small line won’t result in any or much revenue because we don’t tax gas that’s used by Alaskans. If it’s just an instate line, we won’t get any revenue. More importantly it’s not cost efficient. It’s an 800-mile line that delivers very little gas. It’s like the difference between transporting lumber by train, where you can transport a lot of lumber, or transporting lumber with a series of trips by a Volkswagen. That’s why gas delivered by a small line is about twice the cost to Alaskans. If we are going to treat Alaskans fairly so they can afford gas, a big line makes the most sense. It’s cheaper gas. Second point is that it produces revenue for Alaskans. We lost oil revenue. We need revenue in this state to fund roads, schools and hopefully savings. Exporting gas from Alaska produces income. The gas sales produce revenue. And a big line, which would export about seven times as much gas as a small line, will produce cheaper gas, and make it more likely that we will get an export contract. We won’t get an export contract if we are shipping expensive gas. Right now, we’re spending a lot of money on analyzing a bunch projects. Susitna hydro we are subsidizing to analyzing to the tune of $100 million a year. Some people want to subsidize the small line that produces very expensive gas to the tune of $3 billion. I would like to see an analysis that says what happens if we put that money into a big line. What happens if we put a portion of that money into the big line? Does that make the project a go. Maybe it involves state ownership with that amount of money. Maybe it involves state financing. One thing we can do is take ownership of a portion of that line and only require an 8 percent rate of return. Trans Canada – a pipeline owner – will require a 12 to 14 percent rate of return. The math on that is if we get an 8 percent rate of return, we would make money, but less money, and that would reduce the transportation costs on the big line. That would reduce the cost of gas. Maybe that would make a big line a go. The big line has to produce cheap enough gas to export it and the export market is Asia. Everybody used to think the export market was the Lower 48, but that was until shale gas came along. Now it’s Asia. We have to act quickly. I don’t see anybody doing an analysis like that. I’m not sure what the governor is doing. I’m not sure if he’s analyzing his options. I hope he is. Petroleum News: So what do you think can be done? Gara: What’s going on behind the scenes is they are using their nuclear options. They are saying they are not going to let go of the gas unless we come to our knees and give them as low a gas tax as possible. They have all the negotiating power in the world unless we use our leverage, and our leverage is that every gas lease in this state is called a duty to produce. You can’t just warehouse gas if producing it would be economical. You can’t go to a gunfight with a pocketknife and right now we are in a gunfight with a pocketknife. The oil companies are using their leverage by saying unless you lower your gas tax to almost nothing, we aren’t going to produce. The state is not saying unless you produce gas, which is economical, we are going to litigate transferring those leases to a company that will produce the gas. I’m not saying the duty to produce legal argument will work 100 percent. We don’t know how that litigation will go. It will take a while, but it’s leverage. I don’t say we should file a lawsuit tomorrow. You have to negotiate in a sophisticated manner when you are dealing with sophisticated companies.

Alaska gets pipeline, just barely

July 17 marked the 40th anniversary of a pivotal moment in Alaska history. It came in 1973 in the U.S. Senate. “Vice President Spiro Agnew cast the tie-breaking vote on an amendment offered by Senators Mike Gravel and Ted Stevens to remove all environmental and legal impediments to the pipeline carrying oil south from Alaska’s North Slope,” the Senate’s official Alaska timeline says. The vote capped an epic environmental battle over the pipeline. Later that year, the Arab oil embargo would provide the final push needed to bring about the long-delayed construction of the 800-mile line. Daniel Yergin, in his book “The Prize,” talks about the complicated road to the pipeline after the elephant Prudhoe Bay field was confirmed in 1968. Lots of ideas were considered to get the remote, arctic crude to market: icebreaking tankers, trains and trucks, jumbo jet tankers, nuclear-powered submarine tankers. A pipeline route into Canada also was considered, but ultimately the choice was for an “all-American route” to the ice-free port of Valdez, where the crude could be loaded aboard conventional tankers that could go to the Lower 48 or to Asia. An oil company group including ARCO, BP and Standard Oil of New Jersey (Exxon) organized to build the line. The consortium “rushed out and hurriedly bought 500,000 tons of forty-eight-inch pipe from a Japanese company; they did not think there was time to wait for American manufacturers to gear up,” Yergin wrote. “They were wrong. The pipeline was to come to a dead halt before it even started.” Alaska Native land claims and “wrangling among the partners” slowed the project. But the real impediment was an effective legal challenge from environmentalists. Tens of millions of dollars of stockpiled pipe and heavy equipment languished for years in the cold. The Native claims were mostly settled in 1971, and eventually the environmental battle came to Congress. Construction finally begins On a vote of 50 to 49, with Agnew casting the decisive vote as the body’s president, the Senate passed the Gravel-Stevens amendment declaring that the Interior Department had met all the requirements of NEPA, the National Environmental Policy Act, for the pipeline project. Three months later, in October 1973, the Organization of Petroleum Exporting Countries, or OPEC, would impose an oil embargo that shocked the nation. Not long after, on Nov. 16, 1973, President Nixon signed right-of-way legislation, the Trans-Alaska Pipeline Authorization Act, into law. Construction began in 1974, first oil flowed from Pump Station 1 in 1977, and the pipeline has since moved more than 16 billion barrels of crude. Oil revenue utterly transformed Alaska and its economy. And the hope is that the pipeline can continue to operate for many years to come, although throughput has declined to around 550,000 barrels per day, or roughly a quarter of the peak of more than 2 million barrels in 1988. Alaska Sen. Lisa Murkowski, the top-ranking Republican on the Senate Energy and Natural Resources Committee, commemorated the historic 1973 vote with a July 17 press release. “It was a monumental decision that has shaped the trajectory of Alaska to this day,” Murkowski said. She added: “A vast amount of oil remains as yet untapped in Alaska, most of it trapped on federal lands. It’s my hope that on this 40th anniversary of the pipeline, we’ll start to pay greater attention to the looming problem of losing a major portion of our country’s domestic oil production if more federal lands in Alaska aren’t opened to responsible development.” Click here to go directly to this story within the full PDF version of this issue, with any maps, photos or other artwork that appears in some of the articles.

53 senators urge approval of Keystone XL pipeline

WASHINGTON (AP) - More than half the Senate on Wednesday urged quick approval of the Keystone XL oil pipeline, ramping up pressure on President Barack Obama to move ahead with the project just days after he promised in his inaugural address to respond vigorously to the threat of climate change. A letter signed by 53 senators said Nebraska Gov. Dave Heineman's approval of a revised route through his state puts the long-delayed project squarely in the president's hands. "We urge you to choose jobs, economic development and American energy security," the letter said, adding that the pipeline "has gone through the most exhaustive environmental scrutiny of any pipeline" in U.S. history. The $7 billion project would carry oil from Canada to refineries along the Texas Gulf Coast. "There is no reason to deny or further delay this long-studied project," said the letter, which was initiated by Sens. John Hoeven, R-N.D., and Max Baucus, D-Mont., and signed by 44 Republicans and nine Democrats. Another Democrat, Jon Tester of Montana, supports the pipeline but did not sign the letter. At a news conference Wednesday, senators said the pipeline should be a key part of Obama's "all of the above" energy policy, in which he has expressed support for a range of energy sources from oil and natural gas to wind, solar and coal. The Obama administration has twice thwarted the 1,700-mile pipeline, which Calgary-based TransCanada first proposed in late 2008. The State Department delayed the project in late 2011 after environmental groups and others raised concerns about a proposed route through environmentally sensitive land in Nebraska. Under pressure from congressional Republicans to make a decision on the pipeline, President Barack Obama blocked it in January 2012, saying his concerns about the Nebraska route had not been resolved. TransCanada submitted a new application last spring. The State Department said Tuesday it does not expect to complete a review of the project before the end of March. The State Department has jurisdiction over the pipeline because it crosses a U.S. border. The renewed focus on the pipeline comes as Obama pledged during his inaugural address to respond to the threat of global warming. Environmental groups and some Democratic lawmakers argue that approving the pipeline would directly contradict that promise. "If we are going to get serious about climate change, opening the spigot to a pipeline that will export up to 830,000 barrels of the dirtiest oil on the planet to foreign markets stands as a bad idea," said Anthony Swift of the Natural Resources Defense Council. The pipeline would carry heavy oil derived from tar sands in western Canada. The heat-intensive process uses more energy than traditional oil, producing more heat-trapping gases that contribute to global warming. Environmental groups have been pressuring Obama to reject the pipeline, citing the oil's high "carbon footprint." They also worry about a possible spill. At a news conference Wednesday, senators from both parties said the Nebraska decision leaves Obama with no other choice but to approve the pipeline, which would carry up to 800,000 barrels of oil a day from tar sands in western Canada to refineries in Houston and other Texas ports. The pipeline also would travel though Montana, South Dakota, Nebraska, Kansas and Oklahoma. "No more excuses. It's time to put people to work," Baucus said. "Back home, we call this a no-brainer," added Sen. Joe Manchin, D-W.Va. Hoeven, of North Dakota, said the tar sands oil will be produced whether or not the U.S. approves the project. "Our choice is, the oil comes to us or it's going to China," he said. Nebraska's approval of the pipeline means all six states along the proposed route now support the project, said House Speaker John Boehner, R-Ohio. Majorities in the House and Senate also have endorsed the pipeline. National polls repeatedly show a majority of Americans back the project. Boehner said he recognizes the political pressure Obama faces from environmental groups and other opponents, but said "with our energy security at stake and many jobs in limbo, he should find a way to say yes." White House spokesman Jay Carney said Tuesday that the State Department was reviewing the project and he did not want to "get ahead of that process." Once that review is completed, "we'll obviously address that issue," Carney said. Meanwhile, Secretary of State nominee John Kerry said he plans to divest holdings in dozens of companies in his family's vast financial portfolio to avoid conflicts of interest if he is confirmed by the Senate. Kerry, a Massachusetts Democrat, said he would not take part in any decisions that could affect the companies he has holdings in until those investments are sold off. Among the investments are holdings in two Canadian companies, Suncor and Cenovus Energy Inc., both of which have publicly supported the Keystone XL pipeline. Kerry's investments are in family trusts.

Murkowski comments on U.S. energy policy

In a speech to an energy policy forum hosted by George Washington University and Arent Fox LLP on June 5 Sen. Lisa Murkowski, R-Alaska, spelled out her ideas on the needed goals for a U.S. energy policy. Murkowski is the ranking Republican on the Senate Energy and Natural Resources Committee. Commenting that the nation does not currently have a coherent or long-term policy at the federal level, Murkowski said that a policy should be non-partisan and should address the need for energy that is abundant, affordable, clean, diverse and secure. “One thing I won’t do is stand here and tell you which resources, which technologies — or even which exact policies — will enable us to meet our energy goals,” Murkowski said. “Some of that will be laid out in the energy plan I intend to release this summer. For now, I’ll simply say that it’s inappropriate for the federal government to focus on one technology, to the exclusion of others. Markets and consumers will make the choice far better than anyone else. What policymakers should focus on instead is outcomes, and we should be open to a number of routes that could help us get there.” Six factors Murkowski outlined six factors that she said would underpin the successful development of legislation to address the energy policy question. First, legislation must be developed through the Congressional committee process, rather than through some other group of lawmakers brought together to work on energy legislation. Second, there needs to be a balance between different energy technologies, encouraging oil and gas production on federal lands while also focusing on innovation. Third, people need to “make some hard decisions” on the extent of the government’s role in technical innovation. “The federal government can help fund research that would otherwise not be undertaken, but our job is not to offer subsidies that never end or subsidies that prop up a technology every step of the way to commercialization,” Murkowski said, citing Department of Energy involvement in North Slope methane hydrate research as a good example of government research funding. Fourth, energy policies must pay for themselves, Murkowski said, commenting that federal economic stimulus funding for clean energy had resulted in a lower payback than anticipated. Fifth, legislation should not directly or indirectly increase the price of energy. And sixth, the energy legislation needs to be brought for consideration on the Senate floor, rather than languishing low down in the legislative priority list as has tended to happen in recent years. Loan guarantees Murkowski later commented in response to a question that, despite the recent tainting of the use of government loan guarantees, with funds going into unsuccessful renewable energy development, she believes that the government does have a role in encouraging new technologies but that “there has to be a kind of glide path out” of a project. “Some are suggesting the plug just needs to be pulled (on the loan guarantee program),” Murkowski said. “I don’t think that needs to be the case. I think we need to make sure that the loan guarantee program operates as Congress intended.” —Alan Bailey

NPR-A draft plan comment period extended

NPR-A draft plan comment period extended The federal Bureau of Land Management has extended the comment period for the National Petroleum Reserve-Alaska draft plan to June 15. comments for the NPR-A sale should be mailed to: State Director, Bureau of Land Management, Alaska State Office, 222 W. 7th Ave. Mailstop 13, Anchorage AK 99513-7504. BLM-Alaska State Director Bud Cribley said in a statement that the agency received requests from several stakeholders to extend the comment period. “The plan is complex,” Cribley said, and the agency “... decided that we could balance the need to complete the plan in a timely manner and the need to be responsive to our stakeholders by extending the comment period for an additional two weeks.” Four alternative future management strategies are proposed in the draft plan, which is the first to cover the entire NPR-A, including lands in the southwest portion of NPR-A not included in previous plans. The plan includes decisions on availability of acreage for oil and gas leasing, surface protections, Wild and Scenic River recommendations and Special Area designations. The comment period began March 30 and with the extension will run 77 days.

A piece of the methane hydrate puzzle

Known to exist in vast quantities in many parts of the world but with as yet no means of commercial production, methane hydrate could eventually become a prolific source of natural gas. This winter’s test of the production of methane, the main component of natural gas, from the Iġnik Sikumi No. 1 methane hydrate test well on Alaska’s North Slope represents a notable step for methane hydrate research in that, among other achievements, it succeeded in producing methane from hydrate for a record-breaking duration of 30 days. However, determining the next steps in researching gas production from hydrates will depend on the analysis of data obtained from the test, David Schoderbek, ConocoPhillips director, gas hydrates, told Petroleum News May 10. A team involving ConocoPhillips, the U.S. Department of Energy, and the Japan Oil, Gas and Metals National Corp. conducted the test. Methane hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside an ice-like lattice of water molecules. The material is only stable within a narrow range of temperatures and pressures: Move the temperatures and pressures outside that range, and the material dis-associates into methane and water. Using carbon dioxide Researchers have been investigating the possibility of extracting methane from hydrate by de-pressuring a subsurface hydrate accumulation, thus moving the hydrate out of its stability range and causing dis-association of the material. However, ConocoPhillips with its partners has been researching an alternative approach involving the injection of carbon dioxide into the hydrate, causing the carbon dioxide to exchange with methane in the hydrate lattice. The process releases methane while also trapping carbon dioxide inside the hydrate. Schoderbek said that in laboratory tests scientists had successfully displaced all methane from hydrate samples by flooding the samples with carbon dioxide over an extended time period. This technique, if replicated in the field on a commercial scale, might provide a means of sequestering unwanted carbon dioxide as well as enabling natural gas production from the hydrates. According to information in the Department of Energy website, the use of carbon dioxide for gas production from methane hydrates could present additional benefits: The procedure does not liberate water from the hydrates, would not impact the mechanical stability of the hydrate deposits and, unlike de-pressurization of the hydrates, would not cause the formation of pore-clogging ice or secondary hydrates as a consequence of dis-association-induced cooling. The purpose of the test with the Iġnik Sikumi well was to see if the results from the laboratory test could be replicated in field conditions, Schoderbek explained. Test location The North Slope is an especially suitable location for this type of test because of the known existence of hydrate accumulations in cold rocks under the permafrost, with a high saturation of the hydrates in clean sandstone close to an existing oil and gas infrastructure, Schoderbek said. ConocoPhillips used log data from existing wells to home in on a suitable site for the test well, eventually opting for a location next to an existing well pad within the Prudhoe Bay unit. The test location was close to wells known to have passed through methane hydrate deposits under the permafrost, in a situation where subsurface pressures and temperatures appeared close to those used in the laboratory tests. The well location was conveniently close to infrastructure on the existing well pad. At the same time the use of an ice pad as a base for the drilling would avoid any conflict with regular oilfield operations, Schoderbek said. The research team used subsurface and seismic data to extrapolate the position of hydrate bearing sands from under the existing well pad out to the location of the test well. Drilled in 2011 ConocoPhillips drilled the well in April 2011 to a depth of 2,597 feet, 900 feet below the permafrost and also below the base of the hydrate accumulations. Subsequent well logging with gamma ray, resistivity, sonic, density, and magnetic resonance imaging logs provided necessary data for the characterization of the methane hydrate reservoir, in particular for determining the hydrate and water saturations in the pores of the subsurface reservoir sands. “That allowed us to make a higher quality estimate of what conditions would exist during the test,” Schoderbek said. “So we were able to narrow down what the basis of the (test) design needed to be.” This winter, having completed the test design, the team rebuilt the ice pad; re-entered and perforated the well; and installed a downhole screen to prevent sand from clogging the well bore. The team then injected a mixture of nitrogen and carbon dioxide into the methane hydrate reservoir over a period of 13 days, thus replicating what had been done on a smaller scale in the laboratory. Gas mixture For this phase of the test, the nitrogen and carbon dioxide were transported in liquid form to a built-for-purpose gas mixing skid at the well site. In the skid the liquids were gasified and pressurized for injection down the well. The team also mixed in a couple of other gases to act as markers, used later to determine how much of the injected gas returned to the surface during the production phase of the test. After injecting the gases into the subsurface rock formation, the team spent a couple of days converting the well for production by, among other things, re-directing the gas injection equipment and installing a downhole pump in the well — the pump, powered by produced water from the Iġnik Sikumi wellbore, would be necessary to cause fluid to flow to the surface from the producing formation. In the production test the downhole pump drove a mixture of methane, carbon dioxide, nitrogen and tracer gases to the surface, where the production of the various gas types was measured. No delay The team had determined that there would be no technical advantage to shutting in the well long enough to allow the complete replacement of methane in the hydrate by carbon dioxide as had been done in the laboratory test, Schoderbek explained. By the time that the gas injection process had been completed, the reservoir close to the well bore — the section of the reservoir that would likely produce first — would have already been permeated with carbon dioxide, he said. The measurement of what came out of the well in comparison with what was pumped in would enable the effectiveness of the carbon dioxide replacement to be determined. With the pressure in the reservoir drawn down by the downhole pump, the procedure transitioned from a test involving carbon dioxide replacement of methane to a multi-day test of methane production through depressurization. Data analysis Chemical engineers, reservoir engineers and reservoir modelers are now analyzing the huge volumes of data obtained from the test to determine the extent to which methane production resulted from carbon dioxide exchange rather than depressurization, Schoderbek said. Until this data analysis has been completed and the results of the test assessed it will not be possible to say what might be an appropriate next step, or for that matter what the research timeframe might be, he said. And, with many uncertainties remaining regarding the practicalities of large-scale methane hydrate development, the possibility of commercial gas production from the resource is still many years away. “The hydrate resource, globally, could be larger than all conventional hydrocarbons, but turning it into a reserve is far into the future,” Schoderbek said. http://www.petroleumnews.com/pnads/307447534.shtml

Special session called on oil taxes, in-state line; bill based on Senate’s new field tax

By Kristen Nelson Petroleum News It looked like Senate Finance had an oil tax compromise senators could live with when, after weeks of work on the measure, it moved Senate Bill 192 out of committee April 11. But SB 192 never reached the Senate floor. The bill, a fundamental change of Alaska’s oil and gas production tax system with different tax rates for existing production from legacy fields, incremental production from legacy fields and new oil, couldn’t garner enough support from members of the Senate Bipartisan Working Group. On April 14 another plan surfaced, a tax change affecting only production from new fields. Senate Finance added that measure to House Bill 276, credits for exploration and seismic work in frontier basins (see story in this issue). The Senate passed HB 276 by a vote of 17 to 3, but it got no traction in the House, with portions of HB 276 moved to other legislation and HB 276 withdrawn by its sponsor. The tax change proposed by Gov. Sean Parnell last year, an across-the-board production tax cut, passed the House last year but stalled out in the Senate, with senators saying they needed more information before making tax changes. So the session ended with no major changes in the state’s oil tax system. Within the hour of legislators gaveling out the governor had called a special session to begin April 18, with the oil tax issue, House Bill 9 (the in-state gas pipeline bill) and HB 359, sex trafficking, on the agenda. ‘A new dynamic’ At an April 16 press conference the governor said he was interested in the approach the Senate took in HB 276, and said with the “Senate’s action there’s a new dynamic now at work that I think might lead to a compromise that could produce new production, both now and in the future.” Parnell said the Senate proposal wasn’t the whole answer because any new oil discovered as a result of the credits wouldn’t be going into the pipeline for a number of years, and he was concerned “that vast resources in our legacy fields will remain untapped.” The governor also said the Senate’s approach, focusing only on new fields, “will cost the state billions of dollars across 10 years while we have declining production and no new revenues from new production.” He cited the example of a company proposing to spend $9 billion in the state over the next 10 years on new fields. Under the state’s existing tax structure that company would get credits of between 45 and 65 percent, “so the state will pay half of the cost of that exploration across the next 10 years,” meaning the state would have to come up with $4 billion to $6 billion in that timeframe, while production from existing fields is declining. The governor said he wants to see a proposal which would incentivize new production from existing fields, along with new field production, and believes that with “a significant tax change in existing fields” the state could see as much as 100,000 new barrels a day “within a year and a half or two years.” “I want to see whether we can take what the Senate has already agreed is meaningful in the new field context and make it material enough to do the same in existing fields,” Parnell said. If the Legislature reaches an impasse, Parnell said he would understand. “But I think it’s worth a try to create a competitive environment where more production can be produced,” he said. HB 9 On House Bill 9, a bill moving along work on a small-diameter in-state gas pipeline, Parnell said that if the key provisions in HB 9 don’t pass, “Alaska’s gas line efforts, in my view, will be set back for one to two years.” The governor said he was asking the House and Senate to waive the uniform rules and take up HB 9 where it was when the session ended; both bodies did that April 18. Parnell said he disagrees with House Speaker Mike Chenault on whether the Alaska Gasline Development Corp. needs to come back to the Legislature before a pipeline gets built, and said he’s “not trying to empower AGDC at this moment to go and contract and have an open season and sanction a pipeline; I think we have to have some gates they have to go through where they are held accountable by the Legislature and by the executive.” On the other hand, the governor said he doesn’t agree with legislators who believe AGDC’s “efforts should be killed off.” “I’m not in that camp,” he said, explaining that the state needs alternatives — the large line from the North Slope to markets and the smaller in-state line — because without an option, the process would slow down, as it did under the Stranded Gas Act negotiations “when one party’s negotiations were swept off to the side and ... the process slowed down and the state had no other alternative.” The new bill The governor submitted a new oil tax bill to the House and the Senate April 18, describing it as “a piece of legislation that blends the positions of the House and Senate into a comprehensive approach that will bring economic opportunity to Alaskans for generations to come.” New North Slope oil and gas production is incentivized with a 30 percent exclusion, based on gross value at the point of production or GVPP, from the production tax value used to calculate the base rate and progressivity for the first 10 years of sustained production. This applies to fields not in production or in a unit on Jan. 1, 2008 — which would exclude Point Thomson but include Oooguruk and Nikaitchuq. For currently producing North Slope fields, there is an exclusion, but only from the value used to calculate progressivity: 40 percent of the GVPP would be excluded from the monthly production tax value used to calculate progressivity; progressivity would be capped at 60 percent. The bill also extends tax incentives for well lease expenditures available elsewhere in the state to North Slope activities and allow producers to apply tax credits in one year. The new-oil provision So what would the 30 percent exclusion in calculating base rate and progressivity for the first 10 years of sustained production look like? Senate Finance had PFC Energy model the lifecycle effects for a new small development — a 70 million barrel field with peak production of 10,000 barrels per day at $100 oil. Finance co-Chair Bert Stedman, R-Sitka, said at the April 14 hearing when the proposal was first aired publicly that the “concept of the 30 percent gross revenue allowance was derived out of our previous work on trying to enhance new oil production” with a gross progressivity calculation, and is an approach to incentivizing oil outside of existing developments within the current ACES structure. Gerald Kepes, a partner in PFC Energy and head of the consultancy’s upstream and gas practice, showed models run at the 30 percent gross revenue allowance for new developments at three different development costs: $17 per barrel; $25 per barrel; and $34 a barrel. Kepes said with a $17 per barrel capital cost under the current tax, Alaska’s Clear and Equitable Share or ACES, a lifecycle analysis showed a net present value or NPV of $112 million and an internal rate of return or IRR of 16 percent, with total government take ranging from 67 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil. With the gross revenue allowance of 30 percent applied to ACES, NPV rose to $201 million and IRR to 20 percent; government take ranged from 56 percent at $60 oil to 64 percent at $100 oil and 66 percent at $150 oil. “So it’s a substantial difference for these lower-cost new developments,” Kepes said. Capex of $25 a barrel At development costs of $25 a barrel for the same new development, which Kepes said “is more in line with the costs that we see with these new developments ... away from existing infrastructure,” NPR under ACES would be $24 million and IRR 11 percent, with government take ranging from 68 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil. At the $25 a barrel capital cost with the 30 percent gross revenue allowance, NPV is $121 million and IRR 14 percent, with government take ranging from 51 percent at $60 oil to 62 percent at $100 oil and 67 percent at $150. At a capital cost of $34 a barrel, which Kepes characterized as “among the higher or highest cost rates that we’re looking at,” under ACES NPV is a negative $90 million and IRR 7 percent, with government take ranging from 80 percent at $60 oil, to 77 percent at $100 oil and 79 percent at $150 oil. With the 30 percent gross revenue allowance, NPV on this type of project is a positive $3 million and IRR 10 percent, with government take ranging from 49 percent at $60 oil to 62 percent at $100 oil and 66 percent at $150 oil. Legislators received a letter from 70 & 148 LLC, a partner with Repsol in new developments which have been cited at capital costs of $9 billion over 10 years, expressing “strong support” for passage of the new oil provisions Senate Finance added to HB 276, calling the new field tax changes “exactly what is needed in order to have the oil industry focus on Alaska over other oil producing regions,” but also noting that the company hopes modifications can be made in the tax code “that will make operations within the legacy fields more competitive as well.”

Tax Reform: Who needs it?

Oil tax reform: Who needs it anyway? By Andrew Halcro March 30, 2012: On Wednesday over a thousand Alaskans showed up for a lunch time rally for meaningful oil tax reform. As I looked around the room I asked myself; who are these people and who needs oil tax reform anyway? Honestly, who should care that one in three Alaskan jobs are directly or indirectly related to oil industry. Who should care that those attending the luncheon were engineers, oil & gas subcontractor employees, tele-communication employees, retail store owners, union laborers, freight company employees, trucking companies, construction employees, native corporation employees and more small business owners than you could count? Who should care that oil production is declining, state spending is increasing and by 2020 the Department of Revenue predicts that fifty percent of projected oil production will come from investments yet to be made in a fiscal environment that is currently chasing investment away? Who should care that oil revenues fund everything from classrooms, to courts to cops? Who should care that oil funds organizations like the University of Alaska, which has cultivated professors, whose salaries are paid for by oil revenues, who have been opposing oil tax reform in every major newspaper in Alaska? Who should care that one of those professors got his tail handed to him on this very blog after being caught spreading misinformation to make his case against tax reform? Who should care that the latest proposal by another UAF professor is akin to the Lumpy plan; I'll gladly pay you tomorrow for a hamburger today? And while tax reform opponents use the same Lumpy argument about the producers asking for a tax break today in return for investments tomorrow, over the last six years the legislature has a history of raising taxes retroactively and has proven to be a not so trustworthy bunch when it comes to honoring guarantees. In fact, the state has been the equivalent of a hamburger loan shark. But who should care if the opponents of meaningful tax reform who demand guarantees, are the same ones who told the industry the state didn't need to give guarantees when it came to tax certainty on a $40 billion dollar natural gas pipeline? Think about it. The same lawmakers who are demanding certainty from producers over oil production, are the same ones who refused to grant certainty to the producers for building a $40 billion dollar natural gas pipeline. And who should care that opponents of tax reform have no facts on their side and instead are peddling Alaskans half-truths, revisionist history and down right false information? Who cares that they trumpet oil company profits while bitching about gas prices when the two are mutually exclusive? Who should care? Every Alaskan should care. That's why over one thousand men and women whose job security rests on a healthy oil & gas industry showed up at Wednesday's luncheon rally to support meaningful tax reform. The debate over meaningful tax reform has created a gaggle of opponents who have dug in their heels while offering no legitimate alternatives to boosting production under current tax rates. Furthermore the've purposely glossed over the harsh reality that as oil continues to decline and lawmakers begin dipping into savings, the more state government will be looking at Alaskans pockets to start paying for all the state services they've received for the last thirty years free of charge. The arguments against meaningful tax reform have come from a variety of directions including labor unions who have a vested interest in higher government revenues, hoping they'll translate into more government spending and longtime industry critics like radio mouth Bob Lester who has posted a few videos on You Tube taking a sarcastic look at oil tax reform. And while he talks about "our children's future," he doesn't address that our children will be at risk if production continue to decline thus making investments in education, public safety and roads impossible to keep up with growth and rapidly changing socio-economic demographics. Ironically, Lester is the spokesman for Lithia of Anchorage, an automobile dealership. So with thirty percent of the work force existing due to the oil industry, who does Lester think is buying the trucks and automobiles he hawks on television? I'll tell him. Companies like mine who rent and lease to oil companies and sell cars to Alaskans as well, which in turn generate millions in tax revenues for the state and local governments. Companies like construction contractors who survive off work from the oil industry, and employees who get their paychecks directly and indirectly from employment in the petroleum industry. Those are the folks who are entering showrooms and driving away in shiny new vehicles. Meanwhile in Juneau, a number of red herrings have been caught and mounted by legislative oil tax reform opponents. Audits I n a recent Senate Finance Committee, lawmakers got all twisted up about the fact that the state was behind in their audits. State Senator Bert Stedman (R-Sitka) chastised the Parnell administration for failing to keep current on oil industry audits. Whoa there senator...you should look in the mirror first. On October 6, 2007, during the testimony on ACES, Marcia Davis the former Deputy Commissioner of Revenue under Palin, was asked about the states ability to keep audits current. "We have great auditors, but we just don't have enough of them," Davis told lawmakers. Less than two weeks later, International Oil & Gas expert Pedro Van Meurs was testifying in front of the senate and was asked why the legislature shouldn't raise oil taxes for the second time in two years. Van Meurs responded "You haven't even done you first audit under PPT, so you don't have enough information." Even after these clear warnings that the Palin administration and lawmakers ignored, they went on to pass a tax regime that has confused just about every oil company that does business in Alaska. In Palin's fy08 budget not one dime was requested for auditors, nor did the legislature approve an additional funds after hearing twice during the ACES debate that there were simply not enough auditors. In 2008 after a presentation that highlighted the lack of efficiency in the state's auditing division, Palin requested $24 million for more technology and people, but the senate zeroed out their request. But today, lawmakers like Stedman, who ignored the warnings and then vetoed the request for better analytical tools and more auditors, are hot under the collar that the administration is behind on their audits? Please. After all it's just Alaska's economy we're talking about. Oh and the .92 out of every dollar the oil & gas industry contributes to state employee salaries and retirement benefits, along with a few hundred million that benefit the same professors who oppose oil tax reform. But really, who needs oil tax reform anyway? Alaskans who understand the economy,that's who. Read More :

Arctic OCS reparations

ConocoPhillips files plans for drilling in the Chukchi Sea starting in 2014 By Alan Bailey ConocoPhillips is moving ahead with its plans to drill exploration wells in the Chukchi Sea, starting in the 2014 open water season, Mike Faust, the company’s Chukchi Sea exploration project manager, told the National Marine Fisheries Service’s annual Arctic Open Water meeting on March 8. On March 1 the company filed its Chukchi Sea exploration plan with the Bureau of Ocean Energy Management, Faust said. The agency will review the plan for completeness before publishing it for public review. In February ConocoPhillips filed the corresponding oil spill response plan with the Bureau of Safety and Environmental Enforcement. Devil’s Paw The company’s Chukchi Sea lease positions include two prospects: part of the Burger prospect that Shell plans to drill this year, and the Devil’s Paw prospect. ConocoPhillips has no current plans to drill at Burger but does anticipate drilling one well per year in its Chukchi Sea Devil’s Paw prospect using a jack-up drilling rig, Faust said. Depending on ice and weather conditions, and on drilling progress, it might be possible to drill two wells in a single year, but one well per year is probably a more realistic expectation, he said. “Our plan is to drill one well. We’re going to go out there and be prepared to drill two,” Faust said. In its Devil’s Paw project ConocoPhillips is partnering with Statoil and OOGC, the U.S. subsidiary of the Chinese National Offshore Oil Corp. The Devil’s Paw prospect is located about 120 miles west of the Chukchi Sea coastal village of Wainwright and is about 80 miles from the nearest landfall, Faust said. The prospect is the site of the Klondike well, drilled by Shell into a major Chukchi Sea geologic structure in 1989. Although the Klondike well did not encounter commercial quantities of oil and gas, ConocoPhillips clearly views the geologic setting of the prospect and the results of the Klondike drilling as warranting further investigation at considerable expense. Although previous drilling did not conclusively demonstrate the viability of oil and gas development in the Chukchi Sea, ConocoPhillips believes that there is a good chance of finding the type of very large oil field necessary for commercial success in this remote region, Faust said. “Oil development would lead to significant workforce training opportunities, jobs, careers, increased community investment, and very significant tax revenue for the state and for the (North Slope) Borough,” Faust said, commenting that the necessary supporting onshore pipeline system, for example, would generate property tax revenues. Open water ConocoPhillips will only drill during open water conditions, with the drilling equipment being removed from the drill site should sea ice unexpectedly threaten the drilling operation, Faust said. “We have no plans to drill when there’s any ice on location at all,” Faust said. Based on past ice records, the drilling season should last from mid-July to mid-October, with that October end date allowing time for the drilling of a relief well in the unlikely event of a well blowout — it would likely take about 30 days to drill a well at Devil’s Paw, Faust said. In the interests of anticipating and accommodating any unexpected sea-ice movement, ConocoPhillips has developed an ice alert program, making use of frequently downloaded synthetic aperture radar satellite data to spot ice floes even under a cloud cover or at night. ConocoPhillips plans to use a brand new, state-of-the-art rig, equipped with the latest air emissions equipment and capable of operating in up to four-tenths sea ice cover, even although the rig will not be operating in ice in the Chukchi, Faust said. Ideal location And the location of the Devil’s Paw prospect, relatively far south of the likely summer sea-ice extent and under a water depth of about 160 feet, is especially favorable for a jack-up drilling operation, Faust said. A jack-up rig has huge sliding legs that can be jacked down to the seafloor and then used to lift the rig floor above the maximum height of sea waves. This arrangement creates a stable drilling platform that enables the well blowout preventer and other well control equipment to be located on the rig floor, rather than on the seabed, thus allowing easy access to this equipment, Faust explained. “It’s essentially a land rig sticking up some meters above the sea,” he said. And, being fixed rigidly to the seafloor without the need for propellers to keep it in position, the operation of the rig will be relatively quiet, he said. Capping stack To allow for the possibility of a blowout preventer failure, as happened in the Gulf of Mexico Deepwater Horizon disaster, ConocoPhillips is going to install on the seafloor what is called a “capping stack,” the type of equipment eventually used to seal the spilling Gulf of Mexico well. The approximately 150-ton capping stack, in place from the start of the drilling, with the well string passing through it, will be able to shear through the drill pipe, capping the well at the top of the well casing if necessary, Faust said. “That stack could be triggered from the rig. It could be triggered from a boat,” he said. However, the company does not expect an accident. A well at Devil’s Paw should be very similar in terms of drilling complexity to the more than a thousand wells drilled to date at ConocoPhillips’s Kuparuk River field in the central North Slope, Faust said. “We are constantly drilling this exact same kind of geology,” he said — the three primary drilling engineers working on the Devil’s Paw project have between them more than 90 years of experience. And, with a previous well at the Devil’s Paw location, subsurface conditions are known. ConocoPhillips has also acquired the experience of drilling 50 exploration wells in the Alaska Arctic since 1998, including in some in very remote locations, Faust said. Logistical challenge The logistical exercise of deploying a major Arctic drilling fleet, including all of the necessary oil spill response assets, will be a major challenge, Faust said. At the moment ConocoPhillips is engaged in the detailed planning for the operations and in the procurement of equipment. The company hopes to award all contracts for required vessels and equipment, including the drilling rig, by the end of 2012. “For an operation like this it really does take a couple of years of very detailed planning and a lot of work with all of the different contractors involved,” Faust said. “We have to spend a lot of time planning, ensuring that all of the safety precautions are in place, ensuring that all of the communications and simultaneous activities are really well tied together.” ConocoPhillips has spent much time with North Slope communities and is aware of past concerns expressed by North Slope residents that the oil industry had been moving forward too quickly with offshore development, Faust said. “We’ve really tried to step back and take a paced approach, understand what everyone’s concerns are, address as many of those as we possibly can,” Faust said. “We believe the time is right, now, to step out and actually drill a well.” Environmental studies ConocoPhillips has been involved in offshore environmental studies in the Chukchi Sea since 2006 and is proud of its involvement in the collection of baseline environmental data, Faust said. And in the offshore work that the company has conducted to date there have been no safety incidents and no injuries, he said. During drilling operations marine mammal observers will be stationed on the drilling rig and support vessels, and acoustic recording buoys will detect animals not observed on the sea surface. A monitoring program will determine any impact from permitted discharges from the rig by taking samples from the environment around the rig before, during and after the drilling operations. Some sampling will be done a year after the drilling, although no environmental impact is expected, Faust said. In addition to filing its exploration and spill response plans, ConocoPhillips has filed all of its permit applications for its Chukchi Sea operations, Faust said. The company has also applied for authorizations for the incidental disturbance of marine mammals. “We do believe that it’s appropriate to start working on those applications immediately,” Faust said. “There’s a lot of work that went into building those and we want to make sure that we have a good open dialogue with the agencies, and that … we have those authorizations in hand before we go out and commit hundreds of millions of dollars on equipment.” In early April the company will meet people from the North Slope Borough’s mayor’s office, to go through all of the Chukchi Sea permits in detail — the company will hold similar discussions with any of the North Slope communities that are interested in doing that, Faust said. Petroleum News

Senators iffy on Obama energy promises

By Eric Lidji

The Senate contingency of the Alaska congressional delegation offered faint praise to reassurances that the Obama Administration would include Alaska in its energy strategy.
In a recent speech at the University of Miami about domestic energy production, President Obama said his administration would “make available more than 75 percent of our potential offshore oil and gas resources from Alaska to the Gulf of Mexico.”
“I am heartened to hear the President talk about Alaska and the Arctic when discussing new sources of American-made energy to create jobs and build an economy that lasts,” Sen. Mark Begich, a Democrat, said in a statement following the speech, adding, “It is correct to say we have made significant progress as Shell’s spill response plan for the Chukchi Sea was approved last week, and we are moving ever closer to an active summer of exploration in the Arctic. But more work needs to be done. We need to continue to move forward on efforts for responsible oil and gas development beneath Arctic waters, the National Petroleum Reserve-Alaska and the Arctic National Wildlife Refuge.”
With the public and politicians once again arguing about the cause of rising gasoline prices, Sen. Lisa Murkowski, the ranking Republican on the Senate Energy and Natural Resources Committee, said any solution must include more domestic drilling.
“While I welcome the president’s stated commitment to develop ‘every available’ energy source and his reluctant acknowledgment that increasing domestic production does help reduce prices, many of his recent comments and his administration’s actions have been disappointing to those of us who have long been working to make energy more affordable,” Murkowski said in a statement. “Higher energy prices have been this administration’s policy goal, or at least been acceptable as collateral damage — as evidenced by its support for cap-and-trade legislation, its barrage of EPA regulations, the bureaucratic thicket it forces producers to navigate, and the tens of billions of dollars in tax hikes it’s attempting to impose on those who produce the energy we depend on.”
She said if the administration is “serious” about affordable energy, it should approve the Keystone XL pipeline, open the coastal plain of ANWR and new offshore areas to drilling, and work to streamline the permitting process and reduce costly regulations.

http://www.petroleumnews.com/pnads/505751496.shtml

LNG market grows, uncertainties persist

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

Energy Fact of the Week: Trains and Gains

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

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

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

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?

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.