Saturday, August 31, 2013

Former Governor Frank Murkowski steps in to meet with REI

Tim Bradner
Alaska Journal of Commerce

A former Alaska governor has stepped in to smooth over a potential diplomatic faux pas that might have impaired a Japanese initiative to invest in a North Slope liquefied natural gas export project.

Former Gov. Frank Murkowski offered to host the visit by Gov. Toshitami Kaihara, the former governor of Hyogo Prefecture in Japan and a key figure in the formation of a Japanese group interested in Alaska LNG, after Gov. Sean Parnell declined a meeting.

Resources Energy Inc., or REI, is a Japanese consortium of municipalities and business groups formed to find an independent source of LNG. The group opened an office in Anchorage a year ago.

In Japanese business and diplomatic protocol, declining such a meeting is considered a snub, particularly after Parnell met with the president of KoreaGas, a competitor to the Japanese in purchasing LNG, earlier this year.

“The Japanese tradition is to want to shake hands with the top guy. I’m not sure Parnell understands that,” said Murkowski, who helped organize a reception for Kaihara Aug. 20 at the Petroleum Club in Anchorage. “I was glad to step in to accommodate these visitors when our governor had other commitments.”

Murkowski is an old hand in Asian affairs, having chaired the U.S. Senate’s Foreign Relations Committee’s East Asia subcommittee for years while he was in the Senate.

There may have been more to Parnell’s declining the meeting than just diplomatic naïveté, however.

The problem may be Kaihara’s relationship with REI, and it tends to fit a standoffish attitude the governor has exhibited, on several levels, since REI announced its desire to pursue an Alaska LNG project separate from the project North Slope producers BP, ConocoPhillips and ExxonMobil and pipeline company TransCanada are working on.

Kaihara wanted to stop in Alaska on a trip back to Japan from Washington State to pay a courtesy call on Parnell on July 20, with officials from REI also attending. Ironically, Washington State Gov. Jay Inslee met with Kaihara in Seattle — the occasion was the 50th anniversary of a sister-city alliance between Seattle and Hyogo Prefecture — and made the former Japanese governor an honorary Washington State citizen.

Such things are important in Japanese business and government protocols.

Although the request to meet with Parnell was made July 10, the governor declined the appointment with Kaihara, citing schedule conflicts. The governor’s office offered a meeting with Deputy Natural Resources Commissioner Joe Balash as a substitute.

Kaihara did wind up meeting with Balash, and Murkowski organized a private meeting with ConocoPhillips officials. Other Alaska business leaders attended the Aug. 20 reception hosted by Alaska Nippon Kai, a Japan-Alaska business association. Later in the week Kaihara met with Lt. Gov. Mead Treadwell.

Treadwell, who has extensive Asia business experience, was unable to attend the reception but did send a letter welcoming Kaihara.

The sting of being turned down by Parnell was eased, although not completely.

Parnell spokeswoman Sharon Leighow downplayed the issue.

“Look, we can’t accommodate everyone who wants to meet with the governor,” she said.

As a follow-up, Leighow provided a written statement.

“Japan continues to be a major trading partner with Alaska and the governor appreciates our long-standing, respectful relationship with the Government of Japan,” Leighow wrote. “In the past year, Gov. Parnell has met with government officials of Japan as well as senior executives in Japan’s energy, utility and mining companies,” including REI officials.

Leighow also said Alaska Natural Resources Commission Dan Sullivan has met with REI president Shun Shimizu several times during visits to Alaska by Shimizu and REI’s technical team.

On those earlier visits, Shimizu had asked to meet with Parnell, but those meetings were also declined.

Leighow said there were other reasons contributing to Parnell’s decision not to meet with Kaihara but did not explain what they were. Some of it would be explained in emails the governor’s office had received from REI, she said, but the governor’s office could not provide the emails to the Journal unless a Pubic Records Act request was filed.

The Journal filed a Public Records Act request on Aug. 22, but as of Aug. 28 the emails had not been provided.

A source familiar with the proposed LNG export project, asking not to be identified, said he was struck by Parnell’s position.

“This is just plain rude. These kind of meetings are mostly ceremonial and when you’re governor this goes with the job,” the source said. “Someone comes in from overseas who wants to invest, and you shake their hand and tell them they are welcome.”

Parnell’s reluctance to meet with REI officials, most recently with Kaihara, may be rooted in a concern that such a meeting, even if only as a courtesy, might be interpreted as some form of state endorsement of REI’s independent LNG initiative.

The governor may also be concerned that the North Slope producers and TransCanada might interpret such meetings as the state’s flirting with potential competitors, and might use that as an excuse to ease off on efforts to advance their own project.

Parnell has been pushing the Slope producers and TransCanada to show signs of progress on an LNG export project, and expressed displeasure in June when the group failed to meet a key benchmark the governor had laid down: a commitment to begin Preliminary Front-End Engineering and Design work, a key step in the project.

Nuclear fallout

REI’s initiative is somewhat different than that of the producers and TransCanada, however.

For one thing, REI is not yet an actual customer for LNG, but is a startup company formed by Hyogo Prefecture and a group of Japanese technology firms who are anxious, following the near-total shutdown of Japan’s nuclear power industry, to develop their own, direct sources of imported LNG and not have to depend on Japanese LNG imports dominated by major Japanese companies like Tokyo Gas.

The company is an entrepreneur in the field, in other words. If the Alaska project appears possible, REI and its managers, mostly retired senior Japanese executives in the LNG business, would move to expand REI with additional Japanese municipal governments and regional industries, as well as utilities, who want their own direct sources of LNG.

While the company would like a State of Alaska endorsement, it would settle for some form of recognition by the state, REI has said in the past. This is still seen as important in Japan’s business culture given the importance of cooperation by governments in international trade.

To that end, REI asked for a “Memorandum of Understanding” with the state in mid-2011 that would lay out how the state would offer cooperation and an MOU was agreed to and finally signed last December after extended discussions. But rather than the MOU being signed by a senior state official like DNR Commissioner Sullivan, it was signed by a middle-level official, then-state AGIA Coordinator Curt Gibson. MOUs like this are typically symbolic. A previous MOU signed by the state with the Alaska Gasline Port Authority was signed by state commissioners Tom Irwin of DNR and Pat Galvin of the Department of Revenue.

However, the MOU offered REI enough encouragement that the company proceeded with a $20 million initial feasibility study of an independent LNG project in Southcentral Alaska and the marine shipping of LNG to Japan, REI Vice President Mary Ann Pease said.

The study was concluded last April, and while the results are confidential they were promising.

Among other things, the study showed LNG could be shipped to Japan for about $1 per million British Thermal Units, half to one-third of the shipping cost from competing sources of LNG to Japan, Pease said.

REI rebuffed

Meanwhile, the state administration has also been slow to sign a long-pending MOU with the Japan Bank for International Cooperation, or JBIC (formerly the Export-Import Bank of Japan), Japan’s government investment group that is interested in whatever REI might be able to do in Alaska.

The arms-length attitude toward REI was illustrated on another level. The state’s Alaska Gasline Development Corp., AGDC, declined REI’s request in June to establish a confidentiality agreement, as allowed under House Bill 4 approved by the Legislature earlier this year.

A June 18 letter written to REI President Shimizu by Dan Fauske, CEO of the state gas corporation, said, “we have concluded that, due to current law and contractual obligations between the state of Alaska and the AGIA licensee (TransCanada Corp.) AGDC cannot participate in further discussions with REI.”

A key point of concern for AGDC, the letter indicated, was REI’s request to work with the state corporation on shipping 750 million cubic feet per day of gas, which is beyond the limit of 500 million cubic feet per day allowed for AGDC under the state’s agreement with TransCanada.

In an interview, Fauske said he was told by the Department of Law not to sign a confidentiality agreement with REI even though HB 4 now gives the state corporation the authority to do so for commercial discussions.

Despite the terse wording of the June 18 letter, which Fauske said was suggested by state attorneys, “the door is always open” at AGDC for REI or other potential customers for the state-backed pipeline, Fauske said.

Fauske and other AGDC officials also met with Shimizu and others in the visiting Japanese group August 23 to smooth over any misunderstanding about the June letter. Fauske also said he urged REI to participate in an open season for gas shipments that AGDC plans in late 2014 or early 2015.

Pease attended the meeting.

“We indicated that we were willing to start off with a small plant, in the range of 200 million cubic feet per day, which is well below the 500 million cubic feet per day legal limit imposed by AGIA,” she said.

“Even without a confidential agreement, my specific request at the meeting was that REI be included in the list of potential industrial customers who could be anchor customers for an AGDC pipeline. We did not get an answer to that.”

But, because of the inability to sign a confidentiality agreement, REI cannot share any data from its feasibility study on an LNG project with AGDC, which is unfortunate, she said.

Murkowski, in an interview, said he was concerned that REI’s initiative is being given short shrift not only by the current state administration but also the producer-led LNG group.

“I’m concerned over the lack of willingness to really evaluate what these people have to offer,” the former governor said. “Here the Japanese are coming in with a willingness to spend their own money and are not asking for anything,” in the form of a state subsidy.

Murkowski contrasted that to the producers’ and TransCanada’s project where the state is chipping in $500 million at a 90 percent cost reimbursement rate under TransCanada’s AGIA (Alaska Gasline Inducement Act) license, funds that are now being shared with BP, ConocoPhillips, and ExxonMobil as well as TransCanada, he said.

“There seems to be a presumption that only the producers can develop this project and monetize the gas,” Murkowski said. “That may be the case, but here we have people with different ideas who are willing to invest in a project and buy state royalty gas at the wellhead,” to transport it through a pipeline.”

Murkowski said he doesn’t understand why Parnell recently extended the state’s contract with TransCanada, which includes the subsidy, and he faults Parnell for not explaining why he felt the extension was necessary.

“I feel the governor is really exposed on this, by not explaining to the public what we’re getting for our money,” Murkowski said.

Read more:

Wednesday, August 21, 2013

Facing a headwind; Schutt describes the challenges for independent power producer in Alaska

Alan Bailey
Petroleum News

The saga leading to the implementation of Cook Inlet Region Inc.’s Fire Island wind farm, offshore Anchorage, was marked by a sometimes acrimonious debate between the Alaska Native Corporation and its potential power utility customers over issues such as the ease or difficulty of integrating fluctuating wind power into the Alaska Railbelt electricity grid. But were these technical bones of contention the symptoms of some deeper issues regarding the place of independent power production in the Railbelt energy scene?

Cook Inlet Region Inc., or CIRI, funded the Fire Island wind farm as a private project, with the intention of selling power to Railbelt power utilities. But when the wind farm went on line in 2012, CIRI only had one wind power customer — Chugach Electric Association — and the farm itself was smaller than the Native corporation had originally planned.


On July 31 Ethan Schutt, CIRI’s senior vice president for land and energy, told the International Association for Energy Economics’ North American conference about some of the hurdles that the Fire Island project had faced. Characterizing the hurdles as interactions with government, Schutt said that Alaska has no formally recognized space for independent power producers.

“If you want to be an independent power producer in Alaska, you’ve got to make your own space, because it doesn’t exist,” Schutt said.

Early on in the Fire Island project, given this lack of commercial space in the power market, CIRI was faced with something of a Hobson’s choice in having to decide whether to go through the tortuous and risky process of trying to be legally recognized as a regulated power utility, or whether to seek a state government exemption from regulation, allowing the wind farm to operate as an independent power producer. In the event, CIRI opted for that latter course, persuading the state Legislature to pass legislation allowing the corporation to sell power, albeit on a relatively small scale, only from a renewable energy source, and only to regulated utilities, Schutt said.

De-facto government

As CIRI’s project moved forward, the corporation came to the realization that all six of the Railbelt electricity utilities, the wind farm’s potential customers, are either government organizations or de-facto government organizations, Schutt said. Two of the utilities are directly owned by municipalities, while the other utilities are vertically integrated customer-owned cooperatives, operating as monopolies within government-granted, certificated geographic regions, he said. Beyond periodic rate cases, in which the Regulatory Commission of Alaska reviews and approves the rates that the utilities charge their customers, the utilities are largely free to act as they see fit within their certificated areas, Schutt said.

At the same time, although the state has set a target of obtaining 50 percent of Alaska electricity from renewable energy source by 2025, there are no formal incentives, regulatory requirements or public support for the independent production of renewable energy, Schutt said. There is a renewable energy grant fund, but there are no market-based mechanisms for facilitating change, he said.

And while most if not all of the commercial-scale power transmission infrastructure in Alaska is either built or substantially funded by the state, the state exerts very little operational control over the infrastructure and over market access to that infrastructure for private enterprise, Schutt said. Compounding this phenomenon and distorting the energy market is extensive state involvement in the funding of power projects such as the project to construct a major hydropower dam at Watana on the Susitna River, he said. State funding of energy projects raises questions over why people would want to buy energy from a privately-funded facility rather than buy relatively cheap, subsidized power, he said.

“That obviously has significant impacts and distortions on the market,” Schutt said. “We felt it directly with our project.”


Then there is the question of the regulation of power rates. Although CIRI obtained an exemption from regulation for the Fire Island project, there is de-facto regulation because the Regulatory Commission of Alaska has to approve utilities’ power purchase agreements, including the power rates within those agreements, Schutt said. And, despite CIRI conducting what it viewed as “arms-length” negotiations with its eventual utility customer, the Native corporation ran into substantial opposition from some utilities during the power purchase agreement approval process, he said.

In the course of trying to bring the Fire Island project to fruition one utility threatened legal action against the wind farm, while another used what CIRI viewed as manipulated numbers to argue against the merits of the project, Schutt said.

“There is actually something of a deep, pervasive suspicion of for-profit companies within the energy space here in Alaska,” Schutt said.

Read more:

Sunday, August 18, 2013

Arctic drill rules advance; Shell spill dome OK’d

Tim Bradner
Alaska Journal of Commerce

A top federal official offered fresh assurances that new rules governing drilling in the Outer Continental Shelf off Alaska’s Arctic coasts will be out by the end of the year, and that Shell’s special Arctic “capping stack” and containment system for spilled oil have been given final approvals.

“Those systems are now certified. The engineering problems have been overcome,” said James Watson, director of the U.S. Bureau of Safety and Environmental Enforcement, or BSEE.

Shell was unable to get certification for key parts of its containment system — a special barge designed to process and store oil recovered in a spill and the undersea containment capping stack — in time for the 2012 exploration season in the Arctic.

The first tests of the containment dome in Puget Sound failed when it surfaced and the top half was “crushed like a beer can,” according to an email account of the test written by BSEE Alaska Director Mark Fesmire reported by the Seattle National Public Radio affiliate KUOW in December 2012.

Because the spill response barge could not reach the Arctic in 2012, regulators gave Shell approval only to drill “top holes,” or the upper parts of the wells, on two exploration wells. Top-holes do not penetrate potential oil and gas reservoirs, so that there was no risk of a blowout from the 2012 drilling. The wells can be completed when Shell returns to the Arctic, possibly in 2014.

The regulations will also incorporate special requirements placed on Shell’s Chukchi and Beaufort seas exploration in 2012 for standby rigs for relief wells and for an undersea blowout containment system.

“We expect to formally incorporate these procedures in the very near future and to go to a proposed rulemaking (notice of new regulations) by the end of the year,” Watson said at a meeting held by the North American Marine Environmental Protection Association, or NAMEPA, a trade association.

Fesmire has said those things earlier, but Watson’s remarks as the agency’s top manager underscored what Fesmire said.

Shell and other companies are awaiting the new rules so that they can make plans for new drilling. Shell suspended its program for 2013 and has not said when it might resume exploration started in 2012, citing the lack of the federal rules as one uncertainty.

ConocoPhillips has not indicated what year it will drill on Chukchi Sea leases it holds, also citing the lack of the new rule. Statoil, another company holding leases, said it hopes to drill in 2015.

Watson added new details to what is known about the pending rules, however, mainly that BSEE will require independent third party audits of operators’ environmental and safety management programs.

Watson also described the pending new rules as a hybrid of a conventional compliance regulatory system, where the federal agency will do inspections, with a kind of performance system where industry must show it can meet certain standards and goals.

To do that, companies will be required to develop a Safety and Environmental Management system and to obtain audits by independent firms that their operating practices adhere to the management systems, Watson said.

“We don’t want to actually approve the management system because that puts us in a position of responsibility and liability. We will want to see the third-party verification that they are following it,” he said.

BSEE adopted similar requirements for third-party verification of compliance on well completion and cementing for deepwater offshore drilling following the 2010 Deepwater Horizon blowout in the Gulf of Mexico.

The pending new rules were first proposed to apply to the Alaskan Arctic OCS but they will now be broadened to apply to drilling on all OCS submerged lands off Alaska, Watson said. That would include any exploration in the Bering Sea, Gulf of Alaska and Lower Cook Inlet.

OCS lease sales and exploration drilling has previously been conducted in all of those areas but without success by industry.

U.S. Coast Guard Rear Admiral Thomas Ostebo also spoke at the NAMEPA conference, raising fresh concerns about increasing commercial marine traffic in the Arctic and the lack of international rules, both of which are creating risks.

“This is not something in the future. This is happening now,” Ostebo said. “Eight days ago we had a 1,000-foot tanker carrying a million gallons of fuel transit the Bering Straits. This is not a U.S.-registered vessel, it is operated by a third party (not the vessel owner) and it is not polar class,” which meant it lacked special ice protection, Ostebo said.

This year also saw the earliest entry of a cruise ship into the Arctic, a Russian vessel with 600 passengers.

“What would happen if there were a problem? We could have 600 people and half a million gallons of fuel in the sea off Point Hope,” he said.

The risks aren’t just fuel. Chemicals are also being carried on vessels crossing the Arctic. Russia has issued permits to more than 200 vessels to make the crossing this year, a four-fold increase in two years, Ostebo said.

The Coast Guard is particularly concerned about the lack of agreed-on “rules of the road” in the Bering Strait.

“We do not have a vessel separation and traffic system in place,” Ostebo said, unlike other geographically congested points where there is marine traffic, such as the Straits of Mallaca or Gilbralter. “What we have is a free-for-all, with whoever going where they want.”

The rules are complex for establishing international vessel traffic systems under the International Maritime Organization, or IMO, so the best approach is a bilateral agreement with Russia.

“Lt. Gov. Mead Treadwell has proposed a voluntary system that has a lot of merit, but Russia has asked us to go a little slower in developing it,” Ostebo said.

Russia has a lot of influence because the bulk of the Arctic traffic is over Russia’s Northern Sea Route, across the Arctic from Europe to Asia, and through the Bering Strait.

“The U.S. and Russia are the two nations sharing the strait, and every ship transiting the Arctic must go through it,” Ostebo said.

Unimak Pass is an Aleutians is one other area where there is high vessel traffic and no international traffic rules, but at least there are ocean-going tugs available to assist ships. There is nothing near the Bering Strait.

Sunday, August 11, 2013

ConocoPhillips applies for new NPR-A permits

Tim Bradner

CononoPhillips has applied for permits to develop a new production site in the National Petroleum Reserve–Alaska, the 23-million-acre federal reserve in the western North Slope. The company also has a second project on the drawing boards.

The application to develop the first project, GMT-1, was made in late July to the U.S. Bureau of Land Management, which administers the NPR-A. ConocoPhillips submitted the permits on behalf of itself and Anadarko Petroleum Corp., a minority partner, BLM spokeswoman Erin Curtis said.

GMT-1 was one of several projects ConocoPhillips announced it would pursue in the days following the state Legislature’s action April 14 to reduce the state production tax. Although NPR-A is federal land the state tax applies to oil and gas produced there.

The company also said it is evaluating a new production site in the Kuparuk River field and will accelerate drilling and well “workover,” or major maintenance, work.

In the NPR-A, ConocoPhillips owns 78 percent interest in federal leases in the Moose’s Tooth Unit with Anadarko holding the remaining 22 percent.

ConocoPhillips spokeswoman Natalie Lowman said her company will seek corporate approval to develop the GMT-1 project in the Greater Moose’s Tooth Unit of NPR-A in the second half of 2014, assuming the permits are issued by BLM.

If all goes as planned, construction would begin in early 2016 and first production in late 2017. No estimates of cost or production were included in the BLM application.

“We are still doing the preliminary engineering and design to determine cost and the estimated production,” of GMT-1, Lowman said.

The application also said the company also plans the second project, GMT-2, that would be 8 miles west of GMT-1.

“Upon the successful permitting and construction of GMT-1, ConocoPhillips intends to submit permit applications for development of GMT-2. The exact dates for these applications is unknown,” ConocoPhillips said in its filing with BLM.

GMT-1 is approximately 17 miles west of the producing Alpine field, which is on State of Alaska lands and is also owned by ConocoPhillips and Anadarko in the same 78 percent-22 percent shares as the NPR-A leases.

The two companies are also now developing CD-5, an Alpine field satellite unit a few miles west of the field but which is within the NPR-A because it is west of the Colville River channels that forms the boundary between and federal lands.

Construction of CD-5 is scheduled to begin in late 2014 and continue through 2015, with first production in 2015.

An issue that could complicate the CD-5 schedule and possibly GMT-1 are two lawsuits challenging the CD-5 permits. A lawsuit brought in federal court last February against the U.S. Army Corps of Engineers was filed by six residents of Nuiqsut, a nearby Inupiat village.

In June, the Center for Biological Diversity, an environmental group, filed a second lawsuit challenging the CD-5 permit, also in the U.S. Alaska District Court.

The villagers’ lawsuit claims a Colville River bridge and related roads planned for CD-5 will adversely affect wetlands that support subsistence hunting and fishing, and that the Corps did not properly consider tunneling under the river for a pipeline and air-supported access as a reasonable alternatives to the bridge and roads.

In its intervention in the case, ConocoPhillips claimed an underground tunnel for the pipeline creates environmental risks because corrosion and oil leaks are more difficult to detect and repair in a buried pipeline than a surface pipeline. In its separate lawsuit, the Center for Biological Diversity claims that threatened and endangered species are affected.

The State of Alaska, Arctic Slope Regional Corp., and Kuupik Corp. have intervened in the villagers’ lawsuit on the side of the Corps, but a motion to intervene by the North Slope Borough is being opposed by the village plaintiffs represented by Trustees for Alaska, an environmental law firm.

ConocoPhillips has also been granted intervenor status on behalf of the Corps in the Center for Biological Diversity lawsuit.

The case presents a new uncertainty over the CD-5 bridge permit, which was held up by an extended Corps of Engineers review before a corps permit for the bridge and roads was finally issued. If the permit is overturned the schedule for CD-5 could be disrupted, which could also affect the NPR-A site developments because they will depend on the bridge and roads built for CD-5.

The schedule for GMT-1 outlined in the permit application calls for the ordering of long lead-time materials for the project, such as steel, in the fourth quarter of 2014. One year later, in fourth quarter of 2015, the first ice roads would be built to support construction.

Gravel mining and construction of gravel roads, pads and bridges would occur in the first quarter of 2015. Pipeline vertical support members, the pipeline, production facility and power and telecommunications cables would be installed in first quarter, 2017. The first production would be in late 2017.

The project would include 7.8 miles of road to the project from the CD-5 drillsite now in construction; 8.4 miles of pipelines to connect GMT-1 to CD-5, and 8.4 miles of power and telecommunication lines built on horizontal supports from the pipeline.

There would be an 11.8-acre gravel pad at the project site with sufficient space to support 33 production wells.

Several pipelines would be built to support the project including a 20-inch produced fluids pipeline that would move a mixture of crude oil, natural gas and water from GMT-1 to the Alpine field oil and gas processing facilities.

There would also be a 14-inch pipeline to carry seawater or produced water (water produced from the oilfields) from Alpine to GMT-1 for reservoir pressure support, and two separate 6-inch pipelines, one to carry gas from Alpine to GMT-1 to support “artificial lift,” or below-surface pumps, to help bring oil to the surface, and a second 6-inch line to carry a miscible injectant fluids from Alpine that can be used for enhanced oil recovery.

Read more:

Monday, August 5, 2013

Alaska gets pipeline, just barely

—Wesley Loy

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.”

Read more:

Friday, August 2, 2013

Oil production booms, demand drops, prices stay high: Why?

Tim Bradner
Alaska Journal of Commerce

University of North Dakota student Maxwell Johnson, an intern for Hess Corp. stands in front of an oil rig July 10 near Tioga, N.D. Production from the Bakkan oil play in North Dakota jumped 50 percent last year and contributed to the largest single-year increase ever in oil production for the U.S.. Despite the increase in supply and slack demand, prices remain high, however.

The world is awash in oil and the U.S. recorded its biggest increase in oil production last year. Oil demand is down, mainly due to high prices and the weak economy, but also due to huge gains in energy efficiency.

Yet oil prices remain high. Why?

That’s a conundrum energy economists are struggling with, says BP’s chief U.S. economist Mark Finley. If supply is up and demand is down, price ordinarily would fall. It isn’t happening, though.

“It’s a key question we’re facing, and we don’t really know the answer,” Finley said.

One possible answer might be that there is demand on world markets that isn’t being tracked, he said, possibly from governments quietly buying up oil to build strategic stockpiles.

“The U.S. isn’t the only nation with a strategic oil stockpile. China is also building a stockpile, and we now know that Saudi Arabia is building a supply storage, so that it has inventory for strategic advantages,” Finley said.

This could be one explanation for why oil prices remain high.

Finley spoke in Anchorage July 29 to a group of business and community leaders at a luncheon sponsored by the Alaska Oil and Gas Association.

Finley’s comments were drawn from data in BP’s annual Statistical Review, the 62nd edition of the report. BP’s data for 2012 is the latest available as of May, 2013, and the company’s report is typically the first analysis of energy trends published for a year, and is ahead of other reports, such as those produced by the U.S. Department of Energy’s Energy Information Administration.

Overall, the world’s energy market showed weak growth across all regions and all types of fuel.

“Energy consumption grew by 1.8 percent, which is low by recent standards,” Finley said.

The 10-year average is 2.6 percent. Energy consumption in OECD (Organization of Economic Cooperation and Development) countries, or developed nations, fell by 1.2 percent, led by a decline in the U.S. of 2.8 percent.

Among OEDC countries oil consumption dropped 1.3 percent, or 530,000 barrels per day, the sixth decrease in the past seven years. Among non-OECD nations, oil consumption grew by 3.3 percent, or 1.4 million barrels per day.

Non-OECD nations, mostly the developing nations, saw a 4.2 percent growth, but that was below the 10-year average of 6.3 percent growth.

Oil development continues at high levels, however.

“For every barrel of oil consumed reserves grew by two barrels, mainly because of technology improvements, such as in shale oil production,” he said. The world now has a 53-year supply of proven oil reserves and a 56-year supply of gas reserves.

The U.S. enjoyed a booming increase in oil and gas production, led mainly by the technology revolutions in shale production, but oil demand was down in the U.S. mainly due to a sluggish economic recovery and continued high prices.

An interesting aspect of the U.S. shale revolution is that the technology gains continue to improve in shale, somewhat confounding experts who had predicted a plateau effect.

“North Dakota saw its production increase 50 percent (mostly shale oil) but the number of rigs were up only 10 percent. Why is that? It is because the rigs were more productive, and drilling more wells. They were more efficient,” Finley said.

Global energy efficiency gains were also at record levels. Worldwide, the “energy intensity” of economic growth dropped by 1 percent mainly due to efficiency gains, Finley said.

In Asia, still the driving force in world energy markets, oil demand in China fell due to slowing growth, but coal use continued to increase. In Japan, cutbacks in that nation’s nuclear industry led to increased use of oil and particularly gas for power generation, in the form of imported liquefied natural gas, or LNG.

That had a chain-reaction effect on LNG markets, and indirectly on U.S. coal markets, Finley said.

“European LNG purchases fell 25 percent as Europeans were outbid by Japanese importers. To fill that need for fuel for power generation, Europe imported more coal, mostly from the U.S.,” he said.

The U.S. had coal available because cheaper natural gas was available, due to shale production. U.S. gas prices fell by one-third percent in 2012, making gas more attractive for power generation. This illustrates the linkages across regions and types of fuels that connect the world’s energy business today.

Oil remains the dominant fuel of in the world but it is gradually losing market share to other fuels, mainly gas and coal.

“The decline in oil use tracks perfectly with price,” Finley said. “The use of oil (in the mix of energy) is the lowest it has ever been.”

However, in the long term oil demand will be driven by growth of demand for transportation fuels, which is linked to larger numbers of automobiles being purchased, mainly in Asia.

“Twenty years ago China accounted for only 2 percent of new sales in the world. Now it accounts for 20 percent,” Finley said.

Asia overall accounted for 16 percent of new care sales two decades ago and now accounts for almost 80 percent.

A key message Finley conveyed to listeners is that most of the big innovations in energy like shale oil and gas, production from deep offshore fields and the Arctic, and including the biggest gain in energy efficiency in decades, have mostly been in North America.

That’s no accident. “It has happened because we have a political and economic structure that allows markets to respond. We don’t (have the government) pick winners and losers,” in industry, he said.

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