Sunday, November 9, 2014

Joint venture enables production at Mustang

By Tim Bradner
Alaska Journal of Commerce

Brooks Range Petroleum will begin drilling this winter on production wells for the new Mustang oil field on the North Slope. The first release of funding from investors, which includes the Alaska Industrial Development and Export Authority, was made Oct. 29 and will finance the drilling as well as development of an oil and gas processing facility and connecting pipelines.

Mustang is expected to produce about 9,000 barrels per day, or b/d, in 2016 with that increasing to about 12,000 b/d in 2017, Brooks Range Chief Operating Officer Bart Armfield has said. Production will be from the Southern Miluveach Unit west of the Kuparuk River field.

In a press release, Brooks Range said AIDEA, the state’s development corporation, and CES Oil Services, a subsidiary of Charisma Energy Services Ltd. of Singapore, will own the processing facility through Mustang Operations Center 1, LLC. Brooks Range Petroleum Corp. will be the Mustang field operator and will build and operate the facility, Armfield said.

The process plant and pipelines are expected to cost between $200 million and $225 million, he said. Total costs, including drilling, are expected to be $500 million.

“We are very pleased to take this important step and to move forward with the construction of the production facility for the Mustang field,” Armfield said.

AIDEA will invest $50 million in the processing plant in addition to $20 million AIDEA previously invested with partners in a Mustang access road and gravel pad, will will bring the state’s total investment to $70 million.

This is the first equity investment by AlDEA in upstream production infrastructure. The authority’s previous oil infrastructure investment, also done with partners, was in a jack-up rig to do Cook Inlet exploration drilling.

The Mustang plant will be the first independently-owned, open-access production facility on the North Slope.

“The Mustang facility will enable companies operating on the North Slope to economically develop additional fields in a highly prospective area that to date has remained relatively underexplored.” Armfield said in the statement.

This is significant because independent companies exploring on the North Slope have had difficulty negotiating access to process facilities in producing fields that are owned by BP, ConocoPhillips and ExxonMobil, major operators on the Slope. This limitation motivated AIDEA to help finance an independent open-access process plant, AIDEA officials have said.

The plant is being designed to handle 15,000 barrels per day, to leave capacity available for production that would come from new discoveries, separate from the Mustang field. Armfield has said that Brooks Range has nearby prospects it intends to test once Mustang is operating, and companies are exploring and making discoveries in the immediate area. Those include Repsol, which plans to drill three evaluation wells this winter to evaluate discoveries the company made two years ago.

Previously AIDEA, the state authority, has mainly financed infrastructure like access roads for mining projects and ports, although it is also now investing in a small liquefied natural gas plant at Prudhoe Bay that will ship LNG by truck to Fairbanks, in Interior Alaska.

Armfield said production from the Mustang field would not have been possible without the project financing provided by the AIDEA-CES partnership.

“Because of AIDEA, BRPC was able to secure hundreds of millions in private investment to pursue additional development drilling at Mustang.” Armfield said.

This project will boost the state’s economy, create hundreds of new jobs, and generate significant revenue for the state.

“More drilling means more jobs, more production, and more revenue for the State of Alaska,” Armfield said. “This project will generate 50 jobs related to design and engineering, environmental permitting and services; 250 construction jobs; 20 to 25 full-time operations positions and up to 200 indirect long-term jobs.

“AIDEA’s overall $70 million investment is estimated to leverage more than $500 million of private investment in Mustang Field development. We are entering an exciting new era on the North Slope. With this project, Alaska is beginning to see the fruits of Senate Bill 21 (the state’s 2013 oil tax reform legislation) which, when combined with AIDEA’s willingness to work with independent oil and gas companies, will unleash the vast potential that remains untapped on the North Slope.”

Although exploration and development planning had been underway for Mustang prior to the Legislature’s passage of SB 21 the enactment of the tax changes created a more favorable long-term economic environment for production, which helped Brooks Range secure the final package of investment for the field development.

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Buccaneer assets sold; claims state owes $20M in credits

By Elwood Brehmer
Alaska Journal of Commerce

Bankrupt Buccaneer Energy Ltd. is demanding more than $20 million from the State of Alaska, days after appearing to sell its remaining assets.

The Australia-based independent filed a motion Oct. 30 in U.S. Bankruptcy Court for the Southern District of Texas to compel the state to pay tax credits it claims it is owed under the Alaska’s Clear and Equitable Share, or ACES, oil and gas tax system.

Buccaneer’s domestic subsidiary, Buccaneer Resources LLC is based in Houston.

On Oct. 27 AIX Energy LLC, an energy-finance company that in April purchased much of Buccaneer’s debt, won an auction for Buccaneer’s assets with a $44 million bid.

Miller Energy Resources Inc., which owns Cook Inlet Energy, was the only other participant with a $35 million bid.

The sale agreement is tentative pending final approval.

Buccaneer filed for Chapter 11 bankruptcy May 31 after Cook Inlet gas exploration came up empty and financing deals fell through.

Its claim that it is owed more than $20 million in ACES tax credits came about 40 days after the company paid $380,000 to the state and the Kenai Peninsula Borough in property taxes and associated fees related to the small Kenai Loop gas field, according to the filing.

The gas field in the City of Kenai is Buccaneer’s only producing asset.

The state has paid $37.9 million in ACES credits to Buccaneer to date, according to the company.

Prior tax credit payments were made between two and six days after approval notifications were received from the state, Buccaneer claims, and the notifications for the three applications in question were dated Oct. 8, more than three weeks before the motion requesting the court order the state to pay was filed.

“The state’s current treatment deviates significantly from historical practice,” Buccaneer’s attorneys wrote.

Department of Revenue spokeswoman Lacy Wilcox said agency officials could not comment on the issue because it is pending litigation.

A hearing on the outstanding tax credits is scheduled for Nov. 12 in the Houston court.

Southcentral Alaska Native regional corporation Cook Inlet Region Inc. has objected to the auction and sale proceedings multiple times, claiming the expedited timing has not given affected parties enough time to review critical documents. The latest such objection was filed Nov. 4 regarding a proposed hearing about Buccaneer’s bankruptcy plan.

CIRI owns land adjacent to the Kenai Loop pad and is involved with Buccaneer and the State of Alaska in an ongoing Alaska Oil and Gas Conservation Commission hearing over how much it is owed for gas Buccaneer produced from the Kenai Loop field.

Buccaneer has acknowledged in the hearing that it produced gas attributable to CIRI.

“It’s a question of how much. There’s no question that we’re due production from that field. I don’t want to beat around the bush on that,” CIRI Vice President Ethan Schutt said.

The funds in an escrow account that Buccaneer has been feeding with its production revenue should be enough to cover royalty payments to both the state and CIRI, according to Schutt.

Buccaneer was ordered to set up the account by the AOGCC as a way to segregate funds it may need to disburse later. According to a Nov. 3 court filing, about $8 million had been transferred to the account as of Oct. 31, and Buccaneer had $10.9 million in unrestricted cash, nearly all of which came from an ACES credit payment.

When the company filed for bankruptcy it claimed to have assets of less than $500,000 and liabilities between $50 million and $100 million.

To the degree that CIRI is asking for more than royalty payments “it gets a little dicier” as to where that money would come from, Schutt said.

Buccaneer also owes the Alaska Department of Natural Resources more than $605,000 for lease and royalty payments. The state was listed as the company’s ninth-largest unsecured creditor for the amount in a June court filing.

Schutt said that CIRI has had several conversations with AIX representatives presuming it takes over Buccaneer’s assets, which also includes standing in a state Superior Court case that largely parallel’s the AOGCC docket.

“We have some terms to work out with (AIX) one way or another,” he said. Elwood Brehmer can be reached at

Sunday, July 20, 2014

Explorers 2014: Repsol feeling ‘positive’ about Alaska exploration

Eric Lidji
For Petroleum News

Having completed its initial three-season exploration program the Spanish major is eying development

Repsol E&P USA Inc. recently finished its most important season in Alaska to date.

After announcing three discoveries last year, the Spanish major completed a three-well program this winter - a pair of appraisal wells in the Colville River Delta and an exploration well south of the Prudhoe Bay and Kuparuk River units. Those wells “finished with positive results,” Chief Financial Officer Miguel Martinez said at a first quarter earnings call on May 12. “We are working toward defining the most economical way to develop the area,” he added, saying it was too soon to comment further.

With the two appraisal wells, Repsol attempted to alleviate uncertainties around the earlier discoveries with the goal of sanctioning a major development, Repsol Alaska Project Manager Bill Hardham told the Alaska Support Industry Alliance on Jan. 23.

While declining to offer a timeline for development, Hardham said, “I feel confident it’s coming. It’s not a matter of if, but when.” But Hardham also warned, “The predictability of the regulations and tax structure is key to making these big investment decisions.”

It’s certainly no surprise to hear an oil company advocate for low and stable taxes over high and shifting taxes, and Repsol has never given a straightforward ultimatum about what might happen if voters overturn the new fiscal system in a referendum this summer, but Hardham listed taxation alongside geophysical analysis and stakeholder engagement as the major “uncertainties” Repsol must resolve before it could sanction development.

To the west, to oil

Repsol started as a state-owned monopoly created before the Spanish Civil War, but reorganized over the following decades and became a private company in the late 1980s.

Repsol was primarily a European downstream company before it acquired the Argentinean company YPF in 1999 and created the multinational Repsol YPF S.A. After that, the company began rapidly expanding, particularly across Latin America.

Today, Repsol maintains assets in more than 50 countries around the world.

The growth made Repsol a major player, but over the past decade the company decided to take a different approach by focusing on the West and on increasing its oil production.

With its portfolio weighted toward South America and Africa, Repsol decided to grow its presence in developed economies. In a four-year plan announced in early 2008, the company set a goal to have at least 55 percent of its assets in OECD countries by 2012.

Global events subsequently supported the move. Repsol temporarily lost its largest source of production during the recent uprising in Libya. The company cancelled plans for a $10 billion investment in an Iranian natural gas venture because of the threat of sanctions over the Iranian nuclear program. Argentina essentially nationalized the YPF portion of the company, and several other South American countries changed their fiscal terms.

The strategic plan also favored oil production

Over the 2000s, Repsol had invested heavily in liquefied natural gas, becoming the third largest LNG company in the world. Of the 2 billion barrels of oil equivalent in total reserves the company reported in 2009, only 890 million barrels came from oil.

With import terminals in Spain and eastern Canada, and export terminals in Trinidad and Tobago and Peru, Repsol’s LNG assets were focused in the Atlantic Ocean, where there was talk of surpluses. By placing a priority on oil in its strategic plan, Repsol could diversify its portfolio and take advantage of the historic, decade-long rise in oil prices.

First steps north

This strategic plan is why Repsol first dipped its toe in Alaska waters. It started in 2007, when Repsol partnered with Shell and Eni on a block of federal leases in the Beaufort Sea. (Shell operated the joint venture.) Repsol said “exploration activities” could begin as early as 2009-10, but lawsuits delayed any activities.

At the time, Repsol stayed quiet about its larger intentions in Alaska, which allowed rumors to swirl. Given the outreach efforts of the Palin administration, some thought Repsol might invest in a North Slope natural gas pipeline under the Alaska Gasline Inducement Act, which had recently become law and was then accepting applications.

Ultimately, Repsol did not submit an AGIA application, but the company still invested in Alaska. In early 2008, Repsol bid $15.6 million on 104 tracts in the record-breaking federal lease sale in the Chukchi Sea, including $14.4 million in high bids on 93 tracts.

The leases were clustered into three groups. The first was north of the Popcorn well that Shell drilled in 1990. The second was between the Popcorn well and the Burger well to the east. The third was to the north, in a region thought to contain Brookian potential.

A big joint venture

Even with those bold moves into the Arctic, Hardham insisted that Repsol remained cautious about the state, saying that the company “turned down several opportunities to come in further into Alaska, largely because of the uncompetitive tax structure.” In March 2011, though, Repsol acquired a 70 percent working interest in North Slope leases held by the Armstrong Oil & Gas subsidiary 70 & 148 LLC and its fellow Denver-based independent GMT Exploration LLC. The joint venture covered 494,211 acres in the White Hills region south of the Kuparuk River unit and near the Oooguruk unit.

The $768 million deal earmarked some $750 million for exploration, according to Petroleum News sources, suggesting that all three parties wanted to get to development.

Why was Repsol skeptical about Alaska in 2009 but ready to invest heavily in 2011? It was a combination of the right opportunity and the winds of change, according to Hardham. “Repsol felt that this was the right time, things were changing, it was a good opportunity - they don’t come along very often. It fit with the strategy,” he said.

Less than a month before announcing the deal, Armstrong Vice President Ed Kerr had submitted a letter to state lawmakers in favor of House Bill 110, which was the legislative vehicle under discussion at the time for changing the fiscal system for oil production.

“The improved fiscal terms as proposed by HB 110, particularly the portions of the bill that apply to activities outside of existing units, will give us the needed incentive to not only drill multiple new wildcat and delineation wells, but the motivation to drive certain projects to development,” Kerr wrote, saying his company had “more than a dozen ideas outside of existing producing units” that it was eager to explore in the coming years.

What about gas?

Alaska provided a unique opportunity for Repsol.

“This deal is a perfect fit in our efforts to balance our exploration portfolio with lower risk, onshore oil opportunities in a stable environment. We are confident that our worldwide experience combined with a partner with an extensive local knowledge is going to deliver value in the near future,” Chairman Antonio Brufau said at the time.

As a politically low-risk onshore oil opportunity, the Alaska leases offset Repsol’s large liquefied natural gas trade and also its exploration in prolific but technically challenging oil-rich basins such as the deepwater Gulf of Mexico and the Santos basin off Brazil.

Even so, some still wondered whether Repsol might also be interested in natural gas.

Chevron drilled five shallow wells across the White Hills region in 2008 and 2009. The company never released well results, but the state of Alaska believed the region to be both oil and gas prone, and Alaska Oil and Gas Conservation Commission well logs suggested Chevron was targeting oil and natural gas prospects in the Brookian formation.

A poster child

Just as Pioneer Natural Resources Alaska Inc. became a poster child during debates over Alaska’s Clear and Equitable Share in 2007, Repsol E&P USA is getting stuck in a tug-of-war over the More Alaska Production Act, which replaced the ACES system last year. The debates over ACES often featured Pioneer Natural Resources.

The large independent operated under three tax systems during the five years it took to reach first oil at its Oooguruk unit, but also earned considerable tax credits in the process.

While much bigger than Pioneer, Repsol also falls in the middle of the spectrum for international oil companies. It is smaller than Shell, Exxon, BP, ConocoPhillips or even Eni, but much larger than the smaller independents working on the North Slope, like Brooks Range Petroleum Corp. or Savant Alaska LLC. As such, some consider it a bellwether: if Repsol wants to invest in Alaska, the investment climate must be good.

When Repsol arrived on the North Slope in March 2011, the company promised to spend it initial exploration budget over “several years.” Lawmakers such as Sen. Bill Wielechowski, an Anchorage Democrat, believed that the deal vindicated ACES, which expanded tax credits for exploration but also increased the tax rate when oil prices rise.

To some, the deal suggested that even with higher taxes, the developed world might be more attractive because of its lower political risks. “They want to enlarge their portfolio (in areas) that are politically stable,” Rep. Paul Seaton, a Homer Republican, told Petroleum News in March 2011. “Even as we, Norway and other countries have higher tax rates than some Third World countries, the political stability is very beneficial.”

Those comments came as lawmakers were beginning to debate changes to ACES. By the time Repsol announced its discoveries in early 2013, those changes had become the law.

Did SB 21 help?

In announcing the discoveries, Repsol called the recent tax changes “a critical factor in ensuring the development of this project,” a claim that Gov. Sean Parnell proudly touted.

“Can you say they made this investment because of the tax change?” House Speaker Mike Chenault, a Kenai Republican, told Petroleum News in May 2013, referring to Repsol. “I don’t know if you can really say that, but it’s going in the right direction. We are hearing about projects that have a chance of coming online versus where they were pulling projects off the board because they didn’t make economic sense under ACES.”

As the passage of Senate Bill 21 prompted a voter referendum to repeal it, Rep. Les Gara, an Anchorage Democrat, questioned drawing any link to the development plans. “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,” he told Petroleum News in August 2013. “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.”

Today, Repsol claims that its decision to invest so heavily in Alaska in early 2011 was more of an informed risk than vote of confidence. “It was really about timing. … If you wait too long you can’t get the opportunity,” Hardham said. “So Repsol took a bit of a risk. They saw that there was change afoot. There was an opportunity, so we came.”

According to Hardham, Repsol believes the current system brings Alaska closer to the Lower 48, where it maintains operations in the Gulf of Mexico and in the Midcontinent.

“If you’re not competitive it gets really tough to develop these projects,” he said.

The Qugruk unit

The Repsol leasehold is spread across three chunks of the central North Slope.

The first is a T-shaped bundle running up the fairway between the Kuparuk River and Colville River units and spreading along the state waters of the Beaufort Sea. The second is a diagonal swath running south from Kuparuk nearly to the Brooks Range. The third is a smaller bundle hugging a bend in the Colville River south of the village of Nuiqsut.

In October 2011, Repsol and its partners applied to form the 98,852-acre Qugruk unit over 49 leases in the T-shaped bundle and proposed a four-well plan of exploration.

The region had been home to considerable exploration in previous decades, including six wells within the proposed unit boundaries going back to 1966 as well as 2-D and 3-D seismic, according to Repsol. The company described the primary objectives for the proposed unit as “sands within the upper portion of the Jurassic Kingak Shale, the Cretaceous Kup ‘C’ sand and several sands within the Cretaceous Nanushuk Group.”

In January 2012, the Alaska Department of Natural Resources approved a 12,065-acre unit over six leases just east of the Colville River unit, required Repsol to post a $20 million bond that would be returned if the company completed the Qugruk No. 4 well by June 30, 2012, and increased the rental rates on four leases set to expire in August 2012.

The smaller unit, the large bond and the relatively quick drilling commitment was meant to protect the state. The state felt that Repsol had “identified numerous high quality prospective targets over a large area in multiple stratigraphic intervals which will need to be drilled in order to prove up, which they propose to do in part during the proposed initial unit plan,” but also believed that unitization was “not technically supported.”

In mid-2013, Repsol asked the state to extend the primary terms of five un-unitized leases in the Qugruk area by three or four years. The request came after lawmakers passed House Bill 198, which gave state regulators additional authority to extend lease terms.

The law was designed to accommodate exploration companies that had spent considerable time and money exploring, but needed additional time to bring leases into production. Repsol had spent some $200 million exploring the leases since 2011, according to estimates from the company and the Department of Natural Resources.

The state ultimately gave Repsol an additional two years on the leases, but required the company to drill an additional well, post a $100,000 bond and collect new seismic. The decision made Repsol the first company to benefit from the law.

A three-year program

Repsol initially planned a five-well program for early 2012, but narrowed its efforts to four wells to alleviate local concerns. Those wells were the Qugruk No. 1, Qugruk No. 2 and Qugruk No. 4 along the Colville River Delta and just offshore and the Kachemach No. 1 much further south, near the Meltwater satellite of the Kuparuk River unit.

For the work, the company built 48 miles of ice roads in two segments. The first started at the Kuparuk River unit Drill Site 3S (or Palm satellite) and ran over the frozen coastal waters of the Beaufort. The other ran south from Drill Site 2S (or Meltwater satellite).

After a blowout at the Qugruk No. 2 well delayed its operations for several weeks, Repsol was only able to complete two wells: Qugruk No. 4 and Kachemach No. 1.

For early 2013, Repsol planned a three well program. Those wells were a second attempt at Qugruk No. 1, a Qugruk No. 2 re-drill called Qugruk No. 6 and Qugruk No. 3.

The company built an ice airstrip near Kuparuk Drill Site 2M and 38 miles of ice roads snaking north to Qugruk No. 1 and Qugruk No. 6 and south to Qugruk No. 3.

All three wells encountered hydrocarbons. Repsol performed drill stem tests on Qugruk No. 1 and Qugruk No. 6 and performed some early geotechnical work for development.

This winter, Repsol appraised those earlier discoveries with the Qugruk No. 5 and Qugruk No. 7 wells. Repsol also built a four-mile ice road south from Kuparuk to drill the Tuttu No. 1 exploration well on a lease just south of Prudhoe Bay and Kuparuk.

To bolster those activities, Repsol also contracted two 3-D seismic surveys. SAE Exploration conducted the Niglik Fiord survey covering some 222.39 square miles just offshore of the Colville River Delta, including the Repsol-operated Qugruk unit.

And Global Geophysical Services conducted the Schrader Bluff survey covering some 293.45 square miles south of Prudhoe and Kuparuk, including the Tuttu No. 1 well.

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Clock stopped for Shell in Chukchi Sea

By Tim Bradner
Alaska Journal of Commerce

Shell’s Arctic Challenger oil containment barge at the Port of Bellingham International Dock in Bellingham, Wash., seen in February 2013. Shell did not continue its plans for Arctic drilling in 2013 and 2014. The clock is still ticking on the company’s leases in the Beaufort Sea, although the Chukchi leases are on hold.

Shell’s Arctic Challenger oil containment barge at the Port of Bellingham International Dock in Bellingham, Wash., seen in February 2013. Shell did not continue its plans for Arctic drilling in 2013 and 2014. The clock is still ticking on the company’s leases in the Beaufort Sea, although the Chukchi leases are on hold.

The clock is ticking on Shell’s Outer Continental Shelf leases in Alaska’s Beaufort Sea. A large number of the company’s leases are set to expire in October 2017, federal officials said, although the leases on Shell’s two top prospects, Sivulliq and Torpedo, have been extended to July and October 2019.

Meanwhile, the U.S. Bureau of Ocean Energy Management, or BOEM, has stopped the clock on federal offshore leases held by Shell, ConocoPhillips and Statoil in the Chukchi Sea due to an ongoing lawsuit.

The Chukchi Sea has been Shell’s top priority in the Alaska OCS since 2013. ConocoPhillips and Statoil only have leases in the Chukchi Sea, and not the Beaufort Sea.

Shell drilled two partially-complete exploration wells in 2012, one in the Chukchi Sea and one in the Beaufort Sea, and had planned to return to both exploration areas in 2013 until the specialized drilling vessel Shell used in the Beaufort, the Kulluk, was damaged in a grounding near Kodiak in December 2012.

The Kulluk had been designed for Beaufort Sea conditions and had been given air quality permits by the U.S. Environmental Protection Agency. Partly because it lacked a suitable vessel that had its permits, Shell put the Beaufort Sea on the back-burner for its proposed 2013 drilling, and focused on the Chukchi Sea. The company was unable to return to the Chukchi for the 2013 and 2014 open-water drilling seasons because of pending new federal regulations on drilling.

OCS leases have 10-year terms and the Chukchi Sea sale was in 2008, but the lease clock for all three companies with leases in the Chukchi has been frozen until BOEM completes a supplementary environmental impact statement, or SEIS, for the 2008 Chukchi Sea OCS Sale 193, according to U.S. Bureau of Ocean Energy Management officials.

The revamp of the original environmental impact statement for the sale was challenged in court by environmental groups who argued the assumed size of a discovery, and the size of a possible oil spill, were underestimated in 2008 by the U.S. Minerals Management Service, the predecessor agency to BOEM.

The agency is now redoing the estimates. A draft SEIS is expected this fall and a final document by next March, BOEM has said.

“All of the Chukchi Sea leases, including the (Shell) Burger prospect, were put into suspended status. This status will remain in effect until the Bureau meets its obligations to correct the Sale 193 EIS consistent with the U.S. Ninth Circuit’s opinion and the direction of the (federal) district court,” said a BOEM official, who asked not to be identified because of agency procedures.

The revamp of the 2008 EIS, the more recent development, was ordered by a U.S. District Court judge in Anchorage after the U.S. Ninth Circuit Court of Appeals agreed with the environmental plaintiffs.

The U.S. Mineral Management Service had originally used an assumption that a 1 billion-barrel discovery could be made in the Chukchi, and further assumptions on a possible oil spill were based on that. Environmental groups said the figure was too low, and that the assumptions for the oil spill were also too low.

With the standard 10-year term leases sold in Sale 193 would have expired in August 2019. The new expiration date is unknown and will not be established until the SEIS is issued and approved, the BOEM official said.

The delay in drilling Shell’s top prospects in the Beaufort Sea has implications for Alaska. Oil from any discoveries in the Beaufort could be brought ashore to bolster Trans-Alaska Pipeline System, or TAPS, oil “throughput” much more quickly than oil from any Chukchi Sea discoveries.

The Sivulliq and Torpedo offshore prospects are in the eastern Alaskan Beaufort Sea about 15 miles north of the Point Thomson onshore oil and gas development east of Prudhoe Bay. A pipeline to shore could be built more quickly than a 60-mile Chukchi Sea pipeline to shore, and once ashore the Beaufort Sea oil could be shipped to TAPS through the existing Point Thomson and Badami liquids pipeline.

Chukchi Sea oil, once ashore, would still require a new pipeline across the National Petroleum Reserve-Alaska to the TAPS line.

It would take more than a decade for Chukchi Sea oil, once drilled and discovered, to be brought into TAPS, state officials have said. Beaufort Sea oil, once discovered, could possibly be brought to TAPS in about half the time, they said.

Getting more oil into TAPS is important because TAPS throughput has been declining to the point that there could be operating problems during very cold winter conditions. More oil volumes, no matter from what source, will ease these.

Also, although OCS oil pays no royalty or production tax to the state of Alaska it indirectly increases state revenue because the higher volumes in TAPS lowers the pipeline’s per-barrel tariff for shipping oil. Since that applies to all oil shipped in the pipeline it results in a higher value of oil from state leases on the North Slope, resulting in higher royalties and production tax payments.

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