Sunday, June 29, 2014

CEO: Alaska prospects improving for oil, LNG

Tim Bradner
Alaska Journal of Commerce

ConocoPhillips CEO Ryan Lance, seen after addressing the Resource Development Council annual luncheon in Anchorage, said he’s increasingly optimistic about prospects for both increased oil production and a large LNG export project in Alaska.

ConocoPhillips CEO Ryan Lance, seen after addressing the Resource Development Council annual luncheon in Anchorage, said he’s increasingly optimistic about prospects for both increased oil production and a large LNG export project in Alaska.

ConocoPhillips CEO Ryan Lance said his company is increasingly optimistic about Alaska’s prospects to boost oil development and about a future natural gas project.

ConocoPhillips has announced $2 billion in new projects since the Legislature passed an oil tax reform bill in 2013 and Lance said the company expects to add 40,000 barrels per day of new North Slope production by 2017.

Lance, who delivered his remarks at the Resource Development Council of Alaska annual luncheon in Anchorage, is no stranger to the state. Half of his 30-year industry career has been here, mostly with ARCO Alaska, now ConocoPhillips. While with ARCO, Lance led the development of the Alpine field on the North Slope, which began producing in 2000.

New oil is badly needed in the Trans-Alaska Pipeline System, which is operating at about 520,000 barrels per day, one fourth of the amount of oil it shipped at peak production.

Oil production has been declining at an average 6 percent annually but new activity on the Slope could reduce that decline this year to about 1.5 percent and zero decline next year if the current trend of new production holds.

The petroleum industry is booming all over the U.S. due mainly to the revolution in shale gas and oil. Texas has tripled its oil production in the last five years and North Dakota has increased its output nine-fold, but Alaska has lost ground, Lance told the RDC.

Alaska adopted a tough new oil tax in 2007 just as shale oil and gas drilling was taking off in the Lower 48.

“The (2007) ACES tax created an adverse investment climate while conditions were favorable in the Lower 48,” he said, so investments for new development went there, not to Alaska.

The passage of an oil tax reform bill, Senate Bill 21, has changed things. Investment is flowing back to the state and the Alaska gas pipeline and LNG project are starting to move forward, Lance said.

“The state’s participation in the project has enhanced the alignment among the parties,” which include the North Slope producing companies, Lance said.

A joint-venture agreement on the gas pipeline deal is expected to be signed before July 1, state officials have said.

Lance told the RDC he sees a continued robust growth in shale gas and oil and North America moving into a dominant position as a global oil supplier as early as 2020. However, other countries are aggressively pursuing development of their own shale resources, he said.

“The geology is the same (for shale development) in most countries but what’s different is what’s on the surface. Most nations don’t have the wonderful infrastructure that we have. But they’ll catch up,” Lance said.

“I’m always asked if the shale plays have staying power, and we’re seeing that they do. There are about 20 shale trends in development today. Most are new areas, like the Permian Basin. Many of these straddle state boundaries and are transforming states that were not traditional oil producers. The political landscape is going to change.”

North America could become a significant LNG supplier to world markets, “but there will likely be limits placed on our (U.S.) LNG exports and Canada has infrastructure issues,” he said.

Given those constraints, North America might be able to supply 40 percent of the expected global growth, Lance said. U.S. gas production will exceed gas demand by 2016. After that the U.S. would be in a position to export gas, he said.

Citing U.S. Energy Information Agency forecasts, Lance said that by 2015, shale gas will contribute 43 percent of U.S. supply, up from 2.5 percent in 2005. By 2020, shale will contribute 52 percent of the nation’s gas, he said.

As for Alaska LNG, Lance said, “Alaska has advantages (for LNG export) because of its location relative to Asia markets and the desire by buyers to diversify supply.”

The state has one small LNG export plant in operation near Nikiski owned and operated by ConocoPhillips, but North Slope producers are pursuing a much larger project capable of exporting 15 million to 18 million tons per year.

It is in potential oil exports that North America could become very influential.

“We were producing 7 million b/d in domestic production just five years ago, and we are now at 10 million b/d,” he said.

In 2013, the U.S. experienced one of the largest annual oil production increases the world has ever seen, up 1.1 million b/d, according to the 2014 BP Statistical Review, which was released June 16.

In his talk, Lance said the U.S. Department of Energy is forecasting 12 million barrels per day by 2020 and some see 14 million b/d as possible, Lance said. Given that trend the U.S. could overtake Saudi Arabia and Russia as the world’s top oil producers.

Saudi Arabia produced an average 11.5 million b/d in 2013 and Russia produced 10.8 million b/d that year, according to the 2014 BP Statistical Review.

“We (the U.S.) will be in a position to be a net exporter by 2020,” he said. “That would have seemed impossible a few years ago.

“What’s important is that the U.S. will have a surplus of light, sweet crude that will exceed the capabilities of our refineries to process that oil. So we’ll need to export that and import heavier crudes more suited to our refineries.”

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AJOC EDITORIAL: What’s the revenue on a barrel of nothing?

Andrew Jensen, Managing editor
Alaska Journal of Commerce

The problem with starting a political campaign with a deception is that eventually it unravels and has to be abandoned or it has to be defended to the point of inanity.

Such is the case with the ongoing effort to repeal the oil tax reform passed in April 2013 as Senate Bill 21. The proponents of repeal and reversion to the previous regime known as ACES kicked off their petition drive and campaign asserting that SB 21 was a “$2 billion giveaway” to industry — a figure that was roughly based on the projected budget deficit for fiscal year 2014 that will end this June 30.

Of course they knew that was a bogus claim. Alaska was projected for near-term budget deficits while ACES was in effect and, in fact, the state ended the 2013 fiscal year with a deficit of more than $300 million before SB 21 took effect this past Jan. 1.

It is worth noting that the same people who tout and were responsible for passing ACES are the same ones who were in charge of the Alaska Senate and passed the capital and operating budgets that led to the 2013 deficit.

These same people have also begun to shift their tune about the “$2 billion giveaway” since University of Alaska economist Scott Goldsmith released a report that showed ACES and SB 21 bring in roughly the same revenue for the current fiscal year and Alaska would be in a deficit under either system.

That’s because while SB 21 removed the aggressive progressivity formula under ACES that kicked in at high prices, it did raise the base tax rate from 25 percent to 35 percent. That means the state takes in more revenue at lower prices under SB 21 than it does under ACES.

In response, the ACES proponents have shifted their spin after witnessing the cratering of their claim that the current budget deficit is the fault of SB 21.

Now, they will grudgingly acknowledge that in fact there is no “$2 billion giveaway” this year under SB 21 but argue that when prices rise the state won’t make its windfall share of the gain that it would have under ACES.

They also point to Goldsmith’s report that the state would have made $8 billion less under SB 21 that it did under ACES.

That is indeed true. But it raises the larger question: At what cost?

In the last year before ACES, 2007, the annual production decline on the North Slope was 1.86 percent.

In the succeeding years under ACES, the annual decline was 5.3 percent, 5.7 percent, 7.2 percent, 5.7 percent and 5.5 percent.

The total annual production on the Slope declined by 28.5 percent from 280.5 million barrels in calendar year 2007 to 200.3 million barrels in 2013.

The annual decline for the 2013 calendar year was 2.4 percent, and the estimated annual decline for the 2014 fiscal year ending June 30 is 1.8 percent based on production that is exceeding the Revenue Department forecast by more than 13,000 barrels per day (resulting in about $374 million in additional state take).

No matter how you slice it, the production decline was smaller and drilling activity was better in the last year before ACES and in the first year after it was repealed.

So let’s return to the question of the cost to the state for beefing up its savings accounts and spending more than $3 billion per year on capital budgets under ACES.

While it’s true that the state would have made less under SB 21 than it did under ACES from 2008-13, what if production had not declined at an average rate of about 5.3 percent at that same time?

What if production had instead declined by 2 or 3 percent or less annually under a more favorable tax regime during a climate of high prices that should have encouraged additional investment?

Based on the cumulative 80-million barrel drop from 2007 to 2013, the state would have been able to tax an additional 40 million to 60 million barrels of oil if the total production decline had ranged from 7 percent to 14 percent instead of the 28.5 percent we saw under ACES.

Not only would that considerably change the calculus in comparing SB 21 and ACES, the state would be on a much firmer financial footing looking forward with greater production than it is now after enacting a growth-stunting tax formula that left Alaska behind while the rest of North America boomed.

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Corps files proposal to justify CD-5 permit

Tim Bradner
Alaska Journal of Commerce

A lawsuit over a key federal permit is still in court, but ConocoPhillips isn’t slowing down on its construction of CD-5, a small satellite oil deposit near the Alpine oil field on the North Slope.

“Work on CD-5 is continuing,” ConocoPhillips spokeswoman Natalie Lowman said.

U.S. Alaska District Court judge Sharon Gleason accepted briefs June 20 on a suit filed by six villagers from Nuiqsut, a nearby Inupiat community, who claim construction of a bridge over a Colville River channel and roads to the CD-5 production pad will impair their subsistence activity.

The lawsuit was filed last year by Trustees for Alaska, an environmental law firm, on behalf of the six plaintiffs, against the U.S. Army Corps of Engineers. Earlier this year, Gleason found that the permit for the bridge and roads issued by the corps had not been adequately justified.

The State of Alaska and ConocoPhillips intervened in the case in the defense of the corps, along with the North Slope Borough and the Alaska Native corporations who own the surface and mineral rights.

Gleason asked parties in the case for recommendations on remedies to the permit problem, and those were filed June 20. Reponses to those briefs are required by July 1.

Trustees for Alaska proposed that Gleason order an injunction to stop work on the project until the issue on the permit it resolved. The Corps of Engineers proposed to prepare a justification for the permit and file it with the court within 90 days.

ConocoPhillips supported the corps proposal and urged Gleason not to halt construction. The company offered to limit its activity this summer to work on gravel pads that have already been constructed. ConocoPhillips, in its brief, said a work stoppage would disrupt the project and cause environmental harm.

Kuukpik Corp., the Native village corporation for Nuiqsit, sided with the corps and ConocoPhillips and took a position opposite the six village plaintiffs, arguing that delays in completing the bridge and roads would impair the village’s access to subsistence resources.

Isaac Nukapigak, president of Kuukpik, said his corporation, in which almost all Nuiqsut residents are shareholders, had worked with ConocoPhillips earlier to move the bridge and road routing to locations that would reduce impacts on subsistence activity.

Nukapigak also warned that delaying the project and leaving CD-5 roads and bridges partly finished could create hazards for the villagers since some may be tempted to use the uncompleted facilities to reach subsistence sites.

Kuukpik owns the surface mineral rights at CD-5; Arctic Slope Regional Corp., which has also intervened in the case on the side of the corps, owns the subsurface rights.

The lawsuit, filed last year, claims that construction of a bridge and placement of gravel of wetlands will impair habitat important to subsistence activities by the village.

The case is being watched closely by the industry and the state because CD-5 is the first commercial development in the National Petroleum Reserve-Alaska, and the road and bridge infrastructure will also support ConocoPhillips’ development of other NPR-A projects including Greater Moose’s Tooth-1, or GMT-1, another project eight miles west of CD-5.

If it stays on schedule, CD-5 will begin production in late 2015 and will produce 16,000 barrels per day at peak. GMT-1 is scheduled to begin producing in late 2017, with 30,000 b/d peak production, but ConocoPhillips’ board must still approve the project. The company is now working on permits for the project and a draft supplemental environmental impact statement is expected this fall from the U.S. Bureau of Land Management, which administers the federally-owned NPR-A.

Trustees for Alaska, in its original lawsuit, argued the corps approved the CD-5 permit without adequately justifying a decision allowing a bridge across the Colville River, and roads to the CD-5 site, over an alternative the corps itself approved earlier for an underground pipeline crossing of the river and no road to the site. Trustees said the agency did not adequately explain why it had switched its position.

“The (federal) court found the corps had failed to provide a reasoned explanation for why no supplemental NEPA (National Environmental Policy Act) analysis was necessary to address substantive project changes. The changes to align road, pad location and bridge location all have a substantive and significant bearing on the project’s impact to subsistence resources, making the failure to consider the changes significant and serious,” Trustees wrote.

In its request for an injunction filed June 20, the environmental firm cited precedents where federal courts have vacated permits and ordered injunctions where similar flaws in permits were uncovered.

In March this year, Gleason declined to issue an injunction to stop construction at CD-5.

In its filings, ConocoPhillips outlined work that has been completed at CD-5 and activity planned for 2014. In a document filed with the court, James Brodie, ConocoPhillips’ CD-5 project manager, said the entire gravel “footprint” for the project is in place and includes the road, CD-5 pad an valve access pads.

A small amount of gravel is needed on top of the Nigliq channel bridge east abutment, which will be placed next winter without expanding the footprint area.

Four bridge structures were installed last winter including foundations of tubular steel piling, gravel-filled sheet pile abutments, steel superstructure and concrete and deck guardrails.

One bridge is totally complete; two others are structurally complete but require minor deck work. The main bridge of the project, the Nigliq channel crossing, has its piling and other structure but the final span has yet to be installed. That is planned this fall.

In work this summer, Brodie said a construction crew started work June 1 on tie-in work for the CD-5 pipeline at the central Alpine production facility. The work mainly involves welding.

In July, construction crews will mobilize to begin contouring and shaping, and compacting, the gravel that was laid last winter. Typically gravel placed one winter on the Slope must be allowed to “season” over a summer to allow ice to melt out. After that it can used the next winter. This work will be done by Sept. 15, Brodie said.

Also, a logistics and material team at Deadhorse will be receiving pipeline materials in July, including pipe sections, pipe supports and saddles. Finally, a construction crew will start work in September to prepare the placement of the final spans on the Nigliq Channel bridge. That will occur in November, Brodie said.

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Saturday, June 21, 2014

Parnell terminates state’s AGIA contract with TransCanada

Tim Bradner
Alaska Journal of Commerce

A much-criticized 2010 agreement between the State of Alaska and TransCanada Corp. to pursue a large North Slope natural gas pipeline is now in the past.

Gov. Sean Parnell signed documents June 17 terminating the contract with TransCanada, negotiated under the state’s Alaska Gasline Inducement Act, or AGIA.

This sets the stage, Parnell said, for a larger joint-venture agreement with the pipeline company and North Slope producers BP, ConocoPhillips and ExxonMobil.

The new partnership is focused on a large gas pipeline from the North Slope and a large plant to export liquefied natural gas, or LNG, at Nikiski,

TransCanada and the state, as well as the producers, were originally focused on an all-land pipeline to Alberta but the development of abundant shale gas in the Lower 48 ended that project, for now.

TransCanada has accepted the termination as a step toward the larger LNG export agreement, state Natural Resources Commissioner Joe Balash said.

The next step is for the parties to sign the joint-venture agreement spelling out responsibilities and cost-sharing to ramp up the next phase of the process, which is expected to include preliminary engineering and design and getting a more specific estimate of costs.

Balash said discussions surrounding these issues have been going on for months and he saw no reason for the agreement and associated documents to not be signed. The state itself will be a signatory to the part of the agreement on the LNG plant through the Alaska Gasline Development Corp., a state corporation that would hold the state’s 25 percent share of the plant.

Both ExxonMobil Corp. and BP are ready to sign, spokeswomen for those companies said June 17. TransCanada spokesman Shawn Howard, by email to the Associated Press, said his company has resolved its issues with the joint-venture agreement.

Howard declined to say what those issues were, saying they were part of the discussions between parties that he could not discuss publicly.

ConocoPhillips spokeswoman Natalie Lowman said there were still “open issues” that needed to be resolved from the company’s perspective. Lowman did not specify the issues, saying negotiations are confidential.

She said by email to the Associated Press that the company continues to support moving the project forward and all parties were “working closely to bring these agreements to closure.”

State officials expect the Joint Venture Agreement to be signed before July 1, said Elizabeth Bluemink, spokeswoman for the state Department of Natural Resources.

The 2010 AGIA contract with TransCanada had become a thorn in the side for Alaskans because it obligated the state to pay` $500 million in subsidies to the pipeline company for its efforts to put together a pipeline project on its own. The contract provided for the state to pay 50 percent of TransCanada’s costs until an “open season” in 2010 and 90 percent of its costs after 2010.

The Lower 48 pipeline effort was unsuccessful and led eventually to the larger effort now underway focused on a LNG export project, but not before the state had paid TransCanada $300 million under the AGIA deal. Any future refunding obligation is voided, however.

The AGIA contract also limited the state’s ability to pursue alternative gas projects, mainly a smaller in-state gas pipeline that could be built if the larger project does not move forward. Those limits are now also lifted.

Signing of the new Joint Venture Agreement will launch a Pre-Front End Engineering or Design phase for the pipeline and LNG project, although parts of the pre-FEED are already underway, Balash has said previously.

The pre-FEED will generate updated cost estimates for the project, now estimated at between $45 billion and $65 billion. The new estimates are expected to be available in late 2015, the commissioner said.

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Friday, June 20, 2014

Houston company takes stake in Brooks Range

Tim Bradner
Alaska Journal of Commerce

Brooks Range Chief Operating Officer Bart Armfield confirmed Houston independent Thyssen Petroleum Corp. will take an equity stake in the company developing the Mustang field on the North Slope. The transaction will mark the fourth new entrant to the Slope in the last year.

Brooks Range Chief Operating Officer Bart Armfield confirmed Houston independent Thyssen Petroleum Corp. will take an equity stake in the company developing the Mustang field on the North Slope. The transaction will mark the fourth new entrant to the Slope in the last year.

Another small independent company is taking a stake in new North Slope development. Thyssen Petroleum Corp. of Houston has taken an equity position in Brooks Range Petroleum Corp., an Alaska-based company active in exploration and development on the Slope.

Thyssen Petroleum’s investment was confirmed by Brooks Range Chief Operating Officer Bart Armfield. Thyssen will buy the equity shares of Brooks Range that are now held by Alaska Venture Capital Group, a consortium of small Kansas-based independents, and Ramshorn Investments Inc., a subsidiary of Nabors Industries.

There may be additional investors in Brooks Range announced soon.

Brooks Range has been exploring on the Slope for more than a decade and is now developing one of its discoveries, the small Mustang oil field west of the Kuparuk River field.

The company plans to have first production in early 2016, Armfield said.

Mustang is expected to initially produce between 8,000 barrels per day and 10,000 barrels per day in 2016, its first full year of production, and about 12,000 b/d in 2017 as development drilling in the field is completed, Armfield said.

An oil gas processing facility being built at the field will have to capacity to process 15,000 b/d and will be available for other companies developing nearby prospects to use, he said.

Armfield said drilling on three production wells will begin this fall with drilling of six to eight additional wells in 2015 to provide the initial production. Another eight to 10 wells are planned in 2016, he said. Two test wells were drilled at Mustang in 2011 and 2012.

Total costs for the project, including the plant and drilling, are estimated at $580 million, Armfield said. The Alaska Industrial Development and Export Authority is investing $50 million in the process plant, which is estimated to cost between $200 million to $220 million.

AIDEA has also invested about $20 million in a $27 million gravel access road and pad to support the Mustang project. Other partners in the project including Brooks Range also contributed to the road and pad construction.

The authority’s investment in the processing plant, as in the road and pad, are structured so that AIDEA is a preferred member in the two limited liability companies created for the projects. The agreements provide for AIDEA’s share to be purchased by the other parties.

Over time Mustang will generate about $300 million in new state tax and royalty revenues and North Slope Borough tax revenues, according to estimates developed by AIDEA.

Mustang’s resources are estimated at 24 million barrels of recoverable reserves but there are additional prospects nearby that Brooks Range intends to pursue after the initial project is producing, Armfield said.

Its investment in Brooks Range will be Thyssen Petroleum Corp.’s first venture into Alaska. The company is now focused on production onshore in the U.S. Gulf coast states. Thyssen was not available for comment.

The company is the latest of a number of small companies becoming active on the slope. Miller Energy, a small Tennessee-based company active in Cook Inlet, through its subsidiary, Cook Inlet Energy, recently purchased Savant Alaska, a majority owner and operator of the small Badami field east of Prudhoe Bay.

Earlier this year Caelus Energy, a newly-formed independent, completed the acquisition of Pioneer Natural Resources’ Alaska assets, which include the producing offshore Oooguruk field near the Kuparuk River field.

Another new entrant on the North Slope will be Hilcorp Energy after that company’s deal is approved to acquire properties now owned by BP. Hilcorp will acquire two small producing offshore fields, Northstar and Endicott, as well as 50 percent of the Milne Point field, whch is onshore. Hilcorp would be the operator of all three fields.

Hilcorp would also become 50 percent owner in Liberty, a small offshore project that is not yet developed. BP would remain as operator of that project, however. A development plan is to be submitted for Liberty to the U.S. Bureau of Ocean Energy Management by the end of the year.

The Hilcorp acquisition of the BP properties is expected to be given final approval by the end of the year.

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Bering Straits Native Corp. seeks land for future Arctic port

Elwood Brehmer
Alaska Journal of Commerce

The prospect of new port facilities in Western Alaska will rely heavily on Arctic oil and gas development, according to a recent Northern Economics study.

Commissioned by Bering Straits Native Corp. and marine services company Crowely Maritime Corp., the feasibility analysis released June 6 focused on Port Clarence, northwest of Nome on the Seward Peninsula.

BSNC found that a “basic” port and man camp could be up and running within four years of a firm oil and gas industry commitment to engage in developing the Alaska Outer Continental Shelf, or OCS, energy resources.

Northern Economics Inc. is an Anchorage-based consulting firm that frequently analyzes resource and infrastructure development in Alaska.

Shell was the last company to do major work in the Chukchi and Beaufort seas in 2012, drilling partial “top holes” in leases at each. Shell was restricted to only drilling above oil-bearing zones because its spill response barge had not been approved for Arctic operations.

With the 2008 Chukchi lease sale environmental impact statement now being revised by the Bureau of Ocean Energy Management after a court order, it is unclear exactly when Arctic OCS oil and gas exploration will resume. The agency is targeting March 2015 to complete its work, which could allow for Shell to have a working season that year. When it does, BSNC wants to be ready.

Early stage infrastructure at Port Clarence would likely cost between $34 million and $72 million, with a likely total falling in the $48 million range, the study determined. With that money, a basic, gravel-filled sheet pile dock, similar to that at the Red Dog port, and a 66-man camp could be constructed, according to the study.

One of the biggest reasons Port Clarence was the focus of the study is its low projected ongoing costs when compared to other, more developed sites in the region. Operations and maintenance for the preliminary development is forecast at $1.4 million per year. When assumed debt service on the infrastructure is added, the annual revenue requirement of such a base is estimated at $4.15 million.

Port Clarence is one of a handful of spots on Alaska’s western coast with naturally deep water; it would require little to no dredging. Its mean near-shore depth is about 35 feet, and the channel past Point Spencer leading into the natural harbor is more than 40 feet deep.

Northern Economics concluded that oil and gas exploration and oil field support services were the only two large industry markets likely to use the port regularly.

If the decision is made by the oil industry to further invest significant money into Arctic OCS exploration — Shell alone has said it has spent upwards of $6 billion there already over eight years — the critical decision to develop or not would likely come in 2018 or 2019, according to the study. An active and ready Port Clarence would be needed not long after.

The study noted that Port Clarence is about 500 miles from the majority of the federal Chukchi OCS oil and gas leases. Dutch Harbor, currently the closest domestic deepwater port, is more than 1,300 miles from the lease areas, a distance that could make timely emergency or spill response difficult.

Port Clarence is typically ice-free from early June through mid-October, according to the study. In the study, Crowley is cited as suggesting ice breakers could expand the operating season up to 10 months a year.

The depth characteristics of the port are one of the reasons BSNC is seeking conveyance of the shoreside land, the region Alaska Native corporation has said.

“The growing potential of the Arctic is a high priority for us. I believe that in addition to supporting oil and gas industry needs, Port Clarence is going to positively contribute to sustainable economic growth in the region,” BSNC President and CEO Gail Schubert said in a formal statement.

In May Rep. Don Young introduced legislation to the House to transfer nearly 2,400 acres of federal land on and near Point Spencer to BSNC as part of the land owed to it under the Alaska Native Claims Settlement Act, plus 180 acres to the State of Alaska.

Current infrastructure at Point Spencer includes an airstrip and a U.S. Coast Guard LORAN-C navigation facility, decommissioned in 2010. Young’s bill would allow the Coast Guard to retain its use of the 140-acre site and give it the option of leasing space from BSNC if it needs to in the future.

Rep. Duncan Hunter, R-Cali., chairman of the Coast Guard and Maritime Transportation Subcommittee supported the legislation, Young said in a May 16 release.

“We are desperately in need of development in the region, particularly as activity in the Arctic continues to increase, and this bill establishes a path forward for a variety of necessary tasks and missions, including search and rescue operations, shipping safety, economic development, oil spill prevention and response, port development and refuge, arctic research, and maritime law enforcement,” Young said.

Increasing maritime activity in the Bering Strait is a major reason the U.S. Army Corps of Engineers is also investigating the possibility of enhancing the marine infrastructure in the region, currently centered in Nome. In March 2013, the Corps of Engineers released a preliminary study of its own — part of ongoing multi-year planning — that narrowed a list of potential Western Alaska deepwater port sites to Nome and Port Clarence, specifically for their respective infrastructure and proximity to deep water.

A number of projections have been made as to how much Bering Strait vessel traffic will increase in the coming years if summer Arctic sea ice continues to recede. The study reports that from 2009-2013, the trans-Strait vessel count grew from 239 to 349 in 2013, including the first liquefied natural gas tanker — headed south — through the Strait.

The Northern Economics team referenced the Corps of Engineers work numerous times in its study. A federal Arctic port plan was originally scheduled to be released earlier this year, but a desire by Corps leadership to investigate more options in regards to specific site plans has pushed the release of the draft plan back closer to the end of the year, according to Corps of Engineers Alaska spokesman Curt Biberdorf.

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Saturday, June 14, 2014

July hearing set for Kenai Loop gas payments

Elwood Brehmer
Alaska Journal of Commerce

Buccaneer Energy, Cook Inlet Region Inc., and the State of Alaska will be back before the Alaska Oil and Gas Conservation Commission July 7 to duke it out once more over gas royalty rights from Buccaneer’s Kenai Loop well pad.

The hearing will be held — as has been the case with most milestones in the dispute — if the parties cannot come to an agreement on royalty payments prior to July 7.

CIRI claims Buccaneer owes it royalties for gas Buccaneer drained from the Native corporation’s land that is adjacent to the Kenai Loop pad. Buccaneer once held a now-terminated gas lease with for the CIRI property. It does not dispute that the drainage is occurring.

The Alaska Mental Health Trust Authority, which owns the property under the Buccaneer pad also owes it money, CIRI claims, because the authority has been receiving royalties on gas that CIRI had right to.

Whether or not CIRI is liable for production expenses if it is eligible to receive gas revenue will be another point of debate at the hearing.

The commission ordered Buccaneer to set up an escrow account by June 1 to hold its Kenai Loop production revenue until the dispute is resolved and make monthly deposits to the account starting June 10.

Formation of the account has been delayed as Buccaneer asked the commission for clarification regarding details in the order and a brief comment period for the other parties was also established.

How Buccaneer’s May 31 filing for Chapter 11 bankruptcy filing in South Texas will impact negotiations and where its money goes immediately remains unclear.

All of the parties have said an agreement has been close at times during months of negotiations.

Buccaneer’s bankruptcy filings list the company’s combined assets at between $50,000 and $500,000 and liabilities of $50 million to $100 million.

In May 2013, Division of Oil and Gas Director Bill Barron denied Buccaneer’s application to form a Kenai Loop unit from its leases in the area.

When the application was submitted in July 2012 Buccaneer was the working interest owner to 7,499 acres of lease space in the proposed unit. The company had right to 4,827 acres Mental Health Trust Authority land, its 1,275-acre lease with CIRI and 1,391 acres of state land over four leases.

Units are typically formed when an oil or gas pool extends beyond a sole landowner’s property; they are a way to parcel royalties and prevent drainage or other resource rights disputes among multiple lessees.

Before the decision to deny the unit was made, CIRI informed the division that it had terminated Buccaneer’s lease, but Buccaneer did not acknowledge that fact, according to Barron’s ruling.

CIRI’s termination of the lease has subsequently been upheld in Alaska Superior Court.

Barron wrote in the 20-page document that his decision was based on the fact that Buccaneer was at the time the sole working interest owner in the area, thus making unit formation unnecessary.

Additionally, the state land leases were set to expire on at the end of September 2012 when the application was filed a couple months prior to their expiration. The only interest that would have been protected by granting the unit would have been Buccaneer’s by way of gaining state lease extensions, according to Barron’s findings.

He also claimed that Buccaneer made no commitments to fully develop the gas resources in the unit, and “exploration may be a component of unit activity but the primary purpose of unitization is development of reserves proven during the primary term of a lease,” Barron wrote.

Subsequently Buccaneer appealed Barron’s decision in April 2013 to the Department of Natural Resources commissioner. That appeal is currently unresolved before commissioner Joe Balash.

The commissioner is withholding a decision on the appeal while the “fundamental issues involving the leases that would underpin the proposed unit are addressed” through either a settlement reached by the parties or the conservation commission process, according to DNR spokeswoman Elizabeth Bluemink.

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Sunday, June 8, 2014

Point Thomson-TAPS connection complete

By Elwood Brehmer
Alaska Journal of Commerce

After a second winter construction season, the connection between the Point Thomson gas field east of Prudhoe Bay and the Trans-Alaska Pipeline System was completed this March. ExxonMobil expects to be producing 10,000 barrels of condensates per day into TAPS by 2016 from Point Thomson. The total project will cost about $4 billion.

After a second winter construction season, the connection between the Point Thomson gas field east of Prudhoe Bay and the Trans-Alaska Pipeline System was completed this March. ExxonMobil expects to be producing 10,000 barrels of condensates per day into TAPS by 2016 from Point Thomson. The total project will cost about $4 billion.

At Point Thomson, it is $2 billion dollars down and $2 billion to go for ExxonMobil.

Sofia Wong, the Point Thomson infrastructure and pipeline manager for ExxonMobil, said a pipeline connecting the eastern North Slope gas field to the Trans-Alaska Pipeline System, or TAPS, was completed in March.

The 12-inch, 22-mile pipeline will carry natural gas condensates to the Badami field line that is a common carrier to TAPS, she said.

“Our expectation is by 2016 we will be starting to produce at 10,000 barrels per day (of condensates) into TAPS,” Wong said.

A hydro test will likely be run on the pipe in July.

The pipeline has a capacity of 70,000 barrels per day. Early production will be slow with three wells — two injector wells and one production — until it’s known how the gas reserve responds to production, she said.

Point Thomson is about 60 miles east of Prudhoe Bay on the edge of the Arctic National Wildlife Refuge. The natural gas field is estimated to hold roughly 8 trillion cubic feet of gas, roughly 25 percent of total North Slope gas reserves. The gas also contains about 200 million barrels of usable liquids. It was originally discovered in 1977.

Unlike Prudhoe Bay gas, the Point Thomson field is under high pressure, Wong said, making it easy to capture the liquids for TAPS.

“When you get gas at 10,000 pounds and you let it expand into separators, the condensate, the liquids just simply fall out and you collect those and put them into the pipeline,” she said. “(It’s) very simple from a process standpoint.”

The gas processing facility will arrive at Point Thomson via barge along with summer in 2015. The four-piece modular plant is currently being constructed in Korea, according to Wong.

To date, ExxonMobil has spent about $2 billion on Point Thomson. The major producer expects to spend a total of about $4 billion on the project to get it to full production, the company has said.

During the winter of 2012-13, the first construction season for ExxonMobil at Point Thomson, about 2,200 vertical supports were installed for the pipeline.

Nearly all of the pipeline construction work was done by a subsidiary of Interior Alaska Native corporation Doyon Ltd., Wong said.

The peak of just-completed winter construction at Point Thomson saw about 1,200 people working on the project, she said, similar to the first-year job numbers. Of those, 729 were rotational Slope positions, meaning some were backed by an additional laborer.

Wong said ExxonMobil has a camp of about 100 workers in Deadhorse managing logistics. Overall, Alaska-hire rates on Point Thomson are in the 85 percent range, she said.

Other major work last winter included laying another 1 million cubic yards of gravel to expand the site pad to the north on top of the 1 million cubic yards laid during the first construction season.

Over the summer, 2.2 million gallons of diesel storage was added to the site, Wong said. Completion of a warehouse and Alaska Clean Seas maintenance facility is scheduled for this year’s warmer months.

The infrastructure at Point Thomson will go a long ways towards spurring future North Slope gas development, particularly since the State of Alaska, the three major Slope producers, and TransCanada, a pipeline company, have agreed on a framework of ownership for a large export liquefied natural gas project, she said.

“Point Thomson has been key to the progress we’ve made on the large (LNG) project,” Wong said.

If the $40 billion to $65 billion project ever comes to fruition, she said another $6 billion to $8 billion of investment will be needed at Point Thomson to capture the gas there and would be part of the overall expenditure. She said that investment would include a 30-inch gas line connected to a treatment plant in Prudhoe Bay.

“It’s the 8 trillion cubic feet of gas that we’re focusing on; that’s really what I call the prize,” Wong said. “The condensate that comes along with that is just gravy that comes on top of the natural gas.”

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Friday, June 6, 2014

Buccaneer files for bankruptcy

By Tim Bradner and Elwood Brehmer
Alaska Journal of Commerce

The Alaska Industrial Development and Export Authority and Ezion Holdings, owners of the Endeavour-Spirit of Independence jack-up rig, seen at Homer in March 2013, are looking for work in Cook Inlet this summer after Buccaneer Energy filed for Chapter 11 bankruptcy May 31.

The Alaska Industrial Development and Export Authority and Ezion Holdings, owners of the Endeavour-Spirit of Independence jack-up rig, seen at Homer in March 2013, are looking for work in Cook Inlet this summer after Buccaneer Energy filed for Chapter 11 bankruptcy May 31.

Buccaneer Energy, an independent Cook Inlet explorer with high hopes but skimpy resources, saw those hopes come crashing down May 31. The company filed for Chapter 11 bankruptcy protection that day in a U.S. Bankruptcy Court in south Texas.

The company has been fighting a rear-guard action on finances almost since the time it arrived in Cook Inlet, bidding on lease sales and then bringing a jack-up rig to the Inlet from Asia with a Singapore company and the State of Alaska as partners.

Buccaneer had also become embroiled in a dispute with Cook Inlet Region Inc., which owns land adjacent to the state land on which Buccaneer’s producing Kenai Loop gas wells are located.

Buccaneer previously had a lease on the CIRI land but the Anchorage-based Alaska Native corporation for Southcentral terminated the lease. Buccaneer sued, claiming the termination was improper, but lost in court.

Meanwhile, CIRI filed a complaint with the Alaska Oil and Gas Conservation Commission, the state agency that regulates industry production practices, alleging that Buccaneer’s Kenai Loop wells were draining gas from its lands.

After two hearings and months of deliberations, the conservation commission decided May 22 to escrow all revenues from gas sales minus operating expenses at Kenai Loop until it could sort out how the gas should be shared among Buccaneer, CIRI, the State of Alaska and the Mental Health Land Trust. Under the commission order, the escrow account was to be created at an Alaska bank by June 1, and revenues to be deposited on the 10th day of each month beginning in June until an allocation was determined. Cut off from its only source of cash income amid its restructuring, Buccaneer had no choice but to file for protection, sources familiar with the company said.

In bankruptcy filings for its parent and subsidiary companies, Buccaneer claimed combined assets of $50,000 to $500,000 and liabilities of between $50 million and $100 million.

In a state Superior Court civil dispute between Buccaneer and CIRI paralleling the AOGCC case, the Native corporation sued for compensation over the gas drained from its land.

On April 22, Judge Frank Pfiffner stayed a ruling on CIRI’s drainage claims until a decision is handed down by the commission or an agreement is reached between CIRI, Buccaneer, the Department of Natural Resources and the Mental Health Trust Land Office, which owns the Kenai Loop property adjacent to CIRI’s parcel.

As of June 3, Buccaneer had not set up the escrow account, AOGCC Commissioner Cathy Foerster said. The company asked for clarifications regarding its responsibilities, she said, and a 10-day comment period was issued for the other parties involved to respond.

June 10 is also the deadline set by the commission for the parties to reach an agreement on gas and royalty payments. If an agreement is not reached, the commission will determine gas rights at a future hearing.

“We don’t have an agreement yet; we’ve been close a few times over the last year — certainly the last six months,” DNR Commissioner Joe Balash said June 2. “I would say there’s no good reason we don’t have an agreement, that’s my perspective.”

The “hodgepodge” of subsurface ownership, combined with disputing past and future payments has complicated negotiations, he said.

Trust Land Office Deputy Director John Morrison said there has been “good communication among all four parties” and that he felt they were close to an agreement June 3.

CIRI spokesman Jason Moore said it is unclear whether Buccaneer’s bankruptcy would influence negotiations, but also that the Native corporation could see the bankruptcy coming.

Moore said CIRI pressed for the escrow account to be set up to hold funds in dispute.

Further, he said the Trust Land Office owes CIRI “a lot of money” for royalties it has taken from CIRI gas produced on the Kenai Loop pad. CIRI has a right to 20 percent of production minus expenses, according to Moore.

CIRI Land and Energy Development Vice President Ethan Schutt said at an April 21 AOGCC hearing that the Kenai Loop wells were producing in the neighborhood of 8 million cubic feet of gas per day.

Morrison said the Trust Land Office is “pretty comfortable” that the payments it receives from Buccaneer will be safe from creditors involved in the Chapter 11 bankruptcy action after discussing the issue with counsel.

Foerster said she did not know whether the bankruptcy would affect Buccaneer’s regulatory commitments.

As for the Land Trust Office’s royalties, Balash said there is a memorandum of understanding, or MOU, between the Alaska Mental Health Trust Authority and DNR that gives the department the responsibility to help the authority maximize revenue from its lands. The MOU shifts gas royalty payments that typically go to the Division of Oil and Gas to the Trust Land Office when produced on Trust land, he said.

“At least from where I sit (the MOU) causes all ‘ties’ to go to the trust, and that’s OK because the situation we find ourselves in is that it’s either going to the general fund or the Mental Health Trust account and either way they’re state sources of revenue,” Balash said.

Income from leasing and resource development on the 1 million acres of Mental Health Trust land across the state is part of the roughly $26 million the trust budgets each year for programs and services for Alaskans with disabilities and mental illness, according to the trust.

Overall, Balash said the state has had “a couple rubs” with Buccaneer during the company’s oil and gas work in the state, but he said the issues were nothing out of the ordinary. Buccaneer still holds other Cook Inlet leases that are currently without issue, he said.

“They were an aggressive company and had a lot of enthusiasm; they just didn’t have enough capital,” Balash said.

Plague of problems

Before the May 22 Kenai Loop decision and the May 31 bankruptcy filing, a lot of other things went wrong for Buccaneer, including a dispute and a lawsuit with its first rig operator, delays in getting the jack-up operating, problems siting the rig at an offshore location in the Inlet and an expensive dry-hole on the Peninsula.

The unraveling of the company’s Alaska strategy began in March when the board of directors suspended CEO Curtis Burton with pay pending a review of operations. Burton meanwhile filed a lawsuit in a Texas state court arguing a breach of his employment contract.

On May 14 the board completed its review, terminated Burton and also removed him from the board. Burton’s lawsuit continues, meanwhile.

What really aggravated the financial situation was when an investor that had promised to help fund expensive offshore drilling at Buccaneer’s Southern Cross prospect failed to come through with the money.

One of Buccaneer’s shareholders, Meridian Capital International Fund, stepped in with interim financing, but the company was still left seeking other longer-term capital.

There was a second win, however, with a potentially major gas discovery at Cosmopolitan, near Anchor Point. It was a bittersweet development, though. To raise cash, Buccaneer had to sell its minority interest in the discovery to its partner in Cosmopolitan, BlueCrest Energy of Fort Worth, and also its share of the jack-up rig.

Through all of this, Buccaneer worked on a long-term refinancing strategy.

On April 30 the company’s major creditor, Meridian Capital CIS Fund, an affiliate of Meridian Capital International, sold its debt to Houston-based AIX Energy LLC, a privately-held energy finance group that has been affiliated with Meridian. Meridian itself remained as a major shareholder in Buccaneer.

Sources familiar with Buccaneer said a major payment to AIX on the debt is due June 30, but that may be delayed due to the bankruptcy.

What made people really take note of Buccaneer initially in Cook Inlet was its discovery of the small Kenai Loop gas field near the city of Kenai and successful production of gas in 18 months from the time the exploration well was drilled, which is light-speed compared with the lengthy permitting and occasional lawsuits that get other companies bogged down.

Ironically, it was Kenai Loop that finally forced the company into bankruptcy after the commission’s decision. The company will now sell most of its assets.

Kenai Loop’s discovery came at a time when the regional utilities were deeply worried about depleted gas fields in Cook Inlet and the possibility that they would have to import gas as liquefied natural gas. Buccaneer showed, with a drill bit, that there was still gas to be found.

Also, the company found new gas just a mile from the long-producing Cannery Loop gas field, formerly owned and operated by a large company, Marathon Oil. This seemed to show that the large companies like Marathon that have long dominated the industry were not aggressively exploring despite the utilities’ worries.

“As part of the Chapter 11 proceedings Buccaneer Energy has also reached an agreement in principle with its secured lender on certain critical elements of a plan of reorganization that would result in the sale of substantially all of the company’s assets,” Buccaneer said in a June 2 press release.

Meanwhile, there are no changes, for now, in production operations. The company has three employees overseeing the Kenai Loop gas wells.

“Buccaneer will continue to operate and oversee its assets during and throughout the restructuring process,” the press release said.

The restructuring should allow Buccaneer to pay off its creditors, but at the expense of its assets.

“The company expects to have sufficient cash on hand throughout the Chapter 11 proceedings to pay all of its post (bankruptcy) petition obligations as they come due,” the press release said.

What next for Endeavor rig?

With the bankruptcy filing of Buccaneer Energy, what happens to the Endeavour jack-up rig that is still parked at Port Graham in lower Cook Inlet and partly owned by the Alaska Industrial Development and Export Authority?

The answer: AIDEA and Ezion Holdings, the remaining partner in the rig, are looking for work for the rig and wells to drill.

Buccaneer had chartered the rig for its exclusive use to drill several wells in the Inlet this summer, including a deep test for oil at the “Tyonek Deep” North Cook Inlet gas field held by ConocoPhillips’.

That well will not be drilled, this summer at least. AIDEA officials expect Buccaneer will be relieved of its charter obligation as a part of the bankruptcy filing.

Assuming the South Texas bankruptcy court approves this, the rig would be placed back under the control of Kenai Offshore Ventures, the AIDEA/Ezion partnership that owns the Endeavour, according to Mike Catsi, business development manager for the authority.

“KOV, through its member-manager Ezion, is already investigating and negotiating with a replacement rig manager,” an entity to take the place of Buccaneer.

The day-to-day management of the rig is through a drilling contractor, Spartan, which is also managing the other jack-up rig in the Inlet, the Spartan 151 that is working for Furie Operating Alaska, another independent working in the Inlet.

Catsi said Buccaneer, through a subsidiary Kenai Drilling, was obligated to make payments and it did so through Dec. 1, 2013.

However there were five monthly payments from the end of 2013 and through the first months of 2013 that were deferred and not yet due, Catsi wrote in an email.

There may yet be business for the rig.

“AIDEA has been approached by another party who has expressed strong interest in using the rig in Cook Inlet. AIDEA has passed this information through to Ezion Holdings,” Catsi wrote.

Buccaneer had promoted the rig being brought to Cook Inlet and persuaded AIDEA and Ezion Holdings to help finance the purchase of the drilling unit and its move to the Inlet.

Buccaneer was originally an investor and a major partner in Kenai Offshore Ventures but had to sell its shares last year when the company encountered financial difficulties.

Although it was no longer an owner, Buccaneer still had its charter of the rig for drilling, however.

In his email, Catsi described AIDEA’s current relationship with the rig: “AIDEA is a Preferred Member in Kenai Offshore Ventures, LLC with a stake of about $23.6 million invested. Ezion Holdings Limited and its affiliate Teras Investments Pte., Ltd. (who bought out Buccaneer’s stake in KOV in January of this year) are the Common Members of KOV; Buccaneer is no longer a member of KOV,” Catsi wrote.

“AIDEA is entitled to receive repurchase payments of its entire investment plus dividends at fixed dates, if KOV’s revenues and cash permit. AIDEA has received one payment against dividends owed to AIDEA of about $4,062,000 in February of this year. All of AIDEA’s investment plus dividends must be repaid by KOV by January 1, 2018 (regardless of KOV’s revenues and cash) or AIDEA may pursue recourse to all its security including the rig.”

The Endeavour is capable of drilling to 20,000 feet and in water depths up to 300 feet. It was originally designed for the North Sea but was in storage in Asia when it was purchased by the Kenai Joint Ventures partners. After modifications it was brought to Cook Inlet.

The other jack-up rig in the Inlet, the Spartan 151, was brought earlier from the U.S. Gulf coast by Escopeta Oil and Gas (now Furie Operating Alaska).

AIDEA made the decision to help Buccaneer get its jack-up to Alaska because at the time it was not clear that Escopeta could get the Spartan rig moved. The authority felt there was an urgent need to have a jack-up rig in Alaska because of the belief then that there could be shortages of natural gas in Southcentral Alaska.

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