Tuesday, July 31, 2012

State’s biggest barge crane aids Inlet salvage operation

Jonathan Grass
Alaska Journal of Commerce

The DB Salvation was brought to the Christy Lee oil loading platform in Cook Inlet by Pacific Pile and Marine. The 600-ton crane will lift the fender that detached and sunk in March. Global Diving & Salvage will do the dive work for the project.
Courtesy Global Diving & Salvage

In March, a mechanical failure caused a 180-foot steel fender to detach from the Christy Lee oil-loading platform on the west side of Cook Inlet near Kalgin Island. Now a major diving operation is under way to retrieve the sunken piece for repairs.

Size matters for this operation. The biggest marine crane currently operating in Alaska has been commissioned to lift the massive piece of infrastructure. The Derrick Barge Salvation is 300-foot by 90-foot barge with a 600-ton crane. It has the capacity to lift 600 tons off the stern and 350 tons over the side.

The Salvation also carries a 110-ton capacity support crane and a four-way mooring system to assist in the rigging and service lifts.

Pacific Pile and Marine is operating the Salvation and providing the heavy lift support. The Salvation is the largest piece of its marine construction fleet.

The specialized machine will pull the dormant fender off the ocean floor. It will then be raised, repaired and reattached.

“I suspect before the end of October it will be fully installed and back functioning,” said Hilcorp Facilities Manager Bo York said. Cook Inlet Pipeline Co. owns the Christy Lee while Hilcorp is the parent company. Cook Inlet Pipeline is a common carrier company, enabling the two to operate independently.

The repairs are mostly for the hoist mechanism, which is what failed in March. The fender itself will require minor repairs.

Christy Lee is an offshore platform that’s unique in Cook Inlet in that it’s an oil-loading facility as opposed to being an exploration and production platform.

The fender acts as a buffer for offloading vessels. After it dislodged and sank, Tesoro Maritime Co., which is Christy Lee’s sole shipping customer, was worried about sending tankers to the platform. York said a tanker vessel typically goes into the port every 10 to 14 days so a solution had to be drawn fast.

“Without this fender there, Tesoro was not comfortable bringing their tanker vessel up,” York said.

A temporary floating fender system was quickly installed. This system could only be temporary because it would not be able to handle the winter ice in Cook Inlet.

York said having the temporary system hasn’t affected productivity. The floating mechanism can handle the same vessels the mounted on can.

“From day one, it was fully functional,” he said. “The only reason why it’s temporary is because of the ice conditions.”

Pacific Pile and Marine operates the Salvation. Division Manager Jason Davis said this project, combined with another for the U.S. Army Corps of Engineers, allowed Pacific Pile and Marine to commission the large crane. The company is already working on future projects to help justify a permanent home in Alaska for it. After this operation, the Salvation will aid in constructing the new Carl E. Moses Harbor breakwater in Unalaska.

Davis said the intention is to keep the Salvation in Cook Inlet so that it may service the oil and gas industry, but it will depend on demand. Davis said the company will expand its market search to Puget Sound if the need arises because there’s been interest in that region. Still, he hopes to keep it here as an asset to the oil and gas industry.

“We really value this Alaskan market,” he said.

Davis said Pacific Pile and Marine has a lease purchase agreement for the Salvation.

The diving support and salvage expertise comes from Global Diving & Salvage Inc., which has worked with Pacific Pile and Marine before. Part of the company’s job is to attach the underwater piece of massive metal to the crane.

Global Diving’s vice president of marine causality response, David DeVilbiss, said this project is a good example of a piece of equipment specially needed for one project but can be used for others.

“We’ve committed to keep marine construction working in Alaska,” Davis said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-5-2012/States-biggest-barge-crane-aids-Inlet-salvage-operation/#ixzz22EM9TNAg

$100 Oil Drives Western North Dakota Oil Boom

Northern Energy Science & Technology Fair

Hear from some of the best minds in energy technology and innovation:

• Joe Balash, Deputy Commissioner, Alaska Department of Natural Resources
• Gwen Holdmann, Director, Alaska Center for Energy and Power
• Meera Kohler, CEO, Alaska Village Electric Cooperative
• Mark Myers, Vice Chancellor for Research, University of Alaska Fairbanks

After lunch, take your time exploring the Science and Technology Fair—visit booths to view presentations and ask questions.

When: August 15, 2012
Time: 11:30 am - 3:00 p.m.
Where: Dena'ina Center
Cost: $45.00/lunch panel | $15.00/students or attend the fair.

Register at https://www.institutenorth.org/programs/arctic-advocacy-infrastructure/week-of-the-arctic/northern-energy-science-and-technology-fair/

This is a Week of the Arctic event; to learn more about other opportunities during this Week, visit http://institutenorth.org/woa

Sunday, July 29, 2012

Update on Alaska Natural Gas Pipeline Projects Set; Caucus Meeting in Anchorage July 30 to Hear from State, Feds and Industry

(Big Lake) - The Alaska Legislature's Joint In-State Gas Caucus is hosting a meeting of state, federal and industry officials next week to hear updates on efforts to monetize the state's natural gas and Point Thompson.

Officials from the Parnell administration, the Alaska Stand Alone Pipeline Project (ASAP), Exxon Senior Point Thompson Manager Lee Bruce, and Federal Coordinator for Alaska Natural Gas Transportation Projects Larry Persily will present to the caucus at the Anchorage Legislative Information Office next Monday, July 30 at 1:00 p.m.

The meeting will be streamed live online at http://akl.tv and via the Legislature's Teleconference Network by calling 1-855-463-5009. Interested Alaskans are encouraged to attend in person, at a regional LIO or online.

Who: In-State Gas Caucus members, Government officials, Industry officials
What: Update on Alaska Natural Gas Projects
When: Monday, July 30, 2012, 1:00 p.m. to 4:00 p.m.
Where: Anchorage Legislative Information Office - Room 220, 716 W 4th Avenue

For more information contact Rex Shattuck, Aide to Rep. Mark Neuman, at 907-376-2679, or Michael Pawlowski, Aide to Sen. Lesil McGuire, at 907-269-0252.

Conoco earns $551M; Second quarter earnings down on production, prices; Conoco gives tax data

Eric Lidji
For Petroleum News

ConocoPhillips earned $551 million in Alaska in the second quarter, down from $620 million earned in the first quarter on steadily declining production and lower oil prices, but a slight increase from adjusted earnings in Alaska during the same period last year.

“Our legacy asset in Alaska continues to operate well and provides strong earnings and production performance… The lower production was driven by natural gas field decline partially offset by improved drilling performance and lower unplanned downtime,” Chief Financial Officer Jeff Sheets said during a quarterly earnings call for analysts on July 25.

ConocoPhillips completed “a major turnaround at Kuparuk on schedule and on budget” during the second quarter and expects to lose between 40,000 to 50,000 barrels of oil equivalent per day during the third quarter as a result of planned turnaround activities.

In its first full quarter as an independent exploration and production company, ConocoPhillips is releasing detailed information from its business units — including information on revenue and taxation sure to add to the local debate on oil tax reform.

Looking ahead in Alaska, “we have opportunities to mitigate decline from incremental exploitation opportunities and we retain the option for some longer term projects such as [liquefied natural gas] exports of [Alaska North Slope] gas,” Sheets said. “However, future developments from Alaska are contingent upon some improved fiscal terms.”

But opponents of such changes drew a different conclusion for the earnings report.

“Under our current tax structure, ConocoPhillips is making huge profits from Alaska’s oil,” Sen. Bill Wielechowski, D-Anchorage, said in a statement. “While this is great news for ConocoPhillips and Alaskans, it calls into question the need for major tax rollbacks.”

ConocoPhillips earned $104 million in the Lower 48 and lost $94 million in Canada during the second quarter. Companywide, ConocoPhillips reported adjusted earnings of $1.5 billion, down from $1.8 billion quarter over quarter and $2.3 billion year over year.

The additional information also includes revenue figures for various business units.

ConocoPhillips brought in $856 million in Alaska before income taxes — a figure that does not include the impact of other taxes and royalties in the state — down from $983 million in the first quarter but up from $781 million in the second quarter of 2011.

The company earned $207 million before income taxes in the Lower 48 and Latin America and lost $134 million before income taxes in Canada during the second quarter.

Companywide, ConocoPhillips earned $4 billion before income taxes during the second quarter, down from $4.4 billion quarter over quarter and $4.5 billion year over year.

Production declining

The quarter saw continued production declines for ConocoPhillips in Alaska.

The largest producer of oil in the state had an output of 215,000 barrels of oil equivalent per day in Alaska in the second quarter, down nearly 9 percent quarter over quarter and nearly 8 percent year over year. Companywide, ConocoPhillips produced 1.54 million boe per day during the second quarter, down nearly 6 percent both quarter over quarter and year over year.

Although natural gas production dropped in the quarter, the decline in Alaska production came largely from oil. ConocoPhillips produced 190,000 barrels of oil per day in Alaska in the second quarter, down some 9 percent both quarter over quarter and year over year.

Even with those continuing declines, though, Alaska remains the most prolific oil-producing region in the ConocoPhillips portfolio. By comparison, the company produced 115,000 bpd in the Lower 48. However, Lower 48 oil production is up 30 percent year over year as the company expands in unconventional oil plays, particularly the Eagle Ford Shale of South Texas, the Williston Basin of North Dakota and Canadian oil sands.

Companywide, ConocoPhillips produced 608,000 bpd in the second quarter.

ConocoPhillips reported an average price of $112.38 per barrel for Alaska liquids during the second quarter, roughly even with prices quarter over quarter and year over year.

While oil production is declining in Alaska, natural gas liquids production is steadier.

ConocoPhillips produced 16,000 bpd of NGLs in Alaska in the second quarter, down from 18,000 bpd during the first quarter but even to the second quarter of 2011. By comparison, ConocoPhillips produced 83,000 bpd in the Lower 48 (up from 72,000 bpd year over year) and 154,000 bpd companywide (up from 146,000 bpd year over year).

But natural gas production dropped.

ConocoPhillips produced 56 million cubic feet per day of natural gas in Alaska in the second quarter, down 5 percent quarter over quarter and nearly 10 percent year over year.

By comparison, the company produced 1.4 billion cubic feet per day from its Lower 48 operations and 864 million cubic feet per day from its Canadian operations during the quarter. Companywide, ConocoPhillips produced 4.1 bcf per day in the second quarter.

ConocoPhillips reported an average price of $3.93 per thousand cubic feet for Alaska gas during the second quarter, down from $4.68 per mcf in the first quarter and $4.66 per mcf in the second quarter of 2011. Because of a supply glut from shale plays, though, those relatively low prices are still higher than the $2.10 per mcf average from the Lower 48.

Taxation tops a billion

As part of its expanded reporting, ConocoPhillips is providing quarterly and annual effective income tax rates for continuing operations across its various business units.

The Alaska unit reported an effective income tax rate of 35.7 percent in the second quarter, compared to an average rate of 37.1 percent for all of 2011. The Alaska rate is well below the ConocoPhillips companywide average of 57.1 percent across all its units in the second quarter, and lower than every other individual unit listed beside Canada (29.8 percent) and the combined Asia Pacific and Middle East unit (27.1 percent).

But when non-income taxes are included, the effective tax rate in Alaska jumps to 63.9 percent rate. ConocoPhillips did not include corresponding figures for other units.

In the second quarter, ConocoPhillips paid around $1.25 billion in taxes and royalties on its operations in Alaska, including $983 million paid to the state of Alaska in severance taxes, royalties, property taxes and state income tax, or around $11 million per day.

“The very high government take on the North Slope created by Alaska’s tax structure negatively impacts the investment climate. We believe a better balance between government and producer share would stimulate additional investment in legacy fields and increases in production and jobs,” Bob Heinrich, vice president of finance for ConocoPhillips Alaska said in a statement, pointing to higher spending outside the state.

Since ACES went into effect, tax payments in Alaska have been roughly double earnings in the state, according to the company. In the first half of 2012, ConocoPhillips earned some $1.2 billion in Alaska and paid some $2.8 billion in state and federal obligations.
The Alaska Legislature recently completed another session where the debate over oil taxes took center stage, but lawmakers failed to agree to his changed to the tax code.

For Wielechowski, though, the earnings prove Alaska “is one of the most profitable places in the world for the oil and gas industry.” He added: “This earnings report is another reason Alaskans should continue to fight for our fair share. It’s right here in black and white. Oil companies are making very strong profits in Alaska. We have jobs at an all-time high under ACES. And finally, we have many more companies doing business in the state of Alaska. ACES is truly a win-win situation for everyone involved.”

Capital spending up

ConocoPhillips spent $202 million on capital expenditures and investments in Alaska in the second quarter, up from $196 million in the second quarter of 2011, but considerably less than in the Lower 48 and Latin America ($1.3 billion) and Canada ($428 million).

ConocoPhillips reported $133 million in depreciation, depletion and amortization in Alaska in the second quarter, down from $135 million quarter over quarter and $151 million year over year. The company reported $1.6 billion in DD&A across all units.

Bromwich: Shell drilling should proceed if it meets regulations

—Alan Bailey

Michael Bromwich, the erstwhile director of the Bureau of Safety and Environmental Enforcement and now managing principal of the Bromwich Group, has weighed in on the controversy over Shell’s planned drilling in the Beaufort and Chukchi seas.

Bromwich, the man placed in charge of the U.S. Department of the Interior offshore oil and gas regulations in the aftermath of the Deepwater Horizon disaster, was responding to a question posed on July 23 in a blog on the National Journal website, asking whether the United States is ready to venture into oil drilling in “a new frontier of offshore oil and gas drilling in the Arctic Ocean.”

“If Shell is able to fully satisfy the remaining regulatory requirements, they should be allowed to move forward with a necessarily shortened drilling program this summer; if not, then they should not,” Bromwich wrote, reflecting on delays that have already impacted the start of Shell’s planned drilling program. “These should be decisions made by experienced regulators, not decisions driven by politics or influence.”

Drilling delay

Shell originally planned to start moving its drilling fleet into the Chukchi Sea in early July, but unusually large amounts of early summer sea ice in the Chukchi have caused a delay into early August. In addition, Shell has not yet obtained Coast Guard certification of its oil spill containment barge, an essential component of the company’s oil spill response assets. And Shell has had to ask the Environmental Protection Agency to approve modifications to the air quality permits for its drilling vessels.

“The wells that Shell proposes to start drilling in the Arctic’s Chukchi and Beaufort seas in the next few weeks are almost surely the most widely litigated, hotly debated and heavily scrutinized wells in the country’s history,” Bromwich wrote. “The extraordinary level of interest that has existed for some time has increased as the time for Shell to begin drilling has drawn closer, focusing most recently on the complications and difficulties Shell has experienced.”

Bromwich listed a series of issues that he views as heightening the interest in Shell’s plans: the massive investment of time and money by Shell in its Arctic program; the significance of Shell’s program as a first step for the oil and gas industry in the Arctic offshore; concerns about the fragility of the Arctic ecosystem; painful memories of the Deepwater Horizon disaster; concerns about the feasibility of responding to an oil spill in the Arctic; and concerns about the potential impact of an oil spill on Alaska Native communities.

“In short, Shell’s proposal brings into stark relief the difficult question of how to appropriately balance the need to continue developing our offshore energy resources, especially in a region with such vast resources, with the need to preserve and protect the environment in one of the most fragile and treasured ecosystems in the world,” Bromwich wrote.

Balancing interests

By law, the government has to balance the various interests of different stakeholders when regulating programs such as Shell’s Arctic venture.

“Even though the wells Shell proposes to drill in the Chukchi and Beaufort are in shallow water, have low pressure, and are relatively simple as a technical matter, they have received extensive regulatory scrutiny,” Bromwich said.

And the Department of the Interior has yet to approve the permits for any of Shell’s planned wells — the applications for those permits must satisfy the more stringent regulatory requirements that went into effect after the experience of Deepwater Horizon. Those requirements now include an oil containment system for dealing with a subsea well blowout and a mandate to station government inspectors at drilling operations. The Environmental Protection Agency and the U.S. Coast Guard also have responsibilities to ensure that Shell’s activities comply with other regulatory requirements, including air emission limits and the seaworthiness of Shell’s vessels.

Assessing risks

Deepwater Horizon demonstrated that offshore drilling is not without risk.

“But just as the risks should not be minimized, they also should not be exaggerated, as has been frequently been in the case in the debate over Arctic drilling,” Bromwich said. “The risks of an oil spill are extremely small, and never have so many precautions been taken to minimize the chances of a low probability, high consequence event in the world of offshore drilling.”

If Shell can satisfy the regulatory requirements, the company should be allowed to move forward.

“Ironically, the final approval lies in the hands of Mother Nature and whether the sea ice melts in time. That is a powerful reminder of the formidable challenges presented by the Arctic,” Bromwich said.


Linc refines portfolio; The Australian independent allows most of its Cook Inlet acreage to expire

Eric Lidji
For Petroleum News

Linc Energy (Alaska) Inc. has allowed almost all of its Cook Inlet acreage to expire.

The local subsidiary of an Australian independent allowed 26 State of Alaska leases to expire in early June, keeping one state lease currently proposed for unitization, its Alaska Mental Health Trust leases and exploration licenses and its Cook Inlet Region Inc. leases.

The leases are split into two blocks on either side of the Cook Inlet — a 10-lease block in the Trading Bay area and a 16-lease block along the Knik Arm north of Pt. MacKenzie.

“The majority of Linc Energy’s Cook Inlet oil and gas leases expired June 1, 2012 at the end of their primary term,” Linc spokeswoman Maria VanderKolk told Petroleum News.

Pioneer Oil originally acquired the leases in 2005 on a seven-year term, but eventually sold the leases to San Francisco-based independent GeoPetro Resources. Linc picked up the leases as part of a 123,000-acre Cook Inlet acquisition from GeoPetro in March 2010.

Originally, Linc planned to drill a well on each block.

While Linc drilled the LEA No. 1 well on the Pt. MacKenzie leases in late 2010, and plans to continue exploring the area, it never drilled a well on the Trading Bay leases.

Shell discovered gas near the Trading Bay leases while looking for oil in the 1960s, but didn’t pursue development because of the low value of Cook Inlet gas at that time.

Linc plans to continue exploring in the area north of Pt. MacKenzie. The company kept one Cook Inlet lease, ADL 390581. In May 2012, Linc applied to form the 1,950-acre Angel unit combining the state lease and a contiguous Alaska Mental Health Trust lease.

The proposed three-year unit agreement includes plans for 2-D and 3-D seismic, drilling and potential development of conventional natural gas resources in the area in the future.

Linc said it expects a decision about the unit by mid-August.

LEA No. 1 encountered natural gas, but Linc originally decided the field could not be developed economically. But after analyzing the region further, the company recently announced its interest in returning to investigate a feature of the Pittman Anticline.

In addition to its conventional gas program, Linc is currently exploring the potential for underground coal gasificiation development over an Alaska Mental Health Trust exploration license spread across three large sections of the Interior and the Cook Inlet.

Linc also plans to explore the North Slope Umiat oil field this coming winter.

Other Cook Inlet expirations

Because the Alaska Department of Natural Resources typically holds its Cook Inlet areawide lease sale in May, the month is also a time when many former leases expire.
The current batch of expired leases includes acreage at active and dormant prospects across the basin, including the southern Kenai Peninsula, prospects dotting the northern Kenai Peninsula, the North Alexander prospect and some scattered offshore leases.

Marathon Alaska Production LLC allowed five leases to expire on the east side of Cook Inlet. They include four leases scattered outside the boundaries of the Marathon-operated Sterling Unit near Soldotna. The leases are mostly non-contiguous plots interspersed among state and Alaska Mental Health Trust leases held by Apache Alaska Corp.

The fifth lease is further south, several miles inland from Clam Gulch.

Apache Alaska Corp. allowed three Cook Inlet leases to expire.

ADL 390567 is an offshore lease northeast of Tyonek, abutting the ConocoPhillips-operated Beluga River unit and the Buccaneer-operated Northwest Cook Inlet unit.

ADL 390572 is an onshore lease north of the Beluga River unit. The lease includes the Pretty Creek No. 1 well. Apache still holds other yet-to-expire leases in the region.

Southern Kenai expirations

The southern Kenai Peninsula saw much activity in late May.
Apache also allowed ADL 390604 to expire.

The onshore lease is just inland from Anchor Point in the southern Kenai Peninsula, between the onshore North Fork unit and the offshore Cosmopolitan prospect.

Apache is holding onto another lease in the region not set to expire until 2013.

After remaining in a holding pattern for decades, the southern Kenai Peninsula is undergoing a renaissance of interest. Armstrong recently brought North Fork online and plans to drill additional wells in the area. Buccaneer is working to close on its previous acquisition of the Pioneer Natural Resources-owned Cosmopolitan unit and has outlined plans to explore the onshore West Eagle prospect located further inland, to the east.

However, Armstrong Cook Inlet also allowed two leases in the southern Kenai Peninsula to expire at the end of May. ADL 390597 and ADL 390603 sit to the east and to the south, respectively, of the Armstrong-operated North Fork unit. Armstrong still holds additional state acreage outside the boundaries of the unit not set to expire until 2013.

Hilcorp Alaska LLC allowed four leases in the southern Kenai Peninsula to expire. The onshore leases — ADL 390598, ADL 390600, ADL 390601 and ADL 390602 — are all north of the North Fork unit and west of the Hilcorp-operated Nikolaevsk unit.

Hilcorp acquired the leases — as well as the leases and operatorship of Nikolaevsk — through its recent acquisition of Union Oil Co. of California’s leases in the Cook Inlet.

Hilcorp also allowed a fifth lease to expire. ADL 390568 is a small onshore lease north of Tyonek on the west side of Cook Inlet, near an existing Marathon 16-inch pipeline.

Because many of these expirations come from the portfolios of companies retaining a presence in the region, the southern Kenai Peninsula could be active in future lease sales.

North Alexander and others

Aurora Gas allowed three leases to expire in May.
ADL 390560 is in the area north of the Aurora-operated Nikolai Creek unit on the west side of the Cook Inlet. The other Aurora leases in the area don’t expire until 2013.

The remaining two expired leases are on the east side of the Cook Inlet. Aurora originally asked the Alaska Department of Natural Resources to unitized those leases — ADL 390364 and ADL 390365 — into the Cohoe unit. The DNR denied the request and is currently facing an appeal on that decision from Dan Donkel and Donkel Oil & Gas Inc.

Cornucopia Oil and Gas Co. LLC allowed three leases to expire.

ADL 390586 and ADL 391216 were originally part of the onshore North Alexander prospect, located on the west side of Cook Inlet near the mouth of the Susitna River.

ADL 391213 is offshore and adjacent to the Furie-operated Kitchen Lights unit.

All three leases originally all belonged to Escopeta Oil Co., but transferred to Cornucopia after Escopeta divided its leases among several independents over the second half 2011.

Escopeta first planned to explore the North Alexander prospect as early as 2002, believing the field could contain as much as 600 billion cubic feet of gas. Despite attracting numerous partners to the project over the years, beginning the permitting process and contemplating unitization, Escopeta never drilled at North Alexander.

Cook Inlet Energy LLC allowed three leases to expire in late May.

ADL 390585 and ADL 390578 were adjacent to the Cornucopia leases at the North Alexander prospect. The two Cook Inlet Energy leases include the Cities Services East Lewis River No. 1 well. Cook Inlet Energy holds other, yet-to-expire leases in the area.

Cook Inlet Energy also allowed a lease to the south — ADL 390571 — to expire. The onshore-offshore lease is on the coastline south of the Hilcorp-operated Ivan River unit.

DNR extended ADL 390579 — a fourth lease, also set to expire — because Cook Inlet Energy is drilling on the property. The lease is west of the Lewis Creek and Pretty Creek unit and includes the Texas International Petroleum Co. Pretty Creek State No. 1 well.

Miscellaneous transactions

Great Bear Petroleum Ventures I transferred a 25 percent working interest and 20.83 percent royalty interest in one North Slope lease — ADL 391706 — to Halliburton Energy Services Inc. The companies are exploring the potential of shale in the region.
Aquilonia Energy E&P Inc. transferred a 30 percent working interest and 22.92 percent royalty interest in one Cook Inlet lease — ADL 391104 — to Nordaq Energy Inc., giving Nordaq complete working interest ownership. The lease is in the Trading Bay area.

Finally, ExxonMobil Alaska Production Inc. transferred a 75 percent working interest and 65.625 percent royalty interest in three leases in the Granite Point unit to operator Hilcorp Alaska LLC. The leases are ADL 18761, ADL 374044 and ADL 374045.

Saturday, July 28, 2012

Alyeska Pump Station 1 incident - January 2011

Visiting the Trans Alaska Pipeline

After Colleagues Rushed Proclamations, Senator Wants Focus on Actual Facts and Consequences Before Passing Judgment on ACES

Anchorage – After reviewing the press releases and background documents, State Senator Cathy Giessel cautions taking fellow Senator Bill Wielechowski’s proclamations about ConocoPhillips’ latest Securities Exchange Commission filings with a heaping tablespoon of salt.

“Perhaps he should consider reading glasses,” Giessel, R-Anchorage, said. “The asterisk and small print on Alaska in the segment highlighted by his press release shows that the low-balled 35 percent number doesn’t factor in property taxes or severance tax, which pushes their effective tax rate under ACES closer to 64 percent. If you add in our royalty charge, you’re up around 70 percent. That’s a significant difference, and a big deal.”

“Careful attention to detail is important when scrutinizing a data-packed document like an SEC filing. The Senator needs to read the fine print carefully and not rush to judgment,” Giessel said. “This is of paramount importance to the health and financial well-being of our state and Alaskans deserve better than rash comments that are misleading.” During this year the company is on track to pay the State nearly twice what it will keep in profit from its Alaska business” she added.

The filing further shows that through the second quarter the company invested $2.9 billion in capital projects in Alaska, the Lower 48 and Latin America. Only $388 million of that in Alaska. “$2.5 billion in American spending NOT taking place in Alaska,” Giessel said. “The money’s going south, where companies see the most upside. Obviously, they don’t see that in Alaska under this tax regime.”

The filings also show that they’ve underspent their Alaska budget for last year. “That’s worrisome in and of itself,” Giessel said. “There’s a huge disparity between Senator Wielechowski’s reported ‘facts’ and the context and content. Despite what he would lead you to believe, these filings don’t offer ‘proof’ that ACES is working. What the filings show is that ConocoPhillips is focusing more and more outside of Alaska, and if that’s the Senator’s definition of “working” – sending money and assets away – then I for one will work even harder to make us more competitive.”

The Consolidated Income Statement filing can be viewed at http://www.aksenateminority.com/archives/1079#more-1079

Friday, July 27, 2012

Nip and tuck for Shell season

Tim Bradner
Alaska Journal of Commerce

It is now nip and tick for Shell’s 2012 summer Arctic exploration plans.

The company is already challenged by difficult sea ice conditions off northern Alaska, and the schedule could be pushed further by delays in getting final U.S. Coast Guard approvals on modifications to a spill response barge in Seattle.

Shell is officially sticking to its plan to be drilling in the first week of August but that may have to change. Once the barge clears inspections in Seattle it will take 12 to 18 days for it to move to the Arctic, Shell spokesman Curtis Smith said.

“This will be tight,” he said.

The “Arctic Challenger” spill response barge, which will contain Shell’s new special undersea containment system, is to be positioned between Shell’s planned drilling locations in the Chukchi Sea and the Beaufort seas, which are hundreds of miles apart.

Without the barge being on station in the Arctic the U.S. Interior Department will likely not issue final drilling permits to Shell.

“We are working very closely with the Coast Guard on this. We’re going to make sure this is done right, and we’re not going to take it to the Arctic until it is ready,” Smith said.

There is also a second wrinkle. The U.S. Environmental Protection Agency has yet to approve modifications to air quality permits for Shell’s two drilling vessels, which are now waiting in Dutch Harbor, a port in the Alaskan Aleutian Islands.

The modifications are minor, a matter of how the permit is worded in the case of the Kulluk, one of the vessels, but the changes must be approved by EPA before the permits are valid.

Smith said Shell is “on track” to get compliance orders on the modifications.

Environmental groups are seizing on the air permits as an opportunity to push for more delays, which could place Shell’s 2012 drilling in further jeopardy.

Lindsey Hajduk, an organizer who works on the Sierra Club’s Arctic program, said the EPA should allow the public to be heard through public hearings in the permit modifications.

Shell’s fleet, consisting of the drillship Noble Discoverer as well as the Kulluk and various support vessels, are all waiting in Dutch Harbor. Shell has spent about $4.5 billion on its Arctic program so far including over $2 billion spent acquiring leases in a 2008 federal Outer Continental Shelf lease sale in the Chukchi Sea.

The company’s Beaufort Sea leases were acquired earlier, in OCS sales in 2006 and 2007.

Shell has had to leap hurdles for years on its planned program. The company mobilized a two-drillship fleet in its first exploration initiative in 2007, planned for the Beaufort Sea, but was stopped by a court injunction after lawsuits were filed by environmental groups and the North Slope Borough, who sued on behalf of Inupiat Eskimo whalers.

Shell reached an accommodation with the borough and the whalers with an agreement to withdraw its ships from the area during the annual fall whale migration.

When the company proposed its plan again the Ninth Circuit Court of Appeals unanimously rejected the environmental lawsuits. This time the North Slope Borough did not join the lawsuit.

But then, in 2010, BP’s offshore well in the Gulf of Mexico blew out and caused the U.S. Interior Department to put a hold on all offshore exploration drilling in federally-owned waters including in Alaska.

Shell developed its plans again under new federal rules, and lawsuits were again rejected by the courts. Now the fleet is mobilized again but there are new hurdles, including the ice and delays on the spill barge.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-5-2012/Nip-and-tuck-for-Shell-season/#ixzz21tqvaGD9

PN Bakken: Bakken oil to feed Kenai refinery?

—Kay Cashman
Petroleum News

As completion of Tesoro’s rail terminal to receive Bakken crude at its Washington refinery draws near, there’s talk within the company of shipping the light, sweet oil to Tesoro’s Alaska refinery where the company pays substantially more for both similar oil from the Cook Inlet basin and lower grade oil from the North Slope. If Cook Inlet basin oil explorers are successful, contract negotiations for their new oil could be tricky if Tesoro, the region’s primary oil buyer, plays its Bakken card.

Alaska North Slope, or ANS, crude generally trades above Brent crude; Brent above West Texas Intermediate, or WTI; and WTI above the Bakken light, sweet crude despite the fact Bakken oil should trade at a premium because it is a better grade of oil than ANS crude, which has easy access to West Coast refinery markets. In addition to having other related transportation challenges, Bakken oil has almost no access to west or east coast refinery markets and restricted access to the Gulf coast.

Currently Tesoro’s Anacortes, Wash., refinery, which can process 120,000 barrels of oil per day, receives 1,000 to 2,000 bpd from the Bakken and 30,000 bpd from the North Slope.

Starting in September, and according to the most recent company information, Tesoro will start shipping 30,000 bpd of the lower cost, higher grade Bakken oil via its “pipeline on rails” to Anacortes, replacing the heavier and more expensive North Slope oil the refinery now receives via tanker.

However, Tesoro President and CEO Greg Goff reminded investors May 3 that the physical design of the Washington rail facility is “designed to take, it could physically take, a unit train every day which would be 60,000 barrels a day. We are currently permitted for less than that, but we are working through the process to hopefully increase the capability to maximize the use of the facility.”

The assumption is the additional oil will be used at Anacortes to replace higher-priced crude from foreign sources, but a Petroleum News contact at Tesoro headquarters says there is some discussion about taking the oil, via tanker, to the company’s Kenai refinery at Nikiski on Southcentral Alaska’s Kenai Peninsula, where it would replace North Slope crude currently being used at that facility. And where a local oil producer recently claimed that crude under its new contract with Tesoro is going to be sold at $14 per barrel more than in the past because the previous contract was tied to WTI, not the price of North Slope oil on the West Coast.

A little history

The Kenai refinery, 70 miles southwest of Anchorage, started operating in 1969. It was designed for lighter Cook Inlet oil, a commodity that has been in decline for several years, forcing Tesoro to use both imported foreign oil and the heavier North Slope crude.

For example, in 2011 the refinery’s crude throughput was 55,000 bpd, but only some 11,000 bpd of that came from the Cook Inlet basin. (The refinery has the capacity to process 72,000 bpd of crude, but some operations use other feedstocks.)

Tesoro buys all local oil production. March output of 10,072 bpd is a far cry from the 227,000 bpd that Cook Inlet produced at its peak in 1970.

Only three fields in the basin have production exceeding 1,000 bpd: Granite Point at 1,947; McArthur River at 3,957; and Middle Ground Shoal at 2,345.

Besides price, downsides of ANS oil

Tesoro said in July 2011 that Bakken crude oil at the Anacortes refinery yielded approximately 16 percent more clean product and less fuel oil than ANS crude, and that during the second quarter of 2011, the price difference between those products averaged approximately $28 per barrel.

Although the price differential decreased in the second quarter of this year, Goff confirmed May 3 that, “as a rule of thumb … Bakken barrels substituted for ANS … will improve the gas and diesel by approximately 16 percent. … We basically reduced the fuel oil production by 16 percent and produced gasoline and diesel.”

At the Kenai refinery about the same percentage of ANS crude can’t be processed because it is too heavy, so it is shipped south via tanker for handling elsewhere, an expense that would help cut the cost of shipping Bakken crude from the West Coast to Alaska.

Goff looking to lower feedstocks

Goff told investors that high-return capital projects such as Anacortes reduce the company’s feedstock costs and improve its yields, enhance the competitive position of Tesoro’s assets and drive significant earnings and cash flow growth.
He said Tesoro is “absolutely focused on capturing projects like the … Anacortes crude supply project; projects that help to dramatically improve our crude oil supply costs.”

A resurgence of exploration in the Cook Inlet basin by Hilcorp, Apache, Furie and Buccaneer reportedly has local Tesoro refinery officials hopeful that more local oil production is in the cards.

But contract negotiations could be trickier if Tesoro plays its Bakken card.

Endeavour jack-up rig leaves Singapore for Cook Inlet

Tim Bradner
Alaska Journal of Commerce

Buccaneer Energy Ltd. said its “Endeavour” jack-up rig will depart Singapore for Cook Inlet at the end of July and will arrive in time to begin drilling at the first of two locations for exploration wells planned by the company.

A transit time of 21 days is expected, Buccaneer spokesman Dean Gallegos said in a press release.

The rig will be able to operate until late fall in Cook Inlet, as long as winter ice conditions allow, and will then be moved to drill the Cosmopolitan oil prospect in an ice-free part of the Inlet farther south.

In a related development, sources in industry, speaking on background, said another jack-up rig now drilling in Cook Inlet is reported to be close to completing its first exploration well, to a planned depth of about 14,000 feet.

The well is being drilled by Furie Alaska Operating LLC, using Spartan Drilling Co.’s Blake 151 jack-up rig.

The Blake 151 arrived in Cook Inlet last fall and began drilling on the well, drilling to about 8,000 feet before winter ice conditions caused a suspension of operations. Furie, the operator, reported a gas discovery at approximately the 8,000-foot test, which it was unable to fully test.

The Blake 151 was stored for the winter at Port Graham, in south Cook Inlet.

Buccaneer’s work on refitting the Endeavour rig in Singapore took longer than originally planned because extra work was done to make the rig suitable for Arctic operations. This will allow the rig to be used as a standby rig for offshore drilling in the Chukchi and Beaufort seas, Buccaneer said.

The work, at the Keppel FELS Shipyard in Singapore, also took longer than expected. “In early 2012 there was a change in federal regulations that required an increase in lifeboat capability for jack-ups operating in U.S. waters. This required engineering and steel works to be completed that were not originally anticipated,” Buccaneer said in its press release.

Finally, the plan to use the rig this winter to drill at the Cosmopolitan prospect meant that rig work planned to be done this winter was moved forward and done this summer, Buccaneer said.

The Endeavour has also been given a five-year certification by the American Bureau of Shipping, which means that it can operate for five years without an interruption in schedule for inspections. The unit is capable of drilling in 300 feet of water.

The rig is owned by Kenai Offshore Ventures LLC, a joint-venture of Buccaneer and Singapore-based Ezion. The State of Alaska has an equity ownership in the rig through the state development corporation, the Alaska Industrial Development and Export Authority.

Buccaneer plans to drill two exploration wells in Cook Inlet with the jack-up rig, the “North West Cook Inlet” and the “Southern Cross” prospects.

The company acquired Cosmopolitan, an oil discovery, from Pioneer Natural Resources. Test drilling so far of Cosmopolitan has been with extended-reach wells drilled from shore, but the tests were technical problems of having to drill through coal seams.

Having the jack-up rig available to drill vertical wells will allow for a more thorough evaluation, Buccaneer has said previously.

The Cosmopolitan discovery was originally made by ARCO Alaska.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-5-2012/Endeavour-jack-up-rig-leaves-Singapore-for-Cook-Inlet/#ixzz21qmWaKxj

BLM plans cleanup of one NPR-A legacy well

Tim Bradner
Alaska Journal of Commerce

The U.S. Bureau of Land Management plans to plug and clean debris at one abandoned old exploration well drilled by the government in the National Petroleum Reserve-Alaska and may be able to include several other nearby abandoned wells in the project, Alaska BLM officials say.

“We are working on cost estimates for the project, at the Iko Bay No. 1 well, and also on a three-year plan we are putting together to work on other abandoned wells,” said Bud Cribley, Alaska Director for the BLM.

BLM is being criticized by Alaska U.S. Sen. Lisa Murkowski and Alaska state officials over a lax record in cleaning up old wells, many of which are leaking.

“This is an embarrassment to the federal government. It is a crime for which the government would fine a private company millions of dollars,” Murkowski said in a statement.

Murkowski spoke following a Senate Energy and Natural Resources Committee hearing on the legacy well problem. She is the ranking member on the committee.

Of 135 old exploration wells drilled in the NPR-A over several decades by the U.S. Navy and the U.S. Geological Survey, only 16 have been plugged in accordance with state regulations, Murkowski said.

Alaska Rep. Charisse Millet, R-Anchorage, testified at the Senate hearings. Millet sponsored a resolution passed by the Legislature this spring asking BLM to address the problem.

Cathy Foerster, chair of the Alaska Oil and Gas Conservation Commission, also testified at the Senate hearing, saying that the BLM wells are out of compliance with state law and very likely federal law.

The Iko Bay No. 1 well, BLM’s current priority, is leaking gas from a crack in the wellhead, BLM officials have acknowledged. Foerster said the well has been leaking for years.

“We call it the whistling well because of the sounds it makes,” she said.

BLM officials said they have been hampered by budget constraints. Costs per well for plugging and abandoning have ranged from $2 million to $4 million per well and BLM’s entire annual budget for managing all of NPR-A, which covers 23 million acres of northern Alaska, is about $10 million per year.

However, industry officials said the agency’s cleanup operations have been poorly organized and inefficient.

“Once mobilization is done and a rig and crew and transported it would make sense to close out several wells in an area. Instead they do one well, usually in response to some emergency. It is terribly expensive to do it that way,” said Richard Gerrard, a consulting geologist who manages NPR-A operations for FEX LLC, an independent that has explored in the reserve.

Officials with the North Slope Borough, the regional municipality, said they offered to pool resources with the BLM in a program to plug and abandon several old government wells on lands transferred to the borough. The BLM turned down the offer, according to Jason Bergerson, state and federal government affairs manager for the borough.

The Iko Bay well abandonment will involve setting plugs to meet state regulations set by the state conservation commission Foerster heads, and remove the wellhead. The operation will likely require a workover rig, BLM’s acting chief of communications, K.J. Mushovic, wrote in an email.

Once a rig is brought into the area, other nearby wells may also be closed out. The Iko Bay well is about 20 miles southeast of Barrow in the northern part of NPR-A.

The government explored in NPR-A extensively beginning after World War II but no commercial-scale discoveries were made. It was only in the 1980s that a decision was made to have oil and gas lease sales in the reserve and allow private companies to do exploration.

It is only in recent years that companies have made discoveries, however, and all of them are modest and are in the northeast part of the NPR-A.

The first commercial production from NPR-A will take place in three years when the CD-5 drill site and bridge across the Colville River are completed by ConocoPhillips and Anadarko Petroleum.

Once that infrastructure is complete, two other small discoveries further west in NPR-A are likely to be developed.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-5-2012/BLM-plans-cleanup-of-one-NPR-A-legacy-well/#ixzz21qjF05cu

Tuesday, July 24, 2012

"Market Alaska;" a solution worth revisiting

by Deborah Brollini

I have been sniffing around about what was going on during the 1990s where Alaska's oil production curve had reversed and flattened for several years under then Governor Tony Knowles (D), Speaker of the House Gail Phillips (R), and Senate President Drue Pearce’s (R) leadership. Governor Knowles and the legislature in partnership with the oil industry increased oil production, and reversed the decline curved in the mid-1990s during the days of $9.00 oil. There was no partisan bickering during this time because Governor Knowles had vision, and understood that Alaska was "living on borrowed time."

Since 2006, Alaska’s oil tax debate has been nothing but partisan politics. There is a lot of rhetoric and talking points spewed with no forward thinking offering long-term solutions, or vision. Governor Tony Knowles clearly understood that the state of Alaska was in dire straights, and it was up to him, and his administration to think outside the box, and to rally all parties to a united win. This is called leadership that this state has been lacking since the Knowles administration, and yes he is a democrat. But, first and foremost Governor Knowles is an Alaskan who has rooted his family and businesses in this state, and continues to champion a “can do spirit” because he believes that Alaska is full of such great opportunity if we would just get out of our own way.

I do wish Governor Sean Parnell, and the Alaska state legislature would muster up some courage to lead and think about future generations when making decisions. I think it is time to take a look at the Knowles administration's model that was “Market Alaska,” where the administration and the legislature reached out to the oil industry because there was a shared understanding that Alaska’s future, and the oil companies’ futures were linked. "Market Alaska" resulted in increased oil production, and increased capital investment on the North Slope, and in the end all parties won. We need to be rallying for prosperity for the next generation of Alaskans, and spending less time trying to undermine their futures, and fighting about who is right. Our children deserve better.

Managing Alaska by Baldrige

Aligning Alaska's business interests


April 7 Breakfast: Make Alaska Competitive Coalition - Part 2: Governor Tony Knowles from Resource Development Council on Vimeo.

Listen or download the speech by Governor Tony Knowles to the Resource Development Council regarding the success of "Market Alaska" on iTunes or Listen here.

Since 2007, Alaska has been exploring for oil outside existing fields which has resulted in additional jobs. However, with Alaska'a Clear and Equitable Share (ACES) oil tax policy, the increased oil exploration and increased jobs have not resulted in additional oil into the Trans Alaska Pipeline (TAPS), or increased tax revenue to the state.

"Market Alaska" resulted in increasing oil production because exploration and development occurred in existing fields despite $9.00 oil. The speech given by Governor Knowles was filled with optimism, and he speaks of a shared commitment by all parties to move Alaska's forward.

Sunday, July 22, 2012

Endeavour to embark; Buccaneer executes heavy lift contract to bring jack-up rig to Cook Inlet

Eric Lidji
For Petroleum News

Buccaneer Energy Ltd. is getting ready to bring its jack-up rig to Alaska.

Kenai Offshore Ventures LLC, a subsidiary of the Australian independent, recently completed a heavy lift contract to move the Endeavour rig to Alaska from Singapore.

Buccaneer expects the rig to depart in late July and arrive 21 days later in the Cook Inlet, where the company plans to use it at as many as three offshore prospects this year.

After completing summer work at Southern Cross and Northwest Cook Inlet, Buccaneer will move the rig south sometime in early November to drill at the Cosmopolitan project.

In partnership with the Alaska Industrial Development and Export Authority, Kenai Offshore Ventures bought the Transocean Adriatic XI jack-up rig last September for $68.5 million and renamed it Endeavour — Spirit of Independence. The rig has since been undergoing repairs and upgrades at the Keppel FELS Shipyard in Singapore.

While in Singapore, the rig underwent “substantially” more work than Buccaneer originally planned, according to the company. Those additional upgrades include increasing the lifeboat capacity to meet new U.S. regulations, improvements allowing Endeavour to be used as a standby rig for activities in the Beaufort and Chukchi seas, pushing up work planned for next winter to accommodate the Cosmopolitan drilling program, and work to extend its certification with the American Bureau of Shipping.

With the upgrades, Endeavour can operate in water depths up to 300 feet in both Cook Inlet and the Arctic Ocean. The rig includes two sets of blowout preventers, both 10,000 and 15,000 PSI. Additional upgrades allow the rig to carry heavier-than-usual loads and to perform drilling or repair operations in conjunction with existing platforms.

New capital infusion

Buccaneer also recently said it is raising another $13.5 million for its Alaska operations.

The company said July 18 that it had executed binding agreements for the issue of 292,682,927 shares in the company to raise a total of $12 million and a Share Purchase Plan to eligible shareholders capped at $1.5 million.

The capital will go toward onshore, offshore and exploration ventures in Alaska.

The placement will take place in two parts. The first, to raise some $5.8 million, will take place immediately. The second, to raise some $6.2 million, is subject to shareholder approval. Buccaneer expects to hold a general meeting sometime in late August.

Zenith Securities Pte Ltd and Augsburg Investments Ltd have each subscribed to 48,780,488 shares in the first tranche, each corresponding to a 4.3 percent interest in Buccaneer, according to the company. Zenith and Augsburg will jointly hold a non-executive seat on the Buccaneer board as part of a “long term strategic relationship.”

The remaining shares in the $12 million placement were “supported by existing institutional shareholders and a range of new international and domestic institutions and sophisticated investors and was heavily oversubscribed,” according to Buccaneer.

“The company is about to embark on a significant period of activity and growth in its Alaskan operations and to do this effectively will require the company forming solid business relationships not only within Alaska but also globally,” Buccaneer Director Dean Gallegos said. “The company’s ability to complete a large equity capital raising relative to its size is confirmation of the strong underlying strength of its Alaskan projects and business plan. We look forward in working with Zenith and Augsburg to maximize and monetize the value of the Company’s asset base for the benefit of all shareholders.”

Offshore and onshore work

Buccaneer plans to use the capital for a variety of projects.

Those include drilling another development well at the onshore Kenai Loop project, progressing its offshore exploration efforts, completing its acquisition of a 25 percent interest in the Cosmopolitan project, funding its 50 percent stake in its rig-operating subsidiary Kenai Offshore Ventures and paying for general day-to-day operations.

The initial effort will focus on “maximizing production delivery” at Kenai Loop, Gallegos said. Buccaneer brought the onshore gas field online in January and plans to drill an additional development well at the field this summer. “To optimize its capital expenditure program, offshore exploration will be phased to follow the development of its onshore Kenai Loop project,” Gallegos added. “To reduce operational expenditure while the company focuses on its Kenai Loop development, the company will seek to contract out the recently acquired Endeavour jack-up rig to third party operators.”

Under its unit agreements, Buccaneer must drill one well each at its Southern Cross and Northwest Cook Inlet units by Sept. 30, 2012, or lose the units. “We intend meeting our commitments before leasing out to third parties,” Gallegos told Petroleum News.

Although Kenai Offshore Venture and AIDEA based their business case for buying the rig on Buccaneer projects, they always intended to lease the rig out to third parties.

Southern Cross sits between the Granite Point and Trading Bay oil fields. Northwest Cook Inlet lies on the northwest side of ConocoPhillips’ North Cook Inlet gas field.

The infusion of capital also allows Buccaneer to close on Cosmopolitan.

Buccaneer and BlueCrest Energy II, LP, a privately held energy company out of Fort Worth, Texas, purchased two offshore leases at the prospect from Pioneer Natural Resources Alaska Inc. in February and initially anticipated closing as soon as March 30.

Through the deal, Buccaneer would acquire a 25 percent interest in the leases.

The Cosmopolitan leases are off Anchor Point, in the southern Kenai Peninsula.

Saturday, July 21, 2012

Political Insider with Charisse Millett Cathy Foerster

Representative Charisse Millett and Alaska Oil and Gas Conservation Commissioner Cathy Foerster relate their recent testimony in front of the Senate Energy Committee on the NPR Legacy Wells.

Thursday, July 19, 2012

Shell’s first drilling in Arctic now pushed into August

Tim Bradner,
Alaska Journal of Commerce

With its Arctic drill fleet now assembled in Dutch Harbor, Shell is waiting on unpredictable Mother Nature. Summer ice conditions along the northern Alaska coast are the worst in a 10-year period, Shell spokesman Curtis Smith said July 9.

The heavy ice has caused target dates for the company’s first drilling at two exploration prospects in the Chukchi and Beaufort Seas to be pushed into the first week of August, Smith said.

“This is the heaviest ice coverage we have seen in a decade,” he said.

In a related development, a coalition of environmental groups filed new lawsuits July 10 in federal court in Anchorage over the federal government’s approval of Shell’s oil spill cleanup plans.

The actions are not aimed at stopping Shell’s 2012 drilling, however, but are instead aimed at forcing the U.S. Bureau of Safety and Environmental Enforcement to enforce a more rigorous standard in approving spill plans for future drilling that would follow if Shell is successful this summer, said Michael LeVine, Pacific senior counsel for Oceana, which is one of 10 plaintiffs in the case.

LeVine said the federal Oil Pollution Act of 1990 sets high standards for offshore spill safeguards and that the BSEE did not meet them in approving Shell’s spill plan for the Chukchi and Beaufort seas.

As for Shell’s immediate problem, the ice, Smith said the company is making its own reconnaissance flights as well as relying on satellite remote sensing data. Shell is sharing its high-resolution images of the ice with federal agencies which monitor ice cover across the entire polar region.

There is a long-range trend of thinning and a reduction of the summer Arctic icecap but this year’s condition is created by currents pushing the remaining ice up against the northern Alaska coast, creating a barrier.

Smith said Shell’s observations show that some of the ice is thick, multi-year ice.

Shell had hoped to have its drillships and support vessels in the Chukchi and Beaufort seas in late July. The delay creates a particular issue in the Chukchi Sea because the U.S. Interior Department has ordered the company to cease drilling into any hydrocarbon-bearing zone by late September.

The company had originally hoped to drill three test wells in the Chukchi with its contracted drillship, the Noble Discoverer, but even before ice became a problem, the September restriction would allow the company to complete only two wells, Shell has said, although work could be done to prepare wells for completion in 2013.

The delay forced by ice could jeopardize Shell’s plans to complete even two wells in the Chukchi. Shell’s permits for the Beaufort Sea allow it to drill into October, so the company has more flexibility at that location.

The initial Chukchi Sea target is the Burger prospect about 70 miles offshore the northwest Alaska coast. The Beaufort Sea prospect is east of Prudhoe Bay and in an area about 20 miles offshore from the Point Thomson gas and condensate field, which is 60 miles east of Prudhoe.

Discoveries have been made previously at both locations, by Shell itself in the early 1990s in previous Chukchi Sea exploration, and in the Beaufort Sea by Unocal Corp. at a prospect near where Shell will drill.

Meanwhile, Shell’s drilling fleet has left a Seattle shipyard and is now mostly in Dutch Harbor.

“The Discoverer arrived at Dutch Harbor on (July 7) along with other support vessels. The Kulluk, which is being towed, is about five or six days out from Dutch Harbor,” Smith said.

Dutch Harbor, in the Aleutian Islands, is being used as a staging area before Shell’s fleet, which totals 22 vessels, moves on to the Arctic through the Bering Strait. Shell has spent about $4.5 billion in its Alaskan Arctic exploration program to date, the company has said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-3-2012/Shells-first-drilling-in-Arctic-now-pushed-into-August/#ixzz215QcK3b1

Wednesday, July 18, 2012

Cook Inlet Energy gets busy on west side of Inlet

Tim Bradner
Alaska Journal of Commerce

Cook Inlet Energy, operator of the small Redoubt Shoal and West MacArthur River fields on Cook Inlet’s west side, is completing assembly of a drilling rig on the Osprey offshore platform and will have the rig operating in the next few weeks, company CEO David Hall said.

Cook Inlet Energy is a subsidiary of Tennessee-based Miller Energy Resources.

The company also has a second onshore drilling rig now operational at the West MacArthur field, Hall said. It is Miller Rig 34 smaller than Miller Rig 35, which is now positioned on the platform. Cook Inlet Energy brought Rig 34 to Alaska in 2010 and has been working to weatherize it and adapt the rig to work in Alaskan conditions.

The rig is now operational, Hall said. It is most suited for drilling shallower gas wells, he said.

Rig 35, a heavier rig, was purchased by Cook Inlet Energy in Texas and then disassembled and shipped to Nikiski, on the Kenai Peninsula, in 2011. From there the rig components were shipped in increments to the Osprey platform.

Hall said there is now one well producing about 200 to 220 barrels per day on the Osprey of six wells that were drilled by Forest Oil, the original developer. Cook Inlet Energy intends to do workovers, or repairs and maintenance, of the older wells as well as “sidetracks,” or new well bores drilled off older wells. The plan is to restore production on all six wells.

There are also potential new oil and gas deposits that can be drilled from the Osprey with Rig 35 once the work on the older wells is finished.

“We see a variety of ‘grass roots’ targets. We intend to keep the rig very busy,” Hall said.

Hall said Cook Inlet Energy is also planning an 8-inch, 25-mile, new pipeline across the Inlet that would eliminate the need for tanker shipments from the west side to east side.

The proposed $53 million Trans-Foreland pipeline is being planned to carry 90,000 barrels per day. That far exceeds current production in the area, but Hall said the pipeline would lower current costs of transporting oil by shuttle tankers from the Inlet’s west side to the Tesoro Corp. refinery on the east side.

Those costs now run to $11 and $12 per barrel. Hall said the goal is to reduce the expense of getting oil to Tesoro to about $4 a barrel, which is the range of costs before the prior system was disrupted by the eruption of the nearby Mt. Redoubt volcano in 2009. The eruption resulted in the flooding and subsequent shutdown of the Drift River terminal.

Lower transport costs would allow Cook Inlet and other companies, such as Hilcorp, which now operates the nearby Trading Bay and Granite Point fields, to boost west Cook Inlet development. Engineering is now underway on the pipeline and Hall said construction could begin in 2014, with oil shipments beginning late that year.

Hilcorp, which purchased Chevron Corp.’s Cook Inlet producing properties early this year, said it supports Cook Inlet Energy’s plan.

“This is something we’re following. We’re not a partner in the project but we support the idea of a pipeline,” Hilcorp spokeswoman Lori Nelson said.

However, this does not change Hilcorp’s near-term plan to reopen the Drift River terminal in October, she said.

Hilcorp plans improvements to flood protection dikes around crude oil storage tanks at the terminal. That would allow four 270,000-barrel capacity storage tanks at the site to be used again.

The terminal was closed in 2009 when Mt. Redoubt erupted but limited loading of oil was later restarted via a direct connection of an offshore loading platform with the 20-inch pipeline that connects Drift River with the producing fields.

The terminal is connected with the west Cook Inlet oil fields by a 42-mile, 20-inch pipeline. When the terminal and storage tanks were closed the offshore loading facility was still operated. This allowed smaller intermittent shipments of crude to be made with oil stored at tanks at Granite Point.

Having the terminal and four larger storage tanks available at Drift River will allow more oil to be stored, reducing the number of tanker trips and allowing the vessels to be fully loaded, Nelson said. That will increase the efficiency of the operation.

Because of the limited capacity of tanks at Grante Point oil has to be shipped every 10 to 12 days, Nelson said. That means the small tankers charted by Tesoro can only be partly filled, which raises costs. Being able to store oil at Drift River would allow the tankers to be fully loaded and would also reduce the number of tanker trips across the Inlet, Nelson said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-3-2012/Cook-Inlet-Energy-gets-busy-on-west-side-of-Inlet/#ixzz211GeSFYc

Monday, July 16, 2012

Alaska needs "mission critical" leadership NOW

Deborah Brollini

Governor Sean Parnell has always been supportive of me, and all my outreach efforts to educate Alaskans about oil and gas, and the importance of oil to our state’s economy. He and his administration wanted to assist me more with Alaska Natural Resource Month. However, Alaska Natural Resource Month was not about the Governor, the oil industry, or those who support the oil industry. March was about ALASKANS, educators and our private sector coming together to celebrate our state’s natural resources and it was important that I do it with no money. I have worked my tail off to engage Alaskans, and I just wish the Governor, the legislature, and community leaders would help a gal out and lead.

My children need bold “mission critical” leadership now, because the state is already in the danger zone, and failure is not an option. At the end of August, Jim Posey, General Manager with Municipal Light and Power (MLP) will be deciding whether or not he will need to consider importing liquefied natural gas (LNG) in 2014, and the importing of LNG will be doubling or tripling our utility bills. In addition, oil production through the Trans Alaska Pipeline (TAPS) will be well below 500,0000 BPD which means there will be many more challenges for operating TAPS safely, and ALL Alaskans need to be saying a prayer for TAPS everyday.

My children do to not need leaders who are scared of their own shadows. The state of Alaska by doing nothing in the interim other than initiating another RFP is not the answer. How many PAID non-Alaskan oil and gas consultants does it take to unscrew the mess that is Alaska’s Clear and Equitable Share (ACES) oil tax policy? The question was not meant as joke.

I am tough on our state leaders because I believe they have it in them to lead. We have 710,000 sitting ducks waiting for someone to step up and guide us to the future, and move our state forward. What is going to take?
Parnell administration seeks to hire oil taxes consultant
Audio of this piece:

Tuesday, July 10, 2012

Eric Boling explains high gasoline prices (4/11/11)

Eric Boling, Foxnews anchor, and friend of Alaska Energy Dudes and Divas explains that no Alaskans are not being gouged by refineries, and why gas prices are high. Eric further explains why the lag in gas prices dropping with lower oil prices.

Let us blame everything on the Senate Bipartisan Working

The Alaska GOP would suggest that we blame all of our state’s woes on those republicans who organized with the Alaska Senate bipartisan working group. I recommend that we blame everything on this group of republicans, e.g., the drought and fires in the midwest, high gasoline prices, world hunger, Darfur... hell let us just pile it on. No sense and stopping there. Why not look at ourselves in the mirror and take responsibility for being complacent as citizens? Why not take responsibility for having our hand out in every pocket of this state? Why not take responsibility for having little regard for my children's future? Our state has been flying by the seat of our pants since statehood, and we have lost our way, and we the public want to sit around and point fingers on who is to blame. What are we twelve?

All the throwing of sand in the eyes of elected officials this election cycle is accomplishing what? Alaska has zero leadership, no vision, and no roadmap to the future, and we hold our breath for the next Hail Mary. Good grief. I’ve been asking for years, what is the plan? There is no plan, and we the public need to pull our heads out of the sand, and get busy developing one, because if your waiting around for the Governor or the legislature to put one together, you are going to be turning the lights off on your way out of Alaska.

The replacing of legislators is not going to solve the long-term problem, and hoping for the best as a citizen is not a strategy. We as citizens need to engage in the debate, and take the time to understand the issues and stop relying on sound bites and rhetoric to guide our decisions. It is time that Alaskans grow up, and take responsibility for our state’s future, and we need to grow up today.

Monday, July 9, 2012

ConocoPhillips to give well sites Susie, Nora natural makeovers

—Wesley Loy
Petroleum News

ConocoPhillips is planning to put its green thumb to work this summer on a pair of old drilling sites on Alaska’s North Slope.

The company is seeking state authorization to fertilize and seed the sites as part of a land rehabilitation effort.

Wildcat wells, one known as Susie and the other as Nora, were drilled on the sites in the late 1960s. Both were dry holes.

The sites are about 52 miles south and slightly west of Deadhorse, the support base for the North Slope oil fields.

ConocoPhillips has been working for some time to reclaim the sites and restore them to a natural condition.

The Susie site

The Susie site is about eight miles west of the Dalton Highway, the industrial road to the Slope.

Alaska Oil and Gas Conservation Commission records indicate Atlantic Richfield Co., now part of ConocoPhillips, spudded the Susie Unit No. 1 exploratory well on Feb. 27, 1966, drilling to a total depth of 13,517 feet. The well was abandoned the following year.

The original Susie site featured a gravel pad, a gravel airstrip, a reserve pit and a possible flare pit.

Reserve pits once were used on the North Slope for disposal of drilling muds and cuttings. Now different disposal methods are used, such as injecting waste below ground, and years of effort has gone into cleaning up old reserve pits.

The Susie reserve pit was on a list of inactive reserve pits ConocoPhillips and BP were obliged to close under the Charter for Development of the Alaskan North Slope. The 1999 charter included environmental and other commitments the companies made to the state in conjunction with the ARCO merger.

Certain “corrective actions” were completed at the Susie site during the winter of 2010-11, says a rehabilitation plan ConocoPhillips submitted to the Alaska Department of Natural Resources.

The actions included hauling debris off the site; pumping water out of the reserve pit and then filling it with gravel and topsoil; filling in the flare pit; and cutting off the wellhead at least three feet below tundra grade, in compliance with AOGCC regulations.

Fertilizing and seeding

The Susie site is now largely grown over with a variety of plant species, including willow shrubs, the rehab plan says. The airstrip is “hardly visible today due to vegetation growth.”

The berm around the reserve pit was breached sometime between 1989 and 2001, and as a result the pit was “hydrologically connected with the natural tundra ponds directly to the north and south of the pit,” the plan says.

Two 55-gallon drums were found underwater in the flare pit, it says.

“The goal of the rehabilitation at Susie is to return the site to its natural setting as much as is practical, while providing a substantial vegetated cover on the reserve pit cap and flare pit cap to promote stabilization, and prevent erosion and surface water ponding,” the rehab plan says.

Following the corrective actions in the winter of 2010-11, the site was allowed to stabilize for a season to prepare it for the next step.

This summer, workers plan to use a hand-crank spreader to apply fertilizer to the site, about 200 pounds per acre.

The site also will be seeded with arctic alkali grass, “an indigenous perennial that colonizes easily and rapidly,” the rehab plan says. Gravel substrate areas might be seeded with forbs, herbaceous plants that are not grasses.

The site will be monitored through 2021 with additional treatments applied as needed, the plan says.

The Nora site

ARCO spudded the Nora Federal No. 1 wildcat on March 31, 1969, AOGCC records show. The well was drilled to a total depth of 17,658 feet, but tested as a dry hole and was plugged and abandoned in 1970.

The site, about four miles east of Susie, had a gravel pad, two reserve pits and a gravel airstrip.

Nora also was on the charter list for reserve pit closure.

As with Susie, a number of corrective actions were completed at Nora during the winter of 2010-11, including removal of gravel and soil from part of the pad and the entire airstrip.

The Nora site likewise will be fertilized and seeded.

Fertilizer will be hauled to the drill sites by helicopter, the rehab report says.

DNR, in a June 22 public notice, said it intended to authorize the fertilizing and seeding work pending a public comment period that closed June 27.

This won’t be the first time for seeding at the Nora site. It happened before many years ago, according to an old DNR memo found in AOGCC’s files.

Nora was among wells that were on federal leases originally, with the land subsequently patented to the state.

The memo dated June 4, 1976, detailed a DNR official’s visit to the Nora site for an “abandonment inspection.”

The memo discussed cleanup and restoration activity at the site, and noted that federal officials had been particularly concerned about a spot “northeast of the old pit area where an overflow of fuel oil spilled out onto the tundra and had been burned off.”

The area was reseeded with good results, the memo said.

Sunday, July 8, 2012

An ‘oil museum;' Apache believes Cook Inlet has as much oil left as it has already produced

Eric Lidji
For Petroleum News

For Apache Corp., the Cook Inlet basin might be the Louvre of oil.

“When you go up there it’s kind of like going back into time. It’s like an oil museum, is kind of how I’d describe it,” John Bedingfield, vice president for exploration and new ventures for Apache said at the large Houston-based independent’s annual Investor Day on June 14. “It’s interesting, but things have just been frozen for 40-plus years.”

Apache believes there is as much oil still to be discovered in the Cook Inlet basin as has already been produced in the 55 years since the first discovery well in the region.

To justify that enthusiasm, Bedingfield offered a glimpse of the ambitious three-year 3-D seismic program Apache is conducting in the Cook Inlet. He showed investors a strip of data manipulated just enough to keep competitors from recognizing the location.

“I wish I had taken the scale bar off now,” Bedingfield added as a beguiling aside.

The seismic uncovered eight previously unidentified leads. Extrapolated across its entire leasehold that suggests as many as 650 potential leads, according to the company.

Based on those early results, Apache believes “only a handful of fields have been discovered out here,” Bedingfield said. The field size distribution of the basin “strongly” suggests another 1.3 billion to 1.4 billion barrels of oil yet to be discovered, he said.

Bedingfield didn’t say how much of that oil Apache believes is technically, not to mention economically, recoverable. A June 2011 U.S. Geological Survey assessment estimated 599 million barrels of undiscovered but technically recoverable oil remained in the basin, the mean figure of a possible range of 108 million to 1.359 billion barrels.

The reason operators have not found those fields yet is seismic, he said.

“Every single valid trap that’s been drilled in this basin has hydrocarbons. It does not mean it’s commercial, but every trap has got hydrocarbons,” Bedingfield said, meaning exploration will be “an exercise in trap definition and basically risking investment.”

That’s why the basin is “tailor made” for 3-D seismic.

Until now, much of the 3-D seismic shot in Cook Inlet has been “effectively development scale” and therefore “typically they would be, from a design perspective, insufficient to image some of the structural complexities that we see in the basin.”

In addition to a large volume of plays, Apache expects the seismic work to reveal “complex plays.” Noting the basin contains 100 million barrel fields covering only 800 acres, Bedingfield said the 3-D seismic should show “stacked plays” and “big columns.”

Development in 2013?

So far, Apache has collected about 130 square miles of 3-D seismic in Cook Inlet.

The campaign started small in November, just enough to “shake out the operational business and see where our problems were,” he said, and resumed at full steam in March.

Because daylight is one of the limiting factors for seismic collection, Bedingfield said Alaska presents a unique advantage during its epic summer days. Apache expects to be able to collect between 300 and 400 square miles this year, or a third of its program.

A collection of environmental groups recently challenged the seismic program in court, saying the National Marine Fisheries Service shouldn’t have issued an authorization to Apache for the accidental disturbance of marine mammals during offshore program.

Apache plans to drill its first well in the third quarter and possibly a second later in the year. Acknowledging the many “ifs” involved, Bedingfield said Apache could begin development plans for the region as soon as next year, depending on exploration results.

Earlier this year, Apache outlined plans to drill the Aspen well this summer on the west side of Cook Inlet, four miles west of Tyonek, followed by the Captain Boomer well this fall or winter on the east side of Cook Inlet, some four miles southwest of Moose Point.

Major exploration focus

Cook Inlet is currently the largest exploration play in the Apache portfolio.

At more than 1 million acres, it is nearly double the next largest play. At 1.3 billion barrels of prospective reserves, it is barely trailing a prospect in the Kenyan deepwater.

It is also the only traditional exploration play in the Apache portfolio. The other exploration plays in the Americas and New Zealand are resource plays, such as shale or other unconventional formations. The Kenya program is targeting a deepwater field.

Friday, July 6, 2012

BP again delays development of Liberty field

Tim Bradner
Alaska Journal of Commerce

The BP Liberty heavy drill rig is seen here on the North Slope in a 2010 file photo. Technical issues with the extended reach, horizontal drilling project have forced BP to reevaluate the cost estimates and development has been postponed indefinitely.

The BP Liberty heavy drill rig is seen here on the North Slope in a 2010 file photo. Technical issues with the extended reach, horizontal drilling project have forced BP to reevaluate the cost estimates and development has been postponed indefinitely.

BP has deferred development of the small Liberty field in the Beaufort Sea northeast of the Prudhoe Bay and Endicott fields, this time indefinitely. The company would give no timetable on when the project could be developed.

BP spokeswoman Dawn Patience said June 29 that technical problems with the company’s plan to produce the field with ultra-extended reach production wells drilled from shore have caused the company to revamp the project after an 18-month review of the development plan and a heavy drill rig was built to drill the wells.

“Our review showed that the project cost would be substantially higher than the $1.5 billion we had estimated, and that it would take several years longer to complete,” she said.

Liberty has estimated reserves of 100 million barrels and is five miles offshore in shallow water. If developed, BP believes it would produce about 40,000 barrels per day at peak, Patience said.

The current plan, now on hold, is to drill extended-reach wells to the reservoir from a satellite gravel production island that is part of the Endicott field, which is two miles offshore and connected to shore by a gravel causeway. The wells that were planned would be as long as eight miles in horizontal departure from the drill rig, and set world records, BP has said previously.

The specialized, special-purpose rig for the Liberty project has been constructed and is now on the North Slope at the Endicott field production island. BP owns the rig but it was built by Parker Drilling Co.

Patience said discussions are under way with several companies who were involved with the rig, but those are confidential.

BP and other companies had hoped that development of Liberty with wells drilled from shore would demonstrate that capability and possibly open other near-shore deposits to development using similar techniques.

Other options for developing Liberty will be discussed with federal and state regulatory agencies, Patience said. A decade ago BP developed a similar small offshore field west of Liberty, the Northstar field, with an artificial gravel island and a subsea pipeline to shore.

Northstar, which is six miles offshore at Prudhoe Bay, has been in production since 2001, but with Liberty BP had rejected the artificial gravel island approach because Northstar wound up costing more and taking longer to build than expected.

One reason for the delays at Northstar was the extraordinary scrutiny by regulatory agencies because it was the first true offshore production island in the Arctic.

Federal and state agencies, and the North Slope Borough, are very sensitive to any oil production installation built in the ocean because of worries of problems with ice and an oil spill. The Endicott field, built in 1986, is technically an offshore field but it is close to shore, about two miles out, and water depths are so shallow, two to five feet, that there is virtually no moving ice present in winter.

Northstar, however, was a first because its production island was built beyond the protective barrier islands along the northern Alaska coast, so that the island is fully exposed to winter icepack movement and summer storms. Another first was the construction of the first buried subsea oil pipeline, and although the distance was short – six miles – there were still concerns about gouging of the sea bottom by the “keels” of heavy packice that extend down in the water. In the last 10 years, the island and the pipeline have withstood those natural forces, however.

Liberty is almost the same distance offshore as Northstar but is in a more benign ice environment because of barrier islands further offshore which block the heavy polar icepack. There is mostly stable “shorefast” ice at Liberty’s location.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-2-2012/BP-again-delays-development-of-Liberty-field/#ixzz1zsyNN3jD

New fiscal year rings in with oil prices dipping

Tim Bradner
Alaska Journal of Commerce

Happy Fiscal New Year! For the state of Alaska, municipalities and school districts around the state, July 1 is the start of a new budget year.

It’s a time for reflection, too. Oil prices and state revenues are down. Budgets are rising, pushed by increasing population and rising health and fuel costs.

A modest $250 million surplus is projected for Fiscal 2013, the budget year that started July 1. If oil prices stay low, that surplus could vanish. There was a much more hefty surplus, $1.8 billion, in Fiscal Year 2012 that ended June 30.

The surplus deposit brings the state’s savings, outside the Permanent Fund, to about $15 billion, which means the state has a big cushion. Still, the underlying numbers are cause for concern.

From June 11 to June 28, North Slope oil traded at less than $100 per barrel, reaching a low of $92.44 on June 21. News of a eurozone financial deal sent oil to its fourth-largest gain ever on June 29. Benchmark crude and Alaska North Slope crude each jumped $7 per barrel, with ANS closing at $100.21. Fresh Iran tensions pushed ANS to a close of $130.16 on July 3.

The surge could be a sign of a short-term dip, but it could also be part of a longer-term trend.

That’s worrisome, because the price needed to cover expenses and balance the budget for Fiscal 2013 is $104.25 per barrel, state budget director Karen Rehfeld said. If prices stay down the state will have to dip into its cash reserves.

That’s happened before. In fact, the state ran technical deficits for many years, drawing funds from the Constitutional Budget Reserve, a savings account funded with litigation settlement money. When oil prices and revenues increased the Legislature paid back those draws.

What’s different now, however, is that the expected state revenue decline in Fiscal 2013 is due mainly to oil production declines, and not any expected decrease in prices.

In its revenue forecast the state estimated that oil prices would remain flat in the $110 per barrel range over both Fiscal 2012 and Fiscal 2013.

State revenues, however, are expected to drop, from $14.34 billion in Fiscal 2012 to $12.58 billion in Fiscal 2013. The drop in production, from an average of 580,000 barrels per day in Fiscal 2012 to an average 563,000 barrels per day in Fiscal 2013, accounts for much of the drop.

Oil production from the North Slope has been declining at rates averaging 6 percent per year.

Overall state spending is down about $500 million in FY 2013. However, when the budget surplus transfers to savings are accounted for, costs are actually up for agency operations as well as “formula” programs in the budget like school funding and Medicaid.

The big drivers in the state operating budget include increases in Medicaid, the state/federal health care program for low-income Alaskans that is 50 percent funded by the state.

Medicaid costs are growing because the costs of medical care are rising. The overall Medicaid budget is up $130 million this year to about $1.6 billion, Rehfeld said. The state’s share is about $676 million, she said.

State personnel costs are also rising steadily at about $50 million to $60 million per year, mainly because of agreed-in public employee labor contracts as well as employee medical costs under the state’s benefits programs.

One other built-in increase in the budget is a state appropriation to fund teachers’ and public employees’ pension funds. This is aimed at reducing a projected $10 billion deficit in the funds, between expected income from investments and retirees’ needs, for both the pensions and medical care.

The appropriation toward the pension liability is about $610 million in state funds this year, and the amount will grow under a schedule to retire the unfunded liability in 25 years. The state’s annual payments will exceed $1 billion per year in the near future.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/July-Issue-2-2012/New-fiscal-year-rings-in-with-oil-prices-dipping/#ixzz1zsuRVoob