Sunday, July 31, 2011

NANA buys Gulf offshore platform maintenance group

By Tim Bradner
Alaska Journal of Commerce

NANA Development Corp., the business subsidiary of NANA Regional Corp. of Kotzebue, signed an agreement to purchase a major Louisiana oil platform maintenance contractor, an acquisition that will increase the size of the corporation by about 10 percent.

NANA announced July 25 that it will purchase Grand Isle Shipyard, a long-established platform maintenance operator in the U.S. Gulf of Mexico that now services about 700 offshore platforms in the area.

Grand Isle has about $200 million a year in revenues and employs 1,400. NANA had $1.59 billion in revenues in its last financial year and currently employs about 13,000 worldwide.

Helvi Sandvik, NANA Development's president, said the numbers underestimate the importance of this for the corporation.

"This strengthens the oil and gas support part of our business and allows us to move into the Lower 48 oil and gas service market. It offers long-term stability for us," Sandvik said in an interview. "The size (of the acquisition) isn't huge, but it's a very strategic acquisition for us."

In the July 25 announcement, NANA said Grand Isle Shipyard President Mark Pregeant and the company's management team would stay on under the new ownership.

"This agreement is good for Louisiana and good for Alaska because two stable, respected companies that value doing things the right way – safety and employees first – will grow and expand, creating jobs and economic development," Pregeant said.

NANA has three decades of experience in providing support to North Slope oil and gas producers, with services that include facility management, catering, housekeeping and security, as well as engineering and fuel service to contractors. NANA in the past has held part-ownership in drill rigs.

NANA currently owns a small working interest in the Endicott oilfield, a producing field in shallow water just offshore from the Prudhoe Bay field.

Sandvik said Grand Isle started in 1948 providing service mainly to the Louisiana fishing industry and then shifted to support of offshore platforms as the Gulf's petroleum industry developed.

The "shipyard" in the name is mainly a historical artifact from Grand Isle's history, she said. The company now focuses mainly on maintenance and repair of producing platforms, not drilling or construction.

Sandvik said the Grand Isle purchase will provide new opportunities for other NANA companies in related fields, like oil field and mining construction and engineering. It will also give NANA valuable experience in offshore support if oil discoveries are made off Alaska's coasts.

"The future of Alaska's petroleum industry is clearly offshore," Sandvik said.

But the main benefit of bringing Grand Lyle into the NANA family is diversification into a new region in an industry in which NANA has more than 30 years of experience, she said.

NANA, based in Kotzebue, has 12,500 Inupiat shareholders. The company employs 5,000 Alaskans among its 13,000 worldwide workforce, including 1,315 Alaska Native shareholders of the corporation.

NANA had a net income of $41.1 million in 2010. The corporation's biggest source of income comes through its ownership of the Red Dog Mine in the De Long Mountains about 90 miles north of Kotzebue. The mine, one of the world's largest producers of zinc and lead, paid $146.3 million in net proceeds to NANA in the corporation's 2010 financial year.

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NANA buys Gulf offshore platform maintenance group was republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com

Anadarko resumes exploration, drilling in North Slope foothills

By Tim Bradner
Alaska Journal of Commerce

Anadarko Petroleum Corp. will test its Chandler No. 1 gas discovery made in 2009 in the foothills region of the southern North Slope, the company said. The company will move equipment to the site for testing later this year when cold weather allows the construction of a snow road, Anadarko spokesman Mark Hanley said.

Anadarko drilled the Chandler well over two winter seasons in 2008 and 2009, but did not conduct a production test, Hanley said. A production test was conducted, however, on another gas exploration well Anadarko drilled at Gubik, about 10 miles north of the Chandler well. Results of that test have not been disclosed, Hanley said.

Gas was first discovered at Gubik in exploration in the 1960s but the deposit was considered too small to be commercial. Anadarko and its partners acquired leases on the prospect and drilled two tests to delineate the old discovery including the one where production testing was done.

Anadarko has been active in exploring in the foothills region for several years but took a two-year hiatus after PetroCanada, who was a partner with Anadarko in the foothills exploration, merged with Suncor Energy in 2009. Suncor remained in the venture along with BG Energy and Anadarko, and has now approved its share of expenses related to the planned testing.

Encana and BP were previous partners with Anadarko in the foothills, but have pulled out.

Geologists consider the foothills of the southern North Slope to be gas-prone, but there is also some oil potential.

"There is gas in this region and almost every well that is drilled finds gas. The question is whether enough can be found to make a gas field," Hanley said.

Land ownership in the region is split between the state of Alaska and Arctic Slope Regional Corp., a private development corporation owned by Inupiat people of the region.

Hanley said Anadarko will build a snow road about 75 miles to the Chandler site from the Dalton Highway, a year-around road that parallels the Trans-Alaska Pipeline System. Testing will be done without a drill rig, he said.

Discussions are also underway with Linc Energy, an Australian-based independent, about coordinating winter exploration logistics with that company's plan to do test drilling at Umiat, a small oil field within the National Petroleum Reserve-Alaska about 13 miles west of the Chandler discovery.

Linc Energy has said it will be moving a drill rig to Umiat later this year for its drilling but had initially planned to move the rig by air. Umiat has an existing all-weather airstrip.

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Anadarko resumes exploration, drilling in North Slope foothills republished with the permission of the Alaska Chamber of Commerce

Friday, July 29, 2011

State, JPO favor bridge; Engineering analysis says bridge to CD-5, rejected by Corps, safest way to go

Kristen Nelson, Petroleum News

Behind-the-scenes activity appears to be high on ConocoPhillips Alaska’s application to develop the CD-5 drill site across the Nigliq Channel from Alpine on Alaska’s North Slope.

That development has been stalled by federal permitting difficulties.

State and federal agencies recently told the U.S. Army Corps of Engineers that it was wrong in its determination that burying a pipeline under the Nigliq Channel of the Colville River was the least environmentally damaging practicable alternative.

In April the Corps’ Alaska District requested supplemental comments on the permit application to develop CD-5. ConocoPhillips proposed a bridge over the Nigliq; the Corps disagreed, favoring a buried line.

Alaska Gov. Sean Parnell weighed in, providing an engineering analysis by Louis Kozisek, P.E., of the State Pipeline Coordinator’s Office, favoring an aboveground vs. a buried pipeline crossing for the Nigliq Channel.

Federal agencies which are part of the federal-state Joint Pipeline Office — the Bureau of Land Management’s Office of Pipeline Monitoring and the U.S. Department of Transportations’ Pipeline and Hazardous Materials Safety Administration — said they had reviewed the Kozisek analysis and were in agreement with an aboveground crossing of the Nigliq Channel.

And Deputy Secretary of the Interior David Hayes said Interior strongly favors an aboveground crossing of the channel.

2010 decision
In February 2010 the Corps’ Alaska District ruled that ConocoPhillips’s plan for development of its CD-5 satellite — a bridge over the Nigliq Channel carrying both a crude oil line and a road — was not the least environmentally damaging practicable alternative.

The Corps said the least environmentally damaging practicable alternative was a crude oil line buried under the Nigliq Channel using horizontal directional drilling, no road between the CD-5 development and Alpine, where the oil will be processed, and an airstrip to service the CD-5 development.

ConocoPhillips appealed, and upon review, some issues were remanded to the Alaska district engineer in December.

Those issues included an airstrip added by the Corps in its preferred alternative. The review officer said “it is not clear why the alternative airstrip location was not identified to CPAI, and CPAI should be given an opportunity to address the alternative.”

Also remanded was the Corps’ rejection of ConocoPhillips’ argument that horizontal directional drilling under the Nigliq Channel was not practical on the basis of cost. The review officer said the Alaska District needed to “sufficiently document its consideration of the cost information available at the time of its decision.”

The HDD design issue was also remanded. The review officer said it was ConocoPhillips’ burden to demonstrate that the HDD alternative was “not logistically practicable,” but said the Alaska District’s “determination whether the project is logistically practicable is insufficiently supported and must be better documented.”

HDD the issue
The comments from state and federal agencies, including the governor, primarily addressed the Corps’ selection of HDD over an aboveground pipeline crossing the Nigliq Channel on a bridge.

Parnell told the Corps that ConocoPhillips’ preferred alternative “has the strong support of the several landowners and stakeholders in the area, including the nearby village of Nuiqsut. This rare coalition of supporters includes local communities, Native villages, Alaska Native Claims Settlement Act corporations, affected subsistence users, and the State of Alaska,” the governor said.

CD-5 infrastructure would provide a gateway for satellite developments within 25 miles of existing facilities at Alpine, he said, and create jobs, some of which could be filled by residents of Nuiqsut, which has a 33 percent adult unemployment rate. Parnell noted that the Corps’ regulations state that “the local and national economic benefits of a proposed project are important factors when considering permit approval.”

The governor said several state agencies conducted reviews of the CD-5 proposal, including the Alaska Department of Fish and Game, which approved ConocoPhillips’ bridge plan, and the Alaska Department of Natural Resources.

He said that in contrast to the ConocoPhillips’ proposal, “the HDD alternative selected by the Army Corps in its initial permit decision has generated considerable concern within State agencies.”

The governor urged the Corps “to give serious consideration and deference to the State’s position that a road and bridge crossing across the Nigliq Channel is preferable to HDD.”

Engineering analysis
In a 14-page report Kozisek, the chief engineer at the State Pipeline Coordinator’s Office, compared the advantages of aboveground and HDD crossings of the Nigliq Channel and found that the aboveground crossing had an advantage — or was neutral — in all but one subject area.

Kozisek found that HDD had a weak advantage in the area of hydrology, including ice and scour.

However, the aboveground option had strong advantages in the majority: maintenance and repair; surveillance and monitoring; internal corrosion; reliability (certainty of design); and incident response and emergency access. It had a moderate advantage in external corrosion.

“This opinion considers the advantages and disadvantages of each mode from the point of view of environmental protection, using the perspective of a pipeline engineer,” Kozisek said in his conclusion.

“The decision is clear,” he said. “For the Nigliq crossing, the aboveground crossing offers the greatest overall benefits for environmental protection because it best accommodates the all-important need to mitigate spill risks at a waterway,” and thus provided the least environmentally damaging practical alternative.

BLM, PHMSA agree
BLM’s Office of Pipeline Monitoring and the U.S. DOT’s Pipeline and Hazardous Materials Safety Administration, in a May 3 joint letter said the agencies, both participants in the federal-state Joint Pipeline Office, “affirm our support for a permit alternative that provides road and bridge access to CD-5.”

They noted that the agencies “comprise the nexus of Federal experience and technical expertise in the regulation, monitoring and oversight for oil and gas pipelines operating in the Arctic Environments of Alaska” and said their support for the road and bridge alternative is based on more than 30 years of experience monitoring the trans-Alaska oil pipeline, “and in the case of PHMSA, more recent experience regulating pipeline safety related to corrosion concerns on the North Slope. Our agencies have had many opportunities to evaluate what works and does not work in Alaska pipeline construction and subsequent pipeline operations and maintenance,” they said.

The agencies said they had reviewed Kozisek’s engineering opinion and “in general agree” with his conclusions on why the aboveground alternative is preferable.

Interior in discussions
Deputy Secretary of the Interior Hayes told the Corps that, at the direction of Interior Secretary Ken Salazar he has been communicating with ConocoPhillips Alaska, with representatives of “Native Alaskans with a direct interest in this project” and with several of the agencies involved, including BLM, the U.S. Fish and Wildlife Service and the U.S. Environmental Protection Agency.

“Based on these discussions, it is our view that this matter can and we hope will be resolved so that the project can go forward without further delay,” Hayes said.

He said the primary issue in the remand proceeding before the Corps is “whether the full record, including additional evidence being presented to the Corps following its initial decision, supports a finding that the underground pipeline alternative in the CD-5 matter is the ‘least environmentally damaging practicable alternative.’”

The record of decision that Interior prepared earlier for Alpine development concluded that a bridge would be the environmentally preferred alternative, Hayes said.

Some parties, including Fish and Wildlife and EPA, “raised concerns about potential negative environmental consequences that could be associated with a proposed bridge,” and based in large part on those concerns, the Corps declined Interior’s recommendation and found that HDD, using an underground pipeline, would be less environmentally damaging, and would be practicable.

Hayes said that in the proceedings following the Corps’ decision new attention was directed on the HDD alternative, “and there is important new evidence that should be considered,” in particular the “extensive analysis on the substantial risks associated with an underground pipeline such as that proposed, and the use of HDD in this area,” prepared by the State of Alaska.

Hayes said the new information on environmental risks associated with buried pipelines “is particularly compelling in light of the recent experience with the Trans Alaska Pipeline System, in which a buried portion of the pipeline developed an undetected leak.”

“An undetected leak in a pipeline underlying the extremely sensitive Colville River could lead to environmentally catastrophic results,” Hayes said. And, based on Interior’s experience with last summer’s “failure of previously assured oil and gas technology in the Gulf of Mexico,” the department feels strongly that an aboveground crossing, which can be “visually inspected and monitored with confidence, is an inherently less damaging alternative for this location than an underground pipeline.”

Hayes said that discussions with Fish and Wildlife and EPA, “we believe that environmental concerns raised about the bridge crossing can and should be addressed and mitigated. Toward that end we are moving forward with additional discussions with these parties to outline a mitigation approach to accompany the application that is before the Corps.”

Alaska District Corps of Engineers spokeswoman Pat Richardson told Petroleum News July 27 that there is no fixed timeline for a decision. She said the Alaska District is going through the administrative record and addressing points they were asked to examine in the remand. Part of that process involved additional information from ConocoPhillips and from agencies and Richardson said the Corps has requested and received that information, and is now evaluating the additional information to make a decision.

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Republished with the permission of the Petroleum News

More OCS permits; EPA issues draft Arctic air quality permits for Shell & ConocoPhillips

Alan Bailey, Petroleum News

Just a few weeks after the EPA’s release of draft air quality permits for Shell’s planned use of the drillship Noble Discoverer in Alaska’s Arctic offshore, on July 22 the agency issued corresponding draft permits for Shell’s Kulluk floating drilling platform in the Beaufort Sea, and for ConocoPhillips’ planned use of a jack-up rig in the Chukchi Sea. Shell proposes starting to use the Kulluk for exploration drilling in the Beaufort during the 2012 open water season, while ConocoPhillips plans to commence its Chukchi Sea exploration drilling program in 2013.

Public comments on the new permits are due by Sept. 6, with public hearings scheduled in Barrow and Anchorage in late August. EPA says that it will consider all comments received before making final permit decisions.

Major hurdle
Following a litany of appeals against multiyear attempts by Shell to obtain air permits for its planned Alaska drilling, the permits are proving a major hurdle along the route toward driving drill bits into some promising oil and gas prospects under Alaska’s northern outer continental shelf. In the most recent appeal the Environmental Appeals Board ordered EPA to make several changes to earlier versions of Shell’s permits, and the EAB mandated changes appear to have been carried forward into the new Kulluk and ConocoPhillips permits.

Facing much flak from supporters of Alaska natural resource development over continuing delays in the issuance of air permits sufficiently robust to withstand appeal, EPA’s issue of a flurry of draft permits perhaps reflects a sense of urgency over clearing the permitting logjam.

“I’ve repeatedly asked the Obama administration to put words into action when the president has stated he supports further oil and gas exploration in Alaska,” said Sen. Mark Begich on July 22. “I believe the EPA moving multiple permits forward for public comment in a short amount of time shows that support is real, and there is a recognition Alaska is key to more domestic oil and gas production.”

Sen. Lisa Murkowski expressed some caution.

“Permitting has been the greatest obstacle to our being able to discover and develop new oil prospects in Alaska, so any progress on that front is welcomed,” she said. “Far too often, however, we have seen the permitting process break down at the last moment over environmental challenges. It is my hope that the final approval of these permits will proceed in a fair, timely manner, and that the EPA’s work will stand up to the inevitable challenges from environmental activists.”

Shell has said that it plans drill to up to 10 wells, starting in the open water season of 2012, with up to two wells per year to be drilled in the Beaufort Sea and up to three wells per year in the Chukchi Sea. To meet air quality requirements, Shell has already modified the engine exhaust systems on the Noble Discoverer — the company has now dispatched the Kulluk to Seattle for air-quality-related power plant and generator upgrades.

Kulluk in the Beaufort
And, although Shell’s air quality permit for the Kulluk leaves considerable latitude over the choice of the Beaufort Sea tracts in which Shell could drill, the company’s most recently filed exploration plan indicates an intent to target the Sivulliq and Torpedo prospects, on the west side of Camden Bay, east of Prudhoe Bay. In the Chukchi Sea, the Noble Discoverer would target the Burger prospect, a 25-mile-diameter structure that is known to hold a major natural gas pool some 80 miles offshore the western end of Alaska’s North Slope.

A major point of contention in the appeals over Shell’s air quality permits has been the question of defining the periods within which a drillship becomes a stationary emissions source, requiring an air permit, rather than a regular vessel plying the ocean — the quantity of total emissions regulated as part of a drilling operation becomes larger as the stationary source time period lengthens. The permit for the Kulluk considers the drilling vessel to be a stationary source when the vessel is moored at a drill site by at least one anchor, a stationary source definition consistent with the recently published Noble Discoverer permit. The Kulluk has a total of 12 anchors arranged around the vessel’s perimeter to hold the vessel in position over the well being drilled, with those anchors being positioned in sequence by an anchor handling vessel before a drilling operation commences, and then being removed in sequence after the drilling has been completed, according to information supplied with the air permit.

Fleet emissions
Another bone of contention has been the predicted air emissions from the fleet of vessels such as icebreakers and anchor handlers supporting the drilling vessel. The Kulluk air permit considers these support vessels to be emissions sources when they are located within 25 miles of a drilling operation.

Shell has to notify EPA of the Kulluk’s planned drill sites by April 1 of the year in which drilling at those sites takes place, with drilling limited to a total of 120 calendar days per year, between July 1 and Nov. 30. Drilling activity cannot exceed 1,632 hours within a single drilling season, and there are specific annual limits on the emission of pollutants such as nitrogen oxides, carbon monoxide and sulfur dioxide. Carbon dioxide and other greenhouse gases are included in the regulated emissions inventory, and there are limits on the quantity of particulates allowed in engine exhaust.

Devil’s Paw

ConocoPhillips says that it plans to use a jack-up rig to drill in the Chukchi Sea Devil’s Paw prospect, 70 to 90 miles offshore, starting in 2013. Company spokeswoman Natalie Lowman told Petroleum News in a July 26 e-mail that the company is applying for its air permit well ahead of when the permit is needed to allow time for permit reviews.

The company has not yet contracted a specific rig and support vessels — for the purposes of its air quality permit the company has presented emissions data for equipment similar to what it expects to use. In addition to the drilling rig, ConocoPhillips anticipates using a support fleet that potentially includes up to two icebreakers, oil spill response vessels, workboats, supply vessels, a warehouse vessel, an anchor handling tug and a marine research vessel.

A jack-up rig is floated into position at a drill site but has legs that are lowered to the seafloor to lift the rig platform above the sea surface while drilling is in progress. ConocoPhillips’ air quality permit considers the rig to be a stationary emissions source whenever the body of the rig is lifted above the water and is out of contact with sea waves. And, as with the Shell permit, the emissions from support fleet vessels are regulated when within 25 miles of a drilling operation.

ConocoPhillips must notify EPA of planned drill sites by April 1 of the year in which the drilling at those sites is to take place, and drilling can only be done between July 1 and Nov. 30. In a similar manner to Shell’s permit for the Kulluk, there are specified limits for the emissions of various pollutants during drilling operations.

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Republished with the permission of the Petroleum News

Sunday, July 24, 2011

Homer Electric Association set to purchase Bernice Lake Power Plant

For immediate release

Nikiski area power plant compliments Independent Light; will save HEA more than $15 million.

Homer Electric Association (HEA) has agreed to terms with Chugach Electric Association on the purchase of the Bernice Lake Power Plant. The plant, which has a generation capacity of approximately 69.9 megawatts, is located in Nikiski, just north of the Tesoro refinery.

A condition of the purchase is approval by the Regulatory Commission of Alaska (RCA) of HEA’s request to amortize the purchase price over a period of several years. HEA feels this is necessary so that HEA’s current members do not have to shoulder the entire cost of the acquisition.

Recovering the total acquisition cost of the Bernice Lake Power Plant in member rates over time ensures that both current and future HEA members will be enjoying the benefits of the project at the same time they are paying for it. A petition requesting the rate treatment was filed with the RCA on July 21. The RCA will now consider the petition and eventually issue a ruling.
The agreement calls for the sale to become final on December 31, 2011 with the purchase price set at $11.8 million. HEA will receive revenue from Chugach for use of Bernice Lake Power Plant through 2013.

The purchase of the Bernice Lake Power Plant is being made through HEA’s generation and transmission subsidiary, Alaska Electric and Energy Cooperative (AEEC).

The addition of the Bernice Lake Power Plant to HEA’s power supply portfolio would be a key component of the cooperative’s overall power plan, Independent Light. Independent Light is designed to have HEA ready to take care of its own energy needs once its power purchase contract with Chugach Electric expires on December 31, 2013.

The power plan originally called for the installation of a steam turbine generator at Nikiski and two additional combustion turbines at the Soldotna power plant/substation site. The purchase of the Bernice Lake Power Plant will eliminate the need for a second turbine at Soldotna and save the cooperative a substantial amount of money, according to HEA General Manager Brad Janorschke.

“The net result of the purchase of the Bernice Lake Power Plant and the elimination of the second turbine at Soldotna will save the cooperative more than $15 million. This will have a positive impact on the finances of Independent Light and at the same time provide HEA with a reliable source of power to meet future reserve energy requirements,” said Janorschke.
(more)

Janorschke pointed out that the majority of HEA’s power needs under Independent Light will be met by the operation of the Nikiski plant (80 megawatts when completed in the fall of 2012) and HEA’s share of Bradley Lake hydroelectric power (11 megawatts). The Bernice Lake Power Plant and the single turbine now planned for Soldotna will be used to provide peaking and reserve power to ensure a high level of reliability on the HEA system.

Janorschke noted that the negotiations with Chugach Electric were positive and the transaction will benefit both utilities.
For additional information contact: Joe Gallagher Homer Electric Association 283-2324




Friday, July 22, 2011

A ‘best interest’ fight DNR: Ruling could cause oil and gas delays, appeals to Alaska Supreme Court

Wesley Loy for Petroleum News

The Alaska Department of Natural Resources is asking the state Supreme Court to overturn a lower court ruling the agency says has potential to delay oil and gas exploration.

The case concerns the extent to which DNR is obliged to prepare written findings on whether the leasing of state-owned land is in the state’s best interest.

In February, a state Superior Court judge held that DNR’s practice of issuing only one best interest finding prior to a lease sale or sales is insufficient. Rather, he ruled the agency has an “ongoing duty” under the Alaska Constitution to issue such findings for subsequent project phases.

The ruling was a victory for a group of Alaska Native and environmental plaintiffs who challenged DNR’s Nov. 9, 2009, finding in support of planned 2009-2018 lease sales involving some 2 million Beaufort Sea coastal acres stretching from Barrow to the Canadian border.

The group argued DNR is required to do best interest analyses not only at the leasing stage, but also for the exploration, development and transportation phases of oil and gas projects — activities they contend can jeopardize subsistence hunting and fishing.

Organizations challenging the DNR include REDOIL, or Resisting Environmental Destruction on Indigenous Lands; the Gwich’in Steering Committee; the Alaska Wilderness League; the Center for Biological Diversity; and the Northern Alaska Environmental Center.

The DNR petitioned the Supreme Court to review and reverse the judge’s ruling, and the high court has accepted the case.

An unnecessary burden
Lawyers for the state argue Peter Ashman, Superior Court judge pro tem, got it wrong.

They say DNR has no constitutional or statutory obligation to write extra best interest findings for post-lease phases of oil and gas projects.

Further, the state lawyers argue that the state already does review these phases to make sure they’re consistent with the public interest and don’t, for example, harm fish and wildlife habitat. Before any operations can proceed on leased state land, a company must win DNR approval of a plan of operations. The DNR also reviews and approves unit agreements and plans of exploration and development.

Requiring a written best interest finding for every phase of an oil and gas project would burden DNR, invite lawsuits and “may significantly hinder DNR’s ability to permit oil and gas development,” the department’s lawyers wrote in their Supreme Court petition.

Judge Ashman held that a single best interest finding prior to lease sales, when it’s impossible to assess the “cumulative effects” of development, violates Article VIII of the constitution, which deals with use of the state’s natural resources.

State lawyers, however, argue the judge found a phantom mandate in Article VIII.

“Nowhere in Article VIII does the term ‘best interest finding’ appear,” they wrote.

The requirement for such findings before “disposal” of state land — that is, leasing — actually is found in Alaska statutes, the state lawyers note. And one statute says state officials “need only prepare a single written finding.”

DNR will comply
But Ashman seemed to question the validity of that statute, concluding that the Legislature “is not empowered to enact a statute which would relieve DNR of its ongoing duty to consider best interests of the state at every phase of any project.”

Lawyers for the Native and environmental organizations argue post-lease industry activities such as water withdrawals, geophysical exploration and pipeline construction “effectuate the disposal of state land,” and in fact have far greater impacts than the “paper transaction” of issuing a lease.

DNR’s perspective is very different. It argues it shouldn’t be required to comply with “an amorphous constitutional duty when no such duty exists.”

Subjecting DNR to a constitutional duty that differs from what the Legislature has prescribed “has the potential to raise long-term uncertainty about the validity of DNR’s procedures and to delay exploration activities,” state lawyers wrote in their Supreme Court petition. “Given the importance of oil and gas production to state coffers, the uncertainty and resulting delay would be harmful to the public interest.”

Ashman remanded the case to the DNR, ordering the department to conform to his ruling.

On July 14, DNR said it would comply with the ruling “unless modified by the Alaska Supreme Court.”

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Republished with the permission of the Petroleum News




Sen. Murkowski Floor Speech: America is an Arctic Nation

Sunday, July 17, 2011

Pull together, not apart; Call out for oil sands operators to collaborate in keeping capital costs in check

Gary Park, Petroleum News

A ramping up of large-scale oil sands projects in Alberta is being accompanied by a campaign among industry leaders to promote collaboration among peers and rivals to curb capital costs and deal with a looming shortage of skilled labor and services.

The pace of new development was evident at a TD Securities conference in Calgary.

Devon Canada said it plans to go ahead with its wholly owned 140,000 barrels per day Pike project and is continuing with work on the second stage of its Jackfish joint venture with BP, which is scheduled to come onstream in three phases of 35,000 bpd; Total E&P Canada will break ground this winter on its 100,000 bpd Joslyn North mine, targeting first production in 2017; and Shell Canada said it will file with regulators in January for its two-stage, 80,000 bpd Carmon Creek project.

In addition, ConocoPhillips plans to invest C$1.5 billion this year on its oil sands assets, teaming up with Total to produce a combined 136,000 bpd from the Surmont project and partnership with Cenovus Energy to develop two phases of the Christina Lake thermal recovery project, which are due for completion in 2011 and 2013.

Challenges ahead

But Total’s Canadian President Jean Michel Gires was among those warning that the long-term, complex and capital intensive challenges to meet labor, technical and infrastructure requirements convince him that operators can no longer afford to remain isolated.
He told his audience of analysts and brokers that they should not underestimate the challenges.

“We know the world is watching us, so let us collaborate and prosper with a long-term goal in mind to produce the world-class resource sustainable (to meet) global energy demand,” Gires said.

He said that as projects move ahead they will face an “extremely tight labor market in North America,” especially recruiting qualified engineers and trades people, on top of which 30 percent of the current workforce is due to retire within the next decade.

Gires said that technologies to reduce water use and limit carbon emissions and toxic byproducts have advanced considerably over recent years and the information is being shared more openly.

“Addressing the issues together is much more efficient than attacking them individually,” he said.

Sharing and reducing risks

Nick Olds, senior vice president of ConocoPhillips Canada, said his company plans to spend C$100 million a year over the next five years on technology, targeting reduced gas consumption in its steam-assisted projects.
Rick George, chief executive officer of Suncor Energy, which is partnership with Total on the Joslyn and Fort Hills mines and an upgrader, said the joint venture is designed to share and reduce economic risks.

He urged companies to complete their engineering and procurement before mobilizing on a project, keep their workforces to a manageable size, award bite-sized contracts to proven contractors and avoid being driven by deadlines.

“I’ve got the scars on this one, trust me,” he said. “The focus has got to be on costs.”

John Brannan, chief operating officer of Cenovus Energy, said his company is running its own fabrication yard to restrain costs through quality and quantity control.

In addition, the use of new insulating technologies on tubing and innovative solvents to produce bitumen should trim C$10-C$15 off per-barrel costs over the next few years, he predicted.

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Republished with the permission of the Petroleum News

Our latest numbers - From January 2010

Friday, July 15, 2011

Looking more positive? Obama administration makes moves to speed up Arctic oil and gas development

Alan Bailey, Petroleum News

In May President Obama said that his administration would encourage domestic oil production by offering annual lease sales in the National Petroleum Reserve-Alaska. At that time, as reported in Petroleum News, he also announced an intention to extend the terms of some existing leases in the Alaska offshore.

Now, in the latest twist in the administration’s new moves over Arctic oil and gas, the president has issued an executive order establishing an interagency working group for the coordination of energy development and permitting onshore and offshore Arctic Alaska. Led by the U.S. Department of the Interior and involving multiple federal agencies, the group will facilitate efficient decision making over permits and environmental reviews, the order says. The group will ensure the sharing and integrity of scientific information, environmental information and traditional knowledge among agencies. The group will also ensure the coordination of issues such as oil spill prevention and contingency planning, while also coordinating the development of any necessary support infrastructure in Alaska, the order says.

Cautiously optimistic
Alaska Gov. Sean Parnell said he was cautiously optimistic about the latest presidential action.

“I appreciate the federal government recognizing and taking steps to address the increased costs and lengthy delays the federal permitting process has had on resource development and jobs in Alaska,” Parnell said. “The structure of the federal permitting process must be reformed.”

However, Parnell also expressed concern that the president has not included representation from the State of Alaska in the new working group.

On June 13 President Obama sent a letter to Gov. Parnell saying that the Obama administration “appreciates the importance of Alaska’s vast natural resources, including both the significant potential for energy production and the unique challenges posed by the development of the Arctic environment.”

The letter confirmed the administration’s intention of holding annual NPR-A lease sales and also re-iterated the intent “to extend the leases for certain areas off the coast of Alaska to give companies time to meet heightened safety and environmental standards for exploration and development.”

Taking action?
The U.S. Bureau of Land Management has acted on the president’s instructions for NPR-A lease sales by planning an NPR-A sale for later in 2011. However, so far the Bureau of Ocean Energy, Management, Regulation and Enforcement has not made any public statement regarding the possible extension of Arctic OCS leases.

“Our conversations with BOEMRE regarding lease extensions have not revealed what their intention is for Arctic leases,” Shell spokesman Curtis Smith told Petroleum News in a July 12 e-mail. “We continue to wait for their explanation on how lease extensions will be resolved in the future.”

Shell purchased leases in the Chukchi Sea in 2008 but has so far been unable to drill in any of those leases, in part because of appeals against the 2008 lease sale. The company has reacted positively to Obama’s announcement about the new interagency working group.

“The formal creation of a working group dedicated to pursuing domestic energy solutions in Alaska is welcome news and builds on recent, positive conversations we have had with this administration related to responsible offshore exploration in the Arctic,” Smith said. “We have long advocated for a regulatory process that is fair and accountable. … We’re hopeful this effort to coordinate various regulatory work streams will lead to more data sharing and a more efficient, while still robust, permitting process.”

AK delegation support
“The administration’s decision to designate specific people at each agency to focus on the development of our Arctic resources represents a positive step forward in improving the federal permitting process for companies interested in investing in Alaska,” said Sen. Lisa Murkowski in response to the president’s order. “I will be watching this effort closely to ensure that it’s successful at closing what has been an endless loop of approvals, appeals and delays — delays caused by special interest groups opposed to improving our energy security and the jobs it would create.”

“For the past two years, I’ve called on the administration to have federal agencies work together in Alaska,” said Sen. Mark Begich. “The president recognized the problem in his weekly address at the end of March. I give him full marks for honoring his commitment and look forward to the group untying the procedural knots that have stalled development at CD-5 in the National Petroleum Reserve-Alaska and improving permit processing in the OCS.”

“I am pleased that the administration is seemingly taking Alaska resource development more seriously,” said Rep. Don Young. “Time will tell if this working group helps streamline and expedite the process, as I hope it will, or if it adds another level of bureaucracy and red tape. In the meantime, I commend the president for taking a positive step in the right direction.”

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Republished with the permission of the Petroleum News.

Saturday, July 9, 2011

Alberta crude in TAPS? B.C. firm wants rail link from oil sands to Alaska to access Asian markets


Gary Park, Petroleum News

The long-touted idea of a “pipeline on rails” to carry oil sands bitumen from Alberta to a tanker port on North America’s West Coast has surfaced again, with a new twist, along with a mounting push to increase the use of rail within North America.

G Seven Generations, or G7G, a Vancouver-based company whose principals have strong ties to aboriginal communities, has rolled out plans for a 1,200-mile link from Fort McMurray, Alberta, to the trans-Alaska oil pipeline’s pump station near Fort Greeley in Alaska’s Interior. From there the crude would be delivered south to the pipeline’s terminus at the Valdez Marine Terminal and onward via tanker to Asian markets.

G7G director Matt Vickers told an International Indigenous Summit on Energy and Mining in Ontario June 29 that the plan would “simply mean replacing the declining supply of Alaska crude with a new supply of Alberta crude. …

“Studies have already demonstrated that a rail link to Alaska is a viable alternative to the oil pipelines currently being planned through British Columbia,” Vickers said, referring to Enbridge’s planned Northern Gateway project to Kitimat and Kinder Morgan’s options which include expansion of its Trans Mountain pipeline to the greater Vancouver area and construction of a new line to Kitimat.

“Diversifying markets for Canadian oil is an important challenge, but we need to achieve this goal in the most environmentally and socially responsible way possible,” he said.

The Alberta-Alaska option “promises significant economic benefits while avoiding many of the environmental risks associated with current pipeline proposals, Vickers said.

The G7G initiative offers the advantage of using the existing terminal at Valdez, which faces a declining oil supply from the North Slope, and does not face the same moratorium that exists in northern British Columbia waters along with attempts to ban crude tankers along the total length of the British Columbia coast.

Northern Gateway, in particular, has encountered a hostile reception from First Nations and environmental groups in British Columbia as it prepares for regulatory hearings next year before Canada’s National Energy Board.

G7G said its proposal eliminates three barriers to development of the oil sands — the cost, delays and financial risks involved in building pipelines out of Alberta and obstruction from lawmakers and environmentalists in Canada and the United States —while offering better netbacks to producers.

However, the risks of derailments, especially through sensitive mountain regions, could pose a challenge every bit as great as pipeline ruptures.

First phase C$12 billion

G7G has put a price tag of at least C$12 billion on the first phase of its project, compared with the C$5.5 billion estimate for the 525,000-barrels-per-day Northern Gateway plan, which includes a parallel system to import 193,000 bpd of condensate.
G7G said it has already received endorsement from leaders of First Nations in British Columbia and the Yukon and support from Alaska Native tribes along the rail route.

It now expects to complete a feasibility study, business plan and First Nations consultation in the “coming months.”

An Alberta-Alaska link is just the latest in a campaign by Canada’s two dominant railways — Canadian National, or CN, and Canadian Pacific, or CP — to draw the petroleum industry back to its roots, when the only way to get crude oil to market was by rail.

Earlier this year they made presentations to a Saskatchewan forum, making a pitch to ship crude from that province’s Bakken play, targeting business traditionally controlled by Enbridge pipelines.

Mike Foran, CP’s director of sales, said there is a “need for (shipping) alternatives during unforeseen times of pipeline apportionment.

“Crude on rail is here to stay,” he said, confident that several U.S. refineries will expand to take unit trains. “We can help built a network of markets — multiple origins, multiple destinations.”

CN representative Mark Cvar said one unit train would handle all of the daily Bakken production.

Although pipelines have lower costs, they require long-term shipping commitments, he said, adding that interest in rail is being spurred by a spike in oil prices, space allocations on pipelines and producers realizing that rail is a viable option.

Randy Meyer, CN’s manager of oil sands sales, has previously claimed that an international cost analysis showed moving pure bitumen by rail is cheaper than diluted bitumen for pipeline transportation, but he declined to provide per barrel costs, citing confidentiality agreements with various oil sands producers.

He said the costs associated with establishing a bitumen rail system would run to millions of dollars “not billions,” while shipper commitments would last for years, but not the 25 years sometimes required by pipeline companies.

Meyer also said rail transport is more scalable than pipelines and can be designed to meet current demand, which could be as little as 5,000 bpd for smaller producers — a significantly lower barrier to entry in return for the same market access as “more pipeline sized” producers.

He said CN, rather than requiring producers to commit to provide specific volumes at a particular time or face a penalty, “would meet your timing based on your business requirements.”

Rail offers time savings

Meyer also said bitumen should be shipped from Alberta to U.S. Gulf Coast refineries in eight to10 days compared with 40 to 50 days for a pipeline.
James Cairns, CN’s vice-president of petroleum and chemicals, told producers they “shouldn’t think of a rail project as an absolute alternative to pipe. Our view is that rail can be a companion to pipe, be a merging mechanism to pipeline infrastructure while permitting issues are worked out … or, in some cases, a replacement to pipe.”

Stephen Whitney, CP’s vice-president of marketing, said railway officials are working on altering the oil industry’s perception that pipelines are the only choice.

“I don’t think it is rail versus pipe, though it can be in some cases. The modes are complimentary, but the best supply chain model is going to prevail,” he said.

Whitney said rail’s main advantage is its ability to ramp up faster than the years it takes to approve and build pipelines.

Industry welcomes another option

The Canadian Association of Petroleum Producers said the amount of oil moving by rail is still very small, but the industry welcomes having the extra option available.
Diana McQueen, parliamentary assistant to Alberta Energy Minister Ron Lipert, said rail could have a bridging role to play while the industry expands pipeline infrastructure to access new markets.

“The pipeline-on-rail option may pose a trade-off between bitumen transportation costs by eliminating the need for diluents and higher transportation costs from using rail instead of a pipeline,” she said.

In late 2008, CN approached the Alberta government with a plan to move bitumen, estimating it could carry 2.6 million bpd if 20,000 railcars were added to its fleet.

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Republished with the permission of the Petroleum News.

BP Solar - The story so far

Saturday, July 2, 2011

A message from Sen. McGuire; Alaska Gasline Development Corporation to Release In-State Gas Pipeline Report.


From Sen. McGuire's July 2, 2011 email newsletter to constituents. Alaska Gasline Development Corporation to Release In-State Gas Pipeline Report. Report explores opportunities and answers questions about development of an in-state gasline

Senator Lesil McGuire congratulates the Alaska Gasline Development Corporation (AGDC) on its announcement that it will release the initial report on an in-state natural gas pipeline on July 5th. "Dan Fauske and all of the staff at the Alaska Gasline Development Corporation deserve our thanks for the immense amount of work they have done on this project," said Senator Lesil McGuire, R-Anchorage. "I encourage all Alaskans to read the report AGDC is publishing next week."

The report to the Legislature was required by House Bill 369, sponsored by House Speaker Mike Chenault in 2010. The final version of House Bill 369 was the product of two bills, House Bill 369 by Speaker Chenault and Senator McGuire's Senate Bill 287. Key elements of the compromise were the addition of explicit project milestones like AGDC releasing this report and transferring the project from the Office of the Governor to a sub-corporation of the Alaska Housing Finance Corporation. Another factor was the inclusion of language from SB 287 expressing the Legislature's intent that the in-state gasline be "compatible not competitive" with other large natural gas export projects currently being pursued by the state.

"Opening the North Slope and getting gas to Alaskans is just the beginning," said Senator McGuire. "Alaska's future is dependent on a vibrant North Slope basin that gives companies the opportunity to develop both conventional oil and natural gas and ultimately unconventional resources like heavy oil and methane hydrates. Getting there will certainly mean exporting large volumes of gas, but the point of the language I pushed to include in House Bill 369 is that we need to get gas to Alaskans first."

The Alaska Gasline Development Corporation has been performing preliminary permitting and engineering work on an in-state natural gas pipeline since it was established by the Alaska Legislature in 2010. "This project presents an incredible opportunity for Alaska and the foundation for our economic future," said Senator McGuire. "I am confident the report will reflect the Legislature's intent that the project provides benefits to all Alaskans and not just those in the Railbelt."

House Bill 369 allowed ADGC to consider a broad range of issues, including value added opportunities like gas-to-liquids. The effort to develop an in-state gas line brought members of both parties in the House and Senate together in an In-State Gas Caucus that looked at the pipeline and other issues related to natural gas development. "Our work surrounding this project has always been a collaborative effort, with Representative Mark Neuman and I taking the lead on exploring gas-to-liquids and other value added opportunities, as have others like Senators Charlie Huggins, Bill Wielechowski, Joe Thomas and Joe Paskvan," said Senator McGuire. "That's what is so exciting about this project- the prospect of bringing North Slope gas to Alaskans brings people together in a bipartisan fashion to unlock economic opportunities that will diversify our economy and benefit generations of Alaskans."

In addition to House Bill 369, the Legislature also passed provisions in Senate Bill 220 (the Omnibus Energy Bill) that explore ways natural gas can be used throughout Alaska. A provision sponsored by Senator Fred Dyson required an analysis of the use of compressed natural gas in the state vehicle fleet by the Department of Transportation. Another provision created an Emerging Energy Technology Fund which has already received applications for pilot projects delivering natural gas to Bethel that could be a model for moving gas from an in-state line to rural communities.

The In-State Gas Caucus is currently working with AGDC to schedule a presentation of the report tentatively scheduled for later this month in Anchorage.

The Alaska Gasline Development Corporation report will be available July 5th.

For further information, please contact Michael Pawlowski in Senator McGuire's Office at (907) 269-0250.
Thank you for giving me the opportunity to serve you in our district.

Warmly,

Senator Lesil McGuire
716 W. 4th Ave
Anchorage, AK 99501
(907) 269-0250

Alaska near bottom; State ranks below most North American jurisdictions for global investment


By Eric Lidji, for Petroleum News

Alaska is one of the least attractive places in North America for oil and gas investment, according to recent survey of international petroleum industry executives.

The State of Alaska ranked 83rd out of 136 jurisdictions while the federal Alaska Outer Continental Shelf ranked 78th, according to the Global Petroleum Survey by the Fraser Institute, a right-leaning Canadian think tank.

In addition to its low ranking this year, Alaska “slipped considerably” from its rankings last year, when survey respondents placed the State of Alaska at 68 and the Alaska OCS at 57 among 133 jurisdictions.

The annual survey gauges how higher-ups in the oil and gas sector view provinces, states and countries around the world by measuring 17 factors, including fiscal systems, regulatory certainty, political stability, local infrastructure and outstanding land claims.

The most attractive areas for investment are almost entirely in North America, Europe or Australia and New Zealand, according to the survey. Mississippi topped the list, followed in the top five by Ohio, Kansas, Oklahoma and Texas. The Dutch North Sea ranked highest of regimes outside North America.

The five least attractive jurisdictions are all in South America or the Middle East: Venezuela, Ecuador, Bolivia, Iran and Kazakhstan.

The rankings place Alaska in odd company.

In the United States, only California — home to some of the strictest environmental laws in the country — and the Pacific OCS — a region not included in the Bureau of Ocean Energy Management, Regulation, and Enforcement 2007-2012 five-year program ranked below Alaska.

For North America, Alaska joins Quebec and Northwest Territories at the bottom of the list.

Ranks poorly against shale

Alaska also fared poorly against its traditional and emerging competitors.
With expanding development of the Bakken Shale, North Dakota is poised to push Alaska out of the second place spot for oil production in the United States and that momentum helped North Dakota rank 10th this year, after ranking 24th in 2010.

The U.S. Gulf of Mexico, previously a darling among investors, took a major hit this year because of a federal drilling moratorium and new regulations enacted after the BP oil spill. But even though the Gulf fell farther down the rankings than any other regime in the world — from 11th place in 2010 to 60th this year — it still ranked higher than Alaska.

While Alberta ranked 51st this year, it jumped 11 spots from the 2010 ranking after the provincial government abandoned the New Royalty Framework proposed in late 2007.

Alberta began debating its new royalty structure around the same time Alaska officials debated and passed Alaska’s Clear and Equitable Share, or ACES, the current oil production tax. During those debates, many in Alaska pointed to Alberta as proof that the state could change its production tax and still remain competitive compared to other regimes around the world.

Now, as a way to increase investment, some Alaskans want to change ACES to remove a progressivity feature that increases the tax rate as the price of oil increases.

Perceptions, not investments

Because the survey only measures perception, not actual investment, it only does little to clarify how ACES is or is not harming the investment climate on the North Slope.
While the North Slope majors have said they have significant investment on hold until the fiscal climate improves in Alaska, critics continually note rising industry profits.

The major oil companies mostly released flat spending plans for the coming fiscal year in Alaska, but the State of Alaska has issued nearly $4 billion in tax credits since 2006.

And that debate also does not cover other factors that respondents pointed to in giving Alaska a low ranking, including environmental regulations and Native land claims.

The survey includes “horror stories” from particular regimes. For Alaska, those included the five years one company — unnamed, but undeniably Shell — has been waiting to get air permits from the U.S. Environmental Protection Agency for exploration drilling.