Thursday, December 31, 2015

Brollini 2015

Brollini 2015! May this new year bring many opportunities your way, to explore every joy of life and turning all your dreams into reality and all your efforts into great achievements. Happy New Year!

Thursday, December 24, 2015

Thoughtful Thursday Christmas Greeting

2015 Thoughtful Thursdays Alaska Christmas greeting. Thank you to all who have participated in my Thoughtful Thursday activities celebrating and appreciating Alaska's oil industry since 2012 ( Look for lots of Thursday fun and education in 2016.


Saturday, August 15, 2015

Russia raises tensions; Submits claim for 463,000 square miles of Arctic seabed, including North Pole

Guy Park
For Petroleum News

Eight years ago a Russian polar expedition descended through the waters of the Arctic Ocean in a Mir submarine and dropped a canister containing a Russian flag to the sea bed, 2.5 miles beneath the North Pole.

Per Stig Moller, a former foreign minister of Denmark, which has also staked a claim to the pole, told his Russian counterpart: “Just because you plant a flag there doesn’t mean you own it,” to which the Russian replied: “Just because the Americans planted a flag on the Moon. ...”

Some tended to view the incident as a stunt. Others were less nonchalant and that mood has since been reinforced by the saber-rattling Russia has since indulged in, culminating with its annexation of Crimea, the threat it has posed to the Ukraine and the Baltic states and the combat exercises it has conducted in the Arctic.

That military presence in the Arctic - which has involved 38,000 troops, 50 surface ships and submarines and 110 aircraft this summer - has included the restoration of a Soviet-era base on the New Siberian Islands, along with other military outposts in the region.

Revised submission

Any doubts about the seriousness of Russia’s activities in the region have now been put to rest, with Moscow’s unveiling earlier in August of a revised international submission that lays claim to a broad expanse of Arctic territory, including the North Pole.

The Russian foreign ministry said it is claiming control over 463,000 square miles of Arctic sea shelf extending about 350 nautical miles from the shore.

Russia, the United States, Canada, Denmark and Norway have all been trying to assert jurisdiction over parts of the Arctic, which the U.S. Geological Survey estimates has one-eighth of the world’s untapped oil and a quarter of its natural gas.

Rivalry for development of those resources - which some had once hoped would be a gentlemanly competition - has intensified as shrinking polar ice has opened up new opportunities for shipping and exploration and lowered drilling costs in the process.

Russia was first to submit its claim in 2002, but the United Nations sent that back for lack of evidence.

The resubmitted bid contains “ample scientific data collected in years of Arctic research” to support the claim, the Russian ministry said, indicating it now expects the U.N. Commission on the Limits of the Continental Shelf to start reviewing the bid this fall.

The U.N. Convention on the Law of the Sea allows all coastal nations to extend their jurisdiction beyond 200 nautical miles as long as they can prove the boundary claim is a natural extension.

The submission made by Denmark last December is seen as a test of whether Russia is willing to uphold its commitment and abide by the convention which says countries may control an area of seabed if they can show it is an extension of their continental shelf.

The key element of the counterclaims is the Lomonosov Ridge which bisects the Arctic, starting in Greenland.

Canadian claims

Canada is also developing its own plan to assert sovereignty over part of the ridge.

In late 2013, Prime Minister Stephen Harper ordered officials to rewrite Canada’s Arctic claim to include the North Pole and conduct more survey work this summer before submitting the document.

When Russia released its updated submission, its embassy in Ottawa said that Russia and Canada had previously agreed to allow the U.N. commission overseeing the issue to evaluate and rule on the quality of the hydrographic research “without prejudice to the rights of the other state.”

Rob Huebert, a political science professor and an Arctic expert at the University of Calgary, said it is now Harper’s responsibility to make clear whether his government is willing to negotiate with Russia where claims intersect.

“It is in Canada’s interest to have a safe and stable Arctic,” he told the Globe and Mail.

But he suggested Canada’s recent use of the Arctic Council as a forum to hammer Russia and President Vladimir Putin over tensions in the Ukraine might pose a challenge to serious negotiations.

However, Huebert suggested it is “inevitable” that talks will take place over the next five years, adding that the more reasonable Russia appears to be on the issue the more Canada risks being isolated, especially now that it has been chastised by the United States for making the Ukraine an issue at the Arctic Council.

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Sunday, August 2, 2015

BP, ExxonMobil seek more Prudhoe

Tim Bradner
Alaska Journal of Commerce

BP and fellow Prudhoe Bay lease owner ExxonMobil have filed an application with the Alaska Oil and Gas Conservation Commission seeking to increase their gas offtake to supply the Alaska LNG Project. The commission will have to weigh the benefits of gas sales versus foregone oil recovery produced through reinjecting gas.

BP and fellow Prudhoe Bay lease owner ExxonMobil have filed an application with the Alaska Oil and Gas Conservation Commission seeking to increase their gas offtake to supply the Alaska LNG Project. The commission will have to weigh the benefits of gas sales versus foregone oil recovery produced through reinjecting gas.

BP and ExxonMobil, two of the three major Prudhoe Bay field owners, have applied to the Alaska Oil and Gas Conservation Commission for an increase in the allowable volume of natural gas that can be produced and sold from the North Slope field.

The AOGCC, a quasi-judicial state regulatory commission with oversight of oil and gas production practices, has set a public hearing date of Aug. 27.

In 1977, the commission set a limit on Prudhoe Bay gas offtake of 2.7 billion cubic feet of gas per day, but BP and ExxonMobil, citing new reservoir studies, have now asked for permission to increase the rate to 4.1 billion cubic feet per day to supply a planned gas pipeline and LNG export project.

By law the AOGCC is required to seek maximum recovery of hydrocarbon fluids and must ensure that too rapid a withdrawal of gas from the Prudhoe reservoir will not result in an unreasonable loss of long-term oil recovery.

Prudhoe Bay holds about 24 trillion cubic feet of natural gas in addition to about 12 billion barrels of remaining oil, although not all of the oil can be produced. Prudhoe has already produced about 12.2 billion barrels since operations began in 1977.

If the Alaska LNG Project is built, the field will supply the bulk of the gas, at least in the near term, while additional gas will come from the Point Thomson gas field 60 miles east of Prudhoe Bay. A separate application to the AOGCC for gas offtake from the Point Thomson field is expected later.

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ConocoPhillips, which is also a major lease owner at Prudhoe Bay, was not included in the application made by to the AOGCC by the two other companies. ConocoPhillips spokeswoman Natalie Lowman said her company has been working with BP and ExxonMobil on the offtake issue.

“We are not aware they intended to make a unilateral filing,” she said in a statement.

Lowman said ConocoPhillips will have more to say on the matter at the AOGCC hearing. BP spokeswoman Dawn Patience said her company could not comment on the matter and that there would be more discussion in the hearing in late August.

About 8 billion cubic feet of gas is now produced along with oil at Prudhoe but the majority of that injected back underground to maintain pressure in the reservoir to aid oil production.

Natural gas liquids, or NGLs, produced with the gas are also mixed with crude oil and shipped to market in the Trans-Alaska Pipeline System, while other NGLs are used to make a miscible injectant fluid that is used in Enhanced Oil Recovery on the slope.

The AOGCC’s concern is that if some of the produced gas, in this case up to half, is shipped to markets via pipeline, there will be less gas injected and less support for pressure in the reservoir. That could result in loss of oil.

In their application to the commission, BP and ExxonMobil said the loss of oil recovery would be mitigated by steps including injection of carbon dioxide in an enhanced oil recovery project.

Prudhoe Bay gas contains about 12 percent CO2, which must be extracted from gas before it can be shipped by pipeline to an LNG plant planned to be built in southern Alaska. That process will make large quantities of CO2 available on the North Slope to aid oil recovery.

In the Aug. 27 hearing, the two producers will present evidence showing that the loss of oil recovery can be minimized.

“In accordance with good oil field engineering practices, at various stages of field development the Prudhoe Bay field owners have evaluated the potential effects of Prudhoe Bay major gas sales on oil production and hydrocarbon recovery. Gas production from Prudhoe Bay (to date) has been used for extraction of miscible injectant, manufacture of natural gas liquids, pressure maintenance and enhanced oil recovery,” wrote Dave Lachance, BP’s vice president for reservoir development, in the application.

About 75 percent of the 3.5 billion cubic feet/day of gas supply needed for the Alaska LNG Project, or about 2.7 billion cubic feet/day, is expected to come from Prudhoe Bay. About 25 percent of supply for Alaska LNG will from other sources, Lachance wrote in the application. This would be mainly from Point Thomson.

About 600 million cubic feet per day will be needed to fuel field operations on the North Slope and for local gas sales to contractors, raising the average daily offtake requirement, including the fuel needs, to 3.3 billion cubic feet per day.

However, a contingency must be built in to account for potential interruptions in gas supply from other fields. To include that contingency, BP and ExxonMobil have requested authorization for up to 4.1 billion cubic feet per day to cover shortfalls if they occur, according to BP’s application.

Overall, the Alaska LNG Project will result in the production of an additional 3.8 billion barrels of “oil equivalent,” from Prudhoe Bay, the application said. Oil equivalent is a measure of production that reflects crude oil and natural gas together with the gas covered to the equivalent of liquid barrels of the same energy content as oil. One barrel of oil is equal to about 6,000 cubic feet of natural gas.

The CO2 injection will play an important part in producing oil that remains in the reservoir, according to BP’s application,

In 1979, after it was discovered, Prudhoe Bay was estimated to be able to produce about 9.6 billion barrels of about 23 billion barrels of oil in place in the reservoir rock, but the oil recovery has improved substantially due to a variety of steps including use of the existing gas production for pressure maintenance and to make the miscible injectant for enhanced oil recovery, BP said in the application.

Sunday, July 26, 2015

Approved to start; BSEE issues permits to Shell for top hole sections of Chukchi Sea wells

Alaska Contract Staffing
Alan Bailey
Petroleum News

On July 22 the federal Bureau of Safety and Environmental Enforcement issued permits allowing Shell to drill the top hole sections of two wells in the Burger prospect in the Chukchi Sea. Shell now has all of the permits that it needs to start drilling.

However, BSEE is prohibiting Shell from drilling into hydrocarbon bearing zones until the company has its capping stack staged, available for deployment within 24 hours if needed. The capping stack, a device that would be placed onto a well head to seal the well should the well’s blowout preventer fail during a well loss-of-control incident, is positioned on the icebreaker M/V Fennica.

The Fennica has had to divert to Portland, Oregon, for a repair to a gash in its hull after hitting an uncharted underwater obstruction near Dutch Harbor. Shell has said that it anticipates the vessel being repaired and transitioned to the Chukchi Sea with the capping stack before drilling operations reach the depths where hydrocarbons may be found.

“Without question, activities conducted offshore Alaska must be held to the highest safety, environmental protection, and emergency response standards,” said BSEE Director Brian Salerno. “Without the required well control system in place, Shell will not be allowed to drill into oil-bearing zones. As Shell conducts exploratory activities, we will be monitoring their work around the clock to ensure the utmost safety and environmental stewardship.”

BSEE says that agency safety inspectors will be present on Shell’s drilling units Noble Discoverer and Polar Pioneer to provide continuous oversight of all approved activities.

No simultaneous drilling

The BSEE drilling permits prohibit simultaneous drilling operations at both of Shell’s planned drilling sites. This limitation arises from a stipulation within the U.S. Fish and Wildlife Service’s letter of authorization, allowing the minor, unintended disturbance of walruses and polar bears during Shell’s operations. The stipulation requires simultaneous exploration activities to be spaced at least 15 miles from each other - Shell’s well locations are less than 15 miles apart. If Shell opts to start drilling two wells the company must plug and abandon the top section of the first well before commencing the drilling of the second well, BSEE says.

Drilling vessels dispatched

Shell spokeswoman Megan Baldino has told Petroleum News that the two drilling vessels under contract for the Chukchi Sea drilling have departed Dutch Harbor in the Aleutian Islands for the Chukchi Sea. “The Noble Discoverer left last night around 6:30 and the Transocean Polar Pioneer followed at approximately 1:00 p.m. this afternoon,” Baldino said in a July 17 email.

The two drilling units, with assistance from support vessels, will connect to anchors that Shell has recently placed over the drilling prospect in the Chukchi Sea, Baldino said. The Burger prospect lies about 70 miles northwest of the Chukchi coastal village of Wainwright. The sea depth at Burger is about 140 feet according to BSEE.

Baldino told Petroleum News in a July 22 email that Shell plans to begin drilling at the Burger J prospect using the Polar Pioneer once the area is substantially clear of sea ice.

“The company will comply with all permits,” Baldino said.

BSEE inspection

Between July 7 and July 12, prior to the departure of the Noble Discoverer and the Polar Pioneer from Dutch Harbor, BSEE conducted inspections of the two drilling units, assessing the overall readiness of the units for the Chukchi Sea drilling and testing key safety devices, BSEE said July 16. The inspectors also verified oil lease stipulations, environmental mitigation measures, air quality equipment and permit requirements for the discharge of waste, BSEE said. BSEE Alaska Region Director Mark Fesmire and BSEE personnel re-inspected Shell’s capping stack on board the M/V Fennica, to verify that the capping stack had not been damaged during the incident in which the Fennica’s hull had been breached, BSEE said.

Reactions to the permitting

U.S. Sen. Lisa Murkowski, R-Alaska, expressed her satisfaction with the issue of the BSEE drilling permits.

“Today’s approval by the Department of Interior of the permits Shell needs to resume drilling in the Chukchi Sea is good news for Alaska and our country,” Murkowski said in a July 22 press release. “However, it is not the final regulatory hurdle Shell faces and it is important that the agencies continue to work in good faith and in a timely fashion to complete the remaining regulatory requirements.”

But environmental organizations continue to express their opposition to Shell’s plans.

“Neither Shell nor the oil industry as a whole has learned the lessons of 2010 or 2012,” said Andrew Sharpless, CEO of Oceana. “As its ongoing missteps show, Shell is not prepared to operate safely in the Arctic Ocean where bad weather, darkness and floating ice increase the risks of an accident, and there is no proven way to clean up spilled oil. The government’s approvals for Shell’s drilling fly in the face of common sense.”

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Federal judge rejects state effort to explore ANWR plain

Alaska Contract Staffing
Tim Bradner
Alaska Journal of Commerce

Alaska U.S. District Court Judge Sharon Gleason has dealt the State of Alaska another setback in efforts to conduct exploration of the Arctic National Wildlife Refuge’s coastal plain.

In a decision issued July 21, Gleason upheld Interior Secretary Sally Jewell’s interpretation that her authority to approve limited exploration of the 1.2-million-acre coastal plain expired in 1987.

State attorneys said they are still studying Gleason’s decision and have not yet decided on an appeal to the 9th Circuit Court.

“After we have had time to review it, we will evaluate our options,” said Corri Mills, spokeswoman for the Department of Law.

Under former Gov. Sean Parnell in 2013, the state had proposed a limited winter seismic program to gather more information on potential resources, arguing that Jewell’s authority had not expired and the 1980 Alaska National Interest Lands and Conservation Act, or ANILCA, required her to allow ongoing resource assessments and approve any third party proposal to do it, such as from the state.

After Interior agencies repeatedly rejected the state’s plan, the lawsuit was filed in federal court in 2014 and oral argument was held Jan. 20.

Exploration in the Arctic refuge has been a hotly-contested issue for years. The 18.9-million refuge was created in 1980 by Congress, as an expansion of an 8.9-million-acre wildlife range created in 1960. However, the coastal plain area was withheld from wilderness status by Congress and set aside for potential oil and gas exploration.

Under the 1980 law Congress must approve oil and gas development in the coastal plain but gave the Interior Secretary limited authority to conduct exploration to assess the resource potential.

Congress actually passed a bill approving ANWR exploration once, when both the U.S. House and Senate were under Republican leaderships, but then-President Bill Clinton vetoed the measure.

Former Alaska U.S. Sen. Ted Stevens tried a different tack, placing the question on a budget resolution, a procedure that is not subject to a Senate filibuster (which requires 60 votes to overcome) but the effort failed by one vote.

Bad luck and timing has played a part in foiling the state’s efforts in ANWR at times. Congress appeared close to approving exploration in 1988 and early 1989 but that ended when the tanker Exxon Valdez hit a reef in Prince William Sound in March, 1989, causing a major oil spill.

Meanwhile, ANILCA required Interior to do a resource assessment that included seismic exploration for the purpose of preparing a report to Congress by 1987. When the state submitted its proposal to continue exploration, Jewell ruled that her authority to allow it had expired.

State officials contended that the authority had not expired, and that under the language of the 1980 law the Secretary was actually required to approve an application from a third party.

Gleason disagreed, however, ruling that there was an ambiguity in the statutory language that required that deference be given to Interior’s interpretation that the authority had expired.

In her decision, Gleason wrote: “Congress authorized the Secretary to approve limited-duration exploratory activity on the coastal plain and ordered a report generated from these activities by 1987. Whether the statute authorizes or requires the Secretary to approve additional exploration after the submission of the 1987 report is ambiguous.

“The Secretary’s interpretation that her statutory authority and obligation to review and approve exploration plans ceased after 1987 report has been completed is based on a permissible and reasonable construction of the statute.”

The language in ANILCA is unambiguous as to the Secretary’s authority up until the deadline for the 1987 report but is silent, and therefore ambiguous, on any deadline after that, Gleason noted in the decision.

The state argued in the January trial that the lack of any explicit deadline for the authority meant that it continued in effect, while Interior argued that the lack of a deadline for continuing authority in the statute left 1987, when the report was required, as the only deadline.

The fact that Congress did not insert another, later date for any continuing authority after 1987 indicated that the body intended 1987 to be the final date, Interior officials argued in the trial.

Gleason noted that there could be alternative ways the language can be interpreted but that she was bound to defer to a reasonable construction of the statute by the agency.

“The Court need not find that the agency’s interpretation is the only permissible construction or that it is the Court’s preferred construction,” Gleason wrote, but noted that Interior had stuck with its interpretation since a legal opinion was written by the agency’s Solicitor in 2001. The consistency of the agency’s position was a factor in her decision, Gleason wrote.

The issue of exploring in the coastal plain has a long history. The area has high potential for significant oil and gas discoveries, federal agencies concluded in the 1987 review of resource potential.

Many geologists, government and industry, feel the coastal plain is the last remaining unexplored onshore region of Alaska with potential for very large oil discoveries, such as those made in the central North Slope region.

Inupiat leaders of the North Slope have largely favored ANWR exploration and development because it is onshore, where development can be done carefully, and not offshore, where there are threats to subsistence resources created by potential oil spills.

The Inupiats also have an economic stake in ANWR through a 91,000-acre inholding of surface and subsurface lands in the coastal plain where the surface lands are owned by Kaktovik Inupiat Corp. of Kaktovik and the mineral rights are held by Arctic Slope Regional Corp. of Barrow, the regional Alaska Native development corporation.

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Exploration permits up in air after court ruling

Alaska Contract Staffing
By Tim Bradner
Alaska Journal of Commerce

A May 29 Alaska Supreme Court decision will have wide-ranging impact on the state mining industry after a ruling that declared bore holes drilled and filled during exploration constitute a permanent disposal of state land requiring public notice and comment. State agencies are still interpreting the ruling to decide how to change the current system for issuing Miscellaneous Land Use Permits.

An exploration site at the Pebble prospect near Iliamna Lake is seen from the air in this 2010 photo. A May 29 Alaska Supreme Court decision will have wide-ranging impact on the state mining industry after a ruling that declared bore holes drilled and filled during exploration constitute a permanent disposal of state land requiring public notice and comment. State agencies are still interpreting the ruling to decide how to change the current system for issuing Miscellaneous Land Use Permits.

State attorneys and natural resources officials are wrestling with the implications of a May 29 state Supreme Court decision requiring expanded public notice and review procedures for certain Miscellaneous Land Use Permits issued by the Department of Natural Resources.

The decision, in a lawsuit brought by Nunamta Aulukestai, a Bristol Bay Tribal group, and three individuals, could have widespread effects in natural resource development if it opens opportunities for new litigation. At the least, it raises new uncertainties for projects, people familiar with the case say.

Nunamta Aulukestai was contesting Miscellaneous Land Use Permits, or MLUPs, and Temporary Water Use Permits, or TWUPs, issued for mining exploration at the large Pebble copper/gold project near Iliamna.

In addition to Numamta Aulukestai, four others were plaintiffs: Bristol Bay residents Ricky Delkittie Sr. and the late Violet Willson, state constitutional delegate Vic Fischer and former First Lady Bella Hammond.

The original case, filed in 2009, argued that the drilling of exploration drill holes, which are commonly done in mining exploration, was causing environmental damage through pollution, that the public hadn’t been given adequate public notice and that cumulative effects of the Pebble exploration program, which was extensive, weren’t considered.

The Superior Court initially sided with the state and with Pebble Partnership, the company doing the exploration, but the Supreme Court reversed the lower court decision on the public notice aspect.

The plaintiffs also challenged DNR’s issuing of TWUPs, but the Supreme Court found that those were indeed temporary and were functionally revocable, unlike the land permits.

The Supreme Court found the MLUPs to be functionally irrevocable based on the large investment made by Pebble in exploration that the state would be unlikely to halt, and that the well casings left behind after drilling constitute a permanent “disposal” of public land that requires notice and comment under the state Constitution.

“This decision means that all Alaskans, especially those whose rights and livelihoods are jeopardized by intensive exploration activities like those at Pebble, have the constitutional right to participate in those decisions affecting them,” said Trustees for Alaska Executive Director Vicki Clark in a formal statement after the decision. Trustees for Alaska represented the plaintiffs in the case. “The State has issued permits behind closed doors without even looking at the harm to public resources.”

The Supreme Court did not give the state resources agency much guidance in correcting the legal defects. The matter is now more or less left to the DNR to interpret what court said and devise new procedures, and then wait to be sued again to see if the interpretation is correct.

State attorneys and resource officials are not saying what steps they may take to correct the situation. In a statement, Cori Mills, spokeswoman for the state Department of Law, said, “DNR’s evaluation of the regulatory changes necessary to address the Nunamta decision is underway and will take a bit of time to establish and implement. Any rulemaking that is require to codify changes would be subject to public review and comment.”

The state Legislature may have to step in to clarify statutes, although those already distinguish permits that need public notice from those that are minor, and do not.

Mills said the case is now back to the Superior Court, which will soon issue a declaratory judgment to the DNR that recognizes the Supreme Court decision. A motion on attorneys’ fees has also been made, she said. The Supreme Court also reversed the Superior Court order to make the plaintiffs pay a portion of the state’s and Pebble’s legal fees.

The Supreme Court wrote in its decision it expected Nunamta to file a motion to collect legal fees from the state and Pebble after becoming the prevailing party.

The May 29 court decision didn’t invalidate the MLUPs at Pebble, which were all expired by then, but it has caused a big wrinkle over how certain MLUPs are to be issued in the future, and a variety of industries besides mining could be affected.

This has created a dilemma for state land managers.

“The court didn’t say we couldn’t issue the permits but dealt with what kind of public notice we should issue,” for certain permits, said Wyn Menefee, Chief of Operations for the state Division of Mining, Land and Water.

The division makes all MLUPs available to the public through the state’s on-line public notice system. The public can comment within 14 days but it must be in writing or e-mail, Menefee said, because the state’s on-line system is not set up for on-line comments.

The same notification goes to other state agencies, and the agencies often provide comments and sometime ask for more time to look at the permits, he said.

Essentially, the May 29 decision said that the on-line posting isn’t enough for certain types of land-use permits, those that can be considered “irrevocable,” or more permanent in nature, compared to “revocable” permits which are truly temporary and which the state DNR can rescind within the period of the permit, typically three to five years.

The state high court found that the specific exploration holes drilled at Pebble, some of which were drilled to 7,000 feet and involved placement of permanent steel casing, were irrevocable permits similar land easements issued by DNR and thus needed a broader public notice procedure.

While the decision doesn’t appear to be retroactive in affecting existing land permits there was also little guidance from the court as to how the agency can define the types of activities that can distinguish between irrevocable and revocable MLUPs going forward.

Most important, the court didn’t signal what type of public notice procedure would be acceptable other than it must be more than what is now done.

“We’re still evaluating the decision, but there wasn’t a lot of guidance,” Menefee said. “Almost everything we do is noticed, but is it enough?”

The department will certainly plan a more widespread public notice procedure once it sorts out how to distinguish between activities that are irrevocable (most likely major mining drilling programs of the sort done at Pebble) but whatever the department does will be challenged by environmental groups, said John Shively, chairman of Pebble Partnership and a former state Commissioner of Natural Resources.

“How can this be sorted out? It’s a guessing game. I suspect the environmental groups will keep bringing lawsuits,” Shively said. “Anything the NGOs (non-governmental organizations) can to do make life miserable for miners they will do,” he said.

Shively said the original Nunamta Aulukestai lawsuit “was aimed at shutting us down at Pebble. It didn’t work.”

“They (the plaintiffs) had theories that we were destroying the environment with our drilling, but the Superior Court said there was no evidence of that and the Supreme Court didn’t disagree,” he said.

Pebble has tried to do its exploration in as much a benign way as possible. Exploration there began in 1988 and as of 2010, when the Superior Court trial was held, 1,269 holes had been drilled, along with seismic surveys. When the mineral cores were extracted from the holes they were plugged with concrete and rigs and drill-pads were removed by helicopter.

The plaintiffs lost on that point but the decision has still opened up a Pandora’s Box of other issues for land developers.

What concerns people most, Shively said, is whether continued litigation on the public notice procedures will ultimately lead to a formal Best Interest Finding, or BIF, procedure for mining exploration, but also a lot of activities that require temporary state land permits.

Best Interest Findings, or BIFs, is a state equivalent to a federal Environmental Impact Statement that are done with significant actions on state lands, such as oil and gas lease sales, forest sales or other land actions, and even sales of state royalty oil to refining companies.

Like the federal EIS, the state BIF procedure has provisions for public appeals of agency decisions. They are expensive to do, and can set the stage for litigation, but state BIFs were adopted to formally document state agency decisions and the weighing of alternatives, similar to what an EIS does on the federal level.

Ironically, the procedure was adopted to minimize the disruption to the state oil and gas lease sales cause by environmental lawsuits by spelling out in detail the rationale for the state decisions and consideration of alternatives.

Since BIFs were adopted no state oil and gas lease sale has been held up by an environmental lawsuit.

Nunamta Aulukestai raised the Best Interest Finding issues in the Pebble lawsuit but while the Supreme Court discussed it in its decision the matter was left unsettled.

The state high court said the state Constitution does not require a best interest finding. However, the decision did connect the issue with a previous Supreme Court decision, known as REDOIL (brought by Resisting Environmental Destruction on Indigenous Lands), which dealt with cumulative effects of a state decision.

“They (the plaintiffs) were obviously playing into the REDOIL decision,” Shively said.

Under the REDOIL decision an agency is required to perform some form of “continuing assessment” of impacts from a permit authorizing future actions. This moves in the direction of a cumulative effects analysis by a state agency, long a goal of environmental groups.

“I’m sure there will be more lawsuits on all this,” Shively said.

Other attorneys who familiar with the case, and state land management procedures, felt the Supreme Court decision, in finding the Pebble TLUPs permanent, or irrevocable, was correct.

“I think the court was swayed by the length of time and controversy of the interminable Pebble exploration, which comprised $300 million of expense and explosives, portable rigs, structures, fuel storage and helicopters,” said Jim Barnett, a private attorney who is also a former deputy state resources commissioner.

The sheer scale and the duration of the Pebble exploration is what set it apart, Barnett said. The department should have conducted some form of expanded public notice, he said.

Barnett said he believes that complying with the Supreme Court decision will ultimately require DNR to conduct a review of cumulative impacts, as required by the REDOIL decision, on mining exploration.

Menefee said many activities on state lands that are non-intrusive and don’t require permits, such as small-scale mining or activities with what are essentially hand tools. More substantial uses, such as drilling core holes to certain depths, do require the temporary land-use permits, the TLUPs.

The interpretation will be in what is a temporary permit, and revocable, compared with a de facto permanent permit, in practice irrevocable. The Supreme Court decision cited Pebble’s major investment in exploration at the time the lawsuit was filed, $300 million, as a factor in decided those particularly permits were permanent, but did not give any guidance as to what investment threshold might drive the determination.

Menefee said the installation of metal casing around drill holes, although discussed in the decision, might not be a workable threshold in a determination because many mining bore holes are cased and it is impractical, and very costly, to require the casing be taken out.

“The casing is always cut off below ground and covered,” and typically poses no environmental threat, Menefee said. “We often allow piping, cable or concrete to be left behind as long as it is non-polluting and doesn’t create a safety problem,” he said.

Once mining exploration gets to the stage where a lease is required it does trigger the DNR’s public notice requirements and often a formal Best Interest Finding process, Menefee said.

If the Legislature had wanted land-use permits to be subject to Best Interest Findings it would have required it in statute. Instead, the permits are specifically excluded from the BIFs, he said.

Meanwhile, the DNR will have to come up with some way of dealing with the court decision. “For now, we don’t see this as a big problem. It is something we can manage. But we’re left trying to interpret what the court meant, and someone may still sue us,” Menefee said.

“We want to ensure that our (new) procedures will match what the court said, he said.

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Thursday, June 11, 2015

Walker pitches TransCanada buyout

Alaska Contract Staffing
Tim Bradner
Alaska Journal of Commerce

Gov. Bill Walker is considering ending the state’s relationship with TransCanada Corp. in the big Alaska LNG Project and taking over a full 25 percent share of the project.

In an interview June 7 in Fairbanks, Walker said that he is weighing the takeover option along with keeping TransCanada in the consortium under the current structure. Under that arrangement TransCanada would ship state-owned gas though its share of pipeline capacity.

A third option Walker is weighing is the state taking a 40 percent share of TransCanada’s interest in the project under the current contract with the state.

The state now has a contract with TransCanada that has the pipeline company owning and operating 25 percent of the large North Slope gas treatment plant and the 42-inch, 800-mile pipeline, and with the state itself owning 25 percent of the large liquefied natural gas plant planned for Nikiski.

North Slope producers BP, ConocoPhillips and ExxonMobil Corp. would own 75 percent of the overall project. The percentages will be roughly in line with the gas ownership of each participant, except that under the current arrangement the state would have TransCanada as a partner in its share.

“TransCanada is a very fine company and I have no problems with their capabilities,” Walker said.

However, the state assuming a larger share of ownership of the project may be in its long-term best interests, the governor said.

Walker made the comments at a conference on state fiscal issues in Fairbanks.

In a related development, Walker has shuffled the state’s management team on gas pipeline negotiations. He named Audie Setters, a 35-year industry veteran manager, as the state’s top manager for gas issues. Marty Rutherford, who formerly filled that role, will remain as deputy commissioner of Natural Resources, the governor said.

There was no announcement of the change but in an interview Walker described it as a “transition” that would bring more strength into the state’s negotiating team, while retaining Rutherford’s experience and allowing her to devote more time to Department of Natural Resources matters.

Rutherford would presumably remain engaged in key gas issues as they relate to the DNR, such as a pending decision to take royalty gas in-kind and a separate gas-balancing agreement.

Walker may face some embarrassing questions about naming Setters to the role, however, because he is a resident of Houston, Texas, although he has been working with the state on gas issues for about a year.

Early this year Walker fired a board member of the Alaska Gasline Development Corp. because he lived out of state, also in Houston.

On TransCanada, the governor has asked the state Legislature for $108 million to compensate the pipeline company for its expenses to date on the project. Legislators have asked for more details of the governor’s plans, however.

Walker did express concern over the added burden of financing a larger state share of the project in view of Alaska’s diminished finances, which are currently stressed by low oil prices and a sharp drop in state revenues.

The Heads of Agreement signed by the project participants with former Gov. Sean Parnell set the framework for the preliminary work on the pipeline and LNG plant. The state signed a separate agreement with TransCanada to allow the pipeline company to own a stake in the project. The contract expires in December, although the assumption has been that it would be extended.

Walker may opt not to extend the contract, however, leaving the state in full ownership of 25 percent of the pipeline and Slope gas plant along with its share of the LNG project.

The project is currently in the pre-Front End Engineering and Design, or pre-FEED, stage, with this phase of work to be wrapped up by early next year. The pre-FEED will include a revised cost estimate, which is currently pegged at $45 billion to $65 billion.

The next key decision for the overall project will be moving into full Front-End Engineering and Design, which could occur in mid-2016 and will involve an approximate $2 billion commitment by the parties.

Later this year, however, the state must decide on whether to extend its deal with TransCanada, and also finalize a fiscal agreement with North Slope producers covering gas production tax and royalty terms. Negotiations on the fiscal agreement and other pending issues such as a Payment-in-Lieu-of-Taxes, or PILT, on municipal and state property taxes, are currently under way.

In an email sent to state legislators May 29 but made available June 9, Walker said, “The agreement with TransCanada allows the state to remove the company as its agent at the end of the pre-FEED. The administration could choose to remove TransCanada at that time, and as late as July 2016. Alaska could then take a direct role in the project at the FEED stage.”

TransCanada’s role in the overall project has been somewhat controversial in Alaska. Parnell agreed to bring the pipeline company in as a partner to gain access to the pipeline company’s expertise in large project management and in dealing with the producer partners in capacity management and expansion issues.

Another consideration is that the arrangement would have TransCanada finance its share of equity in the project, which would amount to several billion dollars, with its own resources. That would relieve the state from the burden of having the raise the money, if it were to assume the full 25 percent share.

On the other hand, under that arrangement the state would not make as much profit from the project.

However, the TransCanada deal was also done partly to resolve potential legal issues related to terminating a previous contract the state had with the pipeline company under the Alaska Gasline Inducement Act, or AGIA. Many state legislators, and Walker as a candidate for governor, criticized Parnell’s move, arguing it gave up too much ownership and share of future revenues to the pipeline company.

There has also been an assumption that TransCanada, as a part owner, would also play a major role in managing the actual construction of the pipeline, an area where it is widely experienced. However, an industry source close to the project, asking not to be identified, said decisions on which entities would be involved in construction management have not been made.

In a response to Walker’s request for funds, state legislative leaders wrote, “Many in the Legislature support the termination of the state’s contract with TransCanada once sufficient financial review and a thorough evaluation of the benefits and risks is undertaken.”

The response was in a letter sent June 4 but not released to the public until June 9. It was signed by House Speaker Mike Chenault and Rep. Mike Hawker, R-Anchorage, chair of the Legislative Budget and Audit Committee, and the co-chairs of the House Resources Committee, Reps. Ben Nageak, D-Barrow and Dave Talerico, R-Healy.

Lawmakers also asked for details as to how the state can fund a larger commitment to the project: “Our partners, before progressing to FEED, will need to know the state has the ability to fund its FEED commitment, which will be significantly higher if TransCanada is no longer a partner in the venture.”

Read more:

Saturday, May 16, 2015

Educators misled by the NEA and the Partnership for Public Education

Kara Moriarty

Alaskans deserve facts on all major public policy issues. Sadly, misrepresentations about Alaska’s oil and gas tax credits threaten to turn a situation that requires a thoughtful and fact-based approach into a political skirmish complete with slogans and accusations.

It is impossible for anyone to track every issue, so we tend to rely on media outlets, unions, trade groups, etc., to provide us accurate information that enables us to learn about and take positions on public policies. Unfortunately, in this case, the union representing teachers has let its members down by continuing to spread inaccurate information for the last month -- even after hearing the facts.

The NEA commissioned a poll this spring, in conjunction with the members of the Partnership for Public Education, which include: AFL-CIO; Alaska PTA; Anchorage Polynesian Lions Club; Citizens for the Advancement of Alaska’s Children; NAACP; Polynesian Association of Alaska; and School Business Partnerships. One of the questions asked Alaskans how they felt about oil tax credits, and if the Legislature should revisit oil taxation. Fair question. However, the question as worded was blatantly incorrect. This could have been an honest mistake, but professional standards dictate that when an error is identified, the responsible party is obligated to correct it. To date, the NEA and the Partnership for Public Education refuse to take ownership of their error, which is especially regrettable when you consider this is the union that represents teachers who, more than any other professional, strive for truth in information as they educate the next generation of Alaskans.

More than a month ago, I respectfully presented the correct information from the Department of Revenue to the NEA and the PTA. I asked that they provide the facts to those that received the poll and put a disclaimer on the public results. Several emails and many weeks later, I have been ignored and nothing has been done. The pollster for this organization, Hays Research Group, is also unwilling to correct the record despite what appears to be a clear violation of the ethical guidelines outlined by that profession’s trade organization. As the head of a professional association whose mission is to provide Alaskans with factual, third-party referenced information, this kind of casual attitude toward the truth is unsettling. My professional training is in education; I used to be an elementary school teacher, and an NEA member, and I would be horrified to know my union was consciously choosing to misrepresent an issue that was proven to be false.

The inaccurate statement contained within the poll question posed to Alaskans read like this:

"The state revised its oil tax law in 2013, and Alaskans voted by a narrow margin in August not to repeal the new tax system. At current oil prices, the state gives out more in oil tax credits to the oil industry than it receives in revenue from the oil industry. Would you support the Legislature revisiting the issue of oil credits and taxes in light of the current deficit?"

Who wouldn’t respond with a “yes” to this question as worded? The trouble is, it’s just flat wrong.

In fact, its entire premise is wrong. It is an indisputable fact that the State of Alaska receives billions more in revenues than it pays out to oil companies when you look at all oil revenue sources: royalties (the state’s share as an owner), production taxes, income taxes, property taxes and other fees paid to the state.

Alaskans deserve an honest conversation based on facts as we tackle our fiscal challenges, not half-truths or political spin. No one is served when individuals or organizations throw out inflammatory accusations that are clearly either false or taken out of broader context.

The NEA has every right -- and even the responsibility -- to lobby rigorously for policies that benefit public education and teachers. But it should do so in a way that informs Alaskans with accurate information, not misleads them by spreading false information.

My organization has set up a special page on our website for readers who want more information on oil revenues and tax credits from objective, third-party sources. Visit and learn about it for yourself.


Kara Moriarty is executive director of the Alaska Oil and Gas Association, a nonprofit trade association whose mission is to foster the long-term viability of the oil and gas industry in Alaska.

Thursday, May 7, 2015

Pentex purchase could cut ratepayers’ bills immediately

Fairbanks Natural Gas customers could see their heating bills drop immediately if the utility is sold to the Alaska Industrial Development and Export Authority.

“We do believe through the financing tools that AIDEA has, we could reduce the (gas) rate in Fairbanks right away by approximately 14 percent,” former AIDEA director Ted Leonard said at the authority’s April 30 board meeting.

“Rationalizing” the two gas distribution systems being developed by Fairbanks Natural Gas and the Interior Gas Utility and forming one system could provide significant capital and operating cost savings, he said.

Leonard retired as AIDEA executive director earlier this year but has continued to work on the Interior Energy Project because of his extensive experience with the earlier North Slope work.

Further savings to ratepayers would come from the different business models — moving away from the inherent cost and return requirements in a privately-owned utility structure.

Mark Gardiner, a financial consultant who is working closely with AIDEA on the proposed deal, said that the current rate of $23.35 per thousand cubic feet, or mcf, of gas FNG customers are paying could be $20 next year if the sale goes through. The savings would be even greater if FNG’s pending rate case before the Regulatory Commission of $24.96 per mcf is accepted.

The potential cost savings from the purchase are separate from whether or not the Interior Energy Project moves forward. However, an early projection of $16.80 per mcf in 2020 for all customers of a blended utility was presented to the board.

That estimate assumes liquefied natural gas can be delivered to Fairbanks for the equivalent of $11 per mcf, a midstream price the Interior Energy Project will have to come close to in order to meet the stated goal of the project.

Leonard said North Slope gas trucking project models came in with a comparable price in the $13 to $13.50 per mcf range.

AIDEA projects full buildout of a consolidated Fairbanks gas utility to cost $223 million. To date, the authority has issued $52.8 million in loans for gas distribution from the $332.5 million Interior Energy Project state financing package.

AIDEA announced a preliminary agreement to purchase the parent company to Fairbanks Natural Gas, Pentex Alaska Natural Gas Co., in late January.

That announcement was met with resistance from some Alaska legislators who questioned the premise of the state purchasing outright a private business and how the AIDEA-Pentex sale would affect an earlier agreement for a Hilcorp subsidiary to purchase Titan Alaska LNG — Pentex’s LNG trucks and small Southcentral liquefaction facility.

The 10-year LNG supply agreement Harvest has with Pentex, as part of the Titan sale would remain as well. That agreement is to fuel existing gas customers and does not expand Interior’s natural gas supply.

It’s currently believed the two deals can coexist; AIDEA would purchase Pentex for $54 million and then sell Titan to Harvest Alaska (Hilcorp) for $15.1 million, which is the price Pentex and Harvest originally agreed to.

The AIDEA deal is set to close July 31. The Titan sale is being reviewed by the RCA and Attorney General Craig Richards and has a Sept. 31 financial close date.

If the Titan sale is denied or otherwise fails AIDEA would retain those assets.

Leonard and Gardiner said it is the authority’s intent to sell or otherwise transfer control of Fairbanks Natural Gas within two years to a local entity, most likely IGU, which is owned by the Fairbanks North Star Borough.

Fairbanks Natural Gas President and CEO Dan Britton, who is also a minority shareholder in Pentex, said in an interview that IGU leaders have generally been kept abreast of the negotiations with AIDEA and are supportive of the overall plan.

Fairbanks Natural Gas petitioned the RCA for IGU’s service area and Britton has said two operating gas utilities makes little sense for the small customer base that is the greater Fairbanks area.

IEP gets moving

Now that a bill has passed allowing Cook Inlet gas to be used as a possible supply, it’s full steam ahead for the Interior Energy Project, its manager Bob Shefchik said April 30.

The project team had meetings scheduled the week of May 4 with 15 to 18 parties that have expressed interest in partnering on the Interior Energy Project, Shefchik said.

“Because it’s been such a long process we want to bring them in, talk to them about where we’re headed, what we expect to be in the solicitation and get some feedback,” he told the AIDEA board.

A request for proposal, or RFP, for a private partner to expand Southcentral gas liquefaction capacity should be issued by AIDEA by mid-May and stay open for 30 days, according to Shefchik. Proposals for a small gas pipeline and propane solutions will also be accepted.

He said the board could expect the results of the RFP at its June 25 meeting.

Concurrently, the state Commerce Department along with the Revenue and Natural Resource departments are working on a gas supply solicitation.

Shefchik, a former Interior Gas Utility chair, said the Fairbanks utilities have agreed to participate in the RFP selection process and a range of acceptable gas prices will be worked out earlier than it was during the North Slope supply efforts to keep the utilities on board.

“The thing that has to be avoided is (price) being the last thing decided,” he said.

Sunday, April 5, 2015

State estimates $150B to treasury if ANWR ever opened

Alaska Contract Staffing
Tim Bradner
Alaska Journal of Commerce

Alaskans have long believed oil discovered in the coastal plain of the Arctic National Wildlife Refuge could help keep the Trans-Alaska Pipeline System operating and also replenish the state treasury.

It may be a pipe dream because the federal government shows no sign of opening the coastal plain to further exploration and Congressional approval is required for any exploratory drilling or leasing.

Interior Secretary Sally Jewell, who denied the State of Alaska’s proposal for new seismic exploration of the ANWR coastal plain and is awaiting the outcome of a court case challenging that decision, wants to make it wilderness, a permanent lockup.

But what if? What if there were exploration, and discoveries? How much oil could there be? State officials told legislators in February the revenue to the state treasury could total more than $150 billion over 50 years.

ANWR’s coastal plain, in the eastern North Slope, is thought by geologists to have the best potential for major discoveries of any unexplored onshore area of the U.S.

Major oil fields have been discovered in the central North Slope, including the very large Prudhoe Bay and Kuparuk River fields. There is potential for further discoveries in this area but they are expected to be smaller.

The southern North Slope, and the huge 23-million-acre National Petroleum Reserve–Alaska on the western Slope, are generally thought by geologists to be prone to natural gas discoveries although some oil will almost certainly also be found.

The most informed estimate on ANWR’s coastal plain area came from the U.S. Geological Survey in 1998, which made a “mean” estimate of 7.7 billion barrels of recoverable oil that could be discovered. “Mean” is basically mid-way between high and low estimates.

Whether oil is really there isn’t known for sure. The USGS worked with data from 1,180 miles of two-dimensional seismic program conducted between 1983 and 1985, plus what is known about the regional geology.

The only exploration well drilled in ANWR, in a 91,000-acre in-holding of private lands owned by Kakovik Inupiat Corp. and Arctic Slope Regional Corp., was drilled in the early 1980s by BP and Chevron Corp., and the results are still secret.

No matter what the drilling showed, development of even these private lands are blocked unless Congress decides to open the rest of the costal refuge.

Still, state legislators in Juneau want to know what Alaskans may be missing out on.

In mid-February, the House Resources Committee asked the state departments of Natural Resources and Revenue to develop the most plausible oil discovery and production scenarios based on that is known, and to derive state revenue estimates from those.

The two agencies presented their results to the committee on Feb. 12.

Paul Decker, acting director of DNR’s Division of Oil and Gas, described ANWR’s regional geology in the so-called “1002” area, a coastal plain area named for the section of the law in which Congress designated for additional study of petroleum resources in the Alaska National Interest Lands and Conservation Act of 1980, the federal law that created the refuge.

Decker said the best prospects for discovery are in the western third of the coastal plain, which state geologists believe to hold the most oil potential. Of the 7.7 billion barrels of resources estimated to be in the 1002 area, 6.4 billion barrels are expected to be in the western third.

That is about five times the oil potential of the eastern two-thirds of the coastal plain.

“The northwestern one-third of the coastal plain is geologically simpler and more favorable to hosting oil accumulations,” Decker told the committee.

The area is also adjacent to state lands across the Canning River where companies have made discoveries at Point Thomson (gas, liquid condensate, and oil), and Sourdough (oil). Oil has also been discovered offshore the 1002 area, with the Kuvlum well in 1993 and “Hammerhead” (where Shell is exploring) in 1985.

Geologists in the division did further analysis, predicting that most of the accumulations that might be discovered would be in the 32 million-barrel range to 256-million-barrel range, but accumulations of 1 billion barrels were also possible.

Based on that analysis, the Department of Revenue developed possible production and oil royalty and tax estimates. Ken Alper, director of the Tax Division, presented the conclusions, assisted by Dan Stickel, assistant chief economist.

The scenario presented by Alper and Stickel would have permission granted by Congress to explore in 2016 and leases issues between 2017 and 2019. Exploration would begin in 2019, with the first field located in 2022, and with its development beginning that same year.

First production would be in 2026. From that point on, the scenario foresees one new field discovered and brought into production every two years so that there would be 25 fields in total developed by 2074. The assumed size of discoveries vary along the lines of the estimates by the Division of Oil and Gas but most of the new fields would be between 64 million barrels and 512 million barrels of recoverable resources.

All prices and costs in the modeling assumed 2015 constant dollars and an oil price of $110 per barrel along the lines of the Revenue Department’s very long-range price forecast (a $90 per barrel case was also considered, however).

The modeling assumes no gas being developed, although surely there would be gas discovered also.

Given these assumptions in the modeling, a “base case” of 7.1 billion barrels of oil developed and produced until 2075 would bring $150.9 billion to the state treasury, although the number could be higher, or lower, depending on the amount of oil found.

The production profile in the base case was about 560,000 barrels per day, with a high case, with more oil discovered, of 760,000 barrels per day and a low case, with less oil discovered, or 350,000 barrels per day.

The required investment by industry would reach $5.75 billion per year in the development, pre-production phase, with continuing investment all through the operating lives of the fields.

Because of tax credits in the current state production tax the state treasury would not begin to experience income net of the tax credits until 2030 or 2031, but revenues would then increase rapidly to a peak of about $4.9 billion per year in 2045.

Revenues would the taper off gradually, but even by 2075, the end of the period modeled, there would still be $3.3 billion per year net to the state treasury.

Read more:

Saturday, March 7, 2015

Beechey’s fate unclear; State termination proceedings began last year; BRPC wants to consolidate prospects

Eric Lidji
For Petroleum News

The state is considering the fate of the Beechey Point unit.

The Alaska Department of Natural Resources started termination proceedings for the North Slope unit last September, although it agreed to reconsider after operator Brooks Range Petroleum Corp. made a case for maintaining the unit in the Gwydyr Bay region.

Then-Commissioner of Natural Resources Joe Balash initiated the termination proceedings in September 2014, saying the Alaska-based company had failed to meet certain work commitments in its initial five-year plan of development and failed to meet any of the conditions for justifying an extension. In addition to obvious conditions like sustained oil or gas production or ongoing exploration activities, those conditions include having a well certified as capable of producing hydrocarbons in commercial quantities.

With no such certified well at the unit, Balash believed termination was justified.

The company disagreed. In a late September 2014 letter, Vice President for Exploration Larry Vendl named two certified wells within the unit boundaries. He asked for a chance to negotiate a plan of development that would allow the company to continue exploration and development activities. The company could start as early as 2015, Vendl wrote.

Wells on leases

The leases included in the Beechey Point unit undeniably include two wells certified as capable of producing hydrocarbons in commercial quantities: Gwydyr Bay South No. 1 from 1974 and North Shore No. 1 from 2008. Both wells, though, were drilled before the state approved the Beechey Point unit in mid-2009. To the state, that made them irrelevant for extending the terms of the unit. To the company, it made no difference.

Of particular interest is North Shore No. 1, which was the first well Brooks Range Petroleum drilled in Alaska. The state certified the well in July 2008, approved the Beechey Point unit in August 2009 and asked the company to apply for a recertification by August 2010. To Brooks Range Petroleum, this “redetermination requirement” represented a changing standard. No other operator had been asked to perform a similar task, according to the company, which asked the state, in July 2010, to reconsider.

The state never responded, according to the company. The debate may be more than merely an administrative debate, though. In his September 2014 letter, Balash wrote, “It is my understanding that the well is physically incapable of producing hydrocarbons.”

New plan wanted

Brooks Range Petroleum now wants to negotiate a new plan of development, citing its commitment to the project thus far. The company said it had spent more than $85.5 million exploring the region to date and had begun permitting for a proposed North Shore Development Project. The company also applied to form an initial participating area. The state had yet to rule on the application when the termination proceedings began.

What the company failed to do was drill all the exploration wells required by the unit agreement. The agreement required Brooks Range Petroleum to drill at least one well in two different exploration blocks by December 2010 and December 2012, respectively.

The company only met the first work commitment. The state subsequently extended the deadline for the second commitment until 2014, which the company also missed.

In October 2014, Balash agreed to reconsider the termination. His decision came shortly before the election of Gov. Bill Walker, which prompted a turnover of many cabinet-level positions, including the Department of Natural Resources. The new commissioner, Mike Myers, inherited the matter and had yet to issue a decision by early March.

A decade of work

Although recently sold to a multiparty joint venture, Brooks Range Petroleum Corp. started its life as the operating arm of the Alaska Venture Capital Group, which came to Alaska in 1999 to pursue sizeable oil fields passed over by the major oil companies.

The Gwydyr Bay region north of Prudhoe Bay fit the bill.

The company acquired leases through a 2001 land swap with Phillips Petroleum and arranged an exploration program. The program collapsed under the weight of various logistical problems. Still intrigued, the company acquired the acreage again in 2005.

Brooks Range Petroleum commissioned a two-well exploration program in early 2007.

North Shore targeted Ivishak

The 10,319-foot North Shore No. 1 well targeted an oil accumulation in the Ivishak formation first tested by Mobil Oil with the Gwydyr Bay South No. 1 well in 1974. The well encountered “approximately 70 feet of oil-charged Ivishak sandstone formation.”

The 11,348-foot Sak River No. 1 followed up on a prospect previously included in the BP-operated Sak River unit. The well proved to be a dry hole, although the results were intriguing enough for the joint venture to consider returning to drill a sidetrack.

That winter, the company also commissioned a 130-square-mile 3-D seismic survey, which “identified two small satellite prospects to North Shore No. 1 that can be reached from the North Shore No. 1 drilling pad,” according to a former partner on the project.

Combining small prospects

The results of that initial season started the company along its current path - finding a way to string together several marginally economic prospects into a single, profitable development. An early partner described the strategy as “establishing a threshold” for development. Potential solutions included two production pads or extended reach drilling.

Brooks Range Petroleum re-entered North Shore No. 1 in early 2008 to test the Ivishak and the shallower Sag River formations. The Ivishak flowed at 2,092 barrels of oil per day. A mechanical problem down hole compromised the Sag River test, although the partner estimated that an unencumbered test could have flowed at 1,000 barrels per day.

That summer, the joint venture acquired the nearby Pete’s Wicked prospect from Pioneer Natural Resources Inc. BP discovered the prospect in 1997 and Pioneer acquired it in a 2003 lease sale. The acquisition provided an additional opportunity for bundling several prospects together.

A legal dispute among partners prevented drilling in early 2009. The following winter, Brooks Range Petroleum drilled the Sak River No. 1A sidetrack and the North Shore No. 3 delineation well. The company suspended both wells at the end of the drilling season.

Sak River 1A wet

“Sak River No. 1A was truly an exploration project with a pre-drill risk factor of 1 in 5, unfortunately the well encountered mainly water from the Kuparuk formation,” Brooks Range Petroleum Chief Operating Officer Bart Armfield wrote in a completion report for the season, which was published after a mandatory two-year delay. Although the company had plugged and abandoned the original Sak River No. 1 well, it suspended the sidetrack, which would allow it to be used for providing pressure maintenance for future wells in the Sag River formation. The company said it was considering plans for a second sidetrack, which would aim for an “up-dip target of the Kuparuk,” Armfield wrote.

North Shore No. 3 “identified a common oil/water contact between the Sag and Ivishak formations and presents a reduced reserve base for the North Shore development,” Armfield wrote, adding that the company had now discovered reserves at North Shore No. 1, North Shore No. 3 and Pete’s Wicked, which would guide future activities.

With its attentions increasingly devoted to the Mustang development, just west of the Kuparuk River unit, Brooks Range Petroleum has yet to return to the Beechey Point unit.

The original unit covered some 52,876 acres north of Prudhoe Bay. The unit contained five exploration blocks. In September 2012, the company relinquished some 42,119 acres on the western side of the unit, leaving a seven-lease unit covering some 10,757 acres.

‘Close proximity’

The challenge at Beechey Point remains the same, according to Vendl.

“The potential for successful exploration and development in this area requires the compilation of several prospects with known reservoir reserves in close proximity to one another,” Vendl wrote in his letter. “The smaller prospects need to be a part of a larger program; each independent prospect does not support an economic development model.”

The current strategy involves combining the prospects of various operators in the region, including the East Shore prospect at Beechey Point, the ConocoPhillips-operated Kup Delta lease and the UltraStar Exploration-operated Dewline unit, all of which are located on adjacent leases (see map). At the time of the letter, in September 2014, Brooks Range Petroleum was involved in discussions with both ConocoPhillips and UltraStar, according to Vendl.

Another option, Vendl noted, would be to expand the 3-D seismic survey BP Exploration (Alaska) Inc. is commissioning for the northern end of Prudhoe Bay, including Beechey Point. “We continue to pursue the availability of the contractor to include the (Beechey Point unit) leases so that we can determine the full potential of the Kup Delta and (Beechey Point unit) eastern area, including the Dewline unit,” Vendl wrote in his letter.

Read more:

Mustang under way; Alaska company drilled initial injection well in January, planning two more

Alaska Contract Staffing
Eric Lidji
For Petroleum News

The Mustang development is under way. Brooks Range Petroleum Corp. began drilling its first development well at the North Slope field in early January using Nabors rig 16E. The approximately 9,300-foot SMU-M02 well is a directional injection well to support Southern Miluveach unit production.

The well is the first in a three-well development program planned for this winter. The next two, SMU-M03 and SMU-M04, will be horizontal production wells. The Alaska Oil and Gas Conservation Commission issued a drilling permit for SMU-M03 on Feb. 13.

The Mustang field is the initial development project at Southern Miluveach, which sits along the southwestern border of the Kuparuk River unit, north of the Tarn satellite.

The program is aimed at bringing the field into production by April 2016. In a plan of development submitted to the Alaska Division of Oil and Gas in the latter half of 2014, Brooks Range Petroleum described plans to drill as many as 13 wells during 2015.

The Mustang project includes a gravel pad, a gravel access road connecting to the existing road grid at the Kuparuk River unit and a standalone production facility. The road and pad were completed last year. Construction of the facilities is running concurrently with the initial drilling operations. The Alaska Industrial Development an Export Authority is helping to finance both the early infrastructure and the facilities.

The all-season road means Brooks Range Petroleum can continue work beyond winter.

The company expects the approximately 40 million barrel oil field to initially produce between 8,000 and 10,000 barrels per day, which would leave considerable room at the 15,000-barrel-per-day processing facility to accommodate future developments nearby.

Last year, a joint venture comprising Thyssen Petroleum USA, the JK Group and Magnum Energy Partners acquired ownership of Brooks Range Petroleum from Alaska Venture Capital Group LLC and Ramshorn Investments Inc. The joint venture also acquired with a 90 percent interest in the Alaska holdings of the two former owners.

Fairway under way

The Mustang development will be the first in the region between the Kuparuk River unit and the Colville River unit, which is colloquially known as “the billion-dollar fairway.”

The optimistic name reflects the advantages of operating in a region with considerable transportation and processing infrastructure, which is a rarity on the North Slope.

A standalone processing center in the region could improve the economics of other projects in the fairway. Brooks Range Petroleum operates the nearby Putu and Tofkat units and, until its recent termination, the Kachemach unit. ASRC Exploration LLC operates the Placer unit. Repsol E&P USA Inc. is exploring on leases to the north. Royale Energy Inc. intends to drill exploration wells on leases to the south as early as 2016.

Quick turnaround

After more than a decade of exploration activities, including three prolific drilling seasons, Brooks Range Petroleum farmed-in the North Tarn prospect in early 2010.

Over the 2011 and 2012 exploration seasons, the company drilled the North Tarn No. 1 exploration well, the North Tarn No. 1-A sidetrack and the Mustang No. 1 delineation well. The wells tested the Brookian formation and deeper Kuparuk formation.

The company initially expected to find some 6 million barrels of oil in the Kuparuk formation. Instead, the wells proved an estimated 44 million barrel resource, according to an independent audit by the global consulting firm DeGolyer and MacNaughton.

The larger discovery prompted the company to seek alternative ways to finance a development program, including AIDEA and the recently formed joint venture. The region is also thought to hold considerably reserves in the Brookian formation, although the more complication geology will likely delay development for some time.

Read More:

Hilcorp Energy keeps up spending despite oil price slide

Thoughtful Thursdays
Tim Bradner
Alaska Natural Resource Month

Hilcorp Energy continues to grow its Alaska business despite the slump in oil prices. The company has increased its Alaska production and plans additional investments of $300 million to $350 million this year in spite of the skid in prices, Hilcorp President and CEO Greg Lalicker told state legislators Feb. 24 in Juneau.

The company’s Cook Inlet production has reached about 40,000 barrels of oil equivalent per day, or boe/day, a measurement includes crude oil and natural gas values expressed, in energy content, as barrels of oil.

Meanwhile, Hilcorp’s acquisition of interests in three North Slope producing fields last November has added another 20,000 boe/day, Lalicker said.

Alaska now contributes 60,000 boe/day to the company, or about 40 percent of Hilcorp’s total production, he said.

Hilcorp is the nation’s largest privately-owned independent producer and specializes in buying mature producing properties and rejuvenating them to add production.

The company also has to deal with some of the problems that come with acquiring older production properties, however. On Saturday, Feb. 28, a breach occurred in a 10-inch production line in the Milne Point field, one of the older North Slope fields where Hilcorp is now operator, resulting in a spill of undetermined size.

Four adjacent production pads were shut in while response crews struggled through blizzard conditions. A plug was inserted in the pipe and spill cleanup operations were underway March 1 as the weather improved.

Meanwhile, a bypass line was installed to reestablish the flow of oil through the pipe, eliminating the danger of a freeze-up and adding additional protection against a further spill. Production was restored to normal levels the same day.

So far, Cook Inlet has been a success for Hilcorp. Before the company purchased the aging Inlet producing properties from Chevron Corp. and Marathon Oil in 2012 and 2013, production averaged about 18,000 boe/day.

By January 2014, after two years of new investment and intense activity, production had reached 32,000 boe/day. By July it had passed 40,000 boe/day, according the materials Lalicker presented to state legislators.

“Our business strategy is straightforward. We buy old producing assets, we figure out how to operate them most efficiently and we find ways to increase production. We don’t just cut costs. We find ways to produce more,” Lalicker said.

Hilcorp is now applying a similar strategy on the North Slope. In November it took ownership of the Northstar, Endicott and Milne Point producing fields after purchasing them from BP last November. Liberty, a non-producing offshore discovery, was included in the purchase.

Hilcorp now owns 100 percent of Northstar and Endicott and 50 percent of Milne Point, but Hilcorp is operator in all three fields.

The company’s immediate focus is on Milne Point, Lalicker said, because there are a larger number of wells there than at the Northstar and Endicott fields.

Hilcorp’s strategy of doing aggressive workovers on older wells should have immediate benefits in production at Milne Point, he said.

Hilcorp has already put one workover rig to work at Milne Point and is now constructing a new workover rig for the field that will be shipped to the North Slope in late summer, he said.

The company is taking a cautious approach, however, in developing Liberty, a nonproducing offshore deposit also purchased from BP in November. Hilcorp owns 50 percent of Liberty with BP owning the other half, with Hilcorp as operator.

Hilcorp presented a possible development plan to the U.S. Bureau of Ocean Energy Management but the company is still studying the project, Lalicker said.

“We haven’t sanctioned development. It’s still up in the air,” he said. “We need to do a lot more on the development plan before we start pouring money into Liberty.”

Liberty is about five miles offshore in federally-owned submerged lands beyond the state’s territorial limit, with the U.S. BOEM as the managing agency.

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Saturday, February 28, 2015

DOI wants operation plan, relief well rig for exploration drilling

Alaska Contract Staffing
Alan Bailey
Petroleum News

The Bureau of Safety and Environmental Enforcement and the Bureau of Ocean Energy Management, the two agencies within the Department of the Interior responsible for oversight of U.S. outer continental shelf oil activities, have released proposed new regulations for exploration drilling in federal waters of the Beaufort and Chukchi seas.

The agencies have been developing the regulations in the aftermath of the Deepwater Horizon disaster in the Gulf of Mexico - the draft regulations had been under review by the White House Office of Management and Budget since August and were released on Feb. 20. The regulations are subject to a 60-day comment period that will begin following publication in the Federal Register.

“The Arctic has substantial oil and gas potential, and the U.S. has a longstanding interest in the orderly development of these resources, which includes establishing high standards for the protection of this critical ecosystem, the surrounding communities, and the subsistence needs and cultural traditions of Alaska Natives,” said Secretary of the Interior Sally Jewell. “These proposed regulations issued today extend the administration’s thoughtful approach to balanced oil and gas exploration in the Arctic, and are designed to ensure that offshore exploratory activities will continue to be subject to the highest safety standards.”

Performance-based and prescriptive

Interior says the new regulations contain a combination of performance-based and prescriptive standards that cover all phases of offshore exploration in the Arctic.

The proposed rule includes requirements that an offshore operator file an integrated operations plan for proposed drilling operations; that the operator of a drilling project has available a capping stack and containment dome for dealing with an out-of-control well; and that the operator has available a second rig for the drilling of a relief well, should a well loss-of-control incident arise.

“This proposed rule is designed to ensure safe energy exploration in unforgiving Arctic conditions,” said BSEE Director Brian Salerno. “It builds upon our existing Arctic-specific standards and experience with previous operations offshore Alaska, encourages further development of technology, and includes rigorous safeguards to protect the fragile environment.”

“As we make the vast majority of the Arctic oceans offshore Alaska available for oil and gas leasing, we have an obligation to provide the American people with confidence that these shared resources can be developed responsibly,” said BOEM Director Abigail Ross Hopper.

The regulations specifically relate to exploration drilling, rather than the drilling required for oilfield development or maintenance.

During a Feb. 20 news conference Salerno said that a final version of the regulations will not be completed before this summer’s Arctic offshore drilling season and will not, therefore, apply to Shell’s planned exploratory drilling in the Chukchi Sea this year. But, Salerno commented, provisions within the regulations draw heavily on requirements that were set during Shell’s 2012 Arctic drilling operations, on lessons learned from those operations and on discussions held with Shell regarding its 2015 plans. Thus, if Shell does drill in 2015, the company will need to comply with some new requirements that correspond to features of the new regulations, Salerno said.

Integrated operations plan

The purpose of the integrated operations plan, which, according to the proposed regulations, an Arctic offshore operator would have to file with Interior at least 90 days prior to filing an exploration plan, is to provide government agencies with early information about what an operator intends to do and to stimulate early discussions about the operator’s intentions. “The whole purpose behind the operational plan is to provide early indications of how an operator proposes to approach a drilling season,” Salerno said.

The integrated operations plan would include information such as proposed vessel and equipment specifications; the schedule of operations; the drilling program objectives and timeline; contractor management arrangements; and plans for the preparation and deployment of spill response assets. The plan would not require formal agency approval, as is needed for an exploration plan.

Salerno said that the proposed regulations require that a company conducting drilling operations in the Arctic outer continental shelf has available in the Arctic the appropriate systems needed for the capping of a well following a loss-of-control incident, and for the containment of spilled oil, should the capping system fail. A capping stack, for sealing the wellhead, must be available for transfer to the well site within 24 hours of an incident, while cap-and-flow and containment systems, for gathering spilled oil and transferring the oil into surface vessels, must be available within seven days.

Salerno said that, given the remote nature of the Arctic, it would not be acceptable for an operator to contract the use of capping and containment systems that are stationed in the Gulf of Mexico.

Relief well capability

One particular feature of the proposed regulations is the mandating of a second drilling rig for the drilling of a relief well following a loss-of-control incident - a relief well is a secondary well drilled after a well blowout, to enable cement to be injected into the problem well bore, to permanently seal the well. The need for the rig and the need for a time window before the onset of the winter to drill a relief well add significant cost to an Arctic drilling operation. In a presentation to the Office of Management and Budget Shell argued there has been no recorded instance of a relief well bringing a well blowout under control, and that new well capping technology, coupled with improved well integrity management, can effectively reduce the probability of a loss of well control.

“We understand that the same-season relief rig is somewhat controversial,” Salerno said. “From our perspective that sets a level of protection for the Arctic that is necessary.”

Interior is also insisting that an operator has available sufficient mechanical oil recovery equipment to recover all oil spilled in a worst case spill scenario, even although there are alternative techniques, such as in-situ burning and dispersant use, that could be employed if appropriate.

And during drilling operations, it will be necessary to test the well blowout preventer every seven days rather than every 14 days, as is mandated elsewhere.

The discharge of drilling waste into the ocean has in the past proved controversial, especially in the context of Arctic offshore drilling. The proposed regulations would prohibit the discharge of any petroleum-based drilling mud and associated cuttings and would also give Interior’s regional supervisor the discretion to ban the discharge of water based mud.

And during drilling operations an operator must transmit drilling data to an onshore location, and make the data available to BSEE on request.

Varied responses

Shell, in its response to the proposed regulations, said that it supports regulations that further its concern about safety and environmental protection.

“We support regulations that further these imperatives in the Arctic, provided they are clear, consistent and well-reasoned,” said Shell spokeswoman Megan Baldino in a Feb. 23 email. “While we review the draft Arctic regulations put forward by the Department of Interior, we will continue to work with federal agencies, the State of Alaska, local communities, and contractors to develop a 2015 drilling program that achieves the highest technical, operational, safety and environmental standards.”

U.S. Sen. Lisa Murkowski, R-Alaska, chair of the Senate Committee on Energy and Natural Resources, said on Feb. 20 that she was still reviewing the proposed regulations and that she wants to evaluate what impact the regulations may have on the economic development of Alaska’s vast resources.

“Given the opposition this administration has shown so far to responsible resource development, I’m reserving judgment until it’s demonstrated that these regulations will not unnecessarily block investment,” Murkowski said. “If this administration is truly committed to developing our Arctic resources then it is imperative that the Interior Department provide clear direction to Shell and the other leaseholders in the region on how they can proceed.”

Environmental organizations praised the tightening of drilling regulations for the Arctic offshore while also expressing concern about the risks associated with drilling for oil in Arctic conditions.

“We applaud the government for recognizing that existing oil and gas regulations are not adequate,” said Susan Murray, Oceana’s deputy vice president, Pacific. “The new rules clearly are needed and are an improvement, but they do not ensure safe and responsible operations in the Arctic Ocean. There is no proven way to respond to a spill in icy Arctic waters and, as Shell unfortunately demonstrated, companies simply are not ready for the Arctic Ocean.”

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Thursday, February 26, 2015

Good trends for Alaska; Annual BP Energy Outlook 2035 sees a global shift in trade patterns for energy

Alaska Contract Staffing
Eric Lidji
For Petroleum News

With oil prices at six-year lows, it can be difficult to see much optimism for Alaska.

But three trends bode well for the oil and gas sector in Alaska over the next 20 years, according to the most recent edition of the BP Energy Outlook 2035, released Feb. 17.

First, the global energy system is changing directions. Second, global oil market should return to their normal balance. Third, liquefied natural gas should become dominant.

With Alaska sitting at the edge of the Asia-Pacific market and working toward expanding LNG exports while finding a market for existing oil supplies, those trends could help.

The annual outlook is a projection of current energy trends and policies rather than a prediction of what will happen, according to BP Group Chief Economist Spencer Dale.

Rising in the west

As always, trade patterns come down to supply and demand.

The growth of unconventional oil supplies in North America, the growth in oil demand in developing economies like China and India and the flattening of demand in developing economies such as North America, are currently shifting how energy moves around the world. Simply put, oil is moving from west to east after decades of moving east to west.

Specifically, imports to Asia are expected to account for 80 percent of trade among regions by 2035, up from 60 percent today, while exports from the Middle East are expected to fall from 55 percent in 2013 to slightly less than 50 percent by 2035.

At the same time, North America should soon become a net exporter of oil. While the United States imported some 12 million barrels of oil per day in 2005 - or 60 percent of its total demand - the country is on pace to become self-sufficient by the 2030s. By 2035, China should surpass the United States as the leading consumer of liquid fuels.

While unconventional oil production in North America is expected to flatten in the coming decades, the United States and Canada are expected to remain at the forefront of the boom currently under way, even though similar resources exist in other countries.

The current “weakness” in oil markets, as BP phrased it, is largely seen as the result of unconventional oil from North America backing out imports and glutting the market.

Seeing as how these resources drove the two largest single-year increase in domestic oil production in 2013 and 2014, the glut should take several years to “work through,” according to the outlook. Eventually, the high decline rate of unconventional wells and the limited available oil resource should lead domestic tight oil production to flatten.

As it does, global demand is expected to increase. The outlook expects the demand for oil to grow by 19 million barrels per day by 2035, which is the equivalent of adding another United States to global demand. The increase will come largely from China and India.

While tight oil supplies from North America will accommodate much of the demand in the short term, the Organization of Petroleum Exporting Companies is expected to meet the rising demand toward the end of the forecast period, which could rebalance the global market to the position it held long before North American tight oil.

Of the three fossil fuels, natural gas is expected to grow the most by 2035.

While coal has been the fastest growing fossil fuel in recent years, it is expected to become the slowest over the next 20 years as Chinese demand moderates, more policies aim to reduce carbon dioxide emissions and plentiful gas supplies ease conversion.

The outlook expects demand for gas to increase 1.9 percent each year through 2035 with about half being met by increased production from Russia, the Middle East and shale gas.

What is more relevant for Alaska is an expected change in the way natural gas moves.

As part of the changing movement of global energy supplies, the Asia-Pacific is expected to overtake Europe as the leading region for natural gas imports by the early 2020s and growing shale gas production will turn North American from an importer to an exporter.

The “overwhelming majority” of this increasing trade will come in the form of LNG, according to the outlook, which expects 8 percent growth per year through 2020. More tellingly, the outlook expects LNG to overtake pipelines by 2035 - a first in history.

Such a shift would impact gas pricing, as well as the geography of supply and demand.

Of that growth, about half should come over the next five years, as projects currently in the works come into operation. The rest should come between 2025 and 2035.

Given that LNG tankers are more mobile than pipelines, and therefore able to respond to price signals more quickly, an increase in LNG supplies would have the effect of integrating the global natural gas market, which is currently constrained by region.

While LNG is unlikely to create a “global gas price,” according to the outlook, it could cause gas prices around the world to move up and down in unison, with the differences between regions reflecting transportation costs rather than regional issues of supply and demand.

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