Wednesday, January 29, 2014

Longtime Alaskans Named to Junior Achievement of Alaska Business Hall of Fame

Alaska Energy Dudes and Divas is proud to be partners with Junior Achievement of Alaska, and the Alaskans being recognized this year for their support of Alaska's youth.

Anchorage, AK – Five outstanding Alaska business leaders will join the Alaska Business Hall of Fame at the annual Junior Achievement recognition event on January 30, 2014. Business peers recently selected:

  • Walter J. Hickel Jr. – Hickel Investment Company/Hotel Captain Cook
  • Martin Pihl – Chairman, Alaska Timber Insurance Exchange
  • Chris von Imhof – Alyeska Resort
  • The Doyle Family – Weaver Bros.
  • Helmericks Family – Colville Brooks Range Supply.

These business leaders are honored for their direct impact toward furthering the success of Alaska business, demonstrated support and commitment to Junior Achievement’s programs, and demonstrated commitment to Alaska business.

The induction ceremony into the Alaska Business Hall of Fame will be held Jan. 30, 2014 at the Dena’ina Civic & Convention Center. Junior Achievement of Alaska, Inc. and Alaska Business Monthly are the Title sponsors of this event. Alaska Business Monthly will feature an interview and biography of each of the Laureates in the January 2014 edition.

In 1987, Junior Achievement of Alaska, Inc. began the Alaska Business Hall of Fame to honor outstanding individuals of Alaskan business. Since then, the Hall of Fame has become one of the state’s most prestigious events, inducting new Laureates on an annual basis.
“This class joins a group of more than 100 Hall of Fame Laureates exemplifying the rich diversity of Alaska in terms of geographical regions, business and industrial heritage, and cultures. In essence, the Laureates represent the foundation upon which the state of Alaska is built and continues to grow.” Ret. Gen. Mark Hamilton, Hall of Fame 2014 Emcee
The 28th annual celebration includes a reception beginning at 5:30 p.m., dinner and induction ceremony at 6:30 p.m., concluding by 8:30 p.m.

Monday, January 20, 2014

BP drilling increases 30% in 2013, more planned for ‘14

Tim Bradner

BP Exploration Alaska ramped up its North Slope drilling and well activity on the in 2013 and plans further increases in 2014.

Drilling of new wells increased 30 percent last year over the previous year, an increase of about 100 wells, according to information made available by the company. Well intervention work, mostly remediation of older producing wells, was up 40 percent, according to the company.

BP operates Prudhoe Bay, Milne Point and Endicott oil fields on the Slope.

Well activity and new development work is being stepped up by BP and ConocoPhillips, the two major North Slope operators, following changes to the state’s oil and gas production tax by the state Legislature last April. The new tax went into effect Jan. 1.

BP spokeswoman Dawn Patience said plans for BP’s 2013 activity were in place previously but that the tax change has now encouraged expanded activity for 2014 and beyond.

“We see a further uptick in drilling,” she said.

BP added two new drill rigs last year to its North Slope drilling fleet to bring the total number of rigs working for the company to seven. Two more will be added in 2015, bringing the total to nine, Patience said.

BP is doing the design work for 67 percent more wells to be drilled in 2016 over 2012, according to the company.

ConocoPhillips is also increasing work in the Kuparuk River field, where it is operator. The company added one new drill rig there in 2013, will add a second in February, and is also planning a new production pad. ConocoPhillips is also working on a new production project in the National Petroleum Reserve–Alaska, GMT-1.

Drilling creates a lot of jobs.

“Each drilling rig directly employs 100 people on the North Slope, plus operations jobs and other jobs designing the wells. In all, each rig directly adds a couple of hundred jobs to the Alaska economy,” BP Alaska President Janet Weiss said Jan. 10 at “Meet Alaska,” a conference and tradeshow sponsored by the Alaska Support Industry Alliance in Anchorage.

“Under the new oil tax reform law, BP plans to reinvest nearly 90 cents of every dollar we make here over the next five years in Alaska. We’re investing more, and a bigger percentage than we did previously, an increase from 60 percent from previous years under ACES,” the previous state oil tax law, Weiss said.

The new investment is coming none too soon.

“Of the 13 oil-producing U.S. states in 2011 and 2012 there was only one where production declined. That was Alaska. All the others increased, even California, which recently surpassed Alaska in oil production,” Weiss said.

In Prudhoe Bay, where BP is the operator, the field owners, which include ConocoPhillips and ExxonMobil as well as BP, have pledged $1 billion in investment in near-term field work as well as the start of development planning for a $3.2 billion project in the western end of the field, Weiss said at the Meet Alaska conference.

The west end project includes a major new well pad with 118 wells and production facilities. It is the first significant addition to Prudhoe Bay in a decade, Weiss said. “This is 200 million barrels of new oil reserves, ultimately adding 40,000 barrels per day of new production down TAPS (Trans-Alaska Pipeline System),” she said.

Another project BP will tackle, Weiss said, is development of the Sag River formation, a thin, economically marginal reservoir section overlying the main Prudhoe Bay reservoir. The company will begin a 16-well drilling program in 2015 and 2016, and 200 new wells could eventually be drilled, Weiss said. The project is expected to add another 200 million barrels of reserves, she said.

Read more:

State, producers, TransCanada ink key agreement on pipeline

Tim Bradner
Alaska Journal of Commerce

Gov. Sean Parnell and companies leading the North Slope gas pipeline project took a major step Jan. 14, signing a “Head of Agreement” statement that lays out terms for how the state could help facilitate the effort through an ownership stake and its fiscal terms.

The next step is up to the state Legislature, which convenes Jan. 21 for its 2014 session. Parnell will introduce a number of bills soon that will make the state’s involvement possible.

“The Heads of Agreement is another positive milestone and sets guiding principles, terms and conditions to progress work on the Alaska LNG Project,” said ExxonMobil spokeswoman Kim Jordan. “State of Alaska participation throughout the value chain will improve commercial alignment; provide the state with a seat at the table on the commercial terms of the project, as well as generate additional revenue for the state.”

State officials made more details available Jan. 15 on how it could partner with North Slope producers and TransCanada on the project, which is estimated to cost $45 billion to $65 billion. The deal also changes a licensing agreement with TransCanada under the Alaska Gasline Inducement Act, or AGIA, but it keeps the pipeline company in the consortium as a partner.

If the project moves forward, the state could earn $2 billion to $3 billion yearly in new revenues from gas sales, state Natural Resources Commissioner Joe Balash said in an interview.

Under the plan the state would commit to take its one-eighth royalty share of gas production in kind, or in the form of gas, for the duration of the project, and also take state production taxes as a share of the gas, Balash said.

The state Legislature will be asked to allow that change this spring, Balash said, and also to determine a percentage of the combined state share of gas production. The state royalty is 12.5 percent of production and adding the tax share would bring that to between 20 percent and 25 percent, with the number to be decided by the Legislature, he said.

Separately, the state has entered into a deal with TransCanada to finance, and at least temporarily own, a share of the pipeline and LNG project equal to the state’s share of gas, Balash said. The state will then enter into a shipping contract with TransCanada to transport the state gas to the LNG plant in Southcentral Alaska at Nikiski.

TransCanada would raise the estimated $6 billion to $7 billion needed for its share of pipeline construction, Balash said.

One major concern for the state in the arrangement would be having to market its own gas.

“Under that scenario, we might wind up with a lower price,” for LNG because the state lacks a marketing organization and experience and TransCanada would only ship the state’s gas.

“However, the producers have agreed to a ‘disposition’ agreement, under which they will be prepared to market our gas,” Balash said.

Under the agreement, the state also has the option of purchasing TransCanada’s share of the project when the contract to ship the state gas expires, which could be 20 years to 25 years, Balash said. Alternatively, the state can purchase 40 percent of TransCanada’s share prior to construction beginning, he said.

The pipeline itself will be organized as a joint undivided interest pipeline, meaning that each gas owner will agree to finance and own a percentage equal to its gas production share, essentially a group of separately-owned pipeline entities using one pipe and an LNG plant.

The Trans-Alaska Pipeline System was organized along similar lines when it was formed in the early 1970s to ship North Slope oil. Legally, each TAPS owner operates its own pipeline entity within TAPS, with Alyeska Pipeline Service Co. as the independent operating company.

The LNG plant in Nikiski will be handled differently, Balash said. TransCanada will have no ownership in the plant, and the state’s ownership will be held through a new subsidiary of Alaska Gasline Development Corp., a state corporation formed to build a smaller gas pipeline from the North Slope in the event the large industry-led project stalls.

Balash said AGDC will continue planning on its own project, which is a contingency to supply gas to Alaska communities. If the plan with the producer consortium moves forward, however, the state corporation would finance its share of the LNG plant with revenue bonds, state revenue commissioner Angela Rodell said.

If the Legislature approves statutory changes to enable the plan, which also includes converting the state’s net profits gas production tax to a flat tax on gross revenues, the companies are prepared to begin Preliminary Front-End Engineering and Design work, or pre-FEED, a step that will involve an expenditure of several hundred million dollars, Balash said.

Conversion of the net profits tax to a flat gross revenues tax is necessary because the net profits tax is volatlle, reacting quickly to price changes, which would make it more difficult to convert the tax to a share of gas and contract for capacity in a pipeline, Balash said. The flat-rate gross revenues tax simpler and more transparent, he said.

Also, if the Legislature approves the statute changes, North Slope producers have agreed to begin organized marketing efforts to sell the Alaska LNG including the state’s share, Balash said. The project would produce 15 million to 18 million tons of LNG yearly.

An important consideration in the deal with TransCanada — an element that is retained from the AGIA contract — is the pipeline company’s commitment to certain terms in financing that are to the state’s advantage in maximizing revenues.

The pipeline company has agreed to fund its share of the pipeline and Gas Treatment Plant on the Slope using a 75 percent debt and 25 percent equity investment ratio. That combination results in a lower pipeline tariff, Balash said, which means less shipping costs for state-owned gas, and higher state revenues.

The debt-equity ratio commitment was one of the state’s “must-haves” in its AGIA initiative in 2008 and 2009, and is one the producers have always balked at. It was one of the key obstacles confronting the current deal, too.

As the arrangement now stands TransCanada will retain its commitment on the debt-equity ratio but the producers will retain the flexibility in using whatever financing ratio is most advantageous to them.

Because the producers will be shipping their own gas, and not the state’s, and the state’s royalty and tax share would be converted to gas shipping by TransCanada, the matter is less important under the new deal.

Read more:

Tuesday, January 7, 2014

Alaska in NWT dreams; Industry Minister Ramsay encouraged by Alaska, Yukon, Alberta, NWT relationship

Gary Park
For Petroleum News

Northwest Territories Industry Minister Dave Ramsay is increasingly pinning hopes on Alaska as an outlet for his region’s stranded oil and natural gas at a time when interest in developing those resources is gathering pace.

A series of meetings over the last year with Alaska legislators, along with the Yukon and Alberta, have pointed to the emergence of a “regional perspective” on energy development as the jurisdictions continue their discussions under the umbrella of the Pacific North West Economic Region, he said.

“The Alaskans have been receptive” to proposals that could see crude from the Alberta oil sands and northern Canada fed into the underutilized Trans Alaska Pipeline System and delivered to Valdez for export, Ramsay said, adding: “We’re fooling each other if we’re not thinking on a regional basis.”

The “northern option” is getting a fresh look as pipelines such as TransCanada’s Keystone XL and Energy East, Enbridge’s Northern Gateway and Kinder Morgan’s Trans Mountain expansion face potentially crippling political, aboriginal and environmental opposition.

With those mega-pipeline projects in trouble — although Ramsay emphasizes he wishes “only the best for all of them because we need them” — he said it’s time for the region to ask “what if” a pipeline could carry crude from Alberta and the Central Mackenzie Valley northward through the Gwich’in Tribal Council land in the Mackenzie Delta, into the Yukon and across to Alaska.

Alaska ‘didn’t say no’

When the idea was raised Alaska “didn’t say no (because) it’s important for them to have options” and look for means to pump new revenue into the state with TAPS operating at less than 25 percent of capacity, Ramsay said. He said the NWT must also “continue talking” about other alternatives, notably feeding its gas into LNG exports from British Columbia.

Ramsay said the NWT can speak from experience about the costs of not acting on proposals after spending 10 years, four of them in the formal regulatory phase, on the Mackenzie Gas Project, before it was overtaken by a flood of new gas from shale deposits and got “put on the shelf for the time being.”

“We can tell a really sad chapter about what happened and what could have been” he said.

Ramsay also noted that the MGP gave the NWT an opportunity to involve aboriginal partners in the venture, with the Aboriginal Pipeline Group slated to take a one-third equity position in the pipeline.

He said companies that “have said outright that they don’t want aboriginal partners are too quick to say ‘No.’ Getting aboriginal people involved is the way we do business here in the NWT.”

“We want to see our resources developed in safe, sustainable manner and we believe the NWT is well-situated to be a key energy player well into the future,” Ramsay said, noting that the region is estimated to hold 35 percent of Canada’s total oil resources and 37 percent of its gas.

He said the fact that the MGP proponents — Imperial Oil as operator, ExxonMobil, Shell Canada and ConocoPhillips — are “willing to stay with the project is encouraging” and has been bolstered by indications from Imperial Chief Executive Officer Rich Kruger that the MGP could get a second wind as a source of gas feedstock for LNG exports.

In an October interview with the Globe and Mail, Kruger said a shift to LNG is a “serious” consideration.”

The consortium’s continued interest in the MGP was reinforced in mid-December when it updated the project’s costs to C$16.1 billion for a pipeline and gas-gathering system from C$11.3 billion in 2007, with the costs of developing the three anchor fields estimated at about C$4 billion.

Although the filing with the National Energy Board was largely a formality, Imperial spokeswoman Christine Graves told Petroleum News that her company will consider any “investment opportunities that provide the greatest shareholder value.”

But she cautioned that any attempt to link the MGP with joint plans by Imperial and its parent company ExxonMobil to proceed with an LNG project are premature.

Devolution on track<br>
Of all the hurdles on which the MGP stumbled, the one that caused the most frustration and despair among the industry partners was a drawn-out regulatory process, which is now only three months from its most radical overhaul when authority is passed from the Canadian to the NWT government.

Ramsay said that “devolution” is on track for introduction April 1 “when we should be able to hit the ground running.”

He said the NWT will “use the size of our government to our advantage. We’re not some big, cumbersome bureaucracy. We can see the direct impact that decisions are going to have on people, on the economy and on our environment and we can act accordingly.”

The territorial government has no interest in allowing a ponderous regulatory process to “take opportunities away from the territory,” he added.

The change, including the collection of royalties, initially applies only to the onshore, but negotiations on sharing royalties from the offshore will start after April 1, while regulatory control over the offshore will remain with the National Energy Board for probably another 20 years, Ramsay said.

The Beaufort Sea includes close to C$2 billion in exploration work commitments (through a partnership of Imperial, ExxonMobil and BP and a standalone venture by Chevron), while “numerous discussions” have taken place with ConocoPhillips as it weighs the next round of exploration at its Amauligak discovery, Ramsay said.

But it “remains to be seen” whether companies can use advances in northern technology to satisfy the National Energy Board’s requirement for proof of a “same-season relief well, or an equivalency. We need to see some things happen and it’s important for us to work with the industry.”

On the front-burner are plans for the Canol shale oil play in the Central Mackenzie Valley where ConocoPhillips is ready to conduct horizontal drilling and fracturing of two wells and Husky Energy has scheduled four wells for this summer.

Although the play is focused on oil, if it “gets into commercial viability there’s going to be large volumes of natural gas and natural gas liquids” which in turn could have an impact on the economics of Mackenzie gas, he said.

Read more:

Sunday, January 5, 2014

More questions than answers for oil and gas in new year

Tim Bradner
Alaska Journal of Commerce

What’s in store for Alaska’s oil and gas industry in 2014? There are more questions than answers at this point with three major uncertainties.

First, will North Slope producers and TransCanada finally reach a commercial alignment to proceed with the big North Slope gas pipeline and LNG project? That was unresolved as 2013 ended.

Second, will North Slope producers and explorers quicken the tempo of new development enough to convince Alaskans that Senate Bill 21, the oil tax reform bill passed by state legislators in 2013, was a good idea? Voters will decide on a possible repeal of SB 21 in the August primary election.

People want to see more activity, and Alaskans going to work, as a result of the tax.

Third, will Shell decide — and will it be allowed — to proceed with a Chukchi Sea exploration program now proposed for summer 2014? The company has at least $5 billion sunk in its Arctic offshore exploration since 2005, when leases were first acquired, and has nothing to show for it except two partially-drilled holes done in 2012.

Lawsuits, changes in government rules and operational mishaps, mainly the loss of the Kulluk drillship in a 2012 New Year’s Eve Gulf of Alaska storm, have dogged Shell’s efforts.

Shell has filed an exploration plan for 2014 with the U.S. Bureau of Ocean Energy Management, or BOEM, that lays out a strengthened program for renewed drilling in the Chukchi Sea.

Another question to follow in 2014 will be whether momentum in new Cook Inlet development led by independents Hilcorp Energy, Buccaneer Energy and Furie Operating Alaska is sustained?

Hilcorp’s activity is centered on redevelopment of mature producing fields in the Inlet and it is highly likely this will continue, unless oil prices crash.

Furie is now planning the installation of a gas production platform, so its 2014 activities seem assured. Buccaneer’s work will depend, however, on pending release of new resource estimates for its Cosmopolitan gas discovery and on its ability to resume exploration drilling on other offshore projects with a jack-up rig.

As for Shell, its renewed drilling in the Beaufort is on hold while the company focuses on the Chukchi. Although Shell is drilling on two prospects where discoveries were previously made, Burger in the Chukchi Sea and Siivuk in the Beaufort, the prospects for major finds in the Chukchi are considered greater, causing the company to focus its available resources there.

The exploration plan calls for a fleet of 29 vessels and aerial support from a support base in Barrow and an alternative base in Wainwright. Oil spill response equipment would be kept on hand near Kotzebue Sound and a standby rig, the Polar Pioneer, will be in Dutch Harbor.

The drillship Noble Discoverer would be used for drilling, as in 2012, but it will have had considerable overhauls and upgrades to resolve problems encountered in 2012.

Arctic offshore drilling is considered to have the best prospects for halting, or even reversing, the decline of oil flowing through the Trans-Alaska Pipeline System. That’s because the offshore prospects are large while onshore prospects on the North Slope are more modest.

In the aftermath of oil tax reform passed by the Legislature, the North Slope producers have announced new drilling and new projects that total about $4.6 billion in new investment, and that could add about 55,000 barrels per day more oil production by 2018, although about 18,000 barrels per day of this will come from CD-5, a project by ConocoPhillips that was planned and approved before the Legislature’s passage of SB 21 last April.

A significant new project planned by ConocoPhillips and its minority partner, Anadarko Petroleum, is GMT-1 in the National Petroleum Reserve-Alaska. This is eight miles west of CD-5, which is also within the petroleum reserve although barely because it is near the Colville River, the eastern boundary of NPR-A.

These are projects that have been announced, but there are also two other projects planned by independent companies that, if they proceed, could add another 30,000 barrels per day roughly in the same time period.

One is the Mustang field project planned by Brooks Range Petroleum, an Alaska-based company. The other is Nuna, a satellite of the small Oooguruk field previously owned by Pioneer Natural Resources, which sold its North Slope assets for $550 million to Caelus, another Texas-based independent in September 2013.

Neither company has yet given the go-ahead for the projects, however.

There are also other possible developments. Repsol made three oil discoveries in three exploration wells drilled last winter, two of them that could be commercially viable, the company has said. More test drilling is planned this winter to delineate the two most attractive discoveries. If those are developed there would be more oil added to TAPS, but the timing may be beyond 2018.

Likewise, Linc Energy is in the second winter of test drilling at the small Umiat oil field in the far southeast NPR-A. Umiat is where early U.S.-government sponsored drilling found oil in shallow formations, but the find was uneconomic at the time. Linc hopes to harness new technology, like horizontal production wells, to produce up to 50,000 barrels per day.

Wednesday, January 1, 2014

Bye Bye ACES

Deborah Brollini

SB 21 passing the legislature in 2013 was monumental not only from a state perspective but also from a personal perspective.

My children got their mother back after years of attending fundraisers, and having to care about “ACES,” Alaska Clear and Equitable Share oil tax policy.

On April 14, 2013, my children and I watched the final SB 21 vote go down in the Senate. I knew SB 21 was going to pass. But, it was important for me that my children witness this decision because they have been the heart of my advocacy for oil tax reform since 2009.

Growing up in Alaska is something special, and you can certainly spot those who grew up with Alaska oil and those who have not. Those of us like myself who grew up with oil do not hold Alaska's oil industry in contempt. My children deserve the same future their mother experienced, and so it should be no surprise that I would jump in and fight for their futures. Alaska was worth saving, and I continue to be unapologetic to those who got in my way.

SB 21 is not perfect law. But, I will take it with all of its imperfections. It was a lot of hard work seeing this legislation through. SB 21 is law today, and I can now rest, get on with my life and enjoy my children.

My children’s Alaska future is so bright with SB 21 that they have to wear shades.