Monday, February 27, 2012

ASD receives 50 book donation of "Cracking the Code: A Citizens Guide to the Alaska Natural Gas Pipeline Discussion"

ASD MEMORANDUM #199 (2011-2012)

February 27, 2012




The Anchorage School District’s Alaska Studies teachers will greatly benefit from receiving the book, “Cracking the Code: A Citizens Guide to the Alaska Natural Gas Pipeline Discussion,” donated by Ermalee Hickel and Cindy Roberts.

This is a unique resource that will strengthen the understanding of the pipeline and oil and gas issues, as well as be a great addition to the District’s Alaska Studies materials. The book supports a wide-range of social studies and science related conversations, from government to geology and physics. It will enable teachers to build a strong understanding of this issue in our next generation of Alaskan leaders.

“It is so generous of Ermalee Hickel and Cindy Roberts to provide this resource to all Alaska Studies teachers. It is with partnerships such as these that we can strengthen our teachers and together build a strong and engaged Alaskan citizen,” said ASD’s Social Studies Coordinator Pamela Orme.

It is requested that the Board officially thank and recognize Ermalee Hickel and Cindy Roberts for their generous donation of 50 copies of this book. Their thoughtfulness and effort to advance the District’s mission are greatly appreciated.

ASD Core Value: Public education should be responsive to an ever-changing world.

Sunday, February 26, 2012

Steve Pratt's "3-1-3 Rap"

Your Alaska Energy Dude Steve Pratt wrote the following rap celebrating 3-1-3 (March 13th)

3-1-3 for you and me
Alaskans love the land and sea
Our lives depend on Mother Earth
Her bounty gives us health and wealth
Come celebrate on 3-1-3
Alaska's natural resources for you and me 3-1-3

Discovery Day is March 13, 2012. March 13th is the day ARCO, and Humble Oil announced their Prudhoe Bay discovery in 1968.

Become a March 13th Alaskan

March 13th Alaskans know the significance of the Prudhoe Bay discovery, and what oil has meant to Alaska, and our state's economy. This year 2012, marks the 35 year anniversary of first oil through the Trans Alaska Pipeline.

Sunday, February 19, 2012

Governor Speaks on HB110

How to achieve a millions of oil per day production goal

Alaska Business Roundtable presents Alaska Department of Revenue Commissioner Bryan Butcher and Deputy Commissioner Bruce Tangeman discussing Alaska oil taxes and how to achieve Governor Parnell's million barrels of oil a day production goal.

Alaska Business Roundtable presents! from Bradley Fluetsch, CFA on Vimeo.

Deciding on best partner; New shale player Royale hopes to drill up to six North Slope wells next winter

Kay Cashman
Petroleum News

Grab a drilling rig while you can — or order one built — because the second new player to target oil in North Slope source rocks is planning to drill up to six evaluation wells next winter, two on each of its three lease blocks.

But before it puts together a drilling and testing program to evaluate oil production from source rocks in its Alaska leases, Royale Energy Inc. has to decide on the best partner for its northernmost venture. Fortunately, it says it has several to choose from.

The San Diego-based company first entered the state when it was high bidder on more than 100,000 acres in the state of Alaska’s Dec. 7 North Slope lease sale.

The acreage has some conventional oil potential in the Brookian and Beaufortian in Royale’s western block of leases, which could result in “cooperation with other North Slope explorers,” company executives told Petroleum News Feb. 8. (See the Mapmakers preliminary lease sale map with this story. Great Bear’s new leases are dark blue and its pre-existing leases are gray; Royale’s tracts are purple; Armstrong affiliate 70 & 148’s are light brown; ConocoPhillips’ bright red.)

But Royale’s focus is on what company Co-President and CEO Stephen Hosmer calls its “promising, hand-picked acreage for oil-rich shale.”

Royale, which was founded in 1986, has 23 full-time employees, and is recognized as one of the 20 fastest growing producers in the United States by Oil & Gas Journal. It has an “unconventional view,” Hosmer said, on the source locations and migration pathways of the oil that escaped northern Alaska’s source rocks, making its way into the region’s world class reservoirs that include the giant Prudhoe Bay field.

“Our view would surprise many geologists working the region,” he said.

Abdel-Rahman and Mukluk

The company’s unconventional concept is not based on idle speculation, but rather years of study and discussion led by Mohamed Abdel-Rahman, Royale’s vice president for exploration and production, who joined the company about five years ago, Hosmer said.
While employed by BP predecessor Sohio in Alaska, Abdel-Rahman headed up the post mortem on the famous 1983, $1 billion, Mukluk well in Harrison Bay. The most expensive dry hole in history, operator Sohio and its partners expected the well to encounter a massive oil pool, but all that remained of any oil that might once have existed in the Mukluk structure was extensive oil staining and residual asphalt-rich heavy oil.

Abdel-Rahman had been working for Shell in the Atlantic on offshore leasing before joining Sohio, and was ultimately named Alaska district geologist for the company.

“I went to work for Sohio in San Francisco in 1982. I started as area geologist for south Alaska. Then I became district geologist for the whole of Alaska. That’s when I was picked to head the Mukluk task force … to do a technical evaluation, in order to determine what really went wrong,” Abdel-Rahman said.

After Mukluk was drilled, “everybody in Sohio and in the industry was in a total shock. … I had not worked Mukluk as a prospect but moved into the position of statewide geologist as it was being drilled,” Abdel-Rahman said, so he didn’t have a personal stake in the task force’s conclusions.

Both a geologist and a chemist, Abdel-Rahman said he has always “used chemistry as much as I can. At the time it was not fashionable to talk about biomarkers — organic compounds that are characteristic of the organisms from which the oil is generated — but we did biomarkers work in Mukluk and compared it to all the other oils that had been discovered on the North Slope. We found an astounding match of the Mukluk oil and Kuparuk oil. … In my view there is no doubt that the Mukluk oil went to Kuparuk.” (See sidebar for more on the Mukluk post mortem.)

Optimum for oil generation

It was from the Mukluk drilling review that Abdel-Rahman developed his “concept, his unique viewpoint” about the locations of the source rock that “charged” Prudhoe Bay and other North Slope oil fields, Hosmer said.
The latest North Slope lease sale “presented us with an opportunity to secure a position along the heart of the oil window, of the source rock itself. We chose leases for their thermal maturity for oil,” Abdel-Rahman said.

Royale took 60 leases in three blocks: Two of the blocks adjoin Great Bear’s acreage to the east and southwest whereas the third block is further west along the Colville River.

Royale was bidding against Great Bear on some acreage and against Armstrong’s 70 & 148, in other areas.

“Everything we picked is optimum for oil generation — in all three shales,” Abdel-Rahman said, referring to the North Slope’s three stacked source rocks, from deepest to shallowest, the Triassic-age Shublik formation, the Jurassic-age Kingak shale and the Cretaceous-age Hue, or HRZ, shale, although Hosmer said Royale is most excited about the Shublik, which is very similar in composition to the Bakken shale.

Which company got the best acreage?

The assumption has been that Great Bear tied up the best acreage for shale that was liquids rich, but when asked about that, Abdel-Rahman was reluctant to discuss the difference between his model and acreage choices and that of Great Bear President Ed Duncan.
“I would rather talk about our acreage,” he said. “Let me put it this way: Had all the acreage been available and no acreage taken we would have picked up more acreage but we would have still chosen the acreage we did.”

First a technical partner

Before any well drilling occurs Royale has to decide on a partner.
“We’re hoping to move into technical design so that we can get into drilling phase next winter,” but for that the company will need a partner with technical expertise in designing wells in shale plays, Hosmer said.

“We have a lot of folks talking to us, a lot of opportunities to pick the right partner,” he said.

According to its website,, its Nasdaq trading symbol, Royale’s model in its Lower 48 operations is to sell a portion of the working interest in each newly acquired lease to third-party investors, retaining a portion of the prospect. The prospects are then bundled into multi-well investments.

“Our model is to partner up with folks; that probably won’t be any different here, but we’re looking for a somewhat different relationship — a technical and strategic partner rather than our traditional model of a group of investors, each with a small piece of the investment,” Hosmer said.

“We typically never like to give up operation but that’s open to discussion in Alaska, based on who that partner might be,” he said.

Royale is considering several potential partners, both oil companies and oilfield service firms, gauging “how comfortable we are with them, and whether their technical expertise lends itself to operating our Alaska leasehold or simply using their technical expertise” in an advisory capacity, Abdel-Rahman said.

So why Alaska?

So why Alaska, when there are proven shale plays in the Lower 48?
“Part of what led us to the choice was it coincided with out move back to the liquids, away from natural gas,” Hosmer said.

According to its website, Royale markets about 15 million cubic feet per day of natural gas from conventional gas wells in California’s Sacramento and San Joaquin basins. The company also has interests in Utah and Texas.

Abdel-Rahman said that a few years ago his company had production from the Monterey shale, a Californian play, before selling its interests to Occidental.

Hosmer and Abdel-Rahman want to get in on the ground floor for producing oil from Alaska shale.

“We had been contemplating it for many years, discussing Mohamed’s concept for the North Slope, and we have a West Coast orientation. We shy away from mid-continent exploration, so Alaska was a natural for us,” Hosmer said.

“We were caught by surprise when Great Bear Petroleum took that much acreage (500,000 acres in the October 2010 state North Slope lease sale). It forced us to move quickly,” Hosmer said.

Royale’s executives would have liked “more time to get rigs in place, internal infrastructure ready, but we had to move on it this year,” he said.

“We are very excited about our land position; it’s just a tremendous position. We are thrilled to be there,” Hosmer said.

The challenge, he said, echoing what Duncan has been saying since Great Bear entered Alaska, “is not in the geology, but in how to get the oil out. The geo-mechanical properties of the source rock needs to indicate high degree of brittleness. In particular the Young’s module and Poisson’s ratio need to be determined for these rocks, which are typically measured in the lab from rock plugs that are taken from cores. These will determine which zones from the vertical wells companies will chose to drill through horizontally and for multi-stage fracs. All these things have really not been done in Alaska to date.”

And they won’t be done, he said, until Great Bear “drills its first few wells, executes its proof of concept program,” starting this spring.

“The challenge is not whether there is oil, but whether or not the oil is going to be extractable economically.”

A lot, he said, will depend “on whether the state of Alaska is willing to work with us to make oil shale prospects viable.”

Many oil provinces have “prospects that have lower risk than Alaska, but much, much lower rewards. The potential reward in Alaska is huge. No other shale opportunity comes close to this, not only in the Lower 48 but in other parts of the world that we can access. This is a prime shale play,” Abdel-Rahman said.

Friday, February 17, 2012

Oil Patch Insider: Point Thomson EIS schedule firms up, Exxon issues RFPs

—Kay Cashman
Petroleum News

Over the course of the last two years the construction and production schedule for ExxonMobil’s Point Thomson development has slipped from August 2011 to the fall of 2012, bumping construction startup from the winter of 2011-12 to 2012-13, and delaying startup of the 10,000 barrel-a-day of condensate project from 2014 to late 2015 or early 2016.

The reason for the delay — the U.S. Corps of Engineers’ work on the project’s environmental impact statement — is no longer an issue.

In early February, Hank Baij, project manager for the Corps, said the record of decision is now “scheduled to be completed this fall,” all of which might have something to do with Exxon issuing requests for proposals for the construction of the Point Thomson project that propose construction of gravel fill pads for drilling and hydrocarbon production, an airstrip, infield roads, infield gathering pipelines, a processing facility, as well as a 22-mile, gas liquids export pipeline to Badami.

The Point Thomson project has appeared to be on hold; most people assumed it was waiting on a settlement or a final court decision, the second of which is likely years away.

But Point Thomson has been progressing in two different, albeit related, directions: commercially and legally.

On the commercial side, in January 2009 Exxon made a promise to the state, under oath at a Department of Natural Resources hearing in front of Tom Irwin, then DNR commissioner, to drill two wells at Point Thomson and bring them into production by 2014, an offer that included processing facilities and a pipeline to Badami, the closest connecting pipeline to take the condensate to Pump Station 1.

Irwin required “a drill contract for each well, unconditional authorizations for expenditure for each well signed by all parties, an AFE for the production infrastructure, and affidavits from each appellant (Exxon, BP, Chevron and ConocoPhillips) stating its willingness to pay its share of the costs for each well and for the production infrastructure.”

In exchange, Irwin conditionally reinstated two of the 31 core Point Thomson unit leases for Exxon and the other lessees (see 2009 map at

The penalty for not bringing the leases into production by 2014 was the loss of those two leases. Presumably, force majeure, a contract clause that excuses a party from liability if some unforeseen event beyond the control of that party prevents it from performing obligations under the agreement, will protect the lessees.

Exxon and its partners have invested upwards of $700 million since 2008 in those leases, although they will be reimbursed for about half of that because of development and related credits in the state’s production tax regime.

At a Feb. 12, 2009, DNR hearing, Irwin asked Craig Haymes, then Exxon’s Alaska production manager, whether Exxon would complete the two wells and produce from them if DNR didn’t award any other leases in the unit to Exxon and its partners.

Haymes said yes.

On May 13, 2009, after an industry luncheon in Anchorage, Haymes said all issues regarding Point Thomson would have to be settled with the state or it would hold up permitting and impact the beginning of production.

The first two wells were completed in 2010, as promised.

On the legal side, Exxon is the winner to date in Superior Court, having prevailed in overturning DNR’s termination of the Point Thomson unit, but it was a win predicated on two points that the state has successfully requested the Alaska Supreme Court to review (first hearing was Feb. 8).

Moving forward with the condensate project has been part of Exxon’s legal strategy as well, so it remains to be seen what will happen to that project if there is no settlement between the parties.

But for now, it looks as though Exxon is moving forward as promised.

Thursday, February 16, 2012

House approves opening ANWR — again

Alaska Journal of Commerce

For the 12th time, U.S. Rep. Don Young has gotten legislation passed out of the House of Representatives to authorize opening of a portion of the Arctic National Wildlife Refuge to resource development.

By a 237 to 187 vote, the House today sent H.R. 3408 to the Senate where it faces an uncertain future. Opening ANWR has only made it out of the Senate once, and was vetoed by President Bill Clinton in 1996.

“This is a great piece of legislation for the American people,” said Young in a statement released by his office. “Tapping into ANWR’s enormous energy potential could provide up to 1.5 million barrels a day for years to come. America is blessed with an abundance of natural resources and this bill will finally let us develop those resources for the good of our people.

“This is my 12th time passing ANWR out of the House and although this is a momentous day, there is still work to be done. The Senate should not drag its feet on this bill. The American people are sick and tired of high energy prices, high unemployment, and out of control deficits - they want cheap energy created here in America and that is exactly what this bill will do.”

Among the provisions in the bill noted by Young’s office.

• ANWR – The bill would open roughly 3 percent of ANWR to energy development and direct the Department of Interior to execute lease sales.

• Offshore Development – The bill would open portions of the Alaska, Pacific, Atlantic and Gulf of Mexico coasts to offshore drilling and require the Interior Department to execute lease sales. Additionally, this bill would provide coastal states with 37.5% of revenues generated from all new offshore development.

• Oil Shale – The bill would require oil shale leases to be issued by the Interior Department as well as promote shale technology research and development. The bill would make permanent the Resource Management Plan regulations published by the Interior Department in November 2008.

Alaska’s oil taxes too high, too complex, consultant tells legislators

Tim Bradner
Alaska Journal of Commerce

A consultant retained by Alaska’s Legislature has recommended the state rein in taxes on oil production to attract industry investment but also to dismantle a complex set of exploration and development incentives that gives away too much, with the state paying as much as 80 percent of the cost of new exploration wells, state lawmakers were told in hearings Thursday.

The Legislature is reviewing the state tax system with hopes of encouraging new investment to slow or reverse a decline in production from the North Slope.

Following several days of joint hearings by the Resources and Finance committees of the state Senate, Pedro van Meurs, a Calgary-based expert on international fiscal systems, suggested the state revise its taxes so the total state take including royalty is no more than 75 percent on existing production and 65 percent on new production.

To encourage heavy oil development the Legislature may have to lower total state take to 45 percent, van Meurs said.

The current tax system has the state taking over 80 percent at high oil prices, which van Meurs said is too high. There is also a disconnect in the incentives in the tax system, he said. The exploration and development tax credit system now in the law is generous in assisting companies in finding oil, but once discoveries are made the production tax burden becomes very high, and is a big disincentive.

“For the large companies who are now producers, there’s no attraction for development any new oil found, so why even explore? They have alternative investment opportunities around the world that are much more attractive,” van Meurs said.

On the other hand the tax credit system is attractive to smaller companies who can enjoy the lower up-front cost with the state picking up most of the expense of drilling.

Another criticism is that Alaska’s existing tax system is too complex, and discourages companies from considering Alaskan projects. Repsol, for example, told van Meurs it had sought assistance in deciphering the Alaska system from four major accounting firms as well as the state revenue department and was never able to get answers for certain questions, he told the legislators.

Repsol went ahead with its Alaska exploration anyway, which is currently under way, but a simplification would make the tax system more transparent, van Meurs said.

Van Meurs’ most substantial criticism, however, was on the way crude oil and natural gas are combined for tax purposes when they are produced together, such as would happen on the North Slope if and when commercial gas production begins.

If gas has a much lower value than oil, as it does today, the effect of a tax on the combined Barrel of Oil Equivalent, which the current tax imposes, would be to sharply reduce the revenues compared with what they would have been if imposed on the oil and gas separately.

“Once you start to produce gas as well as oil you’ll lose billions. If you do a large gas project you could wipe out your revenues. This is the most nonsensical system in the world,” van Meurs said. “Alaska cannot develop its gas resources as long as this is on the books.”

Van Meurs suggested that the state simplify its taxes by removing the progressivity formula that sharply escalates tax rates at higher oil prices, leaving a flat 25 percent tax on net profits which is the base tax rate in the current law.

He would do away with an array of exploration tax credit but leave a basic 20 percent credit on all industry capital investment. To capture more gains from oil price escalation, he would include a 2.2 percent severance tax on gross revenues.

Van Meurs said this basic structure could be adapted with special tax rates for new oil and heavy oil. Natural gas would have its own, separate tax, so that gas production would not dilute oil revenues as would be the case under the current law.

Monday, February 13, 2012

Going through motions; With settlement still pending, Alaska Supreme Court hears Point Thomson case

Wesley Loy
For Petroleum News

In front of a special audience of several hundred high school kids, the Alaska Supreme Court heard oral arguments Feb. 8 in the high-stakes Point Thomson case.

Justices left their regular courtroom to conduct the hearing in Anchorage’s West High auditorium. It’s part of a public outreach program known as Supreme Court Live.

With respect to the case, it was a significant event not so much for the arguments the opposing lawyers made, but the fact that the hearing was held at all.

The case pits the state Department of Natural Resources against ExxonMobil, operator of the Point Thomson field.

The two sides have for years have been tussling for control of the rich but undeveloped field, and the case was elevated to the state’s highest court after DNR in early 2010 appealed an unfavorable lower court ruling.

State officials in August said a “resolution in principle” had been reached with ExxonMobil to settle the Point Thomson conflict.

But the deal remains incomplete. And so the lawyers went to school on Feb. 8.

Origins of conflict
The case centers on DNR’s efforts to terminate the Point Thomson unit. The unit designation binds together leases within the field, located on the North Slope just west of the Arctic National Wildlife Refuge.

Leaseholders went to court to try to preserve the unit. Aside from ExxonMobil, major Point Thomson leaseholders include Chevron, BP and ConocoPhillips.

The state long has been frustrated Point Thomson has not been developed more than 30 years after its discovery on leased state acreage. The field is believed to contain some 8 trillion cubic feet of natural gas plus hundreds of millions of barrels of oil.

The leaseholders have cited Point Thomson’s technical challenges, along with the lack of a very expensive North Slope natural gas pipeline, as reasons the field hasn’t been developed.

Alaska Gov. Sean Parnell has complained that the reason the tentative settlement of the case hasn’t been finalized is because ExxonMobil’s partners in the field haven’t yet signed onto the deal.

DNR Commissioner Dan Sullivan told legislators in August the Point Thomson working interest owners were trying to work out “internal commercial terms between themselves.”

Points on appeal
In April 2008, the DNR commissioner at the time, Tom Irwin, terminated the Point Thomson unit.

A Superior Court judge in January 2010 reversed Irwin’s unit termination on two grounds.

First, she held that the Point Thomson stakeholders were wrongly denied a hearing under Section 21 of the Point Thomson unit agreement.

Second, the judge said DNR failed to accord the oil companies their constitutional right to due process in allowing state lawyers and DNR’s unit manager to both advise Irwin, in his role as an impartial decision maker, and fight the companies in court.

During the oral argument at West High, state Assistant Attorney General Richard Todd argued no due process violation occurred.

Most of the hearing centered on the Section 21 question.

Section 21 says the state has authority to adjust the “quantity and rate of production,” but only after the unit operator has the opportunity for a hearing to consider, among other things, whether any rate increase would violate “good and diligent oil and gas engineering and production practices.”

ExxonMobil and the other companies argue Section 21 is a vital contractual protection when faced with the prospect of losing an enormously valuable asset such as Point Thomson.

But Todd told the four Supreme Court justices — Craig Stowers, Dana Fabe, Daniel Winfree and Chief Justice Walter Carpeneti — that the Superior Court ruling incorrectly served to reverse the roles of DNR and the oil companies. Under that ruling, he said, it would fall to DNR to craft an acceptable plan of development for the unit — something the department is not as well-equipped to do as the major oil companies.

Todd further said the lower court ruling, if allowed to stand, had “statewide implications,” as other unit agreements in Alaska contain a Section 21 clause.

Section 21 actually was drawn from federal regulations adopted in the 1930s to avoid overdrilling and excess production, Todd told the justices. It’s a tool for government — one Alaska has never used — and not something for oil companies to invoke whenever DNR rejects an unacceptable plan of development, as it did with Point Thomson, he argued.

Questions and answers
Charles Lifland, an attorney speaking for ExxonMobil and the other Point Thomson leaseholders, told the justices Section 21 was “backstop protection” for the companies.

One justice asked him why the companies, with Section 21, would ever submit a plan of development that ever required them to do much of anything. Why not just let DNR propose a plan?

Lifland replied that the companies, under their leases, “have an obligation” to propose a plan of development.

After the oral argument — each side had about 30 minutes to talk — the high school students had a chance to pose questions to the lawyers and the justices. The students had been studying the complex case prior to the hearing.

Not surprisingly, the students asked some quite pointed questions.

One student asked: If the state wins the appeal and the oil companies get “kicked out” of Point Thomson, what then?

“It’s sort of premature to talk about the companies getting kicked out,” Todd replied. Either way the Supreme Court rules, he said, the case will be sent back to the Superior Court for further proceedings.

Todd went on to say that if the state did end up rebidding the Point Thomson acreage, lots of companies would want the property but probably the current leaseholders would get the land back, as they know the most about the field.

Another student asked Lifland what the plans are for Point Thomson if the Supreme Court favors his side.

Lifland said he couldn’t comment on that, but noted ExxonMobil is now working on a project to produce natural gas liquids from the field.