Alaska Energy Dudes and Divas

Pre-emptive action; Shell requests Greenpeace restraining order & judgment on Chukchi plan

2012-03-02T16:51:00.001-09:00

Alan Bailey
Petroleum News

Breaking News: As Petroleum News was headed to press on March 1, the federal District Court in Alaska issued a temporary restraining order, forbidding Greenpeace from breaking into or trespassing on the drilling vessels Noble Discover and Kulluk. The order will last for 14 days, until a court hearing on March 14, after which the court will decide on whether to issue an injunction against Greenpeace and what the scope of that injunction will be.

With several of Shell’s permits for drilling in Alaska’s Chukchi and Beaufort seas this summer slotting into place, the company has started taking some pre-emptive court action to head off last minute challenges by organizations opposed to Arctic offshore oil and gas exploration. Shell spokesman Curtis Smith has told Petroleum News that the company does plan to drill in the Alaska Arctic offshore this year unless prohibited from doing so by a federal agency or by court action.

Restraining order
On Feb. 24 the company asked the federal District Court in Alaska to issue a restraining order that would prohibit environmental organization Greenpeace from taking physical action against Shell’s vessels, facilities and properties in a U.S. port or within offshore areas under U.S. jurisdiction.

In February a group of Greenpeace activists, including actress Lucy Lawless, occupied the drillship Noble Discoverer in harbor in New Zealand, to try to prevent the drillship from leaving New Zealand for Alaska for Shell’s planned drilling program. Greenpeace and other environmental organizations say that drilling for oil in the Arctic offshore presents an unacceptably high risk to the Arctic offshore environment. Shell and U.S. federal regulators have said that Shell’s oil spill prevention measures and oil spill contingency arrangements are sufficient to prevent an Arctic offshore environmental disaster during drilling operations.

And Shell has already spent upwards of $4 billion on its Alaska Arctic offshore exploration venture, including the purchase of leases in federal lease sales in the Beaufort and Chukchi Seas.

“Greenpeace has embarked on an international campaign against Shell and Shell’s U.S. OCS assets,” wrote attorney Jeffrey Leppo in Shell’s request to the District Court. “Greenpeace intends to disrupt, delay and if possible prevent Shell from conducting exploration drilling in the Arctic Ocean OCS in 2102 by committing on-the-water or nearshore acts of trespass and nuisance.”

District Court Judge Sharon Gleeson issued a summons to Greenpeace, requiring a response to Shell’s complaint. And on Feb. 29 the judge held a hearing in the case.

Spill response plan
Also on Feb. 29 Shell took the unusual move of filing an action against 13 environmental organizations, asking the court to declare that the Bureau of Safety and Environmental Enforcement, or BSEE, had properly approved Shell oil spill response plan for the Chukchi Sea.

“This pre-emptive action is an attempt to avoid challenges on the eve of summer drilling operations by organizations that have historically used last-minute legal maneuvers to delay properly approved operations,” Smith told Petroleum News in a Feb. 29 email.

BSEE approved Shell’s response plan on Feb. 17.

In its request to the court Shell says that a legal challenge by environmental organizations against its spill response plan “is virtually a certainty.”

“It is the consistent practice of these defendants to bring their judicial challenges, using the potential for litigation-related delay as a tactic in their publicly-stated attempt to block all oil and gas exploration on the Alaska OCS,” wrote attorney Kyle Parker in Shell’s court filing.

The filing lists statements by various environmental organizations claiming that Shell’s response plan is inadequate and implying the threat of legal action against the BSEE plan approval. The organizations have a “consistent practice of waiting to the last possible date before filing their judicial challenges,” the filing said.

Shell has asked the court for a “declaratory judgment” that the approval of the Chukchi Sea response plan by BSEE was not “arbitrary, capricious, an abuse of discretion, or otherwise in violation of the law.” In general, when an agency decision is appealed to the courts, a court will defer to agency expertise in the technical basis for the decision but will rule on whether the decision was made in a legally defensible manner, following required legal protocols and meeting the requirements of applicable statutes.

BP finishes first test production well drilled to Sag River

2012-03-02T08:49:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

BP has completed the first of five pilot wells drilled to test production from the Sag River formation that overlies the main producing reservoir of the Prudhoe Bay field, company officials told state legislators Feb. 23.

The test wells involve long, extended horizontal production wells, drilled from the surface at an angle and then turned horizontally to intercept the thin production layer of rocks.

The first well was drilled with a 6,700-foot horizontal production section through a thin layer of oil-bearing reservoir about 20 feet thick, Damian Bilbao, BP’s Alaska resources and development director told the Senate Resources Committee.

If the wells are as productive as hoped, BP could develop 200 or more production wells in the Sag River over a 10-year period, adding 150 million to 220 million barrels of new reserves to the Prudhoe Bay field, Bilbao said. The investment required would be $270 million to $610 million.

BP is also considering testing the Sag River formation in the nearby Milne Point field, which could add 10 million to 50 million barrels of oil.

In other developments, Claire Fitzpatrick, BP’s chief financial officer, said the company is continuing work on a pilot heavy oil production project at the Milne Point field. However, even if technical problems are worked out and BP is able to produce oil from the large Ugnu oil deposit, economically it would be at least 10 years before any significant amount of oil, such as in the range of 10,000 barrels per day, is produced, Fitzpatrick told the senators.

BP’s first heavy oil production test at Milne Point was encouraging, with a horizontal well producing about 650 barrels per day over a 100-day period, state Oil and Gas Director Bill Barron said in a presentation to the committee earlier in the day. Barron said BP is now searching for a specialized rig to drill more of the heavy oil test wells. These would employ the CHOPS technology (Cold Heavy Oil Production with Sand) that is used in Alberta and that BP will adapt to the North Slope.

The first heavy oil test well was drilled using a more conventional horizontal production well in the Ugnu, and it worked better than BP expected. This well is now off production so that BP can modify pumps used in the process. Ugnu heavy oil has a quality that ranges from 10 to 15 degrees API and is technically challenging. In comparison, conventional crude oil in the Prudhoe Bay field has an API gravity of 29 degrees API.

However, there is a large resource, an estimated 23 billion barrels of oil, in the deposit, which is shallow and overlays the deeper, conventional fields in Prudhoe Bay, Milne Point and Kuparuk River.

While only a part of the resource will ever be produced, even a 10 percent to 15 percent recovery would be a large amount of oil. One other challenge with heavy oil is that it cannot flow by itself through the Trans Alaska Pipeline System. It must be mixed with conventional light crude oil so that the combined liquids will flow.

On other matters, Fitzpatrick said a record number of Prudhoe Bay production facility “turnarounds,” or major maintenance projects this summer. This will mean a drop of production and oil moving through the Trans-Alaska Pipeline System this summer.

Fitzpatrick said BP will also expand, and in fact will double the application of a proprietary Enhanced Oil Recovery technology the company has developed. The Bright Star EOR process involves injection of polymers to improve the effectiveness of oil recovery in waterflood.

Another proprietary EOR process, called Low-Sal also will be tested at Prudhoe Bay this year by BP. Low-Sal involves the use of low-salinity or even fresh water in a waterflood instead of the briny formation water or even seawater currently used.

Low-Sal has been tested by BP at the nearby Endicott field in past years and has been found to be effective in improving oil recovery.

Fitzpatrick said BP also plans a large summer offshore seismic program in the Simpson Lagoon area north of the Milne Point field. Substantial sections of the Milne Point field extend out under the ocean and are produced with extended-reach production wells drilled from shore. The seismic will identify opportunities for fill-in drilling, she said.

Other plans at Milne Point, which will depend on results of the summer seismic program, include additional in-fill drilling and pad expansions that could add 25 million to 35 million barrels of reserves.

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

Repsol still works to thaw frozen drill rig at blowout site

2012-03-01T17:36:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

Repsol E&P USA was still working last week to thaw and clean a frozen drill rig at the site of its Qugruk No. 2 exploration well on Alaska’s North Slope, state officials said. The rig was evacuated the morning of Feb. 15, when drillers encountered a shallow gas pocket at the 2,523-foot depth, causing a gas blowout and spill of drilling fluids.

There were no injuries or fire resulting from the blowout. Gas stopped flowing the evening of Feb. 16.

The well cannot be considered under control until the rig is brought back into operation, said Cathy Foerster, a Commissioner on the Alaska Oil and Gas Conservation Commission.

“It’s going to be later this week, at least, until they can start work to reestablish mud circulation in the well. If they are able to do that the well will be under control and they can proceed to inspections of the drill pipe and the condition of the hole,” Foerster said Feb. 24.

The AOGCC is the state agency responsible for drilling safety. Nabors Alaska Drilling Co. is the owner and operator of the rig.

In a situation report issued Feb. 27, the state Department of Environmental Conservation said technicians at the site were to inspect the “cold start generator” on Feb. 27.

“The cold start generator will be the first generator to be started and supplies the power needed for the restart of the rig,” the DEC said in the situation report. “The restart of the rig is one of a series of steps in the progression needed for completion of the well-kill operation. However, due to the need for a very methodical and careful cleaning and drying of the rig’s power components, the time of the restart cannot be determined at this time.”

Foerster said the drillers will check to see if the well and pipe can be salvaged or if a new well will have to be started. If drilling resumes, officials will inspect for possible gravel wash-out around the wellbore and the possible formation of an ice or debris plug.

“If there is a debris or ice plug, they will have to be very cautious because there might be gas below it,” she said.

Meanwhile, Repsol reported to DEC that its contractors have removed 1,260 barrels of liquids, mostly snow contaminated with drilling fluid, from the site, the agency said in the Feb. 27 report. The drill fluid was water-based rather than diesel-based, which will lessen its environmental impact. The drill fluids were ejected from the well by the gas when the well blew out.

Qugruk No. 2 is approximately 150 miles southwest of Barrow, on state-owned lands in the Colville River delta. The nearest community is the Inupiaq Eskimo village of Nuiqsuit 18 miles south of the well location.

The well is one of five exploration wells Repsol is hoping to drill this winter to assess acreage acquired last year in a deal with Armstrong Oil and Gas Co., a Denver-based independent. Several of the leases have near-term expiration dates, state Division of Oil and Gas director Bill Barron said, which is why Repsol has mounted an aggressive exploration program this winter.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-March-4-2012/Repsol-still-works-to-thaw-frozen-drill-rig-at-blowout-site/#ixzz1nvHjYu1I

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

2012-02-27T14:47:00.007-09:00

ASD MEMORANDUM #199 (2011-2012)

February 27, 2012

TO: SCHOOL BOARD

FROM: OFFICE OF THE SUPERINTENDENT

SUBJECT: RECOGNITION OF ERMALEE HICKEL AND CINDY ROBERTS FOR BOOK DONATION

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.

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

2012-02-26T11:57:00.004-09:00

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
3-1-3
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 http://pinterest.com/dbrollini/march-13th-alaskans/

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.

Governor Speaks on HB110

2012-02-19T21:03:00.001-09:00

How to achieve a millions of oil per day production goal

2012-02-19T11:23:00.001-09:00

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

2012-02-19T10:49:00.001-09:00

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, royl.com, 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.

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

2012-02-17T17:21:00.003-09:00

—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 http://bit.ly/xHwfhW).

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.

House approves opening ANWR — again

2012-02-16T17:07:00.000-09:00

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

2012-02-16T15:36:00.002-09:00

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.

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

2012-02-13T02:44:00.001-09:00

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.

SB 167 Oil and Gas Decoupling Senate Finance Committee Hearing - 01/27/12

2012-01-29T03:16:00.009-09:00

Overview: oil and gas decoupling (47 minutes)
Presenters: Brian Butcher, and Bruce Tangerman
Department of Revenue Slides
SB 167: Legislative Documents

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CPAI earns $1.9B in 2011; A 34 percent jump in oil prices helped offset a 6.5 percent decline in production

2012-01-28T11:02:00.001-09:00

Eric Lidji
For Petroleum News

A steep rise in oil prices last year helped ConocoPhillips earn nearly $2 billion in Alaska, an increase over 2010 earning despite falling oil and natural gas production in the state.

ConocoPhillips earned $1.9 billion in Alaska last year, up from $1.7 billion in 2010.

While ConocoPhillips’ annual earnings in Alaska rose, its quarterly earnings fell.

The company earned $443 million in the fourth quarter, down 11 percent from the third quarter ($501 million) and 7 percent from the fourth quarter of 2010 ($476 million).

ConocoPhillips earned $1.2 billion from its Lower 48 E&P operations in 2011, up from around $1 billion in 2010, while maintain roughly level production throughout the year.

Companywide, the company earned $12.4 billion in 2011, up from $11.3 billion in 2010.

Rising Lower 48 oil

While ConocoPhillips continues to earn more from its upstream operations in Alaska than from its upstream operations in the Lower 48, that balance could start to shift this year.

The company plans to ramp up its activities in the oil-rich Eagle Ford and Bakken Shales this year to take advantage of high oil prices and, conversely, shut-in around 100 million cubic feet of North American natural gas production due to chronically depressed prices.

In Alaska, ConocoPhillips produced 215,000 barrels of oil and natural gas liquids per day in 2011, a 6.5 percent decline from the 230,000 bpd of liquids the company produced in 2010. ConocoPhillips produced 61 million cubic feet of natural gas per day in the state last year, down roughly 25 percent from the 82 mmcf per day the company produced in 2010.

In the Lower 48, ConocoPhillips produced 168,000 bpd of liquids in 2011, up slightly from 160,000 bpd in 2010, and 1.5 billion cubic feet of gas per day, down from 1.7 bcf in 2010.

Significantly higher oil prices in Alaska continue to offset gradual production declines for ConocoPhillips. The company realized an average oil price of $105.95 per barrel for Alaska last year, up from $78.61 in 2010. By comparison, the company realized an average price of $74.09 per barrel for Lower 48 liquids in 2011, up from $57.69 in 2010.

While oil jumped, natural gas prices remained relatively flat year-over-year for ConocoPhillips, from $4.62 per thousand cubic feet in 2010 to $4.56 per mcf in 2010. By comparison, Lower 48 gas prices fell from $4.25 per mcf in 2011 to $3.99 per mcf in 2010.

Liquefied natural gas sales declined considerably in 2011, as ConocoPhillips began the process of closing its nearly 45-year-old facility on the Kenai Peninsula. The company sold 26 mmcf per day in 2011, down nearly 45 percent from 47 mmcf per day in 2010.

While mentioning recent discussions about a proposal to market North Slope natural gas as LNG, ConocoPhillips’ executives made no noteworthy comments about the project.

Tax debate continues

ConocoPhillips has released its year-end earnings as Alaska lawmakers are once again considering changes in the state’s production tax code.

In his recent state-of-the-state address, Gov. Sean Parnell tied tax reform to his goal of increasing throughput in the trans-Alaska oil pipeline to 1 million barrels per day over the coming decade. Because it is the only major oil producer to break out financial figures for Alaska on a quarterly basis, something BP only does annually and Exxon does not do at all, ConocoPhillips’ earnings often become a wedge in those debates, something Parnell seemed to anticipate by asking, “Do we have enough will to give up short-term gains for long-term growth?”

With tax reform, the industry is willing to invest $5 billion in legacy fields, Parnell said.

Rep. Les Gara, an Anchorage Democrat, is promoting an alternative bill designed to create incentives for companies to explore and develop new fields in the state.

ConocoPhillips doesn’t release its complete annual report until late February. The filing typically includes Alaska-specific taxation, spending and budgetary information.

Moving gas in-state; House plan combines existing bills, wraps ANGDA into AGDC with same board

2012-01-27T19:39:00.002-09:00

Kristen Nelson
Petroleum News

Last year the Alaska House picked away at issues surrounding an in-state gas pipeline, moving three bills to the Senate.

In July, the Alaska Gasline Development Corp. delivered its feasibility report to the Legislature, complete with a list of recommended legislative changes.

House Speaker Mike Chenault, R-Kenai, and Rep. Mike Hawker, R-Anchorage, introduced legislation Jan. 24 combining the existing bills with recommendations from AGDC and additional tools, all of which Chenault described as designed to advance a natural gas pipeline project and bring natural gas to Alaskans.

AGDC has been working on a plan for an in-state gas pipeline since the Legislature passed House Bill 369 in the spring of 2010. HB 369 called for the development of an in-state natural gas pipeline plan, with a proposal to have gas moving through a line by 2015 to be delivered to the Legislature in July 2011.

AGDC delivered the initial plan, but told legislators that it would take until 2018 for first gas.

The new legislation, a committee substitute for HB 9, would keep the momentum going for development of gas for Alaska, “while keeping open all the options for participating in an aligned project,” Chenault said, referring to the governor’s proposal that a large line under AGIA, the Alaska Gasline Inducement Act, could morph into a liquefied natural gas project and combine with an in-state project.

Hawker said he believes we are “on the verge” of seeing a pipeline constructed “that actually will bring Alaska’s gas to Alaskans,” and said the proposed legislation would empower AGDC to carry through to the point where “we can bring a project back before the Legislature and debate the sanctioning” of a project.

He said the bill brings state agencies, including the Alaska Natural Gas Development Authority, “together into a common mission with a common management.” The bill eliminates the present ANGDA board and moves ANGDA under the Alaska Housing Finance Corp. board of directors, which would also replace the Joint In-State Gasline Development Team, which has been the board for AGDC.

Dan Fauske, president of AGDC and CEO of Alaska Housing Finance Corp., said the legislation would give AGDC additional tools. ANGDA’s role in the development, he said, would be in gas marketing and gas purchasing.

Fauske said AGDC is currently in the process of working on a draft environmental impact statement, with public hearings scheduled, and said the EIS is expected to be completed in May. An open season is planned for 2013.

Committee substitute

The proposed legislation is a committee substitute for House Bill 9, introduced last year and includes HB 203, which establishes a fund to receive $200 million appropriated in 2011 for work toward an open season and directs fund management and investment; HB 215, which limits challenges to right-of-way leasing decisions similar to protections extended to the trans-Alaska oil pipeline; and HB 189, which allows AGDC to enter into confidentiality agreements. All three of these bills were passed by the House last year and are in the Senate.

In addition, HB 9 gives AGDC the ability to determine pipeline ownership and operating structure, to exercise eminent domain, to issue bonds and to manage pipeline and related project assets. The bill also removes language limiting an in-state line’s scope to linking North Slope to tidewater, allowing flexibility if there are major finds elsewhere in the state.

The bill recognizes AGDC as an Alaska Housing Finance Corp. subsidiary by replacing the Joint In-State Gasline Development Team with AHFC’s board of directors, and brings the Alaska Natural Gas Development Authority under common management with AGDC. It also protects the state and AHFC from liability related to AGDC and directs state agencies to support AGDC’s efforts by providing permits and state resources such as water, sand and gravel, at no cost.

It amends regulatory requirements for a state-sanctioned project by allowing AGDC to operate a pipeline as a contract carrier and provides AGDC the option for Regulatory Commission of Alaska oversight.

And the bill would exempt an in-state gas pipeline from state and local taxes during construction.

ANGDA changes

The sectional analysis for the committee substitute for HB 9 says certain statutory provisions relating to ANGDA pertaining to the construction of a natural gas pipeline are deleted.

“The overall effect of the amendment in this and later bill sections would be to clarify that ANGDA may operate as a shipper of gas but not as a pipeline owner or developer. This clarifies the respective responsibilities of AGDC and ANGDA and conforms to general requirements of FERC and other potential pipeline regulatory agencies,” the analysis said.

Other provisions of the bill would allow ANGDA to focus on marketing, and give ANGDA the ability to pledge royalty gas owned by the state as long as that gas is not already committed by contract.

Alignment possible

In discussing the proposed legislation, Hawker said that one of the things it does is to broaden the authority of AGDC so that the project could have alignment with a large line going through the state to a tidewater port.

Fauske said the AGDC team is “in constant communication” with the AGIA (Alaska Gasline Inducement Act) project — the Alaska Pipeline Project — and with Kurt Gibson (director of the Alaska Gas Pipeline Project Office, the state agency which is working on the AGIA project) and his staff and with TransCanada.

AGIA is the project being pursued by TransCanada and ExxonMobil to take North Slope natural gas to North American markets in a large line, some 4.5 billion cubic feet a day. The project has held an open season but so far no shippers have committed to shipping on the line, and Gov. Sean Parnell asked the project proponents late last year to look at shipping Alaska North Slope natural gas to Asian markets as liquefied natural gas, a reflection of high prices in Asian markets and the fact that the Lower 48 currently seems more than adequately supplied with natural gas from new shale developments.

Fauske said there is a “community spirit” in progressing the project and noted that if AGIA goes forward, then the work AGDC is doing “is worthwhile in that it becomes the spur line coming off the big line.”

Hawker said provisions in the bill enable AGDC to be a partner or an investment equity holder in other projects, and also allow it to take capacity in other projects, so “this legislation expands the powers and authority of AGDC to be an active participant in other lines.”

Asked about this project in relation to AGIA, Chenault said the legislation “is not about picking a winner: This is about getting gas to Alaskans.”

HB 369 was structured to be within the limits established in the AGIA which prohibits the state from investing in a competing project which would deliver more than 500 million cubic feet a day of natural gas, he said.

Norway Lessons Learned - Legislative Lunch and Learn

2012-01-27T18:37:00.002-09:00

Senate’s oil tax bill ready in less than two weeks, Senate President says

2012-01-27T16:42:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

JUNEAU — Senate President Gary Stevens, R-Kodiak, says the Senate’s version of an oil tax reform bill is being drafted and will be before the Senate Resources Committee within two weeks.

Stevens spoke in a briefing by Senate leaders held in Juneau Thursday.

The oil tax change is considered one of the key issues to be resolved by the Legislature in its 2012 session. “It’s the elephant in the room,” Stevens said.

Gov. Sean Parnell said the state needs to adjust taxes to encourage more oil industry investment on the North Slope, where production is now declining.

After the Resources Committee finishes its work the bill will go to the Senate Finance Committee, then to the floor of the Senate and the state House, which passed its own version of oil tax changes last year.

That bill, House Bill 110, had been introduced by the governor, and is now in the Senate Labor and Commerce Committee. Stevens said the pending new Senate bill will be the “vehicle” for resolving the issue rather than the House bill.

“Our goal is to get it to the House with 30 days left in the session, the give House members time to review the proposal,” Stevens said.

That timetable would have the bill to the House by mid-March. Stevens said some conversations have been held already with House Speaker Mike Chenault.

Senators in the Thursday briefing, which included co-chairs of the Senate Resources and Finance committees, would not comment on contents of the bill being prepared but said it would deal with problems in the “progressivity” formula in the current tax law as well as investment tax credits and tax audit procedures.

The progressivity formula is the source of many problems, oil producers have said, because it sharply ratchets up the state tax rate when oil prices climb. At current oil prices, the tax rate is among the highest in the world. Given the high costs of developing new oil on the Slope and the expected modest-sized discoveries, Alaska is now having trouble being competitive in attracting investment, the companies have said previously.

Stevens said there was agreement in the Senate majority that action is needed to get more oil into the Trans-Alaska Pipeline System, which is moving smaller amounts of oil with the decline of production in the North Slope oil fields.

However, the approach being developed in the Senate is “far apart” from the approach taken by the governor and the House in HB 110, Stevens said. Stedman said the two versions of the tax change would be closer than many expect because there is agreement on the problem areas in the tax.

“People agree on the choke points. What we have to agree on is the policy changes needed to fix them,” Stedman said in the briefing.

Stedman said one focus of the Senate bill will be on the split of production profits at different crude oil price ranges between the state and the producing companies.

Sen. Joe Paskvan, D-Fairbanks, co-chair of the Resources Committee, said legislators now have far more information about the need for a tax change than was available a year ago, when HB 110 passed the House.

“I now have 100 pages of answers to my questions from the Department of Revenue and 25 pages of answers from the Department of Natural Resources,” Paskvan said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-29-2012/Senates-oil-tax-bill-ready-in-less-than-two-weeks-Senate-President-says/#ixzz1kiGv2F7M

Norway Lessons Learned Testimony to House Committee on Economic Development, Trade and Tourism (19:00)

2012-01-26T20:04:00.008-09:00

Fairweather builds Deadhorse Aviation Center

2012-01-19T21:10:00.002-09:00

Jonathan Grass
http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-22-2012/Fairweather-builds-Deadhorse-Aviation-Center/#ixzz1jya9oo7c

An architectural rendering shows the exterior of the new Deadhorse Aviation Center that will be the area’s largest facility. It is scheduled to open this summer.
Courtesy of Fairweather, LLC

A dormant North Slope project has been reborn as a way to support oil and exploration companies faced with the area’s currently scant facilities. The Deadhorse Aviation Center is designed to be the area’s largest and most modern piece of infrastructure, and is expected to open this summer.

The 70,000-square-foot facility includes a 21,000-square-foot hangar joining two floors of various accommodations plus a mezzanine. The facility — owned by Fairweather, LLC, Offshore Support Services, LLC (an Edison Chouest company) and Kaktovik Inupiat Corp. — is to provide support and safety to both large oil companies and smaller operations that use this area of the North Slope.

The multi-modal facility is located on the north end of runway 5 of Deadhorse’s airport, one of the North Slope’s busiest.

“This will be, if not the, one of the newest pieces of infrastructure available for the industry in Deadhorse,” said Fairweather Manager Sherron Perry.

DAC will house a cargo and passenger terminal, offices, conference rooms, a medical facility and clinic, ambulance and medevac facilities, bedroom accommodations for 48 people, kitchen capacity for 60 people and secure areas for hazardous materials. There is also an adjacent 10.5-acre gravel yard for outside storage. High-speed Internet will be available there as well.

Fairweather’s medical personnel will operate the clinic. This will be Deadhorse’s largest medical facility, as well as the only privately owned one on the North Slope.

Fairweather Director of Business Development Lori Davey said companies that utilize this service will likely use the center’s other services as well.

Another feature that will be new to companies outside big oil will be the incident command center.

“This will provide smaller companies that don’t have a lot of infrastructure up there to be able to come into the secure environment and manage a spill or a leak or some other problematic issue that they need to set up an instant command structure to manage,” Perry said.

The hangar accommodates offshore helicopter capacity and fixed wing activities.

The design also calls for Deadhorse’s first heated jet ways. These won’t be constructed unless a contract is reached with an air carrier, however.

The project manager is Neil McCleary, who helped design the facility with Marvin Ungerecht of Architects Alaska. McCleary works for Fairweather.

The hangar is finished with the exception of the fire suppression system. Building is under way for the rest of the facility. Contracting work is being done through Ukpeaġvik Iñupiat Corp.’s construction services out of Barrow.

Perry said the total costs will be $35 million once the facility is completely finished.

The facility actually went into construction in 2006, when it was to be used to support Shell’s offshore operations. Construction was suspended shortly after Shell was unable to move offshore and had to abandon its leases in the summer of 2007.

“We believe the market is growing now and it’s time for us to lead this project,” Perry said. He said he believes offshore development will proceed this summer and has seen an increase wintertime exploration.

The center is using its original design as a shore base to support offshore drilling and exploration activities.

“A number of companies have seasonal work in the area,” he said. This includes government research projects such as those by the U.S. Forest Service, Bureau of Land Management and National Oceanic and Atmospheric Administration.

DAC will be ready for occupancy in June 2012. The next step is to sign leasers. None are signed yet. Fairweather is talking with several prospects, including all the big oil companies and gasline companies with aviation components. Perry said there are discussions with aviation companies, Alyeska Pipeline Service Co., the U.S. Coast Guard, the Air Force and other government and private agencies.

The state Department of Transportation has identified a number of issues in current Deadhorse aviation facilities, including inadequate lighting, limited expansion possibilities and the need for runway surface rehabilitation. The survey also indicated current insufficient sizes for a flight service station, rescue and fire fighting, and now removal equipment.

The new DAC is intended to address several of these. It also accommodates Transportation Security Administration screening compliance, something that current Deadhorse facilities are too small to do. This design is based on TSA recommendations.

Fairweather has multiple specialty divisions, such as environmental science and medical subsets, which played a big role in the diversifying the new resources. Davey said an example of such advantages is that leasers will be able to get weather and ice reports from the building, something that is important to offshore drilling. She said Fairweather’s logistics support is also important to oil companies that may not know everything involved with drilling in the North Slope.

“It’s been important for gaining the support of all the different entities combined because we’re considered a third-party, non-biased entity doing the science,” Davey said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-22-2012/Fairweather-builds-Deadhorse-Aviation-Center/#ixzz1jya9oo7c

Buccaneer Energy starts production at new Kenai natural gas well

2012-01-19T20:54:00.000-09:00

By Tim Bradner
Alaska Journal of Commerce

Bucaneer Energy has started natural gas production at its Kenai Loop No. 1 well near Kenai, the company announced in a written release Monday. Production began Jan. 14.

The well will be produced at a rate of 5 million cubic feet per day for the next two to three months while performance of the reservoir is evaluated, company spokesman Dean Gallegos said.

Buccaneer, an Australia-based independent company, will sell its gas into the daily gas auction conducted by Enstar Natural Gas Co. and will also have the ability to sell gas to ConocoPhillips Alaska Inc. for that company’s gas liquefaction plant in Nikiski under a contract with ConocoPhillips, according to the press release.

Enstar’s daily gas auction “is a system where gas producers are advised of Enstar’s additional requirements for the next 24 hours and the producers bid the price and volume to sell gas to meet those requirements,” the press release said.

Buccaneer plans additional drilling in its Kenai Loop field beginning in the second quarter of 2012, the company said. The Kenai Loop No. 1 well was completed as a successful gas discovery in early 2011 but a second well drilled nearby was unsuccessful. Buccaneer planned additional seismic work this winter to better map the potential reservoir.

The additional drilling is planned to confirm other reserves.

Meanwhile, Buccaneer will be drilling offshore wells in Cook Inlet this summer with a new jack-up rig being brought to the Inlet by an affiliated company, Kenai Offshore Ventures. The company’s offshore prospects have potential for oil as well as natural gas.

There is already one jack-up rig in the Inlet brought north in 2011 by Escopeta Oil Co., a Houston-based independent. Escopeta partly drilled its first Inlet exploration well in late 2011 and discovered gas. Drilling was curtailed for the season with the onset of winter, and will resume next spring.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-15-2012/Buccaneer-Energy-starts-production-at-new-Kenai-natural-gas-well/#ixzz1jyVz9jMR

State of the State: Parnell lays out 2012 benchmarks for LNG deal

2012-01-19T20:38:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

Alaska’s Republican Gov. Sean Parnell gives his annual State of the State address Jan. 18 to the Alaska State Legislature in Juneau. In the background is Senate President Gary Stevens, R-Kodiak, left, and House Speaker Mike Chenault, R-Nikiski.

Alaska’s Republican Gov. Sean Parnell gives his annual State of the State address Jan. 18 to the Alaska State Legislature in Juneau. In the background is Senate President Gary Stevens, R-Kodiak, left, and House Speaker Mike Chenault, R-Nikiski.

AP Photo/Chris Miller

In his annual State of the State address, Alaska Gov. Sean Parnell laid out benchmarks he hopes North Slope producers will reach in 2012 on a possible deal to build a natural gas pipeline and liquefied natural gas project.

Parnell spoke to a combined audience of the state House and Senate in the state capitol in Juneau Wednesday night.

If the companies meet the benchmarks, Parnell committed to introduce a needed agreement on natural gas production taxes to the 2013 state legislative session. The companies say a deal on fiscal terms including taxes and royalties are needed before a major gas project can be pursued.

Parnell had met with the CEOs of the three major slope producers in Anchorage Jan. 5 and urged them to work together on a large LNG project in lieu of an all-land pipeline now being pursued by TransCanada Corp. and ExxonMobil Corp.

BP's Robert Dudley, ConocoPhillips' James Mulva and ExxonMobil's Rex Tillerson met with Parnell.

In his speech to legislators Parnell said he hoped to see the three companies come together in an agreement to pursue an LNG project by March 31, on a plan to integrate work the state has done with a 24-inch in-state pipeline from the Slope, and by Sept. 30 a schedule for a new, large gas project.

An LNG project, aimed to serve export markets, would involve a large-diameter pipeline from the Slope to a southern Alaska port, either Valdez, the present terminus of the Trans-Alaska oil pipeline, or the Kenai Peninsula, near Anchorage, where ConocoPhillips now operates a small LNG plant supplied by Cook Inlet gas fields.

Parnell said he is also pushing for quick resolution to a lawsuit over state leases at Point Thomson, east of Prudhoe Bay on the slope, which all parties agree must be resolved before a major gas deal can move forward.

Point Thomson holds an estimated 8 trillion cubic feet of gas, a sizeable portion of the 35 tcf of gas reserves identified on the Slope that would support a gas pipeline.

“In the last 24 hours I spoke with the CEOs of all three producing companies to ask if there has been progress on reaching agreement on Point Thomson, and I was told there was not,” Parnell told legislators in his speech.

If agreement does not come in the next two weeks Parnell said the state would “vigorously” argue the state's position in the dispute in a hearing planned Feb. 8 by the Alaska Supreme Court.

The case involves a claim by the state that Point Thomson lease-owners, which include ExxonMobil, BP, Chevron and CononoPhillips, did not abide by work commitments. Based on the claim the state moved in 2007 to terminate the Point Thomson Unit.

The lease-owners sued and the case has been winding its way through the state courts since, and is now before the state's high court.

The state has negotiated a possible settlement with ExxonMobil, the operator of the unit, but BP, Chevron and ConocoPhillis, the other major leaseowners, have not agreed to the deal.

Alaska Senate President Gary Stevens says many of Parnell's priorities fit with those of his bipartisan coalition.

Stevens says Parnell is right that this will be an important legislative session, particularly as it pertains to oil and gas and trying to find meaningful solutions to spur production. But he says there are problems with Parnell's oil tax-cut plan and says he'd like the Senate to craft its own tax bill.

House Minority Leader Beth Kerttula says her Democratic caucus wants to ensure Alaska gets its fair share from a tax regime and will stand against giving away the state's resources.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-22-2012/State-of-the-State-Parnell-lays-out-2012-benchmarks-for-LNG-deal/#ixzz1jyRX8uu9

A TAPS bottom line; Operation economics as much as technology will determine pipeline future

2012-01-13T15:32:00.003-09:00

Alan Bailey
Petroleum News

The question of how low the flow rate of oil through the trans-Alaska pipeline can go before the pipeline becomes inoperative seems a bit like the proverbial question about how long is a piece of string: it all depends on how long you want it to be. And in the case of the pipeline commonly referred to as TAPS it seems that the ultimate answer depends on how much money can viably be spent making pipeline modifications to keep ever smaller volumes of oil trickling south from pump station one on Alaska’s North Slope.

As illustrated by the recently concluded court case over the tax valuation of TAPS, the question of how little oil the pipeline can carry matters a great deal. The lower the volume of oil that can flow down the line, and the longer the life of the line, the more pipeline is worth and the greater the property tax bill for the pipeline owners. At the same time, extending the pipeline life increases the amount of oil that can potentially be recovered from North Slope oil fields, thus enabling oil producers to beef up their “booked” oil reserves, hence increasing the values of their companies and raising their appeal to potential investors.

But just what are the facts regarding the issues surrounding the slowing flow of oil through TAPS?

Falling throughput

Few people, if any, dispute the nature of the essential problem: Pipeline throughput is steadily dropping and the 48-inch diameter pipeline was designed to move much more oil than it carries at present. At its peak the line shipped about 2 million barrels of oil per day, while at present that daily throughput has dropped to just over 600,000 barrels.

To enable pumps to push oil over the ups and downs of a pipeline route that includes a couple of mountain ranges, it is necessary to keep the entire line filled with oil. To keep the line full as pipeline throughputs drop, the rate at which the oil flows down the line has to become lower and lower. And nowadays the diameter of the line really is too large for the quantity of oil that the line carries.

With temperatures in Alaska well below freezing during the winter, the oil, warm as it exits the oil fields, cools as it flows south from Prudhoe Bay. And the slower the oil flows, the colder it becomes before it reaches the Valdez Marine Terminal for loading into oil tankers. If the temperature of the oil drops below the freezing point of water, ice is likely to form in the line, potentially causing line blockages and damaging pipeline equipment. At low temperatures, increasing amounts of wax will tend to drop out of the oil, causing clogging of the line. And, also as flow rates drop, the flow in the line will become less turbulent, transitioning into what is termed “laminar flow” and increasing the tendency for sludge to drop out of the oil.

Pig operations

Alyeska Pipeline Service Co., the company that operates the pipeline on behalf of the pipeline owners, periodically runs torpedo-shaped devices called “pigs” down the interior of the line, to scrape and clean the inside walls. Were ice to form in the line, a pig would likely become stuck, a situation that would be difficult and expensive to remedy and that would presumably cause a pipeline shutdown. In addition, the difference in fluid pressure between the front and rear of a pig drives the pig down the line — as the oil flow in the line drops that pressure differential also drops, thus making it increasingly difficult to move pigs and hence clean the line. But, as wax and sludge deposits increase in low-flow scenarios, pig operations become increasingly important in keeping the pipeline clean.

One helpful feature of the TAPS configuration is the existence of an oil refinery at North Pole, near Fairbanks, around the midpoint of the pipeline route. The refinery accepts part of the crude oil stream from the pipeline, refines some products such as jet fuel from it, and then returns the residual fluids back to the line. The residual fluids retain heat from the refinery process, thus heating the oil as it continues on its route to Valdez. Were the refinery to close, Alyeska would presumably have to install some form of heating system, to replace the heating effect of the refinery residues.

A threshold?

The big questions over the future of TAPS relate to estimates of throughput levels at which low-flow problems will start to appear, and whether there is some throughput threshold, below which the pipeline will become impossible to operate.
There are ways to deal with the cooling of the oil, such as the installation of heaters and the warming of the oil by circulating the oil through pipes at pump stations. But can these low-flow mitigation measures handle very low throughput volumes? And at what point does the cost of installing and implementing the mitigation measures cease to be viable? The higher the pipeline operating costs, the higher becomes the transportation cost of the oil, thus lowering the oil’s wellhead value.

In the TAPS valuation court case Superior Court Judge Sharon Gleason accepted the principle that there is some minimum throughput flow rate, below which TAPS ceases to be viable, even if technically the pipeline with appropriate mitigation measures could handle very low rates.

Alyeska study

A report published by Alyeska in June 2011, following a study into TAPS low-flow issues, says that low-flow mitigation measures will be essential to keep oil flowing through the pipeline at flow rates below about 550,000 barrels per day. The report listed a number of potential low-flow mitigation measures, such as the heating of the oil upstream of cold points on the line, but said that the Alyeska study had not addressed the mitigation of low-flow problems at flow rates below 350,000 barrels per day.

“As flow rates decline below 350,000 bpd, issues related to low flow will increase the problematic impact on the TAPS operation,” the 2011 low-flow report said. “Measures to mitigate these issues utilizing the existing 48-inch pipe at throughputs below 350,000 bpd have not been determined at the date of this report.”

In the TAPS valuation court case, the TAPS owner companies used the results of the Alyeska low-flow study to claim a minimum viable TAPS throughput rate in the range 300,000 to 350,000 barrels per day. However, Judge Gleason rejected this argument, saying that the Alyeska study had addressed questions of how to keep the pipeline in operation with throughputs down to 300,000 barrels per day, and that the study had not attempted to establish any minimum possible throughput capacity.

And Dan Hisey, a former Alyeska chief operating officer, testified that TAPS has no hydraulic or mechanical minimum throughput level.

According to an Associated Press report, Alyeska spokeswoman Michelle Egan has said that the Alyeska low-flow study was not intended to identify some technical or economic limit for the pipeline.

BP projections

Judge Gleason’s decision document says that BP had until 2004 used 300,000 barrels per day as the likely minimum TAPS throughput when making estimates of remaining oil reserves on the North Slope. That minimum throughput estimate was apparently based on the use of the turbine powered pumping systems originally installed in TAPS to drive oil from Prudhoe Bay to Valdez. However, the conversion of the pumping systems to the use of new electrically powered pumps as part of a major TAPS upgrade project called “strategic reconfiguration” had considerably increased the flexibility of the system to handle lower oil volumes.

In 2004 BP commissioned a study by a consortium headed by JTG Technology & Information Services Inc. into the potential minimum TAPS throughput following strategic reconfiguration. And a 2005 JTG Technology report for the company suggested that, with the application of heat to the line and some other possible pipeline modifications, pipeline throughput could be sustained down to levels of about 135,000 barrels per day. Further hydraulic flow testing would be required to confirm that result, the report said.

The report also said that, were the pipeline owners to replace the original 48-inch pipeline from Prudhoe Bay to Fairbanks by a new 20-inch pipeline, with oil being carried by railroad from Fairbanks to tidewater in Southcentral Alaska, throughput could be sustained down to 45,000 barrels per day.

Lower limits

BP subsequently used the 135,000 barrels per day lower throughput limit to determine the North Slope oil reserves that the company reported to the Securities and Exchange Commission, the court decision document says. According to testimony presented at the court, transitioning to the 20-inch pipeline option to handle lower flow rates would have involved a “stair step” cost of around $3 billion.

The decision document says that in 2010 BP retained Phil Carpenter, an expert in TAPS low-flow issues, to determine the feasibility of operating TAPS at throughputs below 135,000 barrels per day, without that $3 billion cost hurdle. Carpenter concluded that that it would be possible to operate the pipeline with throughputs in the range of 70,000 to 100,000 barrels per day by installing heaters at intervals along the line. Carpenter’s report stated that wax deposition and issues with pig operations would probably put a lower threshold of 50,000 to 70,000 barrels per day on throughput supported by pipeline heaters. Going below that threshold for oil throughput would likely require other remedies, such as the mixing of seawater with the oil, to maintain total fluid throughput rates, the report said.

However, Carpenter did express concern about the feasibility of operating pigs in the line at 70,000 barrels per day — he recommended research into pig designs for use in this type of scenario, the court decision document says. Carpenter also expressed concern about the impact of pipeline shutdowns and slowdowns on oil temperatures and wax accumulation, the document says.

Cost of heating

In 2010 BP commissioned a report into the likely cost and timing of implementing the system of heaters proposed in the Carpenter report. And from the fall of 2010 BP started using the 70,000- to 100,000-barrel range as the low-flow limit when booking its North Slope oil reserves, the court decision document says.

According to the decision document the BP-commissioned cost report estimated that the implementation of heaters as per the Carpenter plan would cost about $3 billion. However, the Carpenter plan assumed the installation of a heating capacity 70 percent in excess of what might actually be needed, thus making the potential implementation cost substantially lower than the cost estimate prepared for BP, the decision document says. But even with the $3 billion cost, the value of proven oil reserves on the North Slope would render the heating upgrade viable, the document says.

Gleason: 100,000 barrels

Judge Gleason concluded that, based on evidence presented in the court, TAPS can carry oil down at least to a minimum throughput of 100,000 barrels per day.

The question of how this presumed minimum throughput translates to an estimated life expectancy for TAPS then depends on estimates of how much oil remains technically recoverable from Arctic Alaska and on future oil prices, with the prices determining the economic viability of oil production. Testimony presented in court illustrated the considerable uncertainty in current estimates of both oil resources and future oil prices, with various consultants presenting a wide range of estimates for different stakeholders in the economics of TAPS.

Persuasive forecast

Ultimately, Judge Gleason found oil production forecasts presented by consultant Dudley Platt to be the most persuasive of the various forecasts presented to the court. Platt, who used to maintain oil production forecasts for the Alaska Department of Revenue, had prepared forecasts for the Alaska municipalities that obtain revenues from TAPS property taxes.
The decision document says that Platt’s forecasts of remaining recoverable reserves lead to a probable end of life around 2065 to 2068 for TAPS, assuming a 100,000-barrels-per-day minimum throughput. This estimate excludes possible production from the Point Thomson field, the field that is currently the subject of a dispute between the field owners and the State of Alaska.

By comparison, reports by BP to the Securities and Exchange Commission for the Prudhoe Bay Royalty Trust, an investment fund for the Prudhoe Bay field, have indicated TAPS end-of-life expectancies ranging from 2049 to 2075, with that wide range of years apparently related to an equally wide range in future oil price expectations. The pipeline owners’ testimony to the court presented a range of years from 2032 to 2053, with significantly lower estimates of remaining oil reserves than those presented by Platt. The State of Alaska, with reserves estimates between those of the owners and those of the municipalities, estimated an end of life ranging from 2043 to 2053, if the pipeline is operates to its economic limit, the decision document says.

Shell gets final OK on air permit for Chukchi Sea drilling

2012-01-12T22:00:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

The U.S. Environmental Protection Agency's Environmental Appeals Board has approved Shell Oil's air quality permit for the Noble Discoverer drillship, Shell announced Thursday.

The drilling vessel will be used by Shell to drill up to three exploration wells in the Chukchi Sea this summer if Shell secures other permits and approvals that are still pending.

The EAB, an internal appeals panel within the EPA, denied petitions for review of the permits filed by environmental groups.

“Achieving usable air permits from the EPA is a very important step for Shell and one of the strongest indicators to date that we will be exploring our Chukchi and Beaufort Sea leases in July,” Shell spokesman Curtis Smith said in a statement. “That our air permits for the Noble Discoverer withstood appeal is a testament to the robust nature of the work we have done to have the smallest possible impact on the Arctic airshed,” Smith said.

Shell equipped the drillship with advanced emissions control technology and will use ultra-low sulfur diesel fuel in operations of the vessel. Shell is planning to use another drill vessel, the Kulluk, in the Beaufort Sea in 2012.

The company has not yet decided to mobilize for the summer drilling.

“The validation of Shell’s first air quality permits is almost the end of what has been a long and exhaustive process,” said Sen. Lisa Murkowski. “I’m relieved that the EPA’s internal appeals board chose here not to drag out the process any further, and I hope that the permits for Shell’s second drillship, the Kulluk, are similarly confirmed in a timely manner.”

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-15-2012/Shell-gets-final-okay-on-air-permit-for-Chukchi-Sea-drilling/#ixzz1jJqyFkk9

Gov. Parnell says he’s upbeat about state’s economy

2012-01-12T13:58:00.002-09:00

By Tim Bradner
Alaska Journal of Commerce

Gov. Sean Parnell presented an upbeat picture of Alaska’s prospects, but also highlighted the state’s immediate challenges in a keynote address to the Alaska Support Industry Alliance’s annual Meet Alaska conference in Anchorage Jan. 6.

Parnell first applauded the Alliance and its industrial service and support company members.

“You are in the business to do what Alaskans have done from the beginning: maximize opportunity, develop private enterprise,” the governor said. “Every day you accomplish what no government can do. You generate an authentic GDP. And I don’t mean ‘Government Dependent Programs.’ I mean an honest-to-goodness Alaska GDP based on free enterprise. You make that happen every day.”

For now, things are looking positive for the state.

“In case there’s any doubt, I want to make something very clear: Alaska is open for business. Today’s newspapers let us know we’ve had the third straight year of job growth in Alaska. Yesterday (Jan. 5) we saw further evidence that others are taking notice that Alaskans will work together to grow our economy. Three CEOs from major oil companies met here in Alaska to talk about a gas line, to talk about alignment,” Parnell said. “It was the first time these three CEOs have been together in Alaska. Our discussions were very productive, and I was very encouraged. Also, it was announced that our state bond rating was upgraded to AAA. In this world economy, think about what that means. Alaska’s business environment is getting better.”

Still, there are troubling times ahead, he said.

“In 2012, my administration will not yield in our effort to directly address the most pressing economic issue facing our state – the decline of oil coming through the Trans-Alaska Pipeline System. TAPS production is an economic survival issue for Alaska,” Parnell said.

To address this problem, the governor’s plan to increase oil production from its current rate of about 600,000 barrels per day back to 1 million barrels per day was developed last year out of discussions with business and community leaders.

“We sat down, talked with business and community leaders across the state, and we heard their concerns. We carefully listened to these ideas,” Parnell said. “We said we were going to put more oil leases up for sale. We did so in December, during the annual (North Slope areawide) lease sales. We said we were going to challenge federal foot-dragging, and we do so at every turn. Alaska’s voice has rung loud and clear.

“Finally, we are seeing Washington loosen its death-grip on the NPR-A and OCS,” Parnell said, in reference to the federal government’s recent approvals of a permit for a key bridge crossing providing access to the National Petroleum Reserve-Alaska, or NPR-A.

“The federal agency approval is for CD-5, which will mean a bridge over the Colville River that allows access to leases within the NPR-A,” Parnell said.

There are also recent approvals for exploration plans for Shell’s offshore exploration.

“Progress is slower than we’d like, and some of Washington’s decisions in this regard have been disingenuous. But there has been change. We’re thankful for it, and we’re going to keep on fighting,” the governor said.

Parnell laid our some action items as the Legislature opens its 2012 session in Juneau.

“We will restructure our oil tax system to increase production. We will build roads to resources, and you’ll note in my 2013 budget we have funds for a road to Umiat and the Ambler District. We will continue to make the case for a vibrant, business climate and a growing economy,” the governor said.

Looking at the long term, Parnell said the state will reach the goal of having 1 million barrels per day in 10 years. And noted there will be a gas line, he said.

Infrastructure investment is a key part of the plan, he added.

“That means Roads to Resources. Transportation infrastructure. Maintenance of public facilities. And there’s a $350 million bond package I propose putting before Alaska voters to upgrade ports in communities from Ketchikan to Anchorage to Emmonak,” Parnell said.

The state’s investment in a 600-megawatt hydro project in Watana, on the upper Susitna River, is also part of the plan, he said. Susitna-Watana means, “massive amounts of hydro power that will lower the cost of doing business all across the Railbelt, and grow jobs during the construction phase,” the governor said.

There is other recent good news, most notably the fact that Sen. Lisa Murkowski introduced a bill to move permitting for offshore drilling under the Clean Air Act from the Environmental Protection Agency to the Interior Department.

And, “we’ve got a great turn-around story in Cook Inlet, with new players coming in,” Parnell said. “LNG shipments have continued from Nikiski, in response to a changing market around the Pacific Rim. We’re seeing more exploration on the North Slope than we have for a few years.

“Mining – now there’s a strong trend for 2012,” he added. “Red Dog, Greens Creek, Usibelli, all accounting for massive increases in our exports. Donlin (gold mine) is closer to production, and numerous other mines of all sizes are in advanced stages of development. We’re launching our state’s rare earth element mining sector.”

According to the Alaska Miners Association, one-third of all mining exploration in the U.S. is happening in Alaska. And last year exploration in Alaska topped $260 million.

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

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-15-2012/Gov-Parnell-says-hes-upbeat-about-states-economy/#ixzz1jHtLzqeV

State Senate to float new ideas on oil tax changes

2012-01-12T12:03:00.007-09:00

Tim Bradner
Alaska Journal of Commerce

Most of the attention on oil tax legislation has been focused on Gov. Sean Parnell’s House Bill 110, a bill that passed the state House last year and is now in the state Senate.

State senators meanwhile are working on their own ideas for oil tax changes, which will be brought forth in separate bill, or perhaps added to, or substituting for, the existing language in HB 110.

Sens. Tom Wagoner, R-Kenai, and Lesil McGuire, R-Anchorage, are crafting a new version of Senate Bill 85, a bill introduced by Wagoner, which takes a different approach in changing oil taxes than the governor’s bill. Last year Wagoner, who is co-chair of the Senate Resources Committee, attempted a variation of a tax incentive used in Alberta, where companies investing in new development get a speedy recovery of their capital.

Wagoner spoke with other legislators at Jan. 5 meeting of the Resource Development Council in Anchorage. Speaking at the same meeting, House Speaker Mike Chenault, R-Nikiski, said he expected some version of an oil tax change to pass in 2012 and that the House is waiting to see what ideas are developed in the Senate in addition to Parnell’s proposal.

Chenault said most of the attention will be on the “progressivity” formula in the production tax, a formula that escalates the tax rate sharply as oil prices climb, as well as the investment tax credits allowed in the current law. Sen. Bert Stedman, R-Sitka, is reported to be working on his own proposal for changes to the tax. Stedman is co-chair of the Senate Finance Committee.

Wagoner said there are problems with the original version of his SB 85, so a new approach is being crafted in consultation with McGuire, Wagoner said. An idea being studied is a “tax holiday” for new oil production, a period during which there would be no state taxes on new oil that is developed.

Wagoner said he has solicited, and is receiving, technical advice from the Alaska Oil and Gas Association on the idea. AOGA is the petroleum industry’s trade association for Alaska. An oil company tax specialist, speaking on background, confirmed that industry tax specialists are offering advice through the trade association. The idea of a tax holiday on new production is not new and has proven to be effective elsewhere.

Wagoner also said he will seek legislation through a new bill or an amendment to an existing bill to extend the special Cook Inlet jack-up rig investment incentives to the Nenana Basin, an underexplored Interior Alaska sedimentary basin west of Fairbanks, where there is potential for natural gas discoveries and possibly oil.

Doyon Ltd., the Interior Alaska Native regional corporation, is now leading a consortium of Alaska companies intent on exploring state lands in the Nenana Basin. One exploration well was drilled two years ago, and although it did not find a commercial gas deposit, the information yielded confirmed the presence of hydrocarbons in the basin.

Doyon is now doing seismic work in another part of the basin and a well may be planned there if the results are favorable, but being able to use a set of investment tax credits similar to those available to new offshore explorers in Cook Inlet would greatly speed the exploration.

If gas is found in the basin, and enough of it, a 60-mile pipeline could be built to bring gas to Fairbanks.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-15-2012/State-Senate-to-float-new-ideas-on-oil-tax-changes/#ixzz1jHQhaunM

--------------------------------
I will be supportive of Senate Bill 85 only if the Competitive Review Board remains in the bill. - Deborah Brollini Please listen to the audio from Sen. McGuire's comments from Senate Resources Committee on 4/4/11 (highlighted below)

SCR4: Creating and relating to the Alaska Oil and Gas Competitiveness Review Task Force
http://www.legis.state.ak.us/basis/get_bill.asp?session=27&bill=SCR%20%204

Alaska's Future: Sen. McGuire's proposed competitiveness review is important
http://www.alaskadispatch.com/article/alaskas-future-sen-mcguires-proposed-competitiveness-review-important

Energizing Investment in Alberta
http://www.commonwealthnorth.org/documents_cwnorth/EnergizingInvestment%20Alberta.pdf

SB 85 http://www.legis.state.ak.us/basis/get_bill.asp?bill=SB%20%2085&session=27

SB 85: Documents (4/4/11 Competitive Review)
http://www.legis.state.ak.us/basis/get_documents.asp?session=27&bill=SB85

SB 85 Senate Resources Hearing (Audio): Mary Jackson, Staff to Senator Thomas Wagoner, and Michael Pawlowski, staff to Senator Lesil McGuire, testimony to Senate Resources on March 25, 2011.
http://www.legis.state.ak.us/basis/get_audio.asp?session=27&chamber=S&comm=RES&date1=3/25/2011&start=1535&bill=SB85

SB 85 Senate Resources Hearing (Audio): Catherine P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission, and et al and invited testimony (4:41)
http://www.legis.state.ak.us/basis/get_audio.asp?session=27&chamber=S&comm=RES&date1=3/25/2011&start=1535&bill=SB85

SB 85 Senate Resources hearing (Audio): Invited and public testimony (3/30/11)
http://www.legis.state.ak.us/basis/get_audio.asp?session=27&chamber=S&comm=RES&date1=3/30/2011&start=1532&bill=SB85

SB 85 Senate Resources Hearing (Audio): Michael Pawlowski, staff to Senator Lesil McGuire testimony, and Senator McGuire’s comments on the Oil and Gas Competitiveness Review (OGCR) Board. Senator McGuire asks for recommendations rather than a “no” (4/4/11 at 3:38)
http://www.legis.state.ak.us/basis/get_audio.asp?session=27&chamber=S&comm=RES&date1=4/4/2011&start=1531&bill=SB85

Alaska’s Oil Investment Tax Structure, Establishing A Competitive Alaska, Commonwealth North, March 2011
http://www.commonwealthnorth.org/documents_cwnorth/Final%20OITS%20Report%203-15-11.pdf

Time to move beyond talk as legislative session starts

2012-01-12T11:51:00.003-09:00

By Lee Leschper
Alaska regional vice president for Morris Communications

We’re off to an interesting start on what could be an historic year.

Already this year Gov. Sean Parnell has gathered a room full of movers and shakers, with the CEOs of Alaska’s big three oil companies, to talk about the potential for a natural gas pipeline to produce liquefied natural gas for sale in the Far East.

It’s in keeping with his commitment to do what it takes to refill the trans-Alaska oil pipeline with 1 million barrels of oil a day. And the opening round in a legislative session that starts this week in Juneau with some big expectations and bigger challenges.

This is the leadership we need from the governor. Great things always start just such a vision. Connecting the dots, moving from vision to action, will be a larger undertaking.

The Jan. 6 Meet Alaska conference, the annual gathering of the Alaska Industry Support Alliance, got down to detail and to reinforce the need for a change in tax law to attain that goal.

Specifically, BP Exploration (Alaska) Inc.’s John Minge said that only a big change in Alaska oil tax policy will bring more oil company investments to the state. And that it will take a $150 billion investment from those players to generate those million barrels a day.

The state Department of Revenue’s Bruce Tangeman was equally emphatic, saying that only radical changes, not just a few tweaks on the oil tax’s reciprocity, will bring that investment to Alaska.

Is it the right time?

Clearly the vast majority of Alaskans, in and out of the oil business, want action.

Alaska’s Clear and Equitable Share, ACES, was passed in large part because the timing was right, because both voters and legislators agreed the state deserved a bigger share of oil profits.

They united behind then-new Gov. Sarah Palin to demand a bigger cut for the state. And in the final version of ACES, the Legislature demanded even more. The whole process happened in weeks, really just days, so it’s reasonable to expect it was a bold but imperfect draft. It was also based on a lot of projections.

It made great sense in 2006. Does it still?

Aggressive taxation may have made sense when there were fewer alternatives to Alaska oil. That is no longer the case. Now it is time to review five years of history under ACES, with real data, and work to improve the plan.

There seems almost universal agreement it’s got to address reciprocity and reward both exploration and production, with rewards for both the state and the oil companies. It’s got to be a win-win for the industry, Alaskans and Alaska businesses.

It can’t abandon the expectation that Alaskans get a fair return.

The next generation of Alaska oil tax codes has to continue to protect the 90 percent of Alaska’s operating revenue that oil generates.

We also have to understand that the more radical the proposed changes, the less chance we can expect agreement in the Legislature.

It’s not said often enough that ACES hasn’t been all bad for the state. During these last few brutal economic years, when most of other states are sinking deeper into bankruptcy, Alaska has added billions to our reserve.

BP’s Minge pointed out last week that the oil industry makes billion-dollar decisions based on expectations 50 years into the future. We need to have that same 50-year vision for the state.

Is it realistic that any new oil program works whether oil is selling at $80 or $180 a barrel, and whether gas is $2 or $10, whether the customer is China or the Lower 48?

Time will tell.

The perception is that Legislature does most of its work in a flurry at the end of the 90-day session. Let’s not waste those 90 days this year. Lawmakers have heard for months – since well before the 2011 session – that ACES needed changing, that the big producers won’t invest the big money to find and produce new oil in the current tax environment.

Alaskans share an expectation — that their elected officials will do their jobs, will work together and compromise to make real and positive legislation to benefit all Alaskans as well as to the businesses that provide us the economic benefits we have come to rely on.

That meaningful work must begin from Day 1 of the session.

Lee Leschper is Alaska regional vice president for Morris Communications publications including the Alaska Journal of Commerce. Email him at lee.leschper@morris.com.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-15-2012/EDITORIAL-Time-to-move-beyond-talk-as-legislative-session-starts/#ixzz1jHLinhFX

Senator Bert Stedman talks with Dan Fagan

2012-01-09T20:56:00.001-09:00

Entire video of Senator Bert Stedman.

Battle on ACES tweaks to dominate session

2012-01-06T05:12:00.002-09:00

Analysis by Tim Bradner
Alaska Journal of Commerce

The 2012 state legislative session convenes Jan. 17, and probably the most important bill on the session agenda besides the budget is Gov. Sean Parnell’s bill to reduce the state oil production tax as an incentive for new industry investment. It will be a very contentious issue and it may preoccupy legislators in terms of dealing with other significant matters, excepting the state capital budget.

There will be tough sledding for the governor on this bill as it was in 2011. Senate Democrats, who are partners in the Republican-Democratic Senate leadership coalition, appear to be dug into their positions opposing House Bill 110, the governor’s bill that passed the House last session.

However, there may be some room for optimism. In a December talk to Commonwealth North, an Anchorage-based public policy group, Senate President Gary Stevens, R-Kodiak, said the Senate Majority would examine the tax and particularly the “progessivity” formula, a formula in the tax that ratchets up the tax rate as oil prices climb.

Another key Senate leader, Sen. Bert Stedman, R-Sitka, said in legislative committee interim meetings this fall that he recognizes that state taxes on North Slope oil and gas operators merits a close look, and that a mismatch now exists between the industry’s economic situation in Cook Inlet, where there are virtually no state taxes, and the North Slope.

The action on HB 110, will take place mainly in the Senate. It passed the House last March by a vote of 22 to 16, a narrow margin because 21 votes are needed to pass a bill in the 40-member House. HB 110 is now in the Senate Labor and Commerce Committee, which held hearings last summer on employment aspects of the legislation with a focus on local-hire in the oil and gas industry. If the bill moves from the Labor and Commerce Committee it would go to the Senate Resources Committee and then to the Finance Committee.

HB 110 is important because it seeks to stimulate industry investment on the North Slope, hopefully stabilizing or reversing the decline in production. Critics argue the bill gives back too much to the industry and that there are no guarantees that new investments would actually be made. Last year the industry was not able to convince legislators, particularly in the Senate, that investments would occur if tax relief were given.

Near the end of the session ConocoPhillips’ CEO Jim Mulva came to Alaska and in a talk to an Anchorage business group, came as close as any senior executive can come in making a guarantee that a billion dollar-plus project in the west part of Prudhoe Bay would move forward if the tax were adjusted.

Guarantees like this are difficult for public companies because boards of directors ordinarily approve projects. Also, ConocoPhillips has partners in the Prudhoe field, which also must give approvals. In this case, BP’s Alaska president echoed Mulva’s commitment in a separate speech a few days later.

It was, however, too late in the session. Attitudes in the Legislature had already hardened.

The major producing companies, and the governor, argue that there is insufficient new investment on the North Slope in projects that will produce new oil, such as new production wells in the existing fields and projects to increase production of lower-quality oil, such as thick, or viscous, oil now being produced in limited quantities.

Substantial capital investments are being made in the North Slope oil fields, and these amounts are even increasing, according to state Department of Revenue data. But field operators say that much of this is focused on increased maintenance of aging facilities in the producing fields, and that money allocated for new production, such as new in-field drilling, is lagging.

ConocoPhillips, which operates the large Kuparuk field, has said that nearly 70 percent of its capital budget is now devoted to maintenance. A year ago the percentage devoted to maintenance was 60 percent. Given that the capital budgets of the two major operating companies, ConocoPhillips and BP, have been relatively static in recent years, about $900 million a year for each, this means less money is going to develop new oil in the producing fields.

New exploration no panacea

There is new exploration under way, but it is no panacea. The winter 2012 North Slope exploration drilling season looks to be the busiest in many years, but most of this is being driven by one company, Repsol, which has four to five rigs contracted.

Repsol has said it must develop an aggressive exploration program this winter because of expiration deadlines on some of the 500,000 acres of state leases in which it holds an interest. Absent Repsol, the winter exploration season looks about average, with three small independent companies planning test wells.

However, accumulations that might be discovered, at least on state-owned lands, are likely to be modest in size, even Repsol acknowledges. No large Prudhoe Bay-type finds are expected, in other words. Also, any discoveries will take several years to put into production because of the lead times needed to secure permits and build infrastructure like pads, wells, roads, utilities and pipelines.

In contrast, the governor and supporters of HB 110 argue that substantial additions of new oil could be put into production quickly enough to make a difference in slowing the production decline, but this must come from within the existing producing fields, where there is currently infrastructure.

In many cases the resources are known – the large deposits of viscous oil, for example – but the major producing companies say these projects are uneconomic to develop unless the existing state tax is changed.

The surge in exploration is also somewhat of an illusion in that the state itself is paying for much of the cost of the new wells, more than half in some cases, through exploration incentive tax credits in the production tax law. This has created an unusual situation of a tax subsidy for exploration of likely modest oil deposits but an overall tax law that discourages larger resources being developed in the larger fields, the supporters of HB 100 argue.

HB 110 changes the formula

The governor’s bill would address this by reducing the production tax rate and making other changes. The current tax is structured to increase the tax rate as crude oil prices rise to the point that, at the current range of oil prices, Alaska’s tax may be among the highest in the world. Given that the North Slope state-owned lands offer prospects of only modest discoveries and that access is costly, it can be seen why Lower 48 states are enjoying a surge of new industry investment and Alaska is not.

House Bill 110 reduces the tax by changing the “progressivity” formula in the law that causes the tax rate to escalate at high oil prices. The bill also “brackets” the tax law so that it works like the federal income tax, so that high tax rates apply only to the higher brackets of oil prices. The governor would also extend to the North Slope most of the investment tax credits and other incentives that now apply to Cook Inlet, where there is a resurgence of new industry exploration.

The argument against HB 110

The argument against HB 110 is mainly that the bill would result in a significant reduction in future state revenues – how much depends on the assumptions made – and there is no guarantee that new investment would follow.

With production declining, legislators are acutely aware of the fragility of the state’s future finances and are wary of giving up the certainty of revenues in the existing tax system without some clear guarantees that investments will be made that will result in new oil production, strengthening the fiscal outlook.

There seems to be wide political acceptance in the Legislature, even among opponents of HB 110, for the exploration investment tax credit approach, even to the point of the state paying for most of the cost of the new exploration. The difference between the two approaches is that HB 110 would cause a general reduction in taxes, while the investment tax credits, a different form of tax reduction, occur only after an investment is made.

This is an important point. For a long time the governor was lukewarm to the idea of a general tax reduction, like that now proposed as the core of HB 110, but supportive of tax reductions linked to performance, such as through an investment tax credit mechanism.

There appears to be considerable support in the Legislature for the concept of investment tax credits, as illustrated by the exploration credits, but obviously less support for the idea of a general tax reduction, mainly because of the lack of a guarantee. It would seem that a compromise, of some sort, would involve a tax change that reduces the overall tax rate, achieving the objectives of HB 110, but that is linked to some kind of performance guarantee.

It’s possible something like this could develop as the Legislature resumes work on the governor’s bill after Jan. 17.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-8-2012/Battle-on-ACES-tweaks-to-dominate-session/#ixzz1iggCupRd

South Korea natural gas needs lend opportunity for Alaska

2012-01-05T23:40:00.003-09:00

Bob Tkacz
Alaska Journal of Commerce

SK Energy has opened 260 “recharging stations” like this one in South Seoul, since LPG and hybrid-powered cars and trucks arrived in Korea in 2009. LPG prices are posted in liter equivalents for convenient comparison to standard fuel costs. In this November 2010 photo LPG at 944 won per liter ($3.07 per US gallon). In November 2011 LPG at 1070 won (.925 cents/$3.49 per gallon) compared to $6.35/gallon for unleaded gasoline and $6.12 for diesel.

SK Energy has opened 260 “recharging stations” like this one in South Seoul, since LPG and hybrid-powered cars and trucks arrived in Korea in 2009. LPG prices are posted in liter equivalents for convenient comparison to standard fuel costs. In this November 2010 photo LPG at 944 won per liter ($3.07 per US gallon). In November 2011 LPG at 1070 won (.925 cents/$3.49 per gallon) compared to $6.35/gallon for unleaded gasoline and $6.12 for diesel.

Photo/Bob Tkacz/For the Journal

An unexpected increase in South Korea’s short-term natural gas demand, and uncertainties in the energy-poor country’s long-term supply outlook could open opportunities there for sales of Alaska’s clean energy.

While South Korea is making substantial investments in oil and gas from Canada, decision-makers in the Asian country lack information on what’s available from Alaska and state officials have made few, if any, attempts to open the market, according to Korean and U.S. officials there.

Officials said Alaska could improve its prospects for LNG sales to South Korea with some basic steps, some of which are already on the state’s agenda, but Alaska so far has made no toward that.

“We know very little so we did not include it in outlook and price projections,” for Alaska energy resources, said Jinwoo Kim, president and CEO of the Korea Energy Economics Institute, a government agency that tracks and projects Korean energy use and sources.

With virtually no domestic resources, energy is not only a necessity, but a national security issue in South Korea. With 48 million residents, it is the world’s tenth largest energy consumer, importing 97 percent of its energy.

“I do see that Korea will continue for a long time in the future to be the world’s second largest importer of natural gas (after Japan) and will stay that way for quite some time to come despite a lot of emphasis being done for renewable energies,” said Mark O’Grady, commercial attaché at the U.S. Embassy in Seoul.

Partly in response to President Lee Myung-bak’s “green growth/low carbon” initiative, as well as to climate change and oil market issues, South Korea has made dramatic changes in its energy supply and electrical power generation mix.

From 1981 to 2010, oil dropped from 58 percent to 40 percent of the country’s energy sourcing. As a fuel for electrical generation, oil has virtually disappeared, from nearly 80 percent in 1981 to less than 5 percent last year. Coal, including some imports from Alaska, fell slightly as a primary energy source to 29 percent from 33 percent over the same period, but remains an important fuel for electrical generation at 42 percent, up from 6 percent three decades ago.

Nuclear rose from nearly 2 percent to 12 percent of overall energy supplies during the same period and leapt from 7 percent of electrical generation to 31 percent last year. KEEI projections indicated it would generate nearly 60 percent of the South Korea’s electricity by 2030, but the Fukoshima Daiichi power plant disaster in Japan changed that.

“The Korean government has had a very aggressive nuclear expansion plan, but some other voices now coming from NGOs and other ordinary people to reconsider the nuclear expansion plan,” said Ki Joong Kim, the senior research fellow in KEEI’s oil and gas policy division. “If our government has to change their position on nuclear plant expansion then we might have more room to import LNG from other sources.”

Alternative energy now provides for 0.8 percent of Korea’s electrical. Projections call for an increase to 11 percent by 2030, but Jinwoo Kim called that a very optimistic expectation, which could further increase the demand for natural gas.

After nuclear power, natural gas has filled the gaps in Korea’s energy. From zero use in 1981 LNG accounted for 15.7 percent of the country’s energy supply and 20.4 percent of its electrical generation last year.

Korea’s natural gas demand was 31.2 million tons in 2010 and KEEI’s pre-Fukoshima projection showed an increase to 34.1 million tons by 2024. That included a short-term spike in gas use for electrical generation from 2014 to 2017 without, as yet, an identified supply.

The gas gap is projected to start closing in 2017, when a pipeline from Russia that would deliver 7 million tons of natural gas per year, but security questions over its route through North Korea continue to dog the project despite top level support from the South and Russia.

The agreement calls for negotiation, beginning in March, of a master project plan in time to start construction in 2013. South Korean critics continue to question the wisdom of handing North Korea a new tool to threaten the South.

The project schedule is still unclear.

“It’s not 100 percent sure yet. We just hope to start the construction work in the middle of 2013,” said Jinwoo Kim.

O’Grady noted that South Korea and Japan recently announced they have opened discussions to create an LNG “buying block.”

“I don’t know how far that will go, but recent media reports show that they just got through with initial discussions to try to figure out a way that they can harness the fact that they are the first and second biggest importers of LNG to work together to drive down the prices,” O’Grady said.

KEEI spokesmen said the world glut of natural gas allows buyers to demand more flexible terms from suppliers. Ki Joong Kim said U.S. gas could be a hedge against the uncertainty of the Russian project and that Gulf of Mexico producers have traditionally been “very flexible.”

He added that Alaska’s linkage of taxes on natural gas to its oil tax regime is a significant discouragement.

“If Alaskan gas wants to compete with Gulf area LNG, it must offer more flexible conditions,” Ki Joong Kim said.

Some Alaska legislative leaders have said decoupling the state’s oil and gas tax regimes should wait until shippers and TransCanada Corp. come to terms on the Alaska Pipeline Project.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-8-2012/South-Korea-natural-gas-needs-lend-opportunity-for-Alaska/#ixzz1ifKTkyYH

BP, ConocoPhillips endorse LNG project as best for North Slope gas

2012-01-05T15:28:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

BP and ConocoPhillips now believe a major liquefied natural gas project is the best option for marketing North Slope gas, the chief executive officers of the two companies said following meetings with Gov. Sean Parnell Thursday morning.

Robert Dudley of BP, James Mulva of ConocoPhillips and Rex Tillerson of ExxonMobil met with Parnell and then, along with the governor, briefed state legislators on the talks in a separate meeting.

Parnell met with the CEOs to discuss how to align the major Slope producers on a major gas project. ExxonMobil Corp., another major producer, participated in the meetings but did not comment afterward while the leaders of BP and ConocoPhillips said their companies now believe LNG is the best way of marketing gas from the Slope.

“Given the outlook with shale gas in the Lower 48, it looks like LNG has the best potential. We’re not saying the pipeline (to Canada) is impossible,” but a pipeline to southern Alaska to an LNG plant appears to have the best prospects, BP CEO Dudley told reporters following the meetings with Parnell and legislators.

ConocoPhillips’ Mulva agreed with Dudley.

“We believe LNG is the best alternative for North Slope gas, far better than any alternatives,” Mulva said.

Parnell said the three companies have agreed to work with the state on a review of all alternatives including an LNG export project as an alternative to an all-land pipeline from the North Slope to Alberta.

TransCanada and ExxonMobil are now pursuing a land pipeline with state support under the Alaska Gas Inducement Act, or AGIA, but Parnell said an LNG project could be done under the framework of the existing agreement with TransCanada.

AGIA includes a provision that an LNG project can be done as an alternative.

The AGIA contract provides for the state to provide up to $500 million in grants to support engineering and environmental work in return for TransCanada and ExxonMobil meeting certain state requirements on schedules and tariff structure.

AGIA requires TransCanada to file an application for a land pipeline with the U.S. Federal Energy Regulatory Commission this October.

TransCanada vice president Tony Palmer, who attended the noon meeting with legislators but did not participate in the meetings of the CEOs with Parnell, said he supports the new initiative and that the meeting of the three CEOs with Parnell was hugely important.

An LNG alternative would involve a large-diameter, 800-mile pipeline to an LNG plant at a south Alaska port, either at Valdez or near Kenai, on Cook Inlet. ConocoPhillips operates a small LNG plant near Kenai that exports Cook Inlet gas to Asia.

Valdez has also been considered in the past as a possible LNG plant site because of the deep water harbor, and proximity to infrastructure along the existing Trans Alaska Pipeline System and the Valdez Marine Terminal, which ships crude oil.

Cook Inlet is navigable for smaller LNG tankers now used by ConocoPhillips but may have limitations that would impede an expansion of the present LNG plant.

Parnell has been urging the producers to shift their support from an all-land pipeline from Alaska to Alberta to an LNG project to export Alaska gas to Asia. The glut of shale gas in Lower 48 gas markets and continued strong markets for LNG in Asia now make an LNG project more viable than a land pipeline, Parnell has said.

There has been substantial previous work on a large Alaska LNG project as well as previous efforts on an all-land pipeline. In the 1990s BP, ARCO Alaska (now ConocoPhillips), Foothills Pipeline (now TransCanada) along with Marubeni, a major Japanese company, did conceptual feasibility studies of a pipeline to Valdez parallel to TAPS and an LNG plant built adjacent to the Valdez Marine Terminal.

The project did not move forward because the companies felt the Asia LNG market would not be able to absorb sufficient volumes of Alaska LNG to make the project viable.

A separate initiative was led by Yukon Pacific Corp., or YPC, a subsidiary of CSX, a major U.S. transportation company. YPC obtained conditional rights-of-way for the pipeline and a lease for the LNG plant along with a federal LNG export license, but the company was never able to get support from the North Slope producers.

The producers’ and TransCanada’s current work on a land pipeline began in 2001. It followed a failed attempt by an earlier consortium of U.S. utilities and North Slope producers to build a pipeline in the early 1980s. Changes in U.S. gas markets and deregulation of the gas industry made that project uneconomic.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-8-2012/BP-ConocoPhillips-endorse-LNG-project-as-best-for-North-Slope-gas/#ixzz1idKhCXXD

State officials visit China to spark interest in LNG export

2012-01-05T10:48:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

Gov. Sean Parnell has tilted the state’s support toward a large liquefied natural gas, or LNG, export project for North Slope gas, and senior state officials are talking up the idea in Asia.

“We realize deals will be cut by the parties involved, but we want to make sure people in Asia know about Alaska and our potential,” said Dan Sullivan, state commissioner of Natural Resources.

Sullivan and Deputy State Commerce Commissioner Curtis Thayer were in China in mid-November to attend a high level Asia regional energy conference and to meet with senior government and private-sector officials who influence China’s energy policies.

Sullivan had been invited to address the Asia Pipeline Summit, a major conference, held in Beijing Nov. 16. While there, he and Thayer organized a number of appointments to talk about Alaska.

“This was part of a broader effort we are making to promote a better understanding of what is going on in Alaska, and of our resource potential, in the aftermath of the governor’s speech,” announcing the shift to supporting an LNG project.

“The governor was in Europe to meet with BP and Shell, along with attending a seafood marketing event, and Commissioners (Susan) Bell and (Marc) Luiken were also in China at about the same time we were to make calls on seafood buyers and air carriers,” Sullivan said.

The Asia pipeline conference itself was attended by 150 to 200 people, Sullivan estimated, and included a cross-section of government and private officials from several nations interested in energy development and transportation in Asia.

Sullivan’s presentation to the conference was a version of the talk about Alaska’s oil and gas potential he has given many times at conferences and private meetings, highlighting the oil and gas resource base.

Several points were tailored to the audience in Beijing, however. One is that Alaska is currently the only U.S. state exporting gas, in the form of LNG, to Asia. The state has a 40-year record as a reliable supplier of LNG to utilities in Japan. In 2011 the first LNG shipments were made from Alaska to China.

“A lot of people in Asia don’t know about Alaska’s track record as a reliable supplier,” Sullivan said.

Secondly, Alaska’s North Slope gas is “wet” with natural gas liquids mixed with the methane, the main component of natural gas used for heating. This is important because natural gas liquids like ethane are important in the manufacture of other products.

“Wet gas is more valuable than dry gas as a petrochemical feedstock – it contains more of the larger (hydrocarbon) molecules that can be refined and reconfigured into more varied compounds,” Sullivan said in his presentation at the conference.

Among all of the advantages of doing energy business with Alaska, one that seemed to impress people the most was geographic diversification of energy supply sources.

“If China is going to buy more LNG, these people don’t want to be bound to two or three supply sources,” Sullivan said. “Most of the presentation was what I make to others, but people in China were still impressed at how large just the conventional resources are, to say nothing of the unconventional. When I explained that we produce and re-inject 8 (billion) to 9 billion cubic feet of gas daily on the North Slope, a lot of people express disbelief. That’s about the average gas consumption of Canada.”

In addition to the conference, Sullivan met with officials at the Ministry of Finance; China Council for the Promotion of International Trade; The Clean Air Task Force; Goldman Sachs; National Energy Administration; and the CITIC Group. He also met with U.S. Ambassador Gary Locke and other officials at the U.S. Embassy.

Thayer attended many of the meetings.

Potato trade

On a different topic – Alaska seed potatoes – Sullivan met with officials from Heilongjiang Province, including one who had flown to Beijing just to meet with the commissioner.

“They are interested in buying seed potatoes from Alaska and collaborating in research,” Sullivan said.

On returning to Alaska, the commissioner passed the information on to officials in the state Division of Agriculture, which is part of the Department of Natural Resources headed by Sullivan.

Sullivan has previous experience in China from his days working in the U.S. State Department as an assistant secretary of state responsible for energy, among other areas, and has attended dozens meetings there. The experience proved useful on the November trip.

“I’m not a China expert but you get a sense of when someone is just being polite in a meeting. In these meetings there were a lot of questions and some meetings that were scheduled for 45 minutes turned into an hour and a half,” Sullivan said.

Everything learned there has been passed on to the Alaska producing companies, which would actually negotiate any contracts, the commissioner said.

Thayer said he was impressed with how much some officials knew about Alaska even before the meetings.

“They knew about our decline in production and pipeline throughput, and wanted to know what we are doing about it,” Thayer said.

Also, although political concerns over energy ties with the U.S. didn’t surface in talks directly, the subject came up in oblique ways.

“There was concern as to how the U.S. government would view exports of gas to China,” he said.

The U.S. government’s rejection of a bid by a major Chinese company to buy Union Oil Co. of California was mentioned.

Alaska’s rejection four years ago of a bid by major Chinese energy company Sinopec in the Alaska Gasline Inducement Act solicitations did not come up in talks, Sullivan said. Although there were political concerns raised at the time by Alaska’s congressional delegation the company’s AGIA application had other problems with its qualification, the commissioner said. Sinopec was represented by an Alaska company owned by a Chinese-American.

Although China has not yet made a direct investment in Alaska natural resources, Chinese companies are indirectly involved through other parties, Sullivan said. For example, a Chinese company owns a substantial share of Teck, which operates the Red Dog and Pogo mines in Alaska. Also, another Chinese company has an agreement to purchase gold produced at the Kensington Mine near Juneau.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-8-2012/State-officials-visit-China-to-spark-interest-in-LNG-export/#ixzz1icCMEc8a

Congress cuts funding for Alaska federal gas coordinator by 75%

2012-01-05T10:45:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

The budget for the Alaska federal pipeline coordinator has been reduced by 75 percent to $1 million for federal fiscal year 2012, Larry Persily, director of the office said Jan. 4.

The action was taken in the House-Senate budget conference committee. It is an indication that some in Congress doubt a proposed $40 billion-plus Alaska natural gas pipeline will be built anytime soon.

Persily said the office has $2.25 million in funds remaining from its fiscal 2011 appropriation, and those funds, along with the $1 million for fiscal 2012, is sufficient to cover the expected workload for the office over the next two to three years. There will have to be some reductions in the 10-person office staff, he said.

The federal coordinator’s office was established to oversee federal agencies’ responses to permit applications for the pipeline, which would deliver 4 billion cubic feet a day of gas to Alberta, from where it would be shipped on through other pipelines to the continental U.S.

“Whether the federal coordinator’s office has $1 million, $2 million or $3 million, or whether it has eight employees or 10, isn’t going to affect the project. What is going to determine the future of the Alaska gas line is the state’s fiscal system on oil and gas, and the natural gas market,” Persily said.

A glut of shale gas in North American markets has dampened prospects for the large Alaska pipeline. In addition, North Slope gas producers are seeking a long-term fiscal agreement with the state of Alaska before committing to ship gas through a pipeline.

Persily said his plan assumes TransCanada Corp. and ExxonMobil Corp. will proceed with the filing of an application with the U.S. Federal Energy Regulatory Commission for their proposed 48-inch pipeline from Alaska to Alberta next October, as the two companies are required to do under a contract with the state of Alaska, Persily said.

The state of Alaska is contributing $500 million to preliminary engineering and environmental work for the project on the condition that TransCanada and ExxonMobil meet certain performance benchmarks, the most important being the filing of the application to FERC in late 2012.

Although the two companies are contractually committed to continue work on the pipeline to Alberta Alaska, Gov. Sean Parnell has asked TransCanada and ExxonMobil and other North Slope producers to consider a pipeline to a southern Alaska port and an LNG project that would export Alaska gas to Asia.

The alternative LNG project could be done under terms of the existing contract the companies have with the state, which includes the option of LNG instead of an all-land pipeline.

Cost-saving moves will include vacating the federal coordinator’s 13,000-square-foot office in Washington, D.C., which costs $750,000 a year in lease fees, Persily said. The office in Washington will not close, however, and the office in Anchorage will also remain open, he said.

“I expect layoffs and other spending cuts,” Persily said, although there are as yet no details of reductions.

“I don’t think Congress was trying to send a particular message with the cut. They are starting to wonder what is going on, however. Congress passed the loan guarantees, tax breaks, expedited FERC schedule and establishment of our enabling office in 2004. The $1 million, plus our reserves, will get us by until something happens, or not,” Persily said.

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

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-8-2012/Congress-cuts-funding-for-Alaska-federal-gas-coordinator-by-75/#ixzz1icBE0g94

Advice on development; NPC team recommends actions to make best use of Arctic energy resources

2011-12-30T19:48:00.002-09:00

Alan Bailey
Petroleum News

The National Petroleum Council, or NPC, has published a working document containing recommendations to Energy Secretary Steven Chu on federal policies for the development of oil and gas resources in the Arctic regions of North America. With a broad membership from the oil and gas industry, academia, Native American groups, financial organizations and public institutes, and with private funding, the federally chartered NPC provides information and recommendations for the energy secretary on matters relating to oil and gas.

An NPC Arctic subgroup with representatives from several companies involved in the oil and gas industry, including ExxonMobil, Shell, Anadarko Petroleum Corp., Chevron and Schlumberger, prepared the document, the scope of which includes some areas south of the Arctic Circle, where climatic conditions are comparable to those in the Arctic.

Exploration needed

The working document says that exploration needs to proceed now, to begin to validate the huge quantities of oil and gas resources that the U.S. Geological Survey has estimated to exist in Arctic North America. Exploration is especially urgent in Arctic Alaska, to keep oil flowing through the trans-Alaska oil pipeline in viable quantities — low and lowering oil flow rates in the pipeline threaten mechanical problems with pipeline operation as well as economic problems, as the fixed pipeline operational costs become spread over fewer and fewer barrels of oil.
“TAPS (the trans-Alaska pipeline) is a national asset that has successfully delivered billions of barrels of oil to America,” the working document says. “With the current lack of exploration and development in Alaska, this critical asset could be decommissioned sooner than forecast, as the existing North Slope oil fields continue their production decline.”

Regulatory clarity

Access to prospective areas within the U.S. Arctic needs to be encouraged by the removal of regulatory uncertainty and by limiting the endless legal challenges that currently add to that uncertainty, the document says.
“Numerous Arctic producing fields exist around the world, both onshore and offshore, which are operating safely,” the document says. “Technology and practices to prevent and mitigate environmental risks already exist and will continue to be enhanced.”

The document cites the use of low impact Rolligon vehicles and the drilling of extended reach wells as examples of technologies that minimize Arctic environmental impacts. As new Arctic challenges emerge, new innovations will be made — technology will not be a limiting factor in Arctic exploration and development, the document says.

At the same time, a coordinated approach to permitting, as in Norway or Greenland, would lead to more predictable project schedules and eliminate redundant overlaps between the functions of different regulatory agencies.

Insufficient time

Infrequent lease sales, lengthy permitting procedures, a high incidence of litigation and short drilling windows all combine to discourage exploration and field appraisal operations, the document says. And existing 10-year lease terms do not allow sufficient time to ensure sustained exploration and production in Arctic basins, especially in the offshore.
“The realistic drilling window for offshore operations in the Arctic U.S. is typically 70 to 105 days,” the document says. That compares with a typical window of perhaps up to 150 days onshore in the Arctic, and a window of almost 365 days in the Gulf of Mexico. Yet all of these regions have the same 10-year lease terms. Under the current regulatory regime it typically takes four or five years from the first permit application to complete the necessary steps to be able to drill an initial exploration well in an Arctic offshore lease, the document says.

The document recommends the adoption in the United States of a system akin to the use of Canadian discovery licenses — Canada issues a license of this type to an operator that has made a substantial hydrocarbon discovery, to enable the operator to hold a discovered field until can be viably developed, the document says. The U.S. system of lease unitization and development planning can force an operator to abandon leases that are currently uneconomic, even although the constantly changing economic climate may subsequently lead to viability.

Jones Act

The Jones Act, the federal statute that requires all goods carried between U.S. ports to be transported in U.S. flagged ships, causes the United States to lag other nations both in Arctic development and in the deployment of ice breakers, ice-resistant tankers and other Arctic class support vessels, the document says. No equivalent statute exists in Canada, for example.
“While technology exists to find and extract the Arctic energy, a viable solution should be sought to improve the inherent cost premiums associated with complying with the Jones Act,” the document says. “A more reasonable policy would enable the future development of economically sub-marginal and marginal fields.”

The document also questions the current lack of federal oil and gas outer continental shelf revenue sharing with local communities. Given that communities on the North Slope of Alaska are concerned about risks to their livelihoods from offshore oil developments, there needs to be sharing of federal revenues with those communities, the document says.

Tanker use

The document also recommends consideration of the use of ice-resistant oil tankers as a means of transporting oil from the Arctic, rather than building new pipelines across onshore areas with multiple jurisdictions.
“Presently, oil tankering through the Barents Sea is common and this tankering capability is expected to be greatly accelerated in the near future,” the document says. “In the Russian Arctic, ice-breaking oil tankers are being loaded for (oil) export to North American and European markets via an ice-resistant floating storage facility located about as far north of the Arctic Circle as Prudhoe Bay.”

Judge dismisses government’s move to revoke BP’s probation

2011-12-29T13:07:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

U.S. District Court Judge Ralph Beistline dismissed a claim by the U.S. Justice Department that BP had violated terms of a probation order when a field pipeline ruptured and spilled oil in 2009.

BP was on probation over a series of spills in 2006 from Prudhoe Bay field pipelines that were caused by corrosion. The company paid a $20 million penalty over violations resulting from the spills.

The probation had been scheduled to end Nov. 30, 2010. The Justice Department filed its petition for a revocation of the probation Nov. 16, 2010.

In a decision released Dec. 27, Beistline found that BP did not violate terms of the probation and also released the company from probation, which had been scheduled.

Beistline held proceedings in Anchorage from Nov. 29 to Dec. 7 to hear evidence.

The 2009 spill occurred when an 18-inch field pipeline that was not in service but still containing a mixture of produced water and oil froze and ruptured, spilling an oil-water mixture on the tundra. BP cleaned up the oil spill, estimated at 362 barrels, and subsequently repaired the pipe.

In its petition the Justice Department contended that BP should have known about the freezing and blockage earlier than it did, citing a similar problem with a pipeline in 2001, and that better positioning and monitoring of sensors on the L-3 pipeline would have alerted BP to the freeze-up problem.

BP responded that the sensors were installed in 1993 for a different reason — to monitor for problems with handling natural gas in the pipeline.

The government had also claimed BP failed to adequately respond when the no-flow condition of the pipeline was discovered on Nov, 14 and the rupture and spill occurred on Nov. 29.

In his decision, Beistline wrote, “the government has failed to establish by a preponderance of the evidence that BP committed criminal negligence. While the court would prefer a failsafe system where accidents never happen, it recognized that human beings and engineering practices are not perfect and that, on occasion, unexpected or unanticipated accidents can and will happen.”

Beistline concluded BP was in compliance with industry standards in its operation of the L-3 line and that the pipeline alarm systems were operating in line with accepted standards.

The judge also noted that BP conducted a thorough investigation of the 2009 pipe rupture and had shared it with the government.

BP spokesman Steve Rinehart said, “We are pleased with the decision and appreciate the court’s attention. We know that the privilege of working in Alaska comes with a responsibility to maintain high standards. We will continue our commitment to running safe and compliant operations.”

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

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-1-2012/Judge-dismisses-governments-move-to-revoke-BPs-probation/#ixzz1hxpGCVVt

North Slope exploration well count drops; NSB OKs Repsol

2011-12-27T00:48:00.002-09:00

Kay Cashman
Petroleum News

The North Slope Borough Planning Commission’s recent approval of Repsol’s ice pad permits for the coming winter exploration season carries a stipulation that allows no more than three drilling rigs to operate at the same time, even though four drilling pads were approved, effectively dropping the number of total penetrations by Repsol from 12 to nine.

In response to concerns from local residents, prior to the planning commission’s Dec. 15 meeting in Nuiqsut, Repsol had pulled its permit request for the Qugruk-3 pad, reducing its drilling pads from five to four and probable wells from 15 to 12 (see map prepared by Mapmakers in September, prior to that decision, at http://bit.ly/tC1Wev).

The commission approved a fifth pad, but it was for staging ice road construction and drilling operations (not shown on map).

Savant gets rig for half season

Drilling operations have to be complete at Kachemach-1 pad before drilling starts at the single offshore pad in the mix, Qugruk-4, which is the reason for the number of vertical wells, laterals and geologic sidetracks in Repsol’s program dropping to nine, Petroleum News sources say.
When Nabors 9ES rig is done drilling at Kachemach-1 pad, it will be moved to Savant Alaska’s eastern North Slope Red Wolf exploration pad, essentially splitting the short winter season in half.

Kachemach-1 is southwest of Kuparuk, near Meltwater. Except for Qugruk-4 pad north of the Colville unit in the nearshore waters of the Beaufort Sea, all of Repsol’s Qugruk pads are between the Colville River and Kuparuk River units. Following the Dec. 15 commission decision, the fifth rig that Repsol reserved for this winter’s drilling was being considered by Linc Energy for its five to six well program at Umiat, but Linc has reportedly decided to postpone its drilling until next winter, in part because there isn’t enough time to finalize all the details of its program.

The other oil and gas companies that initially wanted to start drilling in January but do not have rigs under contract as of Dec. 22, are Great Bear Petroleum and UltraStar Exploration. (Great Bear is the only one of the 2012 North Slope explorers planning a year-round program and that’s because its proposed four to six drilling pads are in an existing industrial corridor along the Dalton Highway, so the company is not restricted to having to use seasonal ice roads and pads.)

UltraStar has already postponed its well until next winter, but Great Bear’s intentions have been to get a rig for January drilling, so perhaps it will do a deal with Repsol?

Neither company is saying anything at this time, since negotiations, if they exist, would have just begun.

Brooks Range, Pioneer on track

With Nabors 7ES rig under contract, Brooks Range Petroleum Corp.’s plans are still on track to deepen and test its previously drilled North Tarn No. 1 well and to drill two to three appraisal wells, the Mustang No. 1 , 2 and 3, all in the newly formed Southern Miluveach unit on the western boundary of the Kuparuk River unit. (The September Repsol map mentioned above does not show final boundaries for Brooks Range units established by the State of Alaska. See Nov. 6 PN article with current Mapmakers unit map at http://bit.ly/spBC0q.)

With Nabors 27E under contract, Pioneer Natural Resources is still planning to drill two Nuna wells this winter, targeting the Torok formation. Both bottomholes are in the newly expanded Oooguruk unit.

The Alaska Oil and Gas Conservation Commission defines the wells as exploratory because they will be drilled to discover or delineate a new pool.

Following is the current well count estimate for 2012 exploration and evaluation wells, with 22 penetrations on the low side and 27 on the high side:

• Brooks Range Petroleum: 1 rig, 2-3 wells

• Great Bear Petroleum: 1 rig, 4-6 vertical wells + 4-6 laterals/sidetracks

• Pioneer 1 rig, 2 wells

• Repsol: 3.5 rigs, 9 wells, including sidetracks and laterals

• Savant 0.5 rig, 1 well

Conoco sees construction of CD-5 project in 2014, production in 2015

2011-12-26T12:37:00.002-09:00

Tim Bradner
Alaska Journal of Commerce

ConocoPhillips Alaska Inc. will seek corporate approval in the second half of 2012 to proceed with development of the long-delayed $600 million CD-5 project following the U.S. Army Corps of Engineers’ approval of a Colville River bridge permit Dec. 19.

The bridge crossing of the river will allow the company to develop the CD-5 oil accumulation in the National Petroleum Reserve-Alaska.

There were a stipulations attached to the permit.

“We will be evaluating the permit and the stipulations over the next couple of months, and we will then have to incorporate the stipulations into our CD-5 work plan,” ConocoPhillips spokeswoman Natalie Lowman said.

The company will seek corporate approval in the last half of the year, and will then spend about a year in engineering and planning, Lowman said. The schedule would have construction under way in 2014 and the first production from CD-5 – the first commercial oil production from the NPR-A since it was created in 1923 – toward the end of 2015, she said.

CD-5 is expected to produce between 10,000 and 18,000 barrels per day. ConocoPhillips owns 78 percent of the Alpine field, including the CD-5 project, with a 22 percent minority holding by Anadarko Petroleum Co.

Although CD-5 is within NPR-A the subsurface mineral rights are owned by Arctic Slope Regional Corp., the Alaska Native regional corporation owned by Inuit people on the Arctic Slope, which would receive production royalties. Under federal law, however, those are shared 50-50 with the state of Alaska.

An important element in the Corps’ CD-5 decision is that the bridge and road infrastructure would ease the extension of road infrastructure to two other ConocoPhillips oil and gas discoveries farther west in NPR-A that are now part of the Mooth’s Tooth Unit in the reserve.

Phillips said the development of the two NPR-A discoveries farther west would depend on the state of Alaska’s modification of its oil production tax. Although the federal government owns the petroleum reserve, the state’s petroleum tax applies to production from the area.

In a statement issued Dec. 20, Alaska state U.S. Bureau of Land Management Director Bud Cribley hailed the Corps’ decision on the bridge permit, which was originally contested by Interior Department wildlife agencies and the U.S. Environmental Protection Agency, as an example of government and industry working together to find solutions to complex environmental permitting problems.

CD-5 was discovered in 2001 and an Environmental Impact Statement for its development, including the bridge, was approved in 2004. The project went on hold for several years while there were negotiations with local Inuit villagers over the location of the bridge. An agreement was eventually reached to change the bridge location so it would not affect subsistence fishing by the villagers.

The project was then delayed further by the Corps’ decision against the bridge permit, although it had been approved earlier in the EIS.

The concern expressed to the Corps by the U.S. Fish and Wildlife Service and the EPA was that the bridge would require extensive gravel placement that could impair wetlands and sensitive regional waterfowl habitat.

Also, the environmental agencies worried that an east-west road configuration that would result in further NPR-A development west of CD-5 would cut laterally across the northward flow of water in the wetland area, further impairing habitat.

At the urging of the two agencies, the Corps blocked the bridge permit and suggested ConocoPhillips build an underground river crossing for a pipeline and to provide support for CD-5 development by ice road in winter and by air in summer, similar to the way ConocoPhillips has developed other drillsites in the region that are cut off from road access by river channels.

ConocoPhillips and state of Alaska agencies protested the Corps’ decision, arguing that an underground pipeline crossing would create more potential hazard because of the three-phase flow through the pipeline of raw crude, gas and water could create corrosion. Above-ground pipeline on a bridge would be easier to inspect and maintain, it was argued.

After a lengthy review, the Corps agreed with that argument, along with the EPA and U.S. Fish and Wildlife Service.

Among conditions attached to the permit is a requirement that other companies be able to use the bridge for NPR-A development.

“Over the long term, the bridge at CD-5 will minimize environmental impacts in the area because it allows other companies that develop leases in the NPR-A to use the same crossing, rather than seek approval for additional channel crossings in the area,” BLM Director Cribley said in his statement.

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

This article appears in the AJOC December 25 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-25-2011/Conoco-sees-construction-of-CD-5-project-in-2014-production-in-2015/#ixzz1hg9ks2He

Alaska’s economy expected to muddle along in 2012

2011-12-23T10:08:00.000-09:00

Tim Bradner
Alaska Journal of Commerce

Alaska’s economy is doing OK, muddling along, but here are key things to watch for in 2012:

• Oil prices. State Department of Revenue petroleum economists expect prices to remain strong through 2012 and 2013 at about the current $100 per barrel-plus, but continued weakness in the U.S. and world economy could bring softer prices.

That’s good for consumers – especially at the gas pump – but bad news for the state treasury. Declining oil production is expected to cause a $700 million decline in state revenues next year even if oil prices remain at current levels, and any softening of prices will cause the slide in revenues to accelerate.

Oil pays for about 90 percent of the state budget, and directly and indirectly accounts for a third of the state’s economic activity, according to University of Alaska studies.

Oil industry activity is expected to remain stable, although new projects in the existing producing fields will be down. This should be offset to some degree by expanded exploration drilling this winter, however. The industry will watch closely possible actions in the state Legislature in early 2012 in making adjustments in the state oil production tax. If changes are made it would stimulate activity in the large producing fields.

• State of Alaska. State spending is a major driver in the state’s economy and despite some uncertainty over oil revenues, the state operating and capital budgets are expected to be at ranges similar to the current year. Gov. Sean Parnell’s proposed capital budget released Dec. 15 reflects a $600 million reduction from the current year capital budget, but Parnell said he has “left room” in the capital budget for the Legislature to make additions, which it will surely do.

The capital budget usually totals several billion dollars and is spent mainly on construction. It is important to the state’s construction industry.

• Federal cuts. The federal government accounts for about a third of Alaska’s economy, and federal installations and programs are expected to be hit with budget reductions as Congress tries to rein in spending and reduce massive deficits.

• Mining activity. Minerals development is expected to remain strong, although metals prices – particularly for metals like gold, silver and zinc now produced in Alaska – may be volatile amid continued weakness in the economy. Alaska’s major producing mines are producing at expected levels and several new mines are in advanced stages of development.

Mining developments to watch include the large gold project at Donlin Creek being developed by Donlin Gold, a joint venture of Barrick Gold and NovaGold Resources; the International Tower Hills gold project near Livengood, north of Fairbanks; the large Pebble copper/gold project near Illiamna, southwest of Anchorage; and the Niblack multi-metals project near Ketchikan, in Southeast Alaska.

The Donlin Gold partners are expected to file for long-planned environmental permits in April 2012. A key factor will be a source of energy for the project. The current plan is for a natural gas pipeline to be built from Southcentral Alaska. Donlin Gold project is on land owned by Calista Corp. and The Kuskokwim Corp.

International Tower Hills is now finalizing a pre-feasibility study for its Livengood gold project, an important milestone. If the project moves to development it would be a large surface mine similar.,, and possibly larger, than the Fort Knox gold mine northeast of Fairbanks, which is now producing. Power supply is important to International Tower Hills also, and the current plan is for a long-distance electrical transmission line to be built to the mine from Fairbanks along the Elliot Highway.

Golden Valley Electric Association, the Interior electric cooperative, would supply power to the Livengood mine as it does to Fort Knox.

Pebble project partners Anglo American and Northern Dynasty Minerals are engaged in planning and continued environmental studies. At Niblack, project developers are in advanced stages of exploration to expand the base of confirmed resources. If that mine moves to development, it would be similar to the producing Greens Creek Mine near Juneau.

• Fisheries. This sector continues to be an important, traditional industry for Alaska. The annual salmon harvest always has surprises, but the estimates now are for the big Bristol Bay harvest to be similar to 2011; upper Cook Inlet to be better, and Southeast harvests, mainly of pink salmon, to be lower that this year.

The big groundfish offshore fisheries are generally stable. The Bering Sea pollock harvest is expected to be about the same as this year, and Bering Sea cod catches will be up. In the Gulf of Alaska pollock catches will be up. The winter snow crab fishery will see a nice bump in allowable catches to the highest allowable harvests in years.

Halibut catches will be down statewide as regulators restrict harvests to help the biomass rebuild, although the Southeast allowable catch will be up a little from this year. The restrictions will affect commercial harvesters as well as sports fish charter operators for whom halibut fishing is a big draw for clients.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-25-2011/Alaskas-economy-expected-to-muddle-along-in-2012/#ixzz1hO0VuP22

Year in Review: Oil kept Alaska going

2011-12-20T00:11:00.003-09:00

Tim Bradner
Alaska Journal of Commerce

It’s been a good 2011 for Alaska, all things considering. We could be like most other U.S. states, bogged down in recession. Thanks mainly to oil, we’re not.

Looking at the good things first, the number of people working in Alaska continues to gradually increase. State government is wallowing in oil revenues, with North Slope crude oil prices surpassing $100 per barrel.

The state is spending that money, too. Multi-billion-dollar state capital budgets in recent years are helping the state’s construction industry. Despite the pinch of a high state petroleum tax, spending by the industry – and employment – continues to be strong, although the bulk of that is on maintenance, not projects that will produce more oil.

Beyond this and possibly into next year, however, there could be trouble brewing for petroleum. The combination of a steady 6 percent annual decline in production and 10 percent or more increase in the state budget means that big cutbacks in state spending are on the horizon unless there are very large new discoveries of oil very soon on state-owned lands.

Still on the oil front, a positive note is a surge in new exploration drilling on the North Slope this winter, which is reassuring after several years of low activity. But a cautionary note is that most of the exploration is being done by one company, Repsol, and the state is also paying for a half or more of exploration expenses through an incentive program. Also, the exploring companies — including Repsol — believe any discoveries they make will be modest in size.

If Shell and other companies get the go-ahead to explore federally owned Arctic offshore waters the discoveries could be large enough to stop the decline of oil moving through the trans-Alaska oil pipeline, but they will not contribute to state revenues.

In Cook Inlet, explorers are finding new natural gas deposits, which geologists have predicted, somewhat allaying fears of a gas shortage in Southcentral Alaska. Two of the three new discoveries made in 2011 need to be fully tested, but even if modestly successful they will make a big contribution toward security of gas supplies.

Alaska’s other industries appear steady or growing.

Mining

Mining is a real bright spot, with metals prices at high levels. Mineral exploration has increased sharply and several major new mines are in advanced stages of development planning, among them the big Donlin Creek gold project near the Kuskokwim River and International Tower Hills’ gold project near Livengood, north of Fairbanks. These projects haven’t been given approval by their owners or government regulators, but things are looking good for them.

Work also continues on the big Pebble gold/copper project near Illiamna. It will still be several years before a development decision is made, but if Pebble, which is a very large deposit, becomes a mine it will be a major economic boost to the state and Southwest Alaska, an economically depressed region. People in some local communities have concerns over environmental effects of the mine, and state and federal regulatory agencies are certain to give the project applications a through review when they are made.

New mine development will have positive economic benefits to the regions in which the mines are located, and operating mines make substantial and solid contributions to local government revenues if the mines are located within municipalities. However, mines cannot afford to pay the kind of taxes to the state government that oil producers pay.

Tourism

Tourism was better in 2011, back on the growth track after a sharp dip in 2009 caused by the national recession. Visitor numbers were up for cruise visitors, which is the engine that drives much of the Alaska tourism industry, and for independent travelers who typically fly to Alaska and make their own tour and hotel arrangements.

The visitor industry is highly seasonal and while it makes a nice contribution to local employment and municipal revenues, the industry is always subject to the uncertainties of the national and worldwide economy. There is also formidable competition from other tourist destinations including other states, which are easier to reach, and although Alaska has always had an allure pocketbook realities often have the final say. Costs for tour operators, particularly fuel, are also high in Alaska.

Fisheries and seafood

Fisheries, one of Alaska’s traditional industries, are growing. There was a good salmon harvest in 2011 and salmon prices are up significantly, which translates into more income for salmon harvesters and more shared fisheries tax revenue for coastal communities. The offshore ground fish industry appears stable. This industry, mostly involving the harvest of pollock and cod, works in federal waters off Alaska’s shores are relies on shore-based infrastructure and support services in coastal communities.

Fish harvests are subject to the uncertainties of nature, but Alaska fisheries regulators and their federal counterparts in the big offshore fisheries have good reputations for strict management to maintain the biological health of the fisheries. The numbers of fish caught will vary from year to year, sometimes in big swings, but there will always be fish.

The increasing demand for Alaska’s seafood is impressive. Domestic and international buyers seem to have really caught onto consumers’ interest in wild-caught fish, which are free of chemicals and contaminants found in many farmed fish, and this has helped push demand, and prices, upward. The surge in sales of fresh salmon from Alaska during the harvest season is a result of this trend.

Also, the economic growth in big emerging markets, particularly China, has led to a desire for more protein in diets, which has also pushed up demand for lower-value Alaska fish like pink salmon. Pink salmon prices are at high levels this year, and much of the harvest is being exported to China.

Federal spending

A major worry on the horizon for Alaska, however, is the real possibility of big cuts in federal spending. Money from the federal government, for military bases and a plethora of programs, constitutes about a third of the state’s economy (oil accounts for another third and everything else fills in the final third), according to University of Alaska studies.

As the national government deals with its deficits, cuts in spending are almost sure to be part of the agenda and Alaska will feel this more than elsewhere because the federal government presence in Alaska is bigger, on a proportional basis, than in most other states.

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

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-18-2011/Year-in-Review-Oil-kept-Alaska-going/#ixzz1h42E4dIx

Senator Murkowski speaks on air quality authority transfer 12/15/11

2011-12-17T06:12:00.001-09:00

State predicts oil production to drop to 574,000 barrels per day in fiscal 2012

2011-12-16T17:29:00.002-09:00

By Tim Bradner
Alaska Journal of Commerce

The state revenue department estimates that oil production will decline to an average of 574,000 barrels per day for the state’s current fiscal year, 2012, from an average 603,000 barrels per day in fiscal 2011, the financial year which concluded June 30, according to the state’s annual production forecast released Thursday.

The expected rate of decline is 4.7 percent between fiscals 2011 and 2012.

The forecast is for a further decline to an average of 555,000 barrels a day for fiscal year 2013, which begins July 2012, the department said. This assumes a production decline rate of 3.3 percent.

However, state Revenue Commissioner Byran Butcher warned that the production decline could be more severe, because the department assumes that some projects now being evaluated or planned will actually move to production.

“Without these layers (of new production) the production decline could be as high as 9.1 percent,” instead of 4.7 percent, Butcher said in his letter to Gov. Sean Parnell, which accompanied the revenue forecast.

Between fiscals 2010 and 2011, production declined at 6.3 percent, Butcher said.

“The forecast includes a much greater decline from the currently producing sectors offset by potential new development from projects now under development or under evaluation. Most of the opportunities to add production are from continued satellite (field) development at Alpine, at the Nanuq and Alpine West satellites, continued developments of the Oooguruk and Nikaitchuq fields and expanded viscous or heavy oil development,” such as in the Orion satellite of the Prudhoe Bay field, Butcher said in the letter.

The Oooguruk field is operated by Pioneer Natural Resources while Nikaitchuq is operated by Eni Oil and Gas. The Alpine field is operated by ConocoPhillips.

If production rates do drop to the 550,000 barrels per day average in fiscal 2013, they are in the range where Alyeska Pipeline Service Co. has predicted operating problems with the Trans-Alaska Pipeline System. Alyeska said there are likely to be more unexpected winter shutdowns, such as occurred over a one-week period last January, as throughput continued to drop.

The pipeline company is taking steps to deal with the lower throughput issues, including the addition of heaters at critical points along the 800-mile pipeline, Alyeska President Tom Barrett has said previously.

In terms of revenues, high oil prices will push total Alaska revenues to $8.9 billion for 2012, a $1.1 billion increase over revenues in fiscal 2011, but the forecast for 2013 is for a moderation of income to $8.2 billion due mainly to expectations of lower production.

The revenue department expects ANS crude oil sales prices to average $109.33 per barrel in fiscal 2012 and remain basically stable through 2013 at $109.47 per barrel, according to the forecast.

Oil production taxes and royalties provide 90 percent of total state revenues, the revenue department said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-18-2011/State-predicts-oil-production-to-drop-to-574000-barrels-per-day-in-fiscal-2012/#ixzz1gksXYHY4

ANS production down; Revenue says production will drop below 600,000 bpd this fiscal year

2011-12-16T17:15:00.001-09:00

Kristen Nelson
Petroleum News

The Alaska Department of Revenue’s fall forecast, released Dec. 15 as Petroleum News was going to press with this issue, shows a sharp decrease in forecast production compared to the spring forecast, with Alaska North Slope crude oil volumes dropping below 600,000 barrels per day beginning in the current fiscal year, 2012. In the spring forecast, Revenue was projecting production of more than 600,000 bpd through fiscal year 2017.

Production is projected to average 574,000 bpd for FY 2012, dropping below the 500,000 bpd mark in FY 2020.

In his cover letter to the governor, Revenue Commissioner Bryan Butcher said North Slope production declined 6.3 percent in fiscal year 2011 and a decline of another 4.7 percent is expected in FY 2012, “assuming that the oil production included in the ‘under development’ and ‘under evaluation’ layers of our production forecast come to fruition.”

Without those layers, the FY 2012 decline could be as high as 9.1 percent, he said. For FY 2012, Revenue shows 26,000 bpd under development and 1,000 bpd under evaluation.

In a press release on the forecast Butcher said, “Alaska’s revenue outlook is strong and relatively stable this year due mostly to continued high oil prices,” but warned of the impacts of steadily declining oil production.

New oil is a crucial part of the department’s ANS forecast, accounting for 4.6 percent in FY 2012 and rising steeply to 47.2 percent of ANS production in FY 2021.

Butcher contrasted production forecasts by Revenue in fall 2007, shortly after the passages of ACES, or Alaska’s Clear and Equitable Share, when Revenue was projecting “that ANS production in 2012 would be 675,000 barrels per day. Four years later our production forecast has changed, with 100,000 fewer barrels per day anticipated in FY 2012,” he said.

Spring vs. fall

There is also a difference between what Revenue projected last spring and its fall forecast.

The final year of the spring forecast, FY 2020, shows production of 530,000 bpd; the fall forecast shows projected production dropping to 486,000 — the first projection below 500,000 bpd — in FY 2020.

One change between spring and fall is when production is expected from BP Exploration (Alaska)’s Liberty prospect east of Endicott and from ConocoPhillips Alaska’s west side CD-5 project in the National Petroleum Reserve Alaska.

In the spring, Liberty production was shown as beginning in FY 2013. The fall forecast wraps Liberty into an offshore category which includes Northstar, Liberty, Nikaitchuq and Oooguruk, and while Liberty isn’t noted separately, the first uptick in production from the offshore category comes in FY 2016, peaking in 2017. The spring forecast showed a similar pattern, with Liberty production beginning in one year and peaking in the next and the uptick volumes are similar to standalone Liberty forecast from the spring forecast, which showed a peak of 39,000 bpd.

NPR-A production, shown in the spring forecast as beginning in FY 2015, is shown in the fall forecast as beginning in 2017 and peaking in FY 2019.

Kuparuk production the same

For producing fields, only the Kuparuk forecast remains the same, 87,000 bpd in FY 2012, dropping down through 83,000 and 81,000 bpd in FY 2014, with some differences in the out years, but nothing substantial.

Prudhoe Bay stood by itself in the spring forecast; in the fall forecast it includes production from Milne Point, so while Prudhoe numbers would appear to be up, they are actually down compared to the combined Prudhoe-Milne spring forecasts.

Prudhoe is forecast to produce 276,000 bpd in FY 2012, down from 297,000 in the spring forecast. The FY 2013 fall forecast shows 269,000 bpd, down from 284,000 in the spring forecast; the downward trend (both overall and compared to the spring forecast) continues through 2020, the last comparison year.

Prudhoe Bay satellites are also forecast to produce less in the fall forecast, from 37,000 bpd in 2012 to 16,000 bpd in 2020 in the spring forecast down to 36,000 bpd for 2012 in the fall forecast and dropping off to 18,000 bpd in 2020 in the fall forecast compared to 27,000 bpd in the spring forecast.

ANS price up

While Revenue’s production forecast is down from last spring, the price forecast is up.

In the spring, Revenue projected Alaska North Slope on the West Coast at $94.70 a barrel for fiscal year 2012; the fall forecast estimates $109.33.

Revenue’s ANS West Coast price forecast is $109.47 a barrel for FY 2013 (compared to $95.79 in the spring); this fall’s forecast continues above the level forecast in the spring through FY 2016, when the trend reverses and the fall forecast drops below the spring forecast through FY 2021, the end of the forecast period shown in the fall forecast.

The fall West Texas Intermediate price forecast is below the spring forecast with the exception of FY 2014.

2011-12-16T17:13:00.000-09:00

ANS production down

Revenue says production will drop below 600,000 bpd this fiscal year

Kristen Nelson

Petroleum News

The Alaska Department of Revenue’s fall forecast, released Dec. 15 as Petroleum News was going to press with this issue, shows a sharp decrease in forecast production compared to the spring forecast, with Alaska North Slope crude oil volumes dropping below 600,000 barrels per day beginning in the current fiscal year, 2012. In the spring forecast, Revenue was projecting production of more than 600,000 bpd through fiscal year 2017.

Production is projected to average 574,000 bpd for FY 2012, dropping below the 500,000 bpd mark in FY 2020.

In his cover letter to the governor, Revenue Commissioner Bryan Butcher said North Slope production declined 6.3 percent in fiscal year 2011 and a decline of another 4.7 percent is expected in FY 2012, “assuming that the oil production included in the ‘under development’ and ‘under evaluation’ layers of our production forecast come to fruition.”

Without those layers, the FY 2012 decline could be as high as 9.1 percent, he said. For FY 2012, Revenue shows 26,000 bpd under development and 1,000 bpd under evaluation.

In a press release on the forecast Butcher said, “Alaska’s revenue outlook is strong and relatively stable this year due mostly to continued high oil prices,” but warned of the impacts of steadily declining oil production.

New oil is a crucial part of the department’s ANS forecast, accounting for 4.6 percent in FY 2012 and rising steeply to 47.2 percent of ANS production in FY 2021.

Butcher contrasted production forecasts by Revenue in fall 2007, shortly after the passages of ACES, or Alaska’s Clear and Equitable Share, when Revenue was projecting “that ANS production in 2012 would be 675,000 barrels per day. Four years later our production forecast has changed, with 100,000 fewer barrels per day anticipated in FY 2012,” he said.

Spring vs. fall

There is also a difference between what Revenue projected last spring and its fall forecast.

The final year of the spring forecast, FY 2020, shows production of 530,000 bpd; the fall forecast shows projected production dropping to 486,000 — the first projection below 500,000 bpd — in FY 2020.

One change between spring and fall is when production is expected from BP Exploration (Alaska)’s Liberty prospect east of Endicott and from ConocoPhillips Alaska’s west side CD-5 project in the National Petroleum Reserve Alaska.

In the spring, Liberty production was shown as beginning in FY 2013. The fall forecast wraps Liberty into an offshore category which includes Northstar, Liberty, Nikaitchuq and Oooguruk, and while Liberty isn’t noted separately, the first uptick in production from the offshore category comes in FY 2016, peaking in 2017. The spring forecast showed a similar pattern, with Liberty production beginning in one year and peaking in the next and the uptick volumes are similar to standalone Liberty forecast from the spring forecast, which showed a peak of 39,000 bpd.

NPR-A production, shown in the spring forecast as beginning in FY 2015, is shown in the fall forecast as beginning in 2017 and peaking in FY 2019.

Kuparuk production the same

For producing fields, only the Kuparuk forecast remains the same, 87,000 bpd in FY 2012, dropping down through 83,000 and 81,000 bpd in FY 2014, with some differences in the out years, but nothing substantial.

Prudhoe Bay stood by itself in the spring forecast; in the fall forecast it includes production from Milne Point, so while Prudhoe numbers would appear to be up, they are actually down compared to the combined Prudhoe-Milne spring forecasts.

Prudhoe is forecast to produce 276,000 bpd in FY 2012, down from 297,000 in the spring forecast. The FY 2013 fall forecast shows 269,000 bpd, down from 284,000 in the spring forecast; the downward trend (both overall and compared to the spring forecast) continues through 2020, the last comparison year.

Prudhoe Bay satellites are also forecast to produce less in the fall forecast, from 37,000 bpd in 2012 to 16,000 bpd in 2020 in the spring forecast down to 36,000 bpd for 2012 in the fall forecast and dropping off to 18,000 bpd in 2020 in the fall forecast compared to 27,000 bpd in the spring forecast.

ANS price up

While Revenue’s production forecast is down from last spring, the price forecast is up.

In the spring, Revenue projected Alaska North Slope on the West Coast at $94.70 a barrel for fiscal year 2012; the fall forecast estimates $109.33.

Revenue’s ANS West Coast price forecast is $109.47 a barrel for FY 2013 (compared to $95.79 in the spring); this fall’s forecast continues above the level forecast in the spring through FY 2016, when the trend reverses and the fall forecast drops below the spring forecast through FY 2021, the end of the forecast period shown in the fall forecast.

The fall West Texas Intermediate price forecast is below the spring forecast with the exception of FY 2014.

Agencies agree on bridge; Corps of Engineers decision this year

2011-12-10T04:01:00.001-09:00

—Kristen Nelson

A roadblock to development of ConocoPhillips’ CD-5 drill site in the National Petroleum Reserve-Alaska has been removed.

The U.S. Fish & Wildlife Service and the Environmental Protection Agency, which had opposed the company’s plan to put the crude oil pipeline from CD-5 to the company’s Alpine production facilities on a bridge to be built across the Nigliq Channel of the Colville River, have reached “an agreement in principle” with the company on the proposal.

In a Dec. 5 announcement the U.S. Department of the Interior said the agreement fulfills a request from the U.S. Army Corps of Engineers that the agencies evaluate environmental impacts associated with the revised project.

Interior said the agreement in principle confirms that construction of a pipeline and bridge over the Nigliq Channel is acceptable to Fish and Wildlife and EPA “so long as the permit application includes conditions that reflect agreements reached” among ConocoPhillips, Fish and Wildlife and EPA.

“The conditions include engineering changes and substantial mitigation proposed by the company based on consultations with the resource agencies,” Interior said.

ConocoPhillips has also agreed to allow other companies that develop leases in NPR-A to use the same crossing, “rather than seek approval for additional channel crossings in the area. This approach will reduce the environmental impacts” associated with future developments west of the Colville River, Interior said.

Interior said the corps is expected to carry out remaining steps associated with the permit review in the coming weeks.

Pat Richardson, spokeswoman for the corps’ Alaska District, told Petroleum News in an email that the corps’ goal “is to have a decision this month.” She said the corps received additional information from ConocoPhillips as late as Thanksgiving week and that information must be analyzed.

“ConocoPhillips sees this as a positive step in the process of granting the Section 404 permit for the CD5 project,” ConocoPhillips Alaska spokeswoman Natalie Lowman said in a Dec. 5 email. “We have not yet seen the permit nor its conditions, but we are encouraged by today’s announcement.”

Bridge vs. HDD

The current permitting process came to a standstill in February 2010 when the corps denied ConocoPhillips Alaska permits to develop the CD-5 project, citing overriding national interests, specifically concerns about “further impacts to the aquatic resources” in the Colville River Delta, which lies just east of NPR-A.

The preferred alternative in the 2004 environmental impact statement for Alpine satellite development included a bridge and a road.

After facing local opposition over the location of the Nigliq Channel bridge in an earlier proposal, ConocoPhillips had reached resolution on local concerns about the project with changes in bridge location and an agreement to fund a road to connect the nearby community of Nuiqsut to the project’s road system, and had local support for the project.

The corps said it had determined that the pipeline should be buried under the Nigliq Channel using horizontal directional drilling, but noted that would require new permit applications.

EPA and Fish & Wildlife both opposed granting the permits.

EPA told the corps it had determined that the Colville River Delta is an aquatic resource of national importance, triggering action under a 1992 memorandum of understanding between EPA and the Department of the Army. Fish & Wildlife also told the corps it had found the delta to be an aquatic resource of national importance, and also cited a memorandum of understanding with the corps.

The CD-5 drilling pad, on the other side of the Nigliq Channel from the Alpine facilities, is not in the Colville River Delta, but 2.5 miles of the road back to Alpine and the bridges (the Nigliq Channel crossing and two smaller bridges) would be.

State opposed HDD

The State of Alaska opposed horizontal directional drilling under the Nigliq Channel, and has backed ConocoPhillips’ bridge and road proposal.

“We believe the state’s input and advocacy helped in achieving this positive outcome, and we will continue to monitor this project through the permitting process,” Alaska Gov. Sean Parnell said in a statement following Interior’s announcement.

The governor noted that the state has demonstrated in reports that the corps’ preferred alternative, buried pipelines under the Nigliq Channel, was not the least environmentally damaging alternative.

“This agreement is long overdue, but no less welcomed,” said Sen. Lisa Murkowski, R-Alaska, in a Dec. 5 statement. She said she expects the corps to now move quickly to approve the proposed bridge “and allow access to the oil and natural gas reserves within the National Petroleum Reserve.”

The senator said that she has “had numerous disagreements with the administration on Alaska issues, but I appreciate the involvement of the White House and the Interior Department in removing this particular roadblock to improving our nation’s energy security.

Murkowski noted, as she has in the past, that EPA, “without public notice or process, designated the Colville River as an Aquatic Resource of National Importance (ARNI).”

Congressman Don Young, R-Alaska, said he welcomed the announcement, but “the fact of the matter is that this should have happened sooner.” He noted the importance of the CD-5 project not only for Alaska jobs, “but also because it will put this nation on a path towards becoming energy independent.”

“This is a great way to ring in the holiday season at a time when Alaska’s oil and gas industry needs to hear some good news on the development front,” said Sen. Mark Begich, D-Alaska,

“It’s been a long and sometimes frustrating process to get to this decision,” Begich said. “I commend ConocoPhillips and the Interior Department for sticking with it.”

$25 million day; State, Bureau of Land Management, hold North Slope, Beaufort, NPR-A sales

2011-12-10T03:56:00.001-09:00

Kristen Nelson
Petroleum News

The State of Alaska and the U.S. Department of the Interior’s Bureau of Land Management both held Alaska oil and gas lease sales Dec. 7 in Anchorage, with apparent high bids of $24,606,947 from a combination of new entrants and established players.

BLM’s National Petroleum Reserve-Alaska sale, the smallest of the sales, had 20 bids on 17 tracts by three bidders, for a total of apparent high bids of $3,637,477 on some 119,987 acres.

The Alaska Department of Natural Resources’ Division of Oil and Gas held three areawide oil and gas lease sales — Beaufort Sea, North Slope and North Slope Foothills. The state received no bids for the Foothills sale. It received 89 bids on 78 tracts from 11 bidders or bidding groups in the Beaufort Sea sale, a total of $6,874,656.80 in apparent high bids, with 281,095 acres sold. In the North Slope areawide sale, the state received 220 bids on 179 tracts from 13 bidders or bidding groups, for $14,094,812.47 in apparent high bids on 335,289 acres.

Presidential direction

The BLM sale was held in response to a May 14 direction from President Obama to Interior to conduct annual oil and gas lease sales in NPR-A.

In a release on sale results Interior noted that the sale followed the announcement that two federal agencies have reached agreement with ConocoPhillips on the proposed Alpine satellite development plan in NPR-A (see page 1 story in this issue). Interior said the bridge over the Nigliq Channel of the Colville River and the road between the proposed CD-5 drill site and the Alpine facilities would be the first pipeline and all-weather road into NPR-A, and said the existence of that infrastructure is expected to spur further exploration and development in the reserve.

“As industry begins to build infrastructure and explore and develop oil and gas in this area of the North Slope of Alaska, we expect to harness the energy and economic benefits of the NPR-A for our nation,” Interior Secretary Ken Salazar said in a statement.

Interior said the State of Alaska would receive 50 percent of the NPR-A bid receipts, some $1.8 million, as well as 50 percent of the annual rental revenue generated from the sale. An economic evaluation of the NPR-A bids is the next step; BLM expects to issue leases by mid-April.

BLM Alaska Deputy Director Ted Murphy said after reading bids that next year’s NPR-A sale would also be in the fourth quarter.

This was the sixth largest North Slope lease sale the state has held and the second largest since the areawide leasing program was begun in 1998. In recent years, only the 2006 sale ($15.7 million) was larger.

Gov. Sean Parnell said the combined North Slope and Beaufort sales, more than $21 million, was one of the most successful in recent Alaska history, and called it “an important, positive step that attracted additional investment to the North Slope.”

“Reversing the declining flow of oil through TAPS and getting to 1 million barrels per day is critical to our economy and the nation’s energy security,” the governor said in a statement following the sale.

“It was quite a respectable showing,” Commissioner of Natural Resources Dan Sullivan told Petroleum News after the sales.

He said the bids showed “there is more interest in the shale than just Great Bear,” and said he was pleased to see “very big world-class companies who know Alaska well were taking some pretty sizeable positions — Repsol, Shell, ConocoPhillips, Pioneer, Armstrong.”

“We participated in scores of meeting with oil and gas companies, investors, policy makers (leading up to the sale). … Certainly learned a lot. I would say there were some companies that I thought would show up who didn’t. It’s always hard to know why. … Perhaps high costs, but I am just speculating … tax reform, some companies might be waiting it out.”

There were no bids in the North Slope Foothills sale, and Sullivan said that was probably due to the lack of a gas pipeline.

“We’ve been relentlessly working the governor’s five-point plan, and we’ll keep on working it,” Sullivan said. “This is just the first inning of a long term strategy. … Here is the issue: We recognize the status quo is not working. A critical part of our five-point plan is tax reform. We’re going to work hard on that during the upcoming legislative session. Very hard.”

70 & 148, ConocoPhillips

Armstrong subsidiary 70 & 148 LLC bid the most across all the sales: high bids of $2,149,580.80 in the state North Slope sale (11 tracts, 37,120 acres) and $2,701,636 in the NPR-A sale (11 tracts, 62,044 acres), for a total of more than $4.8 million.

In the NPR-A sale, 70 & 148 took tracts between the ConocoPhillips Alaska-operated Greater Mooses Tooth unit and the border of state lands, matching up with the 11 tracts the company took in the North Slope sale, giving the company a substantial block across the state-NPR-A boundary.

ConocoPhillips Alaska, bidding in all three sales, took 35 tracts in the North Slope sale, 99,840 acres for $2,717,424 in apparent high bids, with the bulk of the tracts in a large block south of Point Thomson and Badami on the east side.

In NPR-A, the company took three tracts, 23,650 acres, with apparent high bids of $524,325, bringing the company’s total to more than $3.2 million for the day. The NPR-A tracts are: a tract south of company-held acreage adjacent to its Greater Mooses Tooth unit; one tract adjacent to three state tracts it holds across the NPR-A border south of Nuiqsut; and a tract which was a “hole” in a large block of acreage the company holds southwest of Mooses Tooth.

ConocoPhillips bid unsuccessfully in partnership with Exxon on one tract in the Beaufort Sea sale.

Repsol, Great Bear
Repsol E&P bid in both the North Slope and Beaufort sales

In the Beaufort sale, Repsol was apparent high bidder on five tracts adjacent to a large block of Repsol leases north of the Colville River unit, some 19,200 acres, for which it bid $376,256.

In the North Slope sale Repsol took 26 tracts, 45,920 acres, for $2,642,193.60, bringing its total to just over $3 million.

The North Slope tracts Repsol took are in two blocks, one in the central North Slope, adjacent to existing Repsol leases south of Kuparuk, and the second block adjacent to existing Repsol leases south of Kuparuk and Prudhoe Bay.

Great Bear Petroleum, which bid only in the North Slope sale, had $2,910,633.60 in apparent high bids on 32 tracts, filling in a “hole” in tracts the company took south of Kuparuk in last year’s North Slope sale.

Royale Energy

Royale Energy, a new bidder in the state, took 60 tracts in the North Slope sale with apparent high bids of $2,717,424 on 99,840 acres.

Royale took tracts in three areas: east of Great Bear Petroleum’s existing acreage; south of Great Bear acreage; and a large block of leases near the border with NPR-A.

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

Shell Offshore, bidding in the Beaufort Sea sale, took 18 leases in Harrison bay, 86,400 acres, for $2,615,200.

A bidding group of Daniel K. Donkel 25 percent and Samuel H. Cade 75 percent, took 35 leases in the Beaufort Sea sale from north of the Arctic National Wildlife Refuge (near existing Donkel-Cade leases) on the east to Simpson Lagoon north of Milne Point on the central North Slope, 94,080 acres, for $1,525,760 in apparent high bids. Cade also took a single lease, adjacent to BP’s Northstar unit, 1,920 acres, $21,120.

Donkel and Cade also took three tracts in the North Slope sale, 7,680 acres, for $171,520, bringing their total for the sale to more than $1.7 million.

NordAq Energy, Cook Inlet leaseholder and explorer, took 11 tracts in Smith Bay off NPR-A in the Beaufort Sea sale, 58,880 acres for $1,356,902.40.

Woodstone Resources

Woodstone Resources of Houston, a new bidder, took nine tracts in the North Slope sale, 12,960 acres for $488,160. The tracts are all well south of existing production and include sites of three old exploration wells: Itkillik Unit 1, Nora Fed 1 and Susie Unit 1.

Woodstone was also a bidder in the NPR-A sale, and was apparent high bidder on three tracts, 34,293 acres, for $411,516, bringing its total for the day to almost $900,000 for the two sales. The tracts are in the southern area of NPR-A, adjacent to acreage held by Petro-Canada and Anadarko.

AVCG took one tract in the Beaufort Sea sale, paying $206.75 an acre, a total of $529,280 for 2,560 acres. AVCG fended off two competing bids, including one from a 50-50 bidding partnership of ConocoPhillips and Exxon, to take the tract adjacent to its Beechey Point unit. Its bid for tract 286 was the highest bid in the Beaufort Sea sale.

Savant Alaska also fended off competing bids for two tracts, these in the North Slope sale, paying $212,096 for 5,120 acres, one tract adjacent to three existing Savant tracts on the edge of ANWR and the second tract to the north on the ANWR border.

Pioneer Natural Resources Alaska had the highest per-acre bid in both the North Slope and Beaufort Sea sales, $876 per acre for small tracts at its Oooguruk unit. The company paid $118,260 for 135 acres, two tracts, in the Beaufort Sea sale, and $43,800 for 50 acres, one tract, in the North Slope sale.

A bidding group of J. Andrew Bachner 90 percent and Keith C. Forsgren 10 percent, took five tracts on east side in the Beaufort Sea sale, north of ANWR, bidding against Donkel and Cade. Bachner-Forsgren had apparent high bids on 17,920 acres for $331,878.40.

A bidding group of Alaska LLC/Gavora one lease in the North Slope sale, 1,440 acres, for $36,158.40.

State sees North Slope lease sales as modest success

2011-12-10T03:23:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

Alaska officials called the state’s Dec. 7 onshore and offshore North Slope lease sale a modest success, but expressed disappointment that several companies they courted in months prior to the sale failed to bid.

The state of Alaska received $20.97 million in high bids for onshore and offshore leases sold Dec. 7 the annual area-wide sales on unleased acreage. A federal sale in the National Petroleum Reserve-Alaska drew only a handful of bids, netting $3.06 million from three companies bidding.

Bidding was mostly by companies currently on the North Slope who expanded their acreage positions, although two companies new to Alaska, both small independents, joined the bidding.

"Today’s lease sale was an important, positive step that attracted additional investment to the North Slope,” Gov. Sean Parnell said in a statement. “Reversing the declining flow of oil through TAPS (Trans-Alaska Pipeline System) and getting to 1 million barrels per day is critical to our economy and the nation's energy security.”

"One of our immediate goals for this lease sale was to increase the number and type of investors and companies investing in Alaska,” said Natural Resources Commissioner Dan Sullivan. “We are pleased that the sale was successful in this respect, but there is certainly an opportunity to do more in the future to attract additional investment.”

Sullivan said he had made personal calls on companies in home offices urging them to bid, and followed up with visits by teams of state geologists.

“We need to go back to them and find of what was wrong,” Sullivan said.

Sullivan said he was encouraged, however, that Repsol bid to expand its existing Slope holdings, with high bids on 25 state onshore leases and five state offshore leases, including 45,920 acres. Repsol now has a 70 percent interest in about 500,000 acres of onshore North Slope lands, which it is exploring this winter.

The onshore state sale, conducted first, brought in $14.094 million in high bids for 179 tracts, while the offshore sale, in state-owned submerged lands of the Beaufort Sea, brought in $6.874 million in high bids for 78 tracts sold, state Oil and Gas Director Bill Barron said following the lease sale.

Meanwhile, the federal government received $3.06 million in high bids in a National Petroleum Reserve-Alaska lease sale held hours after the state sale. There were 20 high bids submitted on 17 tracts by three bidders in the sale, according to Ted Murphy, Bureau of Land Management’s deputy director in Alaska.

BLM had initially announced the results at $3.6 million in high bids but then released a corrected amount. Bids were submitted on 141,739 acres out of about 3 million acres of NPR-A lands offered in the lease sale.

Although the bidding was modest, “we are seeing an increased interest in the North Slope also evidenced by results of the state lease sale. This is in sharp contrast to our last lease sale,” in which there were no bids, said Bud Cribley, the Alaska BLM director.

One surprise in the sale was the return of ConocoPhillips, a producer on the Slope, to bidding for state exploration acreage. ConocoPhillips acquired 35 onshore tracts, mostly in the Point Thomson area east of Prudhoe Bay, as well as one tract east of the Alpine oil field, near NPR-A west of Prudhoe.

ConocoPhillips has been absent from onshore exploration for some years, and has focused on its planned exploration of federal offshore leases in the Chukchi Sea.

Industry observers at the sale said that ConocoPhillips’ lease acquisitions in the Point Thomson area are likely related to a pending settlement of litigation between Point Thomson Unit leaseholders, which include ConocoPhillips, and the state of Alaska. A settlement agreement was reached in September between the state and ExxonMobil, the Point Thompson Unit operator, but has not been agreed to yet by other partners in the unit, which include BP, Chevron and ConocoPhillips.

Also in the sale, three small independent companies bid have apparently won their first North Slope leases. Woodstone Resources of Houston was high bidder on nine state onshore leases and two federal NPR-A leases. Royale Energy Inc. of San Diego was high bidder on 60 onshore leases.

Alaska-based NordAq Energy, a small independent active in the Cook Inlet Basin in southern Alaska, was high bidder in 11 state offshore leases north of the NPR-A.

Armstrong Oil and Gas, a Denver-based independent that has worked on the Slope for many years, was high bidder on 11 state onshore leases and 10 federal NPR-A leases.

Great Bear Petroleum, an Alaska independent, was high bidder on 32 onshore leases in an area where the company plans a shale oil exploration project this winter. One surprise of the sale is that Great Bear faced little competition in bidding for leases that were open within its proposed shale oil play except for unsuccessful bids by Royale Exploration on some of the tracts.

This may indicate that other companies do not share Great Bear’s hopes for developing production from shale source rocks in the area, industry sources at the sale said.

Shell acquired 18 state offshore leases near Harrison Bay, south of federal Outer Continental Shelf leases held by the company. Harrison Bay is one of Shell’s target areas for exploration in the Beaufort Sea.

High bids in the state sales, which included North Slope onshore and Beaufort Sea offshore sales held, came from Pioneer Natural Resources Alaska for $876 per acre for two offshore tracts and one onshore tract. Both parcels were small and adjacent to areas where Pioneer is now working.

Individual bidders acquired offshore state leases in Beaufort Sea tracts offshore the Arctic National Wildlife Refuge and offshore state lands in the Point Thomson and Prudhoe Bay field areas.

The bidding did indicate some success for the strategy of the state and the BLM in holding their sales on the same day, an effort to facilitate bids by companies on adjacent acreage along the Colville River boundary between the NPR-A and state lands.

Armstrong and Woodstone Resources both submitted high bids on state and NPR-A tracts along the Colville River, indicating interest in geologic plays extending across the border.

This article appears in the AJOC December 11 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/State-sees-North-Slope-lease-sales-as-modest-success/#ixzz1g8MVngYg

AOGCC proposes new regulations on blowout control plans

2011-12-08T13:19:00.002-09:00

Tim Bradner
Alaska Journal of Commerce

The state of Alaska is considering strengthened regulatory controls on offshore drilling with a new requirement for operators to have a blowout control plan.

A recommendation to change the state’s drilling rules comes at the end of a lengthy review of the state’s drilling safety rules by the Alaska’s Oil and Gas Conservation Commission, said Cathy Foerster, one of the three AOGCC commissioners.

AOGCC is a quasi-judiciary independent state regulatory agency that oversees drilling and other oilfield safety and production practices in Alaska, including state-owned submerged lands to the three-mile territorial limit.

The Alaska Department of Environmental Conservation now requires drillers to have approved contingency plans in place to control oil spills, including large spills from a blowout. The proposed AOGCC rule would be specific to blowout control, however, and would be reviewed by the commission’s staff, where there is expertise on drilling.

The proposal came about because of concerns on the Macondo well, where a blowout preventer on the Deepwater Horizon rig failed to function. The resulting explosion and fire killed several people, destroyed the rig, and caused one of the worst oil peacetime spills in the history of the industry.

“The state of Alaska’s drilling rules, implemented through the AOGCC, were very strong even before Macondo – stronger that the federal government’s, in fact – and a detailed post-Macondo review of regulations by the AOGCC and outside experts revealed no major flaws except in one area, a specific requirement for a plan to control a blowout,” Foerster said.

Foerster said she believes Alaska is the only U.S. state to conduct a detailed review of drilling regulations following the Gulf of Mexico disaster.

The commission also is adding to its staff of inspectors and drilling engineers because of the greater scrutiny that the state is now giving drilling operations, she said.

The state commission decided to do its review because some of the problems in well safety that were identified in deep ocean wells like Macondo could also occur in ultra extended-reach wells drilled in Alaska, such as at BP’s planned Liberty project, where wells would be drilled out as much as eight miles laterally from the surface location of the drill rig.

Extended-reach wells are routinely drilled in Alaska, although not to the distances planned at Liberty. Extended-reach wells were drilled by ExxonMobil at Point Thomson and by BP and at the Milne Point and Niakuk fields near Prudhoe Bay.

Well blowouts have happened in Alaska, although they are rare. So far the blowouts in the state have been on gas rigs, not oil, and there has never been a case of oil released in an Alaska blowout reaching the land surface or open water, Foerster said.

Since 1962 there have been four offshore blowouts in Cook Inlet, all involving releases of gas, the last in 1987. On the North Slope, there have been seven blowouts that have occurred in approximately 5,000 wells drilled since the Prudhoe Bay oil field was discovered in 1967. None of them involved a release of crude oil, and none caused injuries, Foerster said.

State rules require the testing of blowout preventers every seven days on exploration wells being drilled and “workover,” or maintenance well, and every 14 days on new production wells being drilled. Test results must be filed with the commission.

AOGCC inspectors are also on-scene to witness many tests. The commission’s records indicate that state inspectors attend tests of well control systems on every active drill rig in the state once every two months. The AOGCC’s data shows a “pass rate” of 98 percent for blowout control equipment.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/AOGCC-proposes-new-regulations-on-blowout-control-plans/#ixzz1fz4clb82

Working up from typist to executive director, Crockett retires

2011-12-08T12:58:00.003-09:00

Tim Bradner
Alaska Journal of Commerce

Alaska Oil and Gas Association Executive Director Marilyn Crockett is set to retire. Kara Moriarty, formerly deputy director for the association, will move into the executive position. Crockett began at the organization as a typist, and over the years worked her way up the ladder to executive director.

Alaska Oil and Gas Association Executive Director Marilyn Crockett is set to retire. Kara Moriarty, formerly deputy director for the association, will move into the executive position. Crockett began at the organization as a typist, and over the years worked her way up the ladder to executive director.

Marilyn Crockett, a slip of a girl fresh out of high school, met Bill Hopkins, then executive director of the Alaska Oil and Gas Association, for a job interview. Marilyn could type very well, was very proficient at shorthand (a now lost art) and the job was for a receptionist/typist.

It was 41 years ago, and at 17 years old, she felt intimidated by Hopkins and was relieved when the interview was done. She thought she blew it.

To her surprise, Hopkins called and offered her the job.

It was a fortunate decision. It launched Crockett on a long career that would eventually see her rise to take the executive director’s job, from which she is retiring at the end of December. It was a good break for AOGA too, because having someone like Crockett on staff for four decades, rising through the ranks and learning the industry’s issues, has made her a valuable source of institutional memory on a wide variety of complex government policy issues.

In an industry where managers of operating companies typically rotate from Alaska to other places, and vice versa, having that continuity of experience has been invaluable.

It was a different era when Crockett came aboard at AOGA. Cook Inlet was Alaska’s crown jewel in terms of oil production and additional platforms were being installed.

Hopkins, a former assistant to Gov. Bill Egan, was the petroleum industry’s most public persona as its chief lobbyist in Juneau in his work as director of the industry’s trade association.

There was a small staff of three, including Crockett. Long distance phone calls were a major expense. So was the copy machine bill and postage.

Things changed as the industry grew. The North Slope started up in 1977, the major operating companies, on both the North Slope and Cook Inlet, developed their own public relations and lobbying staffs.

While AOGA maintained its advocacy efforts, it also evolved into a more traditional trade association where oil and gas companies, and even refiners, could meet and talk together and work out common approaches to issues.

Trade associations like AOGA perform a valuable function as a forum for companies to meet and talk with each other, but one thing an association must be very careful about is anti-trust considerations. There can be no discussions about prices, marketing or anything that might be construed as inhibiting competition. AOGA’s rules are very strict about this, Crockett says.

As the industry grew AOGA grew, and as the industry contracted as crude oil prices periodically crashed, AOGA contracted. At one time the association had eight people on staff and a variety of public relations programs including a series of teacher orientation workshops that included field trips, some to the North Slope.

Budget cuts, as the industry hit lean times, ended some of those programs but the school programs have evolved. Alaska Resource Education, formerly AMEREF, a project of the Resource Development Council, was established and is now an independent nonprofit.

Another industry group, the Alaska Process Industry Careers Consortium, which works on workforce development, now has a well developed teacher “ex-tern” program were high school teachers spend some of their summers in actual working jobs with producing companies and contractors.

As things tightened and communication technology advanced, AOGA slimmed down its staff and has been stable at four people for several years. The association still has an active public relations outreach program, publishing a newsletter and managing a public speaking program.

“We feel it’s very important to remind people of the industry’s economic contributions. A lot of Alaskans don’t remember what things were like here before there were oil revenues to the state,” Crockett said.

AOGA’s board, made up of the industry’s senior managers in Alaska, provides overall guidance – this year’s AOGA president is Dale Pittman, ExxonMobil Corp.’s Alaska production manager – but the association’s nuts-and-bolts work is done through its standing committees.

The standing committees are Environmental, Health and Safety, Lands, Exploration and Operations, State Legislative, and Tax. Other committees are formed for special purposes, such as an offshore committee now active because of the new interest in exploring in the Arctic offshore.

Specialists in these areas are named to the committees. The legislative committee is very active as it oversees the association’s advocacy and legislative efforts.

Because a lot of activity in the Legislature and the administration involves taxation, the association’s tax committee, made up of tax specialists, is also active, reviewing tax legislation and developing comments, usually technical in nature, which become part of the association’s presentations to legislative committees.

The lands committee has been concerned mainly with lease sales and has been less active in recent years with the state’s switch to its regular “area-wide” lease sales, but the committee still exists and meets on an as-needed basis, Crockett says.

The environment committee is also active, Crockett says, because it deals with highly complex state and federal air and water quality issues. In recent years there are also issues like federal Endangered Species Act designations and habitat declarations that affect the industry, and the association has become active in this area.

It is on complex regulatory issues that trade associations like AOGA can be most effective, and also provide valuable assistance to the government agencies because the association brings the combined experience and knowledge of all companies working in Alaska to bear on a problem.

Governmental agencies and legislators often want to be able to communicate with the industry as a whole, and a trade association like AOGA is a preferred was for agency officials to talk with an industry and listen to thee affected companies in one setting.

In years past AOGA was heavily involved in the development of the coastal management, through the original state legislation and regulations that implemented that, and then in the revamp of the program by former Gov. Frank Murkowski. The program ended last year when the Legislature declined to extend it. Crockett points out that the association supported an extension of the program but not any changes to it, which were proposed by some legislators.

A few other examples illustrate where AOGA, as a trade association, has been effective. One was in working with the state Department of Environmental Conservation in, most recently, the state’s assumption of federal authority to issue industrial wastewater permits.

Previously this permitting was all done by the U.S. Environmental Protection Agency but federal law allows the federal agency to delegate the permit authority to states, although this must be done under guidelines set by EPA. The state DEC is now assuming this authority in stages. There were several issues, most important how the changes for operating the program would be funded, where AOGA worked closely with DEC.

Previously, AOGA played a substantial role in resolving issues related to the state’s assumption of air quality permitting authority from the EPA. In this case the federal Clean Air Act requires states to fund all of the costs of administering the programs.

This got complicated because companies in many industries must obtain air quality permits and the concern was that a cost-reimbursement formula that was based only on a simple criteria, such as tons of air pollution per year, would have operators of major facilities like oil and gas producers, refiners and utilities picking up most of the tab.

In fairness, most of the real cost of the program would come for the DEC in administering permits for a wide variety of businesses which emit much lower volumes of pollutants.

A solution worked out by an ad hoc committee formed by businesses, industries and municipalities and utility operators and with AOGA’s major involvement, led to a unique financing procedure partly based on tons of pollution and partly on the hours spent by agency personnel on a permit.

Crockett and her husband, Jack, will now become “snowbirds,” spending part of the year in warmer climates.

On Crockett’s departure, Kara Moriarty, formerly deputy director for the association, takes over as executive director. Kate Williams is the association’s staff for regulatory issues, and Tamara Sheffield, herself a long-tenure staffer of 30 years, provides support services to the organization.

This article appears in the AJOC December 11 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/Working-up-from-typist-to-executive-director-Crockett-retires/#ixzz1fz0EV4Oh

Busy winter exploration season planned for North Slope

2011-12-08T12:47:00.001-09:00

Tim Bradner
Alaska Journal of Commerce

It will be a busy exploration season on the North Slope.

New drilling by Repsol is driving the pace of exploration with four to five drill rigs under contract but Brooks Range Petroleum, Linc Energy and Great Bear Exploration also plan drilling, employing one drill rig each. In addition Anadarko Petroleum is going back to test a natural gas find in the foothills region of the southern North Slope.

Linc Energy’s Umiat project is not technically exploration since the oil accumulation there has long been known, but the company is planning to drill five wells and to do flow tests of three to four to assess the productivity of the shallow Umiat reservoir.

The company is developing a 90-mile snow road from the Dalton Highway to Umiat to move a drill rig and other major equipment. Anadarko will also use the road for part of the distance to move equipment it will need to test its well, although a drill rig will not be required.

There is an estimated 1 billion barrels of oil resource estimated to lie in the shallow sandstone reservoir at Umiat, much of it actually in the permafrost, according to Corri Feige, Linc Energy’s Alaska manager. Only a part of this will be produced, however. The oil is very good quality, however, measured at 37 degrees API, Feige said.

Linc Energy is studying a small crude oil pipeline that would be built parallel to a gravel access road the state of Alaska is planning to build to the area.

Brooks Range Petroleum, which is exploring on behalf of several independent companies, will return to its North Tarn 1-A well drilled last year to deepen and test the well, said Bart Armfield, Brooks Range’s chief operating officer. When that work is completed the rig will move to the company’s nearby Mustang prospect to drill. An exploration project to search for gravel will also be done.

An ice road will be built from a production pad in the southwest part of the Kuparuk River field, with the Nabors 7ES rig and two camps capable of housing 100 people moved to the exploration site.

If a commercially viable project is developed Brooks Range will move to the design of a production facility and procurement and construction in 2013 with a possible start of production in 2014. Capital costs for the Mustang project are estimated at $597 million. If an extension of the prospect to the north, called Appaloosa, is also developed, a further $454 million in capital investments will be required.

The planning now assumes a 10,000 barrels-per-day production facility with 15 wells, including seven producers and eight injection wells.

Great Bear plans to drill six test wells at locations adjacent to the Dalton Highway south of Prudhoe Bay to test its concept that oil can be produced from shale source rocks, according to Great Bear President Ed Duncan. The shale formations are known to be the sources for oil that accumulated over time in several of the large producing fields to the north of Great Bear’s leases. The company hopes that substantial amounts of oil remain in the shales.

What is planned, if the theory holds, is a production project similar to that being done to extract shale oil in North Dakota and Texas. The production plan involves horizontal wells and multiple fracturing, a procedure similar to that used in the shale oil projects of the Lower 48.

Repsol, a medium-sized integrated company based in Madrid, Spain, acquired a 70 percent interest in 500,000 acres of North Slope onshore leases last March in a deal with Denver-based independent Armstrong Oil and Gas. The company planned an aggressive program to test prospects because of impending lease expiration deadlines, its project manager, Bill Hardham, said.

Drilling will be at prospect locations north and west of the Kuparuk River field and south of Kuparuk near the Meltwater production pad. Four to five rigs will be employed, and the activity will be so intense that the company has chartered an Alaska Airlines Boeing 737 for twice-weekly flights to the Slope.

This article appears in the AJOC December 11 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/Busy-winter-exploration-season-planned-for-North-Slope/#ixzz1fywknBdU

Cook Inlet energy projects under way

2011-12-03T11:38:00.001-09:00

Kristen Nelson
Petroleum News

The Resource Development Council included a fairly complete Cook Inlet update on the program of its annual conference.

From oil and gas, through wind and underground coal gasification, to natural gas storage, companies involved in the current upsurge in Cook Inlet activities were on the podium Nov. 17.

Apache

Apache Corp., Cook Inlet’s newest big player, with more than 800,000 acres, was represented by its newly named Alaska general manager, John Hendrix, who told the RDC audience he remembers Cook Inlet in its heyday, before the discovery of Prudhoe Bay. But by the time he graduated from college and went to work for Schlumberger, the work was on the North Slope.
“All the focus, all the money, were going into Prudhoe Bay,” Hendrix said.

Apache is focused on the historic oil play in Cook Inlet and is looking for oil “with new 3-D seismic technology,” he said.

“We feel there’s potential out there. We’re more focused on oil — gas will come along with the oil … but we’re oil focused.”

Apache has begun a three-year 12,000-square mile 3-D seismic shoot in Cook Inlet using a new nodal technology.

Hendrix said there are 220 people on the west side of Cook Inlet deploying nodes with the first actual shoot done Nov. 11. He said crews will work until mid-December and then start back up Jan. 15. Twelve small drill rigs will be used to drill the holes onshore; offshore air guns will be used.

In all of its operations, Apache shoots a lot of seismic, Hendrix said.

“We’re a very seismic, geo-science oriented company … and you have to know the data before you drill. You gather the data, you put your strategy forward and then we drill.”

He also said that Apache’s “chairman, in a number of meetings I’ve been with him, he doesn’t want us to stop drilling until we hit bedrock. We don’t want anybody to come behind us and turn over a stone and find there’s oil reserves; we want to make sure when we drill, that we leave no … stone untouched.”

Buccaneer

Jim Watt, president and COO of Buccaneer Alaska, said Buccaneer sees majors moving out and independents moving into Cook Inlet, “normal for a lot of maturing basins.”

But, he said, Cook Inlet is an underexplored basin where recent U.S. Geological Survey reports show “tremendous upside” and where there is existing infrastructure, a strong local market and attractive natural gas prices.

Buccaneer has some 66,000 acres onshore and at one prospect, Kenai Loop, just north of the city of Kenai, it “leased, permitted and drilled our first well within nine months.” That natural gas well will be on production in December, he said. Buccaneer has a contract with Enstar for delivery beginning in April, “but we hope we will sell in the spot market” before then, Watt said.

At West Nicolai on the west side of Cook Inlet Buccaneer expects to acquire seismic in 2012 and drill in 2013.

And at West Eagle on the southern Kenai Peninsula Buccaneer is reprocessing seismic and would like to drill in 2012.

The company also has offshore prospects and has completed purchase of the Endeavour jack-up drilling rig for use in Cook Inlet. Buccaneer is also looking at the potential for liquefied natural gas for use in Alaska. Watt said “we feel we can move LNG from the Cook Inlet to Fairbanks and be very competitive.”

Furie/Escopeta

Drilling engineer Bob Laule, filling in for Furie Operating Alaska (formerly Escopeta Oil) President Ed Oliver, gave a brief update.
“Furie came; we drilled; and we found gas,” he said.

He said the company got a late start and wasn’t able to complete its well, but drilled to 8,800 feet and did “some testing which gave us some very good indications of gas in the Sterling and in the Beluga formations.”

Laule said they will re-enter the well next spring, approximately mid-April and drill to total depth, “set a couple of extra additional stands of pipe and go into a testing program.”

Then Furie will drill a second well. Laule said he didn’t know if they’d get to testing the second well next year.

Cook Inlet Energy

JR Wilcox, president of Cook Inlet Energy, said his company “is one of the few small independent oil producers in the state.” Cook Inlet Energy re-established production after Pacific Energy declared bankruptcy in 2009.
Production was shut down in September and Cook Inlet Energy was approved as successor operator in December, hired a staff and “within about two weeks we had some production going.”

Over the next four months the West McArthur River unit was restarted and production was up to 400 percent of what it was when it was shut-in.

Wilcox said the company has continued to optimize wells at its onshore properties.

It took longer to get the Osprey platform back into operation, but first oil came off the platform in June, he said. With a $100 million credit facility work began on a big rig for the Osprey platform so the company could begin drilling sidetracks from the platform and increase production. About a third of that rig is now in Nikiski, Wilcox said, and work will begin on the platform in the next few months.

Cook Inlet Energy is also building a small rig on the west side that will be truck mounted and “should be just an ideal rig for drilling gas on the west side.”

The company is “getting set up to execute our second phase of development on the Osprey platform” with the new rig, is continuing to optimize production from existing wells and continuing to exploit oil and gas reserves near its facilities, Wilcox said.

Enstar, CINGSA

John Sims, director of corporate communications for Cook Inlet Natural Gas Storage Alaska and Enstar Natural Gas, told the RDC audience that while Enstar is “very cautiously optimistic about all the activities going on here in Cook Inlet,” it has concerns until it has a contract for gas delivery before the Regulatory Commission of Alaska.
Semco Energy, Enstar’s parent company, and MidAmerican LLC, partners in Cook Inlet Natural Gas Storage Alaska, or CINGSA, were joined in October by First Alaska and Cook Inlet Region Inc., Sims said.

The five injection-withdrawal wells are being drilled for the storage project, with the project on schedule and slightly under budget. The first well cost about $7 million and the second two came in at about $5 million each, prior to perforating.

The middle three wells, technically the easiest, were drilled first, Sims said. It has taken about 30 days per well, with about half of that time required to move the rig. The wells should be completed by February.

With four customers for storage capacity — Enstar, Chugach Electric Association, ML&P and Homer Electric coming in later — CINGSA is at 11 percent capacity for the 11 billion cubic feet of gas storage.

There is expansion capacity at the facility and Sims said expansion will be “dependent on performance and also the market demand.”

Having storage, which will be available for withdrawal in the winter of 2012-13, helps with swing demand in the winter, he said, helps producers with production in the summer when gas is injected and acts as an insurance policy should there be equipment failure.

Asked whether with successful gas exploration and storage the utilities will still need LNG, Sims said, “storage isn’t the savior for Cook Inlet by any means; it’s a part of the puzzle.”

“Another piece involves the additional exploration and development that we’re seeing.”

But, he said, Enstar and the utilities are still evaluating the LNG option, “not just for gasifying going forward put also for an insurance policy.”

And, he said, “until we actually have those contracts that erase that need, it’s something that we’re still going to have to move forward with.”

Cook Inlet Region Inc.

Ethan Schutt, senior vice president, land and energy development, for Cook Inlet Region Inc., said the Fire Island wind project has regulatory approval for contracts from the Regulatory Commission of Alaska.
Financing for the project needs to be closed, “so that we can move into project construction in April,” he said, adding that the project has all its permits.

CIRI is also working on an underground coal gasification or UCG project.

The Cook Inlet basin has a “world-class coal resource that’s really never been exploited at a commercial level,” Schutt said.

CIRI has been working on UCG for almost three years, he said, and to date has “drilled 13 stratigraphic core holes to test both the geology and the resource,” and collected a suite of oil and gas type data during that program, “so we have a pretty robust data set from that site, a place just north of the Beluga River on the north side of Cook Inlet on CIRI surface and subsurface land.”

The data has been incorporated into a geological model.

CIRI is currently shooting some eight and a half line miles of “shallow high-resolution 2-D … to tie together all the data points that we collected with the drilling program and enhance our data set as we move towards a … characterization program to begin sometime in 2012.”

The project represents some 300-plus million tons of coal, Schutt said, “the equivalent of more than 4 (trillion cubic feet) of natural gas on an energy basis, so just in our little site we have quite a world-class resource in that coal.”

To buy or not buy Norway's house

2011-12-03T07:06:00.013-09:00

Deborah Brollini

I know some Alaskans are a tad disgruntled over lawmakers taking a trip to Norway. However, the trip was far from a junket. I have been mystified by Norway’s economic success, and have had a difficult time wrapping my mind around their state-owned oil company Statoil, and how they invest in themselves in regards to resource development. Not to mention their $600 billion dollar permanent fund. There is a lot to be said for Norway’s success. However, can their success be translated into an Alaska success story?

Norway has had my attention for over a year now. Unfortunately, to date the public presentations, news stories, and sound bites have all fell short in articulating Norway’s investment strategy to the everyday Alaskan. It was not until I got my head into the weeds did I finally get Norway. It is not as complicated as one would think. But, it took some personal tutoring, and a little role-playing over coffee did I finally get it. But should Alaska buy Norway’s house?

Norway has a lot of curb appeal, and as far as the home inspector, there has been a lot of homeowner investment that has gone into their house. Homebuyers, and the mortgage lenders know exactly what they are getting into in term of the seismic data to make some determination whether the property has value, and worth the investment.

Ira Perman, President of the Institute of the North and I discussed a hypothetical new “Brollini” oil find on the North Slope last month because I asked him to tutor me on Norway The seismic data showed a high likelihood of substantial oil within the Brollini field. We determined that Alaska should take a one-third interest in the field with our partners Statoil, and ConocoPhillips who each held a one-third interest in the Brollini field. The field began producing oil in 2011 and the field accumulated three million in profits. So, how will the state tax this new investment in my hypothetical world?

In my hypothetical world Alaska’s take was 75% of profits. Statoil, and ConocoPhillips would pay the state of Alaska $750,000 each in taxes, and get this, for Alaska’s investment… we get to keep the money! All $2.5 million of it. Investing in ourselves is Alaska’s future. Norway learned from us, and let us learn from them and their success. They are willing to mentor us and it is up to us whether or not we want success, and a future for our children.

Rebirth in Cook Inlet? CIRI says more infrastructure needed; CIE calls access ‘progressivity’ of inlet

2011-11-27T13:01:00.003-09:00

Kristen Nelson
Petroleum News

There is more oil and gas exploration and development activity in Cook Inlet currently than the basin has seen in many years.

The Resource Development Council heard two perspectives on this activity at its annual conference in Anchorage on Nov. 17. Both were focused on oil rather than natural gas.

Ethan Schutt, senior vice president of land and energy development for Cook Inlet Region Inc., said CIRI has been promoting Cook Inlet development since it was formed.

JR Wilcox, president of Cook Inlet Energy, which was formed and took over operations after Pacific Energy went bankrupt in 2009, focused on the last couple of years.

CIRI is a major landholder in Cook Inlet.

Schutt said CIRI has always been a proponent of Cook Inlet as an oil and gas basin and in the last four or five years has been “pushing hard to get people to pay attention to Cook Inlet.” He noted that with the exception of Escopeta-Furie, all the speakers on the RDC Cook Inlet panel were CIRI lessees in one form or another, “some major, some minor.”

One CIRI lessee missing from the panel was NordAq Energy, Schutt said, noting that NordAq had a significant gas discovery on CIRI leases on the west side of the Kenai National Wildlife Refuge.

Because of its subsurface holdings, he said, CIRI gets “an inside look at what’s going on in this basin.”

“And I think it can’t be overstated that this is a very important moment in time and it is the early phases of a renewed interest in oil and gas potential in this basin.”

He said the interest of Apache in “coming to this basin and shooting an enormous 3-D seismic program” is significant because of Apache’s size and in-house technology. Schutt said he believes that seismic shoot will result in new oil production in commercial volumes.

Value to state

Schutt said that in discussions of the distinctions between the North Slope and Cook Inlet, state revenues are often left out of the equation. He said much of the remaining oil potential on the North Slope is on federal acreage, so if projects can get permitted and into development it’s great for jobs and getting throughput into the trans-Alaska oil pipeline, “but it’s not as great for revenue into the state government coffers.”

“One of the places where this state government can see real potential for royalties and taxes from oil production is here in Cook Inlet because the oil potential in Cook Inlet is in state land,” Schutt said.

While there is much discussion of roads to resources on the North Slope, one thing that would really help drive down the cost of exploration and development on the west side of Cook Inlet is a road-to-resources road, he said.

“We can’t focus all of our efforts on prizes that are up on the North Slope and in the North Slope offshore when one of the things that would most benefit us here in Southcentral would be infrastructure supporting oil and gas development here,” Schutt said.

The other thing that’s needed in Cook Inlet is improved port facilities on the west side, up near Beluga and at West Forelands. Without port infrastructure and road access, it makes oil and gas exploration more difficult and more expensive, he said.

Unexplored potential

Cook Inlet is “an amazing basin that has, amazingly, a whole interval of geological potential that’s basically never been explored,” Schutt said.

Oil was found at relatively shallow depths during early exploration, so explorers didn’t go deep, he said.

“If you drill to bedrock in Cook Inlet you’re going to go through two or three zones of oil potential and there is a whole zone down at the bottom that has two or three exploration wells in the entire history of the basin.”

While Cook Inlet is described as an underexplored basin, people are talking about the number of wells that have been drilled. “If you consider that there’s a whole basement to that basin that has never, for practical purposes, been tested, it’s even that much more potential for oil and gas development,” he said.

The need for gas in Southcentral is well known, but Schutt said with recent discoveries, “we may actually have found the new reserves that over time will be developed to get us healthy. We may have actually turned that page in the book.”

“What we need here, to really get healthy, is more new oil discoveries,” Schutt said. Oil is needed to feed the refinery at Nikiski, he said.

He encouraged the resource development community to work with legislators to figure out “how do we make this basin more attractive until we actually get the reserves up and we get healthier again.”

He acknowledged that CIRI has a stake in this as a major land and resource owner, but said it is something that would benefit Southcentral residents and the Kenai Peninsula Borough.

Cook Inlet Energy

Cook Inlet Energy is a young company, about to celebrate its second anniversary “of actually operating anything,” said the company’s president, JR Wilcox. He said he and the company’s CEO, David Hall, had helped run the assets for Forest Oil and then for Pacific Energy.

2009 was pretty much the nadir for the inlet, Wilcox said, with the oil price crashing, the Redoubt volcano erupting and Pacific Energy going bankrupt.

When people told him it was too bad about Pacific Energy, but he could always get another job, Wilcox said he and Hall said, “no, no; we’re forming a new company; we’re going to get some money from somewhere,” hire people back and start things up again.

“Somehow that actually happened; it still really amazes me,” he said.

Production was shut down in September, he said, and by December Cook Inlet Energy had been approved as the successor operator, hired a staff, and “within about two weeks we had some production going.” Over the next four months they got production at West McArthur River up 400 percent from where it was when the field was shut in, he said.

(See part 2 of this story, in the Dec. 4 issue, for some specifics on Cook Inlet Energy’s work to date.)

Inlet not there yet

“There’s a lot of hustle in the inlet now; it couldn’t be more different than things were in 2009,” Wilcox said. The U.S. Geological Survey report of an additional 600 million barrels of oil and several trillion cubic feet of natural gas yet to be found is positive, he said, and there are a lot of new players, “bringing a lot of new capital, new expertise and new enthusiasm.” He noted Hilcorp, Apache, NordAq, Buccaneer, Escopeta, Linc and Armstrong.

“We’re starting to really see a critical mass of players of a variety of sizes focused on a variety of different things,” Wilcox said.

But, he said, Cook Inlet oil production is off 97 percent from peak production.

“So one shouldn’t mistake green shoots for a crop here,” he said.

“If things seem great in the inlet now that’s in part just because they’ve been so crummy for so long and what we see is a lot of potential and a lot of enthusiasm.”

But, Wilcox said, there’s also been a lot of potential and a lot of enthusiasm for exploration in the Arctic National Wildlife Refuge and for a gas pipeline from the North Slope to market for about 30 years.

“Potential and reality are sometimes a long way apart from one another and it’s going to take a lot of time, money and effort to turn this potential into reality.”

What’s needed in Cook Inlet?

Wilcox warned against a perception that Cook Inlet has recovered.

“That’s not the case. … I think we may have just stopped getting worse,” he said, comparing Cook Inlet to a patient who was critical and has been stabilized. There’s going to be a “lot of effort between that condition and when they’re ready to go out and play football again,” he said.

He said several things are needed in Cook Inlet, including legislation to ensure the preservation of marginal oil and gas production. Cook Inlet Energy believes House Bill 32 does that, he said.

And there are “real problems with access.”

“I think access is almost the progressivity of the Cook Inlet: It stands between a lot of potential prospects and what could be real projects,” Wilcox said.

One access issue is a requirement for ice roads, which are expensive, can’t be built every winter and don’t give you very long to get in and work when they can be built.

Gravel is prohibited except by exception, he said, and “if you don’t have gravel roads and pads it’s really hard to have an oil field.”

There is the Kenai National Wildlife Refuge on the east side and the Susitna Flats and Trading Bay state game refuges on the west side, and there hasn’t been much road and pad infrastructure added since they were established, Wilcox said.

Road access needed

Wilcox said the 28 miles linking Mat-Su to the Beluga-Tyonek area should be “the poster child” of the roads-to-resources program.

It’s a short road across state land in a permitted right of way and has “been on the books since the late ‘60s,” he said.

A road on the west side “would immediately lower the operating cost” for projects on the west side because you could then access the area by truck.

He said it can be more expensive to work on the west side of Cook Inlet than on the North Slope because there is a road to the North Slope, but none to the west side.

Wilcox also said that platform abandonment is an issue the state needs to address.

“There’s no clear abandonment standard and … we went through this with the Osprey platform when we assumed operatorship,” Wilcox said.

He predicted that Escopeta or Buccaneer would find the lack of clear abandonment standards a hurdle if they were to try to put in new platforms.

And he had a comment on the oil production tax fight: A lot of the discussion around House Bill 110 (the governor’s tax change bill) seems premised on the main point of an energy company being to pay taxes, he said.

Taxes are not what energy companies are for, Wilcox said.

“Better than taxes are that they create jobs and they create a dynamic economy. … But even more important than the jobs is the energy security; that’s why energy companies are here, is to provide energy.”

And he called on the Legislature and the administration to continue their support for revitalizing the inlet, to turn “this nascent recovery into a truly prosperous oil and gas picture.”

----------------
Republished with the permission of the Petroleum News

Producers: bleak outlook without tax reform

2011-11-24T06:09:00.003-09:00

Tim Bradner
Alaska Journal of Commerce

Major Alaska oil producers presented a pessimistic picture of the North Slope production outlook during presentations to the Resource Development Council’s annual conference in Anchorage Nov. 16.

But other companies, mostly independents, were more upbeat and are planning a surge of exploration drilling this winter. However, the state of Alaska is funding much of the exploration through incentives that pay for more than half the costs of a well, the explorers acknowledged.

Most of the exploration is near existing fields and if discoveries are made, the expected reserve additions are modest.

“We don’t expect to find any Prudhoe Bays,” said Bill Hardham, Alaska operations manager for Repsol.

Repsol will be the most active explorer on the North Slope this winter.

The large producing companies were downbeat, however.

Claire Fitzpatrick, BP’s chief financial officer for Alaska, said her company is expecting a 7 percent to 8 percent decline in annual production declines this year in the fields it operates, which amount to two-thirds of total Slope production, and warned that Trans-Alaska Pipeline System throughput could drop to the 550,000 barrels-per-day range this winter.

This is important because at that level, pipeline operating problems could occur, Fitzpatrick said. A study by Alyeska Pipeline Service Co. released earlier this year forecast increasing problems with water drop-out, wax build-up and freezing in cold weather when oil moving through the pipeline drops below 600,000 barrels per day.

Fitzpatrick’s message, and a similar one conveyed at the conference by Trond-Erik Johansen, ConocoPhillips’ Alaska president, was partly aimed at getting business and community leaders at the conference to lobby the state Legislature for a change in state production taxes.

Fitzpatrick said BP’s 2012 activity level in Alaska would be flat, with no growth in activities like drilling that add new production.

“We’re making significant investments in infrastructure and pipeline upgrades, but capital spending on activities that produce more oil, on drilling, pad expansions, debottlenecking and others, is on hold or significantly limited. If the economics in Alaska don’t improve they’ll remain on hold,” Fitzpatrick said.

There are potential projects that could add new Slope production, but a hefty state production tax pushes these projects below the economic threshold when added to problems of high costs on the North Slope, Fitzpatrick said.

“These are prospects that do not make economic sense in the current business climate in Alaska, prospects that will remain only possibilities unless Alaskans and the oil industry work together to make changes that will make these prospects commercially competitive,” she said.

ConocoPhillips’ Johansen said a perverse effect of the Alaska tax is that it depresses companies’ incentive to invest as oil prices rise, resulting in stagnant or even declining investment by major operating companies at higher oil prices.

That happens because of a formula in the tax law that ratchets up the tax rate at steep rate as oil prices rise.

In contrast, industry investment in the Lower 48 and elsewhere is booming. Even in countries like Norway, with high rates of tax, there is enough profit left for industry that new investments are being made, Johansen said.

Johansen said ConocoPhillips’ 2012 Alaska capital budget will be about the same as 2011 and 2010, in the range of $900 million.

Fitzpatrick said BP’s 2012 capital investment will decline from about $800 million to $700 million.

The bulk of BP’s spending will be on major facility and pipeline maintenance rather than activities that add new production, Fitzpatrick said. Johansen has said that 70 percent of his company’s annual capital investment is going to maintenance.

Fitzpatrick said she forecasts Slope production declining 25 percent by 2020, from the current average of about 600,000 barrels a day, unless the investment environment for new projects improves.

“The Alaska Department of Revenue forecasts a 13 percent decline over the same period, but 52 percent of that (the production in 2010) is from projects not now producing and which are still under evaluation,” Fitzpatrick said.

Given the reluctance of the major operators to make new development investments, a good share of the production the state assumes in its forecast will not appear, she said.

Gov. Sean Parnell has proposed adjustments to the tax law, but the governor’s bill is bogged down in the Legislature.

Lawmakers opposing Parnell’s bill point to an upsurge in planned North Slope exploration this winter as proof that the tax adjustment Parnell proposes isn’t needed.

Marilyn Crockett, executive director of the Alaska Oil and Gas Association, said it typically takes eight to 10 years to get new discoveries into production in northern Alaska.

“The reality we face is that our best prospects for new production and adding throughput to TAPS are within existing fields, but these are the kinds of investments being discouraged by the state tax law,” Crockett said.

Repsol’s manager, Hardham, said its aggressive exploration this year is motivated mainly by lease expiration dates on many tracts in a 500,000-acre position it bought into with Denver-based independent Armstrong Oil and Gas.

“If we make a discovery, we’ll want to have a conversation about the state tax rate,” Hardham said.

Repsol plans to have four to five rigs working on exploration this winter on the Slope, testing prospects north and south of the producing Kuparuk and Alpine fields. The company’s schedule has squeezed the supply of rigs available for exploration, which has created problems for other companies seeking to drill exploration wells.

Savant Resources, Brooks Range Petroleum and LincEnergy, all independents, have encountered difficulties getting rigs, according to industry sources.

Another explorer, Great Bear Petroleum, also encountered problems but its president, Ed Duncan, said the company has located a rig it can move to Alaska in time for testing a potential North Slope shale oil prospect in this upcoming winter season.

Resource Development Council presentations

ConocoPhillips: video | slides
BP: video | slides
Exxon: video | slides

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-November-27-2011/Producers-bleak-outlook-without-tax-reform/#ixzz1edTmUSdC

Gearing up for winter; Companies move forward on what could be bumper exploration season

2011-11-23T14:25:00.001-09:00

Alan Bailey & Kay Cashman
Petroleum News

The snow has been falling and the ground freezing in Arctic Alaska, and the various companies planning exploration wells for the coming winter season are lining up for what looks like being one of the busiest ever exploration seasons on the North Slope. The annual freeze-up has yet to reach the point where Alaska Department of Natural Resources can open up state land for off-road travel, but the department said on Nov. 18 that it had been approving the pre-packing of ice roads for a number of projects in its western coastal area, and also for a winter road between the North Slope Haul Road and the lower foothills area.

Brooks Range pre-packing snow

At the Resource Development Council annual conference on Nov. 17, Bart Armfield, chief operating officer of Brooks Range Petroleum Corp., said that his company had just starting pre-packing snow for an ice road that will run from the southwest corner of the Kuparuk River unit to the company’s North Tarn No. 1 well. Brooks Range found oil when drilling this well last winter but it now plans to use the Nabors 7-ES rig to further deepen the well through the Kuparuk C zone and do some flow testing. The company also plans to drill two appraisal wells, the Mustang No. 1 and Mustang No. 2, with these wells and the North Tarn well all being in the newly formed Southern Miluveach unit. In anticipation of what the company calls its “Mustang development” in the unit, this winter the company will also explore for sources of gravel for future roads and pads, Armfield said.

Repsol has largest program

Spanish major Repsol YPF is running by far the biggest exploration program on the North Slope this winter — the company plans to use five drilling rigs at five locations in a partnership with Armstrong Oil & Gas and GMT Exploration Co., drilling multiple wells in their 494,211 acres of state lease holdings.

Repsol’s Alaska operations manager Bill Hardham told the RDC conference on Nov. 16 that his company has been extremely busy gearing up for its winter drilling and that the company will access its drill sites from a network of ice roads originating at the Palm and Meltwater fields.

Four of the drilling locations are in an area of the Colville River Delta where the company has applied for a new Qugruk unit, and the fifth location is called Kachemach, south of the Meltwater field.

Including sidetrack wells, Repsol is permitting a total of 15 wells and five pads, but Hardham anticipates completing about 12 wells, and carrying out two or three drill stem tests.

The company is leasing an office in Anchorage for the winter, as well as establishing a camp office in Deadhorse. And, given the intensity its exploration activity, Repsol has contracted with Alaska Airlines for two flights per week to the North Slope from Anchorage, Hardham said.

He said Repsol’s aggressive approach to exploring in its leases reflects the fact that the leases are set to expire within just six years, although establishing oil production in Alaska as part of the company’s worldwide portfolio is also very important.

According to State of Alaska records, 84 of the company’s leases expire in 2012, 2013 and 2014.

Five wells for Linc at Umiat

Australian independent Linc Energy plans to drill up to five wells in the undeveloped Umiat oil field, on the border of the National Petroleum Reserve-Alaska, to the south of the central North Slope, Corri Feige, Linc general manager for Alaska, told the RDC conference.

The company wants to conduct oil flow testing from three or four of the wells, to obtain data for a field development plan, she said. Permitting for this winter’s drilling is well under way.

Linc will also be installing air quality and weather monitoring equipment this winter, to obtain data needed for future air quality permits for oil production, she said.

The known oil resource at Umiat occurs at shallow depths — Linc also sees possibilities for finding additional oil and gas in deeper structures at Umiat and anticipates starting drilling into those horizons in 2012, Feige said.

Access to Umiat will be by a 90-mile snow-packed road from trans-Alaska pipeline pump station two on the Dalton Highway, she said.

On Nov. 21 Linc spokeswoman Colleen Richards told the Anchorage Chamber of Commerce that the company is still working on securing a rig for its drilling program.

Farther south in Alaska Linc is embarking on another program of exploration drilling, seeking locations for underground coal gasification developments in the company’s state exploration license acreage in the Healy area of the Alaska interior and in the Cook Inlet area. The company has started drilling its first test hole near Beluga on the west side of Cook Inlet and is acquiring some 2-D seismic data for its exploration program, Feige said. The company anticipates drilling four more underground coal gasification wells by the middle of 2012, she said.

Underground coal gasification involves using a controlled underground coal burn to generate synthetic gas for power generation, or for conversion to natural gas or other products.

Anadarko and Pioneer

Back in northern Alaska, Linc will co-locate a portion of its snow packed road to Umiat with a road that Anadarko Petroleum plans to build for access to its Chandler No. 1 gas well. Anadarko plans to conduct some rig-less testing of the Chandler well this winter.

North Slope producer Pioneer Natural Resource plans to drill two wells in its Nuna development on the eastern side of the Colville River, in the southern part of Pioneer’s recently expanded Oooguruk unit.

Savant working on rig deal

Savant Alaska wants to drill a new well on the crest of its Red Wolf prospect in the Badami unit but is still trying to obtain a drilling rig for this project.

In a Nov. 18 email Savant Vice President Greg Vigil told Petroleum News that he expected the drilling project to move ahead this winter and that Savant was currently working a rig deal.

The Red Wolf well will target the Kekiktuk formation, the formation that contains the oil reservoir for the Endicott field, west of Badami.

Rig less likely for UltraStar

UltraStar, a small independent Alaska explorer, has also been looking for a rig to drill the North Dewline No. 1 well, the second well in the Dewline unit, on the coast north of the Prudhoe Bay unit.

At the beginning of November the company notified Alaska’s Division of Oil and Gas that, owing to the lack of an available drilling rig, it was very likely that the company would have to defer its planned drilling into 2013, UltraStar Managing Member Jim Weeks told Petroleum News in a Nov. 20 email. However, the company asked the division to continue processing its permits in case a rig comes available at short notice, should another company change its plans.

Great Bear waiting on permits

Great Bear Petroleum, the company pioneering the possibility of source rock, shale oil development in Alaska, hopes to drill its first test wells on its North Slope acreage in the coming winter.

Ed Duncan, Great Bear’s president and COO, told Petroleum News Nov. 21 that he is considering several rig options, including the possibility of bringing a more modern rig from the Lower 48 that Great Bear thinks may be better suited for drilling in source rock plays; a rig that will have to be made Arctic ready.

Duncan said that he is not going to contract the use of a rig until he is certain of securing all of the permits he needs for his year-round exploration and evaluation program. Permitting is progressing well, he said.

The company has formed a joint venture with oilfield service company Halliburton, in which Halliburton will do some of the test drilling within a limited area of Great Bear’s leases.

Great Bear is permitting six wells on six gravel pads along the Dalton Highway, intending to run short tests on at least four wells before deciding to sanction a pilot plant. It will use a combination of rig mats and existing surface infrastructure at each site, Duncan said.

In Nov. 1 testimony to a special meeting of the Alaska Legislature’s House Resources Committee, Duncan said Halliburton and Great Bear each plans to drill as many as three vertical wells and a lateral from each of those wells.

What I learned at the Resource Development Council's Annual Conference - Deborah Brollini

2011-11-19T19:08:00.004-09:00

Watch live streaming video from dbrollini at livestream.com

Budgets flat, down; BP, ConocoPhillips say tax change needed to make projects competitive

2011-11-18T17:12:00.002-09:00

Kristen Nelson
Petroleum News

That was the message the Resource Development Council’s annual conference heard Nov. 16 from BP Exploration (Alaska) and ConocoPhillips Alaska, operators of the major fields on Alaska’s North Slope.

Trond-Erik Johansen, president of Conoco Phillips Alaska, and Claire Fitzpatrick, chief financial officer for the Alaska region and senior vice president of BP Exploration (Alaska), both said that if the state wants more oil in the pipeline, it needs to change its tax structure.

And both said that while high oil prices make investment attractive in other oil provinces, they don’t plan additional investments in Alaska in 2012.

Johansen said that while ConocoPhillips’ figures haven’t been finalized for 2012, he expects the company’s capital budget to be flat, about the same it was in 2010 and 2011. He didn’t give figures, but according to the graph he used in his presentation, 2011 spending was up slightly from 2010, both in the $800 million range.

Fitzpatrick said that a year ago BP said it would invest about $800 million in capital in Alaska in 2011, but she expects “our final capital budget will be $700 million” for 2012.

ConocoPhillips’ view

Johansen said throughput in the trans-Alaska oil pipeline has dropped another 7 to 8 percent since November of 2010, while production in the Lower 48 has continued to go up. While Alaska used to be the top producer in the United States, it is now number three after the Gulf of Mexico and Texas — and, he said, it looks as though Alaska will soon drop below California. With production in North Dakota is climbing. Alaska could soon be in fifth or sixth place, he said.

Why isn’t Alaska production increasing?

The “easy oil” has been drilled, Johansen said. The sweet spots were drilled when the fields were developed. In the early days it took a very short time and cost very little money to drill wells.
“And when you put them on, they produced a lot of oil and gas,” Johansen said.

There is a lot of light oil left on the North Slope, he said, but “it’s not easily accessible” as it was in the past.

For one thing, while initial water production was low, 3 million barrels a day of water are now being produced.

“We’re more a water production company than an oil production company,” he said, and that water has to be managed: It’s re-injected and used for waterflood.

The other big problem, Johansen said, is the current production tax system, Alaska’s Clear and Equitable Share or ACES. ACES takes away the incentive to invest at high oil prices, he said.

Cost of wells up

Johansen illustrated relative drilling costs at fields operated by ConocoPhillips — Kuparuk, Tarn, West Sak and Alpine — because ConocoPhillips has the data for those fields.
Using inflation-adjusted figures, he said the early wells in Kuparuk, West Sak and Tarn, cost about $2 million to $4 million a well and took about 10 to 15 days to drill.

“Today it costs four times as much and it takes four times as long,” because wells are no longer vertical or near vertical, but now are horizontal.

“And the bad news is that those wells produce less. So we need more of them.”

ConocoPhillips is still spending a lot of money drilling wells, “but we get less and less oil.”

With the same amount of money and the same number of rigs, there is less production out of each well bore, he said.

“My point is we need to drill more wells. We need to have more people working on more wells. That also means it needs to make commercial sense to us,” Johansen said.

State take an issue

With the progressivity in ACES, the higher the oil price the less incentive there is to drill for challenged oil, he said, compared to other places where taxes and royalties are flat. In North Dakota, he said, taxes and royalties are 55 percent. “Right now it’s about 85 percent in Alaska.”
Other places in the world also have high taxes, but when the price of oil goes up, taxes and earnings rise together.

“We take the risk; we want a fair share of that reward for taking that risk and that’s not happening” in Alaska right now.

Johansen said the question is when Alaska will benefit.

With reduced oil taxes, “If you look at it from a very, very short-term perspective standpoint, the state would see less revenue in the short term.”

But what about the long term, “What about the next generation?” he asked.

If there are “improvements in the fiscal regime here, you will see more action. … You will see more drilling; you will see more projects. … That’s just the way capitalism works.”

He said the question is whether the discussion will be “around short-term gains or are we going to talk about the long-term future?”

BP: prospects exist

Fitzpatrick said BP’s planned activity on the North Slope over the next couple of years “won’t begin to offset” the 7-8 percent decline the company sees in the fields it operates, fields which account for about two-thirds of current North Slope production.
What the company currently plans to spend, she said, represents “maintenance, repair work that needs to get done and also development work that currently makes economic sense.”

But the possibilities that exist include prospects “that represent billions of dollars in new investment and billions of barrels of new oil, billions of dollars of new revenue to the state and permanent fund and thousands of long-term, well paying jobs.”

“But these are prospects that do not make economic sense in the current business climate in Alaska,” Fitzpatrick said, and “will remain merely possibilities unless Alaskans and the oil industry work together to make changes to make these possibilities commercially viable and competitive.”

BP’s current plans include continuing the heavy oil pilot that’s on line, “but we’ll not be investing in any further heavy or viscous development beyond some studies over the next couple of years.”

There will be “significant investments in infrastructure and pipeline upgrades,” but capital spending on activities that produce more oil, such as drilling and pad expansion, are “limited or on hold.”

Production down

Production has dropped more than 140,000 barrels per day since ACES passed, Fitzpatrick said.

The Department of Revenue’s spring forecast predicts a 13 percent decline in statewide production between 2011 and 2020, she said, but the department “was also clear that 52 percent of the forecast volume in 2020 was from projects under development or evaluation, including projects in existing producing fields.”

She said she didn’t know what the next Revenue forecast will show, but BP is showing steeper declines over that period than it was a year ago.

“We’re looking at something like a 25 percent decline between now and 2020,” Fitzpatrick said.

BP’s focus is on sustaining infrastructure, improving the efficiency of its activities “and doing strictly preliminary work to keep things on line that might be economic then under a different fiscal regime.”

Only two things are keeping BP from sustained decline over the next nine years: Liberty, “which is on federal land and not subject to ACES,” and efforts to extract as much oil as possible from existing fields.

But it’s still a 25 percent decline, she said.

A lot of possibilities

“I have a lot of possibilities; I don’t need to go exploring for them,” Fitzpatrick said.

Some of those have had enough work done on them that they are ready for consideration when the investment climate becomes more competitive, she said. Among those are I Pad development at Prudhoe Bay; western region development at Prudhoe; S pad expansion with low salinity water flooding; and Sag River reservoir development at Milne Point.

Fitzpatrick said if those had moved forward over the past four years, “that 25 percent decline that I see would be essentially flat over that timeframe.”

“BP and our partners are poised to invest billions of dollars in new projects,” she said, but those projects can’t compete.

“Alaska’s got major reserves already discovered, but it’s running out of investors willing to spend the billions of dollars necessary to actually make those projects into investment,” Fitzpatrick said.

Two things are required, she said: “New projects have to compete for investment capital and existing activities must generate cash.”

“In this environment, new projects can’t compete for investment; and current activities don’t generate the cash required to actually fund them,” Fitzpatrick said.

“Make the economics less favorable, we do less,” she said. “Make the economics more favorable, like the governor proposed and House Bill 110 would do, we respond accordingly: More investment, more production.”

Work on gas bullet line continues, officials say

2011-11-18T05:44:00.002-09:00

By Tim Bradner
Alaska Journal of Commerce

Engineering and planning for a 24-inch natural gas pipeline from the North Slope to Southcentral Alaska by a state of Alaska corporation is continuing for now, despite new gas discoveries in Cook Inlet.

Escopeta Oil recently announced that it had discovered natural gas in Cook Inlet. Escopeta representatives told Anchorage Mayor Dan Sullivan’s Energy Task Force that the company would not be able to confirm proven natural gas reserves until next summer, said Dave Harbour, a spokesman for Alaska Gasline Development Corp., which is planning the 737-mile, 24-inch pipeline project.

Escopeta has estimated its discovery at about 1.4 tcf in recoverable resources, but further testing is needed.

Meanwhile, AGDC officials said work on the 24-inch pipeline from the Slope must continue if the project is to stay on schedule to meet Southcentral Alaska energy needs if Escopeta’s find doesn’t work out.

“The Legislature, with Governor (Sean) Parnell’s support, created the ADGC in 2010 to ensure that by the end of the decade Interior and Southcentral Alaska citizens have adequate supplies of natural gas at the lowest possible price. We remain dedicated to that mission,” Dan Fauske, CEO of the state corporation, said in a statement.

House Speaker Mike Chenault said it is important to continue support for the in-state gas pipeline as a fallback.

There is an estimated 35 tcf of gas that has been discovered on the North Slope. TransCanada Corp. and ExxonMobil Corp. are working on a proposed 48-inch pipeline from northern Alaska to Alberta, but the project appears to have bogged down following large new shale gas discoveries Outside.

Parnell recently asked North Slope producers and TransCanada to reconsider LNG exports from Alaska as an alternative, but whether that might happen is uncertain.

Fauske, of ADGC, has said previously that if a large-diameter pipeline is built from the Slope, the state’s 24-inch pipeline project would become a spur line off the larger pipeline. But if the big line continues to stall the state should be prepared to build the 24-inch line all the way to the Slope, he said.

The state pipeline corporation is now working on a federal Environmental Impact Statement for its project and in securing of a federal right-of-way, said Dave Haugen, project manager. The draft of the EIS is now expected in early spring. The schedule for the EIS has slipped. It had been expected in September.

A right-of-way across state lands has already been secured for the project, he said.

This winter AGDC’s technical group will be evaluating data gathered in the 2011 summer field program, and planning is also under way for the 2012 field program, Haugen said.

Much of the field work is focused on river crossings, including the Yukon and Tanana rivers, as well as at Atigun Pass in the Brooks Range, where there is constricted space because the existing trans-Alaska oil pipeline also uses the pass.

The Legislature has appropriated $44 million over the last two years to support work on the 24-inch pipeline. A state appropriation will be requested for continued work in 2013 but Parnell has not yet approved the amount, according to ADGC financial officer Joe Dubler.

The appropriation is expected to be part of the governor’s fiscal year 2013 budget request that will be released Dec. 15. The Legislature must approve the appropriation.

AGDC has previously said that it will need to spend about $400 million in engineering, planning and the acquisition of permits by the time the project is approved for construction.

Tim Bradner can be reached at tim.bradner@alaskajournal.com. Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-November-20-2011/Work-on-gas-bullet-line-continues-officials-say/#ixzz1e4IfAOiZ

Winter’s here; utilities beef up Southcentral energy systems

2011-11-14T21:51:00.001-09:00

Analysis by Tim Bradner
Alaska Journal of Commerce

Crews work on the new power plant in South Anchorage. The main building has three large boilers that will power a large steam turbine. The joint project between Chugach Electric and ML&P sprawls 40 acres and is due to be completed in 2012. It will feature three new GE LM6000-PF gas turbines that heat the boilers. Each can generate 46 megawatts of power that is then sent to one large steam turbine.

Crews work on the new power plant in South Anchorage. The main building has three large boilers that will power a large steam turbine. The joint project between Chugach Electric and ML&P sprawls 40 acres and is due to be completed in 2012. It will feature three new GE LM6000-PF gas turbines that heat the boilers. Each can generate 46 megawatts of power that is then sent to one large steam turbine.

There’s good news – possibly – about new natural gas discovered in Cook Inlet. But that wouldn’t be in production for two to three years, if Escopeta Oil’s find is proven after more tests and drilling.

Closer at hand, one sure bet is that a new gas storage facility near Kenai will be ready for use next year. It’s in construction now, and it will help the regional utilities insure against cold-weather interruptions in gas supply in 2012.

Likewise, the new Southcentral Power Plant and Fire Island wind projects will be on-line in 2012. Those will significantly reduce the draw on the Southcentral region’s dwindling gas reserves, regional utility managers told the Anchorage Chamber of Commerce Nov. 8 in a joint-briefing on the local energy situation.

The new Southcentral Power Plant will allow Chugach and ML&P to generate power with 25 percent less gas.

“At today’s gas prices the reduced fuel use will save our members $27 million in fuel-use charges in the first full year of the plant operation,” Chugach spokesman Phil Steyer told the Anchorage chamber.

The Fire Island wind project will also result in reduced gas use, about half a billion cubic feet a year, when it is on line in late 2011.

There’s still this winter, however. This year, for the first time, Southcentral Alaska will be without an operating liquefied natural gas plant in Nikiski, which in previous winters diverted gas to the region’s utilities during cold snaps.

Plant owner ConocoPhillips is continuing with plans to mothball the facility in December after making one more shipment of LNG to Asia in late November, according to company spokeswoman Natalie Lowman.

This creates a new uncertainty, one more complication in a delicate regional energy situation. The gas wells that now supply the LNG plant are still available but it’s not as easy to turn them on and off to meet a short-term gas needs for the utilities. When the LNG is operating, the manufacture of the liquefied gas could more easily be turned off, or at least down, and the gas diverted to the utilities.

Some good news for this winter, however, is that the regional utilities have made investments in additional gas compression to beef up the distribution system.

Owners of the Beluga gas field west of Anchorage are investing $90 million in new drilling and compression this year to ensure adequate deliveries of gas, said Jim Posey, general managers of Anchorage’s city-owned Municipal Light and Power, which owns a third of the Beluga field.

About $50 million of the $90 million being spent at Beluga is being invested in compression, and much of the remainder was spent in the drilling of a new production well, Posey said. Beluga field owners, ML&P among them, plan another $258 million in new compression and drilling over the next five years, he said.

The added compression available this winter is important because it will enable the Beluga producers to supply up to 100 million cubic feet a day of gas to customers, Posey said.

In recent years the deliverability of Beluga gas has dropped to 70 million and 80 million cubic feet a day. When it started up three decades ago Beluga was producing up to 200 million cubic feet a day.

Another development is that Enstar Natural Gas Co. has new compression available on its own system and also will have new gas available from independent producers, company spokesman John Sims said. Enstar’s president, Colleen Starring, had spoke to the chamber the previous week.

Enstar’s new suppliers include Anchor Point Energy, a subsidiary of Armstrong Oil and Gas, who will supply about 1.2 billion cubic feet per day, and Buccaneer Energy, who will supply about 1.3 billion cubic feet per day to Enstar in 2012. Enstar also buys gas from long-established Cook Inlet producers Marathon Oil, ConocoPhillips and Unocal, which is owned by Chevron.

Buccaneer and Cook Inlet Energy, which operates the West McArthur River and Redoubt Shoal fields on the west side of Cook Inlet, are also eligible to sell more gas to Enstar under the company’s auction-purchase system.

Armstrong Oil and Gas operates gas wells at the North Fork field east of Homer. Buccaneer Energy has one completed gas producing well near Kenai.

Chugach Electric Association spokesman Phil Steyer said Nov. 8 that if there is a gas supply glitch, the priority among the utilities is to preserve the pressure in Enstar’s gas system because if Enstar’s gas pressure falls below a certain point, the regulators in furnaces kick off and it’s a big problem to get all of them restarted.

Steyer said the electric utilities have options Enstar doesn’t have, like switching some power plants to diesel and purchasing power from Golden Valley Electric Association in Fairbanks.

Energy conservation among consumers and businesses would also be important, he said. The recent “Energy Watch” drill by the utilities and the municipality of Anchorage saw a 1 percent to 2 percent voluntary decrease in use of gas, and in real event the response would be higher, Steyer said.

ML&P’s Posey said voluntary cutbacks by commercial building owners in the Anchorage bowl would be important in a gas supply disruption. In meetings with building owners and managers Posey has urged them to develop an energy conservation strategy.

Joe Griffith, CEO of Matanuska Electric Association, said his utility has a substantial program to upgrade transmission and distribution lines in the MEA service area and is working on engineering and permitting for its own gas-fired power plant, which will be located at Eklutna, north of Anchorage.

This article appears in the AJOC November 13 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-November-13-2011/Winters-here-utilities-beef-up-Southcentral-energy-systems/#ixzz1dkq6rNoF

Zero to 90

2011-11-13T20:07:00.024-09:00

Deborah Brollini

Most who can keep up with me know that I flew to Juneau in February for the Chamber fly-in, and turned the legislature upside down with my testimony to House Resources. Up to that point no one was telling the Alaskan story. I brought reality to the tax debate and a glimpse of what was yet to come for our state because I survived the crash of 1986.

After I returned from Juneau I parked myself at the Loussac Library, and began researching 1986 the year Alaska’s economy crashed. I was young and in my 20s and very busy doing all the things I should have been doing at my age. I was working full-time foreclosing on homes, going to college, and having fun. It was not until I returned from Juneau, and began researching 1986, did I even get how bad things really were, and started hunting down leaders from that time.

After a month of research I run to Joe Beedle, President of Northrim whom in 1986 was referred to as “the hatchet man” and asked him “did our economy crash in 90 days? “ I then go to Scott Hawkins who was an economist at the time who wrote for the Anchorage Times and ask him the same question. Unsatisfied with the answers because they concurred I go to Governor Bill Sheffield and ask him did our economy crash in 90 days? “Yes, Deborah I was there.” Our economy crashed in 90 days, and so what has Alaska learned?

Alaska’s economy crashed because oil prices dropped to $20 on January 1st 1986, and by April 1st 1986 it was over. Alaska got out of it because oil prices rose, and we had lots of oil in our pipeline. Today, Alaskans have a choice. Do we continue on this path, or do we think outside the box, and look at all options? Alaska has so many options and opportunities if we would just get out of our damn way, and everyone has a seat at the Alaska table…. are you in?

To those who think I’m a “shill” for big oil. Would it surprise you to know that I have received my paychecks from the healthcare industry for the past 10 years? This issue has always been about my children’s future. All have access to my research. I am currently writing a white paper about the year Alaska's economy crashed which is kind of turning into a book, and I am doing it at my own expense, and personal time, and all in the vain of Lyndsey and Van’s future. What are you doing for Alaska, and our state's future?

A source of uncertainty; USGS grapples with assessing the North Slope source rock oil potential

2011-11-13T06:11:00.002-09:00

Alan Bailey
Petroleum News

With escalating interest in the potential to produce oil directly from source rocks on Alaska’s North Slope, the U.S. Geological Survey is in the process of conducting an assessment of shale oil resources in northern Alaska. The idea is to use whatever information is available about North Slope geology to estimate ranges of hydrocarbon volumes that might be recovered from the source rocks using the horizontal drilling and fracking techniques that have proven so successful in the Lower 48 states.

On Oct. 25 USGS held a meeting in Anchorage, Alaska, to share its approach to its assessment with Alaska geologists and other specialists, to obtain feedback and comments before determining its resource estimates. USGS anticipates proceeding with the assessment in November, with publication of the results likely in January or February, USGS geologist Dave Houseknecht told the meeting.

Assessment method

The USGS method of estimating the volumes of oil and gas that might be recovered directly from an oil source rock involves mapping the disposition of the source rock in the subsurface; estimating the area of source rock that each production well might be able to access; and estimating the total ultimate recovery of oil from each well. By then calculating the total number of wells needed to access the entire area of the source rock and multiplying the number of wells by the per-well ultimate oil recovery it is possible to estimate of the total quantity of oil that might be produced.
But because none of the numbers involved in the estimating procedure are ever completely certain, the scientists use statistical techniques to factor in the various uncertainties involved, eventually deriving a range of possible total oil volumes that may be recoverable.

Uncertainty arises, for example, from the fact that rock properties and the detailed history of the rocks are never completely uniform across an entire play area: Source rock oil plays have “sweet spots” where oil production is particularly prolific, while other areas may be much less productive. And a key to gaining insights into potential oil production in a source rock play is an understanding of the parameters that can identify where oil and gas can likely be produced and where the sweet spots may be located. Parameters include the brittleness of the rock and indicators of likely oil or gas generation.

Challenges

Houseknecht told the audience at the Oct. 25 meeting that key challenges facing the North Slope assessment include the difficulty of mapping appropriate source rock parameters, given the scarcity of wells penetrating the rocks in areas where source rock oil development might occur. There is also the lack of a history of source rock oil production in the region — ultimate proof of the technical viability of source oil development will depend on drilling some successful production wells.
And, in the absence of any existing North Slope source rock oil development, the USGS assessment depends on identifying shale oil plays elsewhere that can be used as analogues for North Slope source rock plays. Oil productivity from analogues in the Lower 48, for example, can be used for guidance on possible productivity from North Slope source rocks with similar characteristics and geologic histories.

There are three major source rock systems on the North Slope: the late Triassic Shublik, the Jurassic lower Kingak, and an assemblage of rocks of Cretaceous age, including the Hue shale and HRZ or GRZ, within what is known as the Brookian sequence.

Most North Slope source rock oil interest is focused on the Shublik, which has an obvious analogue in the Eagle Ford shale, the rock formation at the center of successful oil shale development in Texas. Both the Shublik and the Eagle Ford have similar organic carbon contents and both are relatively brittle, thanks to an abundant presence of carbonate minerals — rock brittleness is an important factor in the hydraulic fracturing required to induce oil to flow from shale.

Thermal history

However, Houseknecht cautioned about some significant issues relating to the thermal history of North Slope source rocks, when compared with the Eagle Ford and with the Bakken formation, a prolific oil shale in North Dakota.
In a petroleum system such as that on the North Slope, an underground source rock has been heated, progressively passing through temperatures that first generate oil and then natural gas from organic material in the rock. There is a specific temperature window within which oil is generated and a higher temperature window within which gas forms.

As the temperature rises through the gas window, a point is reached at which oil, formed previously at lower temperatures, breaks down to form additional gas. That secondary gas generation from the “cracking” of oil typically leads to elevated fluid pressures within the source rocks, Houseknecht said. And in the Eagle Ford, for example, this “overpressure” from the cracking of oil has driven up the fluid pressure in the petroleum system and has become a factor in oil production, he said.

But, while the oil in the Eagle Ford and the Bakken has formed relatively recently in terms of geologic timescales, most geologists think that the oil in all of source rocks under the North Slope formed much earlier, with generation completed by 50 million to 60 million years ago, Houseknecht said. Thanks to the leakage of fluid from the rocks, the overpressure decays over time thus leading to the probability that overpressures within the North Slope rocks will tend to be lower than in their Lower 48 analogues, Houseknecht said. And the lower overpressures could impact oil production.

The concept that earlier overpressures have decayed seems to be borne out by pressure measurements within wells in the region, with abnormally high pressures limited to rocks in the southern, deeper part of the basin where rapid, deep burial, rather than hydrocarbon production, has likely caused overpressure development.

Thermal measurement

Houseknecht also expressed some caution over the way in which geologists normally assess the thermal history of rocks, and hence determine areas in which oil or gas may have been generated. The standard method of assessing rock temperature histories is the measurement of the reflectivity of vitrinite, a coal component commonly found in rocks containing organic material. According to conventional wisdom, very specific vitrinite reflectance values indicate whether a rock has been heated into the oil or gas generation window. Geologists use the mapping of vitrinite reflectance values from rock samples to delineate areas thought to be prospective for oil or gas, with this technique being used on the North Slope as one of the ways to map potential source rock oil plays.

But recent research has indicated that the vitrinite reflectance boundaries for oil and gas generation are much less clear cut than previously thought, with the reflectance thresholds sometimes varying from one rock formation to another, Houseknecht said. That raises questions over the reliability with which it possible to map areas on the North Slope likely to be conducive for oil or gas generation, especially given the small number of wells penetrating source rocks outside the area of the North Slope oil fields.

Rock variability

Another area of uncertainty when assessing the Shublik is the high level of variability in rock type within the formation. The Shublik consists of various different rock units containing different amounts of materials such as sand, silt and carbonate minerals, University of Alaska Fairbanks scientist Mike Whalen told the Anchorage meeting. And there are three distinct sequences of rock within the Shublik, with the organic carbon content that could generate oil or gas varying from being particularly high in one sequence to being moderate or low in others. The organic carbon content tends to be concentrated into fairly thin rock units, Whalen said.

And depending on exactly which parameters are used to assess the areas of the Shublik likely to have produced oil or gas, the total area of the source rock oil play could range anywhere from 3.7 million to 9.3 million acres for oil, and from 14.9 million acres to 23.6 million acres for gas, Houseknecht said.

The area of a potential source rock play in the Brookian source rocks appears to be smaller than that of the Shublik, but with the Brookian showing overall more potential for oil than for gas. But the rocks in the Brookian do not appear as suitable for hydraulic fracturing as those in the Shublik, thus raising questions over the likely effectiveness of Brookian source oil production. The other North Slope source rock, the lower Kingak, appears to be especially problematic as a target for hydraulic fracturing, since it contains much fairly ductile clay material, Houseknecht said.
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Republshed with the permission of Petroleum News

CIRI drilling confirms coal seams suitable for UCG; seismic planned

2011-11-06T00:59:00.003-08:00

Alan Bailey
Petroleum News

After an exploration program involving the drilling of 13 core holes, Cook Inlet Region Inc. has confirmed the existence of a significant coal resource likely to be suitable for underground gasification in the corporation’s land on the west side of Alaska’s Cook Inlet.

“We’ve done a significant amount of exploration work,” Ethan Schutt, CIRI senior vice president for land and energy development, told the Alaska Senate Resources Committee on Oct. 20. “Through that work we’ve confirmed that we have a significant commercial coal resource in a geological setting that is favorable for UCG (underground coal gasification) development.”

CIRI land

Stone Horn Ridge LLC, a joint venture between CIRI and Laurus Energy, is investigating the potential UCG development at a site called Stone Horn Ridge, northeast of the Beluga River, in an area where CIRI owns both the surface and subsurface land. Laurus Energy is a Houston-based affiliate of Ergo Exergy, a UCG technology company based in Montreal, Canada.
UCG involves the pumping of compressed air through a well into a coal seam deep underground to enable the controlled underground combustion of some coal; the heat from the burn converts excess air and the bulk of the coal to synthetic gas for delivery to the surface through production wells. It would be possible to burn the synthetic gas for power generation or to convert it to methane, the prime ingredient of natural gas. Other potential applications include the production of jet fuel by a gas-to-liquids process, or the production of fertilizer.

And, since the coal is processed deep underground, the UCG process eliminates much of the environmental impact of conventional coal mining and burning.

“We believe that UCG is a technology by which you can access this world-class energy resource in an environmentally acceptable manner,” Schutt said.

Schutt also assured the legislators that the underground burn required for the UCG process could be stopped very easily by closing off the flow of air required for combustion.

Multiple coal seams

Schutt said that the Stone Horn Ridge joint venture has found multiple, thick coal seams at depths below 650 feet in the Stone Horn Ridge area. The geologic setting of the coal appears favorable for the development of a UCG plant, although the joint venture is still in the process of collecting data and modeling the geology of the project site, he said.
The 13 core holes drilled for the exploration phase of the project penetrated depths ranging from about 700 feet to about 2,600 feet — the project team collected rock core and wireline data from the holes. Field and laboratory examination of rock samples; logging of the drilling mud; and field tests of the desorption of gas from coal samples also added to the data from the project site. That data have enabled the construction of a comprehensive computer-based geologic model of the site that has provided a preliminary validation of the existence of a commercial UCG resource.

The next step will be to carry out a high-resolution shallow seismic survey, gathering eight line-miles of data along three lines over a period of about 25-30 days.

“With that data we’ll complete our preliminary model of the site, incorporating that with the data that we already have, and that will help us move to the next phase of the program, which is the (resource) characterization phase,” Schutt said.

Conceptual engineering

The joint venture has already commissioned and obtained a conceptual engineering and cost analysis for a UCG development at Stone Horn Ridge, with the analysis considering various options for the use of UCG-generated synthetic gas, Schutt said.
The geologic modeling indicates the existence of about 300 million tons of coal in the Stone Horn Ridge site, a UCG resource equivalent to perhaps a little more than 4.8 trillion cubic feet of natural gas, with potential gas production rates in the range of 20 billion to 90 billion cubic feet per year, Schutt said.

And CIRI thinks that UCG-fueled electricity generation, for example, would prove significantly cheaper than generation from Cook Inlet basin natural gas, Schutt said.

But, with the project being at the leading edge of UCG technology deployment, CIRI is taking its time, being “pretty deliberate and responsible” and talking to stakeholders as the project moves forward, Schutt said.

“We’re pretty excited about the project and its potential, but we do also realize that we’ve got a lot of work in front of us,” he said.

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Republished with the permission of the Petroleum News

Pump station plumbing; Alyeska to spend millions to reconfigure piping as safeguard against corrosion

2011-11-06T00:10:00.001-08:00

Wesley Loy
For Petroleum News

The operator of the trans-Alaska oil pipeline is embarking on an expensive, three-year program to replace piping in several pump stations.

The work stems from a settlement Alyeska Pipeline Service Co. reached with federal regulators following a corrosion-caused oil spill in January at Pump Station 1 on the North Slope. The leak forced a lengthy shutdown of the pipeline.

Alyeska has told the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration it has completed a risk assessment of pump station piping that’s subject to corrosion and difficult to inspect. It was piping of this sort that leaked at Pump Station 1.

As a result of the assessment, Alyeska is designing plans for work at pump stations 1, 3, 4, 5 and 9.

“These designs will replace buried non-inspectable crude oil piping with piping in an above ground alignment,” says a summary document Alyeska provided at the request of Petroleum News.

Costly campaign

The piping replacement work actually consists of several major projects, each to cost “tens of millions of dollars to complete,” said Alyeska spokeswoman Michelle Egan.
Firms under existing contracts will handle part of the work, with some jobs to be put out for bid, Egan said.

The piping to be replaced is characterized as “dead leg, low and intermittent flow, and concrete encased piping,” the summary document says. Such piping can’t be excavated for inspection, or inspected internally with tools called pigs.

Alyeska has given regulators a schedule for doing the piping replacements. Pump Station 1 will see “the most complex and critical” project, Alyeska says. It will be the first station to have its below-ground crude oil piping rerouted to an above-ground configuration.

The final design for Pump Station 1 will be finished by year’s end, with construction to start in the first quarter of 2012 and conclude in the fourth quarter of 2013, the schedule shows.

Projects will follow at pump stations 3, 4, 5 and 9, with all the piping replacements to be finished by the fourth quarter of 2014.

“Each of the pump stations will have a two year construction season to complete all of the piping work,” the Alyeska summary says. “The first construction season will install civil foundations, pipe supports, trenches, and other preparatory work and the second season will install the piping and make the final tie-ins.”

Aging pipeline

Alyeska is the Anchorage-based consortium that runs the trans-Alaska pipeline on behalf of owners BP, ConocoPhillips, ExxonMobil, Chevron and Koch Industries.
The pipeline has been moving oil from Prudhoe Bay and other North Slope fields since June 20, 1977.

Federal pipeline regulators hit Alyeska with a “notice of proposed safety order” in February, following the leak inside a Pump Station 1 building basement. The leak forced a pipeline shutdown lasting about three and a half days.

The leak was described as a booster pump manifold failure. A manifold is an arrangement of piping or valves designed to control, distribute or monitor fluid flow.

The mainline, 48-inch pipe was not involved.

Alyeska retained Det Norske Veritas, a Norwegian concern specializing in risk management, to do an independent investigation of the Pump Station 1 leak.

A 6-foot section of piping, containing the location of the leak, was removed and shipped to Det Norske Veritas for metallurgical analysis, the Alyeska summary says.

In their proposed safety order, federal pipeline regulators cited “multiple conditions” on the pipeline that appeared to pose an integrity risk. The concerns centered on the pipeline’s declining oil throughput and the potential for freeze-ups and corrosion.

As part of the settlement Alyeska signed with PHMSA in August, Alyeska agreed to replace or remove hard-to-inspect oil piping.

Marine terminal involvement

“It’s important to emphasize that a lot of these piping issues can be attributed to declining flow through our systems and that many of these piping projects were already planned,” Alyeska’s Egan said.
Aside from the pipeline itself, Alyeska operates the Valdez Marine Terminal, where the line ends and where tankers pick up crude for delivery to West Coast refineries. The terminal is a sprawling, waterfront complex of tanks, pipes and piers.

The Alyeska summary says a risk assessment was done not only for pump station piping, but also for marine terminal facility piping.

The summary, however, says nothing about any planned piping replacements at the terminal.

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Republished with the permission of the Petroleum News

South to the Future: North Dakota’s Oil Boom Series

2011-11-01T08:30:00.004-08:00

By Steve MacDonald
Channel 2 News
10:13 a.m. AKDT, October 31, 2011

WILLISTON, North Dakota —
Once upon a time, the town of Williston, North Dakota was a tranquil dot in the middle of the vast prairie, a place where you could drive for hours in any direction and pass maybe one other car.

But today, things are different – and just driving through town means fighting a traffic jam of pickup trucks.

It’s been this way ever since Williston became the epicenter of one of the largest oil fields in North America.

Armed with new technologies, oil companies are reaching into the massive Bakken field, a geological formation that contains a possible 11-billion barrels of recoverable oil.

To get at the oil, thousands of wells must be drilled.

For North Dakota, the hiring boom for workers on the Bakken field looks a lot like Alaska in the 1970s – when thousands of workers rushed to find work on the North Slope.

Among those landing work in the fields are a growing number of Alaskans, who are heading south to jobs in the Bakken field at the same time as oil production declines in Alaska.

Are Alaska’s jobs and people heading South To The Future?

And what should the state do about it?

Contact Steve MacDonald at stevem@ktuu.com

Part 1: Alaskans Head South to a New Oil Boom

Part II: Priming Production in North Dakota

Part III: Plenty of Oil, Not Enough Housing

Natural gas prices will be down in in 2012

2011-10-31T15:38:00.000-08:00

Tim Bradner
Alaska Journal of Commerce

Here’s good news for Southcentral Alaska consumers: Enstar Natural Gas Co. will file a gas cost adjustment with the Regulatory Commission of Alaska later this week for the first quarter of 2012 that will be 37 cents per thousand cubic feet, or mcf, lower than the gas cost filed a year ago for first quarter 2011.

Enstar President Colleen Starring made the announcement at the Anchorage Chamber of Commerce “Make it Monday” luncheon meeting on Monday.

Because there will be no change to Enstar’s administrative or other expenses, it means heating costs for Enstar’s customers will be lower for the first part of the year than last year.

Despite declining gas reserves in Southcentral Alaska, Enstar’s gas prices have been trending downward slowly, and Starring credited that to new gas producers appearing on the scene, mainly small independents, who are exploring for and finding new gas supplies.

State exploration incentives approved by the Legislature have caused an upsurge in drilling in Southcentral Alaska, Starring said.

The lower price is also an effect of a pricing formula for one of Enstar’s major suppliers, Unocal Corp., that is linked to the Henry Hub gas trading index in Louisiana, where natural gas prices are at very low levels.

Enstar’s average gas cost was $6.75 per mcf in 2011, down from $6.99 per mcf in 2010.

BLM sets date, time for December National Petroleum Reserve lease sale

2011-10-28T22:02:00.003-08:00

Tim Bradner
Alaska Journal of Commerce

The U.S. Bureau of Land Management will hold its planned December National Petroleum Reserve-Alaska lease sale on Dec. 7, at 1 p.m. in Anchorage, BLM officials announced Friday. The sale will offer 283 tracts, or about 3.06 million acres, in the northeast and northwest planning areas of the petroleum reserve.

BLM’s sale will come several hours after a state of Alaska area-wide lease sale of about 15 million acres, which will be held at 9 a.m., also in Anchorage.

The unusual timing of having both lease sales on the same day will allow bidders maximum advantage in bidding for prospects that straddle the boundary between federal and state lands, state Natural Resources Commissioner Dan Sullivan said.

This means a bidder could potentially pick up acreage on state and federal land and gain more flexibility in accessing oil and gas pools, Sullivan said.

A 2005 U.S. Geological Survey assessment identified 19 oil plays in the central North Slope region that lie astride the boundary between the NPR-A and Alaska-owned lands, and 17 of these are included in the federal sale, Sullivan said.

The near-simultaneous offering, “should greatly improve a company’s ability to explore and develop both state and federal acreage. We have been coordinating with the federal government on our lease sale dates in the hope that working together will enhance opportunities,” the commissioner said.

BLM officials said they have worked to balance environmental protection responsibilities with orderly resource development. “I believe it is possible to develop oil and gas resources while protecting important surface and subsistence resources,” said Bud Cribley, BLM’s Alaska director. “The sale in December reflects BLM’s mission to balance the protection of natural resources and rural subsistence with the nation’s need for oil and gas development in the NPR-A,” Cribley said.

Republished with the permission of the Alaska Journal of Commerce. This article appears in the AJOC October 30 2011 issue of Alaska Journal of Commerce. Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-October-30-2011/BLM-sets-date-time-for-December-National-Petroleum-Reserve-lease-sale/#ixzz1c9EShOvp

Petroleum industry packs big punch in state’s economy

2011-10-28T21:56:00.002-08:00

Tim Bradner
Alaska Journal of Commerce

Alaska’s oil and gas industry packs a powerful economic punch in the state. A new study by McDowell Group, a Juneau-based consulting firm, has estimated that the petroleum industry directly creates 4,000 jobs, that industry support and service companies create 7,700 jobs, and that the “indirect” employment effect of those 11,700 industry and contractor jobs creates another 26,000 jobs.

The grand total is 44,800 jobs and $2.65 billion in annual payroll in the state, according to Jim Calvin, McDowell Group’s lead researcher on the project.

The data is from industry activity in 2010.

Calvin said that every one job created by a primary company, such as an oil producing company, creates nine additional jobs in the support sector.

The work was sponsored by the Alaska Oil and Gas Association, the petroleum industry trade group. McDowell Group presented the findings last Thursday, Oct. 27, at AOGA’s annual luncheon in Anchorage.

In terms of regional employment impact, the industry created 25,400 jobs and $1.56 billion in wages in Anchorage; 4,700 jobs and $320 million in wages in the Kenai Peninsula Borough; 3,000 jobs and $168 million in wages in the Fairbanks North Star Borough; 3,600 jobs and $268 million in wages in the Matanuska-Susitna Borough; and 700 jobs and $57 million in wages in Valdez.

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Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com. Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-October-30-2011/Petroleum-industry-packs-big-punch-in-states-economy/#ixzz1c9Cwgu5v

Repsol applies for 98,852-acre Qugruk unit; 4 wells this winter

2011-10-28T21:35:00.001-08:00

—Kristen Nelson

Repsol E&P USA Inc. has applied to the Alaska Department of Natural Resources for formation of the 98,852-acre Qugruk on the North Slope.

Repsol, 70 & 148 LLC and GMT Exploration Co. LLC jointly proposed formation of the unit. The three together hold 91.5 percent of the working interest within the proposed unit area.

Other leaseholders in the proposed unit are: Pioneer Natural Resources Alaska Inc., Anadarko Petroleum Co., ConocoPhillips Alaska Inc., Paul L. Craig and Peter G. Zamarello. The unit agreement has been executed by Repsol, 70 & 148 and GMT. Repsol said it has offered the other leaseholders the right to join the unit and is awaiting their response.

The proposed unit, in somewhat of a “T” shape, is between the Colville River unit to the south and west, the Oooguruk unit to the south and east and the proposed Placer and South Miluveach units to the south. The northern limit of the proposed unit is the boundary between state waters and the federal outer continental shelf.

One-year plan

The initial plan of exploration is for one year and includes four wells. Repsol proposed a bond payable to DNR to ensure that work begins, with DNR to release the bond to Repsol when the first exploration well spuds. Repsol said the unit working interest owners agree to having the unit terminate if the first well is not drilled during the 2011-12 drilling season.
Prospective intervals to be tested by the exploration program include — but are not limited to — the Cervelo, Judy Creek, Nechelik, Nuiqsut and Alpine sandstones within the Jurassic Kingak shale, and the Cretaceous Kuparuk C sandstone (Kup “C”), Torok formation and Nanushuk Group.

The four planned wells are the Qugruk 1 in section 28 of township 13 north, range 6 east, Umiat Meridian, with a proposed true vertical depth of 7,100; the Qugruk 2, in section 25 of township 13 north, range 6 east, UM, with a proposed TVD of 7,000 feet; Qugruk 3, in section 31, township 12 north, range 6 east, UM, with a proposed TVD of 7,150 feet; and Qugruk 4, in section 15 of township 13 north, range 4 east, UM, with a proposed TVD of 8,300 feet.

Repsol said the sequence in which the wells are drilled may be changed and the location and drilling depth of subsequent wells may be adjusted following drilling of prior wells.

In its permitting paperwork Repsol has indicated that it may drill one vertical well and as many as two sidetracks at each location. It is also permitting the Kachemach exploration well farther south — outside of the proposed unit area — and just east of the Meltwater participating area of the Kuparuk River unit.

Kingak, Kup “C”, Nanushuk group

There have been many exploration wells drilled in the area surrounding the proposed unit, including six wells within the proposed unit, beginning in 1966 and extending through to 2008, Repsol said in its unit application.
Primary objectives for the proposed unit are “sands within the upper portion of the Jurassic Kingak Shale, the Cretaceous Kup ‘C’ sand and several sands within the Cretaceous Nanushuk Group.” Two sands in the J-2 interval of the Kingak shale are informally termed the Cervelo and Judy Creek sands, the Nechelik sand, the Nuiqsut sand and the Alpine “A” and “C” sands. Within the Nanushuk group the sands are the Nanushuk 3, Nanushuk 2 or Qannik sand, Nanushuk 6 and Nanushuk 7.

There is both 2-D and 3-D seismic over the area of the proposed unit, Repsol said.

While proprietary 3-D seismic exists over most of the proposed unit, Repsol said the primary 3-D seismic it has licensed over the proposed unit are the 2000 Fiord 3-D, the 1997 Kalubik 3-D and the 2007 Big Island 3-D. The company said that variably spaced 2-D lines (half a mile to 2-mile spacing) acquired from the 1970s to the 1990s were used in areas with no 3-D coverage.

Existing seismic “allows detailed mapping of fault patterns, truncation of individual Jurassic sands by the Lower Cretaceous Uncomformity (LCU), and amplitude anomalies associated with sands,” the company said.

Productive

Because of production in adjacent areas, Repsol provided DNR with an extensive analysis of what it considers to be analogous production.

The Nuiqsut sand is productive in the Oooguruk unit to the east of the proposed Qugruk unit, Repsol said, while the Nechelik, Alpine “A” and Alpine “C” sands are producing in the Colville River unit to the west of the proposed unit.

“All the zones are being developed by horizontal laterals with alternating producing and injection wells.”

The Kup “C” sand is a major North Slope reservoir and is produced most notably from the Kuparuk River field southeast of the proposed unit, Repsol said.

“Structure at the Kup ‘C’ level consists of an extremely large, roughly circular, four-way closure known as the Colville High,” Repsol said, and the lands proposed for the Qugruk unit are “on the northwest flank of the structure but are still nearly entirely within the area of closure.”

The Nanushuk group is divided into nine zones within the area proposed for the unit, including the Nanushuk 2, equivalent to the Qannik sand that is being developed within the Colville River unit, where Qannik sand production is south of the proposed Qugruk unit. There are six producing Qannik wells and three injection wells, with oil ranging from 27 to 32 degrees API gravity.

“To date the Qannik sand is the only sand that has been tested within the Nanushuk Group, however reservoir properties for the other Nanushuk sands are anticipated to be similar.”

Madrid-based Repsol took a position in state acreage when it picked up a 70 percent working interest in 494,211 acres assembled by Armstrong Oil and Gas of Denver (bidding as 70 & 148 LLC) and northern Alaska acreage held by GMT Exploration LLC.

Under the deal, announced in early March, the remaining 30 percent is split 75:25 between Armstrong and GMT.

Repsol’s previous interests in Alaska were in federal outer continental shelf acreage in the Beaufort and Chukchi seas.

Through to 2015? New Cook Inlet gas producers help stretch supplies for another few years

2011-10-28T21:25:00.004-08:00

Alan Bailey
Petroleum New

With temperatures in Southcentral Alaska dropping as winter approaches, local gas and power utilities are gearing up for another nail biting few months, trying to ensure that severe cold or an equipment malfunction will not trigger power outages as utility gas supplies from the Cook Inlet basin tighten. And on Oct. 21 four utilities — Enstar Natural Gas Co., Chugach Electric Association, Municipal Light & Power and Matanuska Electric Association — provided the Anchorage Mayor’s Energy Task Force with overview of the current gas supply status.

In summary, the utilities said that the storage of summer produced gas for use in the winter has become a critical factor in the battle to ensure the availability of sufficient gas to meet peak winter demand; new Cook Inlet gas producers are starting to have an impact in the gas supply situation; and utilities will probably have enough gas to meet total annual demand until 2015, from which point the import of liquefied natural gas may be necessary to bolster local gas supplies.

More gas needed

James Posey, ML&P general manager, told the task force that recent Cook Inlet gas discoveries have not been sufficient to avert the LNG import option. Without new discoveries leading to 50 million to 80 million cubic feet per day of production “we’re nowhere out of this box,” he said.

And Colleen Starring, president of Enstar, told the task force that, with the utilities still determining the cost parameters for LNG imports, it is too early to comment on the specifics of import options. Posey said that the utilities anticipated having more information to impart some time in 2012.

Starring said that Enstar continues to negotiate long-term gas supply contracts with local gas producers. However, starting in January 2011 the company has had to tender for daily volumes of “bid gas” from qualified producers, to supplement gas obtained under the terms of contracts for guaranteed gas supplies. The future gas supply situation depends on discoveries by companies currently exploring in Cook Inlet — there has been significant investment in this exploration in the past couple of years, Starring said.

New contracts with new producers are already appearing in Enstar’s contract list for future supplies, she said.

Growing gap

Enstar sees a significant and growing gap between its current contracted gas supplies and gas demand from 2013 onwards. However, the company hopes that new Cook Inlet gas coming on line will delay any need to import LNG until 2015, Starring said. Enstar is also keeping an eye on gas pipeline options for obtaining gas from the North Slope, she said.

Meantime, Cook Inlet Natural Gas Storage Alaska, Enstar’s sister company, is forging ahead with its new gas storage facility on the south side of Kenai, on the Kenai Peninsula. CINGSA plans to start accepting gas for storage in the spring of 2012, to support the delivery of utility gas in the winter of 2012-13. At the CINGSA site the buildings have been constructed, one well has been completed, a second well is ahead of schedule and the drilling of a third well will start soon, Starring said.

At the beginning of 2011 Enstar moved to a quarterly gas cost adjustment for its customers, thus enabling the company to pass on the higher cost of winter gas, Starring said. The Enstar gas cost adjustment ranged from $7.12 per thousand cubic feet in the first quarter of 2011 to $5.74 in the third quarter.

“We’re trying to send the right price signals to customers,” Starring said.

Bid gas

Enstar now has seven companies signed up to potentially supply bid gas during the coming winter, with the company expecting bid gas to account for about 3 percent of its overall supplies. Buccaneer Energy, one of the companies that have a contract for bid gas, also has a contract to supply gas to Enstar for storage in the CINGSA facility, starting in the spring, Starring said.

It is not possible to say how much bid gas might be available to Enstar on any particular day, but on one especially cold day during the last winter the company was able to obtain all of the bid gas that it needed, Starring said.

Phil Steyer, CEA’s director of government relations and corporate communications, said that CEA uses natural gas as a fuel to meet 90 percent of its power generation needs. The company has gas supply contracts to meet its needs through 2013, possibly through 2014, with increasing unmet needs thereafter, he said. Meantime, the tightening gas supply situation has led to increasing complexity in the delivery of gas to power plants, although modifications to the pipeline infrastructure will improve the flexibility with which gas can be transported. And starting in 2012 the company will be storing some of its winter gas supplies in CINGSA’s new facility. Along with other Southcentral utilities, CEA is considering the option of importing LNG to fill gaps in future gas supplies.

CEA is working with ML&P to build a jointly owned, state-of-the-art, combined cycle gas-fired power plant in Anchorage. That plant is scheduled to go into operation by Dec. 1, 2012, and its use will greatly increase the efficiency of the two utilities’ power generation, thus reducing their gas demand from the beginning of 2013, Steyer said. And CEA’s overall retail power load has remained fairly flat, with customers power usage actually dropping in recent years, thanks primarily to improved efficiency in people’s use of energy.

Multifaceted approach

Although CEA expects to remain a gas fueled utility for some time to come, the utility is taking a multifaceted approach to meeting its long-term energy needs, Steyer said. Increments to the power capacities of the Bradley Lake and Cooper Lake hydropower systems on the Kenai Peninsula are planned, although increased power output from Bradley Lake is contingent on some transmission line upgrades on the Kenai Peninsula. Increasing the capacities of the transmission lines running north and south out of Anchorage would also allow greater flexibility in power generation. Looking further into the future, there is also the proposed major hydropower system at Watana on the Susitna River.

Posey said that, in addition to investing with CEA in the new Anchorage power plant, ML&P has been improving its own power plant, replacing turbines and some pipe work. The utility is investing in upgrades, including a new well and compressors, in the Beluga gas field, the field that it part owns with ConocoPhillips and Chevron and that forms its primary source of gas.

Turning point

ML&P expects its gas needs to drop as its power generation efficiency improves, but gas output from the Beluga field is also declining. “Our turning point is 2018, when we will turn the corner of having to buy more and more gas each year,” Posey said.

Joe Griffith, general manager of MEA, told the task force that MEA is moving ahead with a new 135-megawatt power station that the utility has been planning to build at Eklutna, at the base of the Chugach Mountains. The utility has the necessary air permit for the plant but is still seeking fuel supplies for the power generation. The plan is to use natural gas as fuel, but the generators will be also be able to operate with other fuels — MEA plans to keep diesel fuel on site as a backup but is investigating the potential use of propane.

MEA is making improvements to the utility’s transmission and distribution networks, including the rebuild of some very old substations, Griffith said.

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Republished with the permission of the Petroleum News.

Parnell shifts on gas pipeline, wants new look at LNG

2011-10-28T06:52:00.004-08:00

Tim Bradner
Alaska Journal of Commerce

The gas pipeline plan may be shifting from Canada to an LNG project in southern Alaska. Gov. Sean Parnell called on North Slope producers and TransCanada Corp. to reexmine the LNG option in light of low gas prices in the Lower 48 states and the buildup of gas supply from shale gas producers.

In a speech to the Alaska Oil and Gas Association’s annual meeting Oct 27, Parnell said there is little progress to date on TransCanada’s current plan for a pipeline to Alberta, from where gas could be shipped on to the Lower 48. However, markets for LNG in Asia are strong, and the governor wants a new look at that. Various companies including North Slope producers and TransCanada have looked at LNG and exports to Asia over the years.

The state is in a contractual relationship with TransCanada under the state’s Alaska Gasline Inducment Act, or AGIA, to support the pipeline company’s current effort on a 48-inch pipeline from the North Slope to Canada. TransCanada and ExxonMobil are in a separate relationship to do engineering and feasibility work on the pipeline to Canada, which is expected to cost in the range of $40 billion.

Parnell did not commit on any additional state financial support for a pipeline to an LNG project other than $500 million already committed to TransCanada under the AGIA contract, but he did say that he would be open to a tax agreement on gas production this year, in time for the Legislature to consider in 2011, if TransCanada and the North Slope producing companies could agree to pursue an LNG project.

In a statement, TransCanada said, “TransCanada, as the licensee under AGIA, has regular conversations with different levels of the state administration on matters pertaining to the Alaska Pipeline Project. Those discussions are held in confidence under the terms of the license. TransCanada is continuing its efforts to advance the Alaska Pipeline Project to successfully transport North Slope gas to market,” the statement said.

In his comments, Parnell said, “It’s my impression that TransCanada and the producers are looking for something different, because there’s no forward movement on the pipeline to Canada. It appears the market has shifted,” adversely in North America, because of shale gas.

“I have communicated to TransCanada, ExxonMobil, BP and ConocoPhillips the frustration that Alaskans have with the lack of progress, and I want to send a signal that if the producers and TransCanada want to take a hard look at LNG, we are flexible and will support that,” the governor said.

As part of an open season held by TransCanada in mid-2010 under the AGIA contract the pipeline company offered prospective shipped the option of a 36-inch pipeline alternative to an LNG project at Valdez, in south Alaska. TransCanada said it did get offers from shippers in the open season but would not say whether the offers were to send gas to Canada or Valdez.

Since 2010, however, TransCanada vice president Tony Palmer has said that the company’s efforts are focused on the pipeline to Alberta, and not to an LNG project in Valdez.

Parnell did not specify any preference for a pipeline to Valdez or to the Kenai Peninsula south of Anchorage, where there is an existing small LNG plant owned by ConocoPhillips. Separately, the state is backing engineering work on a 24-inch gas pipeline from the North Slope to southern Alaska if the 48-inch pipeline to Canada is not built.

There is speculation in Alaska that the governor may push for the two projects to be merged, with a 36-inch pipeline built to the Kenai Peninsula. ConocoPhillips is currently planning to mothball its plant at Nikikski, near Kenai, partly because of a lack of gas supplies from Cook Inlet producing fields.

If gas were brought from the North Slope the plant would have to be expanded and upgraded.

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Republished with the permission of the Alaska Journal of Commerce . Tim Bradner can be reached at tim.bradner@alaskajournal.com. This article appears in the AJOC October 30 2011 issue of Alaska Journal of Commerc Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-October-30-2011/Parnell-shifts-on-gas-pipeline-wants-new-look-at-LNG/#ixzz1c5X9ISF5

Shell one more notch closer to getting permits

2011-10-27T13:23:00.001-08:00

Tim Bradner
Alaska Journal of Commerce

Shell may be one more notch closer to getting final permission to explore offshore off Alaska’s northern coasts, but environmental organizations and a North Slope tribal group have filed new appeals.

The U.S. Environmental Protection Agency issued a final air quality permit Oct. 21 for Shell’s planned Beaufort Sea exploration program, one of two areas where Shell hopes to explore in 2012 and 2013.

The permit covers activities by the Shell-owned drilling vessel Kulluk and several support vessels. The permit for the Beaufort Sea is a minor source permit, which limits the Kulluk and its support ships to 250 tons of emissions per year. One of Shell’s prime areas of interest is in the Camden Bay areas of the Beaufort Sea east of Prudhoe Bay.

On Sept. 19 EPA issued two final air quality permits for Shell’s Chukchi Sea drilling using the drillship Noble Discover, which is under contract to Shell. The permits for the Discoverer allows that vessel to be used in both the Chukchi Sea and Beaufort Sea. The Kulluk’s permit allows it to be used only in the Beaufort Sea.

However, 10 environmental groups and a tribal organization from Point Hope filed appeals Oct. 24 of both final air quality permits. Earthjustice, an environmental law firm, filed the appeals to the EPA’s internal Environmental Appeals Board, or EAB. It was on behalf of the Native Village of Point Hope, Resisting Environmental Destruction of Indigenous Lands, Alaska Wilderness League, Center for Biological Diversity, Natural Resources Defense Council, Northern Alaska Environmental Center, Ocean Conservancy, Oceana, Pacific Environment, Sierra Club, and The Wilderness Society.

Shell officials were not available for comment but a company spokesman said earlier that appeals of the Kulluk and Discoverer permits to the EAB were expected.

The EAB has previously reviewed draft air quality permits for Shell’s programs. Last year environmental groups appealed an earlier version of the permit to the EAB, which returned a decision last January recommending certain changes. EPA’s Region 10 revamped and reissued the permits, which have now again been appealed to the EAB.

There is no deadline for the appeals board in making its decision. Shell has said previously that it needs to make a final decision in October on whether to mobilize its vessels for the planned 2012 exploration.

EPA had also issued a draft permit to ConocoPhillips for its Chukchi Sea exploration using a jack-up rig, but on Sept. 26 ConocoPhillips withdrew the application with the intention of resubmitting it in December, EPA said in a press release.

“Shell has been in pursuit of a usable air permit for nearly five years. We appreciate that EPA Region 10 has thoroughly evaluated our program and issued a final permit for the Kulluk that is technically and scientifically sound,” Shell spokesman Curtis Smith said. “Shell has gone to great lengths to meet the goal of having no measurable impact on coastal villages, including a retro-fit of the Discover’s catalytic exhaust system and ongoing, multi-million dollar modifications to the Kulluk.”

The EPA air quality permit process was very complex and expensive for both Shell and the agency. One reason is that the Alaska Arctic permits are the first air quality permits worked on by EPA, in this case EPA’s Region 10 office in Seattle, so the agency was doing something for the time, as well as in a new area, the Arctic.

In the U.S. Gulf of Mexico the U.S. Minerals Management Service, now the BOEM, issues and administers air permits but Congress gave authority to EPA for OCS areas outside the western gulf, such as the Alaskan Arctic, the eastern Gulf of Mexico and for any leasing in off the Atlantic and Pacific coasts.

Shell plans to drill up to three wells in the Chukchi Sea using the Discover and up to two wells using the Kulluk in 2012, Smith said. Shell bid for federal Outer Continental Shelf leases in the Beaufort Sea in a 2005 lease sale and in the Chukchi Sea in a 2008 lease sale. Exploration has been held up by a variety of lawsuits and delays in permitting, and despite the appeals the company believes it is now making progress toward a goal of drilling in 2012, Smith said.

On another front, Shell received approval on its Beaufort Sea exploration plan from the U.S. Bureau of Energy Management but the permit has been appealed by a coalition of environmental groups to the U.S. 9th Circuit Court of Appeals. A draft exploration plan for the Chukchi Sea is before the BOEM now, and the agency has only recently been able to begin work on it.

Previously the leases issued in 2008 had been held up by a federal court injunction in a lawsuit brought by environmentalists over claims of defects in the original Environmental Impact Statement for the lease sale. The BOEM has revised the EIS and the injunction has been lifted, but there could be further appeals.

Exploration in the Beaufort and Chukchi Seas is important because both regions are highly prospective for oil and gas. In the Beaufort Sea Shell will drill in an area, near Camden Bay east of Prudhoe Bay, where a previous oil discovery has been made, although it was not economic.

In the Chukchi Sea the company will drill a prospect on which Shell previously had leases, explored in the early 1990s and made a large gas discovery, although also not economic at the time.

Gov. Sean Parnell and other state officials believe the Arctic offshore regions where Shell, ConocoPhillips and other companies want to explore has good prospects for increasing the amount of oil moving through the Trans Alaska Pipeline System, which is now operating at less than a third of its capacity.

The Camden Bay area particularly has potential for additions to TAPS liquids “throughput” because Shell’s prospects are 15 miles to 20 miles offshore and any oil production brought ashore through a subsea pipeline could be moved to TAPS through pipelines that now extend east of Prudhoe Bay.

This article appears in the AJOC October 30 2011 issue of Alaska Journal of Commerce

Republished with the permission of the Alaska Journal of Commerce.

South to the Future: North Dakota’s Oil Boom Series

2011-10-27T05:59:00.001-08:00

KTUU's Steve MacDonald just returned from North Dakota and is working on a three-part series about their Oil Boom and the impact on Alaska. It might be a series you'll be interested in watching. The series will air Monday-Wednesday on the Channel 2 NewsHour at 6pm.

North Dakota is fast becoming one of the largest producers of crude oil in North America. For years, a huge oil field in western North Dakota sat idle until the state lowered taxes, giving oil companies the incentive to invest. Now business is booming. As production at Alaska’s Prudhoe Bay slows, oil workers are beginning to follow the jobs to the North Dakota prairie. Channel 2’s Steve MacDonald recently visited the flourishing region to answer the questions Alaskans need to know: Are Alaska’s oil jobs going south? Is North Dakota’s gain our loss? What does is all mean for Alaska’s future?

Starting Monday October 31st at 6pm on the Channel 2 NewsHour, Steve will introduce us to Alaskan’s seeking opportunity amid the North Dakota oil boom. Throughout the week Steve will explore the jobs migration, oil taxes and small town North Dakota’s growing pains. Don’t miss this unparalleled look at one of Alaska’s most pressing issues.

NANA, NovaGold sign joint-venture deal to explore for minerals

2011-10-23T20:21:00.001-08:00

Tim Bradner
Alaska Journal of Commerce

A long-anticipated agreement on minerals exploration in Northwest Alaska has been signed.

NovaGold Resources Inc. of Vancouver, British Columbia, and NANA Regional Corp., the Kotzebue-based Alaska Native regional corporation, have agreed jointly explore and develop base metals discoveries on lands held by NANA at Bornite, on the upper Kobuk River east of Kotzebue, and by NovaGold in the Ambler Mining District, which is further east but nearby.

NANA’s board gave approval to the joint-venture agreement earlier this year but the deal was not finalized until late Wednesday, Lance Miller, NANA’s vice president for natural resources, told the Resource Development Council Thursday.

NovaGold’s holdings are on state lands while NANA’s lands are its own, selected under the 1971 Native claims settlement act, and patented mining claims that were purchased.

The NovaGold land holdings include the Arctic deposit, a high value copper discovery made originally by Kennecott Minerals and sold to NovaGold. On its lands, NANA owns the Bornite copper deposit, also a discovery made by Kennecott and subsequently sold to NANA.

The two known deposits are about 20 miles apart. Both NovaGold and NANA had active exploration programs in 2011.

Separately, the state of Alaska is doing preliminary feasibility work on an approximate 200-mile road to the Ambler Mining District from the Dalton Highway, an existing road from Interior Alaska to the North Slope. The road is intended to facilitate mineral exploration and mine development in the region.

In addition to work on the Arctic and Bornite discoveries, other mining companies are exploring two other base metals discoveries in the region, the Sun deposit owned by Andover Ventures Inc. and Smucker, a deposit owned by Teck Alaska. Sun is in the eastern part of the Ambler Mining District, while Smucker is in the west.

NANA is also engaged with Teck Alaska at the Red Dog Mine, a large lead/zinc mine in the DeLong Mountains in the western Brooks Range. Red Dog now produces about 1 million tons a year of lead-zinc concentrates. NANA is the land and royalty owner.

“The agreement consolidates NovaGold’s and NANA’s land holdings into an approximate 180,000-hectacre (446,000-acre) land package and provides a framework for the exploration and development of this high-grade and prospective poly-metallic belt,” NovaGold said in a press release Tuesday.

The Arctic deposit holds indicated mineral resources of 17 million tonnes grading 4.1 percent copper and 6 percent zinc plus gold, silver and lead. Expressed in terms of copper-equivalent, a way of representing the value of the combined metals, the deposit is 8.3 percent copper-equivalent. “The Arctic deposit is regarded to be one of the highest grade undeveloped volcanogenix massive sulfide deposits in the world,” NovaGold said in its press release.

The Bornite deposit is estimated at about 50 million tons of ore with copper grades of 1.2 percent to 4 percent.

This article appears in the AJOC October 23 2011 issue of Alaska Journal of Commerce

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Republished with the permission of the Alaska Journal of Commerce.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-October-23-2011/NANA-NovaGold-sign-joint-venture-deal-to-explore-for-minerals/#ixzz1bfaSqSCt

CIRI continuing work on underground coal gasification; seismic survey planned

2011-10-23T20:10:00.001-08:00

By Tim Bradner
Alaska Journal of Commerce

Cook Inlet Region Inc. is continuing its work on a potential commercial-scale underground coal gasification project, the first in North America, and will begin a high-resolution shallow seismic survey at a proposed site for the project in November.

Ethan Schutt, vice president for lands for CIRI, told the Alaska State Senate's natural resources committee Thursday that CIRI is working on lands it owns about 60 miles west of Anchorage and that geologic modeling, completed on a basis on 13 test core holes, has confirmed presence of thick coal seams below the 600-foot depth. This is the depth at which CIRI would target an underground gasification project.

CIRI has now commissioned a high-resolution shallow seismic program, the data from which will allow modeling to be completed, Schutt said. Three seismic survey lines, each eight miles long, will be done, he said.

Underground coal gasification involves combustion in a deep coal seam with production of a synthesis gas, a mixture of hydrogen and carbon monoxide, up a production well from the coal seam. The combustion is regulated by air injected through a separate well.

Synthesis gas would be used either in power generation or, through a process of upgrading, in the manufacture of a synthetic natural gas or other products, Schutt said. Synthetic natural gas would be almost identical to the gas used by Enstar Natural Gas Co. in its system and could be a substitute for that gas.

The coal resource is very large, Schutt said.

“CIRI has identified about 300 million tons of coal in the project area, which is the equivalent of 4.8 trillion cubic feet of gas,” he said.

The gasification technology can be scaled up in increments, so it can start small and be expanded. Based on conceptual work so far the company believes it can supply a synthetic natural gas to the local market for less than prevailing prices, Schutt told the legislators.

Utilities in Southcentral Alaska are now purchasing natural gas from producing companies for prices of about $6 to $8 per thousand cubic feet.

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Republished with the permission of the Alaska Journal of Commerce

This article appears in the AJOC October 23 2011 issue of Alaska Journal of Commerce
Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-October-23-2011/CIRI-continuing-work-on-underground-coal-gasification-seismic-survey-planned/#ixzz1bfXjtZwA

Tom Barrett, President of Alyeska Pipeline Service Company addresses the Alaska Federation of Natives

2011-10-23T09:58:00.004-08:00

Part 1

Part 2

Ormat has a setback on geothermal project

2011-10-20T15:18:00.001-08:00

Tim Bradner
Alaska Journal of Commerce

Ormat Technologies has suffered a setback at its proposed Mount Spurr geothermal project 75 miles west of Anchorage. The company has disappointing results from drilling of a 4,000-foot test well and is now reevaluating the project, according to Paul Thomsen, Ormat’s director of business development.

“Drilling results are discouraging. The rock type found (conglomerate) is inferior for geothermal development than the rock type (volcanic) that we anticipated based on all available data, and the temperature gradient measured was lower than expected,” Thomsen said in an e-mail.

“Volcanic rock has a higher heat capacity, meaning it can hold heat better, thereby increasing reservoir temperature,” he added. “While this undoubtedly represents a setback to our planned exploration and development, we will continue to analyze the data, together with the data collected in 2010 and with other available data, and will file a report by the end of the year,” with state agencies.

Ormat has been working with the Alaska Energy Authority on the project. AEA has provided grants to help fund the exploration work, although Ormat has invested several million dollars of its own money in the project.

Ormat concluded its 2011 summer drilling and demobilized its drill rig in August. The company encountered some difficult drilling conditions as well as weather delays and was forced to stop slightly short of its target depth of 4,100 feet. The depth actually drilled was to 3,988 feet, Thomsen said.

Ormat was hoping to develop the state’s first commercial-scale geothermal project at Mount Spurr. The first phase would have provided 50 megawatts of power to the Southcentral Alaska power grid, but the plan was to eventually scale it up to 100 megawatts.

Thomsen told a state legislative committee last January that the shallow core holes drilled in 2010 showed evidence of water mixing with hot geothermal fluids, and evidence of multiple geologic faults that could accommodate geothermal resources. Ormat had also obtained geochemistry indicating higher temperature resources at depth. The deeper core test planned for 2011 was to confirm that resource, Thomsen told the state House and Senate Resources committees on Jan. 24.

The final report on the 2011 drilling will, “summarize our conclusions and our recommendations moving forward,” Thomsen said. The Alaska Energy Authority has provided a $2.1 million grant to the Mount Spurr project, which was matched with $2.1 million by Ormat. Ormat’s own investment is substantially higher, though.

Additional state grants were approved for the 2012 program, which was to involve the drilling of test production wells.

Unlike wind power, which is intermittent, a geothermal project is steady. Because of this there are fewer problems with the integration of geothermal power into a power grid compared with wind.

This is the second setback this year with an Alaska geothermal project. Nannek Electric Association has had to terminate a planned geothermal project in its service area when drilling and financial problems developed with a test drilling program.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.
Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-October-23-2011/Ormat-has-a-setback-on-geothermal-project/#ixzz1bMoilM7j