Friday, March 30, 2012

Alaska Fear Factor a reality for winter North Slope explorers

—Kay Cashman
Petroleum News

Petroleum News’ Aug. 14 issue carries this headline: North Slope booms.

At the time, five operators were preparing to drill as many as 28 exploration wells in 2012.

ConocoPhillips, Pioneer Natural Resources and Savant later joined the group bringing the operator count to eight and the well count to 32. Then Great Bear Petroleum upped its possible wells to eight, bumping the count to a high of 34.

2012 would have been the busiest exploration season since 1969, when 33 exploration wells were drilled following the Prudhoe Bay discovery.

PN uses “2012,” not the “winter exploration season of 2012,” because not all the drilling would be from ice pads, restricted to just a few months when the tundra was frozen — Great Bear had year-round access because its wellsites were on gravel in an existing transportation corridor.

Here are the explorers, the wells they hoped to drill, and what happened to bring the well count down to 15.

• Repsol: 15 wells from five pads, North Slope Borough and Nuiqsut said yes to only four pads, with no more than three drilling rigs operating at one time, gas blowout (no oil spilled on tundra, no injuries) on Qugruk-2 pad, asked to reapply for drilling permits on other two Q pads. As of March 29, well count down to two, Q-4 and Kachemak-1. Drilling going well at K-1. March 29 received permit for Q-4.

• Brooks Range Petroleum: Two wells, one drilled because got all the information needed from the first (good news).

• UltraStar Exploration: One well, canceled, not enough rigs.

• Linc Energy: Four wells, by the time found a rig (Repsol) headquarters said too late to start.

• Savant: One well, regulatory delay, finally got drilling permit, hoping to spud early April.

• ConocoPhillips: One well, completed.

• Pioneer: Two wells, one completed, other being drilled.

• Great Bear: Six to eight wells, likely only six will be needed for proof of concept program, had to wait for rig to come off North Slope, has Nabors 105AC under contract as of May 15, 3D seismic shoot already under way.

Nabors looks at Alaska non-core sales, but not drilling business

—Kay Cashman
Petroleum News

Nabors Industries is getting back to basics, putting its oil and gas properties and non-core assets up for sale in order to concentrate on two aspects of its business — drilling and rig services and completion and production services.

Nabors Alaska Drilling is not on the chopping block because it’s part of the core asset group its parent intends to preserve and grow.

In Alaska, as well as elsewhere in the world, Nabors says “getting back to the basics” will likely mean selling non-core assets such as Peak Oilfield Services, which specializes in rig moving, custom heavy hauling, crane and rigging services and oilfield transportation, as well as marketing its interest in the Brooks Range Petroleum Corp.-operated oil and gas leases on the North Slope that Nabors-owned Ramshorn shares with Alaska Venture Capital Group, or AVCG.

The streamlining and restructuring comes amid a change in leadership, from Gene Isenberg to Anthony G. Petrello, at Nabors Industries.

Petrello was named chief executive officer of Nabors Industries in October, taking the reins from Isenberg, who remains chairman until June. Petrello, a lawyer who joined the Nabors board in 1991, also carries the titles of deputy chairman and president.

In a March 26 presentation at a Howard Weil conference in New Orleans, Petrello said Nabors is in the process of selling oil and gas properties in Alaska, Colombia and the Eagle Ford shale in south Texas, and should complete those deals in the second half of this year.

Nabors expects those sales to yield between $300 million and $400 million.

It also plans to sell oil and gas properties in British Columbia, including the Horn River and Montney shale plays, as well as its stake in oil and gas producer NFR Energy and Peak Oilfield Service, at a total value of $300-$400 million.

The company’s March 26 SEC filing of those presentation materials says in consolidating into just two divisions, Nabors will migrate away from the business unit structure; consolidate regional operations management; establish customer account managers; consolidate operational, technical and corporate support functions.

Nabors CDR-2 rig in Alaska

Petrello’s presentation materials say that one of the priorities of Nabors’ drilling and rig services unit will be specialized rigs that deliver a “unique niche, proprietary technology, technical leadership” and “strong market positions.”
The drawing accompanying the specialized rig section is none other than Nabors Alaska’s CDR-2, which the company delivered to ConocoPhillips nearly three years ago at the Kuparuk River unit. It is the first purpose-built coiled tubing rig designed for the Arctic.

Peak, Ramshorn sales not certain

The sale of Peak and Ramshorn’s North Slope lease interests are not done deals, Nabors Director of Corporate Development Denny Smith told Petroleum News March 27.

“We’re exploring the sale of Peak, have hired an investment bank to do the work on it, so it’s not a sure deal, there is no definite decision to sell. We’re going to evaluate it first; we’re 30 days away from starting the initial process,” he said.

In regard to the North Slope acreage it shares with AVCG, Smith said Nabors is exploring the possibility of a sale, but a sale will “depend on what we think the value is.”

Production tax deterrent to development

In another one of Petrello’s presentation slides, “Looking Ahead: What Contributes to Our Optimism,” Alaska is noticeably absent.

When asked why, Smith said although there is a favorable outlook for Cook Inlet drilling and development activity, Alaska’s production tax is a deterrent to development and production on the North Slope.

“We see a lot of pent up demand on the North Slope pending modifications to ACES,” he said, referring to the state’s production tax, Alaska’s Clear and Equitable Share.

Divestures yield $1 billion-plus

Petrello’s presentation materials say Nabors is also “evaluating” the sale of five jack-up rigs stationed in the U.S. Gulf of Mexico, five barge rigs in the U.S. Gulf, and eight jack-up rigs located in international waters, the value of all of which has yet to be determined.

According to a March 26 Dow Jones article, analysts with investment bank Dahlman Rose & Co. said in a research note that Nabors divestitures “should bring in comfortably over $1 billion by the end of the year with more to come in 2013.”

Dow Jones reported that while Nabors is selling its oil properties now, analysts say the company will likely wait until market conditions improve before selling its natural gas properties.

Nabors, which is registered in Bermuda but has operational headquarters in Houston, owns the world’s largest fleet of land rigs, currently pegged at 1,200 land rigs and 50 offshore units.

Sunday, March 25, 2012

Alaska's leading economist Scott Goldsmith talks about the future of our economy - March 20, 2012

Part 1

Part II

Part III

House Poll: 58 percent support ACES changes

by Alaska Journal of Commerce

A new in-depth poll by Dittman Research & Communications released by the Alaska House Majority Caucus March 20 carries data on a number of issues before the Legislature, from oil taxes to film incentives, to coastal zone management and education funding.

Dittman Corp. surveyed 1,000 Alaskans during the first week in March, asking 45 impartial questions, in order to secure a low 3.1-percent margin of error. The caucus traditionally commissions a poll to help inform members and the public on priority issues before the legislature, but this poll was more in-depth than previous surveys.

On oil taxes, a contentious issue before the Legislature now, 58 percent of the respondents feel the present state production tax should be repealed or modified. Of those who support modification or repeal of the current tax, 89 percent said it should be done this year.

"The data shows that a majority of Alaskans are feeling good about the state of the state: our leadership, our economy, and future opportunities. Alaskans are willing to invest in large projects like the in-state gasline and other mega-projects, and on education funding and film incentives - provided there's accountability," leaders of the Majority caucus said in a joint statement. "We're pleased with the work done by Dittman Research and staff and will use this information as we enter the home stretch of the legislative session when these issues come before us."

The survey showed 70 percent of the respondents feeling that the state’s economy is “good” or “quite good,” with 27 percent feeling it is “not good” and 3 percent unsure. On current levels of state spending, 44 percent of all respondents felt spending was “about right,” with 30 percent feeling it is “too high” and 11 percent “too low,” and 15 percent unsure.

Those percentages were similar across all regions of the state in the survey sample. However, in a subset of political affiliations, Republicans were evenly split, with 44 percent saying spending was “about right and 40 percent saying “too high.”

Democrats and unaffiliated respondents voiced similar opinions, 45 percent and 46 percent saying spending was about right, 25 percent (Democrats) and 27 percent (non-partisan) saying it was too high, and 10 percent (Democrats) and 16 percent (non-partisan) saying it is too low.

On the question of a large natural gas pipeline project, 74 percent of the respondents said they now have no confidence in the state’s Alaska Gasline Inducement Act, or AGIA, strategy developed by former Gov. Sarah Palin, and 48 percent of respondents blamed a “failure of leadership” by state officials as to why a gas pipeline is not underway. Within that sample, 17 percent felt the AGIA strategy itself is to blame, and 22 percent blame “market conditions.”

The press release is at

Read more:

Study: Inlet gas discoveries won’t stop shortage

Tim Bradner
Alaska Journal of Commerce

Despite new natural gas discoveries in Alaska’s Cook Inlet utilities in the region will still experience shortages of gas supply by 2014 due to declining production in maturing fields, according to a new study of Cook Inlet gas reserves and regional demand released Monday.

The only practical alternative to deal with the shortfall is the import of liquefied natural gas, said Pete Stokes, commercial manager with Petrotechnical Resources of Alaska, an Anchorage-based consulting firm.

PRA’s analysis was done for three Southcentral Alaska utilities, Enstar Natural Gas Co., Chugach Electric Association and Anchorage’s city-owned Municipal Light & Power.

“The PRA report just emphasizes what we’re been concerned with for some time, that there is a lot of talk about new gas resources out there but no one is bringing it to market. We need to see results,” said John Sims, spokesman for Enstar Natural Gas Co., the Southcentral regional gas utility.

Sims said the three utilities are working on plans to import LNG, but negotiations with potential suppliers are confidential.

ConocoPhillips owns and operates a liquefied natural gas plant at Kenai that the company had planned to mothball. However, the plant is now being kept open on a year-by-year basis with incremental shipments being made to customers in Asia.

There are reported new discoveries of gas both offshore and onshore in Cook Inlet including from a well drilled last summer by Escopeta Oil Co. from a jack-up rig, but the discoveries have yet to be tested, Stokes said.

Even if they can be produced commercially it will take five to six years, or more, to secure permits and build a platform and pipelines and other production facilities. The new gas would not come in time to meet the impending shortfall facing the utilities, he said. The expected supply shortfall that year is 7 billion cubic feet short of the utilities’ projected requirement of 80 billion cubic feet, Stokes said.

“Only a significant onshore discovery that is near existing pipelines will be sufficient to offset the shortfall in 2014. Offshore discoveries cannot be developed in time,” he said.

There are two new onshore Kenai Peninsula gas discoveries, one by Australia-based independent Buccaneer Energy in a prospect near the City of Kenai and a second in the Kenai National Wildlife Refuge by Alaskan independent NordAq, but both of these require further testing.

PRA’s analysis tracks studies done in recent years by the state Department of Natural Resources, which show potential reserve additions in the Cook Inlet Basin sufficient to meet local utility needs to 2020.

The difference, Stokes said, is that the state’s study assumes industry will make additional investments by producers in development drilling to prove up needed new reserves. PRA’s study, which is an update of work done in 2009, for the utilities, shows that the investments are not being made, at least at the rate needed.

In 2009, PRA estimated that if producers drilled no new development wells utilities would face a shortfall in 2013. The updated analysis just finished shows that some drilling and compression has been added, but that the supply shortfall is pushed out only one year, to 2014.

In 2009, PRA estimated that, assuming no discoveries of new fields, 185 new wells need to be drilled in the producing fields by 2020, or 14 to 18 new wells per year, to develop enough new gas to meet local utility demand. That level of drilling would require an investment of $1.9 billion to $2.8 billion, PRA said in its 2009 report.

The actual drilling by producers has been far below those levels, Stokes said. In 2010 producers drilled five new production wells. In 2011 six new production wells were drilled.

However, the 2011 drilling resulted in far less new production than wells in 2010, an indication of the declining productivity of the large Cook Inlet gas fields.

Wells drilled by producers in 2010 averages 18.5 million cubic feet of gas per day additions to production, while the wells drilled in 2011 averaged about 9.9 million cubic feet of gas per day, Stokes said.

PRA’s recent analysis indicates that even if producers ramp up drilling by three or four more wells per year the projected shortfall in the utilities’ need still appears in 2014 but drops from 7 billion cubic feet to 1 billion cubic feet that year, Stokes said.

Even if drilling is doubled, to six to eight wells per year over the 2010 and 2011 rates, the shortfall is pushed back only one more year, until 2015, he said.

The state of Alaska is meanwhile backing a plan to build a 24-inch pipeline to bring gas from the North Slope to Southcentral Alaska, or alternatively a 24-inch “spur line” if a large-diameter pipeline is built to Canada, but gas from the Slope cannot realistically be shipped until 2020 at the earliest, state officials have said.

Southcentral Alaska utilities have been grappling for years with the long-term decline of producing fields the region. For many years gas was in surplus to local needs and prices were low, at $1.50 per mcf or lower for many years. There was virtually no exploration given the prices.

In recent years prices have increased and are now in the range of $8 per mcf under new gas contracts signed by the utilities, and there has been new exploration in the last two years. Also, the state of Alaska has stepped in with generous incentives for exploration, paying as much as 60 percent to 70 percent of the cost of new wells.

Friday, March 23, 2012

Oil tax work continues; Consultants tell Senate Finance no positive impact on new production from SB192

Kristen Nelson
Petroleum News

Oil tax changes remain a focus for Gov. Sean Parnell and Alaska legislators, but as the session rolls toward an April 15 adjournment, the Senate Finance Committee is still working on Senate Bill 192.

The state’s goal for oil tax changes is to increase production on the North Slope.

Parnell put an oil tax bill on the table last year; House Bill 110 passed the House, but didn’t move in the Senate, which said it needed time to work the issues. This year the Senate took up its own proposal, SB192. After hearings and amendments in Senate Resources, that bill moved to Senate Finance.

The governor said March 20 that he is asking the Senate to put something on the table that will garner investment guarantees from the state’s oil and gas producers. On the time issue he noted that the Senate’s original schedule was to move a bill to the House with 30 days left in the session.

Senate Finance co-Chair Bert Stedman, R-Sitka, said March 20 that a committee substitute is at least a week away. He said the committee’s consultant has said the bill isn’t as effective as it might be at encouraging incremental oil production. Splitting of profit oil at high prices is another key issue, but consultants have said that at $100-a-barrel oil not a lot of modification is needed to make the state competitive. Stedman is concerned about pushing too much money across the table to the oil companies. He said industry told legislators a few years ago that they count every penny and said the state needs to do the same thing.

Stedman said a committee substitute is at least a week away.

As for how long it will take the House to consider a Senate bill, House Speaker Mike Chenault said March 19 that he expects it will be a week to two weeks before the House sees the Senate’s bill. It will probably be assigned to the House Resources and Finance committees for consideration.

Chenault said he didn’t know if the bill will be similar enough to HB110 to garner support in the House.

As to whether the House will have time to deal with it, he said a lot depends on how complicated the bill is.

If the House gets the bill with two weeks left in the session, Chenault said he didn’t know if that would be enough time. It depends on what’s in the bill and whether the House agrees, he said.

Another survey

In a public opinion survey done March 4-7 for the House, Dittman Research & Communications said March 19 that from a sample of 1,000 it found that 59 percent were in favor of repealing or modifying the state’s existing oil and gas production tax, Alaska’s Clear and Equitable Share or ACES. That compares with 58 percent in favor of repealing or modifying ACES last year.
The detail was 14 percent in favor of repealing ACES (compared to 20 percent last year) and 45 percent in favor of modifying ACES (compared to 38 percent last year). The number in favor of keeping ACES as is, 28 percent, was down this year from 35 percent last year, but the number unsure, 13 percent, was up from 7 percent last year.

Fifty-four percent of those surveyed said they believe that lower state taxes will generally result in greater business investment in Alaska, compared to 35 percent who think the tax rate has little effect on investment decisions and 11 percent who were unsure.

Democrats were almost exactly the reverse of the overall sample, with 34 percent of Democrats saying lower taxes result in more investment and 55 percent saying there was little effect.

The poll also asked respondents whether they favored the governor’s plan (described as “significantly” lowering oil taxes immediately to “encourage more investment and try to increase oil production now”) or the Senate plan (described as studying the issue further, making “only minor changes this year” and insisting on “investment guarantees from industry”).

Overall, 49 favored the Senate plan and 43 percent the governor’s plan, with 65 percent of Republicans (and only 21 percent of Democrats) favoring the governor’s plan and 74 percent of Democrats (and only 28 percent of Republicans) favoring the Senate’s plan.

There was a significant geographic break, with 56 percent of rural respondents favoring the Senate plan, while 55 percent of Interior and 47 percent of Southcentral respondents favored the governor’s plan.

New oil issues

PFC Energy, the consultants hired by the Legislative Budget and Audit Committee to work the production tax issue, told Senate Finance March 15 that the proposal in SB192 to encourage incremental oil production wasn’t very effective.

For a producer with 200,000 barrels per day of existing production, declining at 6 percent per year, it would take incremental oil of 100,000 bpd to produce a year-over-year increase, Jerry Kepes, partner and head of PFC Energy’s upstream and oil, told the committee. The incremental oil feature of SB192 is good for only a single year, so in addition to making up for an estimated 6 percent decline, a company would have to bring on substantial new oil every year to get above the normal decline rate.

Kepes said that even if new production is brought on very quickly, the proposed allowance for new oil only moves government take by fractions of a percentage point. For an existing producer, PFC’s models show that the net present value of the producer’s portfolio rises by about a tenth of a percentage point, where for a new producer, even though the impact on project value is greater, it is insignificant compared to the estimated $10 billion cost of a 100,000-bpd new development.

Kepes said an alternative, providing an allowance for new source oil, rather than incremental production over the previous year, could have a greater impact. The disadvantage, he said is that defining new-source production could be difficult in practice, and would be “a challenge for administrative capacity or regulatory capacity.”

Producers oppose two-tier approach

Senate Finance heard from the North Slope’s largest producers — BP, ConocoPhillips and ExxonMobil — on March 21.
The companies did not support a two-tier approach for existing and incremental production.

Bob Heinrich, vice president of finance for ConocoPhillips Alaska, told the committee that the discretionary production incentive does not incentivize the significant investments required just to offset decline and said it does not improve the investment climate.

Scott Jepsen, vice president external affairs for ConocoPhillips Alaska, said changes need to apply to all barrels — legacy as well as new fields — and make it simple. Only someone with no production would see a significant benefit under the proposal, he said.

Damian Bilbao, head of finance, developments and resources for BP in Alaska, said SB192 doesn’t work as an incentive for additional production. He characterized ACES as a failed fiscal policy which hasn’t delivered a track record of increasing investment. Bilbao said BP looks at the business holistically and starts with the base business: If that’s healthy, you get license to do more things.

It’s all production you want to incentivize, Bilbao said. A two-tier approach could end up discouraging legacy field development, and he said it’s rigs in the legacy fields that result in the most production.

Bilbao also told the committee that differentiating between existing and incremental oil creates unexpected results; he said it would be tremendously complex to differentiate costs. The way to incentivize new production is by making sure the base business is healthy.

Stedman told Bilbao that if changes in the oil tax don’t differentiate between new and existing production, legislators are concerned that they won’t be providing incentives for new production, that the state would move more cash than needed to industry and could end up where it is now in terms of production.

Changes to progressivity

SB192 reduces the rate of progressivity from a 0.4 percent increase to a 0.35 percent increase and reduces the maximum rate from 75 percent at $342 in production tax value (price less transportation and allowable costs) to 60 percent at $202 PTV.

Kepes said the impact on project economics of the progressivity change was relatively limited. He said there was a more appreciable change from the 60 percent cap at high oil prices.

ConocoPhillips’ Heinrich told the committee the 0.05 percent progressivity reduction does not improve the investment climate and said the 60 percent cap has no impact below an oil price of about $230 a barrel.

He noted that PFC Energy said the progressivity reduction would be limited to about a single percentage point at $100 Alaska North Slope oil.

Neither of the changes provides a robust environment for investment, Heinrich said.

Stedman said the committee would like ConocoPhillips’ thoughts on what the split should be between government and industry in the $70 to $150 per barrel price range, and asked if ConocoPhillips thought the split should be frozen at some point or if Alaska’s share should always continue to grow. Jepsen said ConocoPhillips believes the split should be frozen at some point, but said they’d need to understand all of the other elements.

The $100 issue

Stedman noted the committee has heard from consultants that at an oil price about $100 the relationship of government take seems reasonable for current production. Heinrich said that compared to other places where the company invests in North America, the range where the split is reasonable is about $70.

Jepsen said decisions are not made on a single variable, but said when ConocoPhillips looks at making additional investment in Alaska they don’t see the upside. He said they get capital to pursue base business, but said it’s very difficult to attract capital to get another rig or two for the Kuparuk field.

Jepsen said ConocoPhillips doesn’t believe that SB192 changes the investment environment on the North Slope and suggested significantly reducing or bracketing progressivity. He also said changes should include the legacy fields because that is where the largest potential production gains are located.

Bilbao said BP believes that it could be doing more in Alaska, but needs to be competitive for funds. He said that overall SB192 does not move the needle on meaningful tax change, remaining very close to ACES. HB110, he said, represented the beginning of meaningful tax change, although he said BP believes the base tax rate of 25 percent is too high.

Asked by Stedman to define meaningful and significant change, Bilbao said the state would know it was meaningful when it got the results it wanted in terms of more investment. He said a change in progressivity was the single biggest thing the Legislature could do. If progressivity is BP’s number one issue, then bracketing would be number two, Bilbao said, and cited HB110 as an example of meaningful tax change.

Exxon remains committed

Dale Pittman, Alaska production manager for ExxonMobil, told the committee that Alaska has always been and continues to be a critical part of the corporation’s business.

He said there have been questions on the opportunities discussed by BP and ConocoPhillips in the event of oil tax changes and said ExxonMobil fully supports both of its operators, BP at Prudhoe Bay and ConocoPhillips at Kuparuk.

Significant investment is needed to stem decline in the state, and that is why ExxonMobil talks about the need for a meaningful change in the state’s tax policy, Pittman said.

He said investment decisions are really risk-management decisions based on commercial, technical, fiscal and regulatory considerations and tax reform would restore some balance to the risk profile. Pittman said ExxonMobil believes that passage of meaningful tax change would attract additional companies to the state.

He said ACES has many flaws, with progressivity being the most onerous.

The state has benefited from short-term revenue increases under ACES, but has failed to attract investment, Pittman said.

Asked by Stedman about the progressivity issue at high oil prices and the possibility of freezing the split between government and industry, Pittman said what ExxonMobil focuses on is total government take. There are different levers, he said, but as a long-term investor ExxonMobil is fairly indifferent to individual changes, focusing instead on how projects can be made viable.

At $100 oil, dollars are not coming to Alaska, Pittman said, adding that it causes him some concern and he wonders how broad an opportunity the state wants.

Thursday, March 22, 2012

Shops empty as oil production declines

Tim Bradner
Alaska Journal of Commerce

When a film producer called up CH2M Hill’s area manager Tom Maloney a few weeks ago to ask if the company’s empty fabrication shop could be used as space for film production, it was the last straw.

Maloney’s job includes keeping the shop full and its people working.

“I was tempted – it was revenue – but I just couldn’t let it happen on the odd chance that we might get some work into the shop,” Maloney said.

Alaska’s once-bustling oilfield fabrication shops are now empty, CH2M Hill’s among them. ASRC Energy, which also operates a fabrication shop in south Anchorage, reports a similar situation.

Last year the welders, pipe fabricators and electrical technicians were busy building things for the oil fields. Not this year.

NANA/Colt Engineering operates a facility in the Matanuska-Susitna Borough, and Flowline Inc. does fabrication as well as pipe-coating at its Fairbanks plant.

Everyone is in the same boat, Maloney said.

“I’ve never seen things so bad. Even in 1988, oil prices dropped to $10 a barrel but we were still busy. That’s because people were optimistic, and planning new projects. They knew the oil price would go back up,” Maloney said. “Now prices are almost $120 a barrel and we’ve got this pessimism. We’re losing our key workers to North Dakota where oil work is booming.”

Maloney puts the blame for things on the impasse squarely on the Legislature’s inability to agree on a needed adjustment to the state oil and gas production tax, which he says are too high. That is impeding new investment by oil producers and new projects to keep CH2M Hill’s workers busy.

The state House passed a bill last year, House Bill 110, which would lower the taxes, but the Senate disagreed. Senators are now working on their own proposal, but state House leaders and Gov. Sean Parnell are dubious that it will be enough to make a difference.

Meanwhile, CH2M Hill’s 100-plus workers normally at work in the fabrication shop aren’t there.

These employees, and those who work for the company’s competitors in Anchorage, Kenai and Fairbanks, are indirectly employed by Alaska’s oil industry but many don’t show up counted as oil workers in state labor statistics.

“Our people live in Anchorage and Mat-Su and they work here. They don’t go to the Slope,” Maloney said.

The last big jobs the fabricators had was two years ago on the building of Eni’s small Nikaitchuq oil field on the slope, and before that it was the construction of the Oooguruk field by Pioneer Natural Resources. Both companies built many of their production facilities in Alaska as “truckable” modules that could be constructed in Anchorage and moved by road to the North Slope.

A boom time for the fabricators was from 1998 through 2000 when the Alpine and Northstar oil fields were being developed by ConocoPhillips and BP, and large “sealift” modules, so large they had to be moved to the slope by sealift barge in summer, were built in Anchorage and Nikiski, near Kenai.

Since then there have been a steady stream of smaller projects, mostly facilities for expansions of the large oil fields, and then the new fields by Pioneer and Eni. Since then, the work has dried up.

When oil companies decide to build their projects in Alaska the decision has a much bigger economic impact than just the module-building, because companies like CH2M Hill are also asked to help install the modules on the Slope, which creates a lot more jobs.

“With the Eni project we had 120 in our ‘fab’ shop, working 70 to 80 hours a week, and we had 350 at the site on the slope, on installation. At one time we had as many as 600 working for Eni,” Maloney said. “Now it’s zero.”

Engineering work along comes along with a fabrication contract, too, and this creates additional jobs. Terry Bailey, a CH2M Hill vice president responsible for engineer services, recalled that during a particularly busy period when the company was doing the engineering on the CD-3 and CD-4 drill sites for the Alpine field and the DS 1-J drill site in the Kuparuk River field that CH2M Hill had 175 people employed in the design work, and 60- to 70-hour work weeks were the norm.

Not all of those people were engineers. Typically 30 percent to 40 percent of those in the engineering group were support people, for example doing data management, Bailey said.

Module work always had its peaks and dips, said Nate Andrews, CH2M Hill’s manager for the fabrication plant, but the company has always tried to keep a core group of about 60 skilled and experienced fabrication workers busy, to retain them.

With no work in the plant it’s getting really tough to keep these workers, Andrews said.

“The problem we now have is that we’re losing our core workers to North Dakota, as well as Alberta. They can work three weeks on and three off, and the employers will fly them back and forth,” Andrews said.

If work picks up in Alaska, CH2M Hill will be able to get some of these workers back, but not all.

“They can see years of work down there. Why come back here when it’s start-and-stop?” he said.

Maloney said these workers, including project managers and supervisors, are critical.

“Without people like these you’re not in the construction business,” he said.

Andrews said the company is doing everything it can to hang onto these experienced people including putting them temporarily into CH2M Hill’s field maintenance jobs on the North Slope or on loan to the company’s well service group.

This isn’t enough to take care of everyone, however, so the company has initiated a “work-load imbalance” program where it has had to furlough workers, but with benefits. There are about 75 people temporarily furloughed for now, who are on call.

“Some of these people haven’t worked since last November,” Maloney said.

Andrews said it’s tough to compete with North Dakota and Alberta.

“We used to be a high-wage state, and the differential allowed us to retain skilled workers. That’s no longer the case. The wages are the same in North Dakota and the hours are much better,” he said.

A lot of skilled Alaskans have left the state for better work elsewhere. “I don’t think we’ll get them back,” Andrews said.

Hiring new people to fill vacancies, if work picks up, is expensive.

“It costs us $7,000 to $12,000 to hire someone from outside the company,” he said. What’s also of concern, however, is that it takes time to a new person to become part of a team and fit in with a company’s safety culture, an area of importance in construction.

Tim Bradner can be reached at

Monday, March 19, 2012

Race to Win

Speaker cautious, but optimistic, about oil tax changes

Tim Bradner
Alaska Journal of Commerce

JUNEAU — House Speaker Mike Chenault is hopeful, but still cautious, on prospects for a major reform of state oil and gas taxes passing the Legislature in the final weeks of the 2012 session.

With 28 days left in the session before the required April 15 adjournment hearings are still underway on the Senate’s version of the bill, Senate Bill 192, in the Senate Finance Committee.

In a Monday briefing by House leaders Chenault said he thinks it may take one to two weeks for the Senate to finish its work and pass the bill to the House.

The Senate version is much different than an oil tax bill passed by the House last year, House Bill 110.

“When we get the Senate’s bill we will assign it to committees in the House for review, to see what’s in it, and see if we can get enough consensus for action,” Chenault said.

House members are watching the Senate committee’s deliberations but with other bills pending in the House it is difficult to set aside enough time to gain a full understanding of detailed presentations being made by consultants to the Senate, the Speaker said.

It would be possible for the House to pass the bill with just two weeks left, but it will depend on what House members think of the Senate proposal, the Speaker said. “Remember that we passed ACES (the current state oil tax) in just three and a half weeks,” he said.

ACES, or “Alaska’s Clear and Equitable Share,” the state’s net profits production tax, was adopted in 2007.

House Bill 110, which is now in the Senate Labor and Commerce Committee, was introduced last year by Gov. Sean Parnell to make changes in the ACES tax to encourage more industry production.

The bill was modified in House committees and passed to the Senate.

On other matters Chenault said the House version of the operating budget passed that body last Friday and has now gone to the Senate. “We expect to get it back in about two weeks, and then go to conference to work out differences,” between the House and Senate versions of the operating budget, Chenault said.

Meanwhile, the House Finance Committee will start work on its version of a capital budget bill this week, he said. The Senate has been working on its capital budget for several weeks.

Friday, March 16, 2012

BP chief says progress being made on gas deal, oil tax change still needed

Tim Bradner
Alaska Journal of Commerce

BP's Alaska president John Minge said the three major North Slope producers including BP are "on track" to reach agreement to work together on a possible $40 million Alaska gas pipeline, and to settle a contentious lawsuit with the state of Alaska over Point Thomson, a gas and condensate discovery east of Prudhoe Bay.

Minge made his comments in an interview March 14.

Alaska Gov. Sean Parnell has asked the companies to reach an agreement to work toward the pipeline by the end of March, and to agree on a project plan by the end of September. Settlement of the Point Thomson litigation is also needed, the governor said.

“We’re on track to meet the governor’s milestones,” Minge said. ConocoPhillips spokeswoman Natalie Lowman said her company agrees that important progress is being made in talks among the three major producers.

Parnell met with chief executives of BP, ConocoPhillips and ExxonMobil in Anchorage in early January and laid out milestones in his State of the State speech to the legislature in mid-January. The governor favors a large liquefied natural gas export project but left it to the companies to decide the location of the LNG plant, either at Valdez or at a Cook Inlet location.

Parnell also asked the companies to settle the lawsuit that has developed over disputed work commitments at Point Thomson. The state reached agreement with ExxonMobil, a major Point Thomson lease owner, last September but BP, Chevron and ConocoPhillips, which also own leases in the field, have yet to sign off on the deal.

Point Thomson must be settled before any substantial progress can be made on the pipeline because about one fourth of the 35 tcf gas reserves on the slope needed to support the project, about 8 tcf, is in that field. The remainder of the gas is in the Prudhoe Bay field.

Minge also warned that the state Legislature must reduce taxes on oil production, an issue the Legislature is now wrestling with, before a large gas project can move forward. Gas production depends on the underlying oil business to be healthy because that supports the production infrastructure on the North Slope, he said.

"We've made a lot of progress on the big issue, which is an alignment among the three companies and the state of Alaska," as well as the Point Thomson settlement, Minge said in the interview.

"The big question is still where the market is for the gas. It's apparent that there are challenges now for a line to the Lower 48," he said.

Minge said he personally believes a large Alaska liquefied natural gas export project can now be competitive, but the three companies are still exploring all options. Whatever the option selected, “we’ve got a lot of work to do. This is a $40 to $50 billion project,” he said.

Parnell had asked the companies to consider an LNG project instead of a pipeline to Alberta to link with existing pipelines to supply gas to the continental U.S.

The shale gas glut has diminished prospects for that project, which is being worked in by TransCanada Corp. and Exxon Mobil Corp. BP and ConocoPhillips had their own competing pipeline plan, the Denali project, but dropped it because of lack of customers.

Parnell said he believes the Asia LNG market is strong enough to support an Alaska project.

Upping the ante; Armstrong puts plans with Repsol at $9 billion, if oil taxes change

Kristen Nelson
Petroleum News

The major producers on Alaska’s North Slope have said that with meaningful changes in the state’s oil and gas production tax there are some $5 billion in projects which could become economic. Projects discussed by BP Exploration (Alaska) and ConocoPhillips Alaska are in the major producing fields, Prudhoe Bay and Kuparuk.

What about $9 billion in projects on currently undeveloped state land if the state makes meaningful changes in production tax on lands not currently producing?

That was the carrot Bill Armstrong, president of Armstrong Oil & Gas and 70 & 148 LLC, held out to legislators in a March 12 letter.

He said that “meaningful tax reform for non-productive lands” in the state, either as proposed by consultant Pedro van Meurs or as included in House Bill 110, the proposal Gov. Sean Parnell put on the table last year, could result in the expenditure of some $9 billion by Repsol E&P USA Inc. and Armstrong on North Slope acreage the companies are developing.

Armstrong told legislators that it’s typical for large and profitable fields to be found first, just as Prudhoe Bay and Kuparuk were on the North Slope.

But major oil companies tend to move on when they believe there are no remaining large and profitable fields, and smaller independent companies step in to develop smaller, more challenged fields, he said.

Smaller North Slope fields

Armstrong said Armstrong Oil & Gas, through various subsidiaries, “has been at the forefront of the movement to find and develop these smaller fields” on the North Slope and was “the generator of the last two successful developments” on the Slope — Oooguruk and Nikaitchuq.

The company brought in Pioneer Natural Resources USA Inc. as a partner in Oooguruk and ENI Petroleum Exploration Inc. which developed Nikaitchuq.

Armstrong said Oooguruk and Nikaitchuq were sanctioned prior to the state’s current production tax, Alaska’s Clear and Equitable Share or ACES, “and most likely would not have been approved for development had ACES been in place.”

“Alaska with its current tax structure is unintentionally preventing the smaller fields on the North Slope from being developed, thus an amendment to the ACES tax structure on non-productive lands is desperately needed,” he said.

Armstrong said that based on the geologic success of Oooguruk and Nikaitchuq, the company “doubled its efforts on the North Slope generating dozens of fresh ideas for potential fields,” and recruited Repsol to join its efforts.

(Repsol is doing exploratory drilling this winter.)

“The single greatest risk to our partnership moving forward in the development of multiple new oil fields on the North Slope (and for that matter, the greatest deterrent to all other potential new entrants to the North Slope) is the Legislature not passing tax reform on non-producing lands.”

With meaningful tax reform, he said, activities by Armstrong and Repsol could result in expenditure of some $9 billion.

House Bill 110

The governor’s proposal, HB 110, passed the House last year but didn’t move in the Senate, with senators in the majority caucus saying they needed more information about how ACES was working before making changes.

HB 110 is based on the premise that high taxes in Alaska make the state uncompetitive in attracting capital investment, and booming oil development and investment elsewhere in the world and in the Lower 48 driven by high oil prices are frequently cited by proponents of a reduction in the state’s production tax.

Progressivity, which increases the percentage of profits going to the state as oil prices increase, has been mentioned by senators as a feature of ACES that should be considered for change, and a reduction in the progressivity slope is a feature of Senate Bill 192, which was crafted in Senate Resources and is now in Senate Finance.

A major production tax rewrite was passed by the Legislature in 2006, changing the basis for taxation from gross to net. The ACES rewrite was introduced by the Palin administration in 2007 as a reaction to a bribery scandal tied to the passage of the 2006 tax bill resulting in the arrests of several legislators. Before ACES passed, the Legislature increased the progressivity rate.

The Parnell administration continues to argue that without meaningful tax change, such as that proposed in HB 110, investment — and production — will continue to decline on the North Slope.

There has been considerable public support through pro-development groups for a reduction in the state’s oil tax.

On the opposing side, some legislators argue that nothing is wrong with ACES.

Sen. Hollis French, D-Anchorage, has maintained that ACES is not broken and should be protected. On March 13 he rolled out results of a poll conducted by the Hayes Research Group that found only 30 percent of Alaskans in a 501-person survey thought oil taxes were too high, compared to 22 percent who thought they were too low and 28 percent who thought they were about right; 20 percent were undecided.

French said the poll, conducted March 5 and 6, had a margin of error of 4.38 percent.

With 50 percent saying taxes were too low or about right, French said it tells him “that Alaskans are not backing Governor Parnell’s oil tax bill.”

Current hearings

Senate Finance Committee co-Chair Bert Stedman, R-Sitka, said March 13 at a Senate Bipartisan Working Group press availability that the oil tax was a complicated issue with tremendous importance and said it would take longer than a week, probably longer than two weeks, to work through the process in Senate Finance.

He said there is a lot of work to be done on the bill, and said Senate Finance reserves the right to change everything under the title.

Senate President Gary Stevens said it’s important that the process be done right, but said he believes the Senate could get through the bill in the time left and noted that the House would be watching what the Senate does.

Stevens originally proposed getting the bill to the House with a month remaining in the session. With the Legislature set to adjourn April 15, that schedule has already been missed.

House Majority Leader Alan Austerman, R-Kodiak, said March 12 in a House Majority press availability that the House caucus won’t discuss what to do about an oil tax bill until they see what the Senate passes. He said he expects what comes out of Senate Finance won’t be the same as what came out of Senate Resources.

Austerman said the House will feel pressure to pass something this year and said he didn’t know if the Legislature will stay past 90 days. Rep. Bill Thomas, R-Haines, co-chair of House Finance, said if the bill coming out of the Senate isn’t something the House can live with, the Legislature could chose to deal with it next year.

The Resources version

SB 192, as passed by Senate Resources, reduces the rate and cap of progressivity, rewards increased production, establishes a gross minimum tax, separates oil and natural gas for purposes of calculating progressivity (decoupling) and creates an oil information system based in the Alaska Oil and Gas Conservation Commission.

In an overview of the Resources Committee bill for Senate Finance, Resources co-Chair Joe Paskvan, D-Fairbanks, noted that in January 2011, when Parnell introduced HB 110, a status report on ACES by the Department of Revenue cited increasing investment under ACES — although the report noted that it was unclear how much of that capital was for drilling as opposed to maintenance or facilities.

In a January 2010 ACES status report, then-Commissioner of Revenue Pat Galvin, who headed the team that worked on ACES under former-Gov. Sarah Palin, said “ACES successfully allowed the state to share in the benefits of high oil prices while accommodating fluctuations in production costs and oil prices.”

Galvin also said: “Since ACES passed the legislature, overall spending on oil and gas activities on the North Slope has increased,” but said oil taxes are only one factor in many — such as “world oil prices, geologic potential, access to land, resources and markets, costs of infrastructure and support services, and the legal and regulatory framework” — influencing investment decisions.

Administration comments

The Department of Revenue did an initial presentation on SB 192 to Senate Finance March 14.

Revenue Commissioner Bryan Butcher told the committee the department does not believe the changes in the progressivity surcharge in SB 192 are enough to change investment climate in the state. He also said that the proposed allowances for increased production added complexity to the tax structure, already complicated compared to others. He noted that Pedro van Meurs talked about conversations with Repsol and the number of people that company had focused on trying to understand the Alaska tax system. Butcher said Repsol has been going back and forth with the Department of Revenue for several months, trying to understand the state’s tax structure.

Butcher said the complexity of the state’s tax system is something Revenue hears about all the time: it’s a hurdle Alaska has to deal with, he said.

SB 192 includes a gross minimum tax and Butcher said that would be a disincentive to investment in Prudhoe Bay and Kuparuk.

The bill also contains a petroleum information system, which would be developed by the Alaska Oil and Gas Conservation Commission. Butcher said he would defer to AOGCC on that, but said the commission is not in favor of it, believing it to be cost prohibitive and a diversion from what the commission perceives its mission to be.

Stedman said AOGCC would be before the committee March 16 and said the commission may not be the appropriate place to locate information.

On decoupling, separating oil and gas for progressivity calculation, Butcher said the administration’s position is the same as it was when the Legislature passed a decoupling bill in 2010 (which the governor vetoed). He said the governor has very serious concerns with the language as proposed and said Revenue was working on language to decouple and be more revenue neutral.

Existing v. incremental production

Stedman noted that consultants have told legislators that no changes are needed on taxes on existing production, just on incremental production.

Butcher said the department disagrees with Pedro van Meurs on that aspect and believes the current tax structure is too high for both current and new production.

Stedman said he expects the committee will separate current production and incremental production — that over the current 6 percent decline rate.

HB 110 brackets progressivity and Butcher said virtually every other jurisdiction brackets, so Alaska is an outlier in that respect. Lack of bracketing is the reason we see a higher marginal tax rate, he said.

Stedman noted that if bracketing was included, something else would need to change to keep the net to the state the same, noting that the issue on the table is splitting profit oil.

Deputy Revenue Commissioner Bruce Tangeman said the goal of HB 110 was not to keep things the same. The administration believes the pendulum swung out too far with ACES. The goal of HB 110 was not to be revenue neutral but to increase production, he said. Stedman noted that progressivity was introduced to keep the percentage share going to the state from declining as oil prices increased; progressivity was used to neutralize regressive aspects of the state’s tax system.

Now the system is aggressive; the discussion is whether it’s too much, he said.

Saturday, March 10, 2012

Ups, downs for explorers; Repsol resumes drilling at Kachemach 1; Brooks Range pleased with Mustang results

Kay Cashman
Petroleum News

Independent Brooks Range Petroleum finished its Alaska North Slope exploration drilling at the end of February with a smile, per company executive Bart Armfield, who confirmed March 7 that Brooks Range is “very happy” with the results of both its Mustang 1 well and the North Tarn No. 1-A sidetrack, which was started and suspended last year.

Furthermore, Brooks Range’s release of Nabors 7ES drilling rig allowed Savant Alaska to grab the rig for drilling at its eastern North Slope Badami unit, in hopes that its drilling permit for the Red Wolf No. 2 exploration well will be approved by the Alaska Oil and Gas Conservation Commission in time to drill during this winter’s short exploration season.

According to Savant executive Greg Vigil, Nabors 7ES is “currently performing a rig work over on the B1-21 well” at Badami. “When complete it will move to the B1-16 well to conduct another rig work over. Both wells need artificial lift installations to be placed on production into the Badami plant.”

The not-so-good news from Brooks Range is it learned enough about its Mustang prospect from Mustang 1 and the North Tarn sidetrack that it doesn’t need to drill a second well this winter, cutting the anticipated North Slope 2012 exploration well count from a possible high of 27 to 26. The Mustang prospect, which is in the Southern Miluveach unit west of the Kuparuk River unit, was initially a discovery well called North Tarn. The prospect name has since been changed to Mustang.

And there’s good news from Repsol E&P USA: On March 8 the company restarted drilling operations at its Kachemach 1 ice pad.

Both the Q-2 and K-1 drill sites are on Alaska’s North Slope, but K-1 is farther south and not geologically similar to Repsol’s three Qugruk drill sites, which lie near the mouth of the Colville River.

Repsol had stopped drilling operations at Q-2 and K-1 when it had a gas blowout at Q-2. Drilling had not yet begun at the Q-1 ice pad or at Q-4, an ice island, which as of March 7 was 74 percent complete, and the ice road to it 83 percent complete.

Repsol’s decision to suspend all its North Slope exploration activity after the incident (see related story on page 1 of this issue), was in fulfillment of a promise made by the Spanish major to the people of Nuiqsut prior to the start of its winter exploration program.

According to Petroleum News sources, Repsol’s decision to move forward with K-1 drilling came after making sure the village leaders of Nuiqsut, the North Slope Borough and the Alaska Oil and Gas Conservation Commission did not object.

The company, which was testing blowout preventer equipment on Nabors 9ES at K-1 as this issue of Petroleum News went to press, had hoped to drill a total of nine wells from three ice pads and one ice island during this winter’s exploration season, but the likely loss of two potential wells at Q-2 dropped that number to seven, especially since AOGCC has withdrawn all the Qugruk drill site well permits and asked Repsol to reapply for them, a process that will chop at least 14 days from the already short exploration season.

But in the interest of safety, company officials don’t appear to be complaining.

AOGCC permits applied for last

AOGCC drilling permits are often the last permits applied for by operators because other authorizations and permits have to be in place first and because they are rig-specific.
That’s likely why Alaska’s first shale player, Great Bear Petroleum, which can drill year-round from gravel pads in an existing transportation corridor, does not have its 8-12 drilling permit applications into the agency for drilling start-up in May: Great Bear does not yet have a rig under contract.

Following is the status of AOGCC exploration well drilling permits.

Permits issued by AOGCC as of March 8, 2012:

1. Repsol, Qugruk 4 (on hold following Feb. 15 Q-2 incident)

2. Repsol, Qugruk 4a (on hold)

3. Repsol, Kachemach 1

4. Repsol, Qugruk 1 (on hold)

5. Repsol, Qugruk 2 (on hold, likely will not be drilled this winter)

6. Repsol, Qugruk 2a (on hold, likely will not be drilled this winter)

7. Brooks Range Petroleum, Mustang 1 (well completed)

8. ConocoPhillips, Shark Tooth 1 (well completed)

9. Pioneer Natural Resources, Nuna 1 (well completed)

10. Pioneer Natural Resources, Sikumi 1 (well being drilled)

Pending/or yet-to-be-filed permits:

11. Savant applied for its Red Wolf permit the week ending Feb. 10. It is reportedly receiving additional scrutiny as a result of the Feb. 15 incident at Q-2.

12, 13, 14. Repsol has six permits approved, five of which are on hold, but it should have three more applications in.

15-26 Great Bear (8-12 wells, including laterals)

According to AOGCC, it cannot confirm pending permit applications because of “regulation 20 AAC 25.537.”

Subtracting Repsol’s planned Q-2 wells brings the total North Slope exploration well count down to 24.

But Great Bear executive Ed Duncan has said he doesn’t expect to need to drill more than eight wells for his proof of concept program, so 20 is likely the top number for 2012.

If Repsol gets its Qugruk permits reissued.

If Savant gets its Red Wolf permit in time.

And if Great Bear is issued its permits.

Stay tuned.

Head-on coming; Senate Resources completes oil tax bill nothing like what House passed

Kristen Nelson

The Alaska House and Senate appear to be on a collision course over changes to the state’s oil production tax.

Last year the House passed an oil tax reduction requested by Gov. Sean Parnell. The stated goal of House Bill 110 was to encourage more industry investment in the state — and more oil production — by reducing the tax level imposed by Alaska’s Clear and Equitable Share, ACES, passed under Gov. Sarah Palin in 2007. ACES came on top of an oil tax increase enacted in 2006 under Gov. Frank Murkowski, the Petroleum Profits Tax or PPT, which moved the state from a tax on the gross to a tax on the net and added progressivity — as oil prices, and profits, rose, the state would get more revenue.

ACES steepened the progressivity curve in PPT, increasing the state’s take at higher oil prices.

The Senate did not act on HB 110 last year, citing a need for more information before it acted.

The Senate didn’t act on HB 110 this year, instead moving its own bill, Senate Bill 192. A committee substitute for that bill passed out of Senate Resources March 2, headed for Senate Finance. Hearings in Senate Finance had not yet been scheduled when this issue of Petroleum News went to press March 8.

House Bill 110

Dropping volumes in the trans-Alaska oil pipeline were the driver behind tax changes in HB 110.
Industry argued that the steep increases in the state’s production tax rates which were enacted in 2006 and 2007 made Alaska uncompetitive for investment, investment which was needed to stem the state’s production decline.

HB 110 would have made several changes in the state’s production tax system. Significant fiscal impacts were expected from a reduction in tax rates which were bracketed under the bill and capped at a maximum production tax rate of 50 percent.

At forecast production levels, state revenue was expected to drop under HB 110 by $469 million in fiscal year 2013, $989 million in FY2014, $1.166 billion in FY2015, $1.418 billion in FY2016 and $1.554 billion in FY2017, a total of some $5.6 billion over that period. At production levels 20 percent above the forecast, the revenue loss would have been about $2.7 billion over the same period, and with increased royalties at a production level 20 percent above the forecast, the revenue loss would have been $401 million.

In addition to production tax and royalties, the state collects property tax and corporate income tax. The federal government also collects taxes. The total of state and federal taxes is the government take.

Senate Resources bill

The Senate Resources committee substitute for SB 192 lowers the rate of progressivity and the cap on progressivity.

Under the bill progressivity will still be triggered when the price of oil is above $30 per barrel in production tax value (the price of oil less production and transportation costs), but the progressivity rate under SB 192 will be 0.35 percent for each dollar increase in the production tax value, or PTV, instead of the current 0.4 percent. At $101.43 per barrel PTV the progressivity rate will drop to 0.1 percent; at $201.43 per barrel PTV progressivity is capped (the previous cap wasn’t reached until a PTV value of $342.50 per barrel).

The committee said initial Department of Revenue calculations indicated the reductions would result in revenue losses of $200 million to $250 million per year.

SB 192 also provides a reduction of $10 in production tax value for each new barrel produced for the first year, adds a 10 percent tax floor to ensure Alaska receives some revenue even at very low oil prices, provides for decoupling — the separation of oil and natural gas for production tax calculations — and calls for the Alaska Oil and Gas Conservation Commission to develop an electronic petroleum information management system for public information currently gathered by the commission and the departments of Revenue, Natural Resources and Labor and Workforce Development.

The Senate’s reasoning

Senate Resources co-Chair Joe Paskvan, D-Fairbanks, said March 6 in a Senate Bipartisan Working Group press availability that his “inquiry from a year ago indicates that in that range of $120 to $140 a barrel, that there can be a distortion of the relationship between Alaska as the owner of the resource and the amount of monies that are paid by the oil industry.” He said he believes the changes in SB 192, the 0.35 slope compared to the 0.4 slope in ACES, “particularly targets” that $120-$140 a barrel price range and “more appropriately balances the relationship between the state and the oil industry.”

Sen. Kevin Meyer, R-Anchorage, said he believes the bottom line is that there isn’t enough oil in the pipeline and said he thinks “progressivity is the major factor that has to be addressed” to make Alaska a little more competitive with other places worldwide that companies can invest.

BP and ConocoPhillips have committed to invest $5 billion of additional capital in exchange for the tax reductions in HB 110.

Sen. Bill Wielechowski, D-Anchorage, said March 6 that there is “clearly no commitment” for that investment because it would also require ExxonMobil’s agreement. He also said that analysis done last year showed the $5 billion investment would be “wildly profitable under our current tax structure,” with the state actually picking up 60 percent of that through tax credits and deductions.

Sen. Hollis French, D-Anchorage, agreed on the issue of Exxon’s commitment being required on the $5 billion investment, and said that HB 110 would push “1.8 billion a year across the table,” calling the governor’s bill a giveaway.

French said the governor needed to “run the numbers again” ... “look at the strength of the commitment” and recognize that HB 110, with “up to $18 billion” in foregone revenue, is a “horrible, horrible ... business idea for the state to engage in.”

Both Wielechowski and French voted to pass SB 192 out of committee; voting against moving the bill were Sen. Tom Wagoner, R-Kenai, and Sen. Lesil McGuire, R-Anchorage.

The House response

At a House Majority press availability on March 6, Rep. Mike Hawker, R-Anchorage, chair of the Legislative Budget & Audit Committee, called the Senate’s decision not to build on the work the House did on HB 110 last year unfortunate, calling the House process “open and transparent.”

He said he’s “a little disappointed in the process and product that came out of Senate Resources. Most of what was in that bill was never even discussed in committee; it’s something that ... appears to have been written in a caucus meeting rather than in a public forum.”

Hawker said his primary concern with the Senate bill is that he does not think it moves the needle. He characterized the bill as making “nothing more than a very, very small cosmetic change to the state’s progressivity tax, the one that I think everyone has universally agreed is broken.”

Rep. Craig Johnson, R-Anchorage, said he was “a little pleased with what the Senate has done,” saying they have moved from saying last year that no changes would be needed to ACES, “to at least recognizing that it’s broken and that it needs to be fixed.”

Hawker also said he thinks the state has “lost sight of having a vision for our tax policy,” calling the present policy “pretty much a policy of take as much as you can while you can get it.”

He cited Gov. Jay Hammond, who at the time the trans-Alaska oil pipeline was being built espoused a policy that the state and federal government takes two-thirds and leaves one-third to industry.

“I think something as clear and crystal as that vision might be something that would work for this state,” Hawker said.

House Speaker Mike Chenault, R-Nikiski, said he expected the oil tax bill to be taken up in Senate Finance the week of March 12. If Senate Finance keeps the bill for a week and then sends it on to the House, that would allow the House the four weeks that’s been discussed, he said, referring to Senate President Gary Stevens’ proposal that the bill leave the Senate in time for the House to have a month to work on it.

Chenault said he expects that schedule may slip some, but said “the House will take the time that’s necessary to go through that piece of legislation ... and have a good public process.”

He said the House will want to look at modeling on whatever bill comes out of the Senate, will want to have an open process and talk to Alaskans and the industry.

“You know, that may take three weeks; it may take three months; I don’t know. Until the Senate sends a bill out of Finance we won’t know in its entirety what it does,” Chenault said.

Hawker said he shared the Senate’s objectives for tax reform — more production, more jobs and sustainable tax revenue.

He said SB 192 is “nothing more than a cosmetic change to the progressivity factor,” and doesn’t address high marginal rates, a concern that LB&A’s consultants have expressed.

He also said the bill did not pay attention to consultant recommendations that total government take be capped at a reasonable level.

Hawker said if the state wants “robust activity, we offer robust fiscal terms; if we want minimal activity, we offer minimal fiscal terms. It’s a pretty straight tradeoff.”

He said SB 192 is a giveaway — it reduces taxes but not enough to gain additional investment.

Friday, March 9, 2012

Senate committee passes a bill to change oil taxes

By Tim Bradner
Alaska Journal of Commerce

A state Senate committee approved proposed changes March 2 to the state’s oil and gas production tax as part of an effort to attract more industry investment in declining North Slope fields.

Senate Bill 192, reported out of the Resources Committee and now in the Senate Finance Committee, is the Senate’s first step in developing its counter-proposal to an oil tax change bill passed by the state House last year, House Bill 110. The Finance Committee is expected to begin work on SB 192 the week of March 12.

“The committee substitute makes significant changes in the state’s oil and gas production tax,” Resources Committee co-chair, Sen. Joe Paskvan, a Democrat from Fairbanks, said.

However, the other committee co-chair, Sen. Tom Wagoner, a Republican from Kenai, opposed the bill and was one of two votes against moving the bill out of committee.

Alaska North Slope fields are declining at 6 percent to 8 percent a year and producers say the state’s high tax rate is an impediment to new investment particularly in existing fields.

State House leaders were critical of the changes in SB 192. In a March 5 briefing by House leaders, Rep. Mike Hawker, R-Anchorage, said the Senate bill does not “move the needle” sufficiently to attract new investment.

“It’s a cosmetic change, and it’s truly a tax giveaway because it gives something without getting anything in return,” meaning a tax reduction granted that is insufficient.

Hawker was also critical that a substantial section of the Senate bill, dealing with the separation, or “de-coupling,” of oil and natural gas taxes, had never been before the Resources Committee for discussion prior to its introduction in the new committee bill.

“This is a bill written by the Senate majority caucus, not by the committee,” Hawker said.

Industry spokesmen, who spoke to an earlier version of SB 192 in hearings March 1, said that without a key change considered but rejected by the Senate Resources Committee Friday the bill, SB 192, doesn’t go far enough.

Damian Bilbao, head of BP’s Alaska finance and new developments group, said that without the inclusion of a tax “bracketing” mechanism the change doesn’t have sufficient financial effect for producers.

The “bracketing” mechanism, working much like the federal income tax’s different tax brackets at different income levels, would apply to brackets of production as the crude oil prices rise rather than having the tax apply to the entire stream of production, which is the case in the current tax law.

In the Resources committee Sen. Lesil McGuire, R- Anchorage, proposed bracketing as an amendment to SB 192, but it was rejected on a 5-2 vote by the committee. Sen. Bert Stedman, R- Sitka and a member of the committee, said bracketing or something similar could be considered in the Finance Committee, where he is co-chair.

North Slope producers and Alaska Gov. Sean Parnell support the bill that passed the state House and is now in the Senate Labor and Commerce Committee, and that does include bracketing of the tax.

Senators say they felt the House bill gives away too much to producers and want to push their own bill. Sens. Bill Wielechowski and Hollis French, two Democrats on the Resources Committee, said the House-passed bill would lower state tax income by $1.8 billion a year. Initial estimates are that the changes in SB 192 would reduce taxes on producers by about $250 million per year.

However, the Department of Revenue has not completed its analysis of the fiscal impact of SB 192, and Senate President Gary Stevens said consultants to the Legislature are continuing their assessment of the impact of the SB 192 changes as the Finance Committee prepares for its review.

SB 192, as approved by the Resources Committee, would change a formula in the production tax, the “progressivity” formula, that sharply increases the tax rate at high oil prices and also caps the tax at 60 percent of net profits. In the current law the cap is at 75 percent.

The change in the progressivity formula would actually work in two stages. The current formula increases the tax rate, which begins at 25 percent of a company’s net profit, by 0.4 percent for every $1 increase of a company’s profit over $30 per barrel.

SB 192 changes this to a 0.35 percent increase up to a cap of 50 percent of profits going to the state in taxes, and then further adjusts the formula to increase at 0.1 percent for every dollar of profit increase up to a cap of 60 percent.

These changes would immediately benefit production from the so-called legacy fields, the large oil fields now in production where the producing companies say more production can be added.

In another change, the Resources Committee bill added a new section to further reduce taxes on new oil produced above a base rate of existing production in the producing fields, and also added a minimum tax based on gross revenues to protect the state if oil prices decline.

The new oil provision allows producing companies, or anyone bringing on new production, an allowance of a $10 per barrel increase to the per-barrel profit level when the progressivity formula kicks in. Thus, if the threshold for existing old oil is $30 per barrel net profit, this provision would make the progressivity apply at $40 per barrel profit for any increased oil produced from the field.

The minimum tax is essentially a reimposition of a severance tax on gross oil revenues, at a rate of 10 percent. Alaska’s production tax was based on gross revenues until 2006 when the change was made to a tax on net revenues.

The difference is essentially that a net revenues tax allows for production expenses to be deducted as well as transportation (pipeline and tanker) costs. Gross revenues allow only the transportation costs.

State economists have explained that the two types of taxes perform differently as oil prices, and the netback values, change. A net revenues tax gains the state more income at higher oil prices than a gross revenues tax, but also loses the state more if prices drop.

In 2007, when lawmakers enacted the current version of the oil tax, the gross revenues tax as an alternative minimum was hotly debated and was in fact included in the tax law but at a much lower rate.

SB 192 increases the rate in the gross revenues alternative tax so that a crude oil market price of about $70 per barrel the alternative tax would bring the state more revenue.

One other change separated the tax on crude oil from natural gas. Under current law the two are joined with the tax imposed on the computed British Thermal Unit value of combined streams of oil and gas when the two are produced together in wells.

Consultants have warned the Legislature that because of the sharply differing values of crude oil and natural gas the combined tax could result in substantial losses of revenues from oil once commercial production of gas begins on the North Slope.

Wednesday, March 7, 2012

Buccaneer Energy says its new Kenai gas well will produce

By Tim Bradner
Alaska Journal of Commerce

Buccaneer Energy’s new Kenai Loop No. 1 gas well near the city of Kenai is performing, producing about 5 million cubic feet of gas per day after about two weeks of steady production, the company says.

Production began Jan. 14, and the gas is being sold to both Enstar Natural Gas Co. and ConocoPhillips Alaska Inc. under contracts Buccaneer has signed with both companies.

“Based on the available information the company is confident that the (Kenai Loop No. 1) well can be produced at higher rates,” Buccaneer spokesman Dean Gallegos said. “The current production rate will be maintained and monitored over the next 30 to 60 days and, if appropriate at that time, a decision will be made to increase production rates.”

Buccaneer’s discovery of gas at a location one mile from the long-producing Cannery Loop gas field on the Kenai Peninsula is being cited widely as proof that substantial amounts of gas are yet to be discovered in the Cook Inlet basin.

The company’s contract with Enstar allows the company to sell Enstar a minimum of 5 million cubic feet per day and a maximum of 15 million cubic feet per day as soon as a gas storage facility being constructed in the area is ready to accept gas, the statement said. Enstar will pay an annual average price of $6.24 per thousand cubic feet.

Cook Inlet Natural Gas Storage Alaska LLC, which is developing the underground gas storage facility, has informed Buccaneer that it expects to be ready to accept gas for injection in early April. In the meantime, Buccaneer has been offering gas to the utility under Enstar’s daily auction system.

The company is also supplying gas to ConocoPhillips, which has contracts to supply Chugach Electric Association, and owns and operates the Kenai natural gas liquefaction (LNG) plant. That facility is now in a suspended state but the making of LNG from gas will resume in April or May in anticipation of LNG cargo shipments to customers in Asia in the last half of 2012, ConocoPhillips spokeswoman Natalie Lowman said.

Four shipments are being planned for now, she said.

Meanwhile, Buccaneer has a 25-square-mile three-dimensional geophysical survey is under way in the immediate area to determine the best locations for future wells.

“With improved seismic imaging the company believes it will be possible to rapidly drill and place on line a number of wells from existing drilling pad sites,” Gallegos said.

Buccaneer is in the process of contracting for a drilling rig for the next well, with drilling expected to begin in April or May, he said.

Saturday, March 3, 2012

Senate works on oil taxes; passage this session in doubt

By Tim Bradner
Alaska Journal of Commerce

The state Senate had planned to continue work on its proposal for oil and gas production tax changes through March 2. It was unclear whether the Senate Resources Committee would finish its work on the bill by the weekend, but several broad themes have emerged as to changes the Senate will attempt.

Even two Democrats on the Resources Committee, Sens. Hollis French and Bill Wielechowski, both of Anchorage, now support changing the tax, known as ACES, or Alaska’s Clear and Equitable Share, a named applied by Gov. Sarah Palin when she proposed the tax in 2007.

French and Wielechowski have previously been staunch supporters of the current tax. All of the proposals now being made attempt to modify the financial effect of the tax to induce more investment.

The state House passed its version of oil tax reform last year in House Bill 110, a proposal Gov. Sean Parnell supports. Senators rejected that approach, however, and have set to work a counter proposal.

Legislators will be mostly gone from Juneau the week of March 5, many attending the Energy Council meetings in Washington, D.C., so the soonest the Senate Finance Committee can begin its work on the bill sent from the Resources Committee is the week of March 12.

Earlier, Senate President Gary Smith, R-Kodiak, had hoped to have the Senate tax bill passed and to the House by mid-March, in time to give the other chamber a month to consider the bill before the Legislature’s required adjournment April 15.

That schedule now looks virtually impossible. In a Feb. 28 briefing by Senate leaders Sen. Joe Paskvan, D-Fairbanks, co-chair of the Resources Committee, said only that he would like the get the bill out of his committee “as soon as possible.” Earlier Paskvan had expressed hopes that the bill could be to the Finance Committee by the time of the Energy Council break, which begins March 5.

Senate leaders said they want to move deliberately and do the bill correctly given the stakes. However, the delay could imperil any hopes of getting the oil tax bill passed in the regular 2012 session, which raises prospects that the work may have to be finished in a special session, if at all this year.

However, several Senate majority leaders are now on board that the tax has to be modified. Broadly, several senators are pursuing modifications of the progressivity formula in the production tax, a formula that ratchets up the tax rate as crude oil prices climb. This has been identified by industry and the state revenue department as the most troublesome part of the current tax, which is a net profits-type tax where the state tax applies to industry income after transportation and production expenses have been deducted.

A second change being pursued is a mechanism to lower taxes on new oil that is produced, compared to existing production, and a lower tax for oil that is difficult to produce or lower in quality, such as heavy oil.

Several senators are interested in changes to the exploration and development investment tax credits in the current tax law, thinking them too generous.

The bulk of the amendments before the Resources Committee, some of which will be included in a proposed committee substitute bill to be available March 2, were offered by senators the previous week.

Committee co-chair Sen. Joe Paskan, D-Fairbanks, asked PFC Energy, consultants to the Legislature, to develop models illustrating the fiscal effects of the amendments and to report the results to the committee.

Among the amendments offered are two by Sen. Lesil McGuire, R-Anchorage, which would establish a “bracketing” structure to the progressivity formula so the tax rate rises in increments, much like the federal personal income tax, rather than having a higher tax rate apply to an entire stream of production.

An alternative proposal by McGuire would have the bracketing apply only to new production. McGuire’s own analysis is that her proposal would lower taxes for industry by more than $1 billion by 2014, she told the Resources Committee.

In a presentation to the committee Feb. 28, Alaska Oil and Gas Association Director Kara Moriarty explained the problem in the current tax.

“One of the most egregious provisions of the current tax is the fact that as the price of oil increases, and as the higher tax is implemented, all prior dollars are taxed at the higher rate,” Moriarty said. “One approach to address this is through a bracketing concept that sets tax rates at different levels as the price increases so that each level is only taxed once, setting a specific rate for each bracket, thus moderating the impact of higher tax rates.”

Bracketing is included in the House-passed HB 110.

For their part, Wielechowski and French offered an amendment to cap the increase of the tax rate in the progressivity formula.

“I have become persuaded that our tax is now on the high end,” Wielechowski said.

French agreed, and co-signed the amendment with Wielechowski.

However, both Wielechowski and French said they want to see the fiscal effects of the change modeled before making a final decision.

“I will be very cautious in adjusting the progressivity (formula) because there is no guarantee of investment. I am now persuaded we are on the high side (in tax rates compared to other producing regions) but I’m still going to be a foot-dragger in this,” French said in the discussion before the committee.

French said he hopes to solve the problem of a guarantee of increased investment through another amendment that would reward the production of new oil. This would be in the form of an allowance that involves tax relief for new oil production that is measured above a base rate in an existing field.

This basically follows a recommendation by consultant Pedro van Meurs, but French said he felt van Meurs’ proposal for five allowances for new oil, including heavy oil, was too unwieldy.

“We’ll work to come up with something” that is similar but simpler, he said.

“The basic principle is that there is no reduction in taxes without new production,” he said.

Sen. Tom Wagoner, R-Kenai, has offered an amendment for a tax holiday for new oil that is similar in concept to that put forth by French. Wagoner worked with industry tax specialists over the summer on technical aspects of the bill to ensure that it would function properly.

He is not wedded to his own idea, however.

“If French’s approach is simpler, I can support that. I can go either way. I haven’t seen the modeling (of fiscal effects) on my idea, either,” Wagoner said.

The problem with rewarding new oil is how to define it. House Bill 110 has a reward for new oil by allowing a tax reduction for new oil development outside existing fields, which is a simple way to do it.

However, producing companies and consultants have told lawmakers that a great deal of new oil production can be done within the existing fields, both in squeezing more oil from the currently producing reservoirs and developing new, untapped deposits that are known but undeveloped within the field areas, like heavy oil.

Consultant van Meurs suggested a way to measure new oil in existing fields that is done in some other producing regions, by measuring the decline rate in the field and then allowing a reduced tax on any oil produced that is above the measured decline rate, which would be classed new oil.

In the committee discussion, Wielechowski said how the decline rate is set and who sets it would be critical to making such a mechanism work. There must also be allowances for interruptions in production, which would affect the decline rate, he said.

However, the concept is worth pursuing, based on van Meurs’ statement that other producing regions have made such approaches workable. Whether the idea or something similar winds up in the final proposal being developed by the Resources Committee is uncertain, but senators are clearly searching for some way to reward investment in new production, particularly in the existing fields.

Another idea Wielechowski proposed, in the form of a proposed amendment, is a minimum floor to the tax that would give the state assured revenues in case oil prices were to fall. The idea of a minimum was hotly debated when the Legislature adopted the ACES tax changes in 2007 but was rejected.

“We adopted ACES without this because we felt there was so much money at the high end,” meaning the state would be so well compensated at higher oil prices under the tax that it could take the risk on the low end of prices, Wielechowski said in discussion at the Resources Committee.

“What we didn’t contemplate (in 2007) is that the tax would become too high at the higher oil prices,” he said.

In proposing a mechanism for a floor at lower oil prices, Wielchowski would balance the giving up of some revenues at higher prices for a guarantee at lower prices. “We need a tax system that is durable,” in both price environments, he told the committee.

Wielechowski reminded the committee that Alaska North Slope oil was priced at $39.01 per barrel in January 2009. Also, with the investment tax credits currently in effect, there could be situations, in a low oil price environment, that the state would actually be paying industry rather than the other way around, the senator said.

French said he would like to cap the tax credits so the state paid no more than 65 percent of the cost of a new project under all oil price situations.

Sen. Bert Stedman, R-Sitka, said consultant van Meurs had told lawmakers that under certain high price scenarios the tax credits could result in the state paying 100 percent of the cost of projects, or even more.

Friday, March 2, 2012

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

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

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