Update — and a recap — on upcoming state oil tax fight

November 22, 2012

When legislators open their 2013 session in Juneau, the knotty oil tax problem awaits them. Despite the new Republican-led leadership in the Senate, the Legislature will proceed cautiously in considering proposals to reduce the state’s oil production tax. The issue is highly complex and controversial, and the new Republican Senate leaders, while sympathetic to the need for changing the tax, will realize they must move carefully.

Here’s a quick recap of the problem:

• Alaska changed its oil tax system in 2006 to the net-profits type tax from a gross-revenues tax, under Gov. Frank Murkowski. The Department of Revenue had long urged such a tax because a net-profits tax works to bring more revenue to the state when oil prices are high. (The net-profits tax also reduces revenue when prices are low, but also reduces the tax on industry).

• In 2007, Gov. Sarah Palin proposed technical changes at the suggestion of the Dept. of Revenue, some of which would have improved the tax from industry’s standpoint by adjusting a progressivity formula in the tax that increases the tax burden as oil prices rise. The progressivity formula under Murkowski’s PPT was aggressive. Palin’s changes would have softened it.

• Palin’s tax “fix-up” bill, renamed ACES, or Alaska’s Clear and Equitable Share, went through substantial changes in various legislative committees, the most substantial being an upward revision to the progressivity formula. This is the version of ACES that exists today.

• By 2010 it was clear to many that the ACES changes had been too aggressive, and had put Alaska, now a state with modest prospects for large discoveries, at least on North Slope lands open to exploration, near the top of the world’s oil tax systems. Industry investment in new oil development declined. Oil production was meanwhile declining at rates of 5 percent to 6 percent a year, and continues to decline.

• In 2011 Gov. Sean Parnell introduced HB 110, lowering the progressivity rate and making other changes, hoping to induce more investment. The bill passed the House but was opposed in the Senate. HB 110’s key change, to the progressivity formula, is similar to what Palin originally proposed in 2007.

• In 2012 the Senate labored on a counter-proposal. While it was unclear that any substantive proposal to reduce taxes on industry would have passed the Senate under its former 10-10 coalition leadership, the Senate Finance Committee did substantial work to fashion a tax bill that solved certain problems in HB 110.

• Essentially, the Senate ran out of time in working the complex problem, a casualty of the 90-day session. A short special-session called at the end of the 2012 regular session by Gov. Parnell was counterproductive because the governor did not give his Department of Revenue time to develop possible compromise proposal. Also at that point legislators were tired, cranky, and needed a break.

So, what happens now?

It should be expected that the governor will introduce a new bill, although legislators may also introduce bills. Sen. Cathy Giessel, to be chair of the Senate Resources Committee, said she intends to start work quickly on the tax issue. Hopefully, a lot of the work done by the Senate Finance Committee in 2011 can be built on. Sen. Lesil McGuire, who is part of the new Senate leadership, was on the committee last year and is familiar with the work it did. Though not a member of that committee, Sen. Giessel sat through many of last year’s lengthy hearings.

Here are some of the key issues that the Senate Finance was wrestling with in the 2012 session:

• There were no argument over tax reductions on “new” oil that is discovered. A reworked bill that attempted to do this in fact passed the Senate last year, but it was rejected by the House because it did not go far enough and because it was too late in the session for the House to give it adequate review.

• The big argument is over a tax reduction on “old” oil production, or production from existing fields. The companies, and many legislators, argue this is necessary because much of the new oil that can be developed fairly quickly on the North Slope is within the existing fields. There are many small pockets of conventional oil that were bypassed previously because they were uneconomic. Technology improvements have made tapping these pockets feasible, but the ACES tax system still renders them uneconomic, the companies argue. There are massive heavy oil resources although there are still technical issues to be solved to produce these. Work on heavy oil has meanwhile been shelved, for now. The companies argue that without tax changes to improve the overall economic health of the large conventional oil fields, investing in unconventional oil that will depend on the infrastructure of conventional oil is not viable. Also, heavy oil production depends on conventional oil production because heavy oil will not flow on its own through the TAPS pipeline. It must be blending with conventional oil, which is lighter.

• While it is easy to design a tax law that lowers taxes on new fields found outside the existing fields, it is devilishly complex to design a tax that lowers taxes on “new oil” produced in the existing fields, even heavy oil. This is the big problem the Senate Finance Committee wrestled with in the last session, and practical solutions were elusive.

The political arguments of the issue:

There are four arguments advanced against making the tax change. We present them here along with the counter-argument:

• Argument: Industry activity on the North Slope is not declining. Oil employment is high. This is true. However, most of the activity is related to maintenance of the oil production infrastructure and to the exploration activity of Repsol, a new company exploring the slope. The investment within the existing fields, where there is known undeveloped oil, remains stagnant. Oil production continues to decline, which is the most significant indicator.

• Argument: For years, under the old Economic Limit Factor tax, oil taxes on most fields of the slope were low, but investment was also low. Should this reenforce the belief that a tax reduction would not stimulate investment? We don’t think the situations can be compared. During much of the ELF tax era oil prices were low and at one point crashed to $8 per barrel. Also, the technology tools available now, like multi-lateral wells, were not available. Oil prices are now high, and the tools are available.

• Argument: A tax reduction may not translate into new investment and new production. Can there be a “guarantee?” There are ways to guarantee investments related to tax reduction – an investment tax credit does this – and Alaska arguably already has some of the most generous exploration investment tax credits in the world (as much as 75 percent of the costs of a exploration well can be paid for by the state directly). In theory, this concept could be extended to overall new production, but this gets very complicated (see discussion above, new oil vs. old oil). The simplest tax is usually best, so the most practical idea is simply to reduce the tax, assess the response over two to three years, and then, if new investment is not forthcoming, to increase the tax.

• Argument: Development of massive heavy oil resources and shale oil resources will “fill the pipeline” without a tax reduction. This is very doubtful. Heavy oil faces technical problems, as discussed previously, and it is unknown at this point where oil can technically or profitably be extracted from shale rocks on the North Slope. Great Bear Petroleum, an independent company, is working on this, but the company is quick to acknowledge that shale oil in Alaska is still a “science project.” Key tests remain.

The real argument against the tax change is that legislators don’t want to give up the money. This is the crux of it, although it is rarely voiced. In the previous Senate Majority key legislators did not want to give up any revenue to the industry and preferred to keep it coming to the treasury to support state programs, mainly capital budgets. There was an underlying belief that revenues will turn down inevitably because of the production decline, and that any tax reduction would not generate enough production fast enough to offset the reduction in revenues. It was a kind of “get it while we can,” approach to fiscal policy, but also it recognizes the potential cost to vital public services.

The counter-argument must acknowledge the validity of this. It does seem unlikely that industry would be able to develop enough new projects within existing fields, and fast enough, to offset the loss of revenue, which could range from $1 billion to $2 billion a year. Development of any new discoveries on the North Slope are off the table in any short-term discussion because they take years to develop and bring to production.

Advocates for tax reform argue that this has to be looked at in the long term. It seems intuitive that reducing taxes would spur investment and yield results eventually, and one way to look at this is like any other investment: One measures the risk, invests and hopes for a profit, but there are no guarantees. It seems intuitive that an economically healthy North Slope oil industry will eventually produce a lot of new oil, and since the viability of oil and gas production are linked (to be the subject of another report) it will lead to a gas pipeline as well. However, this is no ordinary “investment” because the risk of loss can have real effects on people. But again, there may be ways to mitigate this with intelligent use of the $15 billion in reserve funds as a hedge/bridge. – By Tim Bradner

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– BLM’s annual National Petroleum Reserve–Alaska lease sale Nov. 7 was a bit of a duster with only two independent companies submitting bids that totaled $898,900. It was no surprise, given that the prospective oil acreage along the coast was withheld from the sale. Woodstone Resources of Houston submitted bids along with Alaska-based NordAq Energy. Both NordAq and Woodstone participated in the state areawide sale held on the same day.

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– What was interesting about NordAq’s bidding was that the company picked up a block of leases in the northwest planning area, lands well inland and generally south of Barrow. This area is considered to be gas-prone but NordAq obviously saw something interesting. The company has put together an interesting group of prospects in the region. NordAq now has a sizeable acreage position in Smith Bay just offshore the federal reserve in very shallow state-owned waters. The company also purchased the federal leases held, and explored but then sold by FEX, the U.S. Talisman Energy subsidiary.

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– FEX made discoveries of both oil and gas on these leases but they were never tested. The company’s decision to sell was related to corporate decisions and not so much on the Alaska prospects. However, what NordAq now has is a string of prospects from Smith Bay extending into the northeast NPR–A (the FEX leases) and now inland into the central part of the reserve (the leases acquired Nov. 7). The company plans to drill the Smith Bay state acreage with an ice island, it says.

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– Interior Department officials are making it clear that there will be provisions for an east-west pipeline corridor through NPR–A for Shell and other companies working in the Chukchi Sea when the land management plan for the reserve is adopted later this year. What NordAq is hoping for is a north-south pipeline that would link any discoveries it might make to this pipeline, if it is built.

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– State’s lease sale draws interest

– The state of Alaska areawide lease sale also held Nov. netted $14.2 million in high bids for acreage in the central North Slope, state-owned Beaufort Sea submerged lands, and the foothills region of the southern North Slope. Interestingly, the foothills receive the first bids in several years, and from Anadarko Petroleum, which has been active in exploring for gas in the area. Anadarko picked up several leases near areas where Chevron was exploring several years ago.

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– Generally, companies bid to acquire leases adjacent to their existing leaseholdings, and several leases acquired by Repsol Nov. 7 were near the company’s “Kachemak” exploration well drilled last winter. This supports reports that the company is very encouraged by the well. Repsol also acquired one lease near where it drilled an offshore shallow water test last winter. Repsol is back drilling again this winter with plans to use three rigs. Essentially, the company wants to complete its evaluations of acreage acquired two years ago in a deal with Armstrong Oil and Gas. The evaluation was interrupted last winter when Repsol had a shallow-gas blowout on one of its wells. There were no injuries or damage from that, but it did disrupt and delay Repsol’s plans.

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– Great Bear Petroleum acquired additional leases in the Nov, 7 sale along the possible shale oil trend the company is exploring. This is encouraging because the company has been experiencing delays and various setbacks including higher-than-expected costs. Those are to be expected with a new venture such as shale oil. Great Bear drilled its first two exploration wells this year and is soon planning a long-term production test, the results of which are critical.

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– If there’s some really upbeat news for Alaska it’s that the state’s mining industry is ready to roll. Here’s some of the latest, from last week’s Alaska Miners Association convention in Anchorage:

– • Drilling results at a new deeper copper deposit found at Bornite in the western Brooks Range continue to show very high grades. That, plus the known resources at Bornite and the neaby Arctic deposit, could be reaching the critical threshold for development of mines. About 9 billion pound of copper ore and additional zinc resources have been identified, or now believed probable. This is good for NovaCopper and NANA Regional Corporation, on a joint-venture on Bornite and Arctic. Andover Resources is also finding new resources at its Sun project.

– • Access is the key to the region and the Alaska Industrial Development and Export Authority is looking at the idea of a public-private partnership similar to the Red Dog Mine road and port for a 200-mile access road that would connect with the Dalton Highway.

– • New ore reserves being added and other potential resources at the Pogo gold mine near Delta now give this mine an expected operaing life to 2030, and maybe beyond.

– • The Fort Knox gold mine near Fairbanks, now in its 16th year of production, is now planing a “Phase 8” expansion of its pit that would follow a Phase 7 expansion now underway. The heap leach ore process facility is also being expanded.

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– Heatherdale Resources is working on a plan to locate the ore processing mill for its planned Niblack multi-metals mine in Ketchikan, at a former mill industrial site on Gravina Island that has access via submarine cable to Ketchikan’s sources of hydroelectric power. Ore would be barged about 38 miles from the mine to the mill, which would employ about 65. Building the mill would take about 18 months, employing some 200 in construction. The schedule is for a pre-feasibility study to be done in the second quarter of 2013, with a decision on the project and permits applied for in 2015.

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– Niblack has copper, gold, zinc and silver and would be an underground mine very similar to Greens Creek Mine now producing on Admiralty Island. Niblack produced about 20,000 tons of ore from 1902 to 1908. Its modern era of exploration began in the 1970s when several companies looked at redeveloping the time. About $51 million was spent by companies doing exploration, and Heatherdale has spent an additional $37 million since it acquired the property.

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– Ucore says it plans to have its Preliminary Economic Assessment report on its Bokan Mountain rare earths mine out in late November. The mine is on southern Prince of Wales Island, near Ketchikan. Ucore plans an underground mine using a new process to sort tailings that will minimize waste, placing alll waste back underground in the mine. About 1,000 tons a day of ore would be mined with about 250 tons selected for processing. The schedule calls for its Feasibility Study, the next step to approval by the company, to be done in late 2013, with permit applications to follow. After permits are received construction would take about a year and a half. The mine would require about 6 megawatts of power, which is now planned to be generated with diesel. Ucore is discussing the import of liquefied natural gas, however, which could possibly cut energy costs by half, the company said.

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– By Tim Bradner

Alaska’s oil production is declining. Can exploration in the Outer Continental Shelf bail us out? It might.

But we’ve thought that before.

Exploration in the Outer Continental Shelf off Alaska’s Arctic shores holds the promise of large oil and gas discoveries, much larger than the modest prospects the industry sees onshore.

Oil from the OCS could indeed increase the flow through the Trans Alaska Pipeline System, it’s hoped, keeping that vital transportation system in business. Offshore development could also spawn a new offshore support industry for Alaska, creating thousands of jobs.

It’s an enticing prospect, and not far-fetched. But for Alaskans who have lived in the state for a few years, there is something vaguely familiar about it all.

It should be familiar. We’ve seen OCS exploration before in the Arctic and elsewhere off Alaska’s coasta, including, in the Arctic, drillships, icebreakers and oil spill response barges. Almost two decades ago there were extensive environmental surveys and studies of bowhead whales, including reactions of whales to drill ships, just like studies underway today. There were also companies planning OCS wells in the Chukchi Sea – Chevron and Texaco – that had to delay planned drilling because of government restrictions, again just like today. At that time, however, the problem was state of Alaska, not federal, restrictions on drilling that had been extended to the OCS.

Then, like now, it was Shell Oil that took the lead in both the Beaufort and Chukchi Seas, although other companies including Unocal, Sohio, Amoco and ARCO Alaska were active. There was activity across the Beaufort Sea. Chevron had partnered with Conoco on one prospect in the eastern Beaufort Sea and another in the western Beaufort. The company had asked exceptions to state prohibitions on drilling during the spring and fall whaling seasons, and also for certain changes to strict state oil spill requirements.

ARCO was active in the Arctic OCS waters, too, planning drilling for itself and Shell, Amoco and Unocal on the Fireweed prospect in the western Beaufort, off the National Petroleum Reserve, and in the eastern Beaufort where the company drilled its “Stinson” well near Camden Bay. Amoco was also active, with its “Gallahad” well in the eastern Beaufort.

There is a lot of the history in the Arctic OCS that is almost eerie in its similarity to the present: OCS lease sale 71 in the Beaufort Sea in1982 netted over $2 billion in bids by industry, with about half of this by one company, Sohio. Most of the money was spent to acquire rights on a large prospect over which there was great confidence.

In 2008 the Chukchi Sea OCS Sale 193 was to net $2.66 billion in high bids to the federal government, with Shell bidding the bulk of it. Shell’s objective was to regain leases on the Burger prospect, which it drilled in 1991 but then later relinquished the leases.

The Beaufort Sea prospect that enticed Sohio in 1982 was Mukluk, a large geological formation on OCS leases in Harrison Bay north of the Colville River delta on the North Slope. Unfortunately, in 1983 Sohio was to drill the most expensive dry hole in the history of the petroleum industry at Mukluk. Let’s hope the similiarities between Sohio and Mukluk and Shell and it’s drilling at its top prospect in the Chukchi Sea, Burger, don’t go that far.

There are reasons why Shell’s outcome is likely to be different than Sohio’s, mainly that new and advanced seismic technology is available, but seasoned oilmen say one never really knows until the drill bit penetrates the promising oil formation. For Shell that now won’t be until 2013.

Alaskans have actually seen a lot of OCS activity off all its coasts although most of it was years ago, and the companies that drilling read like a who’s who of the U.S. industry in those days. The most OCS leasing has been in the Beaufort Sea, with 10 lease sales held in the region since leasing there began in 1979.

The first Alaska OCS sale was in 1976 in the Gulf of Alaska, OCS Sale 39. Shell, Exxon,Texaco, Gulf Oil and ARCO drilled in the gulf in 1977 and 1978, and ARCO drilled again in 1983. There were OCS sales in other areas off southern and western Alaska coasts, and in the north, the Beaufort and Chukchi Seas.

There were also lease sales in OCS waters off the Bristol Bay region of southwest Alaska, which the government called the North Aleutian Shelf.

There were also sales in the remote Navarin Basin in the Bering Sea, about 250 miles from the Alaska coast, where Amoco drilled 5 wells, Exxon drilled two and ARCO drilled one. Following an OCS sale in Norton Sound near Nome, Exxon drilled 5 wells and ARCO drilled one test.

The results of all this drilling were not promising. Usually a handful of well won’t write off such large areas but the drilling was also very expensive. The end result is that the companies were not interested in pursuing further prospects in those areas, at least then.

The North Aleutian Shelf OCS area, off Bristol Bay is generally considered more prospective than the other OCS areas. Many geologists see the area as very similar in its geology to Cook Inlet, where many oil and gas discoveries have been made (but is still, in fact, considered underexplored).

Bristol Bay is also a major salmon fishery, however. When the lease sale was held there the fishing industry as well as the state of Alaska put up such opposition to leasing that the federal government cancelled and repurchased the leases. The sale has been proposed again from time to time on periodic federal leasing schedules (the Department of the Interior lays out a five-year OCS leasing schedule) but has always been postponed.

There was more drilling success in the Arctic OCS areas, in both the Beaufort and Chukchi Seas. Thirty four exploration wells were drilled and discoveries in the Beaufort and Shell led much of that exploration. One of Shell’s finds in the Beaufort was even developed, although that was in more recent years.

In that instance the well Shell drilled was called Seal Island. Amerada Hess Corp. drilled a well it called Northstar on the same formation, but on state-owned leases. This is now the Northstar field that was developed in 2001 and is now owned and produced by BP.

The field is about six miles offshore the Prudhoe Bay and straddles the boundary between state-owned and federal OCS submerged lands.

The Seal and Northstar wells resulted in a modest discovery that was too expensive to develop with technology of the 1980s. Both companies sold their leases several years later to BP, which employed new ideas in construction and renamed the field Northstar. Since part of Northstar lies on federal OCS leases the amount of Northstar’s production allocated to those leases is the first OCS production from Alaska waters.

Other companies were also drilling in the Beaufort Sea, and also finding oil. Unocal was an early leader in Arctic offshore drilling and drilled the first well with an artificial island in 1975 followed by a second island, and well, in 1976. Unocal later used a drillship on OCS leases near the Camden Bay area east of Prudhoe and found oil. The company named the discovery Hammerhead, but it was not large enough, and too far from shore, to develop. (Shell now plans to drill its adjacent Sivilliq prospect in 2013). ARCO Alaska drilled a well named Kuvlum in the same area and found oil. Again the discovery was not large enough to develop.

The very costly 1983 Mukluk dry hole at Harrison Bay was to put a chill on deepwater offshore OCS exploration in Alaska for many years. Low oil prices, which affected companies’ exploration budgets, didn’t help, but Mukluk cast a long shadow. The Alaska OCS, at least in deeper waters, had gained a reputation where industry explorationists proposed projects only at the peril of their careers.

Companies did continue on a more cautious path, however. They drilled prospects nearer shore that were not as exposed to the heavy, moving Arctic icepack, and where any discoveries could be reached with relatively short pipelines from shore. One of these, besides Seal Island, is Liberty, a discovery made in shallow offshore waters about five miles offshore and northeast of Prudhoe Bay. Liberty is protected from the heavy, moving offshore icepack by offshore natural barrier islands – there is only “shore-fast” stable ice that forms around the island – and is, interestingly, in a pocket of OCS lands like a doughnut hole more than three miles off the Alaska coast but also three miles from the offshore barrier island, which established a pocket of state-owned submerged lands.

Liberty is a confirmed oil find and BP has considered developing the field a number of ways including building an artificial gravel island connected to shore by a subsea buried pipeline, as the company did at Northstar, and also by drilling extended-reach horizontal production wells from shore. If that path were pursued the well would be record-setters in terms of lateral “reach” from the onshore drill rig, over eight miles. The Liberty development plan is not yet resolved, however.

Northstar, mentioned previously, was developed about 6 miles north of Prudhoe with an artificial gravel island built in about 40 feet of water, with a pipeline to shore. Unlike the Liberty location, which is east of Northstar and behind a string of offshore barrier islands, Northstar is exposed has no protection from the moving ice. Its design has withstood the forces of the ice as well as intense summer storm waves over more than 10 years, however. That proves the point that structures can be designed, with gravel in shallower waters and potentially concrete and steel in deeper waters, that can withstand ice.

Interestingly, as much as it chilled exploration in the deeper water Arctic OCS, Mukluk was actually a technical success in the sense that everything the geologists had predicted was there – the large geologic reservoir trap and a “cap” rock over the top, the sandstone rocks that had the right porosity and permeability for oil to flow, if it was there. Unfortunately the reservoir held water. The oil had once been there, but it had leaked out. In doing an analysis, geologists later concluded that the seismic surveys, which used the best technology available at the time, had missed a small hole in the top of the cap rock which ordinarily would have trapped the oil. It was enough to let the oil leak out, though. People have always wondered where the Mukluk oil went, because it did go somewhere.

Alaskans who remember Mukluk do wonder about the parallels with Shell’s current program, however. Huge amounts of money are similarly being spent and Shell is very optimistic, and seemingly very confident, about chances of success. There is always worry, however, that when the drill bits finally reach down the target depths in the Chukchi and Beaufort Seas the results won’t match expectations, and that the bad-luck cycle of the Alaskan OCS may begin once again.

One big reason why the outcome for Shell may be different this time. One is that, unlike Mukluk, Shell knows there is oil and gas in the Burger reservoir because Shell found it there when the company first drilled the prospect two decades ago.

Shell drilled three prospects in 1990 and 1991. One was Burger, its top prospect in 2012, and the others were Klondike and Popcorn. Klondike was actually completed in the summer of 1990 but only the “top holes” or upper parts of the wells on Burger and Popcorn and could be completed could be done that year before bad weather forced a halt to operations in mid-October. The wells were completed the next summer.

The well results were private but a subsequent analysis by the U.S. Minerals Management Service that was made public showed the well made a very substantial natural gas discovery with some indications of oil. Shell’s drillship on that earlier project was the Canmar drillship “Explorer 2.” It is this promising 1991 discovery that Shell is hoping to prove up in 2013, when it resume drilling in the Chukchi Sea. There are similar hopes for the Beaufort Sea, on the prospect there discovered in the 1980s.

These wells may usher in a whole new industry for Alaska, if they are successful. If not, it will be just another cycle for the OCS off Alaska’s shores.

Mike Bradner is publisher of Alaska Legislative Digest.

Here’s a quick recap of the problem:

So, what happens now?

Here are some of the key issues that the Senate Finance was wrestling with in the 2012 session:

The political arguments of the issue:

There are four arguments advanced against making the tax change. We present them here along with the counter-argument: