Alaskanomics

Is the sun shining a little brighter in Alaska’s oil patch?

By Tim Bradner

There is a little spring warmth, it seems, after a long winter. Several winters, in fact, of low oil prices and workforce cuts.

The job numbers have not yet ticked up and in fact they’re still slipping, though modestly now, after big cuts made in 2016 and 2017 as producing companies adjusted to the world of lower prices.

But prices are ticking up again. Even during the slump a number of new projects were being worked on and the brighter price outlook should cause some companies to push the green button on their projects.

It’s possible there could be enough new oil that the Trans-Alaska Pipeline System, now running at one quarter of its design capacity, could see an increase in oil throughput. But given that some projects could be delayed, not happen at all or meet expectations, it’s a safe bet there will be enough to maintain the current production for a decade or more.

This is significant because it wasn’t long ago that forecasters were predicting continued declines, to the point that the pipeline might be no longer economic in 10 years.

There’s other reasons for cautious optimism. One not widely recognized is that for the first time in years the Alaska Legislature wasn’t convulsed in acrimony over oil taxes. Some lawmakers did raise the tax issue, mainly to look at things not done in a big tax overhaul last year.

Despite that there was little appetite in most of the Democrat-led state House to revisit this issue, at least this year. The Republican-led Senate opposed this from the beginning.

But what’s also important is the Legislature’s action to use some Permanent Fund earnings to help finance the budget, and not turn to the oil companies once again, is a big shift.

This is a signal to new resource industry investors, whether in oil, minerals or fisheries, that if they’re lucky enough to develop profitable businesses after investing they won’t be heavily taxed the next time the state needs money.

Another underappreciated accomplishment of the Legislature this spring was in developing a solution, finally, to the festering sore of a billion dollars in unpaid oil tax credits to oil explorers, mostly small independents, who had been promised payment by the state.

One can argue whether the state’s oil tax credit investment program was a good idea. It involved state funds used to help fund exploration, but it did achieve its objectives in bringing new companies to Alaska and getting more wells drilled, and new discoveries made.

However, it was hugely expensive. In the end we just couldn’t afford it. But welching on commitments, even in our dire financial circumstances, became a black stain on Alaska’s reputation.

This spring the Legislature dealt with it with a plan proposed by Gov. Bill Walker to pay off the tax credit liabilities with bonds. Companies participating would accept a 10 percent discount in what they are paid, which is enough to cover the state’s costs of borrowing. State revenue commissioner Sheldon Fisher said this is a good deal for the companies because they get money right away rather than having to wait 10 years or so.

A feature of this is companies can get a lower discount, down to 5 percent, if they put the money to work in their Alaska projects within 24 months. Sheldon Fisher estimates this could result in over $700 million in new capital being deployed to restart projects stalled when the tax credits couldn’t be paid.

The companies can also get the lower discount by agreeing to a higher royalty on their state oil and gas leases, but state officials believe most will opt to put their money back to work in Alaska. If this plan works – there is a court challenge from an individual that must be dealt with – the stain on our financial reputation will be removed.

Added up, this paints a nice picture. We’re getting our financial house in order, and oil prices are up.

But things are still fragile. What’s causing the oil price rise is the agreement between OPEC and Russia to restrain production as well as continued Middle East tension. This could change quickly. Also, those prolific U.S shale oil producers will respond to higher prices, putting new oil on the market.

We haven’t closed the state fiscal gap, the difference between revenues and spending, although it is narrower. Even with this year’s financial restructuring a $700 million deficit remains for the next fiscal year, which begins July 1.

There are also upward pressures on the state budget that seem uncontrollable. Rising health costs, a problem almost intractable, along with rising costs in prisons and higher pension expenses combine to push the budget up. If the oil price rise sticks and oil production remains stable we could have more revenue, which would help this. But one should never try to predict oil prices.

The plan to use part of the Permanent Fund earnings has risks, too. A few bad years in financial markets could bring the wolf back to the door. The Legislature may be tempted to draw more than is prudent from Permanent Fund earnings.

We can’t even count on all those new oil projects. Most of these haven’t been sanctioned, or formally approved, by their developers. Some of the discoveries that seem very promising need more wells drilled to confirm the oil is really there, and some of these might not pan out. Even if companies move to develop new discoveries there could be unexpected technical problems in reservoirs that could impede production. It’s happened before on the North Slope and in Cook Inlet, more than once in fact.

Summing up, things are still fragile and there are reasons to be cautious. Still, there’s also lot of progress and a lot to be pleased with.

A little sunshine feels nice.

Tim Bradner is co-publisher of the Alaska Legislative Digest and the 2018 Visiting Atwood Professor of Journalism at University of Alaska Anchorage

China Deal Renews Hope for Alaska LNG Line but Hurdles Remain

By Tim Bradner

Alaskans have chased the will-o'-wisp of a North Slope gas pipeline for decades. Several times the prize seemed within our grasp only to slip away, usually because of some unexpected, and adverse, market development. In recent years, the technical prowess and success of U.S. shale gas developers led to a domestic gas supply glut and plummeting prices, ending hopes for an all-land gas pipeline to the Lower 48 states.

Even more recently, a crash of crude oil prices and with it prices for liquefied natural gas, or LNG, has ended an industry-led initiative to build a pipeline and large LNG export project. The state of Alaska, which had been a partner with industry in that, moved to pick up the pieces and keep the LNG project alive, with the state-owned Alaska Gasline Development Corp., or AGDC, leading the effort.

For a period of time the state’s quest seemed quixotic, with a small, untested state agency attempting to develop a $43 billion project amid a worldwide glut of LNG and a host of competitors who are planning big export projects without the burden of having to build an 800-mile pipeline across Alaska.

China deal a game-changer?
Seemingly against the odds, Gov. Bill Walker may have pulled off a coup, landing a potential huge customer, and financier and investor, in Chinese energy company Sinopec, Bank of China and China Investment Corp., that nation’s sovereign wealth fund.

The governor and the AGDC team engineered a deal signed Nov. 9 in Beijing, with U.S. President Donald Trump and China’s president Xi Jiang looking on, for Sinopec to negotiate for 75 percent of the Alaska LNG Project’s 20-million-tons per year of LNG capacity, in which Bank of China would provide financing for the 75 percent project debt and China Investment Corp. an investment in the equity part, planned now at 25 percent.

The underlying concept of the state’s plan, which the North Slope producers say they support, is that while the project does not clear the “hurdle rate” for investment by the large producing companies, it is possible that there are other investors, such as national sovereign wealth funds, interested in long-term infrastructure holdings. These investors would be willing to accept a lower rate of return than would the oil companies, according to this idea. This, combined with possible tax-exempt status of any part of the project actually owned by the state, improves the economics of Alaska LNG Project, it is argued.

There are still doubts among Alaskans, and observations that the “Joint Development Agreement” signed Nov. 9 is non-binding and similar to the several “Memorandums of Understanding” signed previously with potential buyers including Korea Gas Corp. and, most recently, Tokyo Gas Corp. Like the MOUs, the joint development agreements simply set the ground rules for further talks.

Governor Walker argues that the high profile given this agreement, which is seen to be supported by the top U.S. and Chinese political leaders, gives this deal a good chance of actually happening.

Independent observers who are experienced in Asia energy markets, like former ARCO Alaska president and state natural resources commissioner Harold Heinze, gives high marks to the signing. China has a huge need for clean-burning gas and an ability to pay for it, Heinze told me, and Sinopec and the two China financial entities are large and experienced. “This is the dream team,” among potential customers and investors, he said.

Huge uncertainties remain
There are still huge uncertainties, however. In his telephone press conference with Alaska reporters on Nov. 9 Gov. Walker acknowledged that this is not a done deal, and a lot of work remains to be done. The target is for the roles of respective parties to be agreed by May and a final agreement by the end of 2018, but this is a huge, complex undertaking and the December goal may prove ambitious.

The governor also said he hopes for a final investment decision by the end of the first quarter of 2019 (the “FID” is what will trigger procurement and a start of construction) but that seems unrealistic because final engineering on the project cannot be done in such a short timeframe.

When it led the project, ExxonMobil said the final engineering could take one and a half to two years and could cost $1 billion to $2 billion. After it took over the project, AGDC said there might be ways the final engineering could be speeded, and done for less, because the preliminary engineering done by the industry/state consortium was very detailed and to the point that some of it could be considered part of the final design.

Still, the remark raised concerns among some industry professionals who worry about AGDC attempting to hurry the project to meet artificial deadlines. There is ample experience with large industry projects that hurried work at the beginning can lead to mistakes and cost overruns. Chevron Corp.’s Gorgon LNG project in Australia, which suffered huge cost overruns, is cited as an example of inadequate front-end planning, senior Chevron officials have acknowledged. Alaska had its own experience with the Trans Alaska Pipeline System in the 1970s, which was hurried mainly for national security reasons. Luckily for TAPS the margins enjoyed in oil production were enough to absorb the cost increase. Margins in gas production will be much narrower, however. There is less room for mistakes.

Small Alaska labor pool
One reason why there is a concern for cost control is that the Alaska skilled labor market is very small compared with the needs of this large project, which means most of the project workforce will have to be imported from outside Alaska, mainly from the Lower 48 states. Although Chinese investors and customers will push for Chinese “content” in construction, this is most likely in materials and equipment, and some engineering services.

There would be skilled Chinese labor among the professional technicians and engineering staff, but the bulk of the rank-and-file labor would be U.S. particularly if there are project labor agreements, which will almost certainly be the case. However, the labor demand could result in some upward push on wage rates and benefits in Alaska, which happened during TAPS construction. This could lead to higher project costs (labor scarcity was also a factor in Gorgon’s overruns).

Construction management
Finally, there are concerns over the project construction management. The state gas corporation, AGDC, aspires to grow to meet this demand and would in any event rely on experienced contractors. However, Sinopec would also play a role and while this company is very experienced in large energy projects it has not built a large project in the U.S. nor in the Arctic and is therefore unfamiliar with Arctic conditions as well as U.S. labor and environmental rules, all of which could create some problems in management of the project. Harold Heinze believes this could be mitigated if North Slope producers, who are experienced and familiar with the Arctic, are somehow involved in the project management. Just how to do this is unclear if these companies are not also equity owners.

Can the project withstand competition?
There is no doubt that there is formidable competition among world LNG suppliers for any market opening in Asia, and that the need to build the 800-mile pipeline is a disadvantage for Alaska. The most serious competitors are the new shale gas export plants on the U.S. gulf coast, who can tie into existing pipelines and access gas from the large domestic supply, which is now very inexpensive. Gulf coast LNG suppliers will be able to land their product in Asia for about $9 per million British Thermal Units (mmBtu is the international energy unit used in international energy transactions, and it is equal approximately to the U.S. standard unit, one thousand cubic feet, or mmcf).

AGDC argues that the disadvantages of the pipeline are overcome by the shorter shipping distance from Alaska to Asia, which is about one-third the distance from the U.S. gulf and with no Panama Canal transit fee. Alaska has the advantage, however, of an assured gas reserve that could be made available at a long-term price that can be locked in by contract, compared with gulf coast competitors who are subject to variations in U.S. domestic gas prices. These are low now but they were very high in recent years. The potential for more stable pricing was mentioned by China Investment Corp., one of the potential investors, in its statement when the agreement was signed Nov. 9. While the North Slope gas producers would negotiate their own gas sales agreements they would no doubt see the advantages of this approach, but the state itself owns about one-fourth of the North Slope gas as its royalty and tax share of production and is in a key position to influence commercial terms.

AGDC foresees possible $1/mmBtu “netback” gas value
On a straightforward comparison AGDC feels it can land Alaska LNG in Asia for a price equal to or below U.S. gulf competitors, or $9 per mmBtu, mainly because of the shorter shipping. However, after the expenses of the pipeline and LNG shipping are paid from a hypothetical $9 per mmBtu sales price, the “netback” value of the gas on the North Slope would be about $1 per mmBtu for the gas supplied by the producers and the state. Whether this is enough for the producers is unknown but this must be weighed against what alternatives there might be for the gas, which are few.

A $1 per mmBtu price would translate to $1 billion per year paid for the gas, of which the state share would be $250 million per year, or one fourth. AGDC points out that this would increase substantially for the state and producers once the debt on the project infrastructure is paid, which is estimated at 25 years. After that is paid the payments for gas would be several billion dollars a year, AGDC has said in briefings. At that point, once the infrastructure is paid for, the Alaska LNG Project will be very competitive against international competition. When this is combined with the large “upside” potential for new gas discoveries – geologists estimate as much as 100 trillion cubic feet of conventional gas could be discovered once gas exploration begins – the Alaska project is very attractive. The 35 trillion cubic feet (tcf) of proven gas reserves occurred as a byproduct of oil exploration and discovery.

What could go wrong?
There are still challenges. One is still the risk of cost overruns and the problems of managing construction of such a large project. One issue that will have to be resolved early in the commercial negotiation is who carries the risk of non-completion or a delay, or added costs, the China partner or Alaska? Secondly, where will the 25 percent equity investment come from? The assumption is that China Investment Corp. would make an equity investment but AGDC has said that Alaska will maintain “control,” presumably 51 percent of the equity. If the 25 percent equity requires $10 billion, what Alaskan entity would invest 5 billion? AGDC? If so, could that agency issue revenue bonds to raise funds (it has bond authority)? Would bond buyers require the Permanent Fund or, more likely, some of its earnings, to guarantee the bonds?

There is also the danger that China itself may switch course. Alaska’s LNG project is not the only place where Chinese energy companies and banks are investing. They are in projects on the U.S. gulf, Australia and most recently in Russia’s Yamal LNG project, which will soon be shipping LNG to Asia and Europe through Arctic waters.

Since China’s big energy companies and banks are basically under government direction, if one of these projects looks more attractive than Alaska, and if Alaska LNG appears to have more risk, it’s plausible that China could change course. Alaska is still not insulated from competition.

Tim Bradner is co-publisher of the Alaska Economic Report and Alaska Legislative Digest

What's Next for Alaska's Natural Gas Supply?

By Tim Bradner

After years of effort and hundreds of millions of dollars spent, are we any closer to getting a North Slope natural gas pipeline? A number of people are asking whether it’s worth continuing the effort including state legislators who have to pay the bills for work that is continuing.

Even Gov. Bill Walker, the project’s chief booster, acknowledged that if firm customers for the Alaska LNG Project don’t appear soon the time may be at hand to investigate alternatives for using the large “stranded” gas resources on the North Slope.

Alaska LNG is a $40 billion-plus proposal that would build an 800-mile, 42-inch pipeline from the North Slope to a large LNG plant at Nikiski, near Kenai, and a large gas treatment plant on the slope.

The state-owned Alaska Gasline Development Corp.(ADGC), which is now leading the project, did recently receive responses from two North Slope producers following a solicitation for capacity in Alaska LNG, but those are not binding and the details of volumes of gas proposed to be shipped by the producers are confidential.

Significantly, there was no proposal from the third producer company, but the state’s AGDC did reserve capacity for itself to make this available for the third company.

AGDC would not say which two of the three producers, BP, ConocoPhillips or ExxonMobil, submitted proposals and which did not.

Meanwhile, LNG markets conditions in Asia continue to be dismal. Prices are at about half of what is needed to make the Alaska LNG Project work, and there is a lot of surplus LNG in the market. Also, a lot of competing LNG project builders are waiting in the wings who are near tidewater and don’t have to build an 800-mile pipeline.

Is it time to close the books? Maybe, maybe not. The flip side of this is that Alaska LNG has strategic advantages over competitors that are real – a large, confirmed gas supply, a closer sailing distance, and security of supply with LNG from the U.S. These shouldn’t be lost. 

The investment to date shouldn’t be wasted. There is at least $750 million spent to date in this latest effort including $600 million spent through to complete preliminary engineering and regulatory work and $150 million previously by the three slope producers on conceptual planning.

Many argue the state should continue to patiently work toward the time when the market will improve. AGDC, for its part, sees this happening in the early to mid-2020’s when existing LNG contracts will expire and buyers will sign for new purchases.

If it is positioned properly, Alaska has a good chance of landing some of those contracts, but to do that AGDC must have its engineering done and permits in hand. This is a very long-term game.

However, it is also prudent to now look at alternatives. One of these, the governor himself acknowledged, is the notion of direct-shipping of LNG from Prudhoe Bay, which may be feasible with the Arctic Ocean opening up. Russia is now shipping LNG by sea from its Yamal LNG project, which is in the Arctic.

One problem with an Alaska version of this is that coastal waters of the Beaufort Sea are very shallow, which means an offshore LNG loading terminal will have to be several miles offshore, a huge expense. However, there is already one artificial gravel island facility built offshore Prudhoe Bay – Hilcorp’s Northstar oil field production site – which gets out to the 40-foot depth. This would ease the problem.

The more difficult challenge is that while the Arctic icepack is lessening there is still a lot of ice around and summer storms can cause it to move in quickly on the coast, an impediment to navigation. This is less of a problem along Russia’s Northern Sea Route, where the Yamal LNG tankers now operate, but a hazard in the Alaska Beaufort Sea. The commercial problem this presents is that LNG buyers put a high priority on certainty and reliability, which works to Alaska’s disadvantage.

Another alternative, more possible in the near term, is gas-to-liquids, or GTL, which involves a chemical process converting methane, the main component of natural gas, to liquid synthetic crude oil and even finished products like diesel and gasoline.

Commercial-scale gas-to-liquids plants now operate in Malaysia, the Persian Gulf and South Africa. Shell’s plant at Bintulu, in Malaysia, makes petrochemical products that are highly profitable.

While constructing one of these plants on the North Slope presents challenges – nothing is easy or cheap on the slope – the flexibility of this technology offers advantages. Harold Heinze, a former ARCO Alaska president and state resources commissioner, believes such a plant could make specialized “designer” liquids that could have a wide variety of applications on the slope.

New improvements in GTL also allow for smaller scale plants to be viable (traditionally GTL plants have had to be very large) which would lower the front-end costs and risks, and allow the plant to be expanded over time.

Richard Peterson, whose Anchorage-based Alaska Natural Gas-to-Liquids LLC, has done extensive work on the idea of a slope GTL plant and points out that the synthetic crude oil that would be produced could add several hundred thousand barrels per day of new volume through the Tran Alaska Pipeline System (TAPS).

More important, synthetic crude would have the effect of raising the value of the entire stream of oil moving through TAPS because of the quality and value of the GTL fluids.

Most important, however, increasing the flow of oil though TAPS would lower the cost of moving all of the oil, benefitting the existing oil producers and fetching a higher value for the state with its royalty oil.

In reality, both LNG and GTL could be pursued because there’s enough gas on the slope for both. AGDC has also spoken of the possibility of starting its LNG project at a smaller scale and expanding as the market develops.

A sensible approach would be to pursue both LNG and GTL, start both smaller and grow them, one putting more fluids into TAPS and the other delivering gas to export markets and, most important, Alaska communities.

There are 35 trillion cubic feet of confirmed gas reserves just in two fields on the slope, Prudhoe Bay and Point Thomson. Federal and state geologists believe there could be as much as 100 tcf of conventional gas that would be explored and discovered once a customer for the gas is in place. There should actual be two customers, an LNG along with a GTL project.

Tim Bradner is co-publisher of the Alaska Legislative Digest and Alaska Economic Report

Legislative Budget Update

By Tim Bradner

As the Legislature grapples with huge shortfalls in state revenues – the deficit for this fiscal year is estimated at $2.5 billion – there’s talk of new state taxes, which is causing discomfort among many. Never mind that citizens pay virtually no state taxes in Alaska and even get an annual check from the state.

Angst over this has caused extended sessions of the Legislature for two years now. Lines of disagreement are pretty clear and, just like in Washington, D.C., pretty partisan.

Democrats, who control the state House, are arguing that we’ve cut state spending enough, that levels of public services are now at bare bones, and that it’s time to raise revenues. They are pushing for reimposition of a state personal income tax (Alaska had one years ago) and for higher taxes on oil producers.

Republicans, who control the state Senate, say there’s more room to cut spending and we shouldn’t impose new taxes when the state’s economy is down.

Senators agree that taxes on citizens may be eventually needed but now is not the time. Meanwhile, hitting the oil industry with new taxes, with oil prices at half what they were two years ago, seems unwise, Senate leaders say.

The feelings are intense over these disagreements in the state capitol and we’re unlikely to solve the problem this year, to get a long-term fiscal solution in place. That punts the issue to next year and 2018 is an election year, so it seems unlikely much will happen that soon.

Paralysis in the state capital? Politicians unable to negotiate tough decisions? That looks pretty familiar, actually, considering that Illinois went without a budget for three years and New Jersey actually had a state government shutdown, although it was brief.

But our state isn’t really running out of money with $60 billion in the Permanent Fund, and since we’re still sending out Permanent Fund Dividend checks claims of a fiscal crisis look pretty silly when viewed from the Lower 48.

Still, we have drawn down on savings to fund several years of multi-billion-dollar deficits. In fact, we’ve taken $11.3 billion from two ready asset savings funds over the last four years, the Constitutional Budget Reserve and the Statutory Budget Reserve.

At the end of this state budget year next June 30 the Constitutional Budget Reserve could be down to about $2.2 billion (the Statutory Budget Reserve is essentially depleted. Without a change to the state fiscal system, that’s not enough to fund the following year’s budget, FY 2019.

We have to change the system because it’s obvious oil can’t pull this train any longer. In fact, oil prices have dropped again.

But while we haven’t made much progress toward a final solution it’s worth reflecting that, in fact, things are moving in the right direction.

We’ve cut spending, hugely. Our annual spend of state undesignated general fund dollars, the most common way of looking at the budget, is about half of what it was four years ago, in Fiscal Year 2013.

We’ve also largely agreed that we should use some of the Permanent Fund’s annual income, about $3 billion in a typical year, to help fund the state budget. We created the Permanent Fund in 1976, many believe, to help pay for public services when oil revenue winds down. That time has come, after 41 years.

We’ve also agreed, in principle, that the Permanent Fund dividend should be limited through a new formula, so that some of that money could be used for public services. There’s still some disagreement on this – Democrats argue it should be coupled with an oil tax increase – but the fact that most legislators sign off on lowering the dividend is a huge accomplishment.

All this is still a work in progress, however. The structural changes, mainly a framework for using the Permanent Fund income (changing its management so it functions more like an endowment) and the trimming of the dividend, has passed both the state House and Senate in different forms, but they have not yet been finally agreed on. The oil tax question, which is still part of the debate, is not resolved, either.

But even if legislators left these things hanging until 2018 (more likely 2019) we are moving toward a solution. Political bodies move slowly in making major decisions and sometimes it takes three years or more for people to really get their arms around a problem and do something.

I recall that it took three years for the state to make a major change in its state oil and gas tax structure (work started in 2010, it was finally done in 2013) after a huge amount of debate, and even then the question had to be ratified by voters through defeat of a citizen initiative to overturn the Legislature’s action.

An initiative may happen again, with at least the Permanent Fund Dividend part of the proposed fiscal change. Plans are already being laid for a ballot initiative to overturn a trimming of the dividend, if it happens.

Even if these structural changes are made we still have a budget problem, although it is not as serious. These changes would bring about $1.8 billion in new revenues to the state general fund for the budget (they would, separately, fund about $750 million for a trimmed-down citizen dividend). If we assume about $1.5 billion in typical state revenues, from oil and other sources, total revenue would be about $3.3 billion.

That’s still $800 million short of funding a $4.1 billion budget (undesignated general funds), which is where the debate on new taxes comes in. The House Democrats’ proposed income tax would bring in about $700 million a year and an increase in state fuel taxes proposed by Gov. Bill Walker would bring in about $70 million a year.

That solves the math part of the problem. However, Republicans in the Senate and House still say we can wait on the income tax part, meanwhile enacting other parts of the plan, and draw a bit more from savings. The draw would be substantially less because there are new revenues for the budget from Permanent Fund earnings. If those continue to grow, which is likely, the remaining gap may be taken care of in a few years, senators argue.

Democrats’ response to this is that the Senate plan assumes flat funding of the operating budget and no real money for state-funded construction in the capital budget, or for addressing a $1.8 billion backlog of deferred maintenance on university and other state buildings.

Democrats say we should get with this and do new taxes now if we’ll need them eventually. Republicans say not yet, that we can wait longer. And so it goes. 

Tim Bradner is the editor of the Alaska Economic Report and co-publisher of the Alaska Legislative Digest

State Will Pursue Revised Rules for NPR-A with Interior Dept.

By Tim Bradner, for the Alaska Journal of Commerce

State officials will push new U.S. Interior Secretary Ryan Zinke for a revamp of Obama administration rules restricting oil and gas development in the National Petroleum Reserve-Alaska, state Natural Resources Commissioner Andy Mack said May 12.

“We will be submitting a specific proposal within the next couple of weeks to Secretary Zinke. This grows out of meetings our governor, Bill Walker, had with the secretary earlier this year in which he seemed receptive,” Mack said in an interview.

“We believe we can help BLM (Bureau of Land Management) in developing a new plan that is balanced,” between resource development and environmental protection, said Mack, who was officially confirmed to his position May 16.

The NPR-A was created in 1923 as a potential source of oil for the U.S. Navy, but despite exploration over the years it is only recently that there have been commercial oil and gas discoveries.

The U.S. Bureau of Land Management, which manages the 23-million-acre petroleum reserve on the western North Slope, would develop the new plan, but Mack said the state hopes to be heavily involved.

BLM’s current management plan, developed under former Interior Secretary Ken Salazar, was implemented in 2013 and placed large parts of the reserve into special conservation areas, effectively putting large areas off-limits to petroleum exploration and development.

The current plan also makes access difficult for transportation infrastructure, such as pipelines or roads for use by communities in the region, state officials have said in the past.

Salazar’s final Record of Decision approving BLM’s plan placed 11 million acres, about half of the reserve, into special conservation areas. This included a 3.6-million-acre special protected area around Teshekpuk Lake and including coastal wetlands near the Beaufort Sea coast.

State officials were critical of the plan because NPR-A’s coastal areas are considered highly prospective for petroleum discoveries. The Barrow Arch, a broad regional geologic formation that hosted the large Prudhoe Bay-area oil discoveries farther east, also extends along the coast of the northeast NPR-A and includes areas Salazar put off limits.

Mack said the restricted areas also impede infrastructure needed to support discoveries on state-owned submerged lands offshore the reserve.

Caelus Energy, a Dallas-based independent, has announced a significant discovery at Smith Bay, offshore the NPR-A and about 100 miles northwest of the nearest industry infrastructure at the Alpine field.

If Caelus is unable to build an onshore pipeline from Smith Bay through coastal areas of the reserve it will be forced to build an offshore pipeline, which creates risks and environmental hazards.

The prospectivity of NPR-A itself for discoveries has now been confirmed by ConocoPhillips and its minority partner, Anadarko Petroleum, who are making discoveries further inland in the reserve.

The companies are now developing one project, Greater Mooses Tooth No. 1, or GMT-1, which is scheduled to start production in late 2018, and have two other prospects, GMT-2 and Willow, a new discovery, in the planning stages.

Any new initiative to unwind restrictions will be highly controversial with national environmental groups, particularly if it eases restrictions in the Teshepuk Lake and coastal wetlands areas of the reserve that are heavily used by migrating waterfowl in the summer.

It would also require a redo of the environmental impact statement for the current NPR-A management plan, which is also likely to spark litigation from conservation groups.

However, what is also different now, Mack said, is that Inupiat communities on the North Slope, now mainly dependent on air and seasonal barge service, are supporting provisions for transportation infrastructure in the NPR-A as a way to bring living costs down.

In other remarks, Mack said in a May 12 briefing that he believes recent new discoveries on the North Slope will continue to prop up North Slope production. The commissioner spoke to Commonwealth North, an Anchorage-based business and public policy group.

“The recent increase in oil production can almost entirely be attributed to the strong performance at CD-5,” a new project near the Alpine field developed by ConocoPhillips and Anadarko Petroleum, Mack said. Strong production at Prudhoe Bay and the Kuparuk River field, which supply most North Slope oil production, were also factors.

The state Department of Natural Resources is now forecasting a 4 percent drop in North Slope crude oil production next year to an average of 505,000 barrels per day. The new estimate revises a number published April 14 in an earlier forecast, that reflected a sharp drop to 445,000 barrels of average slope output, a 12 percent decline which alarmed state legislators working on state budgets.

Ed King, a petroleum economist and the Department of Natural Resource liaison with the Legislature, said the agency adjusted figures in the earlier number to account for new production.

“New information has come in since the production estimates were prepared several months ago. When we assembled the forecast certain new projects were not included but those are included in the revision," King said.

The forecast period is for state fiscal year 2018, which begins July 1 and extends to June 30, 2018.

The department is also estimating an increase in Cook Inlet oil production in fiscal year 2018 to an average of 17,400 barrels per day, up from a 14,900 barrels per day average for this year, fiscal year 2017.

King cautioned that North Slope production estimates could still vary, depending on the success of producers in the large Prudhoe Bay and Kuparuk River fields holding production even, as they did in 2016, King said.

The two fields provide the bulk of North Slope production and have historically declined at about 5 percent yearly. However, field operators BP, at Prudhoe Bay, and ConocoPhillips, at Kuparuk River, managed to largely stem the declines last year.

BP held production at less than a 1 percent decline at Prudhoe even after cutting its drill rigs from five to two. King said it's uncertain that performance will be repeated in 2017 with fewer rigs at work.

In the Kuparuk River, field production was roughly even with 2015 with the decline largely offset by production from the new Drill Site 2S. CD-5, a nearby production site, also contributed new production, King said.

No new projects are expected in 2017 that will provide a similar offset to decline. However, new production projects now in construction on the Slope will begin production late 2018 and help stem decline in 2019.

These include ConocoPhillips' new Greater Mooses Tooth No. 1 project in the National Petroleum Reserve-Alaska, with an expected output of 30,000 barrels per day, and Hilcorp Energy's new Moose Pad project in the Milne Point field, with an expected output of 12,000 to 18,000 barrels per day.

The state spring forecast also revised a production estimate for current-year fiscal year 2017 production to an average of 523,700 barrels per day, a second straight year of increases and far greater than the 495,000 barrels per day that was projected this past December.

This includes greater output from the Prudhoe Bay than state officials expected earlier as well as more production from CD-5.

While the near-term outlook is for level production in Alaska, or a minor decline, the medium-term, to 2022, is more uncertain because low oil prices have delayed some projects that were expected to come on line in that period, according to Paul Decker, chief of resource evaluation group in the state Division of Oil and Gas.

Those include Caelus Energy's Nuna project, which could produce 25,000 barrels per day, and Mustang, a small project planned by Brooks Range Petroleum, which will be able to produce 12,000 barrels per day to 15,000 barrels per day. Both are on hold and are unlikely to be put into production before 2022.

However, prospects are brighter for the long-term beyond 2022, Decker said, although this may depend on some improvement in oil prices. Armstrong Oil and Gas and Repsol are engaged with regulators on approvals of the Pikka project, which will be capable of producing 120,000 barrels per day, and ConocoPhillips has its GMT-2 in the NPR-A, which could produce 25,000 to 30,000 barrels per day, the company has said.

King said both of those projects are at least five or six years out.

Further out in the queue is Willow, a new ConocoPhillips discovery in NPR-A, that could be capable of 100,000 barrels per day, and Caelus Energy's discovery at Smith Bay, in state-owned offshore waters north of the NPR-A, the company believes might produce 200,000 barrels per day.

Tim Bradner is co-publisher of Alaska Legislative Digest and a contributor to the Journal of Commerce. He can be reached at [email protected].

Oil Tax Credits Must Be Targeted, Affordable

As seen in the Alaska Dispatch News on May 9, 2017

Written by Tim Bradner

Legislators in Juneau are closing out at least one chapter in a very creative, but also expensive, incentive program to stimulate new oil and gas development.

The state's oil and gas tax credit program has existed for years. I will argue that it has achieved its goals of getting more companies exploring, more wells drilled and more oil and gas discovered. But it also grew, piecemeal, into something so top-heavy and complex it just couldn't be sustained, particularly after state revenues imploded in late 2015.

A sore point for legislators was the state's purchase of tax credits for cash from small independent companies who are explorers and developers.

Most of the heavy-lift in winding this down was done last year by the Legislature in a phase out of most tax credits, with most gone in 2019.

This year lawmakers are working to finish things left undone last year, but they're also trying to preserve some of the incentives in ways that don't, like the cash purchases, directly hit the state budget.

Of course, the oil tax bill now before legislators does more than phase out tax credits. It also increases taxes. Whether we want to really do that when our industry and services companies are struggling is another conversation.

Back to the tax credits: Critics have called these subsidies but I think they should be considered investments with the state helping share risks in return for more oil and more revenue, though there are no guarantees.

There's nothing new about this. The state has done it for decades, beginning soon after statehood with a generous royalty break for new discoveries which stayed on the books for many years.

Over the decades we've had many forms of tax and royalty incentives, most to help small, economically-challenged new fields but also incentives for companies who were just exploring.

Governments do this all this time. Across the nation tax breaks are offered to woo new investment. In Alaska the Kenai Peninsula Borough did it in the late 1960s to help get a liquefied natural gas plant and ammonia plants built near Kenai. Anchorage did it in the late 1980s to get the air cargo hubs built at Ted Stevens International Airport.

Incentives can be abused, of course. They have to be thought out and administered carefully. The trick is to design them to really accomplish what's intended and for the sponsoring community to get something back, ideally in results that are measurable and transparent.

I believe our oil and gas incentives have had mixed but mostly good results, using these yardsticks. Just a few years ago there were only a handful of large oil and gas companies operating in Alaska and very little exploration with the exception of ConocoPhillips on the North Slope. The incentives helped bring in a number of aggressive new companies, mostly experienced independents.

Thanks to them fears of a gas shortage in Southcentral are in the past. On the Slope, the list of recent new discoveries could, potentially, increase the amount of oil moving through the Trans-Alaska Pipeline System to a million barrels a day, twice what it is now. Clearly, we're doing something right.

However, it has been at a substantial cost to the state treasury. While we note the successes it's important for legislators to do due diligence and ask questions. One is whether these developments might have happened without the incentives. Some might have. The companies are quick to acknowledge that what really brings them to Alaska is geologic prospectivity, or good rocks, although the tax credits help and result in getting more work done more quickly.

A core dilemma in all incentives is whether investment would have occurred anyway, but in most cases this is unknowable. Government officials in charge of these programs, and elected officials approving the framework, just have to make the judgment call.

However, what is always a good idea is for incentives to be targeted to achieve certain goals, for example enticing exploration in large, unexplored Interior Alaska sedimentary basins, or exploring for new gas in Cook Inlet to meet local utilities' needs, or deep oil in the Inlet or technically-challenged oil deposits on the North Slope.

The unexplored Interior basins offer an example where incentives are clearly helping get exploration done, in this case by Alaska Native corporations like Doyon Ltd. and Ahtna Corp., which are investing their own money in exploring, interestingly, state-owned lands. These are areas where few oil and gas companies have been willing to spend money.

There are a lot of ways incentives can be structured, too. We do have options, even tools that are unused, as we wind down our current program.

Arguably, incentives work best if they are automatic if certain criteria are met. There's no subjective judgment by a state bureaucrat, in other words. An explorer can then have confidence that the incentive will come, as long as criteria are met, and on that basis financial planning can be done.

Another way to offer incentives, however, is through negotiation, which does involve judgment. This is a procedure that may be cumbersome as a part of tax policy but more workable, and in fact required, as a part of modification of state royalty. This approach can provide for assured outcomes, such as certainty that development will occur. This works best after a discovery is made and we do it now through modifications of royalty for discoveries that appear to be economically marginal.

Another form of this, designed for explorers, is our state exploration licensing program. This allows a company to negotiate an exploration contract for a block of state lands without having to tie up money in up-front bidding, instead spending the money on exploration. If a discovery is made this is converted to conventional state leases. The key is that a commitment to invest, and to drill, is achieved.

The state can assist in other ways. Low-cost loans and even equity participation can be done. Equity investment is another option. The Alaska Industrial Development and Export Authority, the state development corporation, has already participated in at least three oil and gas projects, two through equity and one in a loan.

The prime example of participation was our state's partnership with North Slope producers in pursuing a large natural gas pipeline project.

Ironically, we're already a partner with industry through our royalty interest in state oil and gas leases. We own one-eighth to one-sixth of the oil and gas through the royalty share.

No matter how we may feel about joint-venturing with Big Oil, we're already doing it.

Are there creative blends of these ideas that could preserve some incentives without breaking the bank? I believe there are, but surprisingly I haven't seen much discussion of alternatives despite all the angst over tax credits. I believe it's time for that to happen.

Tim Bradner is co-publisher of the Alaska Legislative Digest. He is also a consultant and columnist who writes for the Alaska Journal of Commerce.

Yes, Oil is Down, For Now...But Hold On!

By Tim Bradner

It’s easy to feel uneasy about our state’s petroleum industry right now. Let me cite some reasons:

• Crude oil prices are still down. They are slowly rising but conventional wisdom is that $60 per barrel may be a kind of price ceiling, the threshold where those prolific shale oil drillers flip the switch and bring more supplies, sending prices down again.
• The newspapers are full of articles about layoffs in the oil industry that are now rippling out through the economy, affecting even retail.
• Legislators in Juneau are again talking about increasing taxes on oil producers even though many are still operating in the red. Question: Shall we shoot ourselves in the foot?
• The big gas pipeline/LNG project, which is thought to be our long-term economic savior, now seems more distant than ever.

All the above is true and it is enough to make one feel blue.

But here’s a secret: Whatever we think about our situation now will turn out to be wrong. That’s because we’re always wrong when we think the future will be like the present. It won’t be.

Here are some big positives. Yes, we do need to diversify the economy along with our state revenue sources, which are too dependent on oil. But our petroleum industry has a lot of life left in it, and we now know there’s still a lot of oil on the North Slope. Recent discoveries by ConocoPhillips, Armstrong Oil and Gas and its partner Repsol, and by Caelus Energy confirm that.

This is actually a new paradigm. Until recently, in fact until those discoveries were made, most geologists, particularly government geologists, believed the big heyday of the North Slope was past and that from here on out only small or medium-sized fields will be found.

While there’s a lot we don’t know about the new discoveries – there are still uncertainties about them – but what we do know shows how wrong the past assumptions have been.

For example, it’s a good thing that ConocoPhillips didn’t believe the U.S. Geological Survey when it predicted the National Petroleum Reserve–Alaska would hold mostly natural gas and very little oil. ConocoPhillips is finding a lot of oil, and is now pretty busy with three discoveries there. 

The lesson that ConocoPhillips, Armstrong/Repsol and Caelus is teaching us is that you never know until you drill. (On the other side of the coin, the same must be said about the Arctic National Wildlife Refuge, where there’s a lot of high expectations by Alaskans. Until we can drill, we’ll never really know.)

But this gets me to another point: Those oil incentive tax credits. A lot of legislators call them subsidies. I prefer to call them investments. It’s true that we can no longer afford them and Gov. Bill Walker and legislators are correct that the program, in its present form, needs to wind down.

But the basic idea behind the incentives was to bring more companies to Alaska and get more exploration wells drilled – because that’s the only way more discoveries can be made. The fact is that the incentive program has performed brilliantly. It resulted in new companies coming to Alaska. More natural gas was discovered in Cook Inlet, ending fears of electrical brownouts because of fuel shortages for power generation. More exploration wells were drilled on the slope, with those recent discoveries made.

We can never say that the newcomers, firms like Hilcorp Energy and BlueCrest Energy, Armstrong, Repsol and Caelus, came to Alaska because of the tax credits. They came because we have good rocks. But the tax credit program was what caught their attention. No other place in the world has anything like it. It caused them to come here and take a look and once here they really liked what they saw, in the rocks. Financially, the tax credits allowed them to do more work and at a quicker pace, which speeded the discoveries.

They also allowed companies to tackle new ideas, like the work that Great Bear Petroleum, an Alaska-based company, Burgundy Xploration of Texas and 88 Energy of Australia are going to test the potential for producing oil from the large North Slope shale formations.

That’s out in the future, but let’s put some numbers around what’s been discovered so far.

• ConocoPhillips says its newest NPR-A discovery, Willow, could produce up to 100,000 barrels a day by 2023. Two other ConocoPhillips projects in the petroleum reserve, GMT-1 and GMT-2, are in construction (GMT-1) or in permitting (GMT-2). Together they could add 55,000 barrels a day by between 2019 and 2021.
• Armstrong and Repsol are planning production facilities for their discovery that will be capable of producing 120,000 barrels per day.
• Brooks Range Petroleum, a small independent, has a small project, Mustang, in development that could produce 12,000 barrels per day.
• Caelus has a small project, Nuna, which is in advanced planning that could produce 20,000 to 25,000 barrels per day. Caelus’ big project, further out, is the Smith Bay discovery, which still needs tests but which the company hopes could produce 200,000 barrels per day.

All that adds up to about 400,000 barrels per day of new oil. Let’s not forget that there’s still a lot of undeveloped oil, several billion barrels, left in the big producing fields, like Prudhoe Bay and Kuparuk River. This gives us a lot of reasons to be optimistic.

We are going through some tough times in our state’s “oil patch” but let’s not forget that we’re also coming off several years of boom when oil prices were $100 or more. Our industry is now back to where it was in 2012, and that wasn’t so bad.

Given the uncertainties in future prices we may not see $100 oil, and boom times, again. That could be wrong, of course (and probably will be) but we should plan for what we know, and that includes the knowledge that there’s a lot of oil on the slope.

We can take comfort in that. Meanwhile, let’s not shoot ourselves in the foot. That’s a message to our legislators.

Tim Bradner is editor of the Alaska Economic Report and co-publisher of the Alaska Legislative Digest.

Risk and Reward: The Permanent Fund as a Source of Income for the State of Alaska

By Tim Bradner

It seems inevitable that state of Alaska finances will soon be closely linked to performance of the state’s Permanent Fund. That has caused many Alaskans to look closely at how this change could affect the Fund’s management, and at the institutional protections for the Fund built into state law. Some consider those protections weak.

Gov. Bill Walker has proposed legislation that would make earnings of the Fund available to help support the state budget, and also put limits, indirectly, on the popular Permanent Fund Dividend.

The governor’s plan, in Senate Bill 128, passed the state Senate but not the state House, mainly over concerns about limiting the dividend in an election year. The governor is still pushing for passage of the bill either in a possible special session later this year or the regular 2017 session that begins in January, and with the 2016 elections over it’s quite likely the bill will pass.

Basically, Walker’s idea, which was modified in the state Senate, provides for an annual payment of the Fund’s earnings equal to 5.25 percent of the market value of the Fund, a “percent of market value”, or POMV, that is used by many large endowments in one form or another.

Based on this, the Fund could contribute between $2 billion to $2.5 billion yearly in support of the state general fund budget and still leave enough income retained in the Fund to offset inflation, and to allow the Fund to continue growing.

Of course, this would still leave a large deficit in state finances which would have to be filled with other revenues, most likely taxes in some form.

Here’s the math: If the state general fund budget is $4.5 billion, approximately its current level, and oil revenues contribute $1.2 billion, again about the current amount (and assuming, conservatively, that oil prices will remain in current range for an extended period), and that non-oil taxes contribute $300 million, this leaves a deficit of about $3 billion.

This is close to the state’s actual deficits for the past two fiscal years, which are being paid for by drawdowns from the Constitutional Budget Reserve, another state savings account (this fund will be exhausted in two years).

If the Permanent Fund can provide $2 billion to $2.5 billion each year, that still leaves a gap of $500 million to $1 billion to fill. The governor’s solution to this is a mixture of tax increases on various industries like fisheries and mining as well as a hike in the state’s motor fuel tax, which is the lowest in the nation, and a broad-based tax like a personal income tax.

However, given that some kind of change to the Permanent Fund’s relation to the state budget is coming, what questions does this raise?

First off, there are many who are concerned that a 5.25 percent annual draw is too high, that it could erode the Fund over time. Given the long-term uncertainties for financial markets, which are driven by expectations of long-term lower growth in the world economy, many pension funds and endowments are lowering their percentages of annual draws to four percent or 4.5 percent.

If the state of Alaska decides to be more prudent, that would lower the amount the Fund would make available to help the budget, requiring an increase in revenue from other sources or additional spending cuts.

The Permanent Fund’s managers say there are ways a larger draw can be accomplished, however, because the Fund is actively managed and that changes in asset allocations can result in more income. However, more aggressive management of the Fund will also assume more risk, an important consideration.

There are other issues affecting management, for example how the requirement to meet a required large annual cash payout would affect the Fund managers’ decisions over a mix of short-term, more liquid (and less income-producing) investments compared with that are long-term and less liquid (and more income-producing). These are issues but they are similar to those faced by other large endowments and can be dealt with. To some extent the Fund faces this problem now on a smaller scale, in ensuring that $1.5 billion or so is available in the fall to finance the annual PFD payout and an annual “inflation-proofing” payment of earnings back into the Fund to further offset inflation, although this has been low in recent years.

If the state does begin to use Permanent Fund earnings to help support the state budget, the governor and the Legislature will have to balance different goals. One, most important, is preserving and growing the Fund over the long term. A second, if the Legislature approves the governor’s plan, will be to have the Fund become a reliable source of revenue.

A concern many Alaskans have is that these two goals could conflict with each other.

On State Fiscal Policy, History Knocking at the Door

By Tim Bradner

In the din of intense debate, like what’s happening right now in Juneau, it’s hard to hear history knocking at the door. But in fact I hear knocking. Here we are–at a pivotal point in our state’s history.

We’re facing a tough set of facts: Oil prices at $30 per barrel; state revenues less than a third of what’s needed to balance the budget and a drawdown of available cash that will leave the treasury empty in four years, except for the Permanent Fund.

Of course, it’s not really a financial crisis. It’s a political will crisis.

We actually have plenty of money on hand, mainly several billion dollars of yearly revenue we’ve never touched, meaning the investment earnings mainly of the Permanent Fund.

This is not the Fund itself, which can’t be spent, but rather the earnings, which have always been available but never spent except for the annual Permanent Fund Dividends.

To illustrate, while the state’s petroleum revenues have gone into the tank, investments revenues, most from the Permanent Fund, are up smartly. Investment income increased from $2.58 billion in state Fiscal Year 2015, the budget year ended last June 30, to an estimated $3.77 billion for FY 2016, the current fiscal year, according to the Department of Revenue’s December 2015 state revenue forecast. For FY 2017, which begins in July, estimated investment earnings are $4.88 billion, according to the revenue department forecast.

So while oil income is down, investment income is up. Viewed that way, our situation is not as stark.

Gov. Bill Walker is widely given credit for being the first politician to call out the fiscal imbalance and propose solutions, including using some of the Permanent Fund’s earnings and also, by the way, asking Alaskans to pay some taxes. The governor’s specific proposals may not pass, at least all at once, but I believe a similar package will eventually be developed by legislators showing leadership.

This is history at the door: We’ll be taking the first step at diversifying our revenue base away from a 90 percent dependence on a volatile commodity–oil. This will help stabilize and diversify our state’s economy, in the long run, because we’ve allowed ourselves to become too dependent on the spending of state oil dollars.

In the meantime it will be a cold shower, however. Alaska jobs are starting to decline after years of slow, steady growth, and this will accelerate the news of more drill rigs being laid down on the North Slope. State budget cuts of several hundred million dollars won’t help.

However, state spending cuts appear to be the political price to be paid for the historic shift in our revenue base. The governor has proposed $100 million in spending reductions after last year’s $400 million cut to the operating budget, but it appears legislators want to go deeper, maybe equal to last year’s cuts.

Gunnar Knapp, at the University of Alaska’s Institute of Social and Economic Research, has estimated that each $100 million in across-the-board spending reduction in Juneau costs the economy about 1,300 jobs. If $400 million in cuts are made for next year’s state budget, the effect will be 6,500 jobs lost, according to ISER’s modeling. Some of that will be in retirements and attrition but the bottom line, loss of jobs in the economy, is still the same.

As a point of information, if we were to simply whack the budget to match available revenues, cutting spending by $3.5 billion (the possible size of our deficit) the effect would be, using the ISER estimates, to lose 45,500 jobs in the state’s economy, well over 10 percent of our workforce.

I can’t think of what that would be like, but it wouldn’t be pleasant. Losing 5,000 to 6,000 jobs will be tough enough on top of the oil patch jobs losses (which are likely to be far fewer lost jobs, actually). However, if it’s the price we must pay for our state’s leaders to muster up the courage needed to transform the finances, it’s worth it.

However, Rep. Mark Neuman, the co-chair of the House Finance Committee, points out that we’ve made substantial budget cuts in recent years that have gone largely unrecognized. In FY 2013 state general fund spending totaled $7.8 billion, a good share of that being the capital budget. In FY 2016, the current budget year, it is $5.4 billion including capital. FY 2017, the financial year beginning next July, will be substantially less.

As painful as this is, there’s a silver lining. We’ve talked for years about making structural fiscal changes but these never happened because we didn’t really have to do it. There was plenty of oil money, or if oil prices did drop they shot up again.

Let’s hope that cycle doesn’t repeat, and that prices stay down at least long enough for these decisions to get made. Legislators obviously are worried about the elections later this year and the effects on their careers, but here’s a chance for politicians to be part of history, a historical state policy change equal, in my mind, to the enactment of the Permanent Fund itself.

Those opportunities, to be part of history, don’t often come along.

Tim Bradner is co-editor of Alaska Inc. Magazine and co-publisher of Bradners’ Alaska Legislative Digest

Walker Administration's Fiscal Plan

By Tim Bradner

Gov. Bill Walker will roll out his Fiscal Year 2017 budget proposal fairly soon. The statutory deadline is Dec. 15 but the governor is working to get parts of it out earlier. What will really grab peoples’ attention; however, are revenue measures Walker says he will propose, including some form of broad-based tax.

The governor is also working on a new way of structuring state finances. It would fund government partly from Permanent Fund earnings, which would bring more stability to state finances. The state budget is now mainly financed by oil revenues that can be unpredictable and volatile, as recent experience has shown.

The fiscal plan has been under development for several months and was rolled out as a concept by state Attorney General Craig Richards in a briefing to legislators on Oct. 28. Lawmakers were in Juneau for a special session on natural gas issues.

The fiscal plan is a work in progress, Richards admitted, but it essentially involves bulking up the Permanent Fund by diverting certain oil revenues that now go to the state General Fund and funding the state budget from a portion of earnings of the Permanent Fund.

The governor’s team is still studying several ideas for a payout mechanism from the Permanent Fund, but some of the ideas are based on variations of a percent-of-market-value formula, similar to that used by many large endowments.

Under this approach, a percentage, say 4 percent or 5 percent, of the total market value of the fund would be tapped for the budget. This should allow enough earnings to be retained in the Fund to account for inflation. Another payout mechanism is a fixed sum paid to the general fund, with this amount inflation proofed. There are variations of this, too.

Technically the payout would actually come from the Earnings Reserve of the Permanent Fund, an account in which income from the Fund is deposited. The Legislature cannot appropriate funds from the principle of the Fund but money in the earnings reserve can be used.

These ideas aren’t really new–similar notions have been discussed for years and there are other plans out there, like one proposed by University of Alaska economist Scott Goldsmith–but the matter is urgent now given the state’s financial situation.

The governor is being given credit for stepping forward with a concrete idea, and it is certain to spark serious discussion in Juneau.

What’s also in Walker’s proposal, however, is a change in the way Permanent Fund dividends are financed and this would have the effect, in the near term at least, of reducing the annual dividend and making more money available for the state budget.

The plan described by the Attorney General Oct. 28 would have the dividends funded by a portion of state oil royalties (the remaining royalties would go to the Permanent Fund, as some now do). Currently the dividends are financed from the Fund’s earnings, with the money actually taken from the earnings reserve.

This would be a fundamental change, severing the connection between the dividend and its amount from the financial performance of the Permanent Fund. Instead, citizens would have a very direct connection with state oil revenues. Some are viewing this as good–giving Alaskans a direct stake in the performance of the oil and gas industry–while others view it more critically. Separating the dividend from Permanent Fund performance could lessen citizens’ interest in the Fund. Currently, the direct connection with the Fund performance acts as a brake against any unwise investments the trustees might make or any indirect raid on the fund by the Legislature (while the Fund cannot be spent directly it can be used as collateral in state financing, such as for a gas pipeline, which may or may not be wise). However, under current oil market conditions the amount of the dividend under the governor’s plan, if it were adopted immediately, would be roughly cut in half from the 2015 dividend amount. 

There is certain to be a lot of discussion on all aspects of this and other proposals for solving the state fiscal gap. Legislators are being very cautious in their reactions and that no one has yet voiced sharp criticism is encouraging.

The state’s credit rating agencies gave praise to Walker for at least offering up something, although they noted that his plan, as now designed, wouldn’t completely close the $3 billion deficit. New revenue sources will still be needed.

So this is a start, and possibly a good one. There’s a lot more to come. But solve the problem we must, and soon.

 

Tim Bradner is a natural resources writer for the Alaska Journal of Commerce