Alaskanomics

How much is uncertainty costing the state of Alaska?

By Mouhcine Guettabi, Assistant Professor of Economics, Institute of Social and Economic Research UAA

Due to the decline in oil prices, the state has had to rely on savings to fund government for the last few years. The legislature has, however, not decided how it intends to fund government activity going forward. Given the size of the deficit and the paucity of non-oil sources, it seems that a draw from the Permanent fund is necessary.  While, understanding the potential short term effects from the imposition of taxes or government cuts seems to be fairly well understood, we try to quantify below the potential investment losses stemming from delaying a decision that provides fiscal stability.

What is the scale of private capital spending in Alaska?

While there does not exist a database of private and public capital spending by year for the state of Alaska, we have yearly construction forecasts which use as a proxy for these activities. In figure 1, we show that non-oil private spending between 2013 and 2017 declined by 410 million dollars. In figure 2, we show that O&G capital spending peaked in 2014 at 4.25 billion dollars and was only 2.43 billion in 2017. In other words, capital spending- including oil and non-oil- decreased by more than 2.5 billion dollars in the three years since oil prices declined.

Figure 1: Private sector construction spending (No Oil and Gas) between 2013 and 2017

Figure 2: Oil and Gas construction spending between 2013 and 2017

Is there any academic evidence linking uncertainty and investment?

Baker, Bloom, and Davis (2013) construct a novel index of economic policy based on a diverse array of metrics, performing tests of the index’s validity through a human audit of 3,500 newspaper sources and other common-sense measures. They find that the increase in policy uncertainty that followed the onset of the Great Recession had significant negative effects on aggregate investment and on employment as well as on consumption expenditures. Matching firm-level data with the data series of this index, Gulen and Ion (2013) find that economic policy uncertainty can explain up to 32% of the drop in corporate investment over the 2007-2009 time period.

Do we know anything about the effect of uncertainty at the state level?

Gao and Qi (2012) find that municipal bonds issued by state governments immediately before a gubernatorial election pay a premium of 6 to 8 basis points due to this electoral proximity. Jens (2013) estimates the investment-suppressing effect of a gubernatorial election on the state-level investment during the quarter of the election at between 5% and 15% depending on the subsample, with the closeness of an election exacerbating the decline.

Does the information above allow us to determine how uncertainty affects the Alaska economy?

Private Construction spending in 2017 is supposed to be around 4 billion dollars. Using the 5 to 15% estimated by Jens (2013), we would conclude that the direct effects of policy uncertainty is costing the state somewhere between 200 and 600 million in private capital spending. The decline in spending due to policy uncertainty would indicate that waiting is not a costless option. In fact, the losses due to uncertainty are important and similar in magnitude to the ones the economy would experience due to a tax or further government cuts.

Table 2 Capital spending in billions in Alaska between 2012 and 2017[1]

		2012	2013	2014	2015	2016	2017
Private
	Oil and gas	3.152	3.638	4.255	3.84	3.125	2.43
	Mining	0.34	0.33	0.205	0.21	0.18	0.187
	Other basic	0.01	0.02	0.076	0.025	0.104	0.13
	Utilities	0.794	0.83	0.851	0.68	0.459	0.498
	Hospitals	0.325	0.229	0.23	0.24	0.195	0.336
	Other commercial	0.12	0.15	0.17	0.135	0.15	0.15
	Residential	0.4	0.44	0.48	0.415	0.329	0.277
Private sector  total   total		5.141	5.637	6.267	5.545	4.542	4.008
Public
	National defense	0.46	0.209	0.395	0.435	0.552	0.635
	Highways	0.585	0.824	0.765	0.755	0.705	0.629
	Airports	0.375	0.479	0.425	0.465	0.387	0.37
	Alaska Railroad	0.055	0.024	0.023	0.025	0.026	0.022
	Denali	0.02	0.013	0.009	0.01	0.01	0
	Education	0.408	0.497	0.477	0.465	0.406	0.212
	Other federal	0.207	0.245	0.3	0.255	0.253	0.255
	Other state	0.474	0.45	0.515	0.555	0.422	0.322
Public sector total		2.584	2.741	2.909	2.965	2.761	2.445
Overall total		7.725	8.378	9.176	8.51	7.303	6.453

[1] We use the forecast figures from the construction forecast produced by ISER to proxy for actual capital spending.

References:

Baker, Scott R., Nicholas Bloom, and Steven J. Davis (2012), “Measuring Economic Policy Uncertainty,” manuscript, Stanford University.

Gulen, H. and Ion, M. 2013. Policy Uncertainty and Corporate Investment. Purdue University mimeo.

Jens, C. 2017. Political uncertainty and investment: Causal evidence from U.S. gubernatorial elections. Journal of Financial Economics 124:563-579.

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

The 38th Annual Alaska Resources Conference

Last week, the Resource Development Council (RDC) hosted its 38^th Annual Resources Conference in Anchorage. The event is the chance for leaders from the tourism, fishery, oil and gas, mining, and forestry industries to come together and share highlights and frustrations from the past year and look forward to the coming year.

As was the case in 2016, presenters were cautiously optimistic about the future of resource development in Alaska. There is still major concern about the State’s fiscal situation. The continued lack of a sustainable plan has caused great frustration in the industry.

There was a bright spot in the first morning’s presentation when Senator Murkowski phoned in to say that the Senate Committee on Energy and Natural Resources released budget reconciliation legislation to open a small part of the non-wilderness portion of the ANWR, known as the ‘1002 Area’ to responsible oil and gas development. On the Senate Committee’s webpage, Senator Murkowski is quoted by saying, “This legislation is a tremendous opportunity for both Alaska and our country. The legislation I released tonight will put us on a path toward greater prosperity by creating jobs, keeping energy affordable for families and businesses, generating new wealth, and strengthening our security- while reducing the federal deficit not just by $1 billion over ten years, but tens or even hundreds of billions of dollars over the decades to come.”

This announcement was an encouraging start to the conference. An additional positive note was that for the 2^nd year in a row, there has been an increase in production on the North Slope and more oil in the pipeline. The increase has been small, but everyone agreed that any increase was good. There was also renewed excitement for the Alaska LNG project, after the announcement of the agreement between Alaska and China. Governor Walker noted that due to the fact that the project had support from the highest levels of government in China and the United States, he was optimistic that the project has new life and could move forward with renewed enthusiasm.

Many speakers noted frustrations that there was still no sustainable solution for the State’s fiscal crisis. Rather than focusing on the negative, presenters chose to focus on what they could do within their own industries to help encourage development across all sectors. Individual presentations highlighted the work that has been done in the past year, as well as plans for future development.

The conference highlighted work between different industries that will help grow the Alaska economy. All presentations, including videos of each session, are located on RDC’s website.

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

August Unemployment at 7.2 percent

Alaska’s seasonally adjusted unemployment rate continues to creep up and was at 7.2 percent in August. This is two-tenths of a percent higher than the rate in July and much higher than the national rate of 4.4 percent.

Employment continues to drop and preliminary numbers show a loss of 4,800 jobs in August, compared to August last year. Most job losses were from industries related to oil and gas. Industries that saw an increase over last year are health care, local and federal government. Anchorage and Mat-Su saw the largest decrease in jobs, losing 3,100 jobs over last year. The Northern Region, which includes the North Slope lost 1,000 jobs during the same time frame.

August still has strong tourism, fishing and construction numbers and low unemployment numbers for those census areas.

Complete employment numbers are located at the State of Alaska’s Department of Labor and Workforce Development website.

TAPS 40th Anniversary

Today marks the official anniversary of the completion of the Trans-Alaska Pipeline System (TAPS). 40 years ago today the first oil flowed to Valdez through TAPS. This was the culmination of a three year, $8 billion project that employed approximately 70,000 people during construction.

In the past 40 years, more than 17 billion barrels of oil have been produced on Alaska’s North Slope. Through 2016, the oil industry has invested more than $55 billion in Alaska. In many years, oil has funded 90 percent of the state’s unrestricted General Fund and generated more than $180 billion in total state revenue. Today, oil revenues account for approximately 67 percent of unrestricted General Fund revenue.  

There is no doubt about the impact that the oil and gas industry has had on Alaska’s economy. Prudhoe Bay has exceeded initial projections and is the third-largest oil field in the US by proved reserves. Despite low oil prices, 2016 was the first year in a decade that had increased production through TAPS. This year is expected to have another increase. If the prediction holds true, it would be the first time with 2 years of increased production since 1988.

As we celebrate the Summer Solstice, we think about all that TAPS has brought to Alaska’s economy. The longest day of the year brings life and growth, just as TAPS has brought life and growth to Alaskans throughout the state. Many have their own stories of working on the pipeline or coming to Alaska for a fresh start. The same fresh start that we feel on Solstice as we look forward to the coming summer season. Happy Anniversary to the Trans-Alaska Pipeline System and all who have helped to make it a lifeline for Alaska.

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.

December Unemployment at 6.7 Percent

The Alaska Department of Labor and Workforce Development released the December unemployment rate on Friday. Alaska ended the year with 6.7 percent unemployment, two percentage points higher than the national rate.

Preliminary data shows a decline of 7,600 jobs compared to December 2015. Most of the private losses came from oil and gas, construction, and professional business services. State government had the highest losses in the public sector.

Anchorage and Fairbanks both have 5.7 percent unemployment, while Juneau is at the national rate or 4.7 percent. Skagway had the highest percentage at 20.3 percent, while Sitka had the lowest rate at 4.3 percent.

For full employment statistics, visit http://live.laborstats.alaska.gov/labforce/index.cfm