Alaskanomics

Alaska Housing Market Remains Steady

A recent article in Alaska Economic Trends outlines the state of the housing market in Alaska. While the recession has slowed growth in the housing market, it remains healthy. Fewer homes are being built, but sale prices are stable, rising 2.6 percent from 2015 to 2016. Like many things in Alaska, homes are more expensive than in the rest of the U.S., averaging 40 percent more for a single-family home.

Experts note that the fact that prices haven’t dropped during the first year of the recession in Alaska is a sign of a relatively stable market, even with the job losses seen throughout the state. This is in direct contrast to the housing bust that was seen during the recession in the 1980s in Alaska.

Another piece of the market that has remained relatively stable is affordability. This is measured by the number of average paychecks required to afford the average single-family home. It’s determined by area’s wages, sales prices and interest rates, which continue to be near historic lows. In 2015 and 2016, affordability was the same with 1.24 average paychecks needed to afford a typical home. While wages have remained flat, low interest rates have offset the slight increase in prices to remain in at the same level of affordability. Purchasing a home in Fairbanks, Juneau and Kodiak became more affordable, while it because less affordable in Anchorage, Mat-Su, Kenai and Ketchikan.

For more information on the Housing Market or Alaska Economic Trends, visit the State of Alaska's Department of Labor. 

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.