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A look at Alaska's royalty relief history

  • Author: Eric Lidji
  • Updated: September 28, 2016
  • Published December 8, 2014

With the Walker administration facing a decision to maintain, revise or reject a Parnell administration recommendation to offer royalty relief for the Nuna development, it is helpful to consider the nearly 20-year history of the royalty relief program in Alaska.

Since 1996, the Alaska Department of Natural Resources has only received seven requests for royalty reduction. Prior the current case, the state had only approved two.

On Dec. 2, the state Legislative Budget and Audit Committee reviewed a state plan to reduce the royalty rates on five leases at the proposed satellite of the Oooguruk unit.

If operator Caelus Natural Resources Alaska LLC sanctions the project by the end of the year and meets spending and development targets through early 2017, the Alaska Department of Natural Resources would lower its royalty rate to 5 percent on the leases.

The existing royalty rates on those fives leases are either 12.5 percent or 16.667 percent.

The reduced royalty would remain in effect until Caelus earns $1.25 billion in revenue.

Relief requested for 11 leases

In its application, Caelus requested royalty relief on 11 leases associated with the development. The company said the development would be uneconomic without relief.

The bulk of the application -- the section laying out the case for reduction - is proprietary. However, the state claimed to have run independent models before making its recommendation. The state will rule after the comment period ends on Dec. 12.

In documents shown at the hearing, state and company officials claimed that the Nuna development is "high risk, high reward." The accumulation is thought to contain 1 billion barrels of oil in place, but the reservoir has low porosity, low permeability, high oil viscosity and high initial water cut. Those conditions will require large hydraulic fracturing operations on producers (which is common) and injectors (which is not).

Privately held independent

Additionally, Caelus is a small privately held independent without the financial muscle to fund projects internally or the financial options available to a publicly traded company.

That said, earlier this year Caelus announced a partnership with the investment firm Apollo Global Management. The deal gave Caelus access to nearly $1 billion in capital.

The state stands to lose some $44 million in revenue by approving the reduction and stands to gain between $1 billion and $1.75 billion in revenue should the project move forward, according to Department of Natural Resources estimates offered at the hearing.

The deal also requires Caelus to give the state a public account of its development work -- including costs, facilities design and forecasts -- after two years of production. The state believes that information will be useful to future operators on the North Slope.

Even so, Rep. Les Gara, D-Anchorage, is challenging the recommendation.

Because the "gross value reduction" provision of the More Alaska Production Act, also known as Senate Bill 21, "already produces a negative or near zero production tax worth for post-2003 fields like Nuna," Gara wrote in a public letter to Parnell administration officials several days before the hearing, "reducing the separate 'royalty' Alaskans receive from this field by over 50 percent might leave Alaskans with very little worth for our oil, and that may not be justified under a fair review of the facts."

Two reduced, two sanctioned

Of the six previous requests for royalty relief received since 1996, the Alaska Department of Natural Resources has approved two: for the Oooguruk unit in 2005 and for the Nikaitchuq unit in 2008. Those two fields have a lot in common. They are the two newest producing fields on the North Slope, and they are the first North Slope fields developed by companies other than BP Exploration (Alaska) Inc. or ConocoPhillips Alaska Inc.

Before Pioneer Natural Resources Alaska Inc. requested royalty relief for the Oooguruk unit in 2005, the three previous requests all came from multinational companies.

First, BP requested relief for the Milne Point unit. The company withdrew the application before the state issued a ruling. BP later developed North Slope field without relief.

Next, Union Oil Company of California requested royalty relief on production from all their Cook Inlet platforms. Concluding that some of the platforms were beyond help and others were economic under existing conditions, the Department of Natural Resources offered to reduce the royalty rate on production from some of the platforms. Unocal instead pursued a legislative solution, successfully lobbying for a law that automatically reduces royalty rates when production from a platform drops below a certain level.

Then, Phillips sought royalty relief for its Tyonek Deep prospect in Cook Inlet. The company later withdrew the application, in part because of complications arising from its subsequent merger with Conoco and in part because the state needed more information.

The Tyonek Deep prospect remained undeveloped.

Oooguruk in 2005

Those requests all came before 2003, when the state made two major changes to the royalty relief process: allowing relief to be granted for an uneconomic portion of an otherwise economic field and allowing regulators to offer royalty relief on a sliding scale taking into account various factors such as oil prices, development costs and total recovery.

In all four cases since that change, including the current case at Nuna, the state has either rejected the request or provided a more limited form of relief than the company wanted.

In 2005, Pioneer Natural Resources wanted a royalty reduction on nine leases at Oooguruk - four at the unit with a 12.5 percent royalty rate and a 30 percent net profit sharing provision and five in a proposed expansion area with a 16.6667 percent royalty.

Pioneer wanted the royalty rate on all nine leases reduced to 5 percent. Without the change, the company told the said it could not "vigorously pursue" development.

The unit included 18 leases altogether.

The state agreed to modify all nine leases but also made all nine leases net profit sharing, which required Pioneer to share 30 percent of its profits from those leases with the state.

The ruling was the first time the state had used its authority to grant royalty relief to an undeveloped field. Pioneer bought the Oooguruk unit into production in mid-2008.

Nikaitchuq in 2006 and 2008

In 2006, Kerr-McGee Corp. wanted a reduction on 14 leases around its Nikaitchuq prospect -- 12 leases with a 16.6667 percent royalty rate and two leases with 12.5 percent royalty rates and 30 percent net profit sharing. The request covered four leases at the Nikaitchuq unit, six at the neighboring Tuvaaq unit, one in the Kuparuk River unit, one in the Milne Point unit and two leases just outside the Nikaitchuq unit boundary.

While the Department of Natural Resources initially signaled a willingness to extend relief, officials waited to issue a decision until after the state approved the Petroleum Profits Tax. Ultimately, the state decided that PPT "materially improved" the economics of the project - to the tune of $120 million fewer taxes - and rejected the application.

By 2007, Eni US Operating Co. had acquired the prospect. The American subsidiary of the Italian multinational merged Tuvaaq into the Nikaitchuq unit and asked for relief reduction on Schrader Bluff and Sag River production for 12 leases in the expanded 18-lease unit. Of the 12 leases, 11 had a 16.6667 percent royalty rate and one had a 12.5 percent royalty and 30 percent net profit share. Eni wanted a 5 percent royalty rate.

Ultimately, the state agreed to reduce the royalty rate on the 11 leases with the higher royalty rate. The state said the remaining lease did not appear to overlie an oil pool.

Conditions at Nikaitchuq

The state added various conditions, though, which proved prescient.

First, under the agreement, the reduction only goes into effect when the delivered price of Alaska North Slope crude oil falls below an inflation-adjusted price of $42.64. Using inflation figures from the U.S. Bureau of Labor Statistics, that threshold is currently about $47.02. Even with the dramatic declines in oil prices over the past six months, the spot price of ANS West Coast price has only recently dipped below $70 per barrel.

The reduction would also go into effect, regardless of prices, if production fell below 4,000 barrels per day during the first 10 years of production (barring initial ramp up).

Second, the reduction only covered production from the Schrader Bluff OA sands. To date, that interval has been the focus of development. But Nikaitchuq is currently appraising the economics of the Schrader Bluff N sand, which would not get relief.

Third, the reduction only lasts for the first 25 years of sustained development. Barring any major shutdowns at the field, that deadline would arrive sometime in early 2036.

The decision also required Eni to meet certain spending targets for the first six years and the first 11 years of development. While spending figures are proprietary, Eni sanctioned a $1.45 billion development program in 2008 and appears to be nearing the end of that initial program. The total 11-year spending requirement from the state was $1.398 billion.

This story originally appeared in Petroleum News and has been republished with permission.