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State approves Northstar unit’s participating area; it’s smaller than BP initially requested Four of five state leases in participating area; BP has until October 2005 to drill an exploration well into fifth lease, or it will contract out of unit By Kristen Nelson PNA Editor-in-Chief
The Alaska Department of Natural Resources’ Division of Oil and Gas has approved the Northstar participating area, defining the area of the unit actually under production.
The participating area findings and decision, signed by Division of Oil and Gas Director Mark Myers Sept. 4, also provides an update on the amended royalty terms for the state leases indicating that, as expected, the state has done better under the amended provisions than it would have under the original terms of the leases.
The state jointly manages the Northstar unit with the U.S. Department of the Interior’s Minerals Management Service and both agencies approved formation of the unit in 1990 when Amerada Hess was operator.
Current unit operator BP Exploration (Alaska) Inc. applied in 2001 to expand the unit boundary and form the participating area. Murphy Exploration (Alaska) Inc. is the other working interest owner in the Northstar unit. DNR and MMS approved the expansion of the Northstar unit in July 2001 to include an additional federal lease for a total of approximately 33,768 acres in eight oil and gas leases: 23,344 acres within five state leases and 10,424 acres within three federal leases. BP holds 100 percent working interest in seven of the Northstar unit leases; in one federal lease BP holds 90 percent working interest and Murphy holds 10 percent.
The state issued an interim approval of the participating area in October. MMS issued an interim approval in October and a final decision in November.
The state said this findings and decision supplements the interim decision and approves two additional exhibits.
The Northstar reservoir includes Ivishak and Shublik “D” intervals within the Northstar field. The division said a portion of the state acreage is “reasonably known to be underlain by hydrocarbons and known or reasonably estimated through the use of geological, geophysical, or engineering data to be capable of producing or contributing to production of hydrocarbons in paying quantities” as required by state regulations for unitization. BP originally proposed that the participating area include all of the three federal leases and portions of four state leases, approximately 28,023.63 acres (12,252.37 state acres and 10,424.14 federal acres).
The state requested a reduction in the state acreage included in the participating area “to conform to 160 acre spacing around the Northstar reservoir oil/water contact contour.” The state said BP also agreed to reduce federal acreage “to exclude other possible hydrocarbon accumulations not in communication with the Northstar reservoir.”
The approved Northstar participating area includes approximately 17,667 acres, approximately 52 percent of the unit, with portions of four of five state leases, all of one federal lease and portions of two other federal leases. Fifty-six percent of the participating area, 9,901 acres, is on state leases and 7,766 acres, 44 percent, on federal leases.
The state accepted in its interim approval the allocation of unitized substances among the leases in the Northstar participating area of 84.097 percent to state leases and 15.903 percent to federal leases.
Within the participating area, BP holds 98.8272 percent working interest and Murphy holds 1.1728 percent. Fourth plan of development BP’s fourth plan of development, Oct. 1, 2001, through Sept. 30, 2004, includes plans to drill and complete up to 16 production wells and five gas injection wells. BP will inject miscible enriched gas for approximately four years and then inject leaner chase gas for the remainder of field life. BP plans to complete development drilling at Northstar within the three-year term of the fourth plan of development.
The state said that BP has estimated recovery at 159.3 million stock tank barrels of oil and 16.9 million stock tank barrels of natural gas liquids over the 15-year field life with enhanced oil recovery compared to 89 and 5.1 million stock tank barrels respectively without EOR. BP began EOR operations in January, two months after beginning production.
BP will evaluate the overlying Kuparuk and Sag River formations while drilling the participating area development wells and will also evaluate acreage that lies within the unit but outside of the approved participating area.
The state said that current available data indicates that no portion of the Northstar reservoir underlies state lease ADL 355001, Northstar unit tract 105, and that lease is not included in the participating area. The division said it requested that the fourth plan of development include plans to explore the area under this lease and BP committed to begin drilling an exploratory well on state acreage at least one-half mile outside of the participating area boundary within four years.
BP must begin drilling the exploration well into ADL 355001 by Oct. 12, 2005, or that lease will automatically contract out of the unit. Royalties to state The Alaska Legislature approved amendments to the Northstar leases in 1996, replacing a net profit share percentages bid at a 1979 state lease sale by Amerada Hess and Texas Eastern Exploration Co. The amendments replaced the net profit share provision with a supplemental royalty provision that imposes a sliding scale royalty rate of up to 7.5 percent in addition to the 20 percent base royalty rate for a maximum total royalty rate of 27.5 percent. The supplemental royalty rate varies depending on the Alaska North Slope spot price on the West Coast relative to a trigger price which is inflation adjusted annually each May based on changes in the Producer Price Index.
In each month that the average ANS spot price is greater than the applicable trigger price, the supplemental royalty rate for the month equals the difference times 1.5 percent.
The Northstar participating area produced 7,519,000 barrels of oil from the beginning of production Oct. 31 through June 30, 2002, the end of the state fiscal year. Approximately 1,857,000 barrels were attributed to the state’s royalty.
The state received supplemental royalties in five of the first eight production months and the royalty rate reached the maximum of 27.5 percent in April, May and June. The division said that the state received 350,000 barrels of royalty oil in excess of the 1.5 million barrels due at the 20 percent base royalty rate, for an effective royalty rate of 24.7 percent.
Had the leases been produced under the original net profit share, the division said, the state might never have received royalties, because the cost to build the production island, pipelines and facilities to develop Northstar “greatly exceeded BP’s original estimate.”
“Under the original lease provisions,” the division said, “the state would receive net profit share payments only after the working interest owners recouped their development costs, which would be much later in the field life, if ever. In addition, the supplemental royalty provision is a greater benefit to the state due to the time value of revenue.”
The division said that the field cost issue has been a concern at other fields, but at Northstar provisions in the state leases require that royalty and supplemental royalty paid in value “shall be free and clear” of lease expenses, unit expenses and participating area expenses “including, but not limited to, expenses for separation, cleaning, dehydration, gathering, saltwater disposal” and preparing unitized substances for transportation.
“This exclusion shall also apply to royalty taken in kind,” the division said. “The working interest owners are not entitled to deduct field costs from the state’s royalty share of oil and gas produced from the Northstar unit.”
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