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THE EXPLORERS 2005: Exxon’s Point Thomson unit in default State of Alaska rejects plan for Exxon’s undeveloped unit on eastern North Slope adjacent to ANWR Kristen Nelson Petroleum News
The state Division of Oil and Gas has rejected Exxon’s 22nd plan of development for the eastern North Slope Point Thomson unit and found the unit in default “for Exxon’s failure to submit an acceptable unit plan of development,” telling the unit owners that if they do not develop the unit the state will terminate it and put the leases up for sale.
“ExxonMobil and the other owners are disappointed with this denial and disagree” with the decision. “This denial will be appealed,” Exxon spokeswoman Susan Reeves said in an Oct. 4, 2005 email.
Exxon is the Point Thomson unit operator; other major working interest owners include BP, Chevron and ConocoPhillips. The four companies hold 98.9 percent of the unit acreage; 21 owners hold the remaining 1.1 percent. Oil and gas vs. gas only The Point Thomson unit has been in existence since 1977 with no oil or gas yet produced.
“Continuing this 30-year record of non-development and delay of an oil and gas lessee’s obligations to develop and produce its oil and gas leases makes a mockery of the statutory, regulatory and contractual protections for the state as owner of the oil and gas estate. Therefore, the 22nd POD is unacceptable,” division Director Mark Myers said in a final decision issued Sept. 30, 2005.
The 22nd plan of development was rejected because it “makes no commitment to timely develop and produce PTU oil, gas, or gas condensate,” he said. Since the unit agreement for Point Thomson requires an approved unit plan, the unit was in default Oct. 1.
The owners defend their position by pointing to past drilling, and focus on marketing Point Thomson gas via the proposed North Slope gas pipeline.
The state, in turn, refers to the 2001 unit extension, which the Point Thomson owners based on a gas cycling project, which the owners said might occur before natural gas was produced. A gas cycling project would produce the condensate and oil in the unit, reinject the natural gas, and ship and sell the liquids through a line connecting to the existing trans-Alaska oil pipeline. Deadline is Dec. 29, 2005 Unit operator Exxon has 90 days — until Dec. 29, 2005 — to submit an acceptable plan of development, which “must contain specific commitments to timely delineate the hydrocarbon accumulations underlying the PTU and develop the unitized substances,” including: plans to bring the Thomson sand reservoir into commercial production; plans to explore, delineate and produce “other hydrocarbon accumulations and lands that lie stratigraphically above or below” the Thomson sand; sanctioning of a commercial Point Thomson development project by Oct. 1, 2006, and providing the division “with evidence of corporate approval and commitment of project funding,” the division said.
Myers said an acceptable plan would include beginning commercial production from Point Thomson by Oct. 1, 2009; and provision of details of operations to fulfill the 2006 development drilling commitment. Failure to fulfill the 2006 drilling commitment would result in contractions of acreage added to the unit in 2001.
Development operations are required to begin by Oct. 1, 2007, and the Point Thomson unit owners “shall have an opportunity for hearing regarding this notice to modify the rate of PTU development.”
Myers said the division would contact Exxon to schedule a hearing on the issue, “which will be held not less than 30 days from the date of this decision.” Owners spend $50 million-plus Exxon said in its statement that the unit owners have “spent significant funds (over $50 million) on engineering, resource definition and permitting efforts on the PTU Gas Injection Project (GIP), which turned out not to be commercially viable under current fiscal terms.”
Point Thomson unit owners “are conducting technical work necessary to develop the PTU as a gas sales project” in parallel with the sponsor group’s application to the State of Alaska for a fiscal contract for a gas pipeline under the Alaska Stranded Gas Development Act. Exxon, BP and ConocoPhillips are the members of the sponsor group in negotiations with the state. In negotiations over the 22nd plan the state said the Point Thomson owners could substitute an exploration well drilled in 2006 in place of beginning development drilling. Exxon said the Point Thomson owners “do not believe additional drilling is required at this time for a gas sales project,” noting that 18 wells have been drilled in or near the unit.
The request for an extension of the expansion leases’ drilling commitment was tied to a gas sales project, Exxon said. As for an exploration/delineation well, the company said, there isn’t justification for such a well, although the owners offered to jointly evaluate the value of such a well with the state “to see if sufficient justification could be identified for such a well.” 2001 expansion based on gas cycling Myers called the premise that Point Thomson can only be developed if there is a North Slope gas pipeline “inappropriate,” noting that in addition to the gas, estimated at 8 trillion cubic feet and 200 million barrels of condensate and oil, there are hundreds of millions of barrels of liquids in the shallower Brookian reservoirs.
“These hydrocarbon liquids could be produced using mostly existing oil pipelines without construction of a North Slope gas pipeline,” he said. While there is no oil pipeline extending into the Point Thomson unit, there is an oil pipeline to the Badami unit, some three miles from the border of the Point Thomson unit.
And, Myers said, while the Point Thomson unit agreement “requires timely exploration, delineation, development, and production of unitized substances, (it) does not guarantee the lessees’ commercial success or provide for indefinite extension of the leases.”
The unit grew from 40,768 acres in 1977 to 106,200 acres as a result of the 2001 expansion agreement. Because the unit owners were not certain of the success of a gas cycling project, which they were still evaluating, the 2001 agreement included an option for the unit owners to drop the expansion acreage in return for a payment to the state of $8 million (compensation for unrealized bonus payments when the acreage was withheld from lease sales) if the project proved uneconomic by June 15, 2003. That deadline was extended to allow the owners time to further evaluate the gas cycling project.
In October 2003 the unit owners told the state that their evaluation of a gas cycling project had “indicated higher costs and lower liquid recovery” than previously estimated. In December 2003 Exxon told the state that the engineering and resource evaluation work the owners had completed confirmed that development of Point Thomson was challenged: there was a significant decrease in expected condensate recovery under the proposed gas cycling plan and the project was more expensive than originally projected, changes significant enough that Point Thomson development could no longer be justified on a standalone basis prior to natural gas sales.
At that time the owners could have surrendered the expansion acreage for a payment of $10 million, but the division stuck to its requirement of development drilling by June 15, 2006, or all of the expansion acreage would contract and $20 million would be due.
If the Point Thomson unit terminates and the leases expire, the division “could re-offer the acreage for lease in future lease sales and impose work commitments in the new leases,” Myers said.
There would be a number of benefits to the state including replacing old lease forms with modern forms and the bonus bids that would be received at a sale. There would also be the potential for increased royalty rates, he said.
Editor’s note: The decision is posted on the division’s Web site: www.dog.dnr.state.ak.us/oil
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