The Alaska Division of Oil and Gas has rejected ExxonMobil’s 22nd plan of development for the 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 Mobil Corp. said in a statement provided by company spokeswoman Susan Reeves in an e-mail.
ExxonMobil is the Point Thomson unit operator; other major working interest owners include BP Exploration (Alaska), Chevron U.S.A. and ConocoPhillips Alaska. The four companies hold 98.9 percent of the unit acreage; 21 owners hold the remaining 1.1 percent.
ExxonMobil said the Point Thomson owners “believe the submitted POD 22 is a well-conceived plan to progress development efforts for the entire PTU. We intend to appeal the ruling and anticipate a mutually satisfactory POD 22 can be agreed,” the company said.
Oil and gas vs. gas only
The division and the Point Thomson owners have different perspectives, with the division pointing out that the unit has been in existence since 1977 with no oil or gas yet produced, while the owners note past drilling and focus on a potential upcoming North Slope gas pipeline project and on providing gas for that project.
“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.
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.
Unit operator ExxonMobil has 90 days — until Dec. 29 — 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 commitments would result in contractions of acreage added to the unit in 2001 and the leases contracted out would no longer be held by unitization.
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.”
The leases with wells certified as capable of production in paying quantities are required to be in production by Oct. 1, 2009.
There is a 20-day appeal period for the decision.
Owners focusing on gas
ExxonMobil 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.”
The company said that the 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. ExxonMobil, 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. ExxonMobil said the Point Thomson owners “do not believe additional drilling is required at this time for a gas sales project,” noting that 18 well 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, ExxonMobil 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.”
Discovery well in 1970s
The division said the Point Thomson resource is “a massive undeveloped gas and gas condensate reservoir” discovered in the 1970s. Unit owners “have determined that production of the unitized substances is, in their view, not commercially viable.” In the 22nd plan the working interest owners proposed “additional studies to determine if the PTU lessees can design a commercially viable production project,” the division said.
Also in the 22nd plan the unit owners said Point Thomson development would require that the state modify its “right to taxes and royalties on oil and gas production and on construction of a North Slope gas pipeline,” and proposed integrating Point Thomson obligations into negotiations for a fiscal contract under the Alaska Stranded Gas Development Act and delaying by two years the development commitments the unit owners made when Point Thomson was expanded in 2001.
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 of 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.”
2001 expansion based on gas cycling
Myers said the Point Thomson owners based the 2001 expansion on a gas cycling project: produce the condensate, ship and sell the liquids and reinject the gas. The unit, formed in 1977 at 40,768 acres, grew to 106,200 acres, 45 leases, as a result of the 2001 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 ExxonMobil 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.
Benefits to re-offering leases
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. The current leases drew bids of nearly $146 million, “and could attract significantly higher bid bonuses today,” he said.
There would also be the potential for increased royalty rates. Most of the original leases carry a 12.5 percent royalty, and the division could increase the royalty if it re-offered the leases. Some of the royalty rates were increased as a part of the expansion areas, with seven of the leases having a royalty increase from 16.67 percent to 20 percent and one lease increasing from 12.5 percent to 16.67 percent.
Myers also noted that if the unit was terminated and the acreage re-offered, the state “might attract new lessees who may bring new ideas and energy as well as new geologic interpretations, engineering, development timelines and marketing perspectives to develop the area.” The current owners, he said, “have had the leases for far beyond their primary term, and their conclusion today is simply that they cannot make enough money to justify development. It is time for the PTU owners to develop and produce or give new lessees a chance to develop the known hydrocarbon resources within the PTU.”
There are wells that have been certified as capable of production in paying quantities, he said, and if the current owners “have been unable to identify a commercial project in nearly 30 years, it is time to terminate the unit and re-offer the acreage to new lessees who will have the opportunity to develop the state’s resources in a timely manner.”
Myers said the division has given the Point Thomson owners “many opportunities over the years to develop” the unit.
“It is not in the public interest to grant a state lessee an indefinite extension on development merely because development in their view is not currently profitable enough or is too risky,” he said.
The intent of leases “is to give producers an opportunity to explore, develop and produce within the primary term of the lease. That intent has been met and exceeded in this case. It is not in the public interest to change leasehold intent by allowing a lessee’s parochial interests to supersede the state interest for orderly and reasonably prompt development.”
The state’s primary interest in leases is development of hydrocarbons which yield oil and gas revenue, he said. “The state’s interest is not met by allowing the producers to delay production until such time as the lessee determines that it is the lessee’s optimum time to develop a known resource or the state agrees to compromise its tax and royalty system.”
