The Point Thomson unit owners, now focused on gas sales, want development of the field tied to a natural gas pipeline from the North Slope, not to deadlines set in a 2001 unit expansion which was negotiated when the owners planned to begin field development with oil sales.
Point Thomson is a high-pressure reservoir containing both oil condensate and natural gas on the eastern edge of state lands on Alaska’s North Slope, adjacent to the Arctic National Wildlife Refuge. A draft of the Point Thomson unit’s 22nd plan of development was submitted to the Alaska Department of Natural Resources Division of Oil and Gas in June by unit operator ExxonMobil. ExxonMobil, BP, Chevron and ConocoPhillips are the major working interest owners in Point Thomson.
The draft plan does not include development drilling by June 15, 2006, a requirement under the 2001 unit expansion, which also requires completion of seven development wells within the unit by June 15, 2008.
Instead the draft plan says the Point Thomson unit owners “have considered the most appropriate time to begin development drilling in the PTU and have concluded that field activities associated with development drilling should begin three to three and one-half years before field startup.” The draft plan says that would allow enough time for gravel pads to settle before drilling begins.
Work during the plan period (Oct. 1, 2005, through Sept. 30, 2006) “will include further development of the Gas Sales Conceptual Depletion Plan” developed during the previous plan period. The work is necessary, ExxonMobil said, to allow the unit owners “to participate in a potential open season for major gas sales from the North Slope of Alaska.”
Expansion terms geared to oil
Point Thomson leases were unitized in 1977.
By the terms of the 2001 unit expansion, the unit owners would contract the expansion acreage out of the unit and pay the state $20 million if development drilling does not begin by the 2006 date. If drilling begins, but the seven development wells are not completed by the 2008 date, the expansion acreage would contract out of the unit and the owners would pay the state $27.5 million. These payments are in lieu of what the state believes it could have gotten for the leases in lease sales if they had not been part of the unit.
In 2002 the unit owners decided not to drill a well on the western Red Dog leases at Point Thomson, and paid the state $940,000, as per the 2001 agreement.
In 2003, ExxonMobil requested a two-year extension of three deadlines in the 2001 agreement: a one-time election by June 15, 2003, to contract the unit; a requirement to begin development drilling by June 15, 2006; and a requirement to complete seven development wells by June 15, 2008. The Division of Oil and Gas extended the unit contraction deadline until Jan. 15, 2004, and increased the penalty from $8 million to $10 million, but declined to extend the other deadlines.
“It is premature to consider extending any of the other dates” in the decision, division Director Mark Myers said in a May 7, 2003, letter to ExxonMobil.
Standalone project not economic
In late 2003 ExxonMobil told the division that further work done in evaluating the Point Thomson resource had “resulted in a significant reduction in liquid resources.”
Point Thomson had been pegged at 400 million barrels of recoverable condensate and about 8 trillion cubic feet of natural gas. The division had been carrying Point Thomson oil reserves in its annual reserves report at 435 million barrels; in the division’s 2004 report that volume was reduced to 329 million barrels.
ExxonMobil also said that work during 2003 found increased facilities, permitting and environmental costs only partly offset by changes in development scope.
“Our conclusion is that a standalone project prior to gas sales is not economically viable under the current fiscal system,” the company told the division. The company said it was exploring other development plans, and discussing alternatives with the state, but said work requirements of the 2001 expansion agreement are no longer “aligned with the intent of the original agreement and not in the best interests of the State of Alaska.” ExxonMobil proposed a change in the requirements of the agreement through June 15, 2006: the owners could elect to contract the expansion acreage at any time until June 15, 2006, and would pay the $10 million (effective Jan. 15, 2004) plus an additional amount based on each month since Jan. 15, 2004.
The division responded in January 2004, telling the companies that it did not believe the Point Thomson owners had “made any specific proposals that would warrant a further extension” of the contraction election date.
Exxon appeals 21st plan
ExxonMobil submitted a 21st plan of development, in which the Point Thomson owners proposed to focus on gas. The Division of Oil and Gas wanted a broader review of hydrocarbon potential in the unit, and various drafts of the 21st plan were exchanged. The division issued a conditional plan in September.
ExxonMobil appealed provisions in the 21st plan of development requiring the owners to provide specific data to the state. The owners also required that the state sign a confidentiality agreement.
In a November 2004 decision, Commissioner of Natural Resources Tom Irwin said the primary question in the appeal was whether or not the division “is entitled to a copy of the data that was the basis for Exxon’s proposed 21st POD” and the division’s decision. The commissioner said the division was entitled to the data.
For several years, the commissioner said, the Point Thomson owners had focused on a gas cycling project: gas would be produced and condensate stripped from the gas and shipped down the trans-Alaska oil pipeline. The gas would be re-injected for later sale.
Once the unit owners determined that gas cycling was not commercially viable, they focused on producing natural gas rather than on gas cycling. The draft 21st plan of development, submitted in June 2004, focused on gas sales, rather than on gas cycling and condensate sales, but the division asked that the 21st plan “include plans to evaluate all potential hydrocarbon resources within the unit area and to evaluate alternate development scenarios.” The division also requested that the Point Thomson owners “provide specific technical data it needed to complete its economic analysis of the gas cycling project and provided Exxon with draft wording describing the type of data needed.” A revised plan included most of the changes requested by the division, the commissioner said.
The Point Thomson owners “agreed to provide some technical data, including digital data and interpretations, (but) the proposed plan did not commit to provide all of the technical data” the division needed for its evaluation of the plan of development.
A conditional approval of the 21st plan issued in September 2004 conditioned approval on Exxon providing copies of all of the data the division had requested no later than Nov. 15, 2004, and without the division executing a confidentiality agreement.
In October Exxon appealed the requirement that technical data be provided by Nov. 15 and the requirement that the 22nd plan include specific plans to fulfill the requirement to drill by June 15, 2006.
Division could have denied 21st plan
The commissioner said that since ExxonMobil, the unit operator, did not incorporate requested changes into the 21st plan, the director of the division could have disapproved the plan, rather than issuing a conditional approval. That would have left the Point Thomson unit without an approved plan, “which is a ground for default under the PTU Agreement.”
Irwin said Exxon said in its appeal that it could not be required to provide interpretations of confidential data and information. But, he said, documents on file with the division show that Exxon has been willing to share both information and interpretations, and proposed that division staff attend work sessions in its Huston office to review the data and to run scenarios on its proprietary models.
At issue in the appeal is whether Exxon can be required to provide copies of requested information to the division or can limit the review of certain information to its office in Houston, and whether Exxon can require a confidentiality agreement.
Exxon says gas cycling is not commercially viable and Irwin said the division needs to evaluate whether the proposed gas sales project will conserve resources at the Point Thomson field, “prevent economic and physical waste, and protect the State’s interests.” In order to make those determinations, the division needs the requested technical data, he said, needs “unfettered access to technical information” that is the basis of the Point Thomson unit owners’ decisions and needs access to that information in the division’s offices in Anchorage.
Irwin said the division also needs to have custody of the complete record that is the basis for its decisions, which it would not have if it is limited to viewing information elsewhere.
As for the confidentiality agreement, Irwin said statutes, regulations and the Point Thomson unit agreement “provide for submittal of confidential information.” The division is already required to hold data confidential upon request, and “interprets the regulations to extend confidentiality to all work product and internal interpretations that are based on confidential data.”
The division has provisions in place to secure confidential data, Irwin said, and “it is inappropriate for Exxon to condition provision of the requested information on the execution of a confidentiality agreement.”
Drilling requirement will stay
ExxonMobil also requested that a paragraph in the 21st plan decision requiring that the 22nd plan of development “must contain specific plans for development drilling” in the Point Thomson unit be struck from the decision. The commissioner said the division was reluctant to expand the Point Thomson unit by 39 percent in 2001, “given that no development had occurred in the unit during the preceding 24 years” and the unit owners “had no plans to develop the known reservoirs underlying the PTU in the foreseeable future.”
The division said in 2001 that approving the unit expansion was only in the state’s interest if the unit owners committed to development.
ExxonMobil has repeatedly said it cannot find a commercial development. It is appropriate, the commissioner said, that the division make clear “what it is and is not approving.” The division “agrees that it is appropriate for Exxon to evaluate development of the Thomson Reservoir through major gas sales from the North Slope, but Exxon is not relieved from the commitments” made in connection with the 2001 unit expansion.
Governor gets involved
The division did not get all of the information it wanted.
In February Alaska Gov. Frank Murkowski wrote to ExxonMobil Chairman and Chief Executive Officer Lee Raymond, requesting additional information. The data ExxonMobil provided in November was applicable to gas cycling development, the governor said, but the unit owners have said that is uneconomic. “I understand the unit owners are now studying alternative field development and depletion scenarios. I assume these include gas cycling followed by gas sales, gas sales without any gas cycling, and various simultaneous gas sales/gas cycling combinations.” The governor asked for reservoir simulation results for each scenario the owners have studied, and told Raymond that the state can’t conduct the required analysis “nor come to any meaningful conclusions as to the best path forward at Point Thomson without the requested data and an understanding of the options that are available to develop the field.”
In March, ExxonMobil presented information on Point Thomson development economics to the Department of Natural Resources and the governor’s gas cabinet and agreed to provide analysis of additional development scenarios and supporting data.
Royalty work under way
ExxonMobil Production told the division in April that the North Slope natural gas sponsor group (BP, ConocoPhillips and ExxonMobil) has proposed converting Point Thomson leases issued with different royalty provisions to the same fixed royalty. Some of the leases are net profit share, and the company said converting all of the royalty to the same fixed percent “would greatly simplify unit administration of royalty oil and eliminate the need for audit” of the net profit share leases.
ExxonMobil said the state requested that the Department of Natural Resources work with the sponsor group to agree on a fixed oil royalty percentage, and forwarded a confidential explanation of the methodology the company used to arrive at a recommended 14.5 percent blended royalty rate.
ExxonMobil said that in addition to the development scenarios mentioned in the governor’s February letter, Point Thomson development scenarios include: condensate sale only with creative gas storage options followed by gas sales; condensate sales only with creative gas storage followed by gas cycling at moderated injection pressures and final gas blow down in major gas sales; and development of Brookian oil accumulations as a standalone, as well as concurrently with the other two scenarios described.
