Analysis by Tim Bradner
Alaska Journal of Commerce

State Natural Resources Commissioner Tom Irwin based his decision to reject ExxonMobil Corp.'s $1.3 billion Point Thomson unit development project on the history of the state's attempts to get the companies to drill wells and do engineering studies related to development of gas and oil resources.

Irwin's decision details the long history of the unit and repeated frustrations state officials have had with the companies' efforts and says his decision to protect the public interest is best served by terminating the Point Thomson unit, which will also end the state oil and gas leases the companies hold.

Some of Irwin's assertions, however, are at odds with an account of the historical record presented under a sworn affidavit by ExxonMobil Corp.'s Alaska production manager, Craig Haymes.

Also, a key difference between earlier plans and what is now proposed is that the companies have made a clear commitment to put the project into production, Haymes said. This has never been done in previous agreements with the state.

Despite the commissioner's complaints Irwin also said good things, albeit grudgingly, about the gas cycling and condensate production project proposed by the companies at Point Thomson, ExxonMobil, BP, Chevron and ConocoPhillips.

“The plan may present a technically reasonable first step for developing these lands,” Irwin wrote on page 31 of his 75-page decision.

Irwin also acknowledged, on page 37, that a project to produce condensates and recycle gas, which is what the companies are proposing, is necessary to prevent large losses of condensate liquids at Point Thomson once a gas pipeline is built and gas production starts at Point Thomson.

“Primary depletion as a gas field (without prior production of condensates through a gas cycling project) is the least efficient and results in the lowest hydrocarbon recovery,” Irwin wrote in the decision.

While the commissioner criticized the companies in several places for proposing a “modest” project that does not fully realize the potential of the large Point Thomson resource, Irwin also said, on page 47, “designing production facilities on a small scale initially and expanding them once the best method of producing a reservoir is known,” may lead to the most efficient development of the resources.

On page 55, the commissioner criticized the companies for not offering “meaningful performance benchmarks” when in fact, performance measures were proposed. He said the companies “could have offered financial penalties to compensate the state for delayed production and lost revenue.”

However, on page 71 the commissioner, in what seems a contradiction, said, “DNR is exceedingly wary of relying on penalties or other types of assurances.”

Much of the Irwin's decision is devoted to details of past dealings the Department of Natural Resources has had with ExxonMobil and its partners on Point Thomson. The assurances the companies are giving now that they will proceed with the gas recycling project are very similar to assurances they gave in previous commitments, which made Irwin doubt they are serious this time, he wrote in his decision.

“The clear pattern established by the history of this unit is of broken development commitments, recalcitrance and repeated efforts to delay rather than bring the substantial hydrocarbon resources in this area to market,” Irwin said.

“It appears that (the companies) made the decision in 1983 to treat the unit as a gas reservoir and hold it until they believe it served their interests to produce and market the gas. The unit history after 1983 reveals a constant shell game where (the companies) induce DNR to approve plans of developments and expansion agreements only to consistently renege on commitments, allowing the (companies) to warehouse this vast resource.”

ExxonMobil said that the lack of a gas pipeline and technical complexities of the Point Thomson reservoir made development uneconomic over most of its history.

The bulk of the $800 million spent by the companies at Point Thomson was in drilling and reservoir studies in the early years. By 1983 the companies realized a gas pipeline, the only way to market Point Thomson gas, was many years away and shifted their focus to a gas recycling project and condensate production project as the only way to get Point Thomson into production, Haymes said.

Development of small oil pools also discovered are most efficiently done as a part of the larger recycling project, Haymes said.

Irwin said there were specific instances where the companies promised to drill wells, such an exploration well in 1985 and a second well in 1990, and to consolidate technical information among themselves. These were not done.

In his affidavit, submitted to DNR after the agency's March hearings, Haymes presented a different picture of events.

The companies complied with commitments in every plan of development for Point Thomson, Haymes said in the affidavit. The wells Irwin cited were commitments made under separate agreements made to expand and add acreage the Point Thomson unit, not the plan of development. The expansion agreements gave the companies the option of not drilling the wells, in which case the unit would be “contracted” (with the added acreage returned to the state) and, in some cases, cash penalties paid.

That happened in each of the cases where the wells were not drilled. Most recently, the companies paid a $20 million penalty in connection with wells committed to in 2001, again under an expansion agreement, but not drilled.

Work on a gas recycling and condensates production project continued through the 1990s, but the technical complexities of the project blocked progress until 2000, when the companies felt they had made enough progress to make a serious proposal to the state.

The plan was similar to one proposed now but larger. It involved a multi-billion-dollar investment and would have allowed 70,000 barrels per day of liquid condensates to be produced, with the gas injected back into the reservoir. The plan proposed now involves 10,000 barrels per day of condensate production.

The companies seemed confident of the project and even told the state, according to Irwin's account, that no more drilling was needed to investigate technical aspects of the reservoir.

But in presentations to several Alaska business groups at the time, ExxonMobil acknowledged that the project posed huge technical challenges, mainly in the ability to safely drill wells into the high-pressure Point Thomson reservoir and inject gas that was produced back into the reservoir at pressures above 10,000 pounds per square inch, which would require compression equipment at the limit of available technology.

DNR seemed pleased to finally see progress, however. An expansion of the unit to include more acreage was agreed and a commitment was made by ExxonMobil to drill an exploration well in the 2002-2003 winter season along with commitments to drill production wells to support the gas recycling project in 2006 and 2007.

Irwin acknowledged in his account that the 2006 and 2007 commitments were conditioned on whether the gas recycling project was viable. The companies also agreed to the $20 million penalty if the production wells were not drilled.

The 2003 exploration well was not drilled, Irwin noted in his decision, and Haymes acknowledged this in his affidavit, but cited changes in the gas recycling project plan that caused the delay. State, federal and North Slope Borough officials were informed of the changes at the time, the affidavit said.

In late 2003, ExxonMobil informed DNR that the gas recycling project, as it was proposed in 2000, was not economically viable. Additional reservoir studies had raised new questions about the quality of the reservoir and how efficiently fluids would flow through the rock, issues which are vital to a gas recycling project.

Through 2004 the companies pursued technical studies of gas production from the field to supply a gas pipeline, but also continued work to see if some form of gas recycling project was possible, Irwin said in his account.

However, the commissioner said that when the DNR asked for copies of reservoir data and other technical studies to evaluate and verify the conclusion that gas recycling was uneconomic, the request was denied. At this point, relations between ExxonMobil and the DNR deteriorated again.

However, in his affidavit Haymes said the companies did supply substantial data to the state but that the state kept changing its requests, asking for more information.

In a 2005 interview, then-Division of Oil and Gas Director Mark Myers said the DNR felt the recycling project might be viable for some companies but might not have met ExxonMobil's internal threshold for profitability.

The companies argued that given the uncertainty of how well the project would perform there was a huge risk that the several billion dollars of investment in leading-edge production and gas compression facilities would be wasted, since the facilities could not be alternatively used, at least fully, in a straight gas production project.

Through 2004 the investigations of a smaller gas recycling project as an alternative did not pan out. By 2005 the companies were in discussions with the state on a gas pipeline and their thinking on Point Thompson had shifted from gas recycling and liquids production to a straight gas production project when a pipeline was built.

Meanwhile, there were still the commitments to drill production wells beginning in 2006 as well as the $20 million penalty the companies had agreed to if the wells weren't drilled. Realizing that production wells without a gas recycling project didn't make sense, state oil and gas director Mark Myers said in interviews that he was willing to renegotiate the commitment to the drilling of one exploration well into the reservoir to clear up uncertainties on characteristics of the rock.

The request was turned down and Myers, irritated by this time, issued a default notice, beginning a train if events leading to the formal termination of the unit in 2006 and the current litigation. The $20 million penalty was paid by the companies.

It is also unclear whether the exploration well Myers proposed as an alternative would have fully answered questions about the reservoir. Uncertainties on how efficiently fluids will flow through the rock will only be answered when a recycling project is actually done.

In the light of the history, the smaller-scale gas recycling project now being proposed as a remedy to the state's action to terminate the unit, could have been agreed to in late 2004 when they concluded a smaller project wasn't workable.

The differences between the two projects are only partly in scale, however. What ExxonMobil is proposing now involves a smaller project that is designed to produce 10,000 barrels per day but to be expanded if the gas recycling works perhaps even to 70,000 barrels/day as envisioned in 2000. The project is also designed to be efficiently converted to a conventional gas production project if recycling doesn't work, so the investment won't be lost.

There has also been progress made with drilling and compression technologies needed for high-pressure fields. ExxonMobil is much more confident now that it can deal with these than it was in 2004, Haymes said.

Irwin concludes his decision by arguing the public interest is best served by rejecting the gas recycling project, terminating the Point Thomson Unit and taking the leases back.

However, the commissioner does not explain how delays involved in taking the leases back, dealing with the litigation involved, and releasing the acreage to other companies and possible added delays caused by further litigation, better serves the public interest than allowing the companies to go forward with the plan they have proposed.

Irwin acknowledges, on page 40 of his decision that, “delayed production is potentially a significant cost to the state.”

There are other consequences the commissioner doesn't consider if the delays also impair an open season for a gas pipeline planned in 2009 under a proposal by TransCanada Corp. or 2010 by BP and ConocoPhillips with their Denali pipeline project. Point Thomson's estimated 9 trillion cubic feet of gas are a significant part of the 35 trillion cubic feet of gas needed for the pipeline, and as long as the ownership of Point Thomson is in doubt that gas cannot be committed to a pipeline.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.