Friday, February 17, 2012

Oil Patch Insider: Point Thomson EIS schedule firms up, Exxon issues RFPs

—Kay Cashman
Petroleum News

Over the course of the last two years the construction and production schedule for ExxonMobil’s Point Thomson development has slipped from August 2011 to the fall of 2012, bumping construction startup from the winter of 2011-12 to 2012-13, and delaying startup of the 10,000 barrel-a-day of condensate project from 2014 to late 2015 or early 2016.

The reason for the delay — the U.S. Corps of Engineers’ work on the project’s environmental impact statement — is no longer an issue.

In early February, Hank Baij, project manager for the Corps, said the record of decision is now “scheduled to be completed this fall,” all of which might have something to do with Exxon issuing requests for proposals for the construction of the Point Thomson project that propose construction of gravel fill pads for drilling and hydrocarbon production, an airstrip, infield roads, infield gathering pipelines, a processing facility, as well as a 22-mile, gas liquids export pipeline to Badami.

The Point Thomson project has appeared to be on hold; most people assumed it was waiting on a settlement or a final court decision, the second of which is likely years away.

But Point Thomson has been progressing in two different, albeit related, directions: commercially and legally.

On the commercial side, in January 2009 Exxon made a promise to the state, under oath at a Department of Natural Resources hearing in front of Tom Irwin, then DNR commissioner, to drill two wells at Point Thomson and bring them into production by 2014, an offer that included processing facilities and a pipeline to Badami, the closest connecting pipeline to take the condensate to Pump Station 1.

Irwin required “a drill contract for each well, unconditional authorizations for expenditure for each well signed by all parties, an AFE for the production infrastructure, and affidavits from each appellant (Exxon, BP, Chevron and ConocoPhillips) stating its willingness to pay its share of the costs for each well and for the production infrastructure.”

In exchange, Irwin conditionally reinstated two of the 31 core Point Thomson unit leases for Exxon and the other lessees (see 2009 map at

The penalty for not bringing the leases into production by 2014 was the loss of those two leases. Presumably, force majeure, a contract clause that excuses a party from liability if some unforeseen event beyond the control of that party prevents it from performing obligations under the agreement, will protect the lessees.

Exxon and its partners have invested upwards of $700 million since 2008 in those leases, although they will be reimbursed for about half of that because of development and related credits in the state’s production tax regime.

At a Feb. 12, 2009, DNR hearing, Irwin asked Craig Haymes, then Exxon’s Alaska production manager, whether Exxon would complete the two wells and produce from them if DNR didn’t award any other leases in the unit to Exxon and its partners.

Haymes said yes.

On May 13, 2009, after an industry luncheon in Anchorage, Haymes said all issues regarding Point Thomson would have to be settled with the state or it would hold up permitting and impact the beginning of production.

The first two wells were completed in 2010, as promised.

On the legal side, Exxon is the winner to date in Superior Court, having prevailed in overturning DNR’s termination of the Point Thomson unit, but it was a win predicated on two points that the state has successfully requested the Alaska Supreme Court to review (first hearing was Feb. 8).

Moving forward with the condensate project has been part of Exxon’s legal strategy as well, so it remains to be seen what will happen to that project if there is no settlement between the parties.

But for now, it looks as though Exxon is moving forward as promised.