At this time only one facility-sharing agreement for production exists between North Slope producers and a non-facility owner and that was negotiated between Kuparuk River unit operator ConocoPhillips and Jim Weeks, managing member of Winstar Petroleum, for his company’s Oliktok Point State No. 1 well. The well, which turned out to be a duster, was drilled in 2003 from onshore drill site 3-R on the northern edge of the Kuparuk River unit to an offshore target was that part of Winstar’s lease.
Weeks, who believes in getting a facility-sharing agreement for production in place before drilling exploration wells, is headed back into negotiations with North Slope producers. This time he is hoping to get an agreement put together for the exploration and development of leases west of the Point McIntyre operating area – leases that are owned by Winstar’s sister company, UltraStar Exploration LLC.
At Prudhoe Bay, where some Point McIntyre oil is processed, it will “only take the Big 3 to make it happen,” Weeks said, because the Prudhoe Point McIntyre Participating Area owners require only 90 percent approval of a facility-sharing agreement.
“The structure of the Point McIntyre deal will probably need to be different than the one at Kuparuk, but the substance shouldn’t be much different since the same three companies have already agreed once to a deal for us non-unit participants. At least there is precedent out there,” Weeks said.
The KPA owners require 100 percent agreement for all non-owner use of Kuparuk River unit facilities and pipelines, which meant Weeks had to win the approval of ConocoPhillips, BP, Unocal, ChevronTexaco and ExxonMobil.
Only two of the owners — ConocoPhillips and BP — were bound by a charter agreement with the state of Alaska that required them to provide reasonable access to their North Slope infrastructure.
“It was a tiny deal for the big guys. Not a lot of money in it for them; more headaches and dilution of their attention away from more leveraging issues,” Weeks said, quick to point out that the intentions on the part of the KPA owners were always to make the deal happen.
“They’re clearly willing to put agreements together to enable a little guy like us to do something up there. It just took us a long time to put the deal together at Kuparuk,” Weeks said, crediting that to the fact it was the first deal of its kind with a non-facility owner.
Backouts the biggest hurdle
The biggest economic challenge in North Slope facility-sharing agreements, Weeks said, is the cost of the backouts, which can “make or break an independent’s economics.”
Backouts represent the amount of oil (owned by the facility owners) from mature fields that must be deferred in order to make room for new oil. The oil from mature fields often has a high water and/or gas content, which can push a processing facility’s water and gas handling capability to the max and so oil from those wells often has to be backed out to make room for new wells.
North Slope facility owners want to be compensated for the amount of their own oil that they have to back out of the system in order to free up capacity to process the new oil.
At Kuparuk, ConocoPhillips uses a computer simulation program to model the day to day processing operations at the facilities which has resulted in a “detailed dynamic plant model,” from which a complex backout methodology is created. Non-facility owners are not allowed access to the model and so have to trust in what the facility operator tells them.
This resulted in non-facility owners stressing the need for a more transparent methodology; perhaps simpler models to be built which were accessible by all, Weeks said.
But after working with the North Slope producers, Weeks is no longer as concerned about transparency.
“One of my objections to backout was it was a giant ‘trust me,’ but I got beyond that. I don’t think they (major North Slope producers) will purposely rig the numbers. I think they will model it straight up the way they see it.”
Backout costs can be 30-50% per barrel
Weeks said if a non-facility owner is looking at testing what he thinks will be a small North Slope field – 50 million barrels or less – he should “get somewhat of an understanding of which facility it’s going to have to go into and what constraints that facility has in terms of backouts and fees. You can’t firm up the costs – but the costs can be staggering.”
Backout costs alone for going into the Kuparuk unit, he said, can be as high as 30 to 50 percent of your per barrel development cost.
“In our case (with Oliktok Point State No. 1 well), we could drill from an existing pad on the road system so we didn’t have the expense of an ice road and ice island to deal with. … (and) CPF3, which we were going into, wasn’t as heavily loaded.”
One of the biggest hurdles with backouts is that the North Slope facility owners do not include in their backout calculation the possibility of being able to produce the backed oil at a later date. It’s calculated as lost forever, which is not what state officials and Petroleum News’ oil industry sources say happens in other parts of the world.
Weeks agreed it was a problem. “That was my biggest objection, but they (North Slope facility owners) argued that on a present value basis we would get it back so late that is would be worthless; plus they have concerns that their field may not have enough life in it to ever allow for the deferred oil to be produced.”
