Oil Patch Insider

Agrium plant shutdown likely; Escopeta has good, not-so-good news; Mac gas line report out, Mazzolini leaves Conoco for FEX

They say three times is the charm. Let’s hope so. We think we’ve got it right this time.

A couple of weeks ago an Agrium contractor told Petroleum News the company’s Kenai Peninsula nitrogen facility would be shut down Nov. 1 through March 1, which was promptly reported via PN’s news bulletin service.

Lisa Parker from Agrium’s corporate communications department asked for a retraction, which PN did in another news bulletin.

Following that, in PN’s Oct. 15 issue, there was an article with the information we had acquired to that point — two contractors saying they had been told on Oct. 12 a shutdown was in the works for Nov. 1, lasting through March 1. PN also reported that Parker said no shutdown was planned.

But PN misunderstood Parker.

She meant no shutdown was planned specifically for Nov. 1.

Here’s what she had to say in a subsequent interview: “We are anticipating having to shut down the plants this winter. The timing of the shutdown will depend on the weather. … There is nothing magical about Nov. 1.”

When PN asked how much warning Agrium would have before a shutdown occurred, Parker said, “We have good communications with the gas producers. We will have enough notice to shut the plants down safely. Safely means ‘No one gets hurt.’”

PN pushed for a more precise answer in terms of hours or days. Parker said two to 24 hours.

Scott Jepsen, Cook Inlet manager for ConocoPhillips Alaska, addressed the general situation for the Cook Inlet basin at a recent energy conference in Anchorage. He said, “What happens on a very cold day is gas goes from industrial users (such as Conoco’s LNG export plant and Agrium’s nitrogen facility) to the utilities.”

On a cold day in Southcentral Alaska the utilities can ask for more natural gas, he said. “It’s an unwritten sort of agreement that we have, but it’s one that makes the whole system work.”

In other words, the industrial gas users in Southcentral Alaska give preference to the utilities that supply gas to homes and offices, making an Agrium facility shutdown as predictable as the weather.

Which explains Parker’s parting comment: “Let’s hope for a warm winter.”

—Kay Cashman

Report says Mac gas line profitable without subsidies

The report, released Oct. 19 by Jim Johnson of Pacific Analytics, an independent resource economics consulting firm, also says governments are failing to capture billions of dollars in potential royalties.

Commissioned by Alternatives North, a coalition of labor unions, environmental and church groups in the Northwest Territories, the report was recently filed with the panel reviewing the pipeline proposal, which would stretch from the Mackenzie Delta down the Mackenzie Valley and into existing gas infrastructure in Alberta.

Johnson used cost estimates of $7.5 billion provided by the gas project partners. He concluded there was an average rate of return of 21.5 percent even if capital costs increased by 30 percent for the full development.

The former Liberal government said it wouldn’t directly subsidize the project, but the current Conservative government has said it would consider buying an equity stake in the project in lieu of subsidies.

Johnson said the rate of return was likely to average 29 percent per year for the three anchor gas fields, but could be as high as 41.8 percent for the Taglu field owned by lead partner Imperial Oil. (Other partners in the project are Shell Canada, ConocoPhillips, Imperial Oil parent Exxon Mobil Corp. and the Aboriginal Pipeline Group.)

But Johnson, who used Norway’s royalty scheme as a model, also concluded that a taxation and royalty regime in which the public sector assumed a significant share of the risk in exploration and development would be better for taxpayers.

He said, “in return, the government takes a larger share of any windfall profits resulting from energy price increases.”

Johnson said his analysis showed that rates of return to the proponents would drop by only 2.5 percent if a Norwegian-style regime were used, allowing the government to garner $17.2 billion more over the 20 to 30 year life of the project.

Imperial has paused its negotiations on fiscal terms with the government while it reviews its cost estimates for the gas project, which had previously been pegged at C$7.5 billion (US $6.6 billion). Analysts have predicted it could now cost as much as C$10 billion because of inflation and cost increases in materials. In addition to the 750-mile pipeline, the Mackenzie Gas Project includes the development of the three anchor gas fields in northwestern Canada.

—Kay Cashman

Escopeta moves forward with Alexander drilling, jack-up

The good news comes from onshore where operator Escopeta has a Nabors rig lined up to drill its first well in Alaska at its North Alexander prospect. According to an Oct. 16 update from Bob Warthen, general manager of Alaska operations, everything is proceeding on schedule with that well expected to spud in January.

A natural gas prospect, North Alexander lies onshore on the northwestern edge of the Cook Inlet basin along the western margin of the Susitna River drainage, six to 10 miles north of the Stump Lake gas field and six to nine miles east of the Lewis River gas field — both of which have established gas production.

Escopeta has said there are three objectives at North Alexander — the Beluga and Tyonek formations (sandstones, siltstones and pebble conglomerates) and the shallower Sterling sandstones — which the Houston-based independent thinks hold almost 400 billion cubic feet of gas.

The not so-good-news comes from Escopeta President Danny Davis who issued this statement to Petroleum News Oct. 19 about the jack-up rig the company has under contract to drill its offshore Kitchen prospects in Cook Inlet early next year:

“The Songa Tellus will come to Cook Inlet in early 2007, as soon as weather allows — if the Tellus is finally ready and if Escopeta and Songa Drilling can iron out contract issues that arose because of refurbishment delays. Escopeta wants Songa to honor its contract, but if the Tellus isn’t available, Escopeta will contract a different jack-up rig to meet its 2007 drilling objectives.”

So what’s the scoop on the Tellus?

Escopeta cut the deal for the Tellus jack-up with Songa on March 3.

The independent-leg cantilever jack-up was supposed to be ready for pick-up by the Tai an kou, a heavy lift vessel that arrived in the Gulf of Mexico in June to pick it up for its trip north to Alaska’s Cook Inlet.

But Songa said it needed more time to finish a refurbishment of the Tellus, which was being done at a shipyard in Port Arthur, Texas. So, Davis renegotiated with Tai an kou’s owner, Coscol (HK) Investment & Development Co. of Hong Kong.

The vessel, he said, would be back in December to pick up the Tellus for the journey to Alaska.

But the news wasn’t all bad. The new schedule worked for Escopeta and its partner Centurion Gold Holdings.

“The timing works because it takes about 60 days to get up there, and leaving in, say, mid-to-late December puts us there at the end of February. If everything works out we could be drilling the first or second week of March,” Davis said.

“That gives us just enough time to drill our three wells before the end of the season,” he said.

Escopeta was also in the process of raising additional funding in London, so all around the change in scheduling was probably not a serious setback.

But days before the Tai an Kou arrived in the Gulf Abbot Holdings Norge AS made an offer for Songa Drilling.

That deal went through in July and included all of Songa’s jack-up rigs — the Songa Tellus, Songa Jupiter and Songa Neptune, rated at 250 feet, 300 feet and 350 feet respectively.

In June, the Abbot Group announced Songa Drilling had won a contract with Mexico’s national oil company Pemex for the Songa Jupiter, a drilling contract that was supposed to commence during the summer of 2006 with an initial duration of two years.

According to Abbot, the contract had a day rate of US $145,000 together with a fee of US $2 million for the mobilization of the rig from Texas to the location in Mexican waters.

In addition, Abbot said, Pemex would provide a substantial number of the required crew members, which Abbot said would substantially reduce Songa’s operating costs.

In Abbot’s announcement its Executive Chairman Alasdair Locke was quoted as saying, “We are very pleased with this award which Songa has been pursuing during our recent negotiations to acquire the company. The terms of the contract are well within our day rate expectations and will bring early cash flows to the acquisition.”

Makes one wonder what the new owners think of the day rate negotiated by Escopeta?

—Kay Cashman