Progress made on LNG line, but key benchmark missed


Once one of the largest employers and taxpayers on the Kenai Peninsula, Agrium Inc. shuttered its fertilizer plant at Nikiski in 2007 because of dwindling supplies of natural gas in Cook Inlet. With the supply picture on the rebound, Agrium has initiated the permit process to reopen the plant. Its neighbor, the ConocoPhillips LNG plant, may also resume exports after being idled in 2012.


North Slope producing companies and TransCanada Corp. continued work on a large natural gas pipeline and liquefied natural gas export project in 2013, making significant achievements but failing to reach a key benchmark for Gov. Sean Parnell that the companies have a formal agreement among themselves as to how the project is to be structured.

The most important accomplishment by the group was the selection of Nikiski, on the Kenai Peninsula, as the terminus of the pipeline and the location of the LNG plant. Other locations had been considered including Valdez but there were several advantages cited for Nikiski, mainly that land was available for the large plant facilities and for future expansion of the plant.

Parnell had also requested also that the companies advance the project into Preliminary Front-End Engineering and Design, or pre-FEED, by June 30, but that was not done. As a result, Parnell said he would not ask the Legislature to take up gas production taxes in the 2014 session.

The pre-FEED step would involve expenditures of several hundreds of millions of dollars and would represent the first significant investment by the companies in the project.

The companies did mount a significant summer field season in 2013 to gather geotechnical and environmental data. Project expenditures by the end of the year were estimated to reach about $100 million.

Meanwhile, the state received the results of a study by Black & Veatch that recommended Alaska take an equity stake in the gas pipeline of as much as 25 percent.

If the state were to invest in and own a share of the project equal to its one-eighth share, or perhaps as much as 25 percent if the tax obligation was included, it could better align the interests of the parties, state Natural Resources Commissioner Joe Balash said in an interview.

“Having a direct stake could solve a lot of problems for us and the project sponsors,” Balash said.

The producers and the state would each finance a share of the project sufficient to ship gas each party owns, he said. It would also spread risks, like cost overruns, more equitably.

Black & Veatch said the improved profitability of the overall investments could make the difference in making the project attractive enough for the producers to back it.

If the state having a stake in the project solves a problem for the companies, it helps the state with other difficulties, Balash said. As an owner the state would have to the inner workings of the project finances, which would help ensure the state’s tax and royalty collections wouldn’t be disadvantaged, he said.

Ensuring fair payment for tax and royalty assumed even more importance after the project switched from the original plan for an all-land pipeline to the continental U.S. to a pipeline and a large natural gas liquefaction project serving an export market.

Much of the state’s previous work on royalty terms became obsolete when the plan switched to include LNG, Balash said.

In its conclusions, the report stated: “Direct state equity participation in the (gas) project can provide key benefits to the state including alignment of interests (among the parties), transparency through the midstream portion of the supply chain, facilitation of third-party access to the midstream and potentially improved state cash flows along with improved producer economics.”

2. Cook Inlet rebound — LNG exports, Agrium could resume

The revival of Cook Inlet’s oil and gas industry continued at a rapid clip through 2013. The Inlet’s oil production is small compared with the North Slope but is increasing fast, up 18 percent since last year and 50 percent since 2010, according to state officials.

Cook Inlet oil production is important to Tesoro’s Kenai refinery, a major source of fuel for the Alaska market, because the refinery is designed to process the lighter crude oil produced in the Inlet. Absent that, Tesoro must purchase North Slope oil, which is heavier, and ship it by tanker from Valdez, or import oil from overseas.

The increasing oil production is mainly the work of Hilcorp Energy, which purchased producing fields from Chevron Corp. in 2012 and is investing heavily in stimulating aging producing wells.

Natural gas supplies in the region have also rebounded, to the relief of local utilities who depend on gas and who worried about declines in gas reserves as older fields were depleted.

The investment by Semco Energy, parent of Enstar Natural Gas, and Mid-America Energy Holdings in a gas storage facility on the Kenai Peninsula has resolved, for now, worries about mid-winter gas delivery problems during cold weather. Gas stored in the facility during the summer is now withdrawn in winter, when local utility needs are at peak.

Gas reserves are also increasing thanks again to work by Hilcorp in the older gas fields. Needs by the local utilities are now met through early 2018. Exploring companies, such as Buccaneer Energy and Furie Operating Alaska, are also making new gas discoveries.

As 2013 comes to a close, efforts are underway to rebuild the Kenai Peninsula’s petroleum manufacturing industrial base. ConocoPhillips announced that it has applied for federal permits to resume exports of liquefied natural gas from its mothballed LNG plant on the peninsula. If the permits are granted the plant could reopen.

Meanwhile, Agrium Corp. is engaged in technical and engineering studies on a possible reopening of its closed fertilizer plant, also on the peninsula. Agrium has also applied a for a federal air-quality permit for the plant and has begin air monitoring to support the permit application.

Agrium said more engineering studies are needed to determine the feasibility of restarting the facility, and those are expected to be underway in 2014. Agrium was a major employer and taxpayer on the peninsula in the years the plant operated, from 1969 to 2007.

The ConocoPhillips plant also began operating in 1969, then owned by Phillips Petroleum (now ConocoPhillips) and Marathon Oil. ConocoPhillips eventually purchased Marathon’s minority stake in the plant.

The plant was affected by declining Cook Inlet gas reserves and was put into “mothball” status in 2012 when export shipments of LNG stopped. ConocoPhillips maintained the plant for a possible restart, however, and there were no layoffs of the plant workforce, which totaled 50 to 60.

3. ExxonMobil begins construction at Point Thomson

ExxonMobil began construction of a gas cycling and condensate production project at the Point Thomson field in 2013. Significant accomplishments last winter included the completion of roads and pads, an airport and a permanent camp at the field, which is about 60 miles east of Prudhoe Bay.

Vertical support members to support a 20-mile pipeline were also installed last winter. The pipeline will be completed this winter.

Installation and tie-in of major gas processing and injection facilities is planned for the winter of 2014-15, and a drill rig will be moved back to the field for more work on wells.

Point Thomson is expected to go into production in 2015. About 10,000 barrels per day of liquid condensates will be produced and shipped to Prudhoe Bay, where the condensates will be mixed, or blended, with crude oil in the Trans-Alaska Pipeline System.

Natural gas produced along with the condensates will be injected back underground, into the producing reservoir.

Point Thomson is still considered a kind of test project because ExxonMobil and its partners, which include BP and ConocoPhillips, are unsure just how well the gas cycling will work in the reservoir, knowledge that is unavailable until the field is actually producing.

If it performs well the gas cycling and condensate production can be stepped up. If the performance is disappointing the facilities being built can be used to support conventional gas production once a gas pipeline is built. Alternatively gas from Point Thomson can be shipped to Prudhoe Bay and used to repressure that field to produce more oil.

4. Shell Arctic effort stalls

Shell was unable to return to the Arctic in 2013 after losing its drill vessel Kulluk in a storm near Kodiak last Dec. 31. The Kulluk grounded and suffered serious damage to the extent that it could not be used in a 2013 Arctic exploration program and it is now considered a total loss.

Another drill vessel used by Shell, the drillship Noble Discoverer, had also developed engine problems. That, combined with the unavailability of the Kulluk to act as a back-up rig in case of an emergency, forced Shell to put its high-profile exploration in the Arctic on hold for a year.

The company hopes to return to the Arctic in 2014 but with another backup drill vessel, the semi-submersible rig Polar Pioneer. The company announced that if it is allowed to resume exploration in 2014, its efforts will be limited to the Chukchi because the Polar Pioneer is required to act as a backup in case a relief well needs to be drilled, and Shell lacks a third rig to drill in the Beaufort after the Kulluk was lost.

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