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Providing coverage of Alaska and northern Canada's oil and gas industry
June 2006

Vol. 11, No. 23 Week of June 04, 2006

Future of Nikiski LNG plant uncertain

Stone & Webster report says continued export of liquefied natural gas after 2011 dependent on new gas supplies, plant renovation

Alan Bailey

Petroleum News

In a recent report commissioned by the Alaska Natural Gas Development Authority, Stone & Webster Management Consultants has predictably concluded that the future of the LNG plant on Alaska’s Kenai Peninsula is uncertain.

The Nikiski plant, owned by Marathon and ConocoPhillips, began exporting liquefied natural gas in 1969 when the Cook Inlet Basin enjoyed a major surplus of stranded natural gas.

But today, with Southcentral gas production starting to drop below local demand and a federal LNG export license due for renewal in 2009, people are speculating on how long the plant can continue in operation.

The ANGDA-commissioned report looks at some future options for the plant, showing how the viability of each hinges on uncertain future economic factors and providing perspectives on what might drive the ultimate decision on the plant’s future.

Harold Heinze, ANGDA chief executive officer, told Petroleum News in late May that the intention of the report is to provide some general information to Alaskans about future options for the plant, assuming that the federal export license would be renewed. It also discusses in less detail what might happen should the license not be renewed (see sidebar).

And, although the plant has been exporting LNG to Japan since 1969, Stone & Webster assume that will stop and instead uses LNG delivery to the U.S. West Coast as the basis for assessing the plant’s future viability.

Exporting to the West Coast would require a waiver to the federal Jones Act for the LNG carriers that serve the Nikiski plant (the Jones Act requires U.S. flagged vessels be used between U.S. ports). However, Heinze said that, in the event of a waiver not being granted, alternative export routes to western Canada or Baja California involve similar economics to U.S. West Coast delivery. Or a cross-trade with Indonesia, in which LNG carriers transporting Indonesian LNG to the West Coast would then deliver Alaska LNG to Japan, would also result in similar economics, he said.

The report says that a key factor in the future economics of the plant is aging equipment. In particular the General Electric Frame 5 combustion gas turbines that drive the LNG compressors have been in continuous service for 37 years and “will require replacement in the next five years,” the report says. And since the replacement of the turbines and the associated upgrade of the facility is likely to be very expensive, the need to upgrade would likely trigger a shutdown of the facility in its current form, unless additional gas reserves become available to justify investment in a new plant.

“These new reserves could be in the Cook Inlet basin or provided via a spur pipeline constructed from the North Slope gas transmission pipeline,” the report says.

However, the report focuses on the economics of obtaining continuing gas supplies using the gas spur line option.

Maintaining current capacity

The current LNG plant capacity of 220 million cubic feet of natural gas per day forms part of a Southcentral Alaska peak daily gas demand that may run as high as 800 million cubic feet per day in the winter, with an average demand of about 500 million cubic feet per day, the report says. Those demand levels would suggest the need for a spur line capacity of 1 billion cubic feet per day, “to ensure year-round supply to domestic and industrial users.”

Under that scenario Stone & Webster has estimated the capital cost of doing a like-for-like replacement of equipment at the LNG plant to be $300 million, with an annual operating cost of $60 million. Economic analysis indicates that, at those costs, the plant would be viable at a price of $2.10 per thousand cubic feet for liquefying gas in the plant, assuming a payout period of three years for the plant costs. Add in estimated pipeline tariffs for shipping gas from the North Slope and transportation costs for delivering LNG to the U.S. West Coast, and you arrive at a price uplift of $3.10 per thousand cubic feet over the base price of North Slope natural gas.

Assuming a netback price of $2.50 per thousand cubic feet for the North Slope natural gas and adding in downstream gas processing and transportation costs of 50 cents per thousand cubic feet results in a West Coast delivered price for natural gas of $6.10 per thousand cubic feet. That compares favorably with recent Henry Hub gas prices in the Lower 48, thus suggesting that the LNG plant modernization would be viable.

Increasing the capacity

But it might also be possible to upgrade the LNG plant using state-of-the-art equipment, to make maximum use of the spur line capacity. A modern LNG train typically has a capacity of 3 million tonnes per year, the report says. That capacity translates to a natural gas feedstock requirement of 500 million cubic feet per day.

Stone & Webster has estimated the capital cost of this type of upgrade to be $1.5 billion, with annual operating costs of $120 million per year. Those costs become economic at an LNG liquefaction price of $3.91 or $2.65 per thousand cubic feet, depending on whether the payout period for the plant costs continues for three years or five years. Those liquefaction prices translate to delivered gas prices of $7.91 and $6.65 on the U.S. West Coast. Although both of these prices seem to compare favorably with current Henry Hub prices, a cash flow analysis of the LNG plant upgrade suggests that an acceptable rate of return on the investment would require the longer payout period and higher price.

Insufficient gas?

But what if a spur line for delivering North Slope gas is not built?

That could result in the shutdown and dismantling of the LNG plant, unless sufficient new Cook Inlet gas reserves are found to render the plant viable.

However, the conversion of the plant to an LNG receiving and regasification terminal could present another future option — the plant could convert imported LNG into natural gas to meet residential and commercial needs in Southcentral Alaska. Stone & Webster has assessed this type of conversion to be a viable option, with a tolling rate of 45 cents per thousand cubic feet of natural gas converted from imported LNG (see the sidebar). Assuming a price of $5 per thousand cubic feet for imported LNG, natural gas would leave the plant gates at a price of $5.45 per thousand cubic feet.

It might also be possible to use the plant as a “peak shaving facility,” in which LNG would be generated and stored during periods of low gas demand. The LNG would later be regasified to meet peak demand. However, Stone & Webster thought this use of the plant unlikely, because the use of old gas fields as gas storage facilities is likely to be a more economic supply balancing mechanism. Stone & Webster also said that the current gas pipeline capacities around the Cook Inlet assume the Beluga River gas field on the west side of the inlet to be a prime source of gas. Making Nikiski the prime source of gas would probably entail some reconfiguration of the pipeline systems, the report says.

The report also discusses the future possibility of converting the Nikiski plant into a facility for fractionating and exporting LPG from North Slope feedstock. The feedstock could come through a spur line or from LPG removal facilities on the North Slope gas transmission pipeline at Fairbanks or Delta Junction.

Stone & Webster estimated a cost of about $200 million for this type of plant conversion at Nikiski, with the LPG being stored in the existing LNG tanks. The economics derived from this cost look unfavorable for selling propane into the U.S. West Coast, especially as U.S. LPG prices are typically tied to natural gas prices. However, with relatively low North Slope gas prices “there may be sufficient LPG price mark-up in the Japanese or other Far East markets to justify such an investment,” the report says, adding that this type of market analysis is beyond the scope of the report.

It all depends

So what does all this mean in terms of the future of the Nikiski plant?

It all depends on whether a spur line for delivering gas to Southcentral Alaska is built, how much additional gas is found in the Cook Inlet area and what happens to future natural gas prices. And the report also points out that the changing gas industry in the Cook Inlet, coupled with changes in the function of the Nikiski plant, could impact both the ownership of the plant and the ownership of the gas that the plant processes — these ownership changes would impact the economics of the Nikiski plant.

“The natural economic life of the Kenai LNG plant is nearing its end,” the report concludes, saying that the plant could continue to operate in its current form through 2011 given sufficient additional gas reserves and a renewed LNG export license.

Operation beyond 2011 will require significant investment in plant upgrade, requiring guaranteed gas supplies for at least a 15-year period.

“As a minimum, major elements of the plant would be replaced on a like for like basis,” the report says. “More likely the plant would be upgraded and optimized, possibly increasing the capacity of the plant to 3 million metric tonnes per year of LNG. In this instance, additional investment would be required in the LNG carrier fleet too.”





Another option: Convert to an LNG import facility

According to a recent report by Stone & Webster Management Consultants for the Alaska Natural Gas Development Authority one future option for the Nikiski LNG plant is to convert the aging plant into a facility for importing liquefied natural gas for use in Southcentral Alaska.

In fact, Enstar Natural Gas Co., the main gas utility in the region, is considering the import of LNG as a future gas supply option, if Cook Inlet gas production is unable to meet gas demand and a spur gas line from the North Slope is not constructed (see “Enstar gives imported LNG another look” in the May 22 edition of Petroleum News).

Also, Northern Dynasty Mines Inc., the would-be developer of the Pebble Mine near Iliamna, has seen the import of LNG at Nikiski as a possible source of natural gas to generate electricity for the mine (see “Don’t call Alaska’s Pebble project isolated” in the March 26 edition of Mining News).

The ANGDA report on future options for the LNG plant, which is owned by ConocoPhillips and Marathon, points out that the plant drives a significant component of current Southcentral natural gas demand — 214 million cubic feet per day, out of an annual average demand of 548 million cubic feet per day for the region. So, conversion of the plant to an import facility would result in a drop in total gas demand in the region.

And swings of about 2.7:1 between winter and summer residential and commercial natural gas demand complicate the economics of an LNG import facility. The ANGDA report suggests that the facility would need to be sized for a winter demand of about 400 million cubic feet per day from residential and light commercial gas users.

The two relatively small LNG carriers that currently export LNG from Nikiski would probably prove adequate to transport imported LNG to the converted plant, the ANGDA report says. But the report comments that some additional spot cargos might be needed to bolster supplies to meet peak winter demand — the additional gas might be stockpiled in Cook Inlet gas storage facilities.

Although the basic infrastructure at Nikiski would work as an LNG receiving terminal some major modifications to the existing plant would also be necessary. Modifications would include the installation of several LNG vaporizers, each rated at 150 million cubic feet or 125 million cubic feet per day. Other new equipment would include LNG transfer pumps, a metering station, piping and instrumentation. The report says that total capital cost for the plant conversion would run to about $62.5 million, with an operation and maintenance cost of $12 million to $14 million per year.

At an average annual send-out rate of 200 million cubic feet of natural gas per day, the conversion project would appear to be viable at a tolling fee of 45 cents per thousand cubic fee of gas converted from LNG over a payout period for the plant costs of three years, the report says.

Assuming an import price of $5 per thousand cubic feet for imported LNG, natural gas would leave the plant gates at a price of $5.45 per thousand cubic feet.

Increasing the capacity of the converted Nikiski facility significantly above the current natural gas Southcentral Alaska demand levels or to accommodate the use of modern, larger LNG carriers, would require additional LNG storage capabilities at the facility, the report says. That additional storage would probably add about another $100 million to the capital cost of the facility conversion.

—Alan Bailey


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