Pacific Northwest gas industry players — including the top executives leading the two remaining proposed liquefied natural gas (LNG) receiving terminal projects in Oregon — are watching the proposed Kitimat LNG export project in British Columbia (BC). In recent interviews with NGI, they expressed a mixture of skepticism and support.

Earlier in May the Canadian units for the two Houston-based owners, EOG Resources Inc. and Apache Corp., reiterated their plans to proceed with the C$4 billion liquefaction and pipeline project tied to BC’s expanding shale gas production.

Contrary to the bullish prospects for BC shale gas, the Oregon LNG advocates — one with ties to western Canada — see the supplies coming to market on a delayed time frame because of technical and economic factors. Generally, the growth of the shale-based supplies will lag the rate of decline of the traditional Alberta supplies, one source said.

Clay Riding, gas supply director at Bellevue, WA-based Puget Sound Energy (PSE), said there is still a lot of engineering and economic analytical work that needs to be done to determine if Kitimat “really pencils out.” However, he thinks an LNG export project along with piping BC gas south are both possibilities.

EOG CEO Mark Papa has touted the newly structured Kitimat project as being able to attract a new global market for BC shale gas (see NGI, May 24). Producers obviously would like to have more options for selling their gas supplies.

Supporting this view is Spectra Energy Transmission, whose pipeline and gathering system customers include Apache and EOG. Spectra executive Gary Weilinger said the Kitimat export partners “are serious about moving the project forward.” Weilinger thinks “their motivation for acquiring this project is to ensure market access for the area’s significantly large unconventional resources — now estimated at 500 Tcf and growing.”

The heads of the proposed Oregon LNG and the Jordan Cove LNG projects aren’t buying this projection, questioning Kitimat’s economics and general viability. In contrast, Riding said “if I had to bet on any one of the Pacific Northwest LNG projects, Kitimat has the best chance to go.”

In the wake of El Paso Corp.’s Ruby Pipeline looking at starting construction by July 1 and being operable in March next year to move gas from the Rockies to West Coast markets, Riding now thinks it is hard to make a case for either of the two Oregon LNG receiving terminals, although he is not against either of them. (El Paso and Global Infrastructure Partners closed $1.5 billion in project financing for Ruby earlier in May.)

“The primary reason [for not needing the Oregon LNG projects] is the increase in production from shale,” Riding said. “This region is just not big enough for 1 Bcf/d of LNG. I think at the most the Pacific Northwest could take an added 200 MMcf/d; we’re just not that big a market.” Spectra’s Westcoast Energy BC Pipeline that delivers BC supplies to the U.S. Northwest is currently underutilized, according to Weilinger.

While it doesn’t have any financial interest in Kitimat or its proposed connecting pipelines, Spectra’s pipeline system for moving gas south would be interconnected. “Year over year demand now continues to grow — particularly gas-fired power generation — Weilinger said, “and we anticipate that this backbone pipeline serving the core [U.S. Northwest] market will continue to become more utilized, with opportunities for incremental expansion — both on our system and presumably on our interconnecting pipeline, Williams’ Northwest Pipeline.

“Since the available pipeline infrastructure to the market is already there, with capacity to spare on Westcoast, and step-out growth in [BC shale gas] supply, we anticipate that the likelihood of any LNG import facilities actually getting built on the Oregon coast to be low.”

From the U.S. side of the border, Oregon LNG CEO Peter Hansen is equally adamant in dismissing the Kitimat LNG export proposal. “I just don’t see how it ever will work; I’m missing something,” he told NGI. “They’re looking at the Japanese and Korean markets, but everyone [globally] wants to send their gas there. The last I checked, both the Japanese and the Koreans do not want to pay too much for anything. So why should they pay $15 when the rest of the world gets it for $5?”

Hansen thinks there is too much of a glut of LNG on the global market, and in the Pacific Rim there is more Australian LNG coming online. “You either have to leave the gas in the ground or put it on a LNG ship. Natural gas at the tidewater in western Australia is a fraction of the cost of what it is going to be in British Columbia.”

Other industry sources in the Northwest speculate that the Kitimat sponsors, which have interests in pipeline options — are only pushing the LNG option to increase their negotiating position for eventually piping the gas east to the Chicago/Great Lakes market. One way or another, a lot of the BC gas has to be shipped east because that is where the big markets are, Riding said.

The other Oregon LNG project, Jordan Cove, is sponsored by Calgary-based Fort Chicago Energy Partners LP, which has a 50% interest in the Alliance Pipeline project to take Western Canadian gas supplies to the Chicago and other upper Midwest U.S. areas. Its backers are familiar with natural gas developments in western Canada.

“We have never quite figured out Kitimat,” said Bob Braddock, project manager for Jordan Cove, which proposes a LNG receiving terminal at Coos Bay along the south-central Oregon coast. “We don’t see that it makes any sense economically. We just can’t figure how it pencils out.”

Braddock said his company’s analysis indicated that oil needs to be well beyond $100/bbl for Kitimat project to work economically. “[The BC gas] certainly is not inexpensive, and there is a whole lot more [LNG] in Australia that is available a lot cheaper,” he said.

However, Braddock said the BC gas will not impact Pacific Northwest supplies if it isn’t exported as LNG because it is likely to flow east — not south. “This [BC] gas is very hot — something like six gallons of liquids [per-MMBtu] with a lot of ethane, and the only way to process it is move it east through the Alberta system where you can both remove the ethane and get values out of it and still take the liquids to a market point, and we [Fort Chicago] would take it to our facility in Illinois.”

Riding said the conservative estimates are for production of 3-4 Bcf/d from BC shale plays, and some stretch as high as 9 Bcf/d. With any of those totals some of the supplies are sure to come south, he said, noting that a lot of the shale gas supplies are “just going to be replacing declines in conventional supplies” from western Canada.

“The step-out growth in unconventional supply from Northeast BC is anticipated to far exceed the ability of our traditional core markets to absorb all this new supply,” Weilinger said. “[That is why there is] the interest in more outlets for the gas — from Kitimat LNG to eastbound capacity to Alberta on the TransCanada system.

As a transmission pipeline infrastructure developer, we want to see our existing pipes used and useful, so we want to ensure there continues to be sufficient pipeline capacity to our core markets in the Pacific Northwest. If our core market isn’t growing quickly enough, we will facilitate infrastructure development to other U.S. export markets as well as eastbound within Canada to ensure our facilities remain highly utilized.”

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