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Apache rules out breaking oil link

US independent Apache has ruled out linking the value of its pending liquefied natural gas (LNG) exports to anything other than the price of oil, according to the firm’s vice-president of gas monetisation

Janine McArdle said using structures other than long-term fixed-price contracts would discourage firms from investing billions of dollars in new capital projects. Without price guarantees, companies would, instead, shift budget dollars to higher-return oil drilling.

“From our perspective, we’re looking for an oil-linked market, and we’re talking to folks on that basis,” McArdle said. “For us, it is a way to diversify our (upstream) asset. It’s a high capital intensive market so it needs this oil linkage.”

Oil-linked pricing is “more transparent” in the international market and provides greater opportunity to “monetise our gas in a meaningful way”, she added, saying she believed Henry Hub pricing will be “limited” in the long-term.

Spot-linked prices make sense for brownfield facilities originally built for re-gasification and are now being converted to export to avoid sitting idle. Hub-linked deals announced to date are fee-for-service agreements and not integrated with upstream production. By contrast, Apache produced 1.45 billion cubic feet a day (cf/d) of North American gas in the first quarter and has a vested interest in promoting an integrated strategy for its growing shale output.

Projects such as Cheniere Energy’s Sabine Pass have “no view or worry about what the commodity price is”, McArdle told Petroleum Economist. “It’s a different business model.” Given the choice between selling low-priced futures, possibly at a loss, Apache will keep its money firmly in pocket and its bulging unconventional reserves in the ground.

It’s not for lack of resources. On 14 June the company announced what could prove to be one of the largest shale-gas discoveries in the world, at Liard in northeast British Columbia. Apache’s 100%-owned lands could hold 45 trillion cf, alongside another 30 trillion cf at Horn River.

Though it’s a major discovery, most of the gas is stranded even under the most bullish development scenario. McArdle said there are no plans to immediately increase the proposed design capacity of the proposed Kitimat LNG facility on Canada’s west coast. The main priority is to be among the first to develop the resource in Canada’s increasingly competitive LNG sector, she added.

Surging Lower 48 production has decimated Canada’s only export market and the rush is on to find other buyers in Asia, especially for remote, relatively high-cost fields like Horn River and Liard.

That’s the main reason producers like Apache are looking to LNG in the first place, to gain alternative markets and higher international pricing. Buyers understandably want the lowest price, but it’s equally clear that producers like Apache are not going to give it to them without some form of surety. Thus it’s likely to be a trade-off between guaranteed volumes and guaranteed rates of return.

“To ensure that supply, buyers are still going to have to buck up and pay oil-linked pricing otherwise the LNG going forward, will dry up,” said Ed Kallio, Ziff Energy’s director of gas consulting. “It’s our view that the oil-price linkage will continue.”

Ziff advised Apache on markets for its Kitimat terminal. The study will be used in conjunction with pending front-end engineering and design (FEED) to determine whether the project is economically viable.

Apache is the operator with 40%. Houston-based EOG Resources and Calgary’s Encana each hold 30%. All three are major unconventional gas producers at Horn River and face a common problem of having too much gas and too few places to sell it.

Last October Kitimat was granted Canada’s first LNG export licence and a final investment decision is pending. McArdle confirmed the 5 million tonne per year (t/y) project will likely be delayed by about a year, possibly to 2017, from a previous target of 2015.

Nonetheless Kitimat is the furthest advanced of half a dozen projects planned for Canada’s west coast. In June Shell announced an agreement with Kogas, PetroChina and Mitsubishi to build a 12 million t/y terminal. To get around the thorny issue of oil-linked contracts, Shell deliberately brought in “customer-producers” to partner in its upstream unconventional production.

Unlike Shell, Apache does not have built-in markets and must now negotiate at a time when Asian buyers are expressing frustration with present pricing arrangements.

However, McArdle predicts other US producers will also be reluctant to commit to a true spot market for many of the same reasons: high capital costs for new terminals and the lack of certainty for making long-term investment decisions on facilities with an expected economic life of 30-40 years. “These projects aren’t built on speculation. What we’re looking for is an alternative market,” she said.

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