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Anadarko, BP offer conflicting gasline views Explorer Anadarko is concerned about tariff rates, access to pipe; producer, likely gasline owner BP is worried about cost overruns, market prices Kristen Nelson Petroleum News Editor-in-Chief
Parties can have different views on tariff issues, Alaska Division of Oil and Gas Director Mark Myers told members of the Alaska Legislature in mid-June. One of those differences is between companies with known gas reserves and those still exploring, legislators were told at a hearing held June 16-17 in Anchorage, the first of three planned by the Legislative Budget and Audit Committee and the Senate Resources Committee.
Anadarko and BP represented companies with such different views.
Mark Hanley, Alaska public affairs manager for Anadarko Petroleum Co., said he wanted to give legislators some perspective from the viewpoint of a company which is still exploring and doesn’t yet have any gas to put into a pipeline.
Depending on whether you are a producer, a pipeline owner, or a producer who is also a pipeline owner, you may want different things from a tariff, he said. The rules of the game for gas pipeline tariffs “are very fluid, there’s a lot of ability to change those rules. And in fact, because of that we’re going to sit back and watch,” Hanley said.
Explorers want a gas pipeline, he said, but they are in no position to build a line themselves, because they have no reserves. Neither are they in a position to invest the billions of dollars to explore for and develop gas reserves, “thinking it might get built.”
Explorers need the lowest tariff possible, he said, but “the terms and conditions of the tariff” also “can affect whether people invest.” The explorers face the exploration risk: “typically in an exploration company your biggest risk is in the geologic side, the underground side. Are you going to find the gas? Is it going to be in quantities, flowing enough and large enough size and close enough to infrastructure to make a commercial gas find?”
But, he said, “the biggest risk in Alaska right now is the aboveground risk, the commercial risk, the risk of the cost of tariffs being too high.”
The producers, he said, face the risk of cost overruns on the pipeline, the risk of legal challenges and the market price risk.
“We face all those same kinds of issues: we also have the exploration risk,” Hanley said. Volumes must be nominated Because gas pipelines are contract carriers, companies with gas to ship contract for specific amounts of space in the pipeline on a ship-or-pay basis. The explorers, who are yet to make discoveries, won’t know for a number of years out how much gas they have, so won’t be able to participate in the open season when nominations are made for space on the initial pipeline. That makes expansion terms critical for exploration companies, Hanley said.
Pipelines can be designed so that expansion is inexpensive or expensive, he said. With inexpensive expansion, the cost of expansion could be rolled into original rates, and could end up reducing rates for everyone.
But if the pipeline is not designed for inexpensive expansion, it could create a situation where there is only one way to get gas to market and that one way is controlled by those with original capacity, precluding new entrants.
The explorers, he said, will be focused on line expansion, and on tariff terms as well as on tariff rates.
The initial pipeline owners, for example, “can say we’re taking the risk, we’re doing this, so we have the right of first refusal on all expansion capacity.”
Hanley also said that while producers should be aligned with explorers in wanting a low tariff and a high netback, “if you have a producer-owned pipe and they’re aligned, there may be some incentive to shift … profits to the pipeline.” Well-established procedures Bill Benham, vice president for regulatory affairs for BP Energy Co., BP’s North America gas and power marketing and trading business, told legislators by phone from Houston that the process for developing and getting regulatory approval for both pipeline tariff rates and other elements of the tariff is “very well established in both the U.S. and Canada.” The tariff rates, he said, reflect the cost of constructing and operating the pipeline.
“There is always going to be some concern about having underestimated capital and operating costs in relation to the rate that ends up being established,” he said, “the concern being then that the resulting rate would not adequately recover those costs.” That is “a key, key risk factor for the pipeline,” he said.
On the shippers side, he said, concerns will be that the shippers may overpay for capacity because of “a loss of the market, a loss of supply or the supply source — in effect the situation where your capacity commitment does not match the actual throughput” for which you contracted. And if a shipper fails to reach a negotiated rate with the pipeline, the shipper may file with the FERC and get an increase in rates.
Sen. Scott Ogan, R-Palmer, asked Benham about open season disadvantages for explorers, and Benham said this is a situation they see in the Lower 48. Pipelines are generally looking to add throughput, he said, and it’s to the benefit of the pipeline to add facilities to get more gas to market, and such expansion can be achieved in various ways.
A shipper coming in after an open season can also go to existing shippers and contract for unutilized capacity, either firm or interruptible, although he acknowledged that interruptible capacity is “probably not something that’s very attractive to Alaska shippers.” What if line is full for years Ogan asked about a situation where “producers could fill the line already for a number of years and potentially shut out others,” while the state of Alaska has an interest in seeing new production brought online.
Benham said that typically pipelines are sized in anticipation of the resource capability of an area, and Dave MacDowell, BP Exploration (Alaska)’s gas project spokesman, said the producers’ (BP, ConocoPhillips, ExxonMobil) proposal of a 52-inch diameter line was designed to be expandable, with production beginning at 4.5 billion cubic feet a day, and expandable to 5.5 bcf a day with compression. Expansion is in everyone’s interest, he said, because “more volumes mean lower unit costs.”
As for who would pay for an expansion, Benham told Ogan that FERC has “rules and regulations around this,” but generally if the expansion is less than 5 percent of the original cost, then that would be rolled into the original rates. If the expansion cost is more than 5 percent, FERC looks at who benefits from the expansion, the whole system or just new users. If only new users benefit, then FERC may apply incremental pricing, which would put the expansion cost on “the new shippers, who are putting the new demand on the system.”
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