Anadarko Petroleum would like to be in an initial open season for an Alaska natural gas pipeline under the Alaska Gasline Inducement Act, but is unlikely to be able to discover and prove up gas if that open season occurs in the next three to three and a half years, says Mark Hanley, the company’s public affairs manager for Alaska.
Anadarko has natural gas prospects in the Brooks Range Foothills, where it is exploring in partnership with BG and Petro-Canada, and Hanley told Senate Resources March 23 that he’s frequently asked why the companies would drill for gas when there isn’t yet a pipeline to move that gas.
One reason, he said, is that the companies want to keep their leases — and to do that they plan to drill a well next winter. “We think they’re valuable leases, so that’s one of the motivations,” he said.
The other motivation is timing: getting started so that they’ll be ready for a gas pipeline.
The issue, he said, is not putting too much money into exploring if a gas pipeline doesn’t go ahead in the next few years. Alaska is already challenged by long lead times for developments, and the companies “don’t want to strand a lot of capital” by committing a lot of dollars if they don’t think a gas pipeline is moving forward.
They have four “pretty well defined prospects” in the Foothills; they want to keep the leases; and “there’s enough movement” on the gas line that they have contracted to build a new rig which will be used in the Foothills.
“We’re going to go out and try to drill one of these prospects” next winter, Hanley said.
He said the companies think there is gas on the prospect, but only drilling will tell them if there is enough gas, if the gas flows well and if the prospect is commercial.
Won’t be an open-season decisionThe results from drilling next winter won’t be enough to allow the companies to go to an open season. A single well won’t give them enough information: “We’re going to need to delineate the field, do some more tests. … There’s a lot of risk,” he said.
Pipeline shippers take long-term risk, “and we can’t make a long-term commitment without understanding the field and how it’s going to perform.” One well won’t provide all the answers, he said.
While Anadarko’s preference would be to participate in an initial open season, “the odds that we could be at an open season if it’s held within about three or three and a half years are not very good, because it’s going to take us one year just to get the first well and a number of years to drill enough delineation wells.”
However, Hanley said, if they drill next winter and “if it looks like a pipeline open season’s going to happen, we may decide to get a couple of rigs and try and delineate that thing as fast as we can and get into the initial open season.”
If things are moving more slowly, they would probably test another prospect each year for the following three years, and then make decisions based on how things are progressing on the line “as to whether we delineate those fields and move forward.”
While they’d like to be at the initial open season, “we may come in two years after the initial open season” and request an expansion, he said. The goal would be to bring half a billion cubic feet a day into the line, Hanley said.
The pipeline would make the decision on how to handle the expansion request. If they just need to add compressors “they may be at a point in the process where they can actually add those as part of their construction” or the expansion might be put off until after startup.
Hanley said even if Anadarko doesn’t make it to the first open season, they want to have resources identified “well before startup.”
Anadarko has concerns about producer-owned pipeHe said Anadarko is concerned about a producer-owned pipeline, in spite of the ability of the producers “to get projects done and do them well.”
“Our only concern is the normal motivations that occur — change a bit, in our view anyway — when you have a producer-owned pipe vs. an independent pipe,” Hanley said. The cost of the pipeline is the cost, he said, but when you go to the Federal Energy Regulatory Commission to argue about the rate of return on a pipeline, a pipeline company will argue for a higher rate of return based on risk while shippers argue for a lower rate.
Hanley said he agrees “the bigger risk is actually on the shippers” because their shipping commitments underpin the financing. Ranges of return from 12 to 14 percent for the pipeline have been discussed, he said, and what normally happens at FERC is pipeline owners argue for a higher rate — telling FERC the pipeline is risky — while the shippers argue for a lower rate based on low risk.
“Our concern with a producer-owned pipe is there isn’t that necessary tension.” The producers, who will be shippers, “aren’t necessarily going to oppose a high rate of return on the pipe within that relative range” if they own the pipe. The cost is what the cost is; “you’re just debating the return. Our concern is that the higher the rate of return on the pipe the higher the tariff is; that means the lower the wellhead value for explorers (and) producers. But if you’re aligned as a producer and a pipeline owner … it’s kind of (from) one pocket into another.” The state is affected because “the higher the tariff is the lower the state’s share because of the wellhead value.”
With a producer-owned pipe, you’ve taken away “a little bit of that tension” that you have with a third-party owner, for people to argue for a low return on the pipe, he said.
Anadarko likes AGIA processHanley said Anadarko likes the process in AGIA and thinks that if the state wants to put money into the project using that money to reduce the tariff is important.
But, he said, Anadarko disagrees with tax and royalty incentives only for shippers who sign up at the first open season. The company thinks all shippers should have the same fiscal certainty.
“One of our arguments would be: What if you come in two years later, and you’re still in on the first shipping, but you didn’t get the fiscal certainty? It will affect our decisions as we go forward, just as it does everyone else’s,” he said.
Hanley said Anadarko supports requiring applicants under AGIA to support rolled-in rates at FERC.
FERC decides whether the rates will be rolled in, he said. “The question is: Do you have to ask for it and support it?”
Initial shippers would probably oppose rolled-in rates, he said. Anadarko, as an explorer, supports them. “If I were a producer and I just had gas and I didn’t want to explore anymore and I was putting gas into that line, I might be sitting here saying I don’t want rolled-in rates.” It’s a policy call, he said, but “I will tell you from our perspective, where we sit as an explorer, we like this provision.”
Anadarko believes the requirement in the bill that applicants under AGIA describe how they plan to manage cost overruns is “absolutely critical,” he said. The risk to the shipper from cost overruns is that the tariff will end up being higher than what the pipeline company said it would be when the open season was held. Shippers protect themselves with contingency bids, he said, and there are risk-sharing agreements on pipeline cost where there are incentives to the pipeline if it comes in on time and on budget. If there are cost overruns under such agreements, the pipeline picks up a share of the cost overrun.
Anadarko also wants to see a pipeline design that will allow for low-cost expansions.