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Royal Dutch Shell Plc .com: Clark: Some contract renegotiation possible

Governor’s chief of staff said comments received so far will be evaluated, taking of gas in kind remains core of proposal

By Kristen Nelson
Petroleum News

Officials from Gov. Frank Murkowski’s administration said June 16 that, despite critiques from consultants working for the Legislative Budget and Audit Committee, the core of the proposed gas pipeline fiscal contract — the state taking its gas in kind — is not subject to change.

Jim Clark, the governor’s chief of staff and the lead negotiator on the contract the state negotiated with BP, ConocoPhillips and ExxonMobil, said the administration believes that the state taking its gas in kind is necessary and the core of the contract. It is not, he said, an area where the administration intends to propose contract changes.

Clark said comments received to date from both the public and the Legislature will be reviewed at a retreat in Washington, D.C., the week of June 19 and the administration will figure out where to make changes in the contract to meet “the valid concerns that we’ve heard from the public.” After that officials will hold another series of public meetings around the state to answer issues raised and discuss the rationale for where changes will and won’t be made in the contract.

The administration heard some recurring themes in public meetings around the state and in talking with legislators, Clark said.

The administration is going to inventory the views it has heard, he said. Proposed changes will be sorted into three bins, he said: bin 1 would be “those where we think substantive changes to the contract may be needed” and work on what the wording would be in changes proposed to the producers. This, he said, would include things such as a change in the period of fiscal certainty for oil in the final version of the production profits tax that passed the Senate, but not the House, at the end of the special session (see “Oil tax lock tied to project approval” in June 11 issue of Petroleum News).

Bin 2, he said, would be issues requiring clarification, such as those identified by the AFL-CIO, areas where the administration’s intent “would not be changed, but the language could be clarified to make some issues go away that were never our intention.”

The third bin would include “issues where we don’t think changes are necessary, but we believe that more explanation is needed.” Clark said he thinks the Legislative Budget and Audit consultants are wrong in recommending the state not take its gas in kind, and that is one of the issues that won’t be changed. “We believe that that was absolutely the right thing to do for the project. It is certainly the core of the contract,” Clark said. Experts have other views, he said, “and it’s our job to make sure that we have adequately explained to the public why we’re doing what we’re doing. This is not an area where we intend to make a change.”

The governor has extended the public comment period until June 24, and Clark said that as additional comments are received those will also be reviewed.

What does the state have now? “We have, as we’ve announced, a contract that is sign-able,” he said. The producers have all said they would sign. This is the first time the state has gotten to that point with a gas line proposal, he said. Those in opposition argue that maybe there was money left on the table, Clark said, “let’s look at this from the point of view of what the producers get and make sure that we didn’t leave any money on the table.” The administration’s view, he said, is “let’s look at what Alaska gets.”

You can look at what Alaska gets, he said, or you can be concerned that perhaps the producers are getting too much.

Marks: prices ‘absolutely unknowable’

Roger Marks, a petroleum economist with the Department of Revenue, said future gas prices are the principle difference between what the administration team believes and what the consultants believe.

“I guess one fundamental judgment that we brought into the negotiation … is that gas prices over the next 45 years are absolutely unknowable,” he said, noting that the LB&A consultants said Alaska North Slope gas is not stranded based on price projections. “Our judgment was that gas prices are virtually unknowable,” he said. “They seem to think otherwise.” Marks called it “a fundamental difference in judgment and that’s how two people could come up with different answers to the same question.”

Cases could be built for $2 gas prices and for $20 gas prices, he said.

What lies between the covers of any history, Marks said, “are a series of low-probability events,” which happen all the time. “A lot of things can happen in 45 years.” In spring 2000, when oil prices were about $12 a barrel, the Department of Revenue forecast that oil prices would be $18 a barrel in 2005: the price in 2005 was $46 a barrel. “So in just five short years the outlook for oil changed profoundly.”

The gas contract covers 45 years. Assuming that gas prices are unknowable and the project could have cost overruns, the project could be either “very, very good” or “very, very, bad.”

The results are not symmetric, he said: “when investors or corporations look at risks, when they look at high-side potential or low-side risk, they look at those asymmetrically.” A bad down side is worse than a good upside. Consider an option to take a chance on doubling your $50,000 a year income to $100,000 vs. losing it altogether; doubling your income would be nice, he said, but losing it entirely would be intolerable.

By taking ownership, state pays upfront

The state believed it was important to increase the rate or return on the project through state ownership of 20 percent of the pipeline and taking 20 percent of the gas in kind, Marks said. “If we own the pipeline and take the gas, we’re shelling out 20 percent of the money upfront.” Under the present system, taking taxes and royalties in value, the producers sell the oil and gas and subtract the transportation costs and write the state a check.

“Under the status quo, we actually pay for the pipeline as well, but we pay for it slowly over time through the tariff deductions,” Marks said. By paying the cost upfront, through ownership, so the producers don’t have to pay that portion and “because of the time value of money the net present value to them is improved and so their rate of return is improved.”

While the state has improved its rate of return, “we haven’t given up a thing: we’re getting the exact same amount of revenues as we would have gotten under the status quo.”

If the state took just pipeline ownership, and took its gas in value, it would demand a firm transportation commitment from the producers to ship the gas, the producers would capitalize that as an upfront cost and “so financially that’s no different than them owning it: taking the FT for 20 percent of the line would be just the same as paying 20 percent of the line; it wouldn’t increase the rate of return.”

By taking gas in kind, along with 20 percent of ownership, the producers don’t have to make the FT commitment, they have to pay less up front, and the rate of return is better.

If TransCanada took 20 percent instead of the state, and the state still took its gas in kind, the state would have to make a 20 percent FT commitment to ship that gas — “financially, that’s no different than us owning it. … It’s basically the same risk. We’d have to pay no matter what: no matter what the price is, no matter if we have the reserves, we would have to make the commitment. Financially, it’s just like we own it; but what we wouldn’t get if we just make the FT commitment without ownership, what we get with ownership as well is the pipeline income, the 14 percent rate of return on the equity piece, plus that seat at the table where we have decision-making power as to how the pipeline is developed, as well as knowing what’s going on.”

What is the value of the 2 percent improvement in the rate of return? That’s about the same as $1 per mcf increase in price for the gas, “quite considerable” over the 50 trillion cubic feet of gas that will be moved or about $4 billion savings on the cost side, Marks said.

Ken Griffin, acting deputy commissioner of the Department of Natural Resources, said the information from the administration and from the legislative consultants is “fairly similar,” with agreement that the internal rate of return went up by about 2 percent. They said it’s not significant, Griffin said, but it is a 10 percent improvement in the internal rate of return: “That means our project remains robust, remains positive, at an extra dollar an mcf lower price and it remains healthy at an extra $4 billion … in capital investment. That, I think is a significant improvement in the project.” Large projects, even ones much smaller than the Alaska gas line, are “very fragile, things can go wrong and when they start going wrong they go very wrong with the project.” Both the producers and the state want to “control this project as we move forward; make sure we have it built as soon as reasonably possible, at the best price we can achieve, so it is as healthy” as possible.

Two projects, two different risks

Dan Dickinson, former director of the Division of Oil and Gas and a consultant to the administration on the gas contract, said there are really two projects: the pipeline, which has a regulated rate of return, “that’s a fairly low-risk project,” vs. owning the gas and getting it to market “and that’s a very high-risk project.” The state has already invited people to take over its gas through its leasing program, Dickinson said. “Having another commercial entity who’s willing to build a pipeline and get a regulated rate of return, that’s not a problem. … The issue is finding someone who already bears a risk with the gas and distributing that risk around,” he said. Moving some of the risk of owning the gas is the issue, Dickinson said.

On the issue of the state taking some of the risk, Marks said the administration believes that “without the fiscal stability there’s no gas line; with the fiscal stability there’s a gas line. We believe that that’s a very good tradeoff.”

With no gas line, Clark added, the state believes production from the North Slope would end, and the trans-Alaska oil pipeline would shut down, in 2030. “So where we are right now, is we’ve got 24 more years of hydrocarbon development without the gas line; with the gas line we have a kind of unlimited horizon.” First there would be gas, but in addition the state believes with the gas line there would be an additional two decades of oil development, Clark said. “So we think that from our point of view the risks are manageable and certainly worth if for the infrastructure we’ll get by getting the gas line built.”

State: no concessions

Marks said there was a lot of discussion from LB&A consultants about concessions the state has made in the contract, such as upstream cost allowance payments.

“Well, we don’t believe there are any concessions in here. What it is is a total deal. There are payments we make, there are payments we get. At the end of the day … at a $5.50 price in Chicago, which is a medium forecast price over 35 years, we would get $100 billion,” he said.

Fiscal stability is important because if the producers take the downside risk, they need the opportunity to realize the upside, Marks said.

If the upside is positive and the state taxes it away, “the whole risk symmetry of downside risk and upside potential has been thrown off balance.”

As for whether the state would step in to take away the upside, Marks noted that some legislators voting against tripling the production tax recently said it was because the tax wasn’t high enough.

The gas reserves tax initiative on the ballot in November is another example, he said. The earliest projection for gas to flow is 2016, but if the gas reserves tax passes the companies would pay $1 billion a year, beginning Jan. 1, 2007. There is a credit against gas taxes, but only through 2030, and at a $5.50 price the maximum recovery would be about 45 percent. If gas starts to flow later than 2016, the companies would recover less than 45 percent.

Uncertainty over future gas prices and the ability of the state to step in and take away the high side in the future “are two of the main reasons we believe the gas is stranded,” Marks said.

Van Meurs: numerous cost risks

Pedro van Meurs, speaking from London, disagreed with the view held by some in the state that with current gas prices the project is commercial without any intervention by the state.

“The idea that this is not a risky project, that this will go ahead regardless, I think is a very dangerous position to take,” he said, citing the 50 percent increase in cost estimates for the Mackenzie Valley gas pipeline project, from $5 billion in 2003 to $7.5 billion, and with project sponsors now asking for a timeout to redo cost estimates.

For the Alaska project, estimated at $20 billion in 2001-02, a 50 percent increase would be $30 billion, van Meurs said.

There are also inflationary pressures in Alberta from too many projects with shortages of labor and basic infrastructure, he said, “precisely the spot we have to go through.”

Van Meurs said these cost issues are why he told legislators there is a fair chance that even with the stranded gas contract the Alaska North Slope gas pipeline will not be built.

GTL and low gas prices

Van Meurs said one of the things that he’s working on in Algeria is a very large gas-to-liquids plant. “GTL plants are not really economic, unless you forecast that gas prices will stay significantly below oil prices,” he said, since it takes 10,000 cubic feet of gas, 10 mcf, to produce one barrel of oil. “Unless you believe in very, very low gas prices, you will not build a GTL plant.”

Who’s bidding? Five “significant oil companies,” like Shell, Chevron and Statoil are interested in building the GTL plant, he said, “on a normal commercial basis.” That means those companies “are willing to gamble billions of dollars today on the forecast that gas prices in the world are going to be low. … And therefore this automatic assumption that gas prices are going to high, is clearly not shared by very significant companies” like Shell and Chevron, “that feel that GTL technology is now indeed getting around the corner and they’re willing to make commercial bids for it.”

Looking at the Mackenzie project and the Algerian GTL project van Meurs said both cost and price risk are high, “and it is not a slam dunk that this pipeline can be built for $20 billion and that gas prices are actually going to be $5 or $6 … per million Btu in Chicago.”

Rate of return improvement necessary

Because of price and cost uncertainty, van Meurs said improving the rate of return is the only way to assure this pipeline goes forward, “without giving up government revenues.”
There are really two North Slope gas projects, he said: gas production is very profitable; the gas pipeline, however, is only moderately profitable because it has a regulated rate of return.

“By participating in the unattractive project, for 20 percent, of course on average you make the project more attractive without having to give up any of your revenues in the upstream.” That, van Meurs said, is the strategy of the stranded gas fiscal contract.

The state participates for 20 percent in the midstream and revenues remain the same from the 20 percent the state takes from the upstream, he said.

Van Meurs said the state is in the same risk position with or without a contract in terms of cost overruns and price: “If the gas prices are $3 per million Btu in Chicago and there is 100 percent cost overrun the wellhead value will be zero, either way.”

Participating reduces the state’s risk, he said, because with either low prices or significant cost overruns, “at least you have the pipeline income.”

The risk of cost overrun and price are the same to the state whether or not is has an equity ownership position: participation risks to the state come from completion risk, marketing risk, shippers risk and resource risk.

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