The State of Alaska has been negotiating for a piece of the proposed Alaska North Slope natural gas pipeline, and a presentation to the Legislative Budget and Audit Committee in Anchorage Aug. 31 shows why. At current and projected natural gas prices, the project should be profitable, according to a study prepared for the committee under contract by Econ One Research.
In addition to looking at long-term natural gas prices and the North American natural gas market, Econ One analyzed project models prepared by the Department of Revenue, the Department of Natural Resources and consultants and also reviewed data prepared by applicants and the administration. While those models and data are confidential, said Barry Pulliam, a senior economist with the firm, Econ One developed its own model of a gas project using publicly available data, and the project Econ One modeled is a profitable one. Pipeline owners get a regulated return from the project, but the Econ One model shows profits to resource owners — and the state is a resource owner — come primarily from resource development and gas sales, not from pipeline ownership.
Gas prices the basis
The price North Slope natural gas would bring in the Lower 48 is the key to profitability and long-term prices of natural gas are expected to be in the range of $5 per million British thermal units, in today’s prices.
Anthony Finizza, an Econ One consultant and chief economist for ARCO from 1975 to 1998, said six forecasts for Henry Hub prices over the 2012-2025 period average $4.71 per million Btu, and price scenarios developed by the National Committee on Energy Policy project only a 10 percent chance that prices will be below $2.76 per million Btu over the period, and a 10 percent chance they will be above $6.39 per million Btu over the period. “There are no facts about the future, but a lot of people certainly want to tell us about it,” Finizza quipped.
Current natural gas prices are at cyclical high levels, he said, and told legislators not to expect prices this high “when your pipeline is in operation.” Natural gas faces competition from coal even in the $4-$5 per million Btu price range, he said.
Rich Harper, an Econ One consultant, formerly president of ARCO Gas, said low natural gas price levels in the 1990s were an over correction to events of the 1980s, when there was a rush of drilling after natural gas prices were deregulated and supply swamped demand, driving prices down. The recent price run up, with New York Mercantile Exchange futures prices hitting $13 per million Btu, with perhaps $1 of that related to hurricane Katrina, is not sustainable, Harper said.
Nymex a ‘price discovery cycle’
Recent high prices are “almost a technical adjustment,” he said, have brought only a modest increase in drilling and not the kind of fuel switching which occurred in the 1990s — partly because fuel-switching equipment is not readily available and partly because oil prices are so high. But, he said, there has been a major structural change: a shift upward in the range of uncertainty about how high and how low natural gas prices can go. This is partly because natural gas pricing operates in different dimensions: paper and physical markets. Over the past decade, Harper said, natural gas has been the most volatile item traded on the Nymex. But those futures trades almost never go to delivery: the Nymex is a “price discovery cycle” for natural gas, he said. The physical trading of North American gas, unlike the paper or financial which occurs on the Nymex, occurs at major market hubs, Harper said: Henry Hub in Louisiana, Chicago and AECO in Alberta. There is also trading in basis differentials — the difference in prices at the different hubs — reflecting volatility from factors such as weather and power demand.
Asked about the effect of spot markets on an Alaska project, Harper said there were two dimensions to that issue: concern about secure long-term supplies and concern about pricing. A contract can deal with the pricing issue by including a market price, he said, with firm supply. Or both supply and price can be fixed and price can then be “unlocked with derivatives” — such as cost collars.
Also infrastructure changes
Pipelines are a critical part of the natural gas industry, Harper said: Crude oil is fungible, there are a lot of ways to handle it, but that’s not true of natural gas — it can only be moved through pipelines. Ownership in the pipeline industry has consolidated among such firms as TransCanada, Kinder Morgan and El Paso and a lot has been done to remove physical bottlenecks in the U.S. and Canadian transportation system, but the natural gas market in the United States remains a series of regional markets, he said.
And producers continue to avoid interstate pipeline ownership, partly because of a perceived risk that the Federal Energy Regulatory Commission might move to extend regulation back up into gathering lines and partly because regulated rates of return on pipelines are not seen as a desirable investment.
Non-traditional supplies of natural gas, such as LNG and frontier gas, now play a more significant role, with some 14 percent of Lower 48 gas now coming from Canada, four active LNG terminals and more than 35 proposed, Harper said.
Alaska gas part of the mix
Alaska gas has been a feature of energy forecasts for many years, and is expected to contribute some 5 percent (1.5 trillion cubic feet a year) of the Lower 48’s natural gas demand, expected to be some 32 tcf a year by 2025, Finizza said.
North Slope gas will be “base loaded” into the Lower 48 market, Harper said, replacing declining supplies in Alberta and on the Gulf Coast, with the load factor referring to the fact that North Slope gas will move to the market every day, as opposed to short-lived fields or LNG which provide swing supply.
Liquefied natural gas will also be needed in the Lower 48 supply mix, some 3-4 tcf a year, but Finizza said Econ One doesn’t think LNG will be a worry for Alaska natural gas.
Foreign LNG and Alaska gas supplies are “neither directly competitive nor mutually exclusive,” Harper said. LNG imports are currently 800 billion cubic feet per year, he said, an amount which is expected to double over five years. “The market doesn’t see them as competitive,” he said. In fact, foreign LNG will be a marginal or swing source of supply because it is the only source of gas that is fungible — LNG ships can be diverted to meet a need. Harper said 100 percent of the LNG going into Lake Charles today is spot.
This is “not a duel between projects” bringing LNG from Algeria or any other source and Alaska gas: “the market has room for both in my view,” Harper said, with foreign LNG and Alaska gas filling different niches — each a part of the total supply mix, and with similar timing and pricing profiles because of long lead times.
Projected tariffs, netbacks
Finizza said project evaluation is done against a range of price cases, including a low or stress price case as well as expected prices. Moody’s and S&P are currently using $3.75-$4 per million Btu as a low or stress price test case, and he said that while $3.50 per million Btu has been used for a low case test, that now seems too low.
Econ One estimated project costs from public numbers — updating numbers the producers presented in 2001 and also using numbers from a recent Tristone Capital report, and then estimated tariffs for a project ending in Alberta at $1.43 per million Btu, plus or minus 20 percent, starting at a gas treatment plant on the North Slope and including a feeder pipeline from Point Thomson.
The firm then estimated the netback to producers at a range of prices. At a $4 per million Btu “stress price,” Finizza said, the netback would be $1.27 per million Btu. At $4.75 per million Btu the netback would be $1.86, at $5 the netback would be $2.05 and at $6 the netback would be $2.83, all based on the state’s current fiscal structure.
Upstream vs. midstream
Jeffrey Leitzinger, president of Econ One, told the committee the upstream vs. the midstream components of the project — the development of the resource vs. its delivery to market — need to be discussed separately because the economics are different.
The regulated pipeline is viable as a standalone investment, he said, because a regulated pipeline has expressed interest in building the system and because in the Lower 48 and Canada billions has been spent in recent years to build thousands of miles of pipelines.
And, he said, if a regulated pipeline is ready to build the line, “the producers don’t have to do that.”
You don’t “need to think about economics on an integrated basis,” he told the committee. A regulated pipeline is viable, so if the upstream economics are attractive, the gas pipeline project is viable.
But regulated pipelines aren’t traditionally very good gas merchants, so it wouldn’t make sense for the gas owners to sell at the gate to the pipeline. They would typically pay for the transportation service, moving gas to a hub and selling it there.
Leitzinger said integrated project return is less than upstream return — but so is the risk, because the pipeline has lower risk and lower return, while the upstream has greater risk and greater return.
Performance looks worse on an integrated basis, but so does risk, and he warned the committee to “beware of rate-of-return comparisons across projects with different risk and investment profiles.”
Capacity commitments
But, he said, capacity commitments are necessary.
When a shipper commits to ship gas it means that if prices go south, the shipper can’t just walk away; it creates a situation where the shipper might lose money, Leitzinger said, and so increases risk. How much risk is there? Leitzinger said there isn’t much, and illustrated with inflation-adjusted numbers, plotting Alberta price against netback. At an inflation-adjusted tariff of $1.75 per million Btu, a shipper with committed capacity has a zero netback at and below an Alberta price of $1.75 per million Btu, and has to ship even though the amount received for the gas is less than the amount required to be paid in tariff.
On Leitzinger’s inflation-adjusted scale an $8 per million Btu Alberta price is equivalent to the roughly $5 per million Btu “real” price used in the rest of the discussion, and at the inflation-adjusted rate the netback is about $6.25 per million Btu. On a scale of possible prices going to $16 per million Btu, half of the scale is above $8, he said, and half below. On that basis, with a capacity commitment and a $1.75 per million Btu tariff, having the commitment reduces the total expected value by about 1 percent if all prices are equally likely. And for the majority of possible prices, he said, the shipping commitment has no effect.
“Based on the picture we have today, the chances of being below $1.75 are very low,” he said. Inflation-adjusted prices are $6.40 per million Btu (equivalent to the $4 low price scenario) and $8.30 per million Btu (equivalent to the expected or forecast price of $4.75 per million Btu). “Shipping commitments,” Leitzinger said, “shouldn’t be considered a negative” to a project.
Differing returns
Pulliam took the lead in discussing the results Econ One got from its own model of a North Slope gas project — built using publicly available data. The project they modeled is a gas pipeline into Canada, with gas sales of 4.2 bcf a day at the AECO Hub in Alberta, with gas prices in Alberta estimated to average 90 cents per million Btu below Henry Hub/Chicago levels. A gas treatment plant, pipeline and Point Thomson facilities would be financed with a combination of 80 percent debt (with federal guarantees) and 20 percent equity, and borrowing costs on the federally guaranteed debt of 5 percent per year. Pipeline returns are based on FERC rates of 14 percent return on equity for the U.S. portion of the line and National Energy Board rates of 12 percent for the Canadian portion.
Pulliam said the capital costs are consistent with the producer presentation to the Legislature in August 2001 and June 2004. Econ One added capital for construction of a feeder pipeline from Point Thomson to the gas treatment plant and also for development of gas reserves outside of Prudhoe Bay and Point Thomson.
If the producers own 100 percent of the pipeline and the price for the gas is $4.90 per million Btu Econ One estimated an internal rate of return to the producers of 19.2 percent; if costs end up being 20 percent higher the internal rate of return would be 17.4 percent; if costs were 20 percent less, the internal rate of return would be 21.5 percent.
Better return for less pipeline ownership
If the producers own only 50 percent of the pipeline — they would still pay for 100 percent of the gas treatment plant, Point Thomson field development and future field development — their internal rate of return in this model is 23.4 percent. Pulliam said the increase in internal rate of return is driven by the fact that there is a regulated return on the pipeline. At a 20 percent increase in costs, the internal rate of return is 21.2 percent; at a 20 percent decrease in costs the internal rate of return is 26.1 percent.
Econ One also looked at a case where the producers own no portion of the pipeline. Their capital outlay includes the gas treatment plant, Point Thomson field development and additional capital for future gas development. A third party constructs the pipeline facilities, including the Point Thomson feeder line. In this case the internal rate of return to the producers is 33.8 percent, 31 percent at a 20 percent increase in costs and 37 percent at a 20 percent decrease in costs.
Econ One said this project will be heavily leveraged — especially since there are federal loan guarantees for up to 80 percent of project costs. The returns shown above reflect average return over the entire capital base, both debt and equity, but the pipeline tariffs will factor in the benefit of leveraging.
The base case (debt plus equity) internal rate of return for a 100 percent producer owned project was 19.2 percent. Econ One estimates a 42.9 percent rate of return on the equity capital only. For the case where the producers own 50 percent of the pipeline, the base case (debt plus equity) internal rate of return was 23.4 percent; the leveraged (equity capital only) rate is 50.9 percent.
And in the case where the producers own none of the pipeline, the base case (debt plus equity) was an internal rate of return of 33.8 percent, and the leveraged (equity capital only) case is an internal rate of return of 70 percent.
