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Lower 48 need for natural gas drives frontier development Tom Robinson of Cambridge Energy Research Associates tells “Meet Alaska” that North American energy production swinging towards gas generation Kristen Nelson PNA News Editor
Tom Robinson told the Alaska Support Industry Alliance “Meet Alaska” Conference that he’s been in the oil and gas industry for 15 years, and never expected to talk seriously about Arctic gas development.
But times have changed, he said.
Robinson, managing director and director of research for Cambridge Energy Research Associates, speaking in Anchorage Jan. 28, said he wasn’t going to compare options for developing Arctic gas.
“I think too much of Alaskan focus has been on which is the best option and not enough focus on exploring all the alternatives. Because after all they really are not mutually exclusive given the size of the resource base.”
North American market Arctic gas is geographically challenged, Robinson said, but a structural shift in the North American gas market “makes the development of frontier resources and the Arctic much more plausible than it was five years ago.”
That shift is driven by the electric power market, he said.
The Lower 48 electric power market has been characterized by a huge surplus that built up in the late 1970s and 1980s, surplus capacity of close to 25 percent in the power industry — coming from coal-fired and nuclear-fired plants built after the oil and gas price spike in the 1970s, Robinson said: “And that surplus has worked off slowly over the last 15 years.”
At the same time, he said, the “electric power market has gradually over that time frame been exposed to competitive and competitive market forces like you see every day for the oil business here in Alaska.”
Ironically, Robinson said, “the market had just begun to deregulate into a period of relative shortage.” The reserve margin for power is now down to about 10 percent, not much in a market where “there’s no storage and you have to be reliable 100 percent of the time” producing tremendous price volatility.
Power price volatility In the Midwest over the last two summers, weekly peak period prices have gone from an average of $35 a megawatt hour to over $700 a megawatt hour, Robinson said.
“Just imagine what would happen if you saw a week of $600 a barrel oil in terms of political developments. And that’s what’s going on in the power market. And it’s driving a tremendous high-speed political response. But more importantly it’s driving a huge wave of new development of gas-fired power generation in the Lower 48.”
There are 100,000 megawatts of capacity under construction, enough to consume about 15-17 billion cubic feet a day of gas, on top of current consumption rates of about 60 billion cubic feet a day, Robinson said.
The installed generating base of the power sector in the Lower 48 today is 15 percent gas fired. But, Robinson said, “if you look at what’s coming in terms of the new wave of construction, 95 percent is gas.
“That’s the kind of inflection point in market dynamics that changes the way we think about markets, that changes the way we think about prices as we look at — this is the force that’s driving us.”
The environment is one reason for the growth in gas generation, along with cheap gas technologies and the fact that gas plants are easy to site, he said.
Growth coming in gas consumption Over the next 10 years, Robinson said, “we expect average growth to stand right at about 500 million cubic feet a day per year in terms of the North American market.” And over that 10 years, consumption will double or triple.
The Lower 48 is going to need new gas over that 10-year period in a range between 12 billion cubic feet a day and 23-24 billion cubic feet a day.
“So what that means for us specifically is we need to connect or find or develop roughly 300 TCF over the next decade, about half a trillion dollars of investment to make that happen.”
And even at the lower end, the investment would be $300-$400 billion and 250-275 trillion cubic feet of newly connected resource, much of which remains to be discovered.
Upstream efficiency There’s another factor affecting Lower 48 markets, Robinson said.
Over the last decade, the upstream end of the business has become more efficient, nowhere more than in the gas business in the upstream in the Lower 48 and Canada.
“Over the last decade, the growth in production that happened in the Lower 48 happened principally because we got a lot more efficient with the production that we have,” Robinson said:
“We produced it in the summer more, we developed storage more and we kept current production levels current.”
So markets grew while reserves declined over the last decade. That worked, he said, at levels of 50-52 billion cubic feet a day. But now, he said, market need is going to grow to at least 60 billion cubic feet a day and possibly as high as 80 billion cubic feet a day.
The Gulf of Mexico has been looked to as a source of more gas, but production in the shelf has fallen from 16 billion cubic feet a day to a current rate of about 10 billion cubic feet a day — and Robinson said it is expected to fall to 7-8 billion cubic feet a day.
Deepwater Gulf of Mexico production is growing, but “is not sufficient to meet the growth imperative that’s coming into the market,” he said.
Higher prices needed “More is going to have to be done. The prices will probably have to be somewhat higher to attract that gas into the market,” Robinson said.
In the early 1990s average prices in the Gulf Coast and Chicago — one of the principal markets for new supply in the Midwest — were about $1.70, he said. Over the last five years, that price has risen to about $2. Today, prices are closer to $2.50 and the long-term price from the financial markets is “$2.50 plus and rising in pace with inflation,” he said.
“So while we think of commodities as falling in price or losing value in real terms, this is one commodity — one of the only commodities, I think, in energy …— that’s actually been gaining price support slowly in the competitive market over the last 10 years.”
And in the $2-$3 range, “the opportunity to develop new sources of supply — unconventional gas, remote gas — is a lot more promising than it was before and indeed, if that gas isn’t developed, there’s going to be more pressure.”
Incremental supplies of gas Growth in the United States over the last 10 years was possible partly because there was very strong growth in gas supplies out of western Canada.
U.S. gas production in that period grew hardly at all with the exception of the Rocky Mountains, which had some growth.
Robinson said that some additional gas supply is available domestically. The deepwater Gulf of Mexico would be a major source of new supplies, but probably only in the range of a few billion cubic feet a day, he said. The Rocky Mountains, producing only 3-4 billion cubic feet a day now, would require a huge capital investment to even double that production.
“Indeed,” he said, “we’ll be surprised if the Lower 48 itself can deliver more than 5 or 6 BCF a day in the relative competitive economics that we’re talking about in terms of growth, principally because there are better options looking north.”
And, he said, in addition to frontier sources, look for the reactivation of existing liquefied natural gas terminals to delivery gas into the United States.
“There are four that have been built. Those could be expanded up to a couple BCF a day. It’s going to be very hard to go beyond that because siting an LNG terminal is somewhat akin to siting a nuclear power plant. You just can’t do it.” He said to look for an announcement this year on one reactivation.
Looking north Looking north, he said, there is Canada — and there is Alaska.
In the east, shallow offshore Canada, under development now, will provide 500 million cubic feet a day into the Northeast and could be doubled or tripled. Hibernia off Newfoundland, however, presents “very difficult subsea pipeline problems that make it really beyond economic reach at this point,” Robinson said.
Western Canada already has major pipelines into the Midwest, a hub for gas distribution to the Midwest, the East Coast and the South.
Over the last three years the Canadians have added 2.5 billion cubic feet a day of incremental pipeline capacity from western Canada.
“Indeed they’re added so much capacity that there’s now a tremendous surplus and that’s had a significant impact on price,” Robinson said.
The difference in price between western Canadian gas and Chicago gas three years ago was in the range of $1.70 per million BTU.
“In other words, the price of gas in Chicago was as high as $2.50. The price of gas in Alberta was 80 cents. And when you start talking about developing Alaska gas and bringing it down through Alberta, that doesn’t sound like a very promising thing to be moving your gas through in terms of the netback.”
But the difference in price is now about 40 cents, “and what that means is that 80 cents in Alberta has become $2.00. And $2.00 in Alberta makes gas in the north look a lot more attractive in terms of interconnecting it.”
The gradual growth in development of supply and drilling activity in western Canada has moved north into the Northwest Territories. In the southern area of the Northwest Territories there have been some significant discoveries.
And there is surplus capacity in pipelines, so they are actively seeking northern frontier supplies to fill the lines.
“And what that’s doing, it’s started a push within Alberta, to develop gas and develop new resources to fit into this market. Both because of the growth potential in the Lower 48 and because of the fact that there’s unutilized pipeline capacity that has gotten that community very focused on developing the Mackenzie Delta and the Mackenzie Delta valley and bringing that gas into the Lower 48, probably in the range of the next five years.”
Only rapid, major new discoveries in Alberta are likely to stop the northward march, Robinson said.
Alaska’s within reach… Where does Alaska fit in? Robinson said there are “various pipeline alternatives — coming down the Taps system and the Alaska Highway or coming down and interconnecting with the Mackenzie Valley Pipeline.”
“There’s a variety of different economics that you can work out as to what the best route is. I don’t think what the best route is really the question.
“What is the issue is this impetus, this pressure to move from Alberta north is real and that’s happened and that’s out of the box first.”
There are a set of choices for Alaska, Robinson said, and “they revolve around how Alaska interfaces with this broad door into the Arctic.”
The Alaska approach could be competitive, partnership or joint development or sequencing. “Sequencing meaning let the Canadians build to the Arctic first.” Once Canadian gas supplies decline, then Alaska gas fills the pipeline.
Robinson said that the opportunity for developing Alaska North Slope gas in the next 10 years is probably put off from 2005 to 2010 “in terms of its relative economics.”
A gas price of $2.50 to $3 in the Lower 48, with transportation costs from the North Slope in the range of $1.60-$1.80 to Chicago leaves 70 cents to a dollar in terms of net back.
There’s still finding someone to execute the project — to bear the risk of $5-$7-$8 billion in capital.
“I think as you look at it, what we can say is the opportunity is there,” Robinson said.
“The resource base is large and can support multiple alternatives. But I think as you should look at this pipeline option — you ought to look at it in the context of a North American solution.”
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