JD: Tell us, how do you see the situation with U.S. natural gas?
DP: One of the issues with the U.S. or North American gas market is that it has changed dramatically from 3-4 years ago, in that 3-4 years ago there was lots of construction of gas-fired or planned construction that ultimately materialized gas-fired power generation units, both fine cycle baseload units and simple cycle peakers that are used mainly in the summertime.
Why natural gas? It’s cheap, it’s clean environmentally; on the power side, its units are lower capital costs, gas is plentiful, we’re not importing gas from anywhere other than Canada, our best friend to the north, etc. If you want to grow supply, all you do is drill more wells.
Where we are today is a much a different picture where we have figured out pretty quickly that we can’t drill our way into more supply. We found that out in dramatic fashion in late 2000 and early 2001. We have a situation where our neighbor to the north, Canada, is probably going to experience gas production decline in 2003 for maybe the first time in a very, very long time, and the outlook is for further decline in 2004. If you extrapolate that, Canadian production will be down, then imports from Canada to the U.S. should be down as well.
When we look into Mexico, four years ago people expected Mexico to be a net supplier of gas to the U.S., that picture again has dramatically changed, where Mexico is now a net consumer of U.S. gas, on the order of ¾ billion cubic feet a day. In fact, the most recent data which expands the second third quarter of 2002 shows that we shipped on a net basis more gas to Mexico than the U.S. imported via LNG.
JD: In case anyone listening doesn’t know, LNG stands for liquefied natural gas.
DP: So LNG imports are not even offsetting U.S. exports of gas to Mexico. That’s a materially different situation today than we found ourselves in. The U.S. natural gas industry is actually in fairly tenuous ground because if you can’t supply demand growth, then you can’t have demand growth. It’s relatively simple economics.
JD: So what will happen to demand, then?
DP: You still build these power plants and the electricity sector to the end user of that power is probably less price sensitive than the average guy, so to the marginal consumer of gas is the industrial sector – your petrochemical plants, your glass plants, your rubber plants, paper, paper products, lumber, those folks who in a relatively weak economy, as we have now, probably have very little margin to begin with, and then we throw significantly increased higher input energy cost at them. So some of those guys are going to go away. Petrochemical plants are going to go elsewhere. That trend has happened and the higher gas prices go, the more accelerated the pace you’ll see over the next number of years.
JD: How do you see the North American natural gas outlook for this year?
DP: When you look at the gas market, gas storage is the buffer where in the wintertime demand exceeds supply so we pull gas out of storage to meet incremental winter heating demand. In the summertime there’s more supply than demand and gas is injected in the ground in anticipation of increased winter heating demand. So the injection season is very important to make sure there’s enough gas in the ground in front of winter. We think there’s certain minimum storage requirements that need to be filled before winter starts. Our sense was that even before this winter where we modeled, conservatively, a relatively warm winter, our view was because of the issues with supplies, supply declining and imports likely to decline, that there was no room for industrial demand expansion in 2003. The industrial demand is roughly 20 – 25% of the total demand, depending on how you count it. Probably 25 is a good number to use. Where are we now?
Winter has been colder so we’ve used more gas in storage or we’ve used more of the surplus, if you will. When we’ve finished the winter, there will be a bigger need or bigger demand to fill storage during the summer injection season. In fact, as we run our supply and demand model, if we keep industrial demand static, you can’t get there. You can’t fill storage. So what does that imply? That implies that either the supply side has to be materially better than we think, and that probably isn’t going to happen, or you’re going to have to cut some demand out of the system to free up some gas to inject and that’s what’s precisely we think will happen.
And how does that demand get removed from the system? It gets removed via price.
It’s exactly what happened two years ago. Whether gas goes to $10 again, is very, very tough to call, but ultimately gas prices will have to go high enough to price enough demand out of the system to ensure that there’s enough gas available for injection. If you think about it, the industrial consumer is all about economics. The local utility who’s buying and injecting gas in the summer doesn’t really care because that entity has ability to pass all of their costs through to the consumer and they don’t want to go to their local or public utility commission and explain why my grandma’s heating bill has gone up, but they sure don’t want to go in front of that public utility commission at the end of winter and try to explain why grandmother didn’t have enough gas. They are absolutely the least price sensitive or the most inelastic group of buyers out there and they will compete with the industrial customer. They will push the industrial customer out of the system.
JD: Does that have implications for power generation, like this year?
DP: Well, it may, to the degree that reduction in industrial capacity impacts electricity generation, but most of the industrial consumers who are levered, who are most susceptible to high gas prices are those folks who use natural gases as feedstock, so if you’re making methanol, or ethylene, or ammonia fertilizer, you’re going to use natural gases as an energy input and a feedstock. So if you’re making basic fertilizer, as an example, even in good times, natural gas may comprise 80% of your total cost of finished goods. So when prices go to $8-10, you can imagine the impact on those companies, particularly given that in the global petrochemical business, there’s a glut of capacity and that capacity can be imported. So if I don’t produce fertilizer on the Gulf Coast, I import it. And that’s precisely what happened two years ago.
JD: Would you say that we see this as an example that shows that natural gas is a much more regional hydrocarbon than say oil?
DP: Yes, if you try to compare and contrast the natural gas market, it’s pretty interesting when you juxtapose gas against crude. Here’s crude oil where there’s excess capacity globally on the supply side, and OPEC has almost all, if not all of the excess capacity in the world, and they try to manage the supply and demand balance by regulating supply. So in the global oil market, supply tends to be the relief valve. Prices go up and OPEC adds more supply; prices go down and OPEC takes supply away. Quite frankly, they’ve done a pretty good job over the last little while doing that.
In the gas market, supply is relatively fixed. U.S. supply was down last year; it’s going to be down again this year. Canadian supply is down as a function of mature basin, mature assets and the inability to drill where the most promising reservoirs are. Whether that is a good or bad public policy decision is not my case to make, but the fact is you can’t get blood out of a turnip – you keep drilling the same basins over and over again, there’s no supply growth.
So what happens? Demand has to be the relief valve because LNG imports at this juncture are insignificant. 5-10 years from now, that’s probably a different story. At the end of the day, LNG imports are kind of the one supply side swing factor, they’re not enough to matter on the margin so you have the demand side that tends to regulate a tight market or a market that’s over supplied and demand responds to market pricing signals. So you’ve set up a regional market on a very big regional market, North America, where by definition of gas prices is going to be very volatile because the market is working.
JD: In the light of what you’re saying, where are the hundreds or thousands of new liquefied natural gas ships and the dozens of terminals that will be needed to support them? Are those being built in the U.S. now?
DP: Well, you know that’s the question. The companies that were going to build all the LNG tankers are the same companies that are fighting to stay afloat here. The Enron, who went away in El Paso, those companies were the most logical buyers and builders of incremental capacity. Now you get some LNG growth over time but the question is, is it enough? And the answer is, probably not. If you’re looking longer term, a decade away, maybe you’ll get a pipeline built up to the north slope of Alaska where’s there no question of significant resource. There’s 8 billion cubic feet a day rejected in the gas cap at Prudhoe Bay everyday. You just need to build a pipeline to Prudhoe and you’ve got the potential for 4-5 bcf a day of offtake. But 10 years and $25 billion is probably what it takes to make that happen.
JD: The production and exporting to America of Canadian natural gas has been an important factor in the U.S. hydrocarbon picture for some time. But now it appears that Canadian natural gas production has peaked and has moving into decline. Can you say anything more about that?
DP: Yes. I think a declining Canadian production in 2003 will be a bit of a watershed event, a wakeup call. You can look at Canadian production over the last few years and clearly all of the growth has been driven by two areas: one, a field in the western basin called Lady Fern, and the east coast development called Sable Island. Between the two, they comprise over a bcf of combined capacity. Sable is experiencing water problems and will probably plateau or even decline in 2003. Lady Fern is on a very well documented high decline rate. The two engines for supply growth in the last 2-3 years aren’t there anymore so now you’re stuck with the majority of the western Canadian sedimentary basin which is fighting some of the same maturity issues that much of the U.S. is and so you build a pipeline up to the MacKenzie Delta. I think the prospects for growth out of Canada continue to be somewhat illusory.
JD: How do you think Americans are going to react when they discover that there is not, after all, boundless and infinite amounts of natural gas in North America, and that’s it’s not so easy to import?
DP: You know, Americans are consumptive pigs, right? We consume 20 billion barrels of oil a day, over 25% of the global oil demand. We consume a huge amount of natural gas.
Quite frankly, the Americans in general, are not educated about where those resources come from and what the implications are. You think that’s crazy, having fought 10 years ago in the Middle East because Saddam Hussein took over a key oil exporting country and the situation we have now in Iraq. But quite frankly, the American consumer is a bit of a whiner. They don’t care until prices are high. There are many unfortunate outcomes of the Enron and the trading scandals but I think one of the most unfortunate outcomes is John Q. Public saying that the whole energy crisis was a figment of Enron’s imagination.
I’m not sure there’s a real recognition that we have a shortage, a tight market out there and it will take another run on prices to make that happen, I’m afraid.
JD: The informed American observer may look at the situation and think, but the U.S. is exporting natural gas to Mexico. If we’re short of it, why are we doing that?
DP: It’s the free market – they’re willing to pay Houston ship channel prices for the gas, so they get the gas. Right? NAFTA says that if they can pay for it, they’ll get it.
JD: Does that mean that NAFTA is working the wrong way this time?
DP: Or the right way, depending on… I’m a free market guy so I wouldn’t say that it’s not working. It’s working, but again, the issues are striking with regard to who is ultimately going to be able to pay for the gas, and who’s not.