Upending the U.S. Energy Sector

In the 1990s, developing a way to economically extract shale gas in the United States was but a pet science project of a few geologists, engineers, and one visionary. Shale gas was very difficult to obtain and expensive to get, after all. It's in low permeability rock formations deep underground. Gas and oil molecules have a very hard time traveling through the rock into the wellbore. But when Texas oilman George Mitchell and company figured out how to combine two old technologies--horizontal drilling and hydraulic fracturing--the key to shale gas was unlocked. They ignited a shale-gas boom that has transformed the industry in the United States.

To understand how shale gas is affecting the U.S. energy sector, I sat down with Morningstar energy analysts Jason Stevens, David McColl, and Mark Hanson. Our discussion took place Feb. 11 and has been edited for clarity and length.

Basili Alukos: Take us through the past decade and the changes the shale-gas industry has experienced.

Jason Stevens: Shale gas has upended everyone's expectations. Ten years ago, the industry was racing to build as many liquefied natural gas (LNG) import terminals as possible, because we feared that conventional gas in the United States was in terminal decline. It was dropping off by close to 3% a year, and gas from the Gulf of Mexico was not ramping up at the rate everyone expected. We were plugging much of the gap with imports from Canada, but that had begun to flatten out as well. Folks were looking at demand growth of 2% a year and seeing a huge supply gap. The thinking was that we're going to need to import lots of gas from overseas, which by the way is difficult and expensive to do.

But then came George Mitchell, the father of fracking, who owned a firm called Chief Oil & Gas. The company was experimenting in a formation called the Barnett Shale basin near Dallas-Ft. Worth. They finally "cracked the code" by combining hydraulic fracturing, which uses water pressure to crack open the rock formation to allow gas molecules to flow from the rock strata into the wellbore, with horizontal drilling.

To illustrate why this technology has had such a huge impact, let's look at an example. Say a rock strata is 200 feet thick. If you have a wellbore dropping through it vertically, you have 200 feet of what we call "net pay of contact" with that formation. But if you can turn the drill bit and go horizontally through that 200 foot strata and run that for a mile, then all of a sudden instead of 200 feet you have 5,280 feet of contact with the reservoir rock. So, by turning the drill bit and drilling a horizontal well and then fracking the whole length, you tremendously increase the volume fed by a well.

As soon as the shale-gas code was cracked, exploration and production companies (E&Ps) began re-evaluating all of the productive regions in the United States. Capital flowed to exploration programs, and in short order, the Haynesville Shale in Louisiana, the Marcellus Shale in Pennsylvania, and the Bakken Shale in North Dakota and Montana were explored and developed--from science project to commerciality.

Alukos: We've seen a massive increase in shale-gas production because of technologies. Can technology be used to help natural gas and shale gas supplant other forms of energy? Can we use this natural gas to benefit the rest of the economy?

Mark Hanson: There are not a lot of opportunities for substitution. One idea that has been bandied about is converting petroleum-based engines into natural-gas-based engines. That is unlikely to take place in the near term, at least on a large scale. We have more than 100,000 gasoline stations across the U.S. that would have to convert to natural gas. Creating the needed infrastructure would be expensive.

More likely, consumption growth of natural gas will come from new sources of demand, such as exporting natural gas in the form of LNG. That's likely to start happening in significant amounts beginning in 2015. It will start modestly but grow from there. Additionally, we've seen a resurgence in chemicals-manufacturing facilities, which either had been mothballed or moved overseas.

We also have the potential to export excess supply via transnational pipeline to Mexico. There's a litany of proposed pipelines.  Kinder Morgan (KMI) is a company that's leading the charge there, with potential to install up to $2.8 billion in new infrastructure over the next 15 years that will export meaningful amounts of natural gas to Mexico. Next year, the U.S. will likely export 2 billion to 2.5 billion cubic feet of natural gas a day to Mexico. To put that in context, the United States consumes about 70 billion cubic feet a day.

The big point here is that there are emerging sources of demand beyond just what we presently consume for heating. But on the whole, if you look across commerce, residential, and power generation, sources of demand will stay at a fairly steady baseline. The incremental sources of gain will be export, either dry gas via pipeline or LNG, and power generation, because of environmental concerns and likely regulatory impacts of shutting down coal plants, which would increase the natural-gas use for power generation.

Stevens: A lot of people in the United States point to this idea of using natural gas to power cars and trucks. But these people should keep in mind that the U.S. auto fleet stock is roughly 12 years old on average. Even if you were to introduce a natural-gas-compatible engine in every car manufacturer's model lineup tomorrow, it would take a long time before it would gain any real critical mass. Look at the adoption rates of hybrids and battery-powered cars. Sure, the hybrid model works, but it's been more than a decade since its introduction. It's nowhere near double-digit penetration into the auto market.

The infrastructure problems are quite complex. There are local and interstate distribution pipelines that move gas all over the country, but to source gas to filling stations in quantity in order to be put into an engine on demand would require many tens of billions of capital spending--just to build that infrastructure out.

The third big knock against natural-gas vehicles is energy density. Natural gas is a less-dense fuel source than oil-derived gasoline or diesel. Natural gas is methane. It's CH4. There's only one carbon molecule. Gasoline is long chains of carbon molecules. There's a lot more stored energy in gasoline; the energy equivalence is a 6:1 ratio. You've got to load up a lot of volume of natural gas to get the same distance traveled as a gasoline-fired engine.

These are big knocks against the natural-gas vehicle dreams of many folks out there. So, new engine technology is not going to be a silver bullet for natural gas. We don't see it as likely that you're going to get the demand pull side of the equation for natural-gas vehicles anytime soon, absent effectively, a congressional mandate.

Alukos: It sounds like we're close to having the technology for energy independence. It's just a question of when we actually want to achieve it.

David McColl: It also depends on how you view the energy-independence equation. As Mark and Jason have been saying, natural gas is not a perfect substitute for oil.

Converting natural gas to liquid is not cost competitive at this point. Yes, it's possible to imagine deploying large fleets of heavy-duty vehicles that use central natural-gas fueling stations. But think of residential use. You have to build up not only long-haul pipeline infrastructure, but infrastructure throughout communities and urban areas. There are just a lot of challenges that we'd have to deal with.

Stevens: Roughly 70% of the U.S. oil consumption is for residential and light-vehicle driving. The biggest threat to gasoline-fired engines isn't natural gas. It's new, developing technologies outside of gas. Self-driving cars are being developed.  Google (GOOG) is pioneering this technology right now. These cars can queue and dispatch with a lot more efficiency than everyone having their own car. Then, there's the development of the electric engine. It is much easier to run the last mile of wiring to put high-voltage lines into a garage than it is to run the last mile of gas pipe into a filling station. These technologies will revolutionize car driving over the next 20 to 30 years more than natural gas will.

Alukos: We talked a little bit about pipelines, or at least the midstream part. Are there any plays centered around the midstream aspect of natural gas that might be interesting?

McColl: What is really interesting in the midstream space is the significant impact that Marcellus has had on pipeliners within Canada and the United States. The Canadian side is an interesting story. Canada had been exporting about 8 billion cubic feet of natural gas per day into the United States at the turn of the century. Now, net exports from Canada are about half that, and thanks to growing Marcellus production, we expect net exports from Canada to drop to 0.5 billion cubic feet per day by 2020. That is a significant decrease in exports from Canada into the United States, and it's had a significant impact on pipeliners. Companies such as  TransCanada (TRP) were created along with a main line running from producing regions in Western Canada to Ontario. They are now considering converting 36-inch pipeline from transporting natural gas to crude oil. That's a direct result of the boom in production from Marcellus.

Stevens: The single factor driving shale gas right now is the Marcellus shale. The Marcellus shale has grown from nothing in 2009–10 to close to 25% of the total gas production, and it is likely to continue to grow at double-digit rates for the next several years.

The Marcellus has upended the geography of gas. The U.S. pipeline network has been built since the 1940s to move gas from Texas and the Gulf of Mexico up to the Midwest and Northeast for our long, cold winters. Well, the Marcellus sits in the Northeast, and all of a sudden it's producing enough gas, on an average annual basis, to supply the Northeast with all the gas it consumes. It has displaced gas imported from other regions, and as it continues to grow that gas needs a market.

So, the biggest infrastructure opportunity out there in the energy patch is to build out the plumbing that moves Marcellus gas to new markets. We think the company best positioned to do this is  Spectra Energy . Spectra Energy is a natural-gas pipeliner. It owns a legacy asset, the Texas Eastern system that runs from the Gulf Coast all the way up to New York, and it owns many other natural gas pipelines. But it has been among the companies at the forefront of building out this new infrastructure to handle Marcellus gas. Spectra Energy also has a master limited partnership subsidiary, Spectra Energy Partners , which houses all of its U.S. natural gas pipelines. We think it looks like a solid investment today.

Alukos: There's been a lot of talk of natural gas prices stabilizing at low rates, and there's a bear case that as efficiency improves prices may fall even further. What's your take?

Hanson: The oversupply conditions in the U.S. are like a walled garden. If we have a period of oversupply, there's not anywhere for excess supply to go. So, we're going to see a very sharp downward response in prices. We saw that with oversupply conditions in 2011 and 2012, when there wasn't enough consumption, given the warm winters in the United States, to balance out supply-and-demand conditions.

If we look at the incremental cost to bring on that last thousand cubic feet of gas, it's between $5 and $6. There's been downward pressure on that marginal cost. People tend to get better at what they do over time; they figure out how to extract more oil or gas from a given volume of rock with a given level of equipment for a given amount of money. But on the whole, the right price is probably somewhere between $5 and $6.

I'm not of the opinion that natural gas is likely to stay in the $3 or even $4 range. If that were to be the case, there are low-cost producers that can take advantage of that. If you were to look at the supply stack, there's a sufficient amount of capacity that can make money at $2 per thousand cubic feet, which would be roughly 40% of today's prices. But even beyond that, to meet the incremental demand that we see, there's going to have to be the incentive in the form of a price increase to bring on new supply.

So, if you are looking to take advantage of the current disconnect between strip prices and what we see as a more normalized price environment,  Ultra Petroleum would be one idea. It's certainly not without its issues. But it's fairly low cost; it can break even at around $3 per thousand cubic feet. The company has chosen to pare back its drilling activity, given current low prices, so it's trying to preserve the value in the ground for a more constructive price environment. That's the biggest disconnect between what all the cash flows could be worth from that company and what it's now trading at. Most of the other low-cost firms have been effectively bid up to what we would say is fair value right now.

This article originally appeared in Morningstar Magazine. To learn more about Morningstar magazine, please visit our corporate website.