The Fight For Gas Supply

Transportation, petrochemical and liquefied natural gas (LNG) companies are gearing up to take advantage of natural gas liquids (NGL) produced from today's prolific U.S. unconventional shale-gas plays. But the time for signing long-term supply contracts with producers and building new capacity for the feedstock is now, as competition for the liquids looms on the horizon. And at the current price of $2 per thousand cubic feet (Mcf), competition is expected to grow.

In fact, at present, not all stakeholders in the upstream, midstream, petrochemical, LNG and transportation sectors can agree on the best way to make use of today's plentiful gas supply, according to a panel of experts and subsequent discussions recently held at Hart Energy's DUG conference in Fort Worth, Texas.

For example, Encana Natural Gas Inc. executives are encouraging the transportation sector to take advantage of the wealth of new natural gas reserves. "We can use natural gas in consumer vehicles, heavy-duty vehicles, off-road vehicles, mining equipment, offshore supply vessels and railways," says David Hill, vice president of operations for Encana Natural Gas Inc. "Using natural gas as transportation fuel has many benefits—the first of which is environmental, due to its lower CO2 footprint, which is anywhere from 20% to 30% less than diesel and gasoline."

In fact, a significant amount of the U.S. transportation market could displace foreign oil and consume almost 62 billion cubic feet (Bcf) equivalent of natural gas per day today, Hill says. Light-duty trucks can use 42.4 Bcf per day, heavy-duty trucks can use 10.8 Bcf per day, medium-duty trucks and marine vessels can use 3.2 Bcf per day in each sector, and railroads can consume about 1.3 Bcf per day.

Much of this infrastructure already exists, he says. Since 2009, the U.S. has experienced a 30% increase in compressed natural gas (CNG) refilling stations and a 31% increase in LNG refilling stations for transportation. Significant expansions of these services are occurring in the Rocky Mountains, the Texas triangle of Dallas-Texas-San Antonio and in the Southeast. Also, included on the list of states with natural-gas-vehicle refilling stations is California with 263 facilities, followed by New York (107), Utah (83), Oklahoma (70) and Texas (40).

Hill encourages E&P operators to switch to natural gas fuel whenever possible, and notes that, in addition to cost savings, the switch would illustrate the industry's desire to "walk the talk," which would encourage "an expanded social license to operate." Integration solutions could include drilling rigs, pressure-pumpers, supply transport, and fleets, vans and pickups used in the field. Indeed, Encana is walking the talk by converting 20% of its company pickup trucks to CNG and by building six CNG stations, says Hill.

Once-in-a-lifetime opportunity

Meanwhile, Ken Bromfield, U.S. commercial director for Dow Chemical Co., believes that the new wealth of gas from shale is "a once-in-a-lifetime opportunity for manufacturing" in the U.S. "But there is significant debate right now about how the U.S. can make the most of the possibilities that this resource offers," he says.

Dow Chemical is one of the largest consumers of NGL feedstocks in the world, and plans further expansions, such as its recently announced intention to build a $1.7-billion world-scale ethylene plant at its chemical hub in Freeport, Texas. The facility will have a capacity of 1.5 million tonnes per year, will use either ethane or propane as feedstock, and will employ up to 2,000 workers during the construction phase alone. Adding in the company's other planned projects, Dow could employ some 4,800 workers during construction and support more than 35,000 people in the broader U.S. economy.

While Bromfield sympathizes with oil and gas producers struggling with today's low natural gas prices, he is convinced that the answer to supply and demand issues lies in "balance and prudence."

"For the first time in more than a decade, natural gas prices are affordable and relatively stable, especially compared to oil," he says, noting that global oil is more than five times as expensive as natural gas on a thermal basis. "Low-priced gas results in lower utility bills for consumers, greater national energy security and billions of dollars in new investment. So while this presents immediate, attractive opportunities for gas producers to export that gas to other countries, it also presents the potential for investment in a U.S. manufacturing renaissance, which, over time, has even greater opportunities."

The new investment could increase the number of new manufacturing jobs, sorely needed due to continuing high unemployment rates in the nation, he says. The jobs, in turn, will increase exports of value-added products, sparking even stronger economic growth.

Just-once lens

"Natural gas represents a tremendous advantage for American industry," says Bromfield. "It's something that we need to nurture carefully, and we can't look at it through a just-once lens. We need to take a holistic approach."

Bromfield sees "an extreme, short-term focus on oversupply," and posits that the current market-clearing price represents only a temporary oversupply of natural gas, partially due to shale-gas production, and partially due to last winter—one of the mildest winters on record.

"We believe this is a very short-term dynamic. The focus needs to be longer term, at least six years out." In fact, he says, at least one-third of current shale-gas production will be needed to offset the decline of production from conventional gas resources. Further, Bromfield sees domestic demand already responding to lower prices in nearly every sector, including industry, utilities and transportation.

"The Energy Information Administration says the total demand for gas could increase by more than 65% by 2035," says Bromfield. "And that is without aggressive exports."

A number of factors will contribute to the supply-demand balance, he says. But the impact of those factors is uncertain. First, the power sector will shift from coal to gas fuel, but how much is yet undetermined. Second, the amount of gas to be used in truck fleets is undetermined. And third, the demand impact of the steel, glass and chemical industries is undetermined. Such industries are unusually sensitive to gas price volatility, he says.

"The point is, we are in very early developments of this shale-gas phenomenon, and we need to walk before we can run. We need to exercise caution, and not be so quick to export this once-in-a-lifetime gift."

If U.S. shale-gas consumption is planned over a longer period, the petrochemical, steel, aluminum, fertilizer, paper and glass industries, among others, can expand consumption economically, says Bromfield. At that point, prices should equilibrate to a level that can simultaneously nurture domestic production and create a manufacturing renaissance.

"Patience will lead to the ultimate payoff. If we compare the future opportunity for the country, between exporting LNG as a solution for the short-term supply situation, or having the patience to spur manufacturing, it isn't even close. The manufacturing sector creates five to eight jobs outside the factory for every one job created inside. When we export, we create only one-time value."

The petrochemical industry is especially sensitive to gas prices because the industry uses the fuel as an energy source and a feedstock. When gas prices are high or volatile, manufacturing suffers, Bromfield says.

"During the past decade of volatile gas prices, $30 billion in exports were lost, and 42,000 factories were shut down. But when prices are as affordable and as competitive as they are today, industries spawn investment and growth."

Bromfield cites the American Chemistry Council's research that shows that a 25% increase in natural gas production could create $16 billion in new investment and 17,000 new high-paying jobs in the chemical industry and hundreds of thousands of indirect jobs. In fact, U.S. manufacturing has created more than 400,000 jobs since January 2012, he says.

The threats to such growth include government policies that drive demand ahead of supply, promotion of a single fuel type, government incentives for natural gas vehicles, the forceful rapid conversion from coal to gas in the power sector, excessive constraints on hydraulic fracturing, and exports of "unreasonable amounts" of LNG and imports of value-added goods "that we could have made in this country," he says. "We are not saying we should not export LNG, we are saying that we need to make sure we have enough of this resource so we don't get into the situation that we got into during the past decade."

Other challenges to continued ample natural gas supply include fracturing regulations and bans in several states. The question is not just whether the massive amount of predicted gas reserves is technically and economically recoverable, but also if it can be produced in a safe and environmentally sound manner, says Bromfield. Certain environmental constituents can stop producers from getting the gas out of the ground. And then, game over.

"Let's don't put demand before supply. Before we start exporting 30 Bcf per day, let's make sure that it will not take away from the chemical, steel and fertilizer industries. We need to look at how to optimize this gift for the country, and that might not be sending those manufacturing jobs overseas," cautions Bromfield.

John Harpole, president of Mercator Energy LLC, disagrees. "I don't necessarily agree with 'let's don't export so we import jobs.' I think we have enough natural gas to really cover the gamut."

As a past employee of General Electric Corp. (GE), Harpole recalls when GE was purchasing natural gas for 20 power plants in upstate New York. About 95% of the gas came from the Gulf of Mexico, with occasional purchases of Appalachian gas during the winters—about 15%, to insure against long-haul interruptions. "But now, most of the GE gas comes from the shale plays," he says.

Today, most producers are heading into liquids-rich plays, he says. Yet, even if oil falls to $65 per barrel, more than 20 wet-gas plays will still be economical.

"I remember when we had coalbed methane Section 29 tax credits. In the San Juan Basin, a producer receiving that tax credit would produce gas at $0.05 to $0.10 per million Btu (MMBtu). I think the liquids-rich plays are driving the production profile, even for dry natural gas."

Harpole points to today's Permian Basin production as a prime example of low development costs for dry gas. The May 2009 forecast showed a linear decline of gas production, but when Permian producers realized the value of the liquids, the forecast jumped to an additional 1.4 Bcf per day.

No job exports

Between fourth-quarter 2011 and fourth-quarter 2012, U.S. liquids plays will contribute about 61% of the incremental volumes of natural gas.

"If we look at gas demand down the road, we can grow the demand for exports so that we are not exporting oil and gas jobs to other countries that are also trying to develop their shale reserves. I'd rather keep those jobs here and export natural gas. We've developed a technological widget that we should be able to export," says Harpole. "And LNG is a major part of that retention of U.S. oil and gas drilling jobs."

Meanwhile, foreign oil companies, such as PetroChina, BHP Billiton, Statoil ASA, Korea National Oil Corp. and China National Offshore Oil Corp. have invested in North America to learn shale-gas technology and the manufacturing process for natural gas, which has changed tremendously from 20 years ago, he says.

For example, in 1988, producers were hard pressed to project completion dates within a range of three days, and were drilling exploratory wells with a 1-in-10 chance for success. Today, in the Piceance Basin in western Colorado, one producer claims to have attained a record 120 consecutive good wells.

"When I look at these national oil companies as investors in these shale plays, I think that, in many instances, they might want to take that natural gas and export it to their countries," says Harpole. "Do they care about the price of natural gas in the U.S.? Is this a simple financial transaction where they want to maximize their investment? Or are they looking for the technology and manufacturing process and the ability to export?"

Beyond the national companies' likelihood of gas exports, Harpole advises that the U.S. should consider all four significant demand factors, including U.S. LNG exports, industrial demand growth, coal-to-gas electric generation fuel switching and CNG vehicles—and possibly a fifth being exports of natural gas to Mexico. Yet, none of these scenarios will generate enough demand response within the next three years to significantly change the current gas-price environment.

Specifically, for an LNG-export solution, Harpole points to eight LNG-export projects now planned, including the Sabine Pass Liquefaction, Corpus Christi Liquefaction, Freeport LNG Expansion, Lake Charles Exports, Dominion Cove Point, Jordan Cove Energy Project, Cameron LNG and Gulf Coast LNG Export, which could total some 15.5 Bcf per day of capacity by 2027. "The problem is, it is difficult to get any of those facilities up and running in the next two to three years to relieve some of this oversupply condition," he warns.

According to his data, Asian countries such as South Korea, Taiwan, coastal China and Japan receive 90% of their consumed natural gas by boat. "As you know, we can put 3 Bcf of gas on one boat, which would heat 50,000 U.S. homes in one year. When you freeze natural gas, it reduces it by 600 times. The amount it would take to fill a beach ball would then fit into a ping-pong ball."

Also, in the petrochemical industry, the favorable gas price is likely to encourage new ammonia-manufacturing capacity, says Harpole.

"One portion of industrial demand growth is just stunning. About four months ago, ammonia was worth about $590 per ton in the world market. Based on current U.S. gas prices, we can produce it for $180 per ton. It's no wonder that there are so many ammonia makers that would like to come back to the U.S., specifically to Louisiana and Texas," he says. About 33 MMBtu of natural gas is needed to produce 1 ton of ammonia.

Also, North America imports about 12.5 million tons of nitrogen per year, including 22% of that from Canada and 78% from overseas. About 37 MMBtu of gas is roughly equal to 1 ton of nitrogen, so if all overseas nitrogen imports were eliminated by domestic production, natural gas demand would increase by 1 Bcf per day, he says.

Coal and transportation demand

Meanwhile, new numbers are emerging in the coal versus natural gas debate. Power generators are taking a hard look at future feedstocks. According to recent reports, the collapse in the price of U.S. natural gas, since 2008, combined with recent increases in the cost of Appalachian coal, caused the variable cost of operations for the average power plant burning Appalachian coal to converge with that of the average combined-cycle gas-turbine generator. While coal accounted for 57% of all power generated in the U.S. in 1985, that percentage has fallen to 42% in 2011, and is projected to fall to 41% by yearend.

"I think we will see a big number, down the road. For now, about 54 gigawatts of the coal-fired capacity of power generators will cease operations and another 12 gigawatts of coal-fired capacity is likely to be retired when those units reach 60 years of age," says Harpole. "About 48% of the coal plants in the U.S. are nearly 40 or more years old."

Also, a recent study from Bernstein Research shows that the U.S. consumes about 60.5 Bcf per day of gas. By 2015, that demand is expected to increase 3 Bcf per day due to coal plant retirements and increased regulations against sulfur dioxide and mercury emissions. "That incremental 3 Bcf per day is equal to one LNG tanker," says Harpole, depicting the small amount of incremental demand from coal switching compared to LNG exports.

Meanwhile, although an increase in the number of U.S. natural gas vehicles (NGVs) would increase natural gas demand, a reasonable increase would not have a significant effect on demand. For example, the U.S. has about 110,000 NGVs on the road, mostly owned by fleets, which represent less than 0.1% of all vehicles, he says.

"To get to 1 Bcf per day of incremental demand, we would have to increase NGV vehicles by a factor of 10," says Harpole. "That would require incentives and plenty of time. NGVs are terrific, and we have to chase that, as an industry, but look at the relative volume of demand as compared to LNG exports."

Overall, projected LNG exports, industrial demand growth, coal displacement, and NGVs will only increase demand by 3.3 Bcf to 7 Bcf per day by 2015.

Do it all

"Today, we produce about 64 Bcf per day. Experts predict that the 2020 supply will be somewhere between 77 Bcf and 80 Bcf per day," says Harpole. "So we should really consider exporting gas while we have this window of opportunity, about 10 to 15 years, before the other countries, which have invested in our shale plays, take advantage of that technology and manufacturing processes to develop their own shale production."

Logan Magruder, chief executive for Chief Oil & Gas LLC, agrees. "The fact that the 3 Bcf per day of gas supply growth during the next five years can be satisfied with one LNG tanker is quite sobering. Low natural gas pricing is really a gift to the economy right now. I just wonder if the political process will realize that if they will allow exporting to take place, it would obviously decrease supply and start to balance the supply and demand curve so prices will go back up."

Encana's Hill says, "At 3 Bcf per day, we'd like to do it all, and I think we can. I've been drilling wells for 30 years, and I think we have a very abundant resource in this country. We should diversify its use. That could mean building an export facility at Kitimat in Canada. There is still stranded gas in North America. And we have a wonderful resource in the Montney and in the Horn River waiting for a market. So I think the opportunities are there for everyone. But it will take time to develop these new demand venues. We look at natural gas vehicles at 4 Bcf per day, but this country is slow to build those. Consumers don't want to change their habits."

In addition to time, billions of dollars will have to be spent on investment, he says. An LNG export plant costs billions of dollars. "And new gas-to-liquids plants are being talked about," says Hill. "There must be tens of billions of dollars spent in this country, which is all possible."

That's good for the economy, but perhaps not so good for petrochemical companies that are counting on cheap supply for their plants, but which do not have long-term supply agreements with producers.

Long-term contract debate

"With no slight to Dow," says Harpole, "if you want long-term price security, sign up now for long-term natural gas. I can name 40 producers that have coalbed methane dry gas that they would marry to a long-term contract, but they are not going to do that for $2 per Mcf, because their finding and development costs are higher than $2."

Harpole advises the gas-consuming industries to agree on a long-term price with a producer and then invest in that producer's assets that might otherwise slip off their portfolio, due to Security and Exchange Commission rules, because they are not currently developing those assets. "You don't have to have a counter-party credit deal," he says. "You can do a creative deal where you actually invest in those upstream dry-gas assets."

Yet, Tim Williams, vice president of upstream and feedstock acquisition for Methanex Corp., has his doubts about that possibility. "One of my jobs is to buy 100 MMcf per day of gas for delivery in Louisiana on a 10-year contract. What I have found is that most companies that have natural gas are strangely unwilling to talk about long-term contracts linked to something that has an 88% correlation coefficient with crude oil.

"We'd pay a price significantly higher than current market price, and yet, long-term contracts have been fairly alien to the industry since the 1980s. I think the gas industry is shooting itself in the foot with its contracting practices," he says.

Harpole disagrees, saying, "I am representing two ammonia companies trying to find long-term contracts. We called 14 producers to see if they would engage in long-term contract negotiations, and 14 said absolutely yes.

"The issue is the smaller producers' credit capacity and ability. So I've seen a unique type of contract develop during the past six months where, for example, a steel company would invest in the actual natural gas drilling in an area that is 99%-guaranteed good well results, such as in western Colorado and southwestern Wyoming. Just in the past four to six months, I have seen producers be more willing to do something creative," he says.

Encana's Hill agrees that long-term contracts and counter-party risks are issues that need to be addressed. "We have found very creative ways to negotiate contracts. We've done a deal with a gas utility where they took a working interest upstream. We've done one with a steel company and a few others that we can't talk publicly about, but these deals are happening. They are a good way for both companies to share the risk. We can't drill dry gas, today, without a hedge and a long-term commitment."

Says Dow's Brumfield, "As one of the largest industrial consumers of natural gas, we have encountered similar issues. We understand that no producer wants a fixed-price contract at $2. But when we do fix a price, we take the risk, because we have to make a bet about what that price is going to be. Even if it is low, if we are wrong and the market goes against us, our competitors won't be in the same situation and we will lose our shirt."

In addition to fixed-price contracts, Brumfield says market-priced contracts can be an issue. "Folks want the Nymex forward curve, but why buy a long-term contract when you can just buy the curve? So the simple solution of 'just give them long-term contracts' isn't the simple panacea that it is being made out to be."

Harpole argues that producers would be willing to sell gas on a long-term contract plus a reasonable internal rate of return. And because the gas price is likely to be lower in the U.S. compared to other countries for quite some time, "I don't see your investment in plants at risk," he says.

But Brumfield answers, "We haven't seen that internal rate of return option, or at least them being reasonable. We have found that they want a lot more. But it's not just that. If our competitors don't lock in the same price that we do, even in the U.S., we could be in trouble. It just not as easy as it appears to be." Also, argument can be made that even fixed-price contracts are not stable, and often do not last their lifetime.

Trust issues

As high levels of dry-gas inventories continue to be a detriment for gas production, and drillers stop drilling for dry gas and turn to oil and rich-gas plays, when will overall gas production begin to fall? Not anytime soon, says Porter Bennett, founder of Bentek Energy.

"Admittedly, there are not nearly as many producers drilling for dry gas as there used to be," he says. "But the Haynesville and some of the dry Marcellus are the only two places where we see big enough initial-production wells that, if you completely quit drilling, would impact the production curve. And producers are not going to stop drilling in either of those places. In fact, new data suggests that, even if those areas were completely shut down, that still wouldn't offset the switch to rich-gas plays. There is just too much gas coming out of plays like the Granite Wash and the Eagle Ford."

The gas coming from those plays can be considered a costless commodity, he says. The only event that might change that production is if the oversupply of ethane becomes acute, or if the price of crude oil falls into the $45- or $50-per-barrel range.

Given the overwhelming data, from production to storage numbers, why are many gas consumers, such as makers of NGVs, petrochemical companies and LNG export terminals still so reluctant to invest in long-term low-cost gas supply?

"Can you blame them?" asks Bennett. "In 1993, the co-generation movement, such as Enron Corp. with all its turbines, put a lot of long-term deals together. Just about the time they got that in full gear, all of a sudden we ran out of natural gas again. The chairmen of Chevron Corp., ExxonMobil Corp. and the National Petroleum Council all said we are running out of gas. So why would anyone in their right mind automatically attribute credence to the performance of the industry? We have to overcome that—and it is going to take time."