(Editor’s Note: Adapted from Historic Opportunities from the Shale Gas Revolution)
Natural gas has long been recognized as a preferred fuel for residential or commercial heating, industrial processes, and power generation, as well as a valuable chemical feedstock. However, despite its myriad advantages and uses, it has had difficulty reaching a market share reflective of its technical potential. The key question is if the resource base unlocked by the shale gas revolution will result in reduced prices and volatility. Infrastructure growth is at the heart of this question.
Price swings and demand volatility have dampened enthusiasm for major gas-based investments in the past. The new abundant supply picture has brought not only lower prices but, in our view, also increased confidence that the supply/demand balance has permanently shifted in a way that will reduce volatility. The geographic dispersion of shale plays reduces vulnerability to weather-induced supply disruptions, which may have contributed to historic volatility, as production from the Gulf of Mexico becomes a less significant source of overall supply.
As the supply has increased and interest grown, infrastructure has followed the market. The necessary expansion in infrastructure is already well underway and we expect this trend to continue. Capital expenditures for gas infrastructure development are forecast at $205 billion from 2011 to 2035, which would expand the mainline gas transmission system by approximately 35,600 miles and create an additional 589 Bcf of working gas storage by 2035.
Exhibit 1 provides an overview of recent and planned natural gas infrastructure additions.
While we are confident that the fundamentals are in place for sustained expansion of natural gas production and deliverability, low gas prices raise concern about the development of the resource; persistently low prices may dampen enthusiasm for additional production.
We believe that current low gas prices result from a “perfect storm” that included a historically mild winter (resulting in gas storage oversupply), slowed economic growth and continued supply expansion. These conditions are poised to turn around. We expect prices to firm over the near term as supply comes back into balance and the current supply overhang is worked off.
Part of this rebalancing comes from a shift in upstream producers’ exploration and production strategies, leading them to focus on oil and wet gas plays instead of maximizing dry gas production gains. Wet gas plays tend to provide more attractive margins given historically low natural gas prices. This shift in development strategy, coupled with heating season demand, should continue to “work off” some of the supply overhang weighing on short-term pricing.
Exhibit 2 provides a graphical representation of the supply overhang and rationalization process as reflected in forward pricing for NYMEX Henry Hub Futures contracts.
While recovering shale gas is now economically attractive, it remains a capital intensive activity, with typical horizontal wells costing $5 10 million depending on location, geology, and commercial factors. Some estimates put total cumulative capital expenditure for upstream natural gas production at over $2 trillion between 2011-35. These upstream investments average $80 billion annually over the period, and are associated with total dry gas production of roughly 35 Tcf annually by 2035.
Over one-quarter of these upstream investments are for the incremental growth in natural gas production, which would require over $560 billion in investments between 2011-35, and support over 500,000 new upstream production and supplier jobs by 2035.
Consumption And Economic Impact
Provided the necessary steps are taken to fully exploit natural gas resources, we project U.S. consumption will grow from 23.8 Tcf in 2010 to 31.5 Tcf in 2035, or an increase of nearly one-third, driven largely by gains in the power sector, as well as sustained industrial consumption, LNG exports, and potentially increased use of natural gas for transportation (see Exhibit 3). An overview of projected growth in domestic gas consumption in key parts of the domestic economy is presented in Exhibit 3.
The electric generation sector would be the prime consumer of the expanded gas supply, with gas-fired generating capacity capturing the lion’s share of new builds in the power sector. Gas consumption in the power sector is forecast to nearly double between 2011-35 increasing from 7.5 Tcf (21 Bcf/d) to 13.3 Tcf (36 Bcf/d) in order to serve an additional 280 GW of gas-fired generating capacity that will be brought online during this period.
This enormous expansion in the gas-fired generating fleet would require $245 billion in capital investment. It would also more than double the labor force in the sector, which is forecast to rise from 50,000 to 120,000 employees between 2011-35. These employment gains include operations performed at the plants, as well as services, equipment, and materials provided to maintain plant operations.
Industrial Gas Use
The industrial sector has historically been the largest natural gas consumer in the U.S. economy. However, during the past 15 years gas consumption in the industrial sector has declined by 20%, as manufacturers became more efficient, shifted production overseas, or moved toward less energy intensive products. Higher gas prices and price volatility from 2000-10 had a significant role in this decline, and a particularly negative effect on such gas-intensive feedstock industries as ammonia and methanol, causing plant shutdowns and increased imports.
The abundant supply of relatively inexpensive natural gas from the shale gas revolution has already begun to reverse this decline. Recent lower gas prices and increased supply have resulted in a surge in industrial gas use, allowing shuttered ammonia plants to reopen and other plants to be built or relocated from abroad. States are now competing with each other to provide economic incentives to induce construction of capital-intensive new plants within their borders. These developments can create a large number of direct and indirect jobs and significant base load demand for natural gas—one ammonia plant (producing 1,500 metric tons of product per day) could consume 44 MMcf/d.
Within the industrial sector, natural gas is used as both a fuel and feedstock. The largest gas users are quite energy-intensive and include the food, paper, chemicals, petroleum refining, non-metallic minerals, and primary metals industries. These industries account for 79% of total industrial gas consumption, while chemicals and petroleum refining alone account for 46%. Industries that use gas as a feedstock tend to be the most gas-intensive; these include ammonia, hydrogen and methanol production.
One high-use industrial application for natural gas is as a feedstock for GTL facilities. These plants convert natural gas to liquid fuels, primarily a low-sulfur diesel fuel. This is another path to apply natural gas for transportation applications, but the investment would be in the fuel production rather than the delivery infrastructure and vehicles, since the fuels are compatible with conventional diesel and gasoline engines.
It is likely that two GTL plants would be built in Louisiana: a Sasol plant is expected to come partially online in 2017 and fully in 2018, and a proposed project from Shell is expected to come online in 2019. These plants would require capital investment of $27 billion over the 20-year life of the plant, and create nearly 215,000 direct and indirect construction and operations jobs over the 20-year period. These plants would also be major sources of natural gas demand, consuming a total of 2.6 Bcf/d (949 Bcf annual), or an incremental increase in GTL gas use of 17 Tcf over an 18-year period (2018-35).
If the two GTL plants are successful, the U.S. may experience further GTL development. Because the GTL product is a petroleum substitute, a GTL plant’s economic viability is a function of the gas and oil prices. GTL plants require natural gas prices around $5 to $6/MMBtu to be economic if crude prices are $80-90/bbl. With gas and oil prices projected to stay in these ranges, based on the forward curve, GTL plants may prove to be a profitable long-term investment. That said, the capital cost is significant, nearly $10 billion for a 100,000 bbl/d plant and one plant in the Middle East has gone significantly over budget. GTL plants constitute a significant capital risk in the event that the fuel price spread shifts over time.
LNG For Export
Another important potential source of gas demand—and significant balance of trade benefits—is development of LNG export facilities. However, there is some political opposition to allowing significant exports of LNG, due to concerns that these exports may drive up domestic prices and harm U.S. competiveness.
It is important to recognize that importing countries would likely not be securing gas at prices comparable to U.S. wellhead prices, and therefore not gain energy price competiveness. Rather, they would likely be purchasing gas at landed LNG rates typically linked to oil prices, and are much higher than U.S. domestic prices. And, while exports could exert modest upward price pressure on domestic pricing—which should spur production growth—these impacts are believed to be relatively modest. One study estimated that exports of 6 Bcf/d (2.2 Tcf annually) between 2015-35 would increase the Henry Hub gas price by just 10% (or $0.64 per MMBtu).
The U.S. Department of Energy (DOE) must approve all applications for projects designed to export natural gas to countries with whom the U.S. does not have a free trade agreement, and in so doing it must find these exports do not harm the public interest. While there are several applications pending at the DOE, only one recent application has been approved, for Cheniere Energy’s 2.2 Bcf/d Sabine Pass project in Louisiana. DOE retained an independent third-party contractor to review the economic impacts of proposed LNG exports and is not expected to act on any further applications until this report is released.
Notwithstanding the current regulatory impasse, we expect three U.S. export facilities would be constructed and brought into operation between 2016-19. These three U.S. LNG facilities, all located on the U.S. Gulf Coast, would require more than $18 billion in capital investments and create nearly 150,000 construction and operation jobs over the 20-year lifetime of the plants. With a combined capacity totaling 1.5 Tcf annually (4 Bcf/d), these facilities would also be major sources of demand, consuming an estimated 26 Tcf between 2016-35. These facilities also have the potential to generate attractive returns.
Because oil is the alternative fuel for most LNG importers, the price of LNG in the international market is typically linked to oil prices. An oil price of $100/bbl equates to a landed LNG rate of $12-15.50-/MMBtu, a significant premium relative to current U.S. gas prices. This premium has resulted in great interest in developing LNG export facilities in the U.S. LNG facilities are, however, quite capital intensive, the average cost for a greenfield 1 Bcf/d LNG plant is estimated at $4.8 billion, while retrofit of an existing import terminal would cost 65% of this, or $3.1 billion. The investment risk for an export terminal would be borne by the developer.
Employment In The Broader Economy
In addition to the direct investment and employment impacts associated with increased gas production and utilization the shale gas revolution would have significant positive spillover effects in the broader economy. A recent study found that the new production techniques driving the shale gas revolution could produce between 835,000 to 1.6 million jobs by 2017. (See http://www.cleanskies.org/techeffect for details.)
The study calculated the jobs along the natural gas and oil value chain as a result of the domestic natural gas, oil, and NGL supply surge and found that the upstream and midstream sectors (i.e., natural gas production, transportation, and processing) together require 13,000 annualized direct and indirect jobs per additional 1 Bcf/d of production.
The study estimated that in oil and gas production, every $1 of direct and indirect economic activity generates between $1.30-1.90 in induced economic activity (thereby creating between $0.30-0.90 in economic activity outside the oil and gas sector and its suppliers). Taken as a whole, the shale gas revolution has the potential to increase GDP by 1.2-1.7% per year by 2017.
Marc Lipschultz (New York) joined KKR in 1995 and is the global head of KKR’s Energy and Infrastructure business. He serves as a member of KKR’s Infrastructure Investment Committee and the Oil & Gas Investment Committee. He received an A.B. with honors and distinction, Phi Beta Kappa, from Stanford University and an M.B.A. with high distinction, Baker Scholar, from Harvard Business School.