Over the past two years, expectations for U.S. domestic natural gas production have changed radically. A range of industry and government studies now are projecting that U.S. natural gas resources are far larger than previously realized, thanks to advances in unconventional gas production; particularly for natural gas production from shale rock formations using advanced drilling techniques. At the moment, the United States is experiencing a glut of natural gas with record underground gas storage inventories and prices around $4/MMBtu, which serves to underscore the new thinking about U.S. natural gas supply—i.e., future gas supplies might be less constrained than earlier studies suggested they would.
Given the speed with which the expectations for U.S. natural gas have changed, it’s reasonable to ask how solid is this new thinking about U.S. natural gas supply and what should the role of natural gas be in meeting our long-term energy needs in a carbon-constrained economy?
The concept of natural gas as a bridge fuel to a low-carbon, sustainable energy future is nothing new. All through the 1990s natural gas was expected to play an increasing role in U.S. energy supply as environmental concerns became more prevalent and uncertainty grew regarding the cost or timing of such alternatives as nuclear power. The environmental benefits of natural gas compared to coal and oil were compelling, and at the time natural gas was seen as abundant and low cost.
However, price spikes and supply concerns raised fundamental questions about the role of natural gas starting in the 2000 and 2001 time frame. By 2005, the DOE’s Energy Information Administration (EIA) was forecasting that imported natural gas brought in by ocean tanker in the form of liquified natural gas (LNG) would comprise 20 percent of U.S. gas supply by 2020, and developers had advanced plans for more than 40 LNG regasification terminals. The U.S. natural gas resource base was seen as old and in decline. If not entirely broken, the concept of a natural gas bridge was in serious trouble. Heavy reliance on LNG imports raised security questions, and the poor domestic supply outlook suggested high and volatile prices were coming.
Then, starting in 2006, the industry became aware of the tremendous strides that had been made in development of the Barnett Shale near Dallas-Fort Worth. For the past decade, producers had been refining approaches to combine hydraulic fracturing of shale rock formations with horizontal drilling techniques to recover increasing amounts of natural gas. The success of those early shale producers led to a drilling boom during 2007 and 2008, both in the Barnett and other promising shale regions (see Figure 1).
As oil and gas prices skyrocketed during the first half of 2008, drilling escalated. The most active unconventional natural gas producers began discussing the need to convert the U.S. transportation sector over to natural gas to absorb the massive increases in production that they saw coming. Oil man T. Boone Pickens started a well-funded campaign aimed at promoting expanded use of wind energy and natural gas. At one point a large shale producer went so far as to suggest that the United States would need to build LNG liquefaction terminals along the Gulf Coast to export the shale gas to needy markets in Europe.
Beyond the hyperbole, the U.S. government and industry were taking notice of unconventional gas production. The EIA’s 2009 energy outlook projected that the United States would be nearly self-sufficient in natural gas with very low levels of imported LNG compared to prior year forecasts (see Figure 2).
Last year a report from Navigant Consulting, sponsored by shale gas producer Chesapeake Energy, was released on July 4, which announced that shale gas was a game changer.
Navigant’s base-case estimate of total U.S. natural gas resources was 1,680 TCF, which included 274 TCF of undiscovered, technically recoverable shale gas resources. Navigant’s estimate of the U.S. shale gas resource was more than double that of the Potential Gas Committee (PGC) report for year-end 2006. Most striking were the high-end estimates of potentially recoverable shale gas that Navigant obtained directly from producers. Producers estimated that 842 TCF of technically recoverable shale gas remained undiscovered. The huge discrepancy was due almost entirely to the exclusion from official estimates of the two shale plays that were getting the most attention from producers in 2008—Marcellus shale (228 TCF of resources according to producers) and Haynesville shale (217 TCF according to producers).
A few months ago, at least one of the official sources—the PGC—appears to have caught up with the producers. PGC’s latest estimate of the U.S. resource base as of year-end 2008 included 616 TCF of technically recoverable shale gas resources and a total resource base of 1,836 TCF. This estimate was the highest of the U.S. natural gas resource base in the 44-year history of the PGC. If EIA’s estimate of proved natural gas reserves are included, the total amount of natural gas resource becomes 2,074 TCF. At current rates of consumption, this is more than 100 years of supply.
Of course, even PGC’s prior study provided more than 75 years of supply at current rates of consumption, so this isn’t meant to imply that there was a puny natural gas resource before. But, the revision in the expected contribution from shale gas was dramatic. Shale gas went from less than 10 percent of the total resource base in the 2006 PGC study to 30 percent in the 2008 study (see Figure 3).
A key, but often overlooked, issue with these resource estimates is that they ignore economics (i.e., whether these natural gas resources aren’t just technically recoverable but also profitably recoverable). And on that issue a great deal of debate is taking place.
There is a wide range of opinion about the price level for natural gas that is required to make economic many of the shale plays. On the optimistic side, there are those that believe most of the shale plays can be exploited profitably, even at average prices well below $6/MMBtu. On the other hand, some argue that the true marginal cost for shale plays is well above $7/MMBtu and that the actual netback price for production that producers are realizing in many of the plays is around $3/MMBtu.
Ultimately, a number of factors will influence the economics of shale gas production and how much shale gas actually is produced from the massive technically-recoverable resource base. While it seems reasonable to expect that, given the large resource base, a scaling up of shale gas production to 20 or 30 Bcf per day (about four or five times current production levels) is manageable, a number of technical, environmental, and economic challenges will make scaling up rather difficult.
Shale gas plays aren’t identical, and in many ways each one is unique. While all shale gas production requires reservoir fracturing, and nearly all require horizontal drilling, the application of a specific drilling and fracturing process is often different and requires a degree of trial and error. Even within a particular shale play there’s often a wide range of cost and performance between core areas and non-core areas of the play. All of this adds to the complexity of scaling up production, and it may take time—and money—for producers to find the right combination of technologies that provide good results in a particular location.
Shale wells also have rather notorious initial decline rates. It’s common for a shale well to see its production rate drop by 60 percent over the first year. Many models assume or predict that there will be a long tail on individual shale-well production as the decline rates flatten out after a few years. Even if this is true, the steep initial decline rates mean that producers need to continuously bring on new wells to maintain overall production levels, let alone increase production. Given how new many of the shale plays are, and the lack of well performance data for any length of time, it might prove that the projected long tails on shale well production are a myth.
Increasingly, shale gas producers are facing environmental concerns dealing with the impact of hydraulic fracturing on local water supplies. Each shale well requires 2 million to 4 million gallons of water, and accessing the required water and then disposing of it poses a challenge in some shale plays. While most regulation is at a state level, there have been recent attempts to introduce federal regulation, which could increase costs.
In addition, the intensive drilling and industrial-like activities that are involved with developing shale gas resources may cause conflicts in more populated areas. Addressing these concerns likely will add costs.
While the integrated oil companies have started showing interest in shale gas production, the leading companies still are relatively small independent natural gas producers. These smaller companies may face greater challenges going forward in accessing capital to fund drilling expansions. In addition, they’re vulnerable to downturns in natural gas price levels, which deprive them of cash flow to fund continuous reinvestment and operations. This vulnerability is apparent in the current environment, which has seen a massive cut in rig activity in response to the collapse in natural gas prices. In addition, it could be an issue in future years when the next phase of LNG liquefaction capacity buildup begins.
A final point is that despite the optimism around shale gas production, some other unconventional resources like tight gas and coal bed methane don’t appear to be expanding, and the conventional components of the U.S. gas resource base are in decline. For example, natural gas production from offshore areas in the Gulf of Mexico has suffered in recent years, and no improvement is expected (see Figure 4).
When the Navigant study on shale gas was released, analysts focused a great deal of attention on the potential for use of natural gas in the transportation sector as a way to reduce greenhouse-gas (GHG) emissions and also reduce U.S. dependence on foreign oil. Somewhat overlooked in the discussion was the tremendous expansion of natural gas-fired power generation capacity and use of natural gas by the power sector over the past decade (see Figure 5).
Data from Ventyx’s Velocity Suite and analysis solution show the rapid expansion of natural gas power plant development during the merchant power boom over 2000-2001. Despite the merchant bust that followed, approximately 200 GW of natural gas-fired capacity was added by the end of 2003.
It’s notable that since 2004, natural gas power plants have continued to be proposed, permitted, and constructed at a fairly constant basis. As a result, in total the U.S. market now includes nearly 300 GW of new natural gas capacity. About 60 percent (163 GW) has been combined-cycle capacity, which represents more than 10 Bcf per day of gas demand during peak load months.
Going forward, as the electric industry increases its focus on lowering carbon emissions, the role of natural gas-fired power generation might shift to firming variable renewable power resources and providing peaking power or standby generation to ensure reliability. However, tremendous uncertainty surrounds the mid-term and long-term outlook for natural gas consumption from the U.S. power sector.
Natural gas power generation potentially might increase dramatically as older coal units are retired under GHG regulation. Even under a scenario where carbon capture and sequestration technology becomes widely available and economic, natural gas consumption for power generation could increase.
Ventyx estimates several potential outcomes for natural gas and coal consumption—based on taking the projections from EIA in its 2009 Annual Energy Outlook and modifying the power plant capacity mix over time so that, under a retirement scenario and a retrofit scenario, a set of CO2 caps that are similar to the structure envisioned by the Waxman-Markey legislation are achieved through 2030.
In the retirement scenario, coal consumption by the power-generation sector begins declining rapidly while the attendant increase in natural gas consumption is relatively gradual; by 2030, however, natural gas consumption for power generation is projected to almost double from current levels.
In the retrofit scenario, coal consumption falls initially but then begins increasing after retrofit technology is assumed to be available. However, natural gas consumption increases even faster than in the retirement case. In large part this increase is due to the energy required by carbon capture, which reduces coal-fired plant power generation output to the grid, requiring additional generation from natural gas to meet loads (see Figure 6).
The point of this analysis isn’t to predict or forecast the exact outcome under a given set of GHG-reduction targets, but to highlight the wide range in potential impacts on natural gas demand from the power sector over time, and also to show that uncertainty exists not just in the long-term but also over the next decade.
The new thinking on natural gas supply in the United States marks a noteworthy turnaround. The notion of the U.S. natural gas resource base as old and in permanent decline has been banished—and possibly just in time, as it appears increasingly likely that natural gas consumption in the power sector will be increasing over the mid- and long-term following federal implementation of GHG regulation. This demand pressure on natural gas likely will encourage more drilling activity, and producers increasingly will look to new shale plays as growth areas. However, stakeholders in the U.S. energy industry shouldn’t count on a massive scaling up of natural gas production from shale gas resources, and planners and developers should consider the limitations and challenges that make realizing the full potential of U.S. unconventional production difficult.