This article was originally published on RBN Energy by Rick Smead
This is the fourth installment in our series analyzing the overall nature of the natural gas surge in supply and demand, as to whether the natural gas renaissance is real and sustainable, with plenty of natural gas at reasonable prices. In Part I “Golden Years: The Golden Age of U.S. Natural Gas,” we tackled the history of industry regulation before the shale era. In Golden Years: The Golden Age of U.S. Natural Gas Part II—How Much Gas Do We Need?, we developed a reasonable demand scenario out to 2025. Our total U.S. demand estimate of 92.5 Bcf/d represented an upward adjustment of 15.5 Bcf/d over EIA’s 2013 estimate (77 Bcf/d). In Part III we showed how Energy Information Administration (EIA) estimates of supply—even though they increased in a new, updated forecast —seem still to be much lower than reality (see Golden Years: The Golden Age of U.S. Natural Gas Part III—How Will Producers Supply Expanding Demand?).
Just to clarify our basic notion in this series, we are not saying that natural gas prices will never increase. In fact, the production scenario that we’ve presented assumes that prices will be somewhat higher going forward than they have been for the last couple of years, high enough to attract drilling rigs back from oil plays to gas plays to resume some significant portion of the large gas-directed drilling programs that were in effect until 2012, when the “call of the oil” brought about a major shift in the drilling population away from natural gas. Today’s benchmark Henry Hub natural gas price bounces around between $3.50 and $4.50/MMBtu, Prices between $4.50 and $5.00, are what we believe are needed and are a level that could remain stable for a long time. EIA’s Annual Energy Outlook for 2013 (AEO2013) forecast constant-dollar prices that did not break $5.00/MMBtu until after 2025. The more recent early release of the Annual Energy Outlook for 2014 (AEO2014 ER) shows higher demand and higher supply, but then forecasts prices about 30 cents higher than AEO2013 at $5.30/MMBtu. Results to date suggest that the AEO2013 price forecasts are high enough to bring producers back to drilling for shale gas.
Back from where? Back from the massive shift to drilling for shale oil that followed (1) low gas prices driven by oversupply in 2012, and (2) successful application of the same horizontal drilling and hydraulic fracturing techniques to the production of higher-value oil.[see blogs] . Figure 1 shows that the shift was both clear and dramatic after January 2012 between falling horizontal rigs looking for natural gas (blue line) and increasing horizontal rigs looking for oil (red line).
Gas directed horizontal rigs stayed constant at a little over 600 throughout 2011, then in 2012 and into 2013, dropped precipitously to less than 300. At the same time, the red line, the rigs looking or oil, went from about 350 to over 800.
So ultimately, the key to producing a lot more natural gas is to have a lot more rigs drilling for it, and the rigs are already out there—just doing something else.
But wait a minute—as we discussed last time, the production of shale gas has kept going up—in the face of a rig count that has dropped by over 50 percent. How did producers do that, and what does it mean for the future?
First, how they did it and are continuing to do it: The efficiency and productivity of shale drilling and production have increased a great deal in the last few years (see The Truth is Out There). Each rig can drill a lot more wells in a year, and each well can produce a lot more gas. Figure 2 illustrates the point well, based on the experience of Southwestern Energy, a producer active in shale gas. Starting from the left, from 2007 (blue) to 2012 (orange), the average time to drill a well went from 18 days to 7 days, a decline of 62 percent, meaning that the wells per year per rig went from 21 to 52, an increase of 148 percent. The average initial production rate over the first 30 days of each well’s life went from 1.6 MMcf/d to 3.7, an increase of 131 percent. So, as the last set of bars shows, simply multiplying everything together means that a single rig’s annual contribution to new supply grew from 34.4 MMcf/d to 192.4 MMcf/d, an increase of 460 percent. That is a lot of natural gas—if every producer could do this, the “shrunken” population of gas-directed horizontal rigs would be bringing something like 54 Bcf per day of new supply to market every year—in a national market that is only 66 Bcf per day in total. That kind of productivity can make up for a lot of decline in existing wells, and produce a lot of growth. Of course, every producer and every shale play does not necessarily achieve those sorts of results, but the industry has definitely stayed ahead of demand, even with a significantly reduced population of gas-directed rigs.
One other element of the new supply that is still showing up is associated gas, the natural gas that comes along with all that oil drilling. In a few unique instances, such as remote plays like Bakken in North Dakota, a great deal of the associated gas is not yet making it to market, rather being flared as oil is produced (see Set Fire to The Gas). As facilities are added to gather and transport that associated gas, it will ramp into increased market supply.
So there we have some of the reasons that supply is and can be very healthy, without big increases in prices. We demonstrated in the last installment that every time EIA catches up with past shale production and lays out its forecast of future production, the industry has already passed the projection. So in that case, what would be a reasonable level of supply to count on to meet the demand levels discussed earlier, in the second installment of this series? (See Golden Years: The Golden Age of U.S. Natural Gas Part II—How Much Gas Do We Need?).
The driving variable in supply adequacy is shale gas. Many analysts predict shale development in many ways. It can be play by play, well type by well type, with excruciating analyses of producer economics, and an ultimate conclusion that “economics dictate” a particular answer. Meanwhile, a common failing in many analyses, particularly involving shale gas, is that so many of the factors are based on historic values for unit costs, productivity per well, historically observed decline curves, etc.—all values that have been changing very rapidly as technology has advanced. This goes along way toward explaining why industry performance has so far outstripped EIA projections.
So for purposes of this review, where we are just trying to determine whether it is plausible for fairly business-as-usual continuation of supply development to provide some safety margin above the likely demand scenarios we have examined, it is enough to see how we would correct EIA’s forecast of shale production, to reflect the actual performance of the industry. Figure 3 does so. First, it identifies the statistical trend indicated by shale gas production growth from 2008 through 2013 (black dashed line), the era when shale really came into its own. At that rate of growth, production would zoom off into the stratosphere pretty quickly. So we have fitted a “discounted” or slowed version of that trend (the green line) starting with a slope equal to one-half of the shale era trend, and then slowing slightly as it moves forward to 2025. This trend line is matched to the curvature of the last couple of years of actuals so it reflects what impact there has been from the reduced rig count. And as you can see, by 2025 even this discounted version of the historic trend exceeds EIA’s forecast production (blue line) pretty substantially.
We then need to adapt our total production estimates for this variation in shale production. That is done in Figure 4. Here, the green line represents EIA’s total-supply forecast adjusted for the increased shale production from Figure 3, then trued-up for the known actual production in 2013. Looking for confirmation that we are in the ballpark, our 2014-2025 estimate comes pretty close to a five-year, 2014-2018, forecast recently prepared by Bentek, in red.
The end result is that by 2025, our adjusted supply curve exceeds EIA’s estimate by 10.2 Bcf/d, almost twice the additional demand of 5.5 Bcf/d that our last two installments explained was reasonable to expect.
The most important aspect of this “adjusted EIA” scenario is that it is based on a slowing down of the shale era trend over the past 5 years, without further technological breakthroughs, without the discovery of new, as yet unknown, shale plays, or any other game-altering developments.
So we wrap up this series by concluding that it is likely that the industry can readily supply much larger demand, including expanded power generation, industrial growth, and exports both by pipeline and by LNG tanker. However, as we indicated at the outset, there is still a lot to do. Producers will need to be incented to move back into gas-rich plays, midstream and pipeline infrastructure will have to be built to accommodate the production, and a lot of pipeline and storage infrastructure will need to be built to get gas to market in parts of the country that don’t seem to like infrastructure construction. So nothing is guaranteed, but all the tools are in place for the Golden Age of natural gas to continue for a long time.