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The Energy Information Administration's (EIA) survey of natural gas production from the Lower 48 states for the month of December 2012 showed the first decline in output since March of that year. With the continued decline in drilling rigs targeting natural gas formations, analysts are encouraged that possibly we are witnessing the first results of the drilling slowdown. The EIA's commentary associated with the release of the data, however, mentioned weather related factors impacting gas output, especially in the associated gas production from the Bakken where an early and severe winter caused a drilling and well completion slowdown. Additionally, many producers ran out of budget money before the end of the year and were forced to slow activity. If nothing else, however, the slowdown in gas output reinforces the phenomenon the industry may soon be confronting, which is the need to ramp up drilling activity to offset the steep decline in existing well production due to the nature of shale gas wells.
Overall, the initial estimate of gross natural gas production for the entire United States fell just about 1 billion cubic feet (Bcf) in December. Alaskan gas production actually rose about 0.2 Bcf while output in the Gulf of Mexico fell almost as much (-0.14 Bcf), meaning that virtually the entirety of the production decline occurred in Lower 48 basins. If we examine the revision to the prior monthly's initial production estimate, there was a reduction of 0.32 Bcf, which suggests the December production decline may only have been about 0.7 Bcf, but of sufficient size to be meaningful. Before analysts get too excited about this potential change in trend and what it might mean for natural gas prices, a new report from natural gas research firm, Bentek Energy, suggests that 2013 and 2014 will be a replay of the past several years – growth in production rather than a decline. The firm's forecast, however, calls for a slowing in the rate of increase in gas production during the next two years compared to the rate of growth experienced in the prior two years.
According to Bentek, natural gas production in the U.S. rose 3.6%, or by 1.6 Bcf per day in 2010 and increased by an average of 3.5
Bcf/d in 2011-2012. They are projecting that overall gas output will grow by 2 Bcf/d in 2013, as nine key shale basins will grow by 4.9 Bcf/d, which will be offset by other production falling by 2.9 Bcf/d. In 2014, the firm sees production increasing by 3.4 Bcf/d. An interesting point in the historical data is that in 2011 offshore gas output fell by 1.2 Bcf/d and then by another 0.9 Bcf/d in 2012. Bentek sees offshore production declining by only about 0.3 Bcf/d in 2013 and reaching steady output in 2014. If we were to exclude the impact of the decline in offshore production in 2011-12, the average annual output increase was about 4.3 Bcf/d, or nearly 0.8 Bcf/d more coming from onshore basins. By the end of 2014, Bentek foresees gas output above 70 Bcf/d, up from current production of slightly be low 65 Bcf/d.
Bentek's forecast for output is based on three primary factors. These include: debottlenecking of geographic regions where output has been constrained by a lack of infrastructure; operators continuing to focus on wet gas and associated gas from oil plays; and continued improvement in drilling rig efficiencies. The impact of the last two factors is shown in several charts from the Bentek forecast report that crystalize their views.
The chart in Exhibit 11 shows the impact of wet gas (green) output on total incremental natural gas production beginning in 2010 and continuing through the 2014 forecast period. As the chart shows, associated wet gas was only a minor contributor to gas output in 2010 but grew in 2011 as the impact of low natural gas prices drove operators to emphasize oil and wet gas formations. With natural gas prices continuing to languish in 2012, that trend became more pronounced with expected results. Because of the strong focus on natural gas liquids (NGLs) and crude oil due to high world oil prices and better investment returns for operators, Bentek sees wet gas production growing as we move through 2013 and 2014. Part of the strength in NGL and oil demand and their prices is due to debottlenecking Bentek assumes will occur based on the list of new pipeline and gas processing facilities either being built or planned to be built in the coming months.
The last major trend is the impact on shale gas costs from improvements in drilling. Exhibit 12 contains a chart showing the number of horizontal wells drilled since 2008 (blue columns), the number of horizontal rigs working (red line) and the average number of wells drilled per rig per month (black dotted line). The wells per month line in most impressive showing how after about a three-year downward trend between 2008 and 2010, the number rose in 2011 and remained essentially stable throughout the year but then started a steady upward climb throughout 2012. This rise in rig performance reflects not only improved knowledge about how and where to drill and the greater use of pad drilling facilities, but also the impact from the growing fleet of new AC (electric) rigs that bring greater capabilities for drilling deeper and longer horizontal wells.
Improvements in drilling in the Bakken have been meaningful as shown in Exhibit 13. Since the first quarter of 2010, the average time to drill a well has declined roughly 15%, although from the fourth quarter of 2010 the decline is much more significant – off nearly 40%! As the average rig can drill more wells per year and more rigs are moving into the Bakken, wells drilled have jumped in the past several quarters - from around 375 wells per quarter to 500 wells and then to a 600-wells per quarter rate for the final three quarters of 2012. The question is can the industry operate more drilling rigs in the region and will those rigs be capable of continuing to drill wells in fewer days in the future?
Last summer, the North Dakota Department of Mineral Resources presented an expected case for the future number of drilling rigs (red columns) working in the state's Bakken formation and the number of producing wells (green columns). As can be seen in Exhibit 14, the forecast calls for a small increase in the number of drilling rigs for 2013 and again in 2014, with rigs remaining flat in 2015 before spiking to a peak of just over 250 rigs in 2016. From that point the rig count begins a modest downward stepping pattern until it reaches a low point of 50 rigs in 2036 where it remains through the balance of the 2050 forecast period. As a result of the boom in drilling between 2010 and 2024, the total number of Bakken wells rises sharply from 5,000 to about 35,000. Thereafter, due to the decline in the active drilling rig count, the climb in the number of producing wells is modest reaching almost 40,000 wells in 2050.
A big challenge for producers in the Bakken is the lack of pipeline infrastructure to move associated natural gas production from the
region. Many people are familiar with the NASA photo of the United States at night showing the gas flaring in the Bakken (red) compared to the lights of Minneapolis, Minnesota on the right hand side of the picture. This picture rivals ones from the past showing the huge volumes of gas being burned in Nigeria and Russia that could be seen from space.
A chart from the North Dakota Department of Mineral Resources shows how the percentage of natural gas produced in the state is
burned. As the chart in Exhibit 16 shows, gas flaring was relatively minor until about 2005 and then it grew to about 24% in 2008 before falling 10 percentage points as a pipeline was opened up. From about 14% in 2009, the percentage of gas burned rose to the 35% area where it remains today awaiting more pipeline capacity and liquids-processing plants being built.
The Bentek natural gas production forecast relies on the continuation of the triumvirate of factors that have made oil shale plays as successful as they have been to date. Debottlenecking of various key producing basins appears a safe bet since it is based on projects already approved and in many cases already under construction with attractive returns. A continuation of improvements in drilling efficiency appears less secure as it depends on the drilling industry converting the balance of its old, conventional rig fleet into a new, AC-based one. That means higher day rates for working rigs in order for contractors to justify the investment in new rigs. What will higher dayrates mean for well economics? What happens to these oil and wet gas plays should oil prices fall from their current lofty levels? These latter considerations could impact the economics of shale drilling and thus gas output that would negatively impact the Bentek forecast since it is based on economic models employing 12-month forward strip pricing for crude oil and NGLs. The one offset to this logic is the dedication of large integrated and independent producers to drill through the period of poor economic returns because they believe in the eventual recovery of oil and natural gas prices that will reward them for their strategy.
G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.
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