In July 2013, U.S. natural-gas production hit a record high of almost 2.1 trillion cubic feet. Nevertheless, every few weeks an article or promotion crosses my desk predicting a huge rally in North American natural-gas prices and stocks leveraged to greater gas demand and consumption.
But investors banking a near-term recovery in the price of natural gas likely will remain disappointed. As I explained in the July 16, 2013, issue of Energy & Income Advisor, The Shale Gas Revolution and Compression Services, U.S. natural-gas prices should range between $3.00 and $5.00 per million British thermal units (mmBtu) over the next two to three years, assuming normal weather conditions.
Persistently weak natural-gas prices reflect a deluge of production from several prolific unconventional plays, including the Eagle Ford Shale in southern Texas and the Marcellus Shale in Appalachia.
Historically, shifts in the gas-directed rig count helped to balance supply and demand. That is, when natural-gas prices spiked, producers would step up their drilling activity, eventually resulting in more output, a looser supply-demand balance and lower prices. Similarly, a sharp drop in natural-gas prices would spur producers to curtail their drilling plans, a move that would reduce overall output and boost natural-gas prices.
This system of checks and balances worked to a tee between 2001 and 2003.
U.S. natural-gas prices rallied to about $10.00 per mmBtu by the start of 2001, prompting producers to ramp up drilling activity. In response, the gas-directed rig count surged to about 1,068 units in mid-2001 from about 600 earlier in the year. This increase in drilling activity produced a corresponding uptick in production in the back half of the year; by September 2001, the price of this commodity had retreated to less than $3.00 per mmBtu.
But the traditional relationship between the U.S. gas-directed rig count, production and spot prices has completely broken down since 2008.
Natural-gas prices topped out at more than $13.50 per mmBtu in 2008 and bottomed at $1.91 per mmBtu in April 2012. Although the commodity has enjoyed a handful of short-term rallies since 2008, natural-gas prices have averaged less than $4.00 per mmBtu since late 2010. This persistent weakness has occurred despite the U.S. gas-directed rig count plummeting to less than 350 active units in June 2013 from more than 1,550 rigs in September 2008.
The explanation for this apparent anomaly: Domestic production has decoupled from the gas-directed rig count, hitting an all-time high in July 2013.
The Great Decoupling
In large part, the declining relevance of the U.S. gas-directed rig count to trends in natural-gas production reflects upstream operators' preference for plays that contain significant volumes of oil and natural gas liquids (NGL).
Whereas the gas-directed rig count has declined precipitously since fall 2011, the number of active drilling units targeting crude oil surged until mid-2012, when it reached a plateaued at 1,350 to 1,400.
Although drilling activity has shifted to liquids-rich plays, these wells also yield significant volumes of associated natural gas-the primary reason that domestic production of this commodity has continued to climb.
Given the importance of the shale oil and gas revolution to America's energy renaissance, the horizontal rig count served as a better forward indicator of U.S. hydrocarbon production-at least for a time.
Along with hydraulic fracturing, horizontal drilling is one of the key technological innovations that have enabled exploration and production companies to extract oil and gas from shale and other low-permeability reservoir rocks. By drilling horizontally from the vertical wellbore, operators expose more of the productive layer and boost initial flow rates.
As recently as 2004, units capable of drilling horizontal well accounted for less than 10 percent of the total U.S. rig count. Today, however, horizontal rigs account for about two-thirds of the units drilling onshore.
However, the usefulness of the horizontal rig count as a predictor of U.S. hydrocarbon production has deteriorated because of the huge efficiency gains that have occurred as operators hone their production techniques in the nation's most prolific shale plays.
These realities prompted oil-field services giant Baker Hughes (BHI) to introduce a new data set to complement its widely watched rig counts. This fledgling index tracks quarterly well counts by U.S. basin and, in conjunction with corresponding data on active drilling rigs, enables users to calculate and track efficiency improvements in various basins.
During a conference call to discuss Baker Hughes' second-quarter results, CEO Martin Craighead highlighted some of the insights analysts can glean from this new data set:
For the last 70 years, we have provided the industry with the Baker Hughes rig count. Last night, we announced the launch of the Baker Hughes well count. This new index captures the number of wells which were spud in each major U.S. basin and, when combined with the Baker Hughes rig count, drilling efficiencies become more obvious.
As industry trends evolve, you can expect new features and information sources to be added to the Baker Hughes well count index periodically. We can see from the data, for example, that drilling efficiencies vary by basin. In the Williston, the Marcellus, and the Eagle Ford, we're seeing about 20 percent more wells per rig compared to this time last year. Whereas, in the Permian [Basin], wells per rig have hardly changed.
Additionally, the Baker Hughes well count shows seasonality that wasn't evident in the rig count alone. During the winter months, the wells per rig slows due to poor weather conditions. For example, the wells per rig dropped by 15 percent in the Granite Wash this past winter before rebounding later in the spring. So, it's this seasonal rebound and the underlying trend of drilling efficiencies that explains why we saw a 3 percent increase in the Baker Hughes well count during the second quarter despite the rig count remaining absolutely flat.
Even though Baker Hughes' publicly available well count data only goes back to the first quarter of 2012, the gains in drilling efficiency are still readily apparent. Check out this graph tracking the average number of wells drilled per rig in 14 of the biggest unconventional oil and gas plays.
Source: Bloomberg, Baker Hughes, Energy & Income Advisor
The average rig operating in a liquids-rich field drilled 4.12 wells in the second quarter of 2012, compared to 4.67 in the third quarter-an increase of 13.4 percent over the past 15 months. However, these improvements pale in comparison to trends in the six gas-focused plays included in our survey; the typical rig in these fields drilled 6.47 wells in the third quarter-up almost 30 percent from the second quarter of 2012.
These statistics help to quantify recent trends in natural-gas production, rig counts and prices. Over the 12 months ended June 30, 2013, the rig counts in the six plays that we classified as dry-gas fields plummeted by 36 percent. But this decline in the rig count produced only a 15 percent drop in the number of wells drilled in these fields.
Bottom Line: As long as these efficiency gains continue, producers can increase the number of wells drilled with a flat or declining rig count.
Behind the Efficiency Gains
Experience is one of the most important drivers of drilling efficiency. With each well drilled in a given play, the resultant production data enables operators to optimize their design and fracturing strategy.
Industry participants often liken shale development to a manufacturing process. Given the rarity of dry holes in these plays, growing oil and gas output hinges on drilling more wells and honing production techniques-for example, determining the ideal lateral length and number of fracturing stages-to maximize recovery rates.
Once producers have cracked a particular shale play's code, the transition to pad drilling can increase rig efficiency dramatically.
In a traditional drilling operation, the rig would be completely disassembled (rigged down in industry parlance) after completing a well and then moved to the next drilling location for reassembly (rigging up).
Drilling horizontally enables producers to sink multiple wells from a single pad location. Although the wells might be close together at the surface, the producers can sink six or more wells from a single pad by moving the rig 10 feet to 20 feet between drilling sites.
Newer rigs often sit on skids or feet that enable operators to relocate these units without rigging down, reducing downtime. And rig mobility continues to improve. Check out this video of one of Patterson-UTI Energy's (PTEN) APEX rigs, which can walk up to 150 feet in any direction on a drilling pad. These advanced rigs can travel 10 feet to 20 feet in about 45 minutes.
Adoption of pad drilling occurs rapidly once exploration and production companies have figured out the ideal well design to exploit a particular play. For example, David Lesar, CEO of Halliburton (HAL), estimates that more than 60 percent of the new wells in the Eagle Ford Shale use pad drilling, up from less than 40 percent a year ago.
Baker Hughes' CEO provided additional color on this trend during the company's second-quarter earnings call:
Analyst: One of the things we continue to hear about is pad drilling starting to expand in different markets. Can you give me a sense of roughly how much of your business do you think is on the pad drilling side and where you think that can go, say, over the next 12 months?
Martin Craighead: Well, I don't want to tell you the percentage, but it's - the amount of revenue that we earned this quarter is twice what we earned this time last year. And I don't want to tell you the magnitude of that. I'll let you judge that. But it's surprising how much is being converted to these pad locations so quickly. Now, that may be in part because of our product mix, particularly the AutoTrak Curve and so forth. So, I don't know if it's inordinately high for us. Certainly as well, relative to last year, the way we've re-architected, redesigned our frac fleets and changed our customer mix may have also accelerated U.S. in that space. But it's 100 percent year-on-year on the pads.
As we explained in Oil-Field Services: Second-Quarter Roundup, increasing adoption of pad drilling has helped to bolster flagging margins in pressure pumping-the horsepower that's critical to hydraulic fracturing.
Baker Hughes, one of the leading providers of these services in North America, doubled its revenue from pad-based wells over the past year-a big reason why the company's second-quarter results surprised to the upside. Moreover, Baker Hughes' profit margins on these wells are 30 percent to 50 percent higher than on traditional, standalone drilling sites; pad drilling reduces downtime and expenses related to transporting fracturing equipment large distances between wells.
Rising adoption of pad drilling has also improved the profitability of producers, as companies can sink more wells with fewer rigs. Shares of EOG Resources (EOG), Oasis Petroleum (OAS) and other leading shale oil and gas producers have enjoyed quite a run this year, thanks to elevated oil prices, rising output and steadily declining production costs.
However, these efficiency gains represent yet another near-term headwind for natural-gas prices. With the marginal cost of production continuing to decline, upstream operators are incentivized to ramp up output whenever the commodity rallies to more than $4.00 per mmBtu. This phenomenon should ensure that natural gas prices don't surpass $5.00 per mmBtu over the next two to three years.
With natural-gas prices likely to remain range-bound over the next few years and North American crude-oil prices weakening in the fourth quarter, investors will need to be selective when choosing the best oil and gas producers for their portfolios.